10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 ____________________________

Form 10-Q

____________________________

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

For the quarterly period ended September 30, 2013

OR

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

For the transition period from to

Commission file number: 333-187868

____________________________

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  ý    No  ¨

(Explanatory Note: Prior to April 24, 2013, the effective date of the registrant’s Registration Statement on Form S-4, the registrant was a voluntary filer and was 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  ý    No  ¨

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

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

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

Number of shares outstanding of each of the issuer’s classes of common stock as of November 14, 2013:

Class	Number of shares
Class A Common Stock, $0.01 par value	70,145
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 September 30, 2013 (unaudited) and December 31, 2012	6
Consolidated statements of operations for the three and nine months ended September 30, 2013 and 2012 (unaudited)	8
Consolidated statements of comprehensive (loss) income for the three and nine months ended September 30, 2013 and 2012 (unaudited)	9
Consolidated statements of cash flows for the nine months ended September 30, 2013 and 2012 (unaudited)	10
Notes to consolidated financial statements (unaudited)	11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Overview	31
Results of operations	33
Liquidity and capital resources	39
Non-GAAP financial measure and reconciliation	45
Critical accounting policies	45
Recent accounting pronouncements	45
Item 3. Quantitative and Qualitative Disclosures about Market Risk	46
Item 4. Controls and Procedures	50
Part II. OTHER INFORMATION	50
Item 1. Legal Proceedings	50
Item 1A. Risk Factors	50
Item 6. Exhibits	51
Signatures	52
EX-10.1 (Asset Purchase Agreement dated as of October 11, 2013, by and between Chaparral Energy L.L.C. and Cabot Oil & Gas Corporation)
EX-10.2 (Thirteenth Amendment to Eighth Restated Credit Agreement dated as of October 29, 2013)
EX-31.1 (Rule 13a-14(a)/15d-14(a) Certification by CEO)
EX-31.2 (Rule 13a-14(a)/15d-14(a) Certification by CFO)
EX-32.1 (Section 1350 Certification by CEO)
EX-32.2 (Section 1350 Certification by CFO)

2

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, and 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 a 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. 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;

• changes 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.

3

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 our Annual Report on Form 10-K filed with the SEC on April 1, 2013. Specifically, some factors that could cause actual results to differ include:

• the significant amount of our debt;

• worldwide supply of and 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.

4

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 CO₂or 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.

• MMBtu. One million British thermal units.

• MMcf. One million cubic feet of natural gas.

• Net acres. The percentage of total acres an owner has out of a particular number of acres, or in a specified tract. An owner who has a 50% interest in 100 acres owns net 50 acres.

• NYMEX. The New York Mercantile Exchange.

• Proved reserves. The quantities of oil and 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.

• PV-10 value. When used with respect to oil and natural gas reserves, PV-10 value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, excluding escalations of prices and costs based upon future conditions, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10%.

• SEC. The Securities and Exchange Commission.

5

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets

	September 30, 2013			December 31, 2012
(dollars in thousands, except per share data)	(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	37,314		$	29,819
Accounts receivable, net	96,463			77,307
Inventories, net	12,069			10,510
Prepaid expenses	2,714			3,465
Derivative instruments	4,449			42,516
Deferred income taxes	989			—
Total current assets	153,998			163,617
Property and equipment—at cost, net	67,302			65,601
Oil and natural gas properties, using the full cost method:
Proved	3,062,399			2,860,611
Unevaluated (excluded from the amortization base)	250,026			162,921
Accumulated depreciation, depletion, amortization and impairment	(1,420,348		)	(1,290,356		)
Total oil and natural gas properties	1,892,077			1,733,176
Derivative instruments	4,032			517
Assets held for sale	4,599			5,689
Other assets	35,940			38,952
	$	2,157,948		$	2,007,552
The accompanying notes are an integral part of these consolidated financial statements.

6

Chaparral Energy, Inc. and subsidiaries Consolidated balance sheets—continued
	September 30, 2013		December 31, 2012
(dollars in thousands, except per share data)	(unaudited)
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	116,225	$	101,598
Accrued payroll and benefits payable	22,293		19,655
Accrued interest payable	33,390		24,131
Revenue distribution payable	23,333		18,152
Current maturities of long-term debt and capital leases	3,322		3,746
Derivative instruments	6,971		436
Deferred income taxes	—		26,872
Total current liabilities	205,534		194,590
Long-term debt and capital leases, less current maturities	1,376,736		1,289,656
Derivative instruments	22		2,192
Stock-based compensation	3,133		3,042
Asset retirement obligations, net of current portion	45,349		46,314
Deferred income taxes	45,394		8,901
Commitments and contingencies (Note 10)
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 70,224 and 67,991 shares issued and outstanding as of September 30, 2013 and December 31, 2012, 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	423,993		422,434
Retained earnings	52,328		17,186
Accumulated other comprehensive income, net of taxes	5,445		23,223
	481,780		462,857
	$	2,157,948	$	2,007,552

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

7

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of operations

	Three months ended						Nine months ended
	September 30,						September 30,
	2013			2012			2013			2012
(in thousands)	(unaudited)			(unaudited)			(unaudited)			(unaudited)
Revenues:
Oil and natural gas sales	$	161,623		$	131,215		$	433,489		$	374,452
Gain from oil hedging activities	9,032			11,468			28,544			35,777
Total revenues	170,655			142,683			462,033			410,229
Costs and expenses:
Lease operating	37,306			35,278			104,232			98,946
Production taxes	8,831			8,748			25,299			24,258
Depreciation, depletion and amortization	47,582			44,421			139,439			119,807
Loss on impairment of other assets	1,090			—			1,090			—
General and administrative	13,065			12,878			38,626			39,165
Total costs and expenses	107,874			101,325			308,686			282,176
Operating income	62,781			41,358			153,347			128,053
Non-operating income (expense):
Interest expense	(24,074		)	(24,087		)	(72,565		)	(72,666		)
Non-hedge derivative (losses) gains	(43,830		)	(25,030		)	(26,484		)	37,035
Loss on extinguishment of debt	—			(18		)	—			(21,714		)
Other income, net	425			104			837			236
Net non-operating expense	(67,479		)	(49,031		)	(98,212		)	(57,109		)
(Loss) income before income taxes	(4,698		)	(7,673		)	55,135			70,944
Income tax (benefit) expense	(2,130		)	(2,727		)	19,993			25,645
Net (loss) income	$	(2,568	)	$	(4,946	)	$	35,142		$	45,299

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

8

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of comprehensive (loss) income

	Three months ended						Nine months ended
	September 30,						September 30,
	2013			2012			2013			2012
(in thousands)	(unaudited)			(unaudited)			(unaudited)			(unaudited)
Net (loss) income	$	(2,568	)	$	(4,946	)	$	35,142		$	45,299
Other comprehensive loss
Reclassification adjustment for hedge gains included in gain from oil hedging activities in the consolidated statements of operations	(9,032		)	(11,468		)	(28,544		)	(35,777		)
Income tax benefit related to other comprehensive loss	3,306			4,129			10,766			14,717
Other comprehensive loss, net of tax	(5,726		)	(7,339		)	(17,778		)	(21,060		)
Comprehensive (loss) income	$	(8,294	)	$	(12,285	)	$	17,364		$	24,239

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

9

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows

	Nine months ended
	September 30,
	2013			2012
(in thousands)	(unaudited)			(unaudited)
Cash flows from operating activities
Net income	$	35,142		$	45,299
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion & amortization	139,439			119,807
Loss on impairment of other assets	1,090			—
Deferred income taxes	19,398			25,540
Gain from oil hedging activities	(28,544		)	(35,777		)
Non-hedge derivative losses (gains)	26,484			(37,035		)
Loss on extinguishment of debt	—			21,714
(Gain) loss on sale of assets	(556		)	21
Other	1,826			2,167
Change in assets and liabilities
Accounts receivable	(20,858		)	(13,140		)
Inventories	(1,689		)	(4,599		)
Prepaid expenses and other assets	2,130			1,763
Accounts payable and accrued liabilities	17,694			13,355
Revenue distribution payable	5,181			(2,215		)
Stock-based compensation	1,747			2,077
Net cash provided by operating activities	198,484			138,977
Cash flows from investing activities
Purchase of property and equipment and oil and natural gas properties	(382,167		)	(379,069		)
Proceeds from dispositions of property and equipment and oil and natural gas properties	91,788			45,023
Settlement of non-hedge derivative instruments	13,097			24,309
Other	(664		)	23
Net cash used in investing activities	(277,946		)	(309,714		)
Cash flows from financing activities
Proceeds from long-term debt	133,208			156,457
Repayment of long-term debt	(51,416		)	(37,608		)
Proceeds from Senior Notes	—			400,000
Repayment of Senior Notes	—			(325,000		)
Proceeds from capital lease obligations	5,203			—
Principal payments under capital lease obligations	(38		)	(10		)
Payment of debt issuance costs and other financing fees	—			(8,867		)
Payment of debt extinguishment costs	—			(15,827		)
Net cash provided by financing activities	86,957			169,145
Net increase (decrease) in cash and cash equivalents	7,495			(1,592		)
Cash and cash equivalents at beginning of period	29,819			34,589
Cash and cash equivalents at end of period	$	37,314		$	32,997

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

10

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements (unaudited)

(dollars in thousands, unless otherwise noted)

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

Nature of operations

Chaparral Energy, Inc. and its subsidiaries, (collectively, “we”, “our”, “us”, or the “Company”) are 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, and Kansas.

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, 2012.

The financial information as of September 30, 2013, and for the three and nine months ended September 30, 2013 and 2012, 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 nine months ended September 30, 2013 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2013.

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 September 30, 2013, cash with a recorded balance totaling $36,259 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. 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. Accounts receivable consisted of the following at September 30, 2013 and December 31, 2012:

	September 30, 2013			December 31, 2012
Joint interests	$	35,856		$	19,282
Accrued oil and natural gas sales	61,380			50,814
Derivative settlements	317			8,013
Other	546			472
Allowance for doubtful accounts	(1,636		)	(1,274		)
	$	96,463		$	77,307

11

Inventories

Inventories are comprised of equipment used in developing oil and natural gas properties and oil and natural gas production inventories. Equipment inventory is 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 September 30, 2013 and December 31, 2012 consisted of the following:

	September 30, 2013			December 31, 2012
Equipment inventory	$	9,688		$	8,047
Oil and natural gas product	3,087			3,175
Inventory valuation allowance	(706		)	(712		)
	$	12,069		$	10,510

Oil and natural gas properties

We use the full cost method of accounting for oil and natural gas properties and activities. Accordingly, we capitalize all costs incurred in connection with the exploration for and development of oil and natural gas reserves. Proceeds from the disposition of oil and natural gas properties are accounted for as a reduction in capitalized costs, with no gain or loss generally recognized unless such dispositions involve a significant alteration in the depletion rate. We sold certain oil and gas properties for total cash proceeds of approximately $90,530 and $44,523 subject to post-closing adjustments for the nine months ended September 30, 2013 and 2012, respectively, which did not have a significant impact on our depletion rate. After September 30, 2013, we also sold certain additional oil and gas properties for a total price of approximately $12,500 subject to post-closing adjustments.

On October 11, 2013, we entered into an agreement with Cabot Oil & Gas Corporation to acquire certain oil and gas properties and related assets in the Panhandle Marmaton Play for $160,128 subject to pre- and post-closing adjustments (the “Cabot Acquisition”). We paid $16,013 in earnest money for the Cabot Acquisition with the balance due upon closing, which is expected to occur in the fourth quarter of 2013.

We capitalize internal costs that can be directly identified with exploration and development activities, but do not include any costs related to production, general corporate overhead or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and natural gas wells, including salaries, benefits and other internal costs directly attributable to these activities.

The costs of unevaluated oil and natural gas properties are excluded from amortization until the properties are evaluated. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Work-in-progress costs are included in unevaluated oil and natural gas properties and as of September 30, 2013, include $95,358 of capital costs incurred for undeveloped acreage, $119,181 for the construction of CO₂ delivery pipelines and facilities for which there are no reserves, and $35,487 for wells and facilities in progress pending determination. As of December 31, 2012, work-in-progress costs included capital costs incurred for undeveloped acreage of $64,840 and $84,183 for the construction of CO₂ delivery pipelines and facilities for which there are no reserves and $13,898 for wells and facilities in progress pending determination.

In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related PV-10 value, net of tax considerations, plus the cost of unproved properties not being amortized. The PV-10 value of our reserves as of September 30, 2013 was estimated based on average first day of the month prices of $95.04 per Bbl of oil and $3.60 per Mcf of natural gas for the twelve months ended September 30, 2013. The cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties as of September 30, 2013, and no impairment was necessary. A decline in oil and natural gas prices subsequent to September 30, 2013 could result in ceiling test write-downs in future periods. The amount of any future impairment is difficult to predict, and will depend on the average oil and natural gas prices during each period, the incremental proved reserves added during each period, and additional capital spent.

12

Assets Held for Sale

In the third quarter of 2013, we reassessed the fair value of certain owned drilling rigs classified as assets held for sale. The accounting for these assets is in accordance with ASC 360-10, Property, Plant and Equipment, which requires assets to be carried on the balance sheet at their carrying value or fair value less cost to sell, whichever is less. In determining current fair value, management performed internal estimates of the value of these assets based on prices that would be received on the sale of each rig in an orderly transaction between market participants. As a result of determining current fair value on certain of the assets held for sale, an impairment loss was recorded in the third quarter of 2013 in the amount of $1,090, which was included in the loss on impairment of other assets in the consolidated statements of operations.

Stock-based compensation

Our stock-based compensation programs consist of phantom stock, restricted stock units (“RSU”), and restricted stock awards issued to employees. Generally, we use new shares to grant restricted stock awards, and we cancel restricted shares forfeited or repurchased for tax withholding. Canceled shares are available to be issued as new grants under our 2010 Equity Incentive Plan.

The estimated fair value of the phantom stock and RSU 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 and the Non-Officer Restricted Stock Unit 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 and RSU awards is recognized over the vesting period using the straight-line method and the accelerated method, respectively.

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.

13

Recently adopted accounting pronouncements

In December 2011, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance that requires enhanced disclosures that will enable financial statement users to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. In January 2013, additional guidance was issued which narrows the scope of the disclosure requirements to derivatives, securities borrowings, and securities lending transactions that are either offset or subject to a master netting arrangement. This guidance, which was effective and adopted by us in the first quarter of 2013, resulted in additional disclosures but had no financial impact.

In February 2013, the FASB issued authoritative guidance that requires disclosures of the amounts reclassified out of accumulated other comprehensive income (“AOCI”) by component, including the respective line items of net income if the amount is required to be reclassified to net income in its entirety in the same reporting period. This additional guidance was effective and adopted by us in the first quarter of 2013. As our entire balance in AOCI consists of deferred hedge gains, implementation of the guidance had no significant impact on our financial statement presentation and disclosures.

Recently issued accounting pronouncements

In July 2011, the FASB issued authoritative guidance regarding how health insurers should recognize and classify in their income statements the fees mandated by the Health Care and Education Reconciliation Act (“HCERA”). The HCERA imposes an annual fee upon health insurers for each calendar year beginning on or after January 1, 2014. The annual fee will be allocated to individual entities providing health insurance to employees based on a ratio, as provided for in the HCERA, and is not tax deductible. This guidance specifies that once the entity has provided qualifying health insurance in the calendar year in which the fee is payable, the liability for the entity’s fee should be estimated and recorded in full with a corresponding deferred cost that is amortized to expense on a straight line basis, unless another method better allocates the fee over the calendar year that it is payable. This guidance is effective for calendar years beginning after December 15, 2013, once the fee is instituted. We are currently assessing the impact that this fee and the adoption of the related authoritative guidance will have on our financial statements.

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Note 2: Supplemental disclosures to the consolidated statements of cash flows

Supplemental disclosures to the consolidated statements of cash flows are presented below:

	Nine months ended September 30,
	2013			2012
Net cash provided by operating activities included:
Cash payments for interest	$	70,735		$	71,475
Interest capitalized	(11,670		)	(3,311		)
Cash payments for interest, net of amounts capitalized	$	59,065		$	68,164
Cash payments for income taxes	$	240		$	100
Non-cash investing activities included:
Asset retirement costs capitalized	$	1,036		$	551
Oil and natural gas properties acquired through increase in accounts payable and accrued liabilities	$	8,298		$	38,184

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Note 3: Long-term debt

Long-term debt at September 30, 2013 and December 31, 2012, consisted of the following:

	September 30, 2013		December 31, 2012
9.875% Senior Notes due 2020, net of discount of $5,581 and $5,969 at September 30, 2013 and December 31, 2012, respectively	$	294,419	$	294,031
8.25% Senior Notes due 2021	400,000		400,000
7.625% Senior Notes due 2022, including premium of $5,942 and $6,631 at September 30, 2013 and December 31, 2012, respectively	555,942		556,631
Senior secured revolving credit facility	108,000		25,000
Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 2.54% to 5.46%, due August 2021 through December 2028; collateralized by real property	11,322		12,596
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.94% to 6.79%, due November 2013 through February 2018; collateralized by automobiles, machinery and equipment	5,210		5,144
Capital lease obligations	5,165		—
	1,380,058		1,293,402
Less current maturities	3,322		3,746
	$	1,376,736	$	1,289,656

Senior Notes

The Senior Notes, which, as of September 30, 2013, include our 9.875% Senior Notes due 2020, our 8.25% Senior Notes due 2021, and our 7.625% Senior Notes due 2022, 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 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;

• incur liens on assets;

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

• engage in transactions with 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 indentures 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.

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 Chaparral Biofuels, LLC.

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Senior secured revolving credit facility

In April 2010, we entered into an Eighth Restated Credit Agreement (our “senior secured revolving credit facility”), which is collateralized by our oil and natural gas properties and, as amended, matures on November 1, 2017. The Thirteenth Amendment, effective October 29, 2013, amended our senior secured revolving credit facility to (a) increase our borrowing base from $500,000 to $550,000, (b) automatically increase the borrowing base to $600,000 upon the consummation of the Cabot Acquisition and (c) allow for the incurrence of $300,000 of unsecured senior or subordinated debt meeting the definition of “Additional Permitted Debt” under our senior secured revolving credit facility, (d) permit entering into swap agreements on production from to-be-acquired properties, including the assets to be acquired in the Cabot Acquisition, in notional amounts up to 80% of anticipated proved developed producing production therefrom if otherwise meeting additional necessary requirements under our senior secured revolving credit facility, and (e) increase permitted other debt from $40,000 to $50,000.

Amounts borrowed under our senior secured revolving credit facility are subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base (the “utilization percentage”) and (2) whether we elect to borrow at the Eurodollar rate or the Alternate Base Rate (“ABR”). The entire balance outstanding at September 30, 2013 was subject to the Eurodollar rate. Subsequent to September 30, 2013, we have drawn down an additional $14,000 under our senior secured revolving credit facility. On November 12, 2013, we committed to borrow an additional $25,000 and will receive the funds on November 15, 2013.

The Eurodollar rate 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 that varies depending on our utilization percentage. During the nine months ended September 30, 2013, the applicable margin was 1.50%. 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 loans subject to the ABR 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 0.50%, or (3) the Adjusted LIBO Rate, as defined in our senior secured revolving credit facility, plus 1%, plus a margin that varies depending on our utilization percentage.

Commitment fees range from 0.375% to 0.50%, depending on our utilization percentage. During the nine months ended September 30, 2013, commitment fees accrued at the rate of 0.375% on the unused portion of the borrowing base amount, and were 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 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 4.5 to 1.0 for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter.

We believe we were in compliance with all covenants under our senior secured revolving credit facility as of September 30, 2013.

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.

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.

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Capital Leases

During the third quarter of 2013, we entered into a lease financing agreement with U.S. Bank National Association for approximately $5,200 through the sale and subsequent leaseback of an existing compressor owned by us. The lease financing obligation is for an 84-month term and includes an option to purchase the equipment for a specified price at 72 months as well as an option to purchase the equipment at the end of the lease term for its then-current fair market value. Lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.4%. Minimum lease payments are approximately $625 annually. In October 2013, we finalized an additional lease financing agreement with U.S. Bank National Association for approximately $11,900 on the sale and subsequent leaseback of compressors.

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Note 4: Derivative 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 various types of derivative instruments, including commodity price swaps, costless collars, put options, and basis protection swaps.

For commodity price swaps, we receive a fixed price for the hedged commodity and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

Collars contain a fixed floor price (purchased put) and ceiling price (sold 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 sold put with a price below the floor price of the collar. The sold put option requires us to make a payment to the counterparty if the market price is below the sold put option price. If the market price is greater than the sold 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 sold put option, we are entitled to a net payment equal to the difference between the floor price of the standard collar and the sold put option price if the market price falls below the sold 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 utilizing the value associated with the sale of a put option.

Put options may be purchased from the counterparty by our payment of a cash premium. If the market price is below the put strike price at the settlement date, we will receive a payment from the counterparty. Purchased put options are designed to provide a fixed price floor with the opportunity for upside if commodity prices increase.

We enhance the value of certain oil swaps by combining them with sold puts or put spread contracts. Sold puts require us to make a payment to the counterparty if the market price is below the put strike price at the settlement date. If the market price is greater than the sold put price, the result is the same as it would have been with a swap contract only. A put spread is a combination of a sold put and a purchased put. If the market price falls below the purchased put option price, we will receive the spread between the sold put option price and the purchased put option price from the counterparty. The use of a sold put allows us to receive an above-market swap price while the purchased put provides a measure of downside protection.

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.

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We protect a portion of our natural gas liquids production from price volatility using crude oil derivatives. The following table summarizes our crude oil derivatives outstanding as of September 30, 2013:

		Weighted average fixed price per Bbl
Period and Type of Contract	Volume MBbls	Swaps		Sold puts		Purchased puts		Sold calls
2013
Swaps	510	$	95.54	$	—	$	—	$	—
Three-way collars	900	$	—	$	77.83	$	99.94	$	114.49
2014
Swaps	739	$	92.51	$	—	$	—	$	—
Three-way collars	2,400	$	—	$	75.50	$	93.25	$	101.94
Enhanced swaps	840	$	98.62	$	80.00	$	—	$	—
Put spread enhanced swaps	2,225	$	93.64	$	80.00	$	60.00	$	—
Purchased puts	840	$	—	$	—	$	60.00	$	—
2015
Enhanced swaps	4,918	$	93.35	$	80.00	$	—	$	—

The following tables summarize our natural gas derivative instruments outstanding as of September 30, 2013:

Period and Type of Contract	Volume BBtu	Weighted average fixed price per MMBtu
2013
Natural gas swaps	4,890	$	4.34
Natural gas basis protection swaps	5,390	$	0.20
2014
Natural gas swaps	18,420	$	4.03
Natural gas basis protection swaps	21,550	$	0.24
2015
Natural gas swaps	10,800	$	4.26
Natural gas basis protection swaps	2,400	$	0.18

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Effect of derivative instruments on the consolidated balance sheets

All derivative financial instruments are recorded on the balance sheet at fair value. See Note 5 for additional information regarding fair value measurements. 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 September 30, 2013								As of December 31, 2012
	Assets		Liabilities			Net value			Assets		Liabilities			Net value
Natural gas swaps	$	9,180	$	(281	)	$	8,899		$	13,642	$	(1,487	)	$	12,155
Oil swaps	122		(5,363		)	(5,241		)	4,957		(1,339		)	3,618
Oil collars	3,974		(538		)	3,436			27,411		(1,180		)	26,231
Oil enhanced swaps	2,005		(8,229		)	(6,224		)	—		—			—
Oil purchased puts (1)	185		—			185			—		—			—
Natural gas basis differential swaps	778		(345		)	433			—		(1,599		)	(1,599		)
Total derivative instruments	16,244		(14,756		)	1,488			46,010		(5,605		)	40,405
Less:
Netting adjustments (2)	7,763		(7,763		)	—			2,977		(2,977		)	—
Current portion asset (liability)	4,449		(6,971		)	(2,522		)	42,516		(436		)	42,080
	$	4,032	$	(22	)	$	4,010		$	517	$	(2,192	)	$	(1,675	)

(1) Includes premiums of $664 paid during the second quarter of 2013. No additional premiums have been paid.

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

We discontinued hedge accounting effective April 1, 2010. Net derivative gains attributable to derivatives previously subject to hedge accounting were deferred through AOCI. As of September 30, 2013 and December 31, 2012, respectively, AOCI consists of deferred gains of $8,590 ($5,445 net of tax) and $37,134 ($23,223 net of tax) that will be recognized as gains from oil hedging activities through December 2013 as the hedged production is sold.

Derivative settlements outstanding at September 30, 2013 and December 31, 2012 were as follows:

	September 30, 2013		December 31, 2012
Derivative settlements receivable included in accounts receivable	$	317	$	8,013
Derivative settlements payable included in accounts payable and accrued liabilities	$	3,393	$	41

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Effect of derivative instruments on the consolidated statements of operations

We do not apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as non-hedge derivative gains (losses) in the consolidated statements of operations. Gain from oil hedging activities, which is a component of total revenues in the consolidated statements of operations, consists of the reclassification of hedge gains on discontinued oil hedges from AOCI into net income.

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

	Three months ended						Nine months ended
	September 30,						September 30,
	2013			2012			2013			2012
Change in fair value of commodity price swaps	$	(7,795	)	$	(22,167	)	$	(12,115	)	$	(7,451	)
Change in fair value of collars	(16,057		)	(14,094		)	(22,795		)	20,480
Change in fair value of enhanced swaps and put options	(17,499		)	—			(6,703		)	—
Change in fair value of natural gas basis differential contracts	342			526			2,032			(303		)
(Payments on) receipts from settlement of commodity price swaps	(2,510		)	8,046			2,327			20,022
(Payments on) receipts from settlement of collars	(256		)	3,079			11,300			5,711
Payments on settlement of natural gas basis differential contracts	(55		)	(420		)	(530		)	(1,424		)
	$	(43,830	)	$	(25,030	)	$	(26,484	)	$	37,035

Any premiums paid on derivative contracts will be included in non-hedge derivative gains (losses) as the derivative contracts settle.

Note 5: Fair value measurements

Fair value is defined by the 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.

Fair value measurements 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 as follows:

• Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.

• Level 2 inputs include quoted prices for identical or similar instruments in markets that are not active and inputs other than quoted prices that are observable for the asset or liability. 

• 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.

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.

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Recurring fair value measurements

Our financial instruments recorded at fair value on a recurring basis consist of commodity derivative contracts (see Note 4). We have no Level 1 assets or liabilities as of September 30, 2013 or December 31, 2012. Our derivative contracts classified as Level 2 as of September 30, 2013 and December 31, 2012 consist of commodity price swaps and basis protection swaps, which are valued using an income approach. 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.

As of September 30, 2013, our derivative contracts classified as Level 3 consisted of three-way collars, enhanced swaps, and purchased puts. As of December 31, 2012, our derivative contracts classified as Level 3 consisted of three-way collars. The fair value of these contracts is developed by a third-party pricing service using a proprietary valuation model, which we believe incorporates the assumptions that market participants would have made at the end of each period. Observable inputs include contractual terms, published forward pricing curves, and yield curves. Significant unobservable inputs are implied volatilities. Significant increases (decreases) in implied volatilities in isolation would result in a significantly higher (lower) fair value measurement. We review these valuations and the changes in the fair value measurements for reasonableness.

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. If available, we use our counterparties’ credit default swap values or the spread between the risk-free interest rate and the yield on our counterparties’ publicly traded debt having similar maturities to our derivative contracts as the measure of our counterparties’ nonperformance risk. As of September 30, 2013 and December 31, 2012, the rate reflecting our nonperformance risk was 1.50% and 1.50%, respectively. The weighted average rate reflecting our counterparties’ nonperformance risk was approximately 0.44% and 0.32% as of September 30, 2013 and December 31, 2012, respectively.

The fair value hierarchy for our financial assets and liabilities is shown by the following table:

	As of September 30, 2013									As of December 31, 2012
	Derivative assets			Derivative liabilities			Net assets (liabilities)			Derivative assets			Derivative liabilities			Net assets (liabilities)
Significant other observable inputs (Level 2)	$	10,080		$	(5,989	)	$	4,091		$	18,599		$	(4,425	)	$	14,174
Significant unobservable inputs (Level 3)	6,164			(8,767		)	(2,603		)	27,411			(1,180		)	26,231
Netting adjustments (1)	(7,763		)	7,763			—			(2,977		)	2,977			—
	$	8,481		$	(6,993	)	$	1,488		$	43,033		$	(2,628	)	$	40,405

(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 our derivative instruments classified as Level 3 in the fair value hierarchy during the nine months ended September 30, 2013 and 2012 were: 

	For the nine months ended September 30,
Net derivative assets (liabilities)	2013			2012
Beginning balance	$	26,231		$	5,049
Realized and unrealized (losses) gains included in non-hedge derivative (losses) gains	(18,198		)	26,191
Purchases	664			—
Settlements received	(11,300		)	(5,711		)
Ending balance	$	(2,603	)	$	25,529
(Losses) gains relating to instruments still held at the reporting date included in non-hedge derivative (losses) gains for the period	$	(8,776	)	$	21,033

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Nonrecurring fair value measurements

Additions to the asset and liability associated with our asset retirement obligations are measured at fair value on a nonrecurring basis. 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 nine months of 2013 and 2012 were escalated using an annual inflation rate of 2.95% and 2.95%, respectively, and discounted using our credit-adjusted risk-free interest rate of 6.90% and 6.70%, respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. During the nine months ended September 30, 2013 and 2012, additions to our asset retirement obligations were $1,036 and $551, respectively. See Note 6 for additional information regarding our asset retirement obligations.

Fair value of other financial instruments

Our significant financial instruments, other than derivatives, consist primarily of cash and cash equivalents, accounts receivable, accounts payable, and long-term debt. We believe the carrying values of cash and cash equivalents, accounts receivable, and accounts payable approximate fair values due to the short-term maturities of these instruments.

The carrying value and estimated fair value of our long-term debt at September 30, 2013 and December 31, 2012 were as follows:

	September 30, 2013				December 31, 2012
Level 2	Carrying value		Estimated fair value		Carrying value		Estimated fair value
9.875% Senior Notes due 2020	$	294,419	$	338,625	$	294,031	$	341,250
8.25% Senior Notes due 2021	400,000		424,000		400,000		434,000
7.625% Senior Notes due 2022	555,942		566,500		556,631		574,750
Senior secured revolving credit facility	108,000		108,000		25,000		25,000
Other secured long-term debt and capital leases	21,697		21,697		17,740		17,740
	$	1,380,058	$	1,458,822	$	1,293,402	$	1,392,740

The fair value of our Senior Notes was estimated based on quoted market prices. The carrying value of our senior secured revolving credit facility approximates fair value because it has a variable interest rate and incorporates a measure of our credit risk. The carrying value of our other secured long-term debt approximates fair value because the rates are comparable to those at which we could currently borrow under similar terms.

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Counterparty credit risk

Our derivative contracts are executed with institutions, or affiliates of institutions, that are parties to our senior secured revolving credit facility at the time of execution, and we believe the credit risks associated with all of these institutions are acceptable. We do not require collateral or other security from counterparties to support derivative instruments. Master agreements are in place with each of our derivative counterparties which provide for net settlement in the event of default or termination of the contracts under each respective agreement. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivatives. Our loss is further limited as any amounts due from a defaulting counterparty that is a lender, or an affiliate of a lender, under our senior secured revolving credit facility can be offset against amounts owed to such counterparty lender under our senior secured revolving credit facility. As of September 30, 2013, the counterparties to our open derivative contracts consisted of ten financial institutions, of which nine were subject to our rights of offset under our senior secured revolving credit facility.

The following table summarizes our derivative assets and liabilities which are offset in the balance sheet under our master netting agreements. It also reflects the amounts outstanding under our senior secured revolving credit facility that are available to offset our net derivative assets due from counterparties that are lenders under our senior secured revolving credit facility.

	Offset in the consolidated balance sheets									Gross amounts not offset in the consolidated balance sheets
	Gross assets (liabilities)			Offsetting assets (liabilities)			Net assets (liabilities)			Amounts outstanding under senior secured revolving credit facility			Net amount
As of September 30, 2013
Derivative assets	$	16,244		$	(8,459	)	$	7,785		$	(7,239	)	$	546
Derivative liabilities	(14,756		)	8,459			(6,297		)	—			(6,297		)
	$	1,488		$	—		$	1,488		$	(7,239	)	$	(5,751	)
As of December 31, 2012
Derivative assets	$	46,010		$	(4,721	)	$	41,289		$	(9,180	)	$	32,109
Derivative liabilities	(5,605		)	4,721			(884		)	—			(884		)
	$	40,405		$	—		$	40,405		$	(9,180	)	$	31,225

We did not post additional collateral under any of these contracts as all of our counterparties are secured by the collateral under our senior secured revolving credit facility. Payment on our derivative contracts would be accelerated in the event of a default on our senior secured revolving credit facility. The aggregate fair value of our derivative liabilities was $14,756 at September 30, 2013.

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Note 6: Asset retirement obligations

The following table provides a summary of our asset retirement obligation activity during the nine months ended September 30, 2013 and 2012.

	For the nine months ended September 30,
	2013			2012
Beginning balance	$	49,214		$	46,492
Liabilities incurred in current period	1,036			551
Liabilities settled and disposed in current period	(4,969		)	(1,484		)
Accretion expense	2,968			2,962
	48,249			48,521
Less current portion	2,900			2,900
	$	45,349		$	45,621

See Note 5 for additional information regarding fair value measurements.

Note 7: Stock-based compensation

Phantom Stock Plan and Restricted Stock Unit 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 “Phantom 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. Phantom shares are cash-settled within 120 days of the vesting date.

Effective March 1, 2012, we implemented a Non-Officer Restricted Stock Unit Plan (the “RSU Plan”) to create incentives to motivate Participants to put forth maximum effort toward the success and growth of the Company and to enable us to attract and retain experienced individuals who by their position, ability and diligence are able to make important contributions to the Company’s success. The RSU Plan is intended to replace the Phantom Plan. Although the Phantom Plan remains in effect, we do not expect to make any further awards under the Phantom Plan.

Restricted stock units may be awarded to Participants in total up to 2% of the fair market value of the Company. Under the RSU Plan, awards generally vest in equal annual increments over a three-year period. RSU awards may also vest following a Participant’s termination of employment in combination with the occurrence of a change of control event, as specified in the RSU Plan. RSU awards are cash-settled, generally within 120 days of the vesting date.

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A summary of our phantom stock and RSU activity during the nine months ended September 30, 2013 is presented in the following table:

	Phantom Plan						RSU Plan
	Weighted average grant date fair value		Phantom shares		Vest date fair value		Weighted average grant date fair value		Restricted Stock Units		Vest date fair value
	($ per share)						($ per share)
Unvested and outstanding at January 1, 2013	$	16.87	84,764				$	17.12	151,909
Granted	$	—	—				$	12.45	291,253
Vested	$	16.20	(21,260	)	$	273	$	17.12	(50,246	)	$	626
Forfeited	$	17.52	(9,388	)			$	14.35	(55,051	)
Unvested and outstanding at September 30, 2013	$	17.03	54,116				$	13.54	337,865

Based on an estimated fair value of $10.68 per phantom share and RSU as of September 30, 2013, the aggregate intrinsic value of the unvested phantom shares and RSUs outstanding was $4,186.

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 Vested” awards) and shares that are subject to market and performance vesting conditions (the “Performance Vested” awards). The Time Vested 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 Vested awards vest in the event of a Transaction that achieves certain market targets as defined in the 2010 Plan. Any shares of Performance Vested awards not vested on a Separation Date (as defined in the 2010 Plan) will be forfeited as of the Separation Date.

Effective January 1, 2013, we amended and restated all outstanding Performance Vested awards to reflect that: (i) those shares which would vest if CCMP receives net proceeds from a Transaction that yields a return of at least 400% per share were removed from the initial Performance Vested awards and an equal number of Time Vested shares were granted effective as of January 1, 2013; and (ii) the return on investment targets applicable to the remaining number of Performance Vested shares and to any new grants of Performance Vested shares were set at the following levels:

Return on Investment Target	Target Shares Vested
175% per share	20% of shares multiplied by the Vesting Fraction
200% per share	20% of shares multiplied by the Vesting Fraction
250% per share	20% of shares multiplied by the Vesting Fraction
300% per share	20% of shares multiplied by the Vesting Fraction
350% per share	20% of shares multiplied by the Vesting Fraction

This modification changed the classification of the canceled and reissued awards from equity to liability instruments and resulted in estimated incremental compensation cost of $4,322, which will be recognized over the five-year requisite service period using the accelerated method. Incremental compensation cost is measured as the excess of the fair value of the modified award over the fair value of the original award immediately before the modification, and will be adjusted for changes in the fair value of the modified awards in each period until the awards are vested or forfeited.

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A summary of our restricted stock activity during the nine months ended September 30, 2013 is presented below: 

	Time Vested						Performance Vested
	Weighted average grant date fair value		Restricted shares		Vest date fair value		Weighted average grant date fair value		Restricted shares
	($ per share)						($ per share)
Unvested and outstanding at January 1, 2013	$	651.97	9,481				$	324.48	55,824
Granted	$	626.02	2,839				$	181.59	5,217
Vested	$	679.09	(2,030	)	$	1,256	$	—	—
Forfeited	$	620.01	(1,779	)			$	340.23	(3,171	)
Modified	$	626.00	11,169				$	324.47	(11,169	)
Unvested and total outstanding at September 30, 2013	$	633.58	19,680				$	307.45	46,701

During the nine months ended September 30, 2013 and 2012, respectively, we repurchased and canceled 873 and 764 vested shares, primarily for tax withholding, and we expect to repurchase approximately 2,000 restricted shares vesting during the next twelve months. Based on an estimated fair value of $626.00 per Time Vested restricted share, the aggregate intrinsic value of the unvested Time Vested restricted shares outstanding was $12,320 as of September 30, 2013.

Stock-based compensation cost

Compensation cost is calculated net of forfeitures, which are estimated based on our historical and expected turnover rates. 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.

A portion of stock-based compensation cost associated with 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. We recognized stock-based compensation expense as follows for the periods indicated:

	Three months ended						Nine months ended
	September 30,						September 30,
	2013			2012			2013			2012
Stock-based compensation cost	$	2,045		$	1,725		$	4,620		$	4,773
Less: stock-based compensation cost capitalized	(505		)	(605		)	(1,440		)	(1,715		)
Stock-based compensation expense	$	1,540		$	1,120		$	3,180		$	3,058

Payments for stock-based compensation were $135 and $120 during the third quarters of 2013 and 2012, respectively, and were $1,433 and $981 during the nine months ended September 30, 2013 and 2012, respectively. As of September 30, 2013 and December 31, 2012, accrued payroll and benefits payable included $4,173 and $2,636, respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized compensation cost of approximately $17,383 is expected to be recognized over a weighted average period of 3.10 years.

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Note 8: Common stock

The following is a summary of the changes in our common shares outstanding during the nine months ended September 30, 2013:

	Common Stock
	Class A		Class B	Class C	Class D	Class E	Class F	Class G	Total
Shares outstanding at January 1, 2013	67,991		357,882	209,882	279,999	504,276	1	3	1,420,034
Restricted stock issuances	8,056		—	—	—	—	—	—	8,056
Restricted stock repurchased	(873	)	—	—	—	—	—	—	(873	)
Restricted stock forfeitures	(4,950	)	—	—	—	—	—	—	(4,950	)
Shares outstanding at September 30, 2013	70,224		357,882	209,882	279,999	504,276	1	3	1,422,267

Note 9: Related party transactions

CHK Energy Holdings, Inc., 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 September 30,						Nine months ended September 30,
	2013			2012			2013			2012
Revenues	$	2,449		$	831		$	5,289		$	2,600
Joint interest billings	$	(453	)	$	(828	)	$	(1,764	)	$	(4,295	)

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 September 30,						Nine months ended September 30,
	2013			2012			2013			2012
Revenues	$	(1,549	)	$	(1,062	)	$	(3,248	)	$	(2,521	)
Joint interest billings	$	1,084		$	3,093		$	8,969		$	7,737

Amounts receivable from and payable to Chesapeake at September 30, 2013 and December 31, 2012 were as follows:

	September 30, 2013		December 31, 2012
Amounts receivable from Chesapeake	$	1,568	$	2,071
Amounts payable to Chesapeake	$	87	$	864

Note 10: Commitments and contingencies

Standby letters of credit (“Letters”) available under our senior secured revolving credit facility 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 September 30, 2013 and December 31, 2012. Interest on each Letter accrues at the lender’s prime rate plus applicable margin 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 nine months ended September 30, 2013 or 2012.

Naylor Farms, Inc., individually and as class representative on behalf of all similarly situated persons 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 natural 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 liability on the claims and raised arguments and defenses that, if accepted by the Court, will result in no loss to us. The case was stayed on August 9, 2012 to allow the U.S. Court of Appeals for the Tenth Circuit to decide two unrelated cases

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that had issues similar to this case. The Tenth Circuit issued its opinions in those unrelated cases on July 9, 2013 and mandates were issued July 31, 2013. On or about October 1, 2013, the Court lifted the stay and entered a new scheduling order. The parties are conducting additional discovery and Plaintiff’s Motion for Class Certification is due August 10, 2014. Because a class has not been certified, we are not yet able to estimate a possible loss, or range of possible loss, if any.

Amanda Dodson, individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C.

On May 10, 2013, Amanda Dodson (the “Plaintiff”), filed a complaint against us, alleging claims on behalf of herself and all non-governmental Oklahoma citizens who are royalty interest owners in oil and natural gas wells we operate in Oklahoma. The Petition was not served until July 2, 2013. The Plaintiff asserts class claims seeking recovery for underpayment of royalties, alleging entitlement to actual damages in an unspecified amount. The Plaintiff also requests allowable interest, punitive damages, injunctive relief, an accounting, disgorgement damages, and an award of attorney fees and costs. We have denied liability on the claims and raised arguments and defenses that, if accepted by the Court, will result in no loss to us. At this time, a class has not been certified and discovery has yet to begin. As such, we are not yet able to estimate a possible loss, or range of possible loss, if any.

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.

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

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

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

Overview

Founded in 1988, we are an independent oil and natural gas exploration and production company headquartered in Oklahoma City, Oklahoma and is one of the largest oil producers in the state. In recent years, we have capitalized on our sustained success in the active Mid-Continent area expanding our holdings to become a leading player in both the liquids-rich Northern Oklahoma Mississippian and the oil-rich Panhandle Marmaton plays. In addition, we have a leadership position in CO₂ EOR and are now the third largest CO₂ EOR producer in the United States based on the number of active projects. This position is underscored by our activity in the North Burbank Unit in Osage County, Oklahoma which is the single largest oil recovery unit in the state.

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, 2012 reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 19%, 14% and 12% 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.

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During the third quarter of 2013, production increased 3% to 2,477 MBoe compared to production of 2,401 MBoe during the third quarter of 2012, primarily due to our drilling activity. This increase in production, combined with a 19% increase in the average sales price before hedging, resulted in a 23% increase in revenue from oil and natural gas sales in the third quarter of 2013 compared to the same period in 2012. This increase was offset partially by an $18.8 million increase in our non-hedge derivative loss, which was primarily due to the significant volatility of oil and natural gas prices and to changes in our outstanding derivatives contracts during these periods. As a result of these and other factors, we reported a net loss of $2.6 million during the third quarter of 2013 compared to a net loss of $4.9 million for the comparable period in 2012.

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:

• Cabot Acquisition. On October 11, 2013, we entered into an agreement with Cabot Oil & Gas Corporation to acquire net production of approximately 2,000 Boe per day and 66,000 net acres in the Panhandle Marmaton Play for $160.1 million subject to pre- and post-closing adjustments (the “Cabot Acquisition”). We paid $16.0 million in earnest money for the acquisition with the balance due upon closing, which is expected to occur in the fourth quarter of 2013.

• Amendment to senior secured revolving credit facility. On October 29, 2013, our senior secured revolving credit facility was amended to, among other things, (a) increase our borrowing base from $500.0 million to $550.0 million, (b) automatically increase the borrowing base to $600.0 million upon the consummation of the Cabot Acquisition and (c) allow for the incurrence of $300.0 million of unsecured senior or subordinated debt meeting the definition of “Additional Permitted Debt” under the senior secured revolving credit facility, (d) permit entering into swap agreements on production from to-be-acquired properties, including the assets to be acquired in the Cabot Acquisition, in notional amounts up to 80% of anticipated proved developed producing production therefrom if otherwise meeting additional necessary requirements under our senior secured revolving credit facility, and (e) increase permitted other debt from $40.0 million to $50.0 million.

• Expanded capital expenditures. In the second quarter, we expanded our 2013 oil and natural gas property capital expenditures budget to $498.0 million to allow us to take advantage of additional leasehold acquisition and drilling opportunities in our repeatable resource plays. We expect to fund the expanded budget through net cash provided by operations, borrowings under our senior secured revolving credit facility, and sales of non-strategic properties.

• Asset sales. During 2013, we have divested certain oil and gas properties for cash proceeds of approximately $103.1 million subject to post-closing adjustments which includes $12.5 million sold subsequent to September 30, 2013. The properties included in the sales accounted for approximately 3% and 6% of our total production during the nine months ended September 30, 2013 and 2012, respectively.

• Stock-based compensation. In the first quarter of 2013, we amended and restated all outstanding Performance Vested awards under the 2010 Plan awards to reflect that: (i) those shares which would vest if CCMP receives net proceeds from a Transaction that yields a return of at least 400% per share were removed from the initial Performance Vested awards and an equal number of Time Vested shares were granted effective as of January 1, 2013; and (ii) the return on investment targets applicable to the remaining number of Performance Vested shares and to any new grants of Performance Vested shares were revised. These modifications resulted in incremental compensation cost of $4.3 million, which will be recognized over the five-year requisite service period using the accelerated method.

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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				Percentage change		Nine months ended				Percentage change
	September 30,						September 30,
	2013		2012				2013		2012
Oil and natural gas sales (in thousands)
Oil (1)	$	144,634	$	116,478	24.2	%	$	380,127	$	338,904	12.2	%
Natural gas	16,989		14,737		15.3	%	53,362		35,548		50.1	%
Total	$	161,623	$	131,215	23.2	%	$	433,489	$	374,452	15.8	%
Production
Oil (MBbls) (1)	1,651		1,530		7.9	%	4,664		4,174		11.7	%
Natural gas (MMcf)	4,956		5,228		(5.2	)%	15,210		14,643		3.9	%
MBoe	2,477		2,401		3.2	%	7,199		6,615		8.8	%
Average sales prices (excluding derivative settlements)
Oil per Bbl (1)	$	87.60	$	76.13	15.1	%	$	81.50	$	81.19	0.4	%
Natural gas per Mcf	$	3.43	$	2.82	21.6	%	$	3.51	$	2.43	44.4	%
Boe	$	65.25	$	54.65	19.4	%	$	60.22	$	56.61	6.4	%

(1) Includes natural gas liquids.

Oil and natural gas revenues increased significantly during the three months ended September 30, 2013 compared to the three months ended September 30, 2012 primarily due to a 19% increase in the average price per Boe combined with a 3% increase in sales volumes. Production for the three months ended September 30, 2013 increased compared to the three months ended September 30, 2012 primarily due to our drilling and development activity in our Northern Oklahoma Mississippi Play and Panhandle Marmaton Play.

Oil and natural gas revenues increased significantly during the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012 primarily due to a 9% increase in sales volumes combined with a 6% increase in the average price per Boe. Production for the nine months ended September 30, 2013 increased significantly compared to the nine months ended September 30, 2012 primarily due to our drilling and development activity in our Northern Oklahoma Mississippi Play and Panhandle Marmaton Play.

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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					Nine months ended
	September 30, 2013 vs. 2012					September 30, 2013 vs. 2012
(in thousands)	Sales change			Percentage change in sales		Sales change		Percentage change in sales
Change in oil sales due to:
Prices	$	18,944		16.3	%	$	1,438	0.5	%
Production	9,212			7.9	%	39,785		11.7	%
Total change in oil sales	$	28,156		24.2	%	$	41,223	12.2	%
Change in natural gas sales due to:
Prices	$	3,019		20.5	%	$	16,438	46.2	%
Production	(767		)	(5.2	)%	1,376		3.9	%
Total change in natural gas sales	$	2,252		15.3	%	$	17,814	50.1	%

Production volumes by area were as follows (MBoe):

	Three months ended		Percentage change		Nine months ended		Percentage change
	September 30,				September 30,
	2013	2012			2013	2012
Enhanced Oil Recovery Project Areas	377	334	12.9	%	1,135	1,000	13.5	%
Mid-Continent Area	1,680	1,573	6.8	%	4,766	4,071	17.1	%
Permian Basin Area	255	285	(10.5	)%	788	873	(9.7	)%
Other	165	209	(21.1	)%	510	671	(24.0	)%
Total	2,477	2,401	3.2	%	7,199	6,615	8.8	%

Production in our EOR Project Areas increased primarily due to our ongoing drilling and CO₂ injection activities in our Booker and Farnsworth Area Units. Production in our Mid-Continent Area increased primarily due to our drilling and development activity in our Northern Oklahoma Mississippi Play and Panhandle Marmaton Play. The decrease in production in the Permian Basin Area is primarily due to the natural decline in production from natural gas wells in the Haley area.

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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 various types of derivative instruments, including commodity price swaps, costless collars, put options, and basis protection swaps.

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 on realized prices:

	Three months ended						Nine months ended
	September 30,						September 30,
	2013			2012			2013			2012
Oil (per Bbl)(1):
Before derivative settlements	$	87.60		$	76.13		$	81.50		$	81.19
After derivative settlements	$	84.12		$	78.89		$	82.97		$	82.09
Post-settlement to pre-settlement price	96.0		%	103.6		%	101.8		%	101.1		%
Natural gas (per Mcf):
Before derivative settlements	$	3.43		$	2.82		$	3.51		$	2.43
After derivative settlements	$	4.02		$	4.06		$	3.92		$	3.83
Post-settlement to pre-settlement price	117.2		%	144.0		%	111.7		%	157.6		%

(1) Includes natural gas liquids.

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.

(in thousands)	September 30, 2013			December 31, 2012
Derivative assets (liabilities):
Natural gas swaps	$	8,899		$	12,155
Oil swaps	(5,241		)	3,618
Oil collars	3,436			26,231
Oil enhanced swaps	(6,224		)	—
Oil purchased puts(1)	185			—
Natural gas basis differential swaps	433			(1,599		)
Net derivative assets	$	1,488		$	40,405

(1) Includes premiums of $0.7 million paid during the second quarter of 2013. No premiums have been paid since.

We discontinued hedge accounting effective April 1, 2010. Net derivative gains attributable to derivatives previously subject to hedge accounting were deferred through accumulated other comprehensive income (“AOCI”). As of September 30, 2013 and December 31, 2012, respectively, AOCI consists of deferred gains of $8.6 million ($5.4 million net of tax) and $37.1 million ($23.2 million net of tax) that will be recognized as gains from oil hedging activities through December 2013 as the hedged production is sold.

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We no longer apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as non-hedge derivative gains (losses) in the consolidated statements of operations. Gain from oil hedging activities, which is a component of total revenues in the consolidated statements of operations, consists of the reclassification of hedge gains on discontinued oil hedges from AOCI into net income.

The effects of derivative activities on our results of operations and cash flows were as follows for the periods indicated:

	Three months ended September 30,
	2013						2012
(in thousands)	Non-cash fair value adjustment			Cash receipts (payments)			Non-cash fair value adjustment			Cash receipts (payments)
Gain from oil hedging activities	$	9,032		$	—		$	11,468		$	—
Non-hedge derivative (losses) gains:
Oil swaps, collars, enhanced swaps and puts	$	(40,714	)	$	(5,754	)	$	(23,964	)	$	4,217
Natural gas swaps	(637		)	2,988			(12,297		)	6,908
Natural gas basis differential contracts	342			(55		)	526			(420		)
Non-hedge derivative (losses) gains	$	(41,009	)	$	(2,821	)	$	(35,735	)	$	10,705
Total (losses) gains from derivative activities	$	(31,977	)	$	(2,821	)	$	(24,267	)	$	10,705
	Nine months ended September 30,
	2013						2012
(in thousands)	Non-cash fair value adjustment			Cash receipts (payments)			Non-cash fair value adjustment			Cash receipts (payments)
Gain from oil hedging activities	$	28,544		$	—		$	35,777		$	—
Non-hedge derivative (losses) gains:
Oil swaps, collars, enhanced swaps and puts	$	(38,357	)	$	6,837		$	31,992		$	3,745
Natural gas swaps	(3,256		)	6,790			(18,963		)	21,988
Natural gas basis differential contracts	2,032			(530		)	(303		)	(1,424		)
Non-hedge derivative (losses) gains	$	(39,581	)	$	13,097		$	12,726		$	24,309
Total (losses) gains from derivative activities	$	(11,037	)	$	13,097		$	48,503		$	24,309

We reclassified into earnings gains of $9.0 million and $11.5 million, respectively, during the third quarters of 2013 and 2012, and gains of $28.5 million and $35.8 million, respectively, during the nine months ended September 30, 2013 and September 30, 2012. These gains were associated with oil swaps for which hedge accounting was previously discontinued.

We recognized net non-hedge derivative losses of $43.8 million and $25.0 million, respectively, during the third quarters of 2013 and 2012. We recognized net non-hedge derivative losses of $26.5 million during the nine months ended September 30, 2013 compared to net non-hedge derivative gains of $37.0 million during the nine months ended September 30, 2012. The fluctuation in non-hedge derivative gains (losses) from period to period is due primarily to the significant volatility of oil and natural gas prices and to changes in our outstanding derivative contracts during these periods.

Total (losses) gains on derivative activities recognized in our consolidated statements of operations were $(34.8) million and $(13.6) million, respectively, during the third quarters of 2013 and 2012, and were $2.1 million and $72.8 million, respectively, during the nine months ended September 30, 2013 and September 30, 2012.

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Lease operating expenses 

	Three months ended September 30,				Percentage change		Nine months ended September 30,				Percentage change
	2013		2012				2013		2012
Lease operating expenses (in thousands)	$	37,306	$	35,278	5.7	%	$	104,232	$	98,946	5.3	%
Lease operating expenses per Boe	$	15.06	$	14.69	2.5	%	$	14.48	$	14.96	(3.2	)%

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 $2.0 million, or $0.37 per Boe, during the three months ended September 30, 2013, compared to the three months ended September 30, 2012, primarily due to the incremental cost of oil field goods and services associated with net wells added largely offset by decreased operating expenses due to the divestiture of certain non-core assets.

Our lease operating expenses increased by $5.3 million during the nine months ended September 30, 2013, compared to the nine months ended September 30, 2012, primarily due to the incremental cost of oil field goods and services associated with net wells added partially offset by decreased operating expenses due to the divestiture of certain non-core assets. Our lease operating expenses on a Boe basis, however, decreased to $14.48 during the nine months ended September 30, 2013 from $14.96 during the nine months ended September 30, 2012. The decrease of 3% on a Boe basis is primarily attributable to the increase in overall production volumes between periods.

Production taxes (which include ad valorem taxes) 

	Three months ended September 30,				Percentage change		Nine months ended September 30,				Percentage change
	2013		2012				2013		2012
Production taxes (in thousands)	$	8,831	$	8,748	0.9	%	$	25,299	$	24,258	4.3	%
Production taxes per Boe	$	3.57	$	3.64	(1.9	)%	$	3.51	$	3.67	(4.4	)%

Production taxes generally change in proportion to oil and natural gas sales. Our production taxes were relatively flat during the three months ended September 30, 2013 compared to the three months ended September 30, 2012 primarily due to the 19% increase in averaged realized prices combined with the 3% increase in sales volumes largely offset by lower tax rates on our horizontal wells. Production taxes per Boe during the three months ended September 30, 2013 decreased slightly compared to the three months ended September 30, 2012 primarily due to the increase in overall production volumes between periods combined with lower tax rates on our horizontal wells.

The increase in production taxes during the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012 was primarily due to the 9% increase in sales volumes combined with the 6% increase in average realized prices offset partially by lower tax rates on our horizontal wells. The decreases in production taxes per Boe during the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012 was primarily due to the increase in overall production volumes between periods combined with lower tax rates on our horizontal wells.

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

	Three months ended September 30,				Percentage change		Nine months ended September 30,				Percentage change
	2013		2012				2013		2012
DD&A (in thousands):
Oil and natural gas properties	$	44,416	$	40,702	9.1	%	$	129,993	$	108,993	19.3	%
Property and equipment	2,206		2,726		(19.1	)%	6,478		7,852		(17.5	)%
Accretion of asset retirement obligation	960		993		(3.3	)%	2,968		2,962		0.2	%
Total DD&A	$	47,582	$	44,421	7.1	%	$	139,439	$	119,807	16.4	%
DD&A per Boe:
Oil and natural gas properties	$	17.93	$	16.95	5.8	%	$	18.06	$	16.48	9.6	%
Other fixed assets	$	1.28	$	1.55	(17.4	)%	$	1.31	$	1.63	(19.6	)%
Total DD&A per Boe	$	19.21	$	18.50	3.8	%	$	19.37	$	18.11	7.0	%

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 $3.7 million for the third quarter of 2013 compared to the third quarter of 2012, of which $2.4 million was due to a higher rate per equivalent unit of production and $1.3 million was due to an increase in production. Our DD&A rate per equivalent unit of production increased $0.98 to $17.93 per Boe for the third quarter of 2013 primarily due to higher cost reserve additions and higher estimated future development costs for proved undeveloped reserves.

DD&A on oil and natural gas properties increased $21.0 million for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012, of which $11.4 million was due to a higher rate per equivalent unit of production and $9.6 million was due to an increase in production. Our DD&A rate per equivalent unit of production increased $1.58 to $18.06 per Boe for the nine months ended September 30,2013 primarily due to higher cost reserve additions and higher estimated future development costs for proved undeveloped reserves combined with a decrease in reserves during the first quarter of 2013 compared to the first quarter of 2012 resulting from lower commodity prices.

Impairment of other assets. During the three and nine months ended September 30, 2013, we recognized $1.1 million of impairment losses on certain of our owned drilling rigs due to our expectation that these may not sell at a price that will exceed their carrying values.

General and administrative expenses (“G&A”) 

	Three months ended September 30,						Percentage change		Nine months ended September 30,						Percentage change
	2013			2012					2013			2012
G&A (in thousands):
Gross G&A expenses	$	17,938		$	17,530		2.3	%	$	52,951		$	52,790		0.3	%
Capitalized exploration and development costs	(4,873		)	(4,652		)	4.8	%	(14,325		)	(13,625		)	5.1	%
Net G&A expenses	$	13,065		$	12,878		1.5	%	$	38,626		$	39,165		(1.4	)%
Average G&A expense per Boe	$	5.27		$	5.36		(1.7	)%	$	5.37		$	5.92		(9.3	)%

G&A expenses for the three months ended September 30, 2013 increased 2% compared to the three months ended September 30, 2012 primarily due to increased compensation and benefit costs related to the competitive nature of our market and our increased activity offset partially by decreased professional services related to certain projects and initiatives that phased out by the end of 2012.  Our G&A expenses on a Boe basis decreased slightly for the three months ended September 30, 2013 compared to the same period in 2012 due primarily to the increase in overall production volumes between periods.

G&A expenses decreased slightly for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012 primarily due to decreased professional services related to certain projects and initiatives that phased out by the end of 2012 offset partially by increased compensation and benefit costs related to the competitive nature of our market

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and our increased activity and increased technology costs related primarily to new software licenses.  Our G&A expenses on a Boe basis decreased by $0.55 for the nine months ended September 30, 2013 compared to the same period in 2012 due primarily to these same factors and the increase in overall production volumes between periods.

Other income and expenses

Interest expense. The following table presents interest expense for the periods indicated:

	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2013			2012			2013			2012
8.875% Senior Notes due 2017	$	—		$	—		$	—		$	10,421
9.875% Senior Notes due 2020	7,668			7,642			22,985			22,908
8.25% Senior Notes due 2021	8,409			8,396			25,218			25,179
7.625% Senior Notes due 2022	10,524			7,758			31,552			12,849
Senior secured revolving credit facility	411			391			901			700
Bank fees and other interest	1,182			1,282			3,579			3,920
Capitalized interest	(4,120		)	(1,382		)	(11,670		)	(3,311		)
Total interest expense	$	24,074		$	24,087		$	72,565		$	72,666
Average long-term borrowings	$	1,362,118		$	1,196,051		$	1,338,863		$	1,095,625

Total interest expense for the three and nine months ended September 30, 2013 was relatively flat compared to the same periods in 2012 as our increased levels of borrowing were offset by higher capitalized interest, primarily associated with the construction of CO₂ delivery pipelines and facilities.

Loss on extinguishment of debt. On May 2, 2012, we issued $400.0 million aggregate principal amount of 7.625% Senior Notes maturing on November 15, 2022. Net proceeds from the 7.625% Senior Notes were used to consummate a tender offer for all of our 8.875% Senior Notes due 2017, to redeem the 8.875% Senior Notes not purchased in the tender offer, and for general corporate purposes. During the second quarter of 2012, we recorded a loss of $21.7 million loss associated with the refinancing of our 8.875% Senior Notes, including $15.8 million in repurchase- and redemption-related fees and a $5.9 million write off of deferred financing costs and unaccreted discount.

Liquidity and capital resources

Historically, our primary sources of liquidity have been cash generated from our operations, debt, and private equity sales. As of September 30, 2013, we had cash and cash equivalents of $37.3 million and had borrowed $108.0 million under our senior secured revolving credit facility with a borrowing base of $500.0 million. Subsequent to September 30, 2013, we have drawn down an additional $14.0 million under our senior secured revolving credit facility. On November 12, 2013, we committed to borrow an additional $25.0 million and will receive the funds on November 15, 2013.

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.

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Covenants set forth in the indentures for our Senior Notes, including the Adjusted Consolidated Net Tangible Asset debt incurrence test (the “ACNTA test”), limit the amount of secured debt we can incur. Certain thresholds set forth in the ACNTA test are principally reliant upon the levels of commodity prices for crude oil and natural gas at specified dates. The amount of secured debt permitted under our Senior Notes is set at a minimum of $500.0 million. We have the ability to borrow under our senior secured revolving credit facility, subject to 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 the last day of such applicable fiscal quarter. As of November 14, 2013, our availability under the borrowing base was limited to $352.2 million based on the Consolidated Net Debt to Consolidated EBITDAX ratio.

Sources and uses of cash

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

	Nine months ended
	September 30,
(in thousands)	2013			2012
Cash flows provided by operating activities	$	198,484		$	138,977
Cash flows used in investing activities	(277,946		)	(309,714		)
Cash flows provided by financing activities	86,957			169,145
Net increase (decrease) in cash during the period	$	7,495		$	(1,592	)

Substantially all of our cash flow from operating activities is from the production and sale of oil and natural gas. Cash flows from operating activities were 43% higher in the nine months ended September 30,2013 than they were in the same period of 2012 primarily due to the 16% increase in oil and natural gas sales resulting from the 9% increase in production combined with the 6% increase in the average price per Boe.

We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. For the nine months ended September 30, 2013 and 2012, cash flows provided by operating activities were approximately 52% and 37%, respectively, of cash used for the purchase of property and equipment and oil and natural gas properties.

Our capital expenditures incurred for oil and natural gas properties during the nine months ended September 30, 2013 are detailed below:

(in thousands)	EOR Project Areas		Mid-Continent Area		Permian Basin Area		Other		Total		Expanded 2013 Capital Expenditures Budget
Acquisitions	$	246	$	43,057	$	127	$	175	$	43,605	$	54,000
Drilling	12,079		206,803		5,545		747		225,174		292,000
Enhancements	21,282		14,064		3,482		582		39,410		57,000
Pipeline and field infrastructure	62,065		—		—		—		62,065		78,000
CO2 purchases	10,338		—		—		—		10,338		17,000
Total	$	106,010	$	263,924	$	9,154	$	1,504	$	380,592	$	498,000

During the third quarter of 2013, we expanded our 2013 oil and natural gas property capital expenditures budget from $401.0 million to $498.0 million to allow us to take advantage of additional leasehold acquisition and drilling opportunities in our repeatable resource plays. In addition to the capital expenditures for oil and natural gas properties, we spent approximately $8.9 million for property and equipment during the nine months ended September 30, 2013. We also received proceeds of $91.8 million and $45.0 million during the nine months ended September 30, 2013 and 2012, respectively, primarily from dispositions of certain non-strategic oil and natural gas properties.

During the nine months ended September 30, 2013 and 2012, we received net derivative settlements totaling $13.1 million and $24.3 million, respectively. Primarily as a result of our net capital investments and derivative settlements, cash flows used in investing activities were $277.9 million and $309.7 million during the nine months ended September 30, 2013 and 2012, respectively.

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Cash flows provided by financing activities were $87.0 million during the nine months ended September 30, 2013, primarily due to net borrowings under our senior secured revolving credit facility to finance our capital program. Cash flows provided by financing activities were $169.1 million during the nine months ended September 30, 2012. On May 2, 2012, we issued $400.0 million aggregate principal amount of 7.625% Senior Notes maturing on November 15, 2022. Net proceeds from the 7.625% Senior Notes were used to consummate a tender offer for all of our 8.875% Senior Notes due 2017, to redeem the 8.875% Senior Notes not purchased in the tender offer, and for general corporate purposes. In connection with this refinancing transaction, we paid approximately $8.7 million of issuance costs related to underwriting and other fees and approximately $15.8 million of repurchase and redemption-related costs. We also incurred net borrowings of $118.0 million under our senior secured revolving credit facility to finance our capital program during the nine months ended September 30, 2012.

Senior Notes

The Senior Notes, which, as of September 30, 2013, include our 9.875% Senior Notes due 2020, our 8.25% Senior Notes due 2021, and our 7.625% Senior Notes due 2022, 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 indentures.

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

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

We and our restricted subsidiaries are subject to certain negative and financial covenants under the indentures governing the Senior Notes. The provisions of the indentures 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 debt;

• make investments;

• incur liens on assets;

• create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments 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 indentures governing the Senior Notes), or make 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.

Senior secured revolving credit facility

In April 2010, we entered into an Eighth Restated Credit Agreement (our “senior secured revolving credit facility”), which is collateralized by our oil and natural gas properties and, as amended, matures on November 1, 2017. 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. The Thirteenth Amendment, effective October 29, 2013, amended our senior secured revolving credit facility to (a) increase our borrowing base from $500.0 million to $550.0 million, (b) automatically increase the borrowing base to $600.0 million upon the consummation of the Cabot Acquisition and (c) allow for the incurrence of $300.0 million of unsecured senior or subordinated debt meeting the definition of “Additional Permitted Debt” under our senior secured revolving credit facility, (d) permit entering into swap agreements on production from to-be-acquired properties, including the assets to be acquired in the Cabot Acquisition, in notional amounts up to 80% of anticipated proved developed producing production therefrom if otherwise meeting additional necessary requirements under our senior secured revolving credit facility, and (e) increase permitted other debt from $40.0 million to $50.0 million.

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Amounts borrowed under our senior secured revolving credit facility are subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base (the “utilization percentage”) and (2) whether we elect to borrow at the Eurodollar rate or the Alternate Base Rate (“ABR”). As of September 30, 2013, the balance outstanding under our senior secured revolving credit facility was $108.0 million, all of which was subject to the Eurodollar rate.

The Eurodollar rate 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 that varies from 1.50% to 2.50%, depending on our utilization percentage. 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 loans subject to the ABR 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 0.50%, or (3) the Adjusted LIBO Rate, as defined in our senior secured revolving credit facility, plus 1%, plus a margin that varies from 0.50% to 1.50%, depending on our utilization percentage.

Commitment fees of 0.375% to 0.50%, depending on our utilization percentage, 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.

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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 September 30, 2013 and December 31, 2012, our current ratio as computed using GAAP was 0.75 and 0.84, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 2.77 and 3.74, 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)	September 30, 2013			December 31, 2012
Current assets per GAAP	$	153,998		$	163,617
Plus—Availability under senior secured revolving credit facility	391,080			474,080
Plus—Deferred tax liability on derivative instruments and asset retirement obligations included in net current deferred income tax assets	2,267			—
Less—Short-term derivative instruments	(4,449		)	(42,516		)
Current assets as adjusted	$	542,896		$	595,181
Current liabilities per GAAP	$	205,534		$	194,590
Less—Short term derivative instruments	(6,971		)	(436		)
Less—Short-term asset retirement obligations	(2,900		)	(2,900		)
Less—Deferred tax liability on derivative instruments and asset retirement obligations	—			(32,051		)
Current liabilities as adjusted	$	195,663		$	159,203
Current ratio for loan compliance	2.77			3.74

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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 the last day of such applicable fiscal quarter.

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.

Capital Leases

During the third quarter of 2013, we entered into a lease financing agreement with U.S. Bank National Association for approximately $5.2 million through the sale and subsequent leaseback of an existing compressor owned by us. The lease financing obligation is for an 84-month term and includes an option to purchase the equipment for a specified price at 72 months as well as an option to purchase the equipment at the end of the lease term for its then-current fair market value. Lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.4%. Minimum lease payments are approximately $0.6 million annually. In October 2013, we finalized an additional lease financing agreement with U.S. Bank National Association for approximately $11.9 million on the sale and subsequent leaseback of compressors.

Alternative capital resources

We have historically used cash flow from operations, debt financing, private issuances of common stock and asset sales as our primary sources of capital. In the future we may use additional sources such as additional 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.

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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, 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 hedge reclassification adjustments, (5) non-cash change in fair value of non-hedge derivative instruments, (6) interest income, (7) stock-based compensation expense, (8) gain or loss on disposed assets, and (9) impairment charges and other significant, unusual non-cash charges.

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

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2013			2012			2013			2012
Net (loss) income	$	(2,568	)	$	(4,946	)	$	35,142		$	45,299
Interest expense	24,074			24,087			72,565			72,666
Income tax (benefit) expense	(2,130		)	(2,727		)	19,993			25,645
Depreciation, depletion, and amortization	47,582			44,421			139,439			119,807
Reclassification adjustment for hedge gains	(9,032		)	(11,468		)	(28,544		)	(35,777		)
Non-cash change in fair value of non-hedge derivative instruments	41,009			35,735			39,581			(12,726		)
Interest income	(52		)	(60		)	(206		)	(168		)
Stock-based compensation expense	1,271			1,120			2,553			3,058
(Gain) loss on disposed assets	(332		)	(27		)	(556		)	21
Loss on extinguishment of debt	—			18			—			21,714
Loss on impairment of other assets	1,090			—			1,090			—
Adjusted EBITDA	$	100,912		$	86,153		$	281,057		$	239,539

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, 2012.

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

Recent accounting pronouncements

See recently adopted and issued accounting standards in Part I, Item 1 of this report.

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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 nine months ended September 30, 2013, our gross revenues from oil and natural gas sales would change approximately $4.7 million for each $1.00 change in oil and natural gas liquid prices and $1.5 million for each $0.10 change in natural gas prices.

To mitigate a portion of our exposure to fluctuations in commodity prices, we enter into various types of derivative instruments, including commodity price swaps, costless collars, put options, and basis protection swaps. We do not apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as non-hedge derivative gains (losses) in the consolidated statements of operations. This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices.

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 (purchased put) and ceiling price (sold 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 sold put with a price below the floor price of the collar. The sold put option requires us to make a payment to the counterparty if the market price is below the sold put option price. If the market price is greater than the sold 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 sold put option, we are entitled to a net payment equal to the difference between the floor price of the standard collar and the sold put option price if the market price falls below the sold 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 utilizing the value associated with the sale of a put option.

Put options may be purchased from the counterparty by our payment of a cash premium. If the market price is below the put strike price at the settlement date, we will receive a payment from the counterparty. Purchased put options are designed to provide a fixed price floor with the opportunity for upside if commodity prices increase.

We enhance the value of certain oil swaps by combining them with sold puts or put spread contracts. Sold puts require us to make a payment to the counterparty if the market price is below the put strike price at the settlement date. If the market price is greater than the sold put price, the result is the same as it would have been with a swap contract only. A put spread is a combination of a sold put and a purchased put. If the market price falls below the purchased put option price, we will receive the spread between the sold put option price and the purchased put option price from the counterparty. The use of a sold put allows us to receive an above-market swap price while the purchased put provides a measure of downside protection.

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.

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.

46

Our outstanding crude oil derivative instruments as of September 30, 2013 are summarized below:

		Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls	Swaps		Sold puts		Purchased puts		Sold calls		Percent of total production(1)
October - December 2013										82.9	%
Swaps	510	$	95.54	$	—	$	—	$	—
Three-way collars	900	$	—	$	77.83	$	99.94	$	114.49
January - March 2014										97.3	%
Swaps	194	$	93.32	$	—	$	—	$	—
Three-way collars	600	$	—	$	75.50	$	93.25	$	101.94
Enhanced swaps	210	$	99.76	$	80.00	$	—	$	—
Put spread enhanced swaps	408	$	93.31	$	80.00	$	60.00	$	—
Purchased puts	210	$	—	$	—	$	60.00	$	—
April - June 2014										101.8	%
Swaps	176	$	92.92	$	—	$	—	$	—
Three-way collars	600	$	—	$	75.50	$	93.25	$	101.94
Enhanced swaps	210	$	98.94	$	80.00	$	—	$	—
Put spread enhanced swaps	596	$	93.58	$	80.00	$	60.00	$	—
Purchased puts	210	$	—	$	—	$	60.00	$	—
July - September 2014										104.1	%
Swaps	208	$	91.93	$	—	$	—	$	—
Three-way collars	600	$	—	$	75.50	$	93.25	$	101.94
Enhanced swaps	210	$	98.20	$	80.00	$	—	$	—
Put spread enhanced swaps	616	$	93.91	$	80.00	$	60.00	$	—
Purchased puts	210	$	—	$	—	$	60.00	$	—
October - December 2014										98.9	%
Swaps	161	$	91.83	$	—	$	—	$	—
Three-way collars	600	$	—	$	75.50	$	93.25	$	101.94
Enhanced swaps	210	$	97.58	$	80.00	$	—	$	—
Put spread enhanced swaps	605	$	93.65	$	80.00	$	60.00	$	—
Purchased puts	210	$	—	$	—	$	60.00	$	—
January - March 2015										80.6	%
Enhanced swaps	1,445	$	93.35	$	80.00	$	—	$	—
April - June 2015										80.5	%
Enhanced swaps	1,493	$	93.37	$	80.00	$	—	$	—
July - September 2015										51.5	%
Enhanced swaps	990	$	93.33	$	80.00	$	—	$	—
October - December 2015										52.4	%
Enhanced swaps	990	$	93.33	$	80.00	$	—	$	—

(1) Based on our third quarter internally estimated proved reserves calculated using SEC pricing.

47

Our outstanding natural gas derivative instruments as of September 30, 2013 are summarized below:

Period and type of contract	Volume BBtu	Weighted average fixed price per MMBtu		Percent of total production(1)
October - December 2013				87.5	%
Natural gas swaps	4,890	$	4.34
Natural gas basis protection swaps	5,390	$	0.20
January - March 2014				87.5	%
Natural gas swaps	4,740	$	4.07
Natural gas basis protection swaps	5,430	$	0.24
April - June 2014				86.7	%
Natural gas swaps	4,620	$	3.95
Natural gas basis protection swaps	5,680	$	0.24
July - September 2014				87.6	%
Natural gas swaps	4,530	$	3.97
Natural gas basis protection swaps	5,240	$	0.24
October - December 2014				89.3	%
Natural gas swaps	4,530	$	4.12
Natural gas basis protection swaps	5,200	$	0.24
January - March 2015				53.0	%
Natural gas swaps	2,700	$	4.38
Natural gas basis protection swaps	600	$	0.18
April - June 2015				51.4	%
Natural gas swaps	2,700	$	4.12
Natural gas basis protection swaps	600	$	0.18
July - September 2015				41.1	%
Natural gas swaps	2,700	$	4.19
Natural gas basis protection swaps	600	$	0.18
October - December 2015				39.0	%
Natural gas swaps	2,700	$	4.34
Natural gas basis protection swaps	600	$	0.18

(1) Based on our third quarter internally estimated proved reserves calculated using SEC pricing.

48

Subsequent to September 30, 2013, we entered into crude oil swaps covering 380 MBbls for the period from November 2013 through April 2014 at fixed prices ranging from $93.35 to $99.35 per Bbl.

Interest rates. All of the outstanding borrowings under our senior secured revolving facility as of September 30, 2013 are subject to market rates of interest as determined from time to time by the banks. We may elect to borrow under our senior secured revolving credit facility at either Eurodollar rate, which is linked to LIBOR, or the ABR. Loans subject to the ABR 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 0.50%, or (3) the Adjusted LIBO rate, as defined in our senior secured revolving credit facility, plus 1%. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $500.0 million, equal to our borrowing base at September 30, 2013, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $5.0 million.

49

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., individually and as class representative on behalf of all similarly situated persons 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 natural 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 liability on the claims and raised arguments and defenses that, if accepted by the Court, will result in no loss to us. The case was stayed on August 9, 2012 to allow the U.S. Court of Appeals for the Tenth Circuit to decide two unrelated cases that had issues similar to this case. The Tenth Circuit issued its opinions in those unrelated cases on July 9, 2013 and mandates were issued July 31, 2013. On or about October 1, 2013, the Court lifted the stay and entered a new scheduling order. The parties are conducting additional discovery and Planitff’s Motion for Class Certification is due August 10, 2014. Because a class has not been certified, we are not yet able to estimate a possible loss, or range of possible loss, if any.

Amanda Dodson, individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C.

On May 10, 2013, Amanda Dodson (the “Plaintiff”), filed a complaint against us, alleging claims on behalf of herself and all non-governmental Oklahoma citizens who are royalty interest owners in oil and natural gas wells we operate in Oklahoma. The Petition was not served until July 2, 2013. The Plaintiff asserts class claims seeking recovery for underpayment of royalties, alleging entitlement to actual damages in an unspecified amount. The Plaintiff also requests allowable interest, punitive damages, injunctive relief, an accounting, disgorgement damages, and an award of attorney fees and costs. We have denied liability on the claims and raised arguments and defenses that, if accepted by the Court, will result in no loss to us. At this time, a class has not been certified and discovery has yet to begin. As such, we are not yet able to estimate a possible loss, or range of possible loss, if any.

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 1A. RISK FACTORS

Information with respect to risk factors is included under Item 1A. of our Annual Report on Form 10-K for the year ended December 31, 2012. There have been no material changes to the risk factors since the filing of such Form 10-K.

50

ITEM 6. EXHIBITS

Exhibit No.	Description
10.1	Asset Purchase Agreement dated as of October 11, 2013, by and between Chaparral Energy L.L.C. and Cabot Oil & Gas Corporation
10.2	Thirteenth Amendment to Eighth Restated Credit Agreement dated as of October 29, 2013
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

51

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

CHAPARRAL ENERGY, INC.
By:	/s/ Mark A. Fischer
Name:	Mark A. Fischer
Title:	President and Chief Executive Officer
	(Principal Executive Officer)
By:	/s/ Joseph O. Evans
Name:	Joseph O. Evans
Title:	Chief Financial Officer and Executive Vice President
	(Principal Financial Officer and Principal Accounting Officer)

Date: November 14, 2013

52

EXHIBIT INDEX

Exhibit No.	Description
10.1	Asset Purchase Agreement dated as of October 11, 2013, by and between Chaparral Energy L.L.C. and Cabot Oil & Gas Corporation
10.2	Thirteenth Amendment to Eighth Restated Credit Agreement dated as of October 29, 2013
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

53

EX-10.1

ASSET PURCHASE AGREEMENT

DATED AS OF OCTOBER 11, 2013,

BY AND BETWEEN

CABOT OIL & GAS CORPORATION,

AS SELLER,

AND

CHAPARRAL ENERGY, L.L.C.,

AS BUYER

TABLE OF CONTENTS

Page

ARTICLE I CERTAIN DEFINITIONS    1

1.1 Certain Defined Terms    1

1.2 Rules of Construction    1

ARTICLE II SALE AND PURCHASE    2

2.1 Sale and Purchase    2

2.2 Excluded Assets    3

ARTICLE III CONSIDERATION AND PAYMENT    4

3.1 Consideration    4

3.2 Payment    4

3.3 Adjustments    4

3.4 Post Closing Review    5

ARTICLE IV REPRESENTATIONS AND WARRANTIES    6

4.1 Representations and Warranties of Seller    6

4.2 Representations and Warranties of Buyer    8

ARTICLE V INVESTIGATION OF ASSETS; CONFIDENTIALITY    10

5.1 Investigation of Assets    10

5.2 Confidential Information    11

- 1 -

TABLE OF CONTENTS

(continued)

Page

ARTICLE VI TITLE ADJUSTMENTS    11

6.1 No Warranty or Representation    11

6.2 Buyer’s Title Review    11

6.3 Determination of Title Defects    14

6.4 Seller Title Credit    15

6.5 Exclusion of Title Defect Properties    16

6.6 Deferred Claims and Disputes    16

6.7 No Duplication    17

ARTICLE VII PREFERENCE RIGHTS AND TRANSFER REQUIREMENTS    17

7.1 Compliance    17

7.2 Effect of Preference Rights    17

7.3 Transfer Requirements    18

7.4 Certain Governmental Consents    18

7.5 Express Conditions on Sale    18

ARTICLE VIII COVENANTS OF SELLER AND BUYER    19

8.1 Conduct of Business Pending Closing    19

8.2 Emergencies; Legal Requirements    21

8.3 Conveyance    22

8.4 Public Announcements    22

8.5 Further Assurances    22

8.6 Removal    22

- 2 -

TABLE OF CONTENTS

(continued)

Page

8.7 Records    22

8.8 Amendment of Schedules    23

8.9 Recording    23

8.10 Casualty and Condemnation    23

8.11 Operations    24

8.12 Revenues in Suspense    24

8.13 Certain Invoices    24

ARTICLE IX CLOSING CONDITIONS    24

9.1 Seller’s Closing Conditions    24

9.2 Buyer’s Closing Conditions    25

ARTICLE X CLOSING    26

10.1 Closing    26

10.2 Seller’s Closing Obligations    26

10.3 Buyer’s Closing Obligations    26

ARTICLE XI EFFECT OF CLOSING    27

11.1 Revenues    27

11.2 Payments    27

11.3 Survival    27

ARTICLE XII LIMITATIONS    28

12.1 Disclaimer of Warranties    28

- 3 -

TABLE OF CONTENTS

(continued)

Page

12.2 Texas Deceptive Trade Practices Act Waiver    28

12.3 Damages    29

ARTICLE XIII ASSUMPTION AND INDEMNIFICATION    29

13.1 Assumption and Indemnification By Buyer    29

13.2 Indemnification By Seller    30

13.3 Indemnification and Defense Procedures    30

13.4 Seller’s General Liability Limitation    32

13.5 Exclusive Remedy    33

ARTICLE XIV TERMINATION; REMEDIES    33

14.1 Termination    33

14.2 Remedies    34

ARTICLE XV MISCELLANEOUS    35

15.1 Counterparts    35

15.2 Governing Law; Jurisdiction    35

15.3 Entire Agreement    35

15.4 Expenses    35

15.5 Notices    36

15.6 Successors and Assigns    37

15.7 Amendments and Waivers    37

15.8 Appendix, Schedules and Exhibits    37

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TABLE OF CONTENTS

(continued)

Page

15.9 Purchase Price Allocation for Tax Purposes    37

15.10 Ad Valorem Tax Proration    37

15.11 Agreement for the Parties’ Benefit Only    38

15.12 Attorneys’ Fees    38

15.13 Severability    38

15.14 Time of Essence    38

15.15 Like-Kind Exchange    38

- 5 -

APPENDICES

Appendix A    Definitions

EXHIBITS

Exhibit 8.3    Conveyance

Exhibit 10.2(c)    Certificate of Non-Foreign Status

Exhibit A‑1    Arbitration Procedures

Exhibit A‑2    Property Schedule

SCHEDULES

Schedule 2.2(l)    Certain Excluded Assets

Schedule 4.1(e)    Seller’s Actions

Schedule 4.1(f)    Non-Compliance with Laws

Schedule 4.1(g)    Material Contracts

Schedule 4.1(h)    Tax Matters

Schedule 4.1(i)    Certain Wells

Schedule 4.1(j)    Outstanding Commitments

Schedule 4.1(k)    Environmental Matters

Schedule 4.1(n)    Gas Imbalances

Schedule 4.1(o)    Funds Held in Suspense

Schedule 4.2(e)    Buyer’s Consents

Schedule 4.2(f)    Buyer’s Actions

Schedule 7.1 - Part I    Preference Rights

Schedule 7.1 - Part II    Transfer Requirements

Schedule 8.1     Conduct of Business

Schedule 15.9    Purchase Price Allocation for Tax Purposes

Schedule A-1    Certain Permitted Encumbrances

- 6 -

ASSET PURCHASE AGREEMENT

THIS ASSET PURCHASE AGREEMENT (this “Agreement”), dated as of October 11, 2013, is by and between CABOT OIL & GAS CORPORATION, a Delaware corporation (“Seller”), and CHAPARRAL ENERGY, L.L.C., an Oklahoma limited liability company (“Buyer”).

WHEREAS, Seller owns certain oil and gas properties and related assets located in the States of Oklahoma and Texas; and

WHEREAS, Seller desires to sell to Buyer, and Buyer desires to purchase from Seller, such oil and gas properties and related assets upon the terms and subject to the conditions set forth herein.

NOW, THEREFORE, in consideration of the mutual covenants and agreements hereinafter set forth, the Parties agree as follows:

ARTICLE I
CERTAIN DEFINITIONS

1.1Certain Defined Terms. Unless the context otherwise requires, the respective terms defined in Appendix A attached hereto and incorporated herein shall, when used herein, have the respective meanings therein specified, with each such definition to be equally applicable both to the singular and the plural forms of the term so defined.

1.2Rules of Construction.

(a)All article, section, schedule and exhibit references used in this Agreement are to articles, sections, schedules and exhibits to this Agreement unless otherwise specified. The schedules and exhibits attached to this Agreement constitute a part of this Agreement and are incorporated herein for all purposes.

(b)If a term is defined as one part of speech (such as a noun), it shall have a corresponding meaning when used as another part of speech (such as a verb). Terms defined in the singular have the corresponding meanings in the plural, and vice versa. Unless the context of this Agreement clearly requires otherwise, words importing the masculine gender shall include the feminine and neutral genders and vice versa. The term “including” and its derivatives shall mean “including without limitation” and corresponding derivative expressions. The words “hereof,” “hereto,” “hereby,” “herein,” “hereunder” and words of similar import, when used in this Agreement, shall refer to this Agreement as a whole and not to any particular section or article in which such words appear. The term “cost” includes expense and the term “expense” includes cost. All references to “dollars” or “$” shall be deemed references to United States dollars.

(c)The Parties acknowledge that each Party and its attorneys have reviewed this Agreement and that any rule of construction to the effect that any ambiguities are to be resolved against the drafting Party, or any similar rule operating against the drafter of an agreement, shall not be applicable to the construction or interpretation of this Agreement.

    - 1 -

(d)The captions in this Agreement are for convenience only and shall not be considered a part of or affect the construction or interpretation of any provision of this Agreement.

(e)Any event hereunder requiring the payment of cash or cash equivalents and any action to be taken hereunder on a day that is not a Business Day shall be deferred until the first Business Day occurring after such day.

(f)Each exhibit and schedule to this Agreement is a part of this Agreement, but if there is any conflict or inconsistency between the main body of this Agreement (including Appendix A which shall be considered part of the main body of this Agreement) and any exhibit or schedule, the provisions of the main body of this Agreement shall prevail.

ARTICLE IISALE AND PURCHASE

2.1Sale and Purchase. Subject to the terms and conditions of this Agreement, Seller agrees to sell and convey to Buyer, and Buyer agrees to purchase from Seller, effective as of 7:00 a.m. (local time) on October 1, 2013 (the “Effective Time”), the following described assets and properties except to the extent any of the same constitute an Excluded Asset (collectively, the “Assets”):

(g)All right, title and interest of Seller in and to (i) the undivided interests specified in the Property Schedule in, to or under the Hydrocarbon Interests specifically described therein, and (ii) all other interests of Seller in, to or under any Hydrocarbon Interests in, to or under or derived from any lands covered by or subject to any of the Hydrocarbon Interests described in the Property Schedule, even though such interests of Seller may be incorrectly described or referred to in, or a description thereof may be omitted from, the Property Schedule (collectively, the “Subject Interests”);

(h)All right, title and interest of Seller in and to the lands covered by or subject to the Subject Interests (the “Lands”);

(i)All right, title and interest of Seller in and to the following insofar as the same are attributable to the Subject Interests: (i) all rights with respect to the use and occupancy of the surface of and the subsurface depths under the Lands; (ii) all rights with respect to any pooled, communitized or unitized acreage by virtue of any Subject Interest being a part thereof; (iii) all agreements and contracts, easements, rights-of-way, servitudes and other estates, but excluding any agreement, contract, easement, right-of-way, servitude or other estate to the extent transfer of same is restricted by enforceable third-party agreement or Law and the necessary consents to transfer are not obtained pursuant to Section 7.1; and (iv) all real and personal property located upon the Lands and primarily used in connection with the exploration, development or operation of the Subject Interests;

    - 2 -

(j)Except to the extent transfer thereof may not be made without violating legal constraints or obligations or waiving any attorney/client privilege (other than with respect to title opinions and title curative correspondence), any and all lease files, title files, well files, drilling reports, land files, environmental files, regulatory files, plats, surveys, ownership maps, geologic maps, cross-sections, electric logs, well schematics, mud logs, cores, core analyses, production data, pressure data, decline and production curves, geological data and reports, proprietary seismic data, division of interest files and decks, joint interest billing files and decks, division order files, marketing files, title opinions, abstracts of title, title curative correspondence and documents in each case, (i) relating exclusively to the Subject Interests or the ownership, use, maintenance or operation of the other Assets and (ii) in Seller’s actual possession or control (the “Records”); and

(k)All (i) oil, gas and other hydrocarbons produced from and to the extent attributable to the Subject Interests with respect to all periods subsequent to the Effective Time and (ii) proceeds from or of such oil, gas and other hydrocarbons.

2.2Excluded Assets. Notwithstanding anything to the contrary contained in this Agreement, the Assets shall not include, and there is excepted, reserved and excluded from the purchase and sale contemplated hereby, the following (collectively, the “Excluded Assets”):

(a)Copies of all Records;

(b)All deposits, cash, checks, funds and accounts receivable attributable to the Assets with respect to any period prior to the Effective Time;

(c)All (i) oil, gas and other hydrocarbons produced from or attributable to the Subject Interests with respect to all periods prior to the Effective Time, (ii) oil, gas and other hydrocarbons attributable to the Subject Interests which, at the Effective Time, are in storage, within processing plants, in pipelines or otherwise held in inventory, and (iii) proceeds from or of such oil, gas and other hydrocarbons;

(d)All receivables and cash proceeds which were expressly taken into account and for which credit was given in the determination of Net Cash Flow pursuant to Section 3.3, as adjusted pursuant to Section 3.4;

(e)Claims of Seller for refund of, credit attributable to, or loss carry forwards with respect to (i) Taxes attributable to any period prior to the Effective Time or (ii) any Taxes attributable to the Excluded Assets;

(f)All corporate, financial, Tax and legal records of Seller, other than title opinions and title curative correspondence;

(g)All rights, titles, interests and claims of Seller or any Affiliate of Seller with respect to the Assets (i) under any policy or agreement of insurance, (ii) under any bond or (iii) to any insurance or condemnation proceeds or awards (to the extent such insurance or condemnation proceeds or awards relate to events occurring prior to the Effective Time);

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(h)All computer or communications software or intellectual property (including tapes, data, and program documentation and all tangible manifestations and technical information relating thereto, but excluding electronic files, records and data included within the definition of the term “Records”) owned, licensed, or used by Seller;

(i)Any logo, service mark, copyright, trade name or trademark of or associated with Seller or any Affiliate of Seller or any business of Seller or of any Affiliate of Seller;

(j)All rights, titles, and interests of Seller or any Affiliate of Seller in and to all cars, trucks, trailers and all other rolling stock;

(k)Any futures, options, swaps, hedges or other derivatives of Seller or any of its Affiliates; and

(l)All rights, interests, assets and properties described in Schedule 2.2(l).

ARTICLE III
CONSIDERATION AND PAYMENT

3.1Consideration. The consideration for the sale and conveyance of the Assets to Buyer is One Hundred Sixty Million One Hundred Twenty-Eight Thousand and No/100 Dollars($160,128,000), as adjusted in accordance with the terms of this Agreement (the “Purchase Price”). The “Adjusted Purchase Price” shall be the Purchase Price (i) as adjusted by the Initial Adjustment Amount, (ii) as may be adjusted for Title Defects, if any, in accordance with Section 6.2, (iii) as may be adjusted for excluded Title Defect Properties, if any, in accordance with Section 6.5, (iv) as may be adjusted for payments of portions of the Purchase Price received by Seller from holders of Preference Rights contemporaneously with Closing in accordance with and as contemplated by Section 7.2, (v) as may be adjusted on account of Retained Assets as contemplated by Section 7.3, and (vi) as adjusted downward by an amount equal to the aggregate amount of proceeds which Seller is holding in suspense as of the Effective Time in respect of past production of oil, gas or other hydrocarbons attributable to the Assets.

3.2Payment. Contemporaneously with the execution of this Agreement, Buyer has deposited an amount equal to ten percent (10%) of the Purchase Price with Seller as a deposit hereunder (the “Deposit”). At the Closing, Buyer shall wire transfer the Adjusted Purchase Price minus the Deposit in immediately available funds to JPMorgan Chase Bank, N.A., ABA No. 021000021 for the account of Cabot Oil & Gas Corporation, Account No. 636462608, or such other account specified by Seller to Buyer on or prior to the Business Day immediately preceding the Closing Date.

3.3Adjustments.

(a)The Purchase Price shall be increased or decreased, as the case may be, by an amount equal to the Net Cash Flow with respect to the Assets for the time period (the “Adjustment Period”) beginning at the Effective Time and ending at 7:00 a.m. (local time) on the Closing Date. Seller shall deliver to Buyer on or prior to the Business Day immediately preceding the Closing Date a

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statement (the “Adjustment Statement”) setting forth Seller’s preliminary determination (“Initial Adjustment Amount”) of the Net Cash Flow. If the Initial Adjustment Amount shown on the Adjustment Statement is a positive number, then the Purchase Price shall be increased by such amount. If the Initial Adjustment Amount shown on the Adjustment Statement is a negative number, then the Purchase Price shall be decreased by such amount.

(b)The Adjustment Statement shall be based upon actual information available to Seller at the time of its preparation and upon Seller’s good faith estimates and assumptions. There shall be attached to the Adjustment Statement such supporting documentation and other data as is reasonably necessary to provide a basis for the Net Cash Flow shown therein.

(c)The “Net Cash Flow” shall be the sum of (i) a positive amount equal to the aggregate amount paid by Seller as Seller’s share of the costs and expenses of exploration, maintenance, development, production and operation of the Assets incurred with respect to the Adjustment Period (including prepayments of any such costs or expenses but excluding overhead charges, costs or expenses), (ii) a positive amount equal to the sum of (A) all overhead charges paid by Seller to any operator of any of the Assets, and (B) with respect to any properties operated by Seller or any Affiliate of Seller, the overhead charges payable to Seller or such affiliated operator on account of the Subject Interests in such properties under existing operating agreements or, if no overhead charge is applicable to a Subject Interest under an existing operating agreement, an overhead charge to such Subject Interest equal to $10,000 per month for each drilling well and $1,000per month for each producing well attributable to each such Subject Interest, and (iii) a negative amount equal to the aggregate net proceeds received by Seller from the sale or disposition of oil, gas and other hydrocarbons produced from the Assets during the Adjustment Period or from the rental, sale, salvage or other disposition of any other Assets during the Adjustment Period.

3.4Post Closing Review. After the Closing, Seller shall review the Adjustment Statement and determine the actual Net Cash Flow. On or prior to the ninetieth (90^th) day after the Closing Date, Seller shall present Buyer with a statement of the actual Net Cash Flow and such supporting documentation as is reasonably necessary to support the Net Cash Flow shown therein (the “Final Adjustment Statement”). Buyer will give representatives of Seller reasonable access to its premises and to its books and records for purposes of preparing the Final Adjustment Statement and will cause appropriate personnel of Buyer to assist Seller and Seller’s representatives, at no cost to Seller, in the preparation of the Final Adjustment Statement. Seller will give representatives of Buyer reasonable access to its premises and to its books and records for purposes of reviewing the calculation of Net Cash Flow and will cause appropriate personnel of Seller to assist Buyer and its representatives, at no cost to Buyer, in verification of such calculation. The Final Adjustment Statement shall become final and binding on Seller and Buyer as to the Net Cash Flow thirty (30) days following the date the Final Adjustment Statement is received by Buyer, except to the extent that prior to the expiration of such thirty (30) day period Buyer shall deliver to Seller notice, as hereinafter required, of its disagreement with the contents of the Final Adjustment Statement. Such notice shall be in writing and set forth all of Buyer’s disagreements with respect to any portion of the Final Adjustment Statement, together with Buyer’s proposed changes thereto, and shall include an explanation in reasonable detail of, and such supporting documentation as is reasonably necessary to support, such changes. If Buyer has timely delivered such a notice of disagreement to Seller,

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then, upon written agreement between Buyer and Seller resolving all disagreements of Buyer set forth in such notice, the Final Adjustment Statement will become final and binding upon Buyer and Seller as to the Net Cash Flow. If the Final Adjustment Statement has not become final and binding by the sixtieth (60^th) day following its receipt by Buyer, then Buyer or Seller may submit any unresolved disagreements of Buyer set forth in such notice to final and binding arbitration in accordance with the Arbitration Procedures. Upon resolution of such unresolved disagreements of Buyer, the Final Adjustment Statement shall be final and binding upon Buyer and Seller as to the Net Cash Flow. Within three (3) Business Days after the Final Adjustment Statement becomes final and binding, Seller or Buyer, as appropriate, shall pay to the other Party the amount, if any, by which the Net Cash Flow as shown in the Final Adjustment Statement, is less than or exceeds the Initial Adjustment Amount, together with interest thereon from the Closing Date until paid at the Agreed Rate.

ARTICLE IV
REPRESENTATIONS AND WARRANTIES

4.1Representations and Warranties of Seller. Seller represents and warrants to Buyer as follows:

(a)Organization and Qualification. Seller is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware and has the requisite corporate power to carry on its business as it is now being conducted. Seller is duly qualified to do business, and is in good standing, in each jurisdiction in which the Assets owned or leased by it makes such qualification necessary.

(b)Authority. Seller has all requisite corporate power and authority to execute and deliver this Agreement and to perform its obligations hereunder. The execution, delivery and performance of this Agreement and the transactions contemplated hereby have been duly and validly authorized by all requisite corporate action on the part of Seller.

(c)Enforceability. This Agreement constitutes a valid and binding agreement of Seller enforceable against Seller in accordance with its terms, subject to (i) applicable bankruptcy, insolvency, reorganization, moratorium and other similar laws of general application with respect to creditors, (ii) general principles of equity and (iii) the power of a court to deny enforcement of remedies generally based upon public policy.

(d)No Conflict or Violation. Except for (i) consents or approvals of, or filings with, any applicable Governmental Authorities in connection with assignments of the Assets which are not customarily obtained prior to the assignment of the Assets, and (ii) Preference Rights and Transfer Requirements, neither the execution and delivery of this Agreement nor the consummation of the transactions and performance of the terms and conditions contemplated hereby by Seller will (i) conflict with or result in any breach of any provision of the certificate of incorporation, by-laws or partnership agreement or other governing documents of Seller; (ii) violate, conflict with or constitute a default under the terms, conditions or provisions of any agreement, instrument or obligation to which Seller is a party or is bound; or (iii) violate or be rendered void or ineffective under any Law applicable to Seller or by which Seller is bound, other than, in the case of the matters described in

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clauses (ii) and (iii) of this Section 4.1(d), where such conflicts, breaches, violations, defaults or other events as would not, in the aggregate, have a Material Adverse Effect.

(e)Actions. Except as set forth on Schedule 4.1(e), there are no Actions pending against Seller or, to the knowledge of Seller, threatened against Seller which relate to the Assets or the transactions contemplated by this Agreement other than Actions which are not reasonably expected by Seller to have, in the aggregate, a Material Adverse Effect.

(f)Compliance With Laws. Except with respect to (i) matters set forth on Schedule 4.1(e) and Schedule 4.1(f), (ii) compliance with Laws concerning Taxes (as to which certain representations and warranties are made pursuant to Section 4.1(h))and (iii) compliance with Environmental Laws (as to which certain representations and warranties are made pursuant to Section 4.1(k)), Seller is not in violation of any Law applicable to the Assets other than violations of Law which would not, in the aggregate, have a Material Adverse Effect.

(g)Material Contracts. Schedule 4.1(g) sets forth a list of all Material Contracts that exist as of the date of this Agreement. Except as set forth on Schedule 4.1(g), Seller is not in breach of, or default under, and to the knowledge of Seller, no other Person is in breach of, or default under, any Material Contract, and there does not exist under any provision thereof, to the knowledge of Seller, any event that, with the giving of notice or the lapse of time or both, would constitute such a breach or default by any Person (exclusive of Seller or any Affiliate of Seller), except for such breaches, defaults and events which would not, in the aggregate, have a Material Adverse Effect.

(h)Tax Matters.

(i)Except for Taxes being contested in good faith, each material Tax Return required to be filed with respect to the Assets has been timely and properly filed and all material Taxes with respect to the Assets have been timely and properly paid. All such Tax Returns are correct and complete in all material respects.

(ii)Except as set forth on Schedule 4.1(h), none of the Assets are subject to any Tax partnership agreement requiring a partnership income Tax Return to be filed under Subchapter K of Chapter 1 of Subtitle A of the Code.

(i)Wells. Except as set forth on Schedule 4.1(i), there is no well included in the Assets:

(i)with respect to which Seller is in violation of Law on the date of this Agreement for failing to timely plug and abandon;

(ii)that, to Seller’s knowledge, is, on the date of this Agreement, shut-in and for which Seller would have a current obligation under Law to plug and abandon but for a waiver obtained or an exception granted from the applicable Governmental Authority; or

(iii)that, to the knowledge of Seller, has been plugged and abandoned other than in compliance in all material respects with Law.

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(j)Proposed Operations or Expenditures. Except as set forth on Schedule 4.1(j), as of the date of this Agreement, there are no outstanding authorities for expenditure or other commitments to conduct any operations or expend any amount of money on or with respect to the Assets which are binding on Seller or the Assets and will be binding on Buyer after Closing and which Seller reasonably anticipates will require the expenditure of money in excess of $250,000.00 for any such operation (net to Seller’s interest).

(k)Environmental. Except as set forth on Schedule 4.1(k):

(i)to the knowledge of Seller as of the date of this Agreement, the Assets and Seller with respect to the Assets are in compliance with the requirements of all Environmental Laws, except for such conditions on the Assets which, if remediated in accordance with Environmental Laws, would require remediation expenditures of less than $250,000 in the aggregate; and

(ii)to the knowledge of Seller, all permits, licenses, approvals, consents, certificates and other authorizations required by Environmental Laws with respect to the ownership or operation of the Assets (the “Environmental Permits”) have been properly obtained and are in full force and effect, and the Assets are in material compliance with the Environmental Permits.

(l)Brokerage Fees and Commissions. Neither Seller nor any Affiliate of Seller has incurred any obligation or entered into any agreement for any investment banking, brokerage or finder’s fee or commission in respect of the transactions contemplated by this Agreement for which Buyer shall incur any liability.

(m)Bankruptcy. There are no bankruptcy, reorganization or arrangement proceedings pending against, being contemplated by, or, to the knowledge of Seller, threatened against Seller.

(n)Gas Imbalances. To Seller’s knowledge, except as set forth in Schedule 4.1(n), there are no material gas imbalances attributable to the wells included in the Assets (as of the respective dates set forth in Schedule 4.1(n)). To Seller’s knowledge, there are no wells included in the Assets for which Seller has incurred a current cash payment liability for gas overproduction. No pipeline imbalances have been incurred with respect to the transportation or redelivery of gas produced from the Assets for which Buyer will have any liability or obligation in connection with or after the Closing.

(o)Suspense Accounts, Except as set forth in Schedule 4.1(o), as of the date set forth on such schedule, Seller does not hold any funds in suspense with respect to any of the Assets.

4.2Representations and Warranties of Buyer. Buyer represents and warrants to Seller as follows:

(d)Organization and Qualification. Buyer is a limited liability company, duly organized, validly existing and in good standing under the laws of the State of Oklahoma and has the requisite power to carry on its business as it is now being conducted. Buyer is duly qualified to do business

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and is in good standing in each jurisdiction in which the Assets to be acquired by it makes such qualification necessary.

(e)Authority. Buyer has all requisite limited liability company power and authority to execute and deliver this Agreement and to perform its obligations under this Agreement. The execution, delivery and performance of this Agreement and the transactions contemplated hereby have been duly and validly authorized by all requisite limited liability company action on the part of Buyer.

(f)Enforceability. This Agreement constitutes a valid and binding agreement of Buyer enforceable against Buyer in accordance with its terms, subject to (i) applicable bankruptcy, insolvency, reorganization, moratorium and other similar laws of general application with respect to creditors, (ii) general principles of equity and (iii) the power of a court to deny enforcement of remedies generally based upon public policy.

(g)No Conflict or Violation. Neither the execution and delivery of this Agreement nor the consummation of the transactions and performance of the terms and conditions contemplated hereby by Buyer will (i) conflict with or result in any breach of any provision of the governing documents of Buyer; (ii) violate, conflict with or constitute a default under the terms, conditions or provisions of any agreement, instrument or obligation to which Buyer is a party or is bound; or (iii) violate or be rendered void or ineffective under any Law applicable to Buyer or by which Buyer is bound, other than, in the case of the matters described in clauses (ii) and (iii) of this Section 4.2(d), the matters referenced in Section 4.2(e) and such conflicts, breaches, violations or other events as will not materially impair the ability of Buyer to consummate the transactions contemplated by this Agreement or to perform its obligations hereunder.

(h)Consents. Except for (i) consents or approvals of, or filings with, any applicable Governmental Authorities in connection with assignments of the Assets which are not customarily obtained prior to the assignment of the Assets, (ii) Preference Rights and Transfer Requirements, and (iii) the consents (which have not already been obtained), filings or notices expressly described and set forth on Schedule 4.2(e), no consent, approval, authorization or permit of, or filing with or notification to, any Person is required for or in connection with the execution and delivery of this Agreement by Buyer or for or in connection with the consummation of the transactions and performance of the terms and conditions contemplated hereby by Buyer.

(i)Actions. Except as set forth on Schedule 4.2(f), there are no Actions pending against Buyer or, to the knowledge of Buyer, threatened against Buyer which relate to the transactions contemplated by this Agreement other than Actions which would not materially impair the ability of Buyer to consummate the transactions contemplated by this Agreement or to perform its obligations hereunder.

(j)Brokerage Fees and Commissions. Neither Buyer nor any Affiliate of Buyer has incurred any obligation or entered into any agreement for any investment banking, brokerage or finder’s fee or commission in respect of the transactions contemplated by this Agreement for which Seller shall incur any liability.

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(k)Qualified Owner. Buyer (i) is qualified to own federal and state oil, gas and mineral leases and oil, gas and mineral leases on tribal and allotted Indian lands in all jurisdictions where any of the Subject Interests are located and (ii) has complied with all necessary governmental bonding requirements arising from its ownership of the Assets. The consummation of the transactions contemplated hereby will not cause Buyer to be disqualified as an owner of such leases or to exceed any acreage limitation imposed by any Law.

(l)Funds. Buyer has sufficient funds available to enable Buyer to consummate the transactions contemplated hereby and to pay all related fees and expenses of Buyer.

(m)Buyer’s Knowledge. Buyer has no knowledge of any fact which results in any representation or warranty of Seller in Section 4.1 being breached.

(n)No Distribution. Buyer is an experienced and knowledgeable investor in the oil and gas business, Buyer is able to bear the economic risks of its acquisition and ownership of the Assets, and Buyer is capable of evaluating (and has evaluated) the merits and risks of the Assets and Buyer’s acquisition and ownership thereof. Prior to entering into this Agreement, Buyer was advised by its counsel and such other Persons it has deemed appropriate concerning this Agreement and has relied solely on an independent investigation and evaluation of, and appraisal and judgment with respect to, the geologic and geophysical characteristics of the Assets, the estimated reserves recoverable therefrom, and the price and expense assumptions applicable thereto. Buyer is an “accredited investor,” as such term is defined in Regulation D of the Securities Act of 1933, as amended, and will acquire the Assets for its own account and not with a view to a sale or distribution thereof in violation of the Securities Act of 1933, as amended, and the rules and regulations thereunder, any state blue sky Laws or any other securities Laws.

(o)Bankruptcy. There are no bankruptcy, reorganization or arrangement proceedings pending against, being contemplated by, or, to the knowledge of Buyer, threatened against Buyer.

ARTICLE V
INVESTIGATION OF ASSETS; CONFIDENTIALITY

5.1Investigation of Assets. Promptly following the execution of this Agreement and until the Closing (or earlier termination of this Agreement), Seller (i) shall permit Buyer and its representatives at reasonable times to examine, in Seller’s offices, all abstracts of title, title opinions, title files, ownership maps, lease files, assignments, division orders, and other Records relating to the Assets insofar as the same are in Seller’s possession and insofar as Seller may do so without (a) violating legal constraints or any legal obligation or (b) waiving any attorney/client privilege (other than with respect to title opinions and title curative correspondence) and (ii), subject to any required consent of any third Person, shall permit Buyer and its representatives at reasonable times and at Buyer’s sole risk, cost and expense, to conduct, in the presence of Seller’s representatives, reasonable inspections of the Assets; provided, however, that Buyer shall not conduct any Phase II environmental testing or other invasive surface or subsurface testing without Seller’s prior written consent, which consent shall not be unreasonably withheld; provided, however, Buyer shall repair any damage to the Assets resulting from such inspections and Buyer does hereby indemnify and hold harmless the Seller Indemnified Persons from and against any and all Covered Liabilities to

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the extent arising from Buyer’s inspection of the Assets, REGARDLESS OF ANY CONCURRENT NEGLIGENCE OR STRICT LIABILITY ON THE PART OF ANY SELLER INDEMNIFIED PERSON AND REGARDLESS OF THE FORM OF CLAIM WHETHER AT COMMON LAW, STRICT LIABILITY, NEGLIGENCE OR UNDER ANY STATUTE OR REGULATION, EXCLUDING, HOWEVER, THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF ANY SELLER INDEMNIFIED PERSON. Seller also shall permit Buyer and its representatives, both before and for a reasonable time after Closing, to examine, in Seller’s offices at reasonable times, all financial and operating records and reports maintained by Seller with respect to the Assets, including, without limitation, lease operating statements and similar financial statements and reports, and have reasonable access to members of Seller’s accounting staff, as necessary to permit Buyer to create an historical financial data base with respect to operations on the Assets and to conduct a revenue and expense audit of the Assets as necessary to comply with regulatory filings required by the Securities and Exchange Commission, and shall permit and facilitate communication by Buyer with Seller’s independent auditors for such purpose.

5.2Confidential Information. Buyer agrees to maintain all information made available to it pursuant to Section 5.1 confidential and to cause its officers, employees, representatives, consultants and advisors to maintain all information made available to them pursuant to Section 5.1 confidential, all as provided in that certain Confidentiality Agreement dated September 14, 2013 (the “Confidentiality Agreement”), by and between Seller and Buyer, the terms of which are incorporated herein by reference and made a part of this Agreement.

ARTICLE VI
TITLE ADJUSTMENTS

6.1No Warranty or Representation. Without limiting Buyer’s right to adjust the Purchase Price by operation of Section 6.2 and Section 6.5 and except for the special warranty of title which is contained in the Conveyance, Seller makes no warranty or representation, express, implied, statutory or otherwise, with respect to Seller’s title to any of the Assets and Buyer hereby acknowledges and agrees that, except as provided above, Buyer’s sole remedy for any defect of title, including any Title Defect, with respect to any of the Assets shall be pursuant to the procedures set forth in this Article VI, which remedies (other than those provided for in Section 6.5) shall cease, and be deemed to be finally and conclusively satisfied, in all respects, upon the Closing. Furthermore, Seller makes no warranty or representation, express, implied, statutory or otherwise, with respect to the accuracy or completeness of the information, records and data now, heretofore or hereafter made available to Buyer in connection with this Agreement (including, without limitation, any description of the Assets, pricing assumptions, potential for production of oil, gas or other hydrocarbons from the Subject Interests or any other matters contained in or related to the Reserve Report or any other material furnished to Buyer by Seller or by Seller’s agents or representatives).

6.2Buyer’s Title Review.

(a)Buyer’s Assertion of Title Defects. During the period commencing on the execution of this Agreement and terminating on December 6, 2013 (the “Title Examination Period”), Buyer

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shall notify Seller in writing of any matters which, in Buyer’s reasonable opinion, constitute Title Defects and which Buyer intends to assert as a Title Defect with respect to any portion of a Property Subdivision pursuant to this Article VI. For all purposes of this Agreement, Buyer shall be deemed to have waived any Title Defect which Buyer fails to assert as a Title Defect by written notice given to Seller on or before the expiration of the Title Examination Period. To be effective, Buyer’s written notice of a Title Defect must include (i) a brief description of the matter constituting the asserted Title Defect, (ii) the claimed Title Defect Amount attributable thereto, and (iii) supporting documents reasonably necessary for Seller (as well as any title attorney or examiner hired by Seller) to verify the existence of such asserted Title Defect. To give Seller an opportunity to commence reviewing and curing Title Defects, Buyer agrees to give Seller written notice of any Title Defect which Buyer determines exists promptly following Buyer’s determination of the existence of same, which notice may be preliminary in nature and supplemented prior to the end of the Title Examination Period. Buyer shall also promptly furnish Seller with written notice of any Seller Title Credit which is discovered by any of Buyer’s employees or representatives while conducting Buyer’s title review, due diligence or investigation with respect to the Subject Interests and Property Subdivisions.

(b)Purchase Price Allocations. A portion of the Purchase Price has been allocated by Buyer to the various Subject Interests in Property Subdivisions in the manner and in accordance with the respective values set forth in Part II of the Property Schedule. If any adjustment is made to the Purchase Price pursuant to this Section 6.2, a corresponding adjustment shall be made to the portion of the Purchase Price allocated to the affected Property Subdivision in Part II of the Property Schedule.

(c)Seller’s Opportunity to Cure. Seller shall have ten (10) days after the expiration of the Title Examination Period, at its cost and expense, if it so elects but without obligation, to cure all or a portion of such asserted Title Defects at Seller’s sole cost and expense. Any asserted Title Defects which are waived by Buyer or cured within such time shall be deemed “Permitted Encumbrances” hereunder. If Seller within such time fails to cure any Title Defect of which Buyer has given timely written notice as required above and Buyer has not and does not waive same on or before the day immediately preceding the Closing Date, the Property Subdivision affected by such uncured and unwaived Title Defect shall be a “Title Defect Property”.

(d)Buyer’s Title Adjustments. Subject to Sections 6.5 and 6.6, as Buyer’s sole and exclusive remedy with respect to Title Defects, Buyer shall be entitled to reduce the Purchase Price by the amount, if any, by which the aggregate amount of Title Defect Amounts with respect to all Title Defect Properties exceeds an amount equal to two and one-half percent (2.5%) of the Purchase Price (the “Title Defect Deductible”) plus the aggregate amount of Seller Title Credits with respect to all Property Subdivisions. As used herein, the term “Title Defect Amount” shall mean, with respect to a Title Defect Property, the amount by which the value of such Title Defect Property is impaired as a result of the existence of one or more uncured and unwaived Title Defects, which amount shall be determined as follows:

(1)If the Title Defect results from Seller having a lesser Net Revenue Interest in such Title Defect Property than the Net Revenue Interest specified therefor in Part II(A) of the Property Schedule, the Title Defect Amount shall be equal to the product obtained by

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multiplying the portion of the Purchase Price allocated to such Title Defect Property in Part II(A) of the Property Schedule by a fraction, the numerator of which is the reduction in the Net Revenue Interest and the denominator of which is the Net Revenue Interest specified for such Title Defect Property in Part II(A) of the Property Schedule.

(2)If the Title Defect results from Seller having a greater Working Interest in a Title Defect Property set forth in Part II(A) of the Property Schedule than the Working Interest specified therefor in Part II(A) of the Property Schedule, the Title Defect Amount shall be equal to the present value (discounted at 10% compounded annually) of the increase in the costs and expenses forecasted in the Reserve Report with respect to such Title Defect Property for the period from and after the Effective Time which is attributable to such increase in Seller’s Working Interest; provided, however, that no Title Defect Amount shall be allowed on account of and to the extent that an increase in Seller’s Working Interest in such a Property Subdivision has the effect of proportionately increasing Seller’s Net Revenue Interest therein.

(3)If the Title Defect results from Seller having fewer number of Net Acres in a Title Defect Property set forth in Part II(B) of the Property Schedule than the number of Net Acres specified therefor in Part II(B) of the Property Schedule, the Title Defect Amount shall be equal to the product obtained by multiplying the portion of the Purchase Price allocated to such Title Defect Property in Part II(B) of the Property Schedule by a fraction, the numerator of which is the reduction in the Net Acres and the denominator of which is the number of Net Acres specified for such Title Defect Property in Part II(B) of the Property Schedule.

(4)If the Title Defect results from the existence of a lien, the Title Defect Amount shall be an amount sufficient to discharge such lien.

(5)If the Title Defect results from any matter not described in paragraphs (1), (2), (3) or (4) above, the Title Defect Amount shall be an amount equal to the difference between the value of the Title Defect Property affected by such Title Defect with such Title Defect and the value of such Title Defect Property without such Title Defect (taking into account the portion of the Purchase Price allocated in Part II of the Property Schedule to such Title Defect Property); provided, however, if such Title Defect is reasonably susceptible of being cured, the Title Defect Amount shall not be greater than the reasonable cost and expense of curing such Title Defect.

(6)If a Title Defect is not effective or does not affect a Title Defect Property throughout the entire productive life of such Title Defect Property, such fact shall be taken into account in determining the Title Defect Amount.

(7)The Title Defect Amount with respect to a Title Defect Property shall be determined without duplication of any costs or losses included in another Title Defect Amount hereunder. For example, but without limitation, if a lien affects more than one Title Defect Property or the curative work with respect to one Title Defect results (or is reasonably expected to result) in the curing of any other Title Defect affecting the same or another Title

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Defect Property, the amount necessary to discharge such lien or the cost and expense of such curative work shall only be included in the Title Defect Amount for one Title Defect Property and only once in such Title Defect Amount.

(8)If a Title Defect affects only a portion of a Property Subdivision (as contrasted with an undivided interest in the entirety of such Property Subdivision) and a portion of the Purchase Price has not been allocated specifically to such portion of a Property Subdivision in the Property Schedule, then for purposes of computing the Title Defect Amount, the portion of the Purchase Price allocated to such Property Subdivision shall be further allocated among the portions of such Property Subdivision in the proportion that the net acreage (or net acre feet, as appropriate) of such Property Subdivision affected by such Title Defect bears to the net acreage (or net acre feet, as appropriate) in the entire Property Subdivision. In the event such Property Subdivision is subject to a unitization agreement, the foregoing allocation shall be made in a manner which is consistent with the allocation of production or productive acreage in such unitization agreement.

(9)The Title Defect Amount attributable to a Title Defect Property or any portion thereof shall not exceed the portion of the Purchase Price allocated to such Title Defect Property or such portion thereof calculated in accordance with paragraph (8) above. For example, but without limitation, if Seller does not own fifty percent (50%) of the Net Revenue Interest specified in the Property Schedule for a Title Defect Property and such unowned fifty percent (50%) interest is also burdened by a lien, the Title Defect Amount for such Title Defect Property shall not exceed the portion of the Purchase Price allocable to such fifty percent (50%) interest notwithstanding that it may be affected by multiple Title Defects.

(10)Notwithstanding the foregoing, if the Title Defect Amount determined pursuant to the foregoing with respect to a Title Defect Property is $20,000 or less (or, with respect to a Title Defect affecting a Property Subdivision described in Part II(B) of the Property Schedule, $20,000 or less per oil and gas lease affected thereby), then the Title Defect Amount with respect to such Title Defect Property (or, with respect to a Title Defect affecting a Property Subdivision described in Part II(B) of the Property Schedule, the Title Defect Amount with respect to such oil and gas lease) shall be deemed to be zero.

The Title Defect Deductible shall be restored to the extent that any portion thereof is applied as a credit against a Title Defect Amount attributable to a Title Defect which is subsequently cured by Seller or determined not to constitute a Title Defect.

6.3Determination of Title Defects. A portion of a Property Subdivision shall be deemed to have a “Title Defect” if Seller does not have Defensible Title thereto as of the Effective Time and as of the Closing Date. Notwithstanding any other provision in this Agreement to the contrary, the following matters shall be deemed to be Permitted Encumbrances and shall not be asserted as, and shall not constitute Title Defects: (a) defects in the early chain of the title consisting of the mere failure to recite marital status in a document or omissions of successions of heirship proceedings, unless Buyer provides affirmative evidence that such failure or omission results in another Person’s superior claim of title to the relevant Property Subdivision or portion thereof, (b) defects arising out of lack of survey, (c) defects arising out of lack of corporate authorization,

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unless Buyer provides affirmative evidence that such corporate action was not authorized and results in another Person’s superior claim of title to the relevant Property Subdivision or portion thereof, (d) defects that have been cured by possession under the applicable statutes of limitations or prescription, (e) defects or irregularities resulting from or related to probate proceedings or the lack thereof, which defects or irregularities have been outstanding for four (4) years or more, (f) defects based solely on the existence of prior oil and gas leases relating to the Subject Interests that are expired and no longer in force and legal effect but not surrendered of record, (g) defects arising from a mortgage encumbering the oil, gas or mineral estate of any lessor (unless a complaint of foreclosure has been filed or any similar action taken by the mortgagee thereunder and in such case such mortgage has not been subordinated to the Subject Interests affected thereby), (h) defects based solely on lack of information in Seller’s files or references to documents if such documents are not in Seller’s files, and (i) defects in the chain of title prior to January 1, 1950, unless Buyer provides affirmative evidence that the defect results in another Person’s superior claim of title to the relevant Property Subdivision or portion thereof.

6.4Seller Title Credit. A “Seller Title Credit” shall mean, with respect to a Property Subdivision, the amount by which the value of such Property Subdivision is enhanced by virtue of (a) Seller having a greater Net Revenue Interest in such Property Subdivision than the Net Revenue Interest specified therefor in Part II(A) of the Property Schedule, (b) with respect to each Property Subdivision described in Part II(A) of the Property Schedule, Seller having a lesser Working Interest in such Property Subdivision than the Working Interest specified therefor in Part II(A) of the Property Schedule without a corresponding reduction in Net Revenue Interest with respect to such Property Subdivision specified therefor in Part II(A) of the Property Schedule or (c) with respect to each Property Subdivision described in Part II(B) of the Property Schedule, Seller having a greater number of Net Acres than the number of Net Acres specified therefor in Part II(B) of the Property Schedule. The amount of Seller Title Credits shall be determined as follows:

(1)If the Seller Title Credit results from Seller having a greater Net Revenue Interest in such Property Subdivision than the Net Revenue Interest specified therefor in Part II(A) of the Property Schedule, the Seller Title Credit shall be equal to the product obtained by multiplying the portion of the Purchase Price allocated to such Property Subdivision in Part II(A) of the Property Schedule by a fraction, the numerator of which is the increase in the Net Revenue Interest and the denominator of which is the Net Revenue Interest specified for such Property Subdivision in Part II(A) of the Property Schedule.

(2)If the Seller Title Credit results from Seller having a lesser Working Interest in a Property Subdivision than the Working Interest specified therefor in Part II(A) of the Property Schedule without a corresponding reduction in Net Revenue Interest with respect to such Property Subdivision specified therefor in Part II(A) of the Property Schedule, the Seller Title Credit shall be equal to the present value (discounted at 10% compounded annually) of the decrease in the costs and expenses forecasted in the Reserve Report with respect to such Property Subdivision for the period from and after the Effective Time which is attributable to such decrease in Seller's Working Interest; provided, however, no Seller Title Credit shall be allowed on account of and to the extent that a decrease in Seller’s

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Working Interest in such a Property Subdivision has the effect of proportionately decreasing Seller’s Net Revenue Interest therein.

(3)If the Title Defect results from Buyer having greater number of Net Acres in a Property Subdivision than the number of Net Acres specified therefor in Part II(B) of the Property Schedule, the Seller Title Credit shall be equal to the product obtained by multiplying the portion of the Purchase Price allocated to such Property Subdivision in Part II(B) of the Property Schedule by a fraction, the numerator of which is the increase in the Net Acres and the denominator of which is the number of Net Acres specified for such Property Subdivision in Part II(B) of the Property Schedule.

(4)In determining the amount of Seller Title Credits, the principles and methodology set forth in paragraphs (6), (7), (8) and (10) of Section 6.2(d) shall be applied, mutatis mutandis.

6.5Exclusion of Title Defect Properties. On or before the Closing Date, Seller may with respect to any Title Defect Property elect to retain and exclude such Title Defect Property from the Assets to be conveyed by Seller to Buyer pursuant to the terms hereof so long as the Purchase Price is reduced by the portion of the Purchase Price allocated (or deemed allocated pursuant to Section 6.2(d)(8)) to such Title Defect Property in Part II of the Property Schedule. In the event Seller exercises its right under this Section 6.5 with respect to a Title Defect Property, said Title Defect Property, together with a pro rata share of all incidental rights, oil, gas and other hydrocarbons and other assets attributable or appurtenant thereto, shall be retained by Seller and excluded from the Assets which are conveyed by Seller to Buyer pursuant to the Conveyance.

6.6Deferred Claims and Disputes. In the event that Buyer and Seller have not agreed upon one or more adjustments, credits or offsets claimed by Buyer or Seller pursuant to and in accordance with the requirements of this Article VI, any such claim (a “Deferred Adjustment Claim”) shall be settled pursuant to this Section 6.6 and, except as provided in Sections 9.1(e) and 9.2(e), shall not prevent or delay Closing. With respect to each potential Deferred Adjustment Claim, Buyer and Seller shall deliver to the other a written notice describing each such potential Deferred Adjustment Claim, the amount in dispute and a statement setting forth the facts and circumstances that support such Party’s position with respect to such Deferred Adjustment Claim. At Closing, the Purchase Price shall not be adjusted on account of, and, except as provided in Sections 9.1(e) and 9.2(e), no effect shall be given to, the Deferred Adjustment Claim. On or prior to the thirtieth (30th) consecutive calendar day following the Closing Date (the “Deferred Matters Date”), Seller and Buyer shall attempt in good faith to reach agreement on the Deferred Adjustment Claims and, ultimately, to resolve by written agreement all disputes regarding the Deferred Adjustment Claims. Any Deferred Adjustment Claims which are not so resolved on or before the Deferred Matters Date shall be submitted to final and binding arbitration in accordance with the Arbitration Procedures; provided, however, that Seller may elect at any time to resolve all disputes relating to the Deferred Adjustment Claims by the payment to Buyer of the amount by which the Purchase Price would have been reduced at Closing on account of the Title Defects which constitute Deferred Adjustment Claims if same did not constitute Deferred Adjustment Claims. Notwithstanding anything herein provided to the contrary, including Section 6.2(c), Seller shall be

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entitled to cure any Title Defect which constitutes a Deferred Adjustment Claim at any time prior to the point in time when a final and binding written decision of the board of arbitrators is made with respect thereto in accordance with the Arbitration Procedures. The amount of any reduction in the Purchase Price to which Buyer becomes entitled under the final and binding written decision of the board of arbitrators shall be promptly refunded by Seller to Buyer together with interest thereon from the Closing Date until paid at the Agreed Rate.

6.7No Duplication. Notwithstanding anything herein provided to the contrary, if a Title Defect results from any matter which could also result in the breach of any representation or warranty of Seller set forth in Section 4.1, then Buyer shall only be entitled to assert such matter as a Title Defect pursuant to this Article VI and shall be precluded from also asserting such matter as the basis of the breach of any such representation or warranty.

ARTICLE VII
PREFERENCE RIGHTS AND TRANSFER REQUIREMENTS

7.1Compliance. Buyer’s purchase of the Assets is expressly subject to all validly existing and applicable Preference Rights and Transfer Requirements. To Seller’s knowledge, all agreements containing a (i) Preference Right are set forth in Part I of Schedule 7.1 and (ii) Transfer Requirement are set forth in Part II of Schedule 7.1. Prior to the Closing Date, Seller shall initiate all procedures required to comply with or obtain the waiver of all Preference Rights and Transfer Requirements set forth on Schedule 7.1 with respect to the transactions contemplated by this Agreement. Seller shall not be obligated to pay any consideration to (or incur any cost or expense for the benefit of) the holder of any Preference Right or Transfer Requirement in order to obtain the waiver thereof or compliance therewith.

7.2Effect of Preference Rights. If a third party who has been offered a Preference Property pursuant to Section 7.1 elects prior to Closing to purchase such Preference Property in accordance with the terms of such Preference Right, and Seller receives written notice of such election prior to the Closing Date, such Preference Property will be eliminated from the Assets and the Purchase Price shall be reduced by the portion of the Purchase Price allocated to such Preference Property pursuant to the immediately following sentence. The portion of the Purchase Price to be allocated to any Asset or portion thereof affected by a Preference Right (a “Preference Property”) shall be the portion of the Purchase Price allocated thereto in Part II of the Property Schedule. If a Preference Right affects only a portion of a Property Subdivision and a portion of the Purchase Price has not been allocated specifically to such portion of a Property Subdivision in Part II of the Property Schedule, then the portion of the Purchase Price to be allocated to such Preference Property shall be determined in the same manner as provided in Section 6.2(d)(8) when a Title Defect affects only a portion of a Property Subdivision. If a third party who has been offered a Preference Property or who has been requested to waive its Preference Right pursuant to Section 7.1 does not elect to purchase such Preference Property or waive such Preference Right with respect to the transactions contemplated by this Agreement prior to the Closing Date, such Preference Property shall be conveyed to Buyer at Closing subject to such Preference Right, unless such Preference Property has been otherwise eliminated from the Assets in accordance with other provisions of this Agreement. If a third party elects to purchase a Preference Property subject to a Preference Right

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and Closing has already occurred with respect to such Preference Property, Buyer shall be obligated to convey said Preference Property to such third party and shall be entitled to the consideration for the sale of such Preference Property.

7.3Transfer Requirements. If a Transfer Requirement is applicable to the transactions contemplated by this Agreement and the failure to satisfy such Transfer Requirement would, by its express terms and applicable Law, render the assignment of an Asset void or result in termination thereof, is not obtained, complied with or otherwise satisfied prior to the Closing Date, then, unless otherwise mutually agreed in writing by Seller and Buyer, (i) any Asset or portion thereof affected by such Transfer Requirement (a “Retained Asset”) shall be held back from the Assets to be transferred and conveyed to Buyer at Closing and the Purchase Price to be paid at Closing shall be reduced by the portion of the Purchase Price which would be allocated to such Retained Asset pursuant to Section 7.2 if such Retained Asset were a Preference Property. Any Retained Asset so held back at the Closing will be conveyed to Buyer within ten (10) days following the date on which Seller obtains, complies with or otherwise satisfies all Transfer Requirements with respect to such Retained Asset for a purchase price equal to the amount by which the Purchase Price was reduced on account of the holding back of such Retained Asset, as adjusted pursuant to Section 3.4; provided, however, if all Transfer Requirements with respect to any Retained Asset so held back at the Closing are not obtained, complied with or otherwise satisfied within one hundred eighty (180) days following the Closing Date, then such Retained Asset shall be eliminated from the Assets and this Agreement unless Seller and Buyer mutually agree to proceed with a closing on such Retained Asset in which case Buyer shall be deemed to have waived any objection with respect to non-compliance with such Transfer Requirements.

7.4Certain Governmental Consents. Seller and Buyer will each use its respective commercially reasonable efforts after Closing to obtain all approvals and consents from the United States Department of Interior and the applicable state or Indian agencies or authorities that may be required under the terms of (or regulations specifically applicable to) any federal, state or Indian leases in connection with the assignment of the Subject Interests therein from Seller to Buyer. Until such approvals and consents are obtained, Seller shall continue to hold legal title to such Subject Interests as nominee for Buyer. Seller shall not be obligated to incur any costs or expenses in Seller’s capacity as nominee. For purposes of Article XIII, Seller and Buyer shall treat and deal with such Subject Interests as if full legal and equitable title to such Subject Interests had passed from Seller to Buyer at Closing.

7.5Express Conditions on Sale. Buyer acknowledges that Seller desires to sell all of the Assets and would not have entered into this Agreement but for Buyer’s agreement to purchase all of the Assets as herein provided. Accordingly, it is expressly understood and agreed that Seller does not desire to sell any Preference Property unless the sale of all or substantially all of the Assets is consummated by the Closing Date in accordance with the terms of this Agreement. In furtherance of the foregoing, Seller’s obligation hereunder to sell the Preference Properties to Buyer is expressly conditioned upon the consummation by the Closing Date of the transactions contemplated by this Agreement, either by conveyance to Buyer, exclusion by Seller or conveyance pursuant to an applicable Preference Right; provided that, nothing herein is intended or shall operate to extend or apply any Preference Right to any portion of the Assets which is not otherwise burdened thereby.

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Time is of the essence with respect to the Parties’ agreement to consummate the sale of the Assets by the Closing Date.

ARTICLE VIII
COVENANTS OF SELLER AND BUYER

8.1Conduct of Business Pending Closing. Subject to Section 8.2 and the constraints of applicable operating and other agreements, from the date hereof through the Closing (or the earlier termination of this Agreement), except as disclosed on Schedule 8.1, or as otherwise consented to or approved by Buyer in writing (which consent or approval shall not be unreasonably withheld, conditioned or delayed), Seller covenants and agrees that:

(a)Sales. Seller shall not sell, transfer, assign, convey, farmout, release, abandon or otherwise dispose of any Assets, or enter into any transaction the effect of which would be to cause Seller’s ownership interest in any of the Assets to be altered from Seller’s ownership interest as of the date of this Agreement, other than (i) oil, gas and other hydrocarbons produced, saved and sold in the ordinary course of business, and (ii) personal property or equipment which is replaced with personal property or equipment of comparable or better value and utility in connection with the maintenance and operation of the Assets.

(b)Liens. Seller shall not grant a lien or security interest on any Assets (other than a Permitted Encumbrance).

(c)Operation of Assets. Seller shall:

(ii)cause the Assets to be maintained and operated in the ordinary course of business, in accordance with Seller’s past practices, maintain insurance now in force with respect to the Assets, and pay or cause to be paid all costs and expenses in connection therewith promptly when due;

(iii)not commit to participate in the drilling of any new well or other new operations on the Assets the cost of which (net to Seller’s interest) is in excess of $250,000 in any single instance, without the advance written consent of Buyer, which consent or non‑consent must be given by Buyer within the lesser of (x) ten (10) days of Buyer’s receipt of the notice from Seller or (y) one-half (½) of the applicable notice period within which Seller is contractually obligated to respond to third parties to avoid a deemed election by Seller regarding such operation, as specified in Seller’s notice to Buyer requesting such consent; provided that, failure by Buyer to respond within the aforesaid applicable period shall constitute Buyer’s consent to Seller’s participation in such well or other operation;

(iv)maintain and keep the Assets in full force and effect, including, without limitation, the timely and proper payment of all delay rentals and the timely and proper exercise of optional renewals or primary term extensions under all of the undeveloped leases included in the Assets for which expiration is scheduled to occur on or before January 31, 2014, except where such failure is due to (i) the failure to pay a delay rental, royalty, shut in royalty or other payment by mistake or oversight (including Seller’s negligence) unless

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caused by Seller’s gross negligence or willful misconduct, or (ii) the failure to participate in an operation which Buyer does not timely approve;

(v)not elect to go non-consent on any operation on the Assets proposed by a third party, subject to the provisions of Section 8.2(b);

(vi)use Seller’s commercially reasonable efforts to maintain its relationships with suppliers, customers and others having material business relations with Seller with respect to the Assets so that they will be preserved for Buyer on and after the Closing Date;

(vi)    subject to the immediately following sentence, not later than November 7, 2013, initiate and diligently continue repair, work or re-work, as applicable, on the John W. Morgan “A” 1 Well located in Section 1, Township 1 North, Range 20 East CM, Beaver County, Oklahoma, to attempt to return such well to production on or before the Closing Date. Notwithstanding anything to the contrary in this Section 8.1(c), Seller shall not perform any operation on such well in excess of $50,000 without the advance written consent of Buyer.

(d)Contracts and Agreements. Seller shall not:

(iii)grant or create any Preference Right or Transfer Requirement with respect to the Assets except in connection with the performance by Seller of an obligation or agreement existing on the date hereof or pursuant to this Agreement;

(iv)enter into any oil, gas or other hydrocarbon sales, supply, exchange, processing or transportation contract with respect to the Assets which is not terminable without penalty or detriment on notice of sixty (60) days or less; or

(v)voluntarily relinquish any Seller’s position as operator with respect to the Assets.

(e)Qualifications on Seller’s Conduct. Seller shall:

(iv)pay all expenses incurred with respect to the Assets owned or operated by it in the usual, regular and ordinary manner consistent with past practice and pay all royalties and other burdens and make distribution of production revenues to the owners entitled thereto in accordance with past practices and applicable Law;

(v)give written notice to Buyer as soon as is practicable of any written notice received or given by Seller with respect to any alleged breach by Seller or other Person of any Material Contract;

(vi)give prompt notice to Buyer of (A) any written notice of any material damage to or destruction of any of the Assets of which Seller has knowledge and (B) any written notice received by Seller of any claim asserting any tort or violation of Law or any investigation, suit, action or litigation by or before a Governmental Authority, that (in each case) relates to the Assets and of which Seller has knowledge;

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(i)not enter into any contract that would have been a Material Contract if it had been in effect on the date hereof; and

(ii)not amend, modify or terminate any Material Contract or otherwise waive, release or assign any material rights, claims or benefits of Seller under any Material Contract (except for amendments or modifications to (A) compressor contracts for the purpose of obtaining additional compressors and (B) oil, gas or other hydrocarbon sales contracts for the purpose of selling oil, gas or other hydrocarbons included in the Assets on the terms provided by such existing contracts).

8.2Emergencies; Legal Requirements. Seller may take (or not take, as the case may be) any of the actions mentioned in Section 8.1 above if reasonably necessary under emergency circumstances (or if required or prohibited (as the case may be) pursuant to Law) and provided Buyer is notified as soon thereafter as practicable.

(b)Non‑Operated Properties. If Seller is not the operator of a particular portion of the Assets, the obligations of Seller in Section 8.1 above with respect to such portion of the Assets, which have reference to operations or activities which pursuant to existing contracts are carried out or performed by the operator, shall be construed to require only that Seller use commercially reasonable efforts (without being obligated to incur any expense or institute any cause of action) to cause the operator of such portion of the Assets to take such actions or render such performance within the constraints of the applicable operating agreements and other applicable agreements.

(c)Certain Operations. Should Seller not wish to pay any lease rental or other payment or participate in any reworking, deepening, drilling, completion, equipping or other operation on or with respect to any well or other Property Subdivision which may otherwise be required by Section 8.1 above, Seller shall give Buyer written notice thereof at least fifteen (15) days prior to the date such rental or other payment is due or, in the case of an operation, promptly after Seller receives notice of such proposed operation from the operator of such property (or if Seller is the operator, at the same time Seller gives or is required to give notice of such proposed operation to the non‑operators of such property); and Seller shall not be obligated to make any such payment or to elect to participate in any such operation which Seller does not wish to make or participate in unless Seller receives from Buyer, within a reasonable time prior to the date when such payment or election is required to be made by Seller, the written election and agreement of Buyer (i) to require Seller to take such action and (ii) to pay all costs and expenses of Seller with respect to such lease rental or other payment or such operation. Notwithstanding the foregoing, Seller shall not be obligated to pay any lease rental or other payment or to elect to participate in any operation if the operator of the property involved recommends that such action not be taken. If Buyer advances any funds pursuant to this Section 8.2(b) with respect to a particular portion of the Assets, such portion of the Assets is not conveyed to Buyer at Closing or Closing does not occur, and such funds are not reimbursed to Buyer within thirty (30) days after the earlier of Closing or termination of this Agreement, then, with respect to such particular portion of the Assets, (i) Buyer shall own and be entitled to any interest of Seller that would have lapsed but for such payment or (ii) in the case of operations, Buyer shall be entitled to receive the penalty, if any, that Seller, as nonconsenting party, would have suffered under the applicable operating or other agreement with respect to such

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operations as if Buyer were a consenting party thereunder; in each case, subject to and after deduction of any damages or other relief to which Seller may be entitled with respect to any breach by Buyer of this Agreement.

8.3Conveyance. Upon the terms and subject to the conditions of this Agreement, at or prior to the Closing, Seller and Buyer shall execute and deliver or cause the execution and delivery of the General Conveyance, in substantially the form attached hereto as Exhibit 8.3 (the “Conveyance”), together with all special federal, state and tribal assignment forms as may be required by Law to be executed in connection with the conveyance of specific Assets; provided that, the terms and provisions of the Conveyance shall control as to any conflict between the Conveyance and any such special assignment forms.

8.4Public Announcements. Without the prior written approval of the other Party, which approval shall not be unreasonably withheld, no Party will issue, or permit any agent or Affiliate to issue, any press releases or otherwise make, or cause any agent or Affiliate to make, any public statements with respect to this Agreement and the transactions contemplated hereby, except where such release or statement is deemed in good faith by the releasing Party to be required by Law or any national securities exchange, in which case the Party or Parties will use its or their, as the case may be, commercially reasonable efforts to provide a copy to the other Party prior to any release or statement.

8.5Further Assurances. Seller and Buyer each agrees that, from time to time, whether before, at or after the Closing Date, each of them will execute and deliver or cause their respective Affiliates to execute and deliver such further instruments of conveyance and transfer and take such other action as may be necessary to carry out the purposes and intents of this Agreement. Any separate or additional assignment of the Assets or any portion thereof required pursuant to this Section 8.5 (i) shall evidence the conveyance and assignment of the Assets made or intended to be made in the Conveyance, (ii) shall not modify or be deemed to modify any of the terms, covenants and conditions set forth in the Conveyance, and (iii) shall be deemed to contain all of the terms and provisions of the Conveyance, as fully as though the same were set forth at length in such separate or additional assignment.

8.6Removal. Buyer shall have no right to use the name or mark of Seller or any of its Affiliates (or any variation or derivative thereof) or the logos relating thereto and, as promptly as practicable, but in any case within sixty (60) days after the Closing Date, Buyer shall remove the name and mark of Seller and any of its Affiliates and any variations and derivatives thereof and logos relating thereto from the Assets. Because damages would be an inadequate remedy, the Parties agree that Seller shall be entitled to seek specific performance and injunctive relief as remedies for any breach by Buyer of this Section 8.6.

8.7Records. Within a reasonable period of time following the Closing, Seller shall make all Records available for delivery to Buyer in Houston, Texas. Buyer agrees to maintain the Records that are acquired pursuant to this Agreement until the fifth (5^th) anniversary of the Closing Date (or for such longer period of time as Seller shall advise Buyer is necessary in order to have Records available with respect to open years for tax audit purposes), or, if any of such Records pertain to any claim or dispute pending on the fifth (5^th) anniversary of the Closing Date, Buyer shall maintain

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any of such Records designated by Seller until such claim or dispute is finally resolved and the time for all appeals has been exhausted. Buyer shall provide Seller and its representatives reasonable access to and the right to copy such Records for the purposes of (i) preparing and delivering any accounting provided for under this Agreement and adjusting, prorating and settling the charges and credits provided for in this Agreement, (ii) complying with any Law affecting Seller’s interest in the Assets prior to the Closing Date, (iii) preparing any audit of the books and records of any third party relating to Seller’s interest in the Assets prior to the Closing Date, or responding to any audit prepared by such third parties, (iv) preparing Tax Returns, (v) responding to or disputing any tax audit or (vi) asserting, defending or otherwise dealing with any claim or dispute under this Agreement or with respect to the Assets. In no event shall Buyer destroy any Records without giving Seller sixty (60) days’ advance written notice thereof and the opportunity, at Seller’s expense, to obtain such Records prior to their destruction.

8.8Amendment of Schedules. Buyer agrees that, with respect to (but only with respect to) the representations and warranties of Seller contained in this Agreement, Seller shall have the continuing right until the Closing to add, supplement or amend all schedules hereto to its representations and warranties with respect to any matter hereafter arising which, if existing at the date of this Agreement, would have been required to be set forth or described in such schedules; provided that, Seller may not add, supplement or amend any such schedules to make any change arising out of any breach by Seller of this Agreement. For purposes of determining whether the conditions set forth in Section 9.2(a) have been fulfilled, the schedules to Seller’s representations and warranties contained in this Agreement shall be deemed to include only that information contained therein on the date of this Agreement and shall be deemed to exclude all information contained in any addition, supplement or amendment thereto.

8.9Recording. Immediately following the Closing, Buyer, at its cost and expense, shall record the Conveyance and all other instruments of assignment in the appropriate governmental offices of the jurisdictions in which the Assets are located and in any other locations and records in which recordation is required or advisable. Promptly following such recording, Buyer shall advise Seller in writing of the pertinent recording data.

8.10Casualty and Condemnation. If after the date of this Agreement and prior to the Closing any part of the Assets shall be destroyed or damaged by fire or other casualty or if any part of the Assets shall be taken in condemnation or under the right of eminent domain or if proceedings for such purposes shall be pending or threatened, this Agreement shall remain in full force and effect notwithstanding any such destruction, damage, taking or proceeding or the threat thereof. To the extent insurance proceeds, condemnation awards or other payments are not committed, used or applied by Seller prior to the Closing Date to repair, restore or replace such destroyed, damaged or taken Assets, Seller shall at the Closing (a) assign to Buyer Seller’s right to receive all insurance or condemnation proceeds, awards or payments owed to Seller by reason of such destruction or taking, less any reasonable costs and expenses incurred by Seller in collecting same or in connection with such proceedings or the threat thereof, and (b) pay to Buyer all insurance or condemnation proceeds, awards or payments theretofore paid to Seller by reason of such destruction, damage or taking, less any reasonable costs and expenses incurred by Seller in collecting same or in connection with such proceedings or the threat thereof. Notwithstanding the foregoing, any insurance or

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condemnation proceeds, awards or payments (or any rights thereto) by reason of such destruction, damage or taking which are held by or owed to Seller for the account or benefit of any third party joint interest owners shall not be paid or assigned by Seller to Buyer pursuant to this Section 8.10 and shall instead be transferred to the successor operator or other Person responsible therefor pursuant to the terms of the applicable operating or other agreement. In the event (i) any condemnation action results in a condemnation payment in an amount less than the allocated value of the affected Asset, or (ii) any casualty event or condemnation action results in the loss or destruction of personal property or equipment without compensation for the reasonable replacement cost thereof, then in any such event the Purchase Price shall be adjusted downward at Closing in the amount of the deficiency.

8.11Operations. Seller agrees to execute and deliver to Buyer, at Closing, change of operator forms as required by the applicable Governmental Authorities and to recommend Buyer as successor operator (i) of each well currently operated by a Seller or an Affiliate of Seller, to the extent permitted under any applicable joint operating agreement, and (ii) under each forced pooling order pursuant to which Seller or an Affiliate of Seller has been designated as unit operator.

8.12Revenues in Suspense. At the Closing, Seller will deliver to Buyer (by adjustment of the Purchase Price pursuant to Section 3.1) all revenues then held in suspense by Seller and relating to the Assets, together with a current suspense register detailing the suspense accounts. Buyer agrees to pay when due to the owners thereof, or otherwise in accordance with applicable law, all suspense revenues so delivered by Seller and to indemnify and hold harmless Seller with respect to the payment thereof up to but not exceeding the amount delivered by Seller.

8.13Certain Invoices. From and after the Closing Date until the first anniversary thereof, Seller agrees to pay any unpaid invoice received by it or by Buyer for services rendered and/or goods and materials delivered to or for the benefit of Seller with respect to the exploration, construction, ownership, maintenance or operation of the Assets prior to the Effective Time. Seller acknowledges and agrees that such obligation exists irrespective of the fact that the costs and expenses reflected in such invoices were incurred pursuant to liens, encumbrances or contracts that constitute Permitted Encumbrances.

8.14    Settlement of Pending Action. Seller will not compromise or settle the Action listed on Schedule 4.1(e), except to the extent such compromise or settlement is for the payment of money for time periods before the Effective Time, without the consent of Buyer, which consent will not be unreasonably withheld, delayed or conditioned. Buyer will not compromise or settle the Action listed on Schedule 4.1(e), except to the extent such compromise or settlement is for the payment of money for time periods after the Effective Time, without the consent of Seller, which consent will not be unreasonably withheld, delayed or conditioned.

ARTICLE IX
CLOSING CONDITIONS

9.1Seller’s Closing Conditions. The obligation of Seller to proceed with the Closing is subject, at the option of Seller, to the satisfaction on or prior to the Closing Date of all of the following conditions:

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(d)Representations, Warranties, Covenants and Agreements. The (i) representations and warranties of Buyer contained in Sections 4.2 and 12.2(A) shall be true and correct in all material respects (and in all respects, in the case of representations and warranties which are qualified by materiality) on and as of the Closing Date (as though made as of the Closing Date), and (ii) covenants and agreements of Buyer to be performed on or before the Closing Date in accordance with this Agreement shall have been duly performed in all material respects.

(e)Officer’s Certificate. Seller shall have received a certificate dated as of the Closing Date, executed by a duly authorized officer of Buyer, to the effect that the conditions set forth in paragraph (a) of this Section 9.1 have been satisfied.

(f)Closing Deliveries. On or prior to the Closing Date, Buyer shall have delivered, or be standing ready to deliver at Closing, all agreements, instruments and other documents or items required to be delivered by Buyer pursuant to Section 10.3.

(g)No Action. On the Closing Date, no suit, action or other proceeding (excluding any such matter initiated by Seller or any of its Affiliates) shall be pending or threatened before any court or other Governmental Authority seeking to enjoin or restrain the consummation of the Closing or recover damages from Seller resulting therefrom.

(h)Adjustments. The sum of (i) the reduction in the Purchase Price on account of the aggregate amount of all Title Defect Amounts and the exclusion of Title Defect Properties pursuant to Section 6.5, (ii) the aggregate amount of Title Defect Amounts claimed by Buyer with respect to unresolved Deferred Adjustment Claims and (iii) the reduction in the Purchase Price on account of the exclusion of Retained Assets pursuant to Section 7.3 shall not exceed Twenty-Five Million Dollars ($25,000,000).

9.2Buyer’s Closing Conditions. The obligation of Buyer to proceed with the Closing is subject, at the option of Buyer, to the satisfaction on or prior to the Closing Date of all of the following conditions:

(a)Representations, Warranties, Covenants and Agreements. The (i) representations and warranties of Seller contained in Section 4.1 of this Agreement shall be true and correct in all material respects (and in all respects, in the case of representations and warranties which are qualified by materiality or Material Adverse Effect) on and as of the Closing Date (as though made as of the Closing Date) (except to the extent such representations and warranties expressly relate to an earlier date, in which case such representations and warranties shall be deemed to refer to such earlier date referenced in such representation and warranty), and (ii) covenants and agreements of Seller to be performed on or before the Closing Date in accordance with this Agreement shall have been duly performed in all material respects.

(b)Officer’s Certificate. Buyer shall have received a certificate dated as of the Closing Date, executed by a duly authorized officer of Seller, to the effect that the conditions set forth in subsection (a) of this Section 9.2 have been satisfied.

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(c)Closing Deliveries. On or prior to the Closing Date, Seller shall have delivered, or be standing ready to deliver at Closing, all agreements, instruments and other documents or items required to be delivered by Seller pursuant to Section 10.2.

(d)No Action. On the Closing Date, no suit, action or other proceeding (excluding any such matter initiated by Buyer or any of its Affiliates) shall be pending or threatened before any court or other Governmental Authority seeking to enjoin or restrain the consummation of the Closing or recover damages from Buyer resulting therefrom.

(e)Adjustments. The sum of (i) the reduction in the Purchase Price on account of the aggregate amount of all Title Defect Amounts and the exclusion of Title Defect Properties pursuant to Section 6.5, (ii) the aggregate amount of Title Defect Amounts claimed by Buyer with respect to unresolved Deferred Adjustment Claims and (iii) the reduction in the Purchase Price on account of the exclusion of Retained Assets pursuant to Section 7.3 shall not exceed Twenty-five Million Dollars ($25,000,000).

ARTICLE X
CLOSING

10.1Closing. The Closing shall be held on the Closing Date at 10:00 a.m., Houston time, at the offices of Fulbright & Jaworski LLP, 1301 McKinney, Suite 5100, Houston, Texas, or at such other time or place as Seller and Buyer may otherwise agree in writing.

10.2Seller’s Closing Obligations. At Closing, Seller shall execute and deliver, or cause to be executed and delivered, to Buyer the following:

(a)The Conveyance and the special assignment forms contemplated by Section 8.3;

(b)The officer’s certificate referred to in Section 9.2(b);

(c)A Certificate of Non-Foreign Status, substantially in the form attached hereto as Exhibit 10.2(c);

(d)Letters in lieu of division and transfer orders executed by Seller relating to the Subject Interests in form reasonably necessary to reflect the conveyances contemplated hereby;

(e)Change of operator forms designating Buyer as successor operator of each well currently operated by Seller or an Affiliate of Seller; and

(f)A current suspense register detailing by owner and Property Subdivision all production revenues held in suspense by Seller relating to the Assets, including for each such owner the earliest date revenues payable to such owner were suspensed by Seller or, to Seller’s knowledge, Seller’s predecessor(s) in interest.

(g)    Any other agreements, instruments and documents which are required by other terms of this Agreement to be executed and/or delivered by Seller to Buyer at the Closing.

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10.3Buyer’s Closing Obligations. At Closing, Buyer shall (i) deliver, or cause to be delivered, the Adjusted Purchase Price minus the Deposit to Seller in immediately available funds to the bank account as provided in Section 3.2 and (ii) execute and deliver, or cause to be executed and delivered, to Seller the following:

(a)The Conveyance and the special assignment forms contemplated by Section 8.3 which require or contemplate execution by Buyer;

(b)The officer’s certificate of Buyer referred to in Section 9.1(b); and

(c)Any other agreements, instruments and documents which are required by other terms of this Agreement to be executed and/or delivered by Buyer to Seller at the Closing.

ARTICLE XI
EFFECT OF CLOSING

11.1Revenues. After Closing, all proceeds, accounts receivable, notes receivable, income, revenues, monies and other items included in or attributable to the Excluded Assets shall belong to and be paid over to Seller and all proceeds, accounts receivable, notes receivable, income, revenues, monies and other items included in or attributable to the Assets with respect to any period of time after the Effective Time shall belong to and be paid over to Buyer, except to the extent any such items are credited to Buyer in calculating the Adjusted Purchase Price, as adjusted pursuant to Section 3.4, the same shall belong to and be paid over to Seller.

11.2Payments. If monies are received by any Party which, under the terms of this Article XI, belong to the other Party, the same shall immediately be paid over to the proper Party.

11.3Survival. Except as provided in this Section 11.3, all representations, warranties, covenants and agreements made herein shall survive the Closing. Each representation, warranty, covenant and agreement made herein shall terminate and cease to be of further force and effect as is expressly stipulated in this Section 11.3 for the survival thereof. Following the Closing or such later date stipulated in this Section 11.3 for the survival thereof, such representation, warranty, covenant or agreement shall not form the basis for or give rise to any claim, demand, cause of action, counterclaim, defense, damage, indemnity, obligation or liability which is asserted, claimed, made or filed following the date stipulated in this Section 11.3 for survival. It is expressly agreed that the terms and provisions of:

(a)The Fundamental Representations shall survive the Closing indefinitely, that is, until any claim based thereon is barred by the applicable statute of limitations ; and

(b)All representations and warranties of Seller set out in Section 4.1 hereof, other than the Fundamental Representations, shall survive the Closing for a period of one (1) year. The representations and warranties of Buyer set out in Section 4.2 hereof shall survive the Closing indefinitely, that is, until any claim based thereon is barred by the applicable statute of limitations. The respective covenants of Seller and Buyer under this Agreement that are to be performed in their entirety prior to the Closing shall terminate upon consummation of the Closing. The respective

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covenants of Seller and Buyer under this Agreement that are to be performed wholly or in part at or following the Closing shall survive the Closing for the period specified herein, or if no period is specified then indefinitely, that is, until any claim based thereon is barred by the applicable statute of limitations (for this purpose, nothing contained in Article IV hereof shall be deemed to be a covenant).

In addition, the definitions set forth in Appendix A to this Agreement or in any other provision of this Agreement which are used in the representations, warranties, covenants and agreements which survive the Closing pursuant to this Section 11.3 shall survive the Closing to the extent necessary to give operative effect to such surviving representations, warranties, covenants and agreements.

ARTICLE XII
LIMITATIONS

12.1Disclaimer of Warranties. NOTWITHSTANDING ANYTHING CONTAINED TO THE CONTRARY IN ANY OTHER PROVISION OF THIS AGREEMENT, IT IS THE EXPLICIT INTENT OF EACH PARTY THAT SELLER IS NOT MAKING ANY REPRESENTATION OR WARRANTY WHATSOEVER, EXPRESS, IMPLIED, STATUTORY OR OTHERWISE, BEYOND THOSE REPRESENTATIONS AND WARRANTIES EXPRESSLY GIVEN IN THIS AGREEMENT AND THE CONVEYANCE, AND IT IS UNDERSTOOD THAT, WITHOUT LIMITING SUCH EXPRESS REPRESENTATIONS AND WARRANTIES, BUYER IS TAKING THE ASSETS AS IS AND WHERE IS AND WITH ALL FAULTS. WITHOUT LIMITING THE GENERALITY OF THE IMMEDIATELY PRECEDING SENTENCE, SELLER HEREBY (A) EXPRESSLY DISCLAIMS AND NEGATES ANY REPRESENTATION OR WARRANTY, EXPRESS OR IMPLIED, AT COMMON LAW, BY STATUTE OR OTHERWISE, RELATING TO (I) THE CONDITION OF THE ASSETS (INCLUDING, WITHOUT LIMITATION, ANY IMPLIED OR EXPRESS WARRANTY OF MERCHANTABILITY, FREEDOM FROM REDHIBITORY VICES OR DEFECTS OR FITNESS FOR A PARTICULAR PURPOSE, OR OF CONFORMITY TO MODELS OR SAMPLES OF MATERIALS, OR THE PRESENCE OR ABSENCE OF ANY HAZARDOUS MATERIALS IN OR ON, OR DISPOSED OF OR DISCHARGED FROM, THE ASSETS) OR (II) ANY INFRINGEMENT BY SELLER OR ANY OF ITS AFFILIATES OF ANY PATENT OR PROPRIETARY RIGHT OF ANY THIRD PARTY; AND (B) NEGATES ANY RIGHTS OF BUYER UNDER STATUTES TO CLAIM DIMINUTION OF CONSIDERATION AND ANY CLAIMS BY BUYER FOR DAMAGES BECAUSE OF DEFECTS, WHETHER KNOWN OR UNKNOWN, IT BEING THE INTENTION OF SELLER AND BUYER THAT THE ASSETS ARE TO BE ACCEPTED BY BUYER IN THEIR PRESENT CONDITION AND STATE OF REPAIR.

12.2Texas Deceptive Trade Practices Act Waiver. BUYER (A) REPRESENTS AND WARRANTS TO SELLER THAT IT (I) IS ACQUIRING THE ASSETS FOR COMMERCIAL OR BUSINESS USE, (II) IS REPRESENTED BY LEGAL COUNSEL, (III) ACKNOWLEDGES THE CONSIDERATION PAID OR TO BE PAID FOR THE ASSETS

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WILL EXCEED $500,000, AND (IV) HAS KNOWLEDGE AND EXPERIENCE IN FINANCIAL AND BUSINESS MATTERS SUCH THAT ENABLE IT TO EVALUATE THE MERITS AND RISKS OF THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT AND IS NOT IN A SIGNIFICANTLY DISPARATE BARGAINING POSITION WITH RESPECT TO SELLER; AND (B) HEREBY UNCONDITIONALLY AND IRREVOCABLY WAIVES ANY AND ALL RIGHTS OR REMEDIES IT MAY HAVE UNDER THE DECEPTIVE TRADE PRACTICES - CONSUMER PROTECTION ACT OF THE STATE OF TEXAS, TEX. BUS. & COM. CODE § 17.41 ET SEQ. TO THE MAXIMUM EXTENT IT CAN DO SO UNDER LAW, IF SUCH ACT WOULD FOR ANY REASON BE DEEMED APPLICABLE TO THE TRANSACTIONS CONTEMPLATED HEREBY.

WAIVER OF CONSUMER RIGHTS

BUYER WAIVES ITS RIGHTS UNDER THE DECEPTIVE TRADE PRACTICES - CONSUMER PROTECTION ACT, SECTION 17.41 ET SEQ., BUSINESS & COMMERCE CODE, A LAW THAT GIVES CONSUMERS SPECIAL RIGHTS AND PROTECTIONS. AFTER CONSULTATION WITH AN ATTORNEY OF BUYER’S OWN SELECTION, BUYER VOLUNTARILY CONSENTS TO THIS WAIVER.

FURTHERMORE, BUYER WAIVES ANY COMPARABLE PROVISION OF THE LAW OF THE STATE OR OTHER JURISDICTION WHERE ANY PORTION OF THE ASSETS IS LOCATED OR TO WHICH THE ASSETS ARE SUBJECT.

12.3Damages. NOTWITHSTANDING ANYTHING CONTAINED TO THE CONTRARY IN ANY OTHER PROVISION OF THIS AGREEMENT, SELLER AND BUYER AGREE THAT, EXCEPT FOR THE LIQUIDATED DAMAGES SPECIFICALLY PROVIDED FOR IN SECTION 14.2, THE RECOVERY BY EITHER PARTY OF ANY DAMAGES SUFFERED OR INCURRED BY IT AS A RESULT OF ANY BREACH BY THE OTHER PARTY OF ANY OF ITS REPRESENTATIONS, WARRANTIES OR OBLIGATIONS UNDER THIS AGREEMENT SHALL BE LIMITED TO THE ACTUAL DAMAGES SUFFERED OR INCURRED BY THE NON-BREACHING PARTY (AND THE INDEMNIFIED PERSONS TO WHICH SUCH OBLIGATIONS MAY EXTEND UNDER THE TERMS HEREOF) AS A RESULT OF THE BREACH BY THE BREACHING PARTY OF ITS REPRESENTATIONS, WARRANTIES OR OBLIGATIONS HEREUNDER AND IN NO EVENT SHALL THE BREACHING PARTY BE LIABLE TO THE NON-BREACHING PARTY OR ANY INDEMNIFIED PERSON FOR ANY INDIRECT, CONSEQUENTIAL, SPECIAL, EXEMPLARY OR PUNITIVE DAMAGES (INCLUDING, WITHOUT LIMITATION, ANY DAMAGES ON ACCOUNT OF LOST PROFITS OR OPPORTUNITIES, BUSINESS INTERRUPTION OR LOST OR DELAYED PRODUCTION) SUFFERED OR INCURRED BY THE NON-BREACHING PARTY OR ANY INDEMNIFIED PERSON AS A RESULT OF THE BREACH BY THE BREACHING PARTY OF ANY OF ITS REPRESENTATIONS, WARRANTIES OR OBLIGATIONS HEREUNDER. For purposes of the foregoing, actual damages may, however, include indirect, consequential, special, exemplary or punitive damages to the extent (i) the injuries or losses resulting

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in or giving rise to such damages are incurred or suffered by a Person which is not a Seller Indemnified Person, a Buyer Indemnified Person or an Affiliate of any of the foregoing and (ii) such damages are recovered against an Indemnified Person by a Person which is not a Seller Indemnified Person, a Buyer Indemnified Person or an Affiliate of any of the foregoing. This Section 12.3 shall operate only to limit a Party’s liability and shall not operate to increase or expand any contractual obligation of a Party hereunder or cause any contractual obligation of a Party hereunder to survive longer than provided in Section 11.3.

ARTICLE XIII
ASSUMPTION AND INDEMNIFICATION

13.1Assumption and Indemnification By Buyer. From and after the Closing, Buyer shall assume, pay, perform, fulfill and discharge all Assumed Liabilities and shall indemnify and hold harmless Seller, Seller’s Affiliates, each of Seller’s and its Affiliates’ respective past, present and future directors, officers, employees, consultants and agents, and each of the directors, officers, heirs, executors, successors and permitted assigns of any of the foregoing (collectively, the “Seller Indemnified Persons”) from and against any and all (a) Assumed Liabilities incurred by or asserted against any of the Seller Indemnified Persons, INCLUDING, WITHOUT LIMITATION, ANY ASSUMED LIABILITY BASED ON NEGLIGENCE, GROSS NEGLIGENCE OR STRICT LIABILITY OF ANY SELLER INDEMNIFIED PERSON OR ON ANY OTHER THEORY OF LIABILITY, WHETHER IN LAW (WHETHER COMMON OR STATUTORY) OR EQUITY and (b) subject to the limitations of Section 11.3 and Article XII, any Covered Liability resulting from any breach or nonfulfillment of any representation, warranty, covenant or agreement on the part of Buyer which is expressly set forth in this Agreement.

13.2Indemnification By Seller. Subject to the provisions of Sections 11.3 and 13.4 and Article XII, from and after the Closing, Seller shall indemnify and hold harmless Buyer, Buyer’s Affiliates, each of Buyer’s and its Affiliates’ respective present and future directors, officers, employees, consultants and agents, and each of the directors, officers, heirs, executors, successors and permitted assigns of any of the foregoing (collectively, the “Buyer Indemnified Persons”) from and against any and all Covered Liabilities resulting from (a) any breach or nonfulfillment of any representation, warranty, covenant or agreement on the part of Seller which is expressly set forth in this Agreement and (b) resolution of the lawsuit described in Schedule 4.1(e) to the extent such resolution results in the obligation of Seller, any Seller Indemnified Person, predecessors in interest, or Buyer to pay amounts which are attributable to periods prior to the Effective Time, as well as all attorney fees and costs incurred by Seller related to the lawsuit attributable to periods prior to or after the Effective Time.

13.3Indemnification and Defense Procedures. A Person which is entitled to be indemnified under Section 5.1, 13.1 or 13.2 is herein referred to as an “Indemnified Person” and the Party which is obligated to indemnify an Indemnified Person under Section 5.1, 13.1 or 13.2 is herein referred to as the “Indemnifying Party” with respect to the matter for which it is obligated to indemnify such Indemnified Person. All claims for indemnification under Sections5.1, 13.1 and 13.2 shall be asserted and resolved as follows:

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(a)If a third-party claim for which an Indemnified Person is entitled to indemnity under Sections 5.1, 13.1 and/or 13.2 (an “Indemnified Claim”) is made against an Indemnified Person, and if Buyer or Seller intends to seek indemnity with respect thereto by or from an Indemnifying Party pursuant to Sections 5.1, 13.1 and/or 13.2, then the Party electing to seek indemnity on behalf of such Indemnified Person shall promptly transmit to the Indemnifying Party a written notice (“Claim Notice”) (i) notifying such Indemnifying Party of such Indemnified Claim and requesting indemnity on behalf of such Indemnified Person with respect to such Indemnified Claim under Sections 5.1, 13.1 and/or 13.2, as the case may be, (ii) setting forth the full name, address for all notices and the authorized representatives of such Indemnified Person with respect to such Indemnified Claim, and (iii) describing in reasonable detail the nature of the Indemnified Claim, including a copy of all papers served with respect to such Indemnified Claim (if any) and the basis of such request for indemnification under Sections 5.1, 13.1 and/or 13.2, as the case may be. Failure to provide such Claim Notice promptly shall not affect the right of the Indemnified Person to indemnification hereunder except to the extent the Indemnifying Party is prejudiced thereby; provided that, the Indemnifying Party shall not be obligated to defend, indemnify or otherwise hold harmless an Indemnified Person with respect to a third-party claim until a Claim Notice meeting the foregoing requirements is furnished to the Indemnifying Party by the Party seeking indemnity hereunder. Within thirty (30) days after receipt of any Claim Notice (the “Election Period”) from a Party, the Indemnifying Party shall notify the Party who sent the Claim Notice (A) whether the Indemnifying Party disputes its potential liability to indemnify the Indemnified Person under Sections 5.1, 13.1 and/or 13.2, as the case may be, with respect to such third-party claim and (B) whether the Indemnifying Party desires to defend the Indemnified Person against such third-party claim; provided that, if the Indemnifying Party fails to so notify the Party who sent the Claim Notice during the Election Period, the Indemnifying Party shall be deemed to have elected to dispute such liability and not to defend against such third-party claim.

(b)If the Indemnifying Party notifies the Party who sent the Claim Notice within the Election Period that the Indemnifying Party (i) does not dispute its liability to indemnify the Indemnified Person under Sections 5.1, 13.1 and/or 13.2, as the case may be, and (ii) elects to assume the defense of such Indemnified Person with respect to such third-party claim, then the Indemnifying Party shall have the right to defend, at its sole cost and expense, such third-party claim by all appropriate proceedings, which proceedings shall be prosecuted diligently by the Indemnifying Party to a final conclusion or settled at the discretion of the Indemnifying Party in accordance with this Section 13.3(b). The Indemnifying Party shall have full control of such defense and proceedings, including any compromise or settlement thereof; provided that, the Indemnifying Party shall not enter into any settlement agreement (or settle or compromise any such third-party claim in a manner) which provides for or results in any payment by or liability of the Indemnified Person of or for any damages or other amount, any lien, charge or encumbrance on any property of the Indemnified Person, any finding of responsibility or liability on the part of the Indemnified Person or any sanction or restriction upon the conduct of any business by the Indemnified Person without the Indemnified Person’s express written consent, which consent shall not be unreasonably withheld. The Indemnified Person is hereby authorized, at the sole cost and expense of the Indemnifying Party (but only if the Indemnified Person is actually entitled to indemnification hereunder), to file, during the Election Period, any motion, answer or other pleadings which the Indemnified Person shall deem necessary or appropriate to protect its interests or those of the

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Indemnifying Party and not reasonably expected to be prejudicial to the Indemnifying Party. If requested by the Indemnifying Party, the Indemnified Person agrees, at the sole cost and expense of the Indemnifying Party, to cooperate with the Indemnifying Party and its counsel in contesting any such third-party claim which the Indemnifying Party elects to contest, including the making of any related counterclaim or cross-complaint against any Person (other than a Buyer Indemnified Person, if the Indemnified Person is a Buyer Indemnified Person, or a Seller Indemnified Person, if the Indemnified Person is a Seller Indemnified Person). The Indemnified Person may participate in, but not control, any defense or settlement of any third-party claim controlled by the Indemnifying Party pursuant to this Section 13.3(b), and the Indemnified Person shall bear its own costs and expenses with respect to such participation. The prosecution of the defense of a third-party claim with reasonable diligence shall include the taking of such action (including the posting of a bond, deposit or other security) as may be necessary to prevent any action to foreclose a lien against or attachment of the property of the Indemnified Person for payment of such third-party claim.

(c)If the Indemnifying Party (i) fails to notify the Party who sent the Claim Notice within the Election Period that the Indemnifying Party elects to defend the Indemnified Person pursuant to Section 13.3(b) or (ii) elects to defend the Indemnified Person pursuant to Section 13.3(b) but fails to prosecute the defense of (or to settle) the third-party claim with reasonable diligence, then the Indemnified Person shall have the right to defend, at the sole cost and expense of the Indemnifying Party (but only if the Indemnified Person is actually entitled to indemnification hereunder), the third-party claim by all appropriate proceedings, which proceedings shall be promptly and vigorously prosecuted by the Indemnified Person to a final conclusion or settled. The Indemnified Person shall have full control of such defense and proceedings; provided, however, that the Indemnified Person may not enter into any compromise or settlement of such third-party claim, without the Indemnifying Party’s express written consent, which shall not be unreasonably withheld or delayed. The Indemnifying Party may participate in, but not control, any defense or settlement controlled by the Indemnified Person pursuant to this Section 13.3(c), and the Indemnifying Party shall bear its own costs and expenses with respect to such participation.

(d)If an Indemnified Person is entitled to indemnity under Sections 5.1, 13.1 and/or 13.2 for a claim or other matter which does not involve a third-party claim, and if Buyer or Seller intends to seek indemnity for itself or on behalf of an Indemnified Person with respect thereto by or from an Indemnifying Party pursuant to Sections 5.1, 13.1 and/or 13.2, then the Party electing to seek indemnity on behalf of itself or an Indemnified Person shall promptly transmit to the Indemnifying Party a written notice describing in reasonable detail the nature of such claim or other matter, the Indemnified Person’s reasonable estimate of the amount of damages attributable to such claim or other matter and the basis for the Indemnified Person’s entitlement to indemnification under Sections 5.1, 13.1 and/or 13.2, as the case may be. If the Indemnifying Party does not notify the Party who sent such notice within thirty (30) days from its receipt of such notice that the Indemnifying Party does not dispute such claim for indemnity, the Indemnifying Party shall be deemed to have disputed such claim.

13.4Seller’s General Liability Limitation.

(a)Notwithstanding anything contained to the contrary in this Agreement:

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(i)In no event shall Seller’s aggregate liability arising out of or relating to Section 13.2 with respect to a breach by Seller of any representation or warranty made by Seller in this Agreement exceed an amount equal to twentypercent (20%) of the Purchase Price;

(ii)Seller shall not be required to indemnify any Person under Section 13.2 with respect to a breach of any representation or warranty made by Seller in this Agreement unless the aggregate amount which would otherwise be payable by Seller thereunder with respect to all breaches of any such representations and warranties exceeds an amount equal to two and one-half percent (2.5%) of the Purchase Price (the “Deductible Amount”), and in such event, Seller shall be responsible for only the amount in excess of the Deductible Amount; and

(iii)After the Closing, for purposes of the indemnification obligation set forth in Section13.2, the knowledge qualification set forth in Section 4.1(k)(i) shall be disregarded.

(b)Notwithstanding anything herein provided to the contrary but without in any way affecting the obligations of a Buyer Indemnified Person to notify Seller of a third-party claim pursuant to Section 13.3, Seller shall not have any liability to any Person with respect to any Covered Liability pursuant to Section 13.2 unless and until Buyer enforces any and all of the rights and remedies that Buyer may have with respect to such Covered Liability against any other Person pursuant to (i) any insurance maintained for the joint account under any operating agreement with respect to the Assets and (ii) any other agreements for insurance, indemnification, guarantee or similar assurances which may be included in the Assets.

13.5Exclusive Remedy. Except as provided in Section 8.6, Seller and Buyer acknowledge and agree that from and after the Closing Date, the indemnification provisions of this Article XIII are the sole and exclusive remedy of Seller and Buyer for the breach of any representation or warranty or nonfulfillment of any covenant or agreement on the part of Seller or Buyer under this Agreement or confirmed in any certificate delivered pursuant hereto, and Seller does hereby release, acquit and forever discharge all Buyer Indemnified Persons and Buyer does hereby release, acquit, and forever discharge all Seller Indemnified Persons from any such other remedies.

ARTICLE XIV
TERMINATION; REMEDIES

14.1Termination.

(a)Termination of Agreement. This Agreement and the transactions contemplated hereby may be terminated at any time prior to the Closing:

(i)By the mutual written consent of Seller and Buyer; or

(ii)If the Closing has not occurred by 5:00 p.m., Central Time, on the Closing Date (the “Termination Effective Time”), then (A) by Seller if any condition specified in

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Section 9.1 has not been satisfied on or before the Termination Effective Time, and shall not theretofore have been waived by Seller, or (B) by Buyer if any condition specified in Section 9.2 has not been satisfied on or before the Termination Effective Time, and shall not theretofore have been waived by Buyer; provided, in each case, that the failure to consummate the transactions contemplated hereby on or before such time did not result from the failure by the Party seeking termination of this Agreement to fulfill any undertaking or commitment provided for herein on the part of such Party that is required to be fulfilled on or prior to Closing.

(b)Effect of Termination. Without limiting Seller’s or Buyer’s respective remedies and rights in regard to the Deposit under Section 14.2, in the event of termination of this Agreement by Seller, on the one hand, or Buyer, on the other hand, pursuant to Section 14.1(a), written notice thereof shall forthwith be given by the terminating Party to the other Party, and this Agreement shall thereupon terminate; provided, however, that the last sentence of Section 8.2 shall survive such termination and Buyer will continue to be bound by its obligations set forth in Article V following such termination. If this Agreement is terminated as provided herein, all filings, applications and other submissions made to any Governmental Authority shall, to the extent practicable, be withdrawn from the Governmental Authority to which they were made.

14.2Remedies.

(e)Seller’s Remedies. Notwithstanding anything herein provided to the contrary, if this Agreement is not terminated by Buyer pursuant to Section 14.1(a)(ii)(B) and the conditions to Closing set forth in Sections 9.1(a), 9.1(b) or 9.1(c) are not satisfied, Seller may, at its sole option, either (i) enforce specific performance of this Agreement or (ii) terminate this Agreement and, without waiving or releasing Buyer’s obligations under Sections 5.1 and 5.2, retain the Deposit, including any interest and other amounts earned thereon, as liquidated damages. Such remedies shall be Seller’s sole and exclusive remedies for such failure, all other remedies being expressly waived by Seller. Seller and Buyer agree upon the Deposit as liquidated damages due to the difficulty and inconvenience of measuring actual damages and the uncertainty thereof, and Seller and Buyer agree that such amount is a reasonable estimate of Seller’s loss in the event of any such failure by Buyer. Without waiving or releasing Buyer from any of its other representations, warranties, covenants and agreements contained herein, specific performance with respect to clause (ii)(b) of Section 10.3 shall not require Buyer to make a false statement in the officer’s certificate of Buyer. If this Agreement is terminated by Seller pursuant to Section 14.1(a)(ii)(A) and the conditions set forth in Sections 9.1(a), 9.1(b) and 9.1(c) have been satisfied, Seller’s sole remedy shall be to terminate this Agreement, in which case Buyer shall receive back the Deposit.

(f)Buyer’s Remedies. Notwithstanding anything herein provided to the contrary, if this Agreement is not terminated by Seller pursuant to Section 14.1(a)(ii)(A) and the conditions to Closing set forth in Sections 9.2(a), 9.2(b) or 9.2(c) are not satisfied, Buyer may, at its sole option, either (i) enforce specific performance of this Agreement or (ii) terminate this Agreement and receive back the Deposit, together with interest thereon from the date of this Agreement to the date repayment is made by Seller to Buyer at the Agreed Rate. Such remedies shall be Buyer’s sole and exclusive remedies for such failure, all other remedies being expressly waived by Buyer. Without waiving

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or releasing Seller from any of its other representations, warranties, covenants and agreements contained herein, specific performance with respect to Section 10.2(b) shall not require Seller to make a false statement in the officer’s certificate of Seller. If this Agreement is terminated by Buyer pursuant to Section 14.1(a)(ii)(B) and the conditions set forth in Sections 9.2(a), 9.2(b) and 9.2(c) have been satisfied, Buyer’s sole remedy shall be to terminate this Agreement, in which case Buyer shall receive back the Deposit. In the event this Agreement is terminated by mutual written consent of Seller and Buyer pursuant to Section 14.1(a)(i), then Buyer shall be entitled to receive back the Deposit.

(c)    Dispute Resolution. In the event of a dispute between Seller and Buyer with respect to entitlement to the Deposit, then either Party may by written notice to the other refer such dispute for resolution by binding arbitration pursuant to and in accordance with the Arbitration Procedures, reasonably modified by agreement of the Parties acting in good faith to define the “Disputed Issues” as entitlement to the Deposit and eliminating all references to Deferred Adjustment Claims.

ARTICLE XV
MISCELLANEOUS

15.1Counterparts. This Agreement may be executed in one or more counterparts, all of which shall be considered one and the same agreement, and shall become effective when one or more counterparts have been signed by each of the Parties and delivered to the other Party.

15.2Governing Law; Jurisdiction.

(c)THIS AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS WITHOUT REFERENCE TO THE CONFLICT OF LAW PRINCIPLES THEREOF.

(d)The Parties agree that the appropriate, exclusive and convenient forum for any disputes between the Parties arising out of this Agreement or the transactions contemplated hereby shall be in any state or federal court in Houston, Texas, and each of the Parties irrevocably submits to the jurisdiction of such courts solely in respect of any legal proceeding arising out of or related to this Agreement. The Parties further agree that the Parties shall not bring suit with respect to any disputes arising out of this Agreement or the transactions contemplated hereby in any court or jurisdiction other than the above specified courts; provided, however, that the foregoing shall not limit the rights of the Parties to obtain execution of judgment in any other jurisdiction. The Parties further agree, to the extent permitted by Law, that a final and unappealable judgment against a Party in any action or proceeding contemplated above shall be conclusive and may be enforced in any other jurisdiction within or outside the United States by suit on the judgment, a certified copy of which shall be conclusive evidence of the fact and amount of such judgment. Except to the extent that a different determination or finding is mandated due to the applicable law being that of a different jurisdiction, the Parties agree that all judicial determinations or findings by a state or federal court in Houston, Texas with respect to any matter under this Agreement shall be binding.

(e)To the extent that either Party has or hereafter may acquire any immunity from jurisdiction of any court or from any legal process (whether through service or notice, attachment

    - 35 -

prior to judgment, attachment in aid of execution, execution or otherwise) with respect to itself or its property, each Party hereby irrevocably (i) waives such immunity in respect of its obligations with respect to this Agreement and (ii) submits to the personal jurisdiction of any court described in Section 15.2(b).

(f)EACH PARTY AGREES THAT IT HEREBY IRREVOCABLY WAIVES THE RIGHT TO TRIAL BY JURY IN ANY ACTION TO ENFORCE OR INTERPRET THE PROVISIONS OF THIS AGREEMENT.

15.3Entire Agreement. This Agreement (including the Confidentiality Agreement) and the appendix, schedules and exhibits hereto contain the entire agreement between the Parties with respect to the subject matter hereof and there are no agreements, understandings, representations or warranties between the Parties other than those set forth or referred to herein.

15.4Expenses. Buyer shall be responsible for (a) any sales Taxes which may become due and owing by reason of the sale of the Assets hereunder, (b) all transfer, stamp, documentary and similar Taxes imposed on the Parties with respect to all transfers of property contemplated pursuant to this Agreement and (c) all recording, filing or registration fees relating to the filing, recording or registration of the Conveyance, the special governmental assignment forms contemplated by Section 8.3 and any other instruments or documents transferring title in or to the Assets or any part thereof from Seller to Buyer pursuant to this Agreement. All other costs and expenses incurred by each Party in connection with all things required to be done by it hereunder, including attorney’s fees, accountant fees and the expense of title examination, shall be borne by the Party incurring same.

15.5Notices. Unless otherwise expressly provided in this Agreement, all notices required or permitted hereunder shall be in writing and deemed sufficiently given for all purposes hereof if (a) delivered in person, by courier or by registered or certified United States Mail to the Person to be notified, with receipt obtained, or (b) sent by facsimile, with “answer back” or other “advice of receipt” obtained, in each case to the appropriate address or number as set forth below. Each notice shall be deemed effective on receipt by the addressee as aforesaid; provided that, notice received by facsimile after 5:00 p.m. at the location of the addressee of such notice shall be deemed received on the first Business Day following the date of such electronic receipt. Notices to Seller shall be addressed as follows:

Cabot Oil & Gas Corporation
840 Gessner Road, Suite 1400
Houston, Texas 77024
Attention: Vice President, Land and Business Development
Facsimile: (281) 589-4653

with a copy (which shall not constitute notice) to:
Cabot Oil & Gas Corporation
840 Gessner Road, Suite 1400
Houston, Texas 77024

    - 36 -

Attention: General Counsel
Facsimile: (281) 589-4888

with a copy (which shall not constitute notice) to:
Fulbright & Jaworski LLP
1301 McKinney, Suite 5100
Houston, Texas 77010
Attention: Ms. Deborah A. Gitomer
Facsimile: (713) 651-5246

or at such other address or to such other facsimile number and to the attention of such other Person as Seller may designate by written notice to Buyer. Notices to Buyer shall be addressed to:

Chaparral Energy, L.L.C.
701 Cedar Lake Blvd.
Oklahoma City, Oklahoma 73114
Attention: David J. Ketelsleger
Facsimile: (405) 425-8872

with a copy (which shall not constitute notice) to:
McAfee & Taft A Professional Corporation

Two Leadership Square, Tenth Floor

211 N. Robinson

Oklahoma City, Oklahoma 73102
Attention: Justin L. Jackson
Facsimile: (405) 228-7440

or at such other address or to such other facsimile number and to the attention of such other Person as Buyer may designate by written notice to Seller.

15.6Successors and Assigns. This Agreement shall be binding upon and inure to the benefit of the Parties and their respective successors and assigns; provided, however, that the respective rights and obligations of the Parties shall not be assignable or delegable by either Party without the express written consent of the non-assigning or non-delegating Party.

15.7Amendments and Waivers. Except as contemplated by Section 8.8, this Agreement may not be modified or amended except by an instrument or instruments in writing signed by the Party against whom enforcement of any such modification or amendment is sought. Either Party may, only by an instrument in writing, waive compliance by the other Party with any term or provision of this Agreement on the part of such other Party to be performed or complied with. The waiver by either Party of a breach of any term or provision of this Agreement shall not be construed as a waiver of any subsequent breach.

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15.8Appendix, Schedules and Exhibits. The appendix and all schedules and exhibits hereto which are referred to herein are hereby made a part hereof and incorporated herein by such reference.

15.9Purchase Price Allocation for Tax Purposes. Seller and Buyer agree that the Purchase Price shall be allocated to the various Assets for federal and state income tax purposes only in the manner set forth on Schedule 15.9. The allocation of the Purchase Price shall be reflected on the completed Form 8594 (Asset Acquisition Statement Under Section 1060), which Form Seller and Buyer will each file separately with the Internal Revenue Service pursuant to the requirements of section 1060(b) of the Code. The Parties agree not to take a federal or state income tax reporting position inconsistent with the allocations set forth on Schedule 15.9. The Parties further agree that the allocations set forth on Schedule 15.9 represent reasonable estimates of the fair market values of the Assets described therein.

15.10Ad Valorem Tax Proration. Ad valorem Taxes related to the Assets will be prorated as of the Effective Time. For ad valorem Taxes for a period which the Effective Time splits which have been paid by Seller, Buyer shall reimburse Seller for the portion thereof equal to the percentage of such period represented by the portion of such period beginning at the Effective Time. For ad valorem Taxes for a period which the Effective Time splits which have not been paid to Seller, Buyer shall pay such Taxes and Seller shall reimburse Buyer for a percentage of such Taxes equal to the portion of such period which ends on the day immediately preceding the Effective Time.

15.11Agreement for the Parties’ Benefit Only. This Agreement is for the sole benefit of Buyer, Seller and their respective successors and assigns as permitted herein and no other Person shall be entitled to enforce this Agreement, rely on any representation, warranty, covenant or agreement contained herein, receive any rights hereunder or be a third-party beneficiary of this Agreement. Any Indemnified Person which is a third Person shall be indemnified and held harmless under the terms of this Agreement only to the extent that a Party expressly elects to exercise such right of indemnity and hold harmless on behalf of such third Person Indemnified Person pursuant to Section 13.3; and no Party shall have any direct liability or obligation to any third Person or be liable to any third Person for any election or non-election or any act or failure to act under or in regard to any term of this Agreement. Any claim for indemnity or hold harmless hereunder on behalf of an Indemnified Person must be made and administered by a Party to this Agreement.

15.12Attorneys’ Fees. The prevailing Party in any legal proceeding brought under or to enforce this Agreement shall be additionally entitled to recover court costs and reasonable attorneys’ fees from the nonprevailing Party.

15.13Severability. If any term, provision or condition of this Agreement, or any application thereof, is held invalid, illegal or unenforceable in any respect under any Law, this Agreement shall be reformed to the extent necessary to conform, in each case consistent with the intention of the Parties, to such Law, and to the extent such term, provision or condition cannot be so reformed, then such term, provision or condition (or such invalid, illegal or unenforceable application thereof) shall be deemed deleted from (or prohibited under) this Agreement, as the case may be, and the validity, legality and enforceability of the remaining terms, provisions and conditions contained herein (and any other application such term, provision or condition) shall not in any way be affected

    - 38 -

or impaired thereby. Upon such determination that any term or other provision is invalid, illegal or incapable of being enforced, the Parties shall negotiate in good faith to modify this Agreement so as to effect the original intent of the Parties as closely as possible in an acceptable manner to the end that the transactions contemplated hereby are fulfilled to the extent possible.

15.14Time of Essence. Time is of the essence in this Agreement.

15.15Like-Kind Exchange. Buyer and Seller consent to any assignment by the other Party of certain of its rights and obligations under this Agreement (a “1031 Assignment”) to a Qualified Intermediary (as that term is defined in Section 1.1031(k)‑1(g)(4)(v) of the Treasury Regulations), or to a Qualified Exchange Accommodation Titleholder (as that term is defined in Rev. Proc. 2000‑37), in connection with effectuation of a like-kind exchange (an “Exchange”). For the purposes of this Section 15.15, the Party executing an Exchange shall be referred to as the “Exchangor” and the other Party shall be referred to as the “Consenting Party”. In the event the Exchangor makes a 1031 Assignment to a Qualified Intermediary or a Qualified Exchange Accommodation Titleholder pursuant to this Section 15.15, the Exchangor agrees to notify the Consenting Party in writing of such assignment at least one (1) Business Day before the Closing Date. Notwithstanding the occurrence of a 1031 Assignment, the Parties acknowledge and agree that any such assignment of any portion of the Exchangor’s rights and obligations under this Agreement to a Qualified Intermediary or to a Qualified Exchange Accommodation Titleholder, does not release either Party from any of their respective liabilities and obligations to each other (including, without limitation, indemnification obligations) under this Agreement. The Consenting Party agrees to cooperate with the Exchangor to attempt to structure the transactions contemplated hereby as a like-kind exchange; provided (i) the Closing shall not be delayed or affected by reason of the Exchange, and (ii) the Exchangor shall indemnify the Consenting Party against any additional costs or liabilities directly incurred by the Consenting Party on account of the Exchangor’s consummation of the transaction contemplated hereby through an Exchange.

[Signature Page Follows]

    - 39 -

IN WITNESS WHEREOF, this Agreement has been signed by or on behalf of each of the Parties as of the day first above written.

1.	SELLER: CABOT OIL & GAS CORPORATION By: /s/ Todd Liebl Todd Liebl Vice President, Land and Business Development
	BUYER: CHAPARRAL ENERGY, L.L.C. By: /s/ Mark A. Fischer Mark A. Fischer Manager

Signature Page to Asset Purchase Agreement

APPENDIX A

Attached to and made part of that certain

Asset Purchase Agreement dated as of October 11, 2013,

by and between Cabot Oil & Gas Corporation, as “Seller”, and

Chaparral Energy, L.L.C., as “Buyer”

DEFINITIONS

“1031 Assignment” shall be as defined in Section 15.15.

“Action” shall mean any action, suit or other proceeding by or before any court or other Governmental Authority or any arbitration proceeding before any arbitral tribunal.

“Adjusted Purchase Price” shall be as defined in Section 3.1.

“Adjustment Period” shall be as defined in Section 3.3(a).

“Affiliate” shall mean, with respect to any Person, any other Person that directly or indirectly (through one or more intermediaries or otherwise) Controls, is Controlled by or is under common Control with the first Person. No Person shall be deemed an Affiliate of any Person by reason of the exercise or existence of rights, interests or remedies under this Agreement.

“Adjustment Statement” shall be as defined in Section 3.3(a).

“Agreed Rate” shall mean an annual rate of interest equal to the lesser of (a) five percent (5%) and (b) the maximum rate of interest allowed by Law.

“Agreement” shall be as defined in the preamble hereof.

“Arbitration Procedures” shall mean the arbitration procedures set forth on Exhibit A‑1.

“Assets” shall be as defined in Section 2.1.

“Assumed Liabilities” shall mean all Covered Liabilities arising out of or attributable to the ownership, use, construction, maintenance or operation of the Assets before, on or after the Effective Time; provided, however, that the Assumed Liabilities shall not include any Covered Liability for which Seller is obligated to indemnify Buyer pursuant to Section 13.2.

“Business Day” shall mean any day that is not a Saturday, Sunday or legal holiday in the State of Texas or a federal holiday in the United States of America.

“Buyer” shall be as defined in the preamble hereof.

“Buyer Indemnified Persons” shall be as defined in Section 13.2.

    Appendix A, Page 1

“Claim Notice” shall be as defined in Section 13.3(a).

“Closing” shall be the consummation of the transactions contemplated by Article X.

“Closing Date” shall mean (a) December 18, 2013, or (b) such other date as may be mutually agreed to in writing by Seller and Buyer.

“Code” shall mean the Internal Revenue Code of 1986, as amended.

“Confidentiality Agreement” shall be as defined in Section 5.2.

“Consenting Party” shall be as defined in Section 15.15.

“Control” shall mean the power to direct or cause the direction of the management and policies of a Person, whether through the ability to exercise voting power, by contract or otherwise; and “Controlled by” and “Controlling” have the meaning correlative thereto.

“Conveyance” shall be as defined in Section 8.3.

“Covered Liabilities” shall mean any and all debts, losses, liabilities, duties, fines, damages, claims, Taxes, costs and expenses (including those arising out of any demand, assessment, settlement, judgment or compromise relating to any actual or threatened Action and any court costs, reasonable fees and expenses of expert witnesses, reasonable investigative expenses, reasonable fees and disbursements of legal counsel and other reasonable legal and investigative fees and expenses incurred in investigating, preparing or defending any Action), matured or unmatured, absolute or contingent, accrued or unaccrued, liquidated or unliquidated, known or unknown, including, without limitation, any of the foregoing arising under, out of or in connection with any Action, any order or consent decree of any Governmental Authority, any award of any arbitrator, or any Law, contract, commitment or undertaking.

“Deductible Amount” shall be as defined in Section 13.4(a)(ii).

“Defensible Title” shall mean, respectively as to the Subject Interest or Subject Interests related to a particular Property Subdivision, title to such Property Subdivision and the Subject Interest or Subject Interests related to such Property Subdivision that: (i) with respect to each Property Subdivision described on Part II(A) of the Property Schedule, entitles Seller to receive not less than the applicable Net Revenue Interest or Net Revenue Interests specified for such Property Subdivision in Part II(A) of the Property Schedule; (ii) with respect to each Property Subdivision described on Part II(A) of the Property Schedule, obligates Seller to bear the costs and expenses attributable to the maintenance, development, and operation of such Property Subdivision in an amount not greater than the applicable Working Interest or Working Interests specified for such Property Subdivision in Part II(A) of the Property Schedule; (iii) with respect to each Property Subdivision described in Part II(B) of the Property Schedule, entitles Seller to not less than the number of Net Acres listed for such Property Subdivision in Part II(B) of the Property Schedule; and (iv) except for Permitted Encumbrances, is free and clear of all liens and encumbrances.

“Deferred Adjustment Claim” shall be as defined in Section 6.6.

    Appendix A, Page 2

“Deferred Matters Date” shall be as defined in Section 6.6.

“Deposit” shall be as defined in Section 3.2.

“Disputed Issues” shall be as defined in the Arbitration Procedures.

“Effective Time” shall be as defined in Section 2.1.

“Election Period” shall be as defined in Section 13.3(a).

“Environmental Laws” shall mean all Laws relating to (a) the control of any potential pollutant, or protection of the air, water or land, (b) solid, gaseous or liquid waste generation, handling, treatment, storage, disposal or transportation, and (c) exposure to hazardous, toxic or other substances alleged to be harmful. “Environmental Laws” shall include, but are not limited to, the Clean Air Act, 42 U.S.C. § 7401 etseq., the Clean Water Act, 33 U.S.C. § 1251 etseq., the Resource Conservation and Recovery Act, 42 U.S.C. § 6901 etseq., the Emergency Planning and Community Right-to-Know Act, 42 U.S.C. § 11001 etseq., the Toxic Substances Control Act, 33 U.S.C. § 1251 etseq., the Safe Drinking Water Act, 42 U.S.C. § 300f etseq. and the Comprehensive Environmental Response, Compensation, and Liability Act, 42 U.S.C. § 9601 etseq.

“Environmental Permits” shall be as defined in Section 4.1(k).

“Exchange” shall be as defined in Section 15.15.

“Exchangor” shall be as defined in Section 15.15.

“Excluded Assets” shall be as defined in Section 2.2.

“Final Adjustment Statement” shall be as defined in Section 3.4.

“Fundamental Representations” shall mean Sections 4.1(a), 4.1(b), 4.1(c), and 4.1(l).

“Governmental Authority” shall mean (a) the United States of America, (b) any state, county, municipality or other governmental subdivision within the United States of America, and (c) any court or any governmental department, commission, board, bureau, agency or other instrumentality of the United States of America or of any state, county, municipality or other governmental subdivision within the United States of America.

“Hazardous Materials” means any (i) toxic or hazardous materials or substances; (ii) solid wastes, including asbestos, polychlorinated biphenyls, mercury, flammable or explosive materials; (iii) radioactive materials; (iv) petroleum or petroleum products (including crude oil); and (v) any other chemical, pollutant, contaminant, substance or waste that is regulated under any Environmental Law.

“Hydrocarbon Interests” shall mean (a) leases affecting, relating to or covering any oil, gas and other hydrocarbons in place and the leasehold interests and estates in the nature of working or operating interests under such leases, as well as overriding royalties, net profits interests, production

    Appendix A, Page 3

payments, carried interests, rights of recoupment and other interests in, under or relating to such leases, (b) fee interests in oil, gas or other hydrocarbons in place, (c) royalty interests in oil, gas or other hydrocarbons in place, (d) any other interest in oil, gas or other hydrocarbons in place, (e) any economic or contractual rights, options or interests in and to any of the foregoing, including, without limitation, any farmout or farmin agreement or production payment affecting any interest or estate in oil, gas or other hydrocarbons in place, and (f) any and all rights and interests attributable or allocable thereto by virtue of any pooling, unitization, communitization, production sharing or similar agreement, order or declaration.

“Indemnified Claim” shall be as defined in Section 13.3(a).

“Indemnified Person” shall be as defined in Section 13.3.

“Indemnifying Party” shall be as defined in Section 13.3.

“Initial Adjustment Amount” shall be as defined in Section 3.3(a).

“knowledge” shall mean the actual knowledge (excluding any imputed or implied knowledge) of any fact, circumstance or condition by a current officer of the Party involved.

“Lands” shall be as defined in Section 2.1(b).

“Law” shall mean any applicable statute, law, ordinance, regulation, rule, ruling, order, writ, injunction, decree or other official act of or by any Governmental Authority.

“Lease Net Acres” shall mean, as calculated separately with respect to each oil and gas lease covering land within a Property Subdivision described in Part II(B) of the Property Schedule, (a) the number of gross acres in the lands covered by such oil and gas lease, multiplied by (b) the lessor’s undivided percentage interest in oil, gas or other minerals covered by such oil and gas lease, multiplied by (c) Seller’s Working Interest in such oil and gas lease; provided, that if items (b) and/or (c) vary as to different areas of such lands covered by such oil and gas lease, a separate calculation in accordance herewith shall be performed for each such area as if it were a separate oil and gas lease.

“Marmaton Formation” shall mean the interval extending between the top of the Marmaton formation and the base of the Marmaton formation, being defined and identified for purposes hereof as the correlative stratigraphic equivalent to that certain interval occurring between the measured depth of 6,396 feet and the measured depth of 6,800 feet as identified on the Dual Induction – SFL log of Natural Gas Anadarko, Inc. Beckwith #1-26 Well (API No. 35-007-21960) located in Section 26, Township 2 North, Range 22 East C.M., Beaver County, Oklahoma.

“Material Adverse Effect” shall mean a material adverse effect on the value of the Assets taken as a whole (after taking into account any insurance, indemnity and other recoveries payable in respect thereof), excluding any effect resulting from (a) any change in economic, industry, financial, market or political conditions (whether general or regional in nature or limited to any area where any Assets are located), (b) any change in Law, regulatory policy or accounting rules, (c)

    Appendix A, Page 4

entering into this Agreement or the announcement of the transactions contemplated by this Agreement, (d) any matter, contract or agreement set forth on an exhibit or schedule hereto, or (e) any change arising in connection with any natural disasters, hostilities, acts of war, sabotage or terrorism.

“Material Contract” shall mean, to the extent binding upon the Assets and Buyer’s ownership thereof or operations with respect thereto from and after Closing, any contract or agreement which is one or more of the following types:

(a)Any contract or agreement with any Affiliate of Seller;

(b)Any contract or agreement for the sale, purchase, exchange, gathering, transportation, treating, compressing, processing, or other disposition, handling or marketing of oil, gas or other hydrocarbons which is not cancelable without penalty on sixty (60) days or less prior written notice;

(c)Any area of mutual interest agreement;

(d)Any farmout agreement, exploration agreement, development agreement, proprietary seismic agreement, joint venture agreement or other similar agreement relating to the joint or cooperative exploration or development of the Assets, other than routine joint operating agreements; or

(e)Except for (i) the Subject Interests, (ii) operating, unitization, pooling and communitization agreements, (iii) contracts and agreements for the sale, purchase, exchange, gathering, transportation, treating, compressing, processing, or other disposition, handling or marketing of oil, gas or other hydrocarbons, and (iv) contracts and agreements of the nature described in clauses (a), (c) and (d) above, any contract or agreement that could reasonably be expected to result in aggregate payments by Seller of more than $350,000.00 during the current or any subsequent calendar year.

“Net Acres” shall mean, as calculated separately with respect to each Property Subdivision described in Part II(B) of the Property Schedule, the sum of all Lease Net Acres contained in such Property Subdivision.

“Net Cash Flow” shall be as defined in Section 3.3(c).

“Net Revenue Interest” shall mean an interest (expressed as a percentage or decimal fraction) in and to all oil and gas produced and saved from or attributable to a Property Subdivision.

“Parties” shall mean Seller and Buyer and “Party” shall mean either Seller or Buyer.

“Permitted Encumbrances” shall mean any of the following matters:

(a)    all agreements, instruments, documents, liens, encumbrances, and other matters which are described on Schedule A-1;

    Appendix A, Page 5

(b)    (i) undetermined or inchoate liens or charges constituting or securing the payment of expenses which were incurred incidental to maintenance, development, production or operation of the Assets or for the purpose of developing, producing or processing oil, gas or other hydrocarbons therefrom or therein and (ii) any materialman’s, mechanics’, repairman’s, employees’, contractors’, operators’ or other similar liens, security interests or charges for liquidated amounts arising in the ordinary course of business incidental to construction, maintenance, development, production or operation of the Assets or the production or processing of oil, gas or other hydrocarbons therefrom, that are not delinquent and that will be paid in the ordinary course of business or, if delinquent, that are being contested in good faith;

(c)    any liens for Taxes not yet delinquent or, if delinquent, that are being contested in good faith in the ordinary course of business;

(d)    any liens or security interests created by Law or reserved in oil, gas and/or mineral leases for royalty, bonus or rental or for compliance with the terms of the Subject Interests;

(e)    all Preference Rights and Transfer Requirements;

(f)    consents to assignment from the United States Department of Interior and the applicable state or Indian agencies or authorities that may be required under the terms of (or regulations specifically applicable to) any federal, state or Indian leases in connection with the assignment thereof or any interest therein;

(g)    any easements, rights-of-way, servitudes, permits, licenses, surface leases and other rights with respect to operations to the extent such matters do not interfere in any material respect with Seller’s operation of the portion of the Assets burdened thereby;

(h)    any obligations, prohibitions, restrictions, terms or provisions similar to those contained in or under any A.A.P.L. Model Form Operating Agreement;

(i)    all agreements and obligations relating to imbalances with respect to the production, transportation or processing of gas or calls or purchase options on oil or gas production;

(j)    all royalties, overriding royalties, net profits interests, carried interests, reversionary interests and other burdens to the extent that the net cumulative effect of such burdens, as to a particular Property Subdivision, does not operate to reduce the Net Revenue Interest of Seller in such Property Subdivision below the Net Revenue Interest shown therefor in Part II(A) of the Property Schedule or increase the Working Interest of Seller in such Property Subdivision above the Working Interest shown therefor in Part II(A) of the Property Schedule without a proportionate increase in the Net Revenue Interest of Seller;

    Appendix A, Page 6

(k)    all liens, charges, encumbrances, contracts, agreements, instruments, obligations, defects, irregularities and other matters affecting any Asset which individually or in the aggregate are not such as to interfere materially with the operation, value or use of such Asset;

(l)    any encumbrance, title defect or other matter (whether or not constituting a Title Defect) waived or deemed waived by Buyer pursuant to Article VI;

(m)    rights reserved to or vested in any Governmental Authority to control or regulate any of the wells or units or other properties included in the Assets and all applicable laws, rules, regulations and orders of such authorities so long as the same do not, as to a particular Property Subdivision, decrease Seller’s Net Revenue Interest in such Property Subdivision below the Net Revenue Interest shown therefor in Part II(A) of the Property Schedule;

(n)    the terms and conditions of all the Subject Interests and contracts and agreements relating to the Subject Interests, including, without limitation, exploration agreements, gas sales contracts, gas balancing agreements, processing agreements, farmins, farmouts, operating agreements, and area of mutual interest agreements, to the extent such terms and conditions do not, as to a particular Property Subdivision, decrease Seller’s Net Revenue Interest in such Property Subdivision below the Net Revenue Interest shown therefor in Part II(A) of the Property Schedule; and

(o)    rights of reassignment requiring notice and/or the reassignment (or granting an opportunity to receive an assignment) of a leasehold interest to the holders of such reassignment rights prior to surrendering or releasing such leasehold interest.

“Person” shall mean any Governmental Authority or any individual, firm, partnership, corporation, joint venture, trust, unincorporated organization or other entity or organization.

“Preference Property” shall be as defined in Section 7.2.

“Preference Right” shall mean any right or agreement that enables or may enable any Person to purchase or acquire any Asset or any interest therein or portion thereof as a result of or in connection with (a) the sale, assignment, encumbrance or other transfer of any Asset or any interest therein or portion thereof or (b) the execution or delivery of this Agreement or the consummation or performance of the terms and conditions contemplated by this Agreement.

“Property Schedule” shall mean Exhibit A‑2 attached to and made a part of this Agreement.

“Property Subdivision” shall mean each well or other property subdivision described or referenced in Part II of the Property Schedule, provided, however, that with respect to each Property Subdivision described or referenced in Part II(B) of the Property Schedule, such Property Subdivision shall be limited to the Marmaton Formation.

    Appendix A, Page 7

“Purchase Price” shall be as defined in Section 3.1.

“Records” shall be as defined in Section 2.1(d).

“Reserve Report” shall mean that certain reserve report dated August 13, 2013, prepared by Seller with respect to the Subject Interests as of October 1, 2013.

“Retained Asset” shall be as defined in Section 7.3.

“Seller” shall be as defined in the preamble hereof.

“Seller Indemnified Persons” shall be as defined in Section 13.1.

“Seller Title Credit” shall be as defined in Section 6.4.

“Subject Interests” shall be as defined in Section 2.1(a).

“Tax Return” shall mean any return, report, election, declaration, statement, information return, schedule, or other document (including any related or supporting information) filed or required to be filed with any Governmental Authority in connection with the determination, assessment, collection or administration of any Taxes or the administration of any laws, regulations or administrative requirements relating to any Taxes or any amendment thereof.

“Taxes” shall mean all federal, state and local taxes or similar assessments or fees, together with all interest, fines, penalties and additions thereto.

“Termination Effective Time” shall be as defined in Section 14.1(a)(ii).

“Title Defect” shall be as defined in Section 6.3.

“Title Defect Amount” shall be as defined in Section 6.2(d).

“Title Defect Deductible” shall be as defined in Section 6.2(d).

“Title Defect Property” shall be as defined in Section 6.2(c).

“Title Examination Period” shall be as defined in Section 6.2(a).

“Transfer Requirement” shall mean any consent, approval, authorization or permit of, or filing with or notification to, any Person which is required to be obtained, made or complied with for or in connection with any sale, assignment or transfer of any Asset or any interest therein other than any consent or approval of or filing with any Governmental Authority or Indian agency or authority in connection with the assignment of any Subject Interest as contemplated by Section 7.4.

“Working Interest” shall mean the percentage of costs and expenses attributable to the maintenance, development and operation of a Property Subdivision.

    Appendix A, Page 8

EXHIBIT A‑1

Attached to and made part of that certain

Asset Purchase Agreement dated as of October 11, 2013,

by and between Cabot Oil & Gas Corporation, as “Seller”, and

Chaparral Energy, L.L.C., as “Buyer”

ARBITRATION PROCEDURES

The Arbitration Procedures referred to in the Asset Purchase Agreement (the “Agreement”) to which this Exhibit A‑1 is attached shall be as follows:

1. Capitalized terms used and not otherwise defined herein shall have the meaning ascribed to such terms in the Agreement.

2. (a)    With respect to unresolved Deferred Adjustment Claims, on or before the Deferred Matters Date, Seller and Buyer shall each submit to the other the list of what such Party considers to comprise the remaining unresolved Deferred Adjustment Claims. The two lists shall together comprise the “Disputed Issues” relating to Deferred Adjustment Claims which shall be resolved by the binding arbitration provided for herein.

(b)    If, pursuant to Section 3.4 of the Agreement, either Buyer or Seller elect to submit any Final Adjustment Statement disagreements to arbitration, such disagreements will also constitute “Disputed Issues” to be resolved by the binding arbitration provided for herein.

3. Seller and Buyer, each being duly authorized by all necessary corporate, limited partnership or other proceedings, shall submit the Disputed Issues to binding arbitration by a board of arbitration to be selected by the following procedures. Notices hereunder shall be sufficient if sent in accordance with the terms of the Agreement. With respect to Disputed Issues involving Deferred Adjustment Claims, within five (5) days after the Deferred Matters Date, Seller shall by written notice to Buyer name one arbitrator and Buyer shall by written notice to Seller name one arbitrator. With respect to Disputed Issues involving Final Adjustment Statement disagreements, within five (5) days after either Buyer or Seller provides the other Party with written notice that such Party desires to submit such Final Adjustment Statement disagreements to arbitration, Seller shall by written notice to Buyer name one arbitrator and Buyer shall by written notice to Seller name one arbitrator. If a Party fails to name an arbitrator, the other Party shall by further written notice to the other Party name the second arbitrator. The two arbitrators so appointed shall name the third arbitrator within ten (10) days after the selection of the second arbitrator. If they fail to do so, either arbitrator may request the judge of the United States District Court for the Southern District of Texas having greatest tenure, but not yet on retired or senior status, to appoint the third arbitrator. If that judge fails to do so within thirty (30) days, either Party may request the judge of that court next senior to name the third arbitrator, and if that judge fails to do so after ten (10) days, either Party may make the request of the judge of that court next senior, and so on, until the

Exhibit A-1, Page 1

board of arbitration is constituted. Each arbitrator must be experienced in and knowledgeable about the oil and gas exploration and production business and, to the extent the Disputed Issues relate to accounting, must be experienced in and knowledgeable about oil and gas accounting matters. In addition, the third arbitrator, in each case, shall be required to meet the qualification requirements of the Commercial Arbitration Rules of the American Arbitration Association (the “AAA Rules”), whether appointed by the arbitrators or by a judge as provided above.

4. If prior to rendering a decision an arbitrator resigns or becomes unable to serve, the arbitrator shall be replaced as follows. If that arbitrator was one of the two arbitrators appointed by a Party, the Party that named him or her shall name a replacement; provided, however, that if that replacement is not named within five (5) days from notice of resignation or inability to serve, the other Party shall name a replacement. If he or she was the third arbitrator, the other two arbitrators shall name a replacement; provided, however, that if they fail to agree on a replacement within ten (10) days, either arbitrator may follow the procedures specified in Paragraph 3 above and request judicial appoint of the replacement.

5. No Party subject to these Arbitration Procedures will commence or prosecute any suit or action against the other Party subject to these Arbitration Procedures relating to the Disputed Issues, other than as may be necessary to compel arbitration under these Arbitration Procedures or to enforce the award of the board of arbitration.

6. The board of arbitration may in all matters act through a majority of its members on each matter if unanimity is not attained. It shall not be necessary that the same majority agree on each and every item; that is, the Parties will be bound by majority rulings on each Disputed Issue even though the majority is not the same as to each Disputed Issue. In fulfilling their duties hereunder with respect to Deferred Adjustment Claims, each of the arbitrators shall be bound by the matters set forth in Article VI of the Agreement. The arbitrators shall not add any interest factor reflecting the time value of money to any Title Defect Amount.

7. No matters whatsoever, other than the Disputed Issues, are subject to the agreement to arbitrate embodied in these Arbitration Procedures. The board of arbitration shall be empowered hereunder solely to resolve the Disputed Issues. The board of arbitration shall not have any authority to award indirect, consequential, exemplary or punitive damages. The sole forum for the arbitration shall be Harris County, Texas and all hearings shall be conducted in Harris County, Texas.

8. The decision of the board of arbitration shall be rendered in writing and shall be final and binding upon the Parties as to the Disputed Issues. The expenses of arbitration, including reasonable compensation to the third arbitrator, shall be borne equally by the Parties. Each Party shall bear the compensation and expenses of its own counsel, witnesses and employees and of any arbitrator it has appointed. If the testimony of a witness is obtained by both Parties, the costs associated with obtaining such testimony shall be borne equally between the Parties.

Exhibit A-1, Page 2

9. Matters not specifically provided for in the Arbitration Procedures shall be governed by the AAA Rules.

Exhibit A-1, Page 3

EX-10.2

THIRTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

This Thirteenth Amendment to Eighth Restated Credit Agreement (this “Thirteenth Amendment”) is effective as of October 29, 2013 (the “Thirteenth Amendment Effective Date”), by and among CHAPARRAL ENERGY, INC., a Delaware corporation (“Parent”),Borrowers, JPMORGAN CHASE BANK, N.A., a national banking association, as Administrative Agent (“Administrative Agent”), and each of the Lenders party hereto.

W I T N E S S E T H:

WHEREAS, Parent, Borrowers, Administrative Agent, the other Agents party thereto and Lenders are parties to that certain Eighth Restated Credit Agreement dated as of April 12, 2010 (as amended prior to the date hereof, the “Credit Agreement”) (unless otherwise defined herein, all terms used herein with their initial letter capitalized shall have the meaning given such terms in the Credit Agreement, as amended by this Thirteenth Amendment); and

WHEREAS, pursuant to the Credit Agreement, the Lenders have made revolving credit loans to Borrowers; and

WHEREAS, Parent and Borrowers have advised Administrative Agent and the Lenders that Chaparral Energy, L.L.C., as buyer (“Chaparral”), has entered into that certain Asset Purchase Agreement dated as of October 11, 2013 (the “Cabot Acquisition Agreement”) with Cabot Oil & Gas Corporation, as seller, pursuant to which Chaparral will acquire, directly or indirectly, the Oil and Gas Properties listed on Exhibit A-2 of the Cabot Acquisition Agreement (collectively, the “Cabot Assets”), as more particularly described in the Cabot Acquisition Agreement; and

WHEREAS, the parties hereto desire to enter into this Thirteenth Amendment to (i) amend certain terms of the Credit Agreement as more specifically set forth herein, (ii) establish a Borrowing Base of $550,000,000, to be effective on the Thirteenth Amendment Effective Date and (iii) provide for the automatic increase of the Borrowing Base to an amount equal to the sum of (a) the Borrowing Base in effect immediately prior to the effectiveness of the increase in the Borrowing Base provided for in Section 3 hereof upon the consummation of Chaparral’s acquisition of the Cabot Assets, pursuant to the Cabot Acquisition Agreement (the “Cabot Acquisition”) plus (b) $50,000,000, which increase is to be effective contemporaneously with but immediately prior to the consummation of the Cabot Acquisition on the Cabot Acquisition Closing Date (as defined below).

NOW THEREFORE, for and in consideration of the mutual covenants and agreements herein contained and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged and confessed, Parent, Borrowers, Administrative Agent and Lenders hereby agree as follows:

Section 1.Amendments. In reliance on the representations, warranties, covenants and agreements contained in this Thirteenth Amendment, and subject to the satisfaction of the conditions precedent set forth in Section 4 hereof, the Credit Agreement is hereby amended effective as of the Thirteenth Amendment Effective Date in the manner provided in this Section 1.

1

1.1Amended and Restated Definitions. The definitions of “Loan Documents” and “Permitted 2012 Bond Debt” contained in Section 1.02 of the Credit Agreement shall be amended to read in full as follows:

“Loan Documents” means this Agreement, the First Amendment, the Second Amendment, the Third Amendment, the Fourth Amendment, the Fifth Amendment, the Sixth Amendment, the Seventh Amendment, the Eighth Amendment, the Ninth Amendment, the Tenth Amendment, the Eleventh Amendment, the Twelfth Amendment, the Thirteenth Amendment, the Notes, the Letter of Credit Agreements, the Letters of Credit, the Certificate of Effectiveness, and the Security Instruments.

“Permitted 2012 Bond Debt” means Debt of Parent resulting from the issuance by Parent of senior unsecured notes in an aggregate outstanding principal amount of $550,000,000, and which Debt (a) has a coupon or interest rate of seven and five-eighths percent (7.625%) per annum, (b) matures on November 15, 2022, (c) is not secured by any Properties of the Credit Parties, (d) does not provide for or otherwise require any amortization prior to scheduled maturity, and (e) is evidenced and governed by the 2012 Indenture and related documentation containing customary terms and conditions, including, without limitation, covenants and events of default, for senior unsecured notes or senior subordinated notes of like tenor and amount.

1.2Additional Definitions. Section 1.02 of the Credit Agreement shall be amended to add the following definitions to such Section in appropriate alphabetical order:

“Acquisition” means, the acquisition by any Credit Party, whether by purchase, merger (and, in the case of a merger with any such Credit Party, with such Credit Party being the surviving Person) or otherwise, of all or substantially all of the Equity Interests of, or all or substantially all of the business, property or fixed assets of or business line or unit or a division of, any other Person, or the acquisition by any Credit Party of property or assets.

“Acquisition Properties” has the meaning set forth in Section 9.18(a)(iii).

“Acquisition Properties Reserve Report” means a report, in form and substance reasonably satisfactory to Administrative Agent, setting forth, as of a recent date acceptable to Administrative Agent, the oil and gas reserves attributable to the proved Oil and Gas Properties constituting Acquisition Properties relating to a certain Acquisition, together with a projection of the rate of production and future net income, taxes, operating expenses and capital expenditures with respect to such Acquisition Properties as of such date.

“Mortgaged Properties” has the meaning set forth in Section 8.12(c)(vi).

“Thirteenth Amendment” means that certain Thirteenth Amendment to Eighth Restated Credit Agreement dated effective as of October 29, 2013, among Parent, Borrowers, Administrative Agent and the Lenders party thereto.

1.3Amendment to Section 8.12(c) of the Credit Agreement. Clause (vi) of Section 8.12(c) of the Credit Agreement is hereby amended and restated in its entirety to read in full as follows:

(vi) attached thereto is a schedule of the proved Oil and Gas Properties evaluated by such Reserve Report that are subject to Liens to secure payment of the Indebtedness (such Oil and Gas Properties being referred to herein as the “Mortgaged Properties”), which schedule demonstrates the percentage of the Recognized Value of the proved Oil and Gas Properties evaluated by such Reserve Report that the value of such Mortgaged Properties represent.

1.4Amendment to Debt Covenant

(a)Section 9.02(g) of the Credit Agreement shall be amended by deleting the reference to “May 2, 2012” contained therein and inserting in lieu thereof a reference to “November 15, 2012”.

(b)Section 9.02(h) of the Credit Agreement shall be amended by deleting the reference to “$150,000,000” contained therein and inserting in lieu thereof a reference to “$300,000,000”.

(c)Section 9.02(n) of the Credit Agreement shall be amended by deleting the reference to “$40,000,000” contained therein and inserting in lieu thereof a reference to “$50,000,000”.

1.5Amendments to Section 9.18 of the Credit Agreement.

(a)Section 9.18(a)(ii) of the Credit Agreement shall be amended by deleting the “.” at the end of Section 9.18(a)(ii) and inserting in lieu thereof “; and”.

(b)A new Section 9.18(a)(iii) is hereby added to the Credit Agreement immediately following Section 9.18(a)(ii) thereof, which Section 9.18(a)(iii) shall read in full as follows:

(iii)    notwithstanding the limitations set forth in clause (i) of this Section 9.18(a), in contemplation of an Acquisition consisting directly or indirectly of Oil and Gas Properties (such properties being referred to herein as the “Acquisition Properties”), the Credit Parties may enter into Swap Agreements in respect of commodities (A) with an Approved Counterparty, (B) which shall not, in any case, have a tenor of greater than three years and (C) the notional volumes for which (when aggregated with all other Swap Agreements then in effect on notional volumes relating to the Acquisition Properties and entered into in reliance on this clause (iii)) do not exceed, as of the date such Swap Agreement is executed, eighty percent (80%) of the reasonably anticipated projected production from Proved Developed Producing Reserves of the Acquisition Properties for each of oil and

gas, calculated separately, for each month during the period during which such Swap Agreement is in effect, as set forth in the applicable Acquisition Properties Reserve Report delivered to Administrative Agent; provided, that (w) at the time of entering into such Swap Agreement, and immediately after giving effect thereto, the aggregate amount of Commitments hereunder shall exceed the Credit Exposure by at least fifteen percent (15%) of the aggregate amount of Commitments; (x) such Swap Agreement is entered into after the execution of a definitive agreement with respect to such proposed Acquisition, but in any event no earlier than ninety (90) days prior to the proposed closing date of such Acquisition; (y) in the event such agreement is terminated or such Acquisition is otherwise not consummated within 90 days after such Swap Agreement is entered into, then within fifteen (15) days after such termination or the end of such 90 day period, as applicable, such Credit Party shall novate, unwind or otherwise dispose of such Swap Agreement to the extent necessary to be in compliance with the limitations set forth in clause (i) of this Section 9.18(a); and (z) the notional volumes of such Swap Agreement (when aggregated with all other commodity Swap Agreements then in effect other than basis differential swaps on volumes already hedged pursuant to other Swap Agreements), does not exceed, as of the date such Swap Agreement is executed, the applicable percentage set forth in the table below of the reasonably anticipated projected production from Proved Reserves of oil and gas (but not natural gas liquids) of the Credit Parties for up to 36 months following such date of execution for Oil and Gas Properties of the Credit Parties (for purposes of clarity, expressly excluding the oil and gas reserves constituting Acquisition Properties) as set forth in the most recent Reserve Report delivered to Administrative Agent hereunder (as such report may be supplemented from time to time by the Credit Parties delivering to Administrative Agent updated well projections and other information reflecting the drilling activity, acquisitions, dispositions and other results of operations completed since the effective date of such Reserve Report) for each of oil and gas, calculated separately, for each month during the period during which such Swap Agreement is in effect:

Period  (relative to execution date of relevant Swap Agreement)	Percentage Limitation
	Oil	Gas
Months 1-12	120% TP	120% TP
Months 13-24	110% TP	110% TP
Months 25-36	80% TP	80% TP

(c)Section 9.18(c) of the Credit Agreement is hereby amended and restated in its entirety to read in full as follows:

(c)    terminate any Swap Agreement in respect of commodities (including, as applicable, any trade confirmations made pursuant thereto), now existing or hereafter arising, without the prior written consent of the Required Lenders except to the extent such terminations are permitted by Section 9.12 or required by Section 9.18(a)(iii).

1.6Amendment to Section 12.01(a)(i) of the Credit Agreement. Clause (i) of Section 12.01(a) of the Credit Agreement is hereby amended and restated in its entirety to read in full as follows:

(i)    if to Parent or the Borrowers (or Borrower Representative), to them or it, c/o Chaparral Energy, L.L.C., 701 Cedar Lake Blvd., Oklahoma City, Oklahoma 73114, Attention: Mark A. Fischer (Telecopy No. (405) 425-8410); with a copy to Chaparral Energy, L.L.C., 701 Cedar Lake Blvd., Oklahoma City, Oklahoma 73114, Attention: David J. Ketelsleger (Telecopy No. (405) 425-8872);

SECTION 2.Borrowing Base Increase.    Pursuant to Section 2.07 of the Credit Agreement, and subject to the satisfaction of the conditions precedent set forth in Section 4 hereof, the Borrowing Base shall be increased from $500,000,000 and redetermined to be $550,000,000 effective as of the Thirteenth Amendment Effective Date, and shall remain at $550,000,000 until the next Scheduled Redetermination, Interim Redetermination or other redetermination of the Borrowing Base thereafter, whichever occurs first pursuant to the Credit Agreement as amended hereby, subject, however, to any increase which may occur in accordance with Section 3, below. Borrower Representative (on behalf of each Borrower), Parent and Lenders agree that the redetermination of the Borrowing Base provided for in this Section 2 shall be considered and deemed to be the November 1, 2013 Scheduled Redetermination.

SECTION 3.Borrowing Base Increase Upon Consummation of the Cabot Acquisition. In reliance on the representations, warranties, covenants and agreements contained in this Thirteenth Amendment, and subject to the satisfaction of the conditions precedent set forth in Section 5 hereof, Parent, Borrowers, Administrative Agent, and Lenders hereby agree that the Borrowing Base shall

be redetermined and automatically increased to an amount equal to the sum of (x) the Borrowing Base in effect immediately prior to giving effect to the increase in the Borrowing Base provided for in this Section 3 plus (y) $50,000,000, which increase is to be effective contemporaneously with but immediately prior to the consummation of the Cabot Acquisition on the Cabot Acquisition Closing Date (as defined below). The Borrowing Base shall remain at such level until the next Scheduled Redetermination, the next Interim Redetermination or other adjustment to the Borrowing Base thereafter, whichever occurs first pursuant to the Credit Agreement as amended hereby.

SECTION 4.Conditions Precedent to this Thirteenth Amendment. The effectiveness of (i) the amendments to the Credit Agreement contained in Section 1 hereof, and (ii) the increase of the Borrowing Base contained in Section 2 hereof, is subject to the satisfaction of each of the following conditions precedent:

4.1No Default or Borrowing Base Deficiency. No Default or Event of Default shall have occurred which is continuing and the total Credit Exposures of all Lenders shall not exceed the Borrowing Base.

4.2Upfront Fees. Administrative Agent shall have received, for the account of the Lenders, upfront fees equal to 40 basis points (0.40%) on the amount by which each Lender’s allocated commitment to the Borrowing Base (after giving effect to the redetermination of the Borrowing Base as set forth in Section 2 hereof) exceeds such Lender’s allocated commitment to the Borrowing Base that was in effect immediately prior to the establishment of such redetermined Borrowing Base.

4.3Other Documents. Administrative Agent shall have been provided with such other documents, instruments and agreements, and Parent and Borrowers shall have taken such actions, as Administrative Agent or counsel to Administrative Agent may reasonably require in connection with this Thirteenth Amendment and the transactions contemplated hereby.

SECTION 5.Conditions to Borrowing Base Increase upon Consummation of the Cabot Acquisition. The increase of the Borrowing Base provided for in Section 3 hereof is subject to the satisfaction of each of the following conditions precedent:

5.1Thirteenth Amendment Conditions. Each of the conditions set forth in Section 4 hereof shall have been satisfied.

5.2Cabot Acquisition Closing Date. The closing date of the Cabot Acquisition (the “Cabot Acquisition Closing Date”) occurs on or prior to January 31, 2014.

5.3Deliverables. Administrative Agent shall have received (a) a certificate of a Responsible Officer of Chaparral certifying: (i) that Chaparral is concurrently consummating the Cabot Acquisition and directly or indirectly acquiring the Cabot Assets in accordance with all Governmental Requirements and the terms of the Cabot Acquisition Agreement (together with all agreements, instruments, bills of sale, assignments, and documents executed in connection therewith, the “Cabot Acquisition Documents”), with all of the material conditions precedent thereto having been satisfied in all material respects by the parties thereto and with no provision of such

Cabot Acquisition Documents having been waived, amended, supplemented or otherwise modified in any material respect without the approval of Administrative Agent (such approval not to be unreasonably withheld, conditioned or delayed; provided, that, for the avoidance of doubt, it shall be reasonable for Administrative Agent to withhold its consent to any such waiver or amendment that removes any Oil and Gas Properties (other than a waiver or amendment which removes up to $2,500,000 of Oil and Gas Properties (as determined by Administrative Agent) from the Cabot Assets)); and (ii) as to the final purchase price for the Cabot Acquisition after giving effect to all adjustments as of the Cabot Acquisition Closing Date and specifying, by category, the amount of such adjustments; (b) original counterparts or copies, certified as true and complete by a Responsible Officer of Chaparral, of each of the Cabot Acquisition Documents not previously delivered and certified to Administrative Agent, which Cabot Acquisition Documents shall have terms and conditions reasonably satisfactory to Administrative Agent; and (c) such other related documents and information as Administrative Agent shall have reasonably requested.

5.4No Default or Borrowing Base Deficiency. No Default or Event of Default shall have occurred which is continuing and the total Credit Exposures of all Lenders shall not exceed the Borrowing Base.

5.5Title Information; Mortgaged Properties. After giving effect to the Cabot Acquisition and any additional title information and Security Instruments delivered by any Credit Party to Administrative Agent in connection therewith, (A) Administrative Agent shall have received title information satisfactory to it on at least 80% of the total Recognized Value of the proved Oil and Gas Properties evaluated in the most recent Reserve Report (as supplemented by any applicable Reserve Reports relating to the Cabot Assets) and (B) the Mortgaged Properties shall represent at least 80% of the total Recognized Value of the proved Oil and Gas Properties evaluated in the most recent Reserve Report (as supplemented by any applicable Reserve Reports relating to the Cabot Assets).

5.6Fees. Administrative Agent shall have received, for the account of the Lenders, upfront fees equal to 40 basis points (0.40%) on the amount by which each Lender’s allocated commitment to the Borrowing Base (after giving effect to the redetermination of the Borrowing Base set forth in Section 3 hereof) exceeds such Lender’s allocated commitment to the Borrowing Base that was in effect immediately prior to the establishment of such redetermined Borrowing Base.

5.7Environmental Review. Administrative Agent shall be satisfied with the environmental condition of the Cabot Assets.

5.8Payoff and Release. Administrative Agent shall have received evidence reasonably satisfactory to Administrative Agent that, concurrently with the funding of any Loans on the Cabot Acquisition Closing Date and application of the proceeds thereof, all Liens encumbering the Cabot Assets will be released (other than the Liens securing the Indebtedness and created pursuant to the Security Instruments and Excepted Liens identified in clauses (a) to (d) and (f) of the definition thereof, subject to the provisos at the end of such definition).

5.9Other Documents. Administrative Agent shall have been provided with such other documents, instruments and agreements, and Parent and Borrowers shall have taken such actions, as Administrative Agent or counsel to Administrative Agent may reasonably require, including legal opinions from local counsel in jurisdictions where any Mortgaged Properties are located.

SECTION 6.Representations and Warranties of Borrowers. To induce the Lenders and Administrative Agent to enter into this Thirteenth Amendment, Parent and Borrowers hereby jointly and severally represent and warrant to the Lenders and Administrative Agent as follows:

6.1Reaffirm Existing Representations and Warranties. Each representation and warranty of each Credit Party contained in the Credit Agreement and the other Loan Documents is true and correct on the date hereof and will be true and correct after giving effect to the amendments set forth in Section 1 hereof, except to the extent such representations and warranties are expressly limited to an earlier date, in which case such representations and warranties shall be true and correct as of such specified earlier date.

6.2Due Authorization; No Conflict. The execution, delivery and performance by Parent and Borrowers of this Thirteenth Amendment are within Parent’s and Borrowers’ corporate and limited liability company powers (as applicable), have been duly authorized by all necessary action, require no action by or in respect of, or filing with, any governmental body, agency or official and do not violate or constitute a default under any provision of applicable law or any material agreement binding upon Parent, any Borrower or any other Credit Party or result in the creation or imposition of any Lien upon any of the assets of Parent, any Borrower or any other Credit Party except Excepted Liens.

6.3Validity and Enforceability. This Thirteenth Amendment constitutes the valid and binding obligation of Parent and Borrowers enforceable in accordance with its terms, except as (%3) the enforceability thereof may be limited by bankruptcy, insolvency or similar laws affecting creditor’s rights generally, and (%3) the availability of equitable remedies may be limited by equitable principles of general application.

6.4No Default, Event of Default or Borrowing Base Deficiency. No Default or Event of Default has occurred which is continuing and the total Credit Exposures of all Lenders do not exceed the Borrowing Base.

SECTION 7.Miscellaneous.

7.1Reaffirmation of Loan Documents; Extension of Liens. Any and all of the terms and provisions of the Credit Agreement and the Loan Documents shall, except as amended and modified hereby, remain in full force and effect. The amendments contemplated hereby shall not limit or impair any Liens securing the Indebtedness, each of which are hereby ratified, affirmed and extended to secure the Indebtedness after giving effect to this Thirteenth Amendment.

7.2Parties in Interest. All of the terms and provisions of this Thirteenth Amendment shall bind and inure to the benefit of the parties hereto and their respective successors and assigns.

7.3Legal Expenses. Parent and Borrowers hereby jointly and severally agree to pay on demand all reasonable fees and expenses of counsel to Administrative Agent incurred by Administrative Agent in connection with the preparation, negotiation and execution of this Thirteenth Amendment and all related documents.

7.4Counterparts. This Thirteenth Amendment may be executed in counterparts, and all parties need not execute the same counterpart; however, no party shall be bound by this Thirteenth Amendment until Parent, Borrowers and each Lender has executed a counterpart. Facsimiles or other electronic transmission (e.g. .pdf) shall be effective as originals.

7.5Complete Agreement. THIS THIRTEENTH AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN OR AMONG THE PARTIES.

7.6Headings. The headings, captions and arrangements used in this Thirteenth Amendment are, unless specified otherwise, for convenience only and shall not be deemed to limit, amplify or modify the terms of this Thirteenth Amendment, nor affect the meaning thereof.

7.7Effectiveness. This Thirteenth Amendment shall be effective automatically and without necessity of any further action by Parent, Borrowers, Administrative Agent or Lenders when counterparts hereof have been executed by Parent, Borrowers, Administrative Agent and each Lender, and all conditions to the effectiveness hereof set forth herein have been satisfied.

7.8Governing Law. This Thirteenth Amendment shall be governed by, and construed in accordance with, the laws of the State of New York.

IN WITNESS WHEREOF, the parties hereto have caused this Thirteenth Amendment to be duly executed by their respective Responsible Officers on the date and year first above written.

[Signature pages to follow]

PARENT: CHAPARRAL ENERGY, INC.,
a Delaware corporation

By: /s/ Mark A. Fischer    Mark A. Fischer, Chief Executive Officer and President

BORROWERS: CHAPARRAL ENERGY, L.L.C.CHAPARRAL RESOURCES, L.L.C.
CHAPARRAL CO₂, L.L.C.
CEI ACQUISITION, L.L.C.
CEI PIPELINE, L.L.C.
CHAPARRAL REAL ESTATE, L.L.C.
CHAPARRAL EXPLORATION, L.L.C.
ROADRUNNER DRILLING, L.L.C.

By: /s/ Mark A. Fischer    Mark A. Fischer, Manager

GREEN COUNTRY SUPPLY, INC.

By: /s/ Mark A. Fischer    Mark A. Fischer, Chief Executive Officer and President

SIGNATURE PAGE

THIRTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

ADMINISTRATIVE AGENT/LENDER: JPMORGAN CHASE BANK, N.A.,
as Administrative Agent and a Lender

By: /s/ Scott C. Pittman    Scott C. Pittman,Authorized Officer

SIGNATURE PAGE

THIRTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: CAPITAL ONE, NATIONAL ASSOCIATION,
as a Lender

By:     /s/ Michael Higgins        

Name:    Michael Higgins

Title:    Vice President

SIGNATURE PAGE

THIRTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: ROYAL BANK OF CANADA,
as a Lender

By:     /s/ Mark Lumpkin, Jr.        

Name:    Mark Lumpkin, Jr.

Title:    Authorized Signatory

SIGNATURE PAGE

THIRTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: UBS LOAN FINANCE LLC,
as a Lender

By:     /s/ Lana Gifas        

Name:    Lana Gifas

Title:    Director

By:     /s/ Jennifer Anderson        

Name:    Jennifer Anderson

Title:    Associate Director

SIGNATURE PAGE

THIRTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: CREDIT AGRICOLE CORPORATE AND INVESTMENT BANK,
as a Lender

By:     /s/ Sharada Manne        

Name:    Sharada Manne

Title:    Managing Director

By:     /s/ Michael D. Willis        

Name:    Michael D. Willis

Title:    Managing Director

SIGNATURE PAGE

THIRTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: SOCIÉTÉ GÉNÉRALE,
as a Lender

By:     /s/ David M. Bornstein        

Name:    David M. Bornstein

Title:    Director

SIGNATURE PAGE

THIRTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: WELLS FARGO BANK, N.A.,as a Lender

By:     /s/ Muhammad A. Dhamani        

Name:    Muhammad A. Dhamani

Title:    Vice President

SIGNATURE PAGE

THIRTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: THE BANK OF NOVA SCOTIA,
as a Lender

By:     /s/ Terry Donovan        

Name:    Terry Donovan

Title:    Managing Director

SIGNATURE PAGE

THIRTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: COMERICA BANK,
as a Lender

By:     /s/ Katya Evseev        

Name:    Katya Evseev

Title:    Assistant Vice President

SIGNATURE PAGE

THIRTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: NATIXIS, NEW YORK BRANCH,
as a Lender

By:     /s/ Louis P. Laville, III        

Name:    Louis P. Laville, III

Title:    Managing Director

By:     /s/ Stuart Murray        

Name:    Stuart Murray

Title:    Managing Director

SIGNATURE PAGE

THIRTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: AMEGY BANK NATIONAL ASSOCIATION,
as a Lender

By:     /s/ Larry Sears        

Name:    Larry Sears

Title:    Senior Vice President

SIGNATURE PAGE

THIRTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: COMPASS BANK,
as a Lender

By:     /s/ Ian Payne        

Name:    Ian Payne

Title:    Vice President

SIGNATURE PAGE

THIRTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: CREDIT SUISSE AG, CAYMAN ISLANDS BRANCH,

as a Lender

By:     /s/ Vipul Dhadda        

Name:    Vipul Dhadda

Title:    Authorized Signatory

By:     /s/ Michael Spaight        

Name:    Michael Spaight

Title:    Authorized Signatory

SIGNATURE PAGE

THIRTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: KEYBANK NATIONAL ASSOCIATION,
as a Lender

By:     /s/ Paul J. Pace        

Name:    Paul J. Pace

Title:    Senior Vice President

SIGNATURE PAGE

THIRTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: UNION BANK, N.A.,
as a Lender

By:     /s/ Rachel Bowman        

Name:    Rachel Bowman

Title:    Vice President

SIGNATURE PAGE

THIRTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: U.S. BANK NATIONAL ASSOCIATION,
as a Lender

By:     /s/ Nicholas T. Hanford        

Name:    Nicholas T. Hanford

Title:    Vice President

SIGNATURE PAGE

THIRTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: GOLDMAN SACHS BANK USA,
as a Lender

By:     /s/ Mark Walton        

Name:    Mark Walton

Title:    Authorized Signatory

SIGNATURE PAGE

THIRTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

EX-31.1

Exhibit 31.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER PURSUANT TO

RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACT

I, Mark A. Fischer, Chief Executive Officer of Chaparral Energy, Inc., certify that:

1. I have reviewed this quarterly report on Form 10-Q of Chaparral Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 14, 2013

/s/ Mark A. Fischer

Mark A. Fischer

Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACT

I, Joseph O. Evans, Chief Financial Officer of Chaparral Energy, Inc., certify that:

1. I have reviewed this quarterly report on Form 10-Q of Chaparral Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 14, 2013

/s/ Joseph O. Evans

Joseph O. Evans

Chief Financial Officer

EX-32.1

Exhibit 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

In connection with the Quarterly Report of Chaparral Energy, Inc. (the “Company”) on Form 10-Q for the period ending September 30, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Mark A. Fischer, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Mark A. Fischer

Mark A. Fischer

Chief Executive Officer

Date: November 14, 2013

EX-32.2

Exhibit 32.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Chaparral Energy, Inc. (the “Company”) on Form 10-Q for the period ending September 30, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Joseph O. Evans, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Joseph O. Evans

Joseph O. Evans

Chief Financial Officer

Date: November 14, 2013

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Nature of operations and summary of significant accounting policies (Policies)

9 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Interim financial statements

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, 2012.

The financial information as of September 30, 2013, and for the three and nine months ended September 30, 2013 and 2012, 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 nine months ended September 30, 2013 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2013.

Cash and cash equivalents

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.

Accounts receivable

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. 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.

Inventories

Inventories

Inventories are comprised of equipment used in developing oil and natural gas properties and oil and natural gas production inventories. Equipment inventory is 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.

Oil and natural gas properties

Oil and natural gas properties

We use the full cost method of accounting for oil and natural gas properties and activities. Accordingly, we capitalize all costs incurred in connection with the exploration for and development of oil and natural gas reserves. Proceeds from the disposition of oil and natural gas properties are accounted for as a reduction in capitalized costs, with no gain or loss generally recognized unless such dispositions involve a significant alteration in the depletion rate. We sold certain oil and gas properties for total cash proceeds of approximately $90,530 and $44,523 subject to post-closing adjustments for the nine months ended September 30, 2013 and 2012, respectively, which did not have a significant impact on our depletion rate. After September 30, 2013, we also sold certain additional oil and gas properties for a total price of approximately $12,500 subject to post-closing adjustments.

On October 11, 2013, we entered into an agreement with Cabot Oil & Gas Corporation to acquire certain oil and gas properties and related assets in the Panhandle Marmaton Play for $160,128 subject to pre- and post-closing adjustments (the “Cabot Acquisition”). We paid $16,013 in earnest money for the Cabot Acquisition with the balance due upon closing, which is expected to occur in the fourth quarter of 2013.

We capitalize internal costs that can be directly identified with exploration and development activities, but do not include any costs related to production, general corporate overhead or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and natural gas wells, including salaries, benefits and other internal costs directly attributable to these activities.

The costs of unevaluated oil and natural gas properties are excluded from amortization until the properties are evaluated. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined.

Stock-based compensation

Stock-based compensation

Our stock-based compensation programs consist of phantom stock, restricted stock units (“RSU”), and restricted stock awards issued to employees. Generally, we use new shares to grant restricted stock awards, and we cancel restricted shares forfeited or repurchased for tax withholding. Canceled shares are available to be issued as new grants under our 2010 Equity Incentive Plan.

The estimated fair value of the phantom stock and RSU 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 and the Non-Officer Restricted Stock Unit 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 and RSU awards is recognized over the vesting period using the straight-line method and the accelerated method, respectively.

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.

Recently adopted accounting pronouncements

Recently adopted accounting pronouncements

In December 2011, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance that requires enhanced disclosures that will enable financial statement users to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. In January 2013, additional guidance was issued which narrows the scope of the disclosure requirements to derivatives, securities borrowings, and securities lending transactions that are either offset or subject to a master netting arrangement. This guidance, which was effective and adopted by us in the first quarter of 2013, resulted in additional disclosures but had no financial impact.

In February 2013, the FASB issued authoritative guidance that requires disclosures of the amounts reclassified out of accumulated other comprehensive income (“AOCI”) by component, including the respective line items of net income if the amount is required to be reclassified to net income in its entirety in the same reporting period. This additional guidance was effective and adopted by us in the first quarter of 2013. As our entire balance in AOCI consists of deferred hedge gains, implementation of the guidance had no significant impact on our financial statement presentation and disclosures.

Recently issued accounting pronouncements

In July 2011, the FASB issued authoritative guidance regarding how health insurers should recognize and classify in their income statements the fees mandated by the Health Care and Education Reconciliation Act (“HCERA”). The HCERA imposes an annual fee upon health insurers for each calendar year beginning on or after January 1, 2014. The annual fee will be allocated to individual entities providing health insurance to employees based on a ratio, as provided for in the HCERA, and is not tax deductible. This guidance specifies that once the entity has provided qualifying health insurance in the calendar year in which the fee is payable, the liability for the entity’s fee should be estimated and recorded in full with a corresponding deferred cost that is amortized to expense on a straight line basis, unless another method better allocates the fee over the calendar year that it is payable. This guidance is effective for calendar years beginning after December 15, 2013, once the fee is instituted. We are currently assessing the impact that this fee and the adoption of the related authoritative guidance will have on our financial statements.

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Consolidated statements of operations (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Revenues:
Oil and natural gas sales	$ 161,623	$ 131,215	$ 433,489	$ 374,452
Gain from oil hedging activities	9,032	11,468	28,544	35,777
Total revenues	170,655	142,683	462,033	410,229
Costs and expenses:
Lease operating	37,306	35,278	104,232	98,946
Production taxes	8,831	8,748	25,299	24,258
Depreciation, depletion & amortization	47,582	44,421	139,439	119,807
Loss on impairment of other assets	1,090	0	1,090	0
General and administrative	13,065	12,878	38,626	39,165
Total costs and expenses	107,874	101,325	308,686	282,176
Operating income	62,781	41,358	153,347	128,053
Non-operating income (expense):
Interest expense	(24,074)	(24,087)	(72,565)	(72,666)
Non-hedge derivative (losses) gains	(43,830)	(25,030)	(26,484)	37,035
Loss on extinguishment of debt	0	(18)	0	(21,714)
Other income, net	425	104	837	236
Net non-operating expense	(67,479)	(49,031)	(98,212)	(57,109)
(Loss) income before income taxes	(4,698)	(7,673)	55,135	70,944
Income tax (benefit) expense	(2,130)	(2,727)	19,993	25,645
Net (loss) income	$ (2,568)	$ (4,946)	$ 35,142	$ 45,299

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Derivative instruments

9 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative instruments

Derivative 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 various types of derivative instruments, including commodity price swaps, costless collars, put options, and basis protection swaps.

For commodity price swaps, we receive a fixed price for the hedged commodity and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

Collars contain a fixed floor price (purchased put) and ceiling price (sold 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 sold put with a price below the floor price of the collar. The sold put option requires us to make a payment to the counterparty if the market price is below the sold put option price. If the market price is greater than the sold 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 sold put option, we are entitled to a net payment equal to the difference between the floor price of the standard collar and the sold put option price if the market price falls below the sold 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 utilizing the value associated with the sale of a put option.

Put options may be purchased from the counterparty by our payment of a cash premium. If the market price is below the put strike price at the settlement date, we will receive a payment from the counterparty. Purchased put options are designed to provide a fixed price floor with the opportunity for upside if commodity prices increase.

We enhance the value of certain oil swaps by combining them with sold puts or put spread contracts. Sold puts require us to make a payment to the counterparty if the market price is below the put strike price at the settlement date. If the market price is greater than the sold put price, the result is the same as it would have been with a swap contract only. A put spread is a combination of a sold put and a purchased put. If the market price falls below the purchased put option price, we will receive the spread between the sold put option price and the purchased put option price from the counterparty. The use of a sold put allows us to receive an above-market swap price while the purchased put provides a measure of downside protection.

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.

We protect a portion of our natural gas liquids production from price volatility using crude oil derivatives. The following table summarizes our crude oil derivatives outstanding as of September 30, 2013:

		Weighted average fixed price per Bbl
Period and Type of Contract	Volume MBbls	Swaps		Sold puts		Purchased puts		Sold calls
2013
Swaps	510	$	95.54	$	—	$	—	$	—
Three-way collars	900	$	—	$	77.83	$	99.94	$	114.49
2014
Swaps	739	$	92.51	$	—	$	—	$	—
Three-way collars	2,400	$	—	$	75.50	$	93.25	$	101.94
Enhanced swaps	840	$	98.62	$	80.00	$	—	$	—
Put spread enhanced swaps	2,225	$	93.64	$	80.00	$	60.00	$	—
Purchased puts	840	$	—	$	—	$	60.00	$	—
2015
Enhanced swaps	4,918	$	93.35	$	80.00	$	—	$	—

The following tables summarize our natural gas derivative instruments outstanding as of September 30, 2013:

Period and Type of Contract	Volume BBtu	Weighted average fixed price per MMBtu
2013
Natural gas swaps	4,890	$	4.34
Natural gas basis protection swaps	5,390	$	0.20
2014
Natural gas swaps	18,420	$	4.03
Natural gas basis protection swaps	21,550	$	0.24
2015
Natural gas swaps	10,800	$	4.26
Natural gas basis protection swaps	2,400	$	0.18

Effect of derivative instruments on the consolidated balance sheets

All derivative financial instruments are recorded on the balance sheet at fair value. See Note 5 for additional information regarding fair value measurements. 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 September 30, 2013								As of December 31, 2012
	Assets		Liabilities			Net value			Assets		Liabilities			Net value
Natural gas swaps	$	9,180	$	(281	)	$	8,899		$	13,642	$	(1,487	)	$	12,155
Oil swaps	122		(5,363		)	(5,241		)	4,957		(1,339		)	3,618
Oil collars	3,974		(538		)	3,436			27,411		(1,180		)	26,231
Oil enhanced swaps	2,005		(8,229		)	(6,224		)	—		—			—
Oil purchased puts (1)	185		—			185			—		—			—
Natural gas basis differential swaps	778		(345		)	433			—		(1,599		)	(1,599		)
Total derivative instruments	16,244		(14,756		)	1,488			46,010		(5,605		)	40,405
Less:
Netting adjustments (2)	7,763		(7,763		)	—			2,977		(2,977		)	—
Current portion asset (liability)	4,449		(6,971		)	(2,522		)	42,516		(436		)	42,080
	$	4,032	$	(22	)	$	4,010		$	517	$	(2,192	)	$	(1,675	)

(1) Includes premiums of $664 paid during the second quarter of 2013. No additional premiums have been paid.

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

We discontinued hedge accounting effective April 1, 2010. Net derivative gains attributable to derivatives previously subject to hedge accounting were deferred through AOCI. As of September 30, 2013 and December 31, 2012, respectively, AOCI consists of deferred gains of $8,590 ($5,445 net of tax) and $37,134 ($23,223 net of tax) that will be recognized as gains from oil hedging activities through December 2013 as the hedged production is sold.

Derivative settlements outstanding at September 30, 2013 and December 31, 2012 were as follows:

	September 30, 2013		December 31, 2012
Derivative settlements receivable included in accounts receivable	$	317	$	8,013
Derivative settlements payable included in accounts payable and accrued liabilities	$	3,393	$	41

Effect of derivative instruments on the consolidated statements of operations

We do not apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as non-hedge derivative gains (losses) in the consolidated statements of operations. Gain from oil hedging activities, which is a component of total revenues in the consolidated statements of operations, consists of the reclassification of hedge gains on discontinued oil hedges from AOCI into net income.

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

	Three months ended						Nine months ended
	September 30,						September 30,
	2013			2012			2013			2012
Change in fair value of commodity price swaps	$	(7,795	)	$	(22,167	)	$	(12,115	)	$	(7,451	)
Change in fair value of collars	(16,057		)	(14,094		)	(22,795		)	20,480
Change in fair value of enhanced swaps and put options	(17,499		)	—			(6,703		)	—
Change in fair value of natural gas basis differential contracts	342			526			2,032			(303		)
(Payments on) receipts from settlement of commodity price swaps	(2,510		)	8,046			2,327			20,022
(Payments on) receipts from settlement of collars	(256		)	3,079			11,300			5,711
Payments on settlement of natural gas basis differential contracts	(55		)	(420		)	(530		)	(1,424		)
	$	(43,830	)	$	(25,030	)	$	(26,484	)	$	37,035

Any premiums paid on derivative contracts will be included in non-hedge derivative gains (losses) as the derivative contracts settle.

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Stock-based compensation (Tables)

9 Months Ended

Sep. 30, 2013

Share-based Compensation [Abstract]

Rollforward of unvested stock-based compensation awards

A summary of our restricted stock activity during the nine months ended September 30, 2013 is presented below: 

	Time Vested						Performance Vested
	Weighted average grant date fair value		Restricted shares		Vest date fair value		Weighted average grant date fair value		Restricted shares
	($ per share)						($ per share)
Unvested and outstanding at January 1, 2013	$	651.97	9,481				$	324.48	55,824
Granted	$	626.02	2,839				$	181.59	5,217
Vested	$	679.09	(2,030	)	$	1,256	$	—	—
Forfeited	$	620.01	(1,779	)			$	340.23	(3,171	)
Modified	$	626.00	11,169				$	324.47	(11,169	)
Unvested and total outstanding at September 30, 2013	$	633.58	19,680				$	307.45	46,701

A summary of our phantom stock and RSU activity during the nine months ended September 30, 2013 is presented in the following table:

	Phantom Plan						RSU Plan
	Weighted average grant date fair value		Phantom shares		Vest date fair value		Weighted average grant date fair value		Restricted Stock Units		Vest date fair value
	($ per share)						($ per share)
Unvested and outstanding at January 1, 2013	$	16.87	84,764				$	17.12	151,909
Granted	$	—	—				$	12.45	291,253
Vested	$	16.20	(21,260	)	$	273	$	17.12	(50,246	)	$	626
Forfeited	$	17.52	(9,388	)			$	14.35	(55,051	)
Unvested and outstanding at September 30, 2013	$	17.03	54,116				$	13.54	337,865

Schedule of Performance Award Vesting and Return on Investment Targets

Effective January 1, 2013, we amended and restated all outstanding Performance Vested awards to reflect that: (i) those shares which would vest if CCMP receives net proceeds from a Transaction that yields a return of at least 400% per share were removed from the initial Performance Vested awards and an equal number of Time Vested shares were granted effective as of January 1, 2013; and (ii) the return on investment targets applicable to the remaining number of Performance Vested shares and to any new grants of Performance Vested shares were set at the following levels:

Return on Investment Target	Target Shares Vested
175% per share	20% of shares multiplied by the Vesting Fraction
200% per share	20% of shares multiplied by the Vesting Fraction
250% per share	20% of shares multiplied by the Vesting Fraction
300% per share	20% of shares multiplied by the Vesting Fraction
350% per share	20% of shares multiplied by the Vesting Fraction

Stock-based compensation cost

We recognized stock-based compensation expense as follows for the periods indicated:

	Three months ended						Nine months ended
	September 30,						September 30,
	2013			2012			2013			2012
Stock-based compensation cost	$	2,045		$	1,725		$	4,620		$	4,773
Less: stock-based compensation cost capitalized	(505		)	(605		)	(1,440		)	(1,715		)
Stock-based compensation expense	$	1,540		$	1,120		$	3,180		$	3,058

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Nature of operations and summary of significant accounting policies (Tables)

9 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Accounts receivable

Accounts receivable consisted of the following at September 30, 2013 and December 31, 2012:

	September 30, 2013			December 31, 2012
Joint interests	$	35,856		$	19,282
Accrued oil and natural gas sales	61,380			50,814
Derivative settlements	317			8,013
Other	546			472
Allowance for doubtful accounts	(1,636		)	(1,274		)
	$	96,463		$	77,307

Inventories

Inventories at September 30, 2013 and December 31, 2012 consisted of the following:

	September 30, 2013			December 31, 2012
Equipment inventory	$	9,688		$	8,047
Oil and natural gas product	3,087			3,175
Inventory valuation allowance	(706		)	(712		)
	$	12,069		$	10,510

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Common stock (Details)	9 Months Ended			9 Months Ended
	Sep. 30, 2013	Sep. 30, 2013 Common Stock	Dec. 31, 2012 Common Stock	Sep. 30, 2013 Common Class A	Sep. 30, 2013 Common Class B	Dec. 31, 2012 Common Class B	Sep. 30, 2013 Common Class C	Dec. 31, 2012 Common Class C	Sep. 30, 2013 Common Class D	Dec. 31, 2012 Common Class D	Sep. 30, 2013 Common Class E	Dec. 31, 2012 Common Class E	Sep. 30, 2013 Common Class F	Dec. 31, 2012 Common Class F	Sep. 30, 2013 Common Class G	Dec. 31, 2012 Common Class G
Common stock rollforward
Shares outstanding at January 1, 2013		1,422,267	1,420,034	67,991	357,882	357,882	209,882	209,882	279,999	279,999	504,276	504,276	1	1	3	3
Restricted stock issuances	8,056			8,056
Restricted stock repurchased	(873)			(873)
Restricted stock forfeitures	(4,950)			(4,950)
Shares outstanding at September 30, 2013		1,422,267	1,420,034	70,224	357,882	357,882	209,882	209,882	279,999	279,999	504,276	504,276	1	1	3	3

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Fair value measurements - Fair Value Hierachy (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis [Line Items]
Derivative assets, gross	$ 16,244		$ 46,010
Derivative liabilities, gross	(14,756)		(5,605)
Derivative assets (liabilities), net	1,488		40,405
Total derivative assets (liabilities), net	1,488		40,405
Netting adjustments
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis [Line Items]
Derivative assets, gross	(7,763)	[1]	(2,977)	[1]
Derivative liabilities, gross	7,763	[1]	2,977	[1]
Recurring Fair Value Measurements
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis [Line Items]
Derivative assets, net	8,481		43,033
Derivative liabilities, net	(6,993)		(2,628)
Total derivative assets (liabilities), net	1,488		40,405
Recurring Fair Value Measurements | Significant other observable inputs (Level 2)
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis [Line Items]
Derivative assets, gross	10,080		18,599
Derivative liabilities, gross	(5,989)		(4,425)
Derivative assets (liabilities), net	4,091		14,174
Recurring Fair Value Measurements | Significant unobservable inputs (Level 3)
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis [Line Items]
Derivative assets, gross	6,164		27,411
Derivative liabilities, gross	(8,767)		(1,180)
Derivative assets (liabilities), net	(2,603)		26,231
Recurring Fair Value Measurements | Netting adjustments
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis [Line Items]
Derivative assets, gross	(7,763)	[1]	(2,977)	[1]
Derivative liabilities, gross	7,763	[1]	2,977	[1]
Derivative assets (liabilities), net	$ 0	[1]	$ 0	[1]

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

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Nature of operations and summary of significant accounting policies Nature of operations and summary of significant accounting policies (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Accounting Policies [Abstract]
Fair Value, Concentration of Risk, Cash and Cash Equivalents	$ 36,259
Receivables [Abstract]
Joint interests	35,856		19,282
Accrued oil and natural gas sales	61,380		50,814
Derivative settlements	317		8,013
Other	546		472
Allowance for doubtful accounts	(1,636)		(1,274)
Accounts receivable, net	96,463		77,307
Inventory, Gross [Abstract]
Equipment inventory	9,688		8,047
Oil and natural gas product	3,087		3,175
Inventory valuation allowance	(706)		(712)
Inventories, net	12,069		10,510
Proceeds from Sale of Productive Assets [Abstract]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 90,530	$ 44,523

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Related party transactions (Tables)

9 Months Ended

Sep. 30, 2013

Related Party Transactions [Abstract]

Related party transactions

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 September 30,						Nine months ended September 30,
	2013			2012			2013			2012
Revenues	$	2,449		$	831		$	5,289		$	2,600
Joint interest billings	$	(453	)	$	(828	)	$	(1,764	)	$	(4,295	)

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 September 30,						Nine months ended September 30,
	2013			2012			2013			2012
Revenues	$	(1,549	)	$	(1,062	)	$	(3,248	)	$	(2,521	)
Joint interest billings	$	1,084		$	3,093		$	8,969		$	7,737

Amounts receivable from and payable to Chesapeake at September 30, 2013 and December 31, 2012 were as follows:

	September 30, 2013		December 31, 2012
Amounts receivable from Chesapeake	$	1,568	$	2,071
Amounts payable to Chesapeake	$	87	$	864

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Stock-based compensation (Performance Vested Awards Return on Investment Targets) (Details) (2010 Equity Incentive Plan, Restricted Stock, USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
Performance Vested
Stock-Based Compensation [Line Items]
Incremental compensation cost	$ 4,322
Return On Investment Target One | Performance Vested
Stock-Based Compensation [Line Items]
Return On Investment Target Percentage	175.00%
Vesting Percentage	20.00%
Return On Investment Target Two | Performance Vested
Stock-Based Compensation [Line Items]
Return On Investment Target Percentage	200.00%
Vesting Percentage	20.00%
Return On Investment Target Three | Performance Vested
Stock-Based Compensation [Line Items]
Return On Investment Target Percentage	250.00%
Vesting Percentage	20.00%
Return On Investment Target Four | Performance Vested
Stock-Based Compensation [Line Items]
Return On Investment Target Percentage	300.00%
Vesting Percentage	20.00%
Return On Investment Target Five | Market and Performance Vesting Conditions
Stock-Based Compensation [Line Items]
Return On Investment Target Percentage	400.00%
Return On Investment Target Five | Performance Vested
Stock-Based Compensation [Line Items]
Return On Investment Target Percentage	350.00%
Vesting Percentage	20.00%
Maximum | Performance Vested
Stock-Based Compensation [Line Items]
Award vesting period	5 years
Maximum | Time Vested
Stock-Based Compensation [Line Items]
Award vesting period	5 years

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Derivative instruments - Outstanding Derivatives (Details) (USD $) In Thousands, unless otherwise specified														3 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 Derivatives maturing in 2015 Natural Gas Derivative MMBTU	Sep. 30, 2013 Swaps Derivatives Maturing In 2013 Oil Derivative bbl	Sep. 30, 2013 Swaps Derivatives Maturing In 2013 Natural Gas Derivative MMBTU	Sep. 30, 2013 Swaps Derivatives Maturing In 2014 Oil Derivative bbl	Sep. 30, 2013 Swaps Derivatives Maturing In 2014 Natural Gas Derivative MMBTU	Sep. 30, 2013 Swaps Derivatives maturing in 2015 Natural Gas Derivative MMBTU	Sep. 30, 2013 Costless Collars Derivatives Maturing In 2013 Oil Derivative bbl	Sep. 30, 2013 Costless Collars Derivatives Maturing In 2014 Oil Derivative bbl	Sep. 30, 2013 Enhanced Swap Derivatives Maturing In 2014 Oil Derivative bbl	Sep. 30, 2013 Enhanced Swap Derivatives maturing in 2015 Oil Derivative bbl	Sep. 30, 2013 Put Spread Enhanced Swap Derivatives Maturing In 2014 Oil Derivative bbl	Sep. 30, 2013 Put Options Purchased Oil Derivative	Sep. 30, 2013 Put Options Purchased Derivatives Maturing In 2014 Oil Derivative bbl	Sep. 30, 2013 Basis Protection Swaps Derivatives Maturing In 2013 Natural Gas Derivative MMBTU	Sep. 30, 2013 Basis Protection Swaps Derivatives Maturing In 2014 Natural Gas Derivative MMBTU
Derivative [Line Items]
Volume of derivative instruments held			2,400,000	510,000	4,890,000	739,000	18,420,000	10,800,000	900,000	2,400,000	840,000	4,918,000	2,225,000		840,000	5,390,000	21,550,000
Weighted average fixed price per unit, swaps			0.18	95.54	4.34	92.51	4.03	4.26			98.62	93.35	93.64			0.20	0.24
Weighted average fixed price per Bbl, sold puts									77.83	75.50	80.00	80.00	80.00
Weighted average fixed price per Bbl, purchased puts									99.94	93.25			60.00		60.00
Weighted average fixed price per Bbl, sold calls									114.49	101.94
Premium paid for put options on commodity derivative contracts														$ 664
Derivative settlements	317	8,013
Derivative settlements payable	3,393	41
Cash flow hedge gains deferred through AOCI [Abstract]
Accumulated other comprehensive income, before tax	8,590	37,134
Accumulated other comprehensive income, net of taxes	$ 5,445	$ 23,223

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Fair value measurements - Nonrecurring Fair Value Measurements (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Nonrecurring Fair Value Measurements [Line Items]
Liabilities incurred in current period	$ 1,036	$ 551
Significant unobservable inputs (Level 3) | Nonrecurring fair value measurements
Nonrecurring Fair Value Measurements [Line Items]
Annual inflation rate	2.95%	2.95%
Credit-adjusted risk-free interest rate	6.90%	6.70%
Liabilities incurred in current period	$ 1,036	$ 551

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Related party transactions (Details) (USD $) In Thousands, unless otherwise specified				3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended
	Sep. 30, 2013 Chesapeake	Dec. 31, 2012 Chesapeake	Sep. 30, 2013 Chesapeake Holdings Corporation	Sep. 30, 2013 Properties Operated by Chesapeake	Sep. 30, 2012 Properties Operated by Chesapeake	Sep. 30, 2013 Properties Operated by Chesapeake	Sep. 30, 2012 Properties Operated by Chesapeake	Sep. 30, 2013 Properties Operated by Chaparral	Sep. 30, 2012 Properties Operated by Chaparral	Sep. 30, 2013 Properties Operated by Chaparral	Sep. 30, 2012 Properties Operated by Chaparral
Related Party Transaction [Line Items]
Chaparral common stock owned by Chesapeake			20.00%
Revenue from jointly owned properties				$ 2,449	$ 831	$ 5,289	$ 2,600	$ (1,549)	$ (1,062)	$ (3,248)	$ (2,521)
Joint interest billings				(453)	(828)	(1,764)	(4,295)	1,084	3,093	8,969	7,737
Amounts receivable from Chesapeake	1,568	2,071
Amounts payable to Chesapeake	$ 87	$ 864

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Supplemental disclosures to the consolidated statements of cash flows (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Net cash provided by operating activities included:
Cash payments for interest	$ 70,735	$ 71,475
Interest capitalized	(11,670)	(3,311)
Cash payments for interest, net of amounts capitalized	59,065	68,164
Cash payments for income taxes	240	100
Non-cash investing activities included:
Asset retirement costs capitalized	1,036	551
Oil and natural gas properties acquired through increase in accounts payable and accrued liabilities	$ 8,298	$ 38,184

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Fair value measurements Fair value measurements - Schedule of Derivatives Offset in the Consolidated Balance Sheet (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Fair Value Disclosures [Abstract]
Derivative assets, gross	$ 16,244	$ 46,010
Derivative assets, amounts offset	(8,459)	(4,721)
Derivative assets, net	7,785	41,289
Derivative assets, net, credit facility balance subject to right of offset	(7,239)	(9,180)
Derivative assets, net of offsetting amounts	546	32,109
Derivative liabilities, gross	(14,756)	(5,605)
Derivative liabilities, amounts offset	8,459	4,721
Derivative liabilities, net of offsetting amounts	(6,297)	(884)
Derivative assets (liabilities), net	1,488	40,405
Total derivative assets (liabilities), net	1,488	40,405
Derivative assets (liabilities), net of offsetting amounts	$ (5,751)	$ 31,225

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Common stock (Tables)

9 Months Ended

Sep. 30, 2013

Equity [Abstract]

Common stock rollforward

The following is a summary of the changes in our common shares outstanding during the nine months ended September 30, 2013:

	Common Stock
	Class A		Class B	Class C	Class D	Class E	Class F	Class G	Total
Shares outstanding at January 1, 2013	67,991		357,882	209,882	279,999	504,276	1	3	1,420,034
Restricted stock issuances	8,056		—	—	—	—	—	—	8,056
Restricted stock repurchased	(873	)	—	—	—	—	—	—	(873	)
Restricted stock forfeitures	(4,950	)	—	—	—	—	—	—	(4,950	)
Shares outstanding at September 30, 2013	70,224		357,882	209,882	279,999	504,276	1	3	1,422,267

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Consolidated statements of cash flows (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Cash flows from operating activities
Net income	$ 35,142	$ 45,299
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion & amortization	139,439	119,807
Loss on impairment of other assets	1,090	0
Deferred income taxes	19,398	25,540
Gain from oil hedging activities	(28,544)	(35,777)
Non-hedge derivative losses (gains)	26,484	(37,035)
Loss on extinguishment of debt	0	21,714
(Gain) loss on sale of assets	(556)	21
Other	1,826	2,167
Change in assets and liabilities
Accounts receivable	(20,858)	(13,140)
Inventories	(1,689)	(4,599)
Prepaid expenses and other assets	2,130	1,763
Accounts payable and accrued liabilities	17,694	13,355
Revenue distribution payable	5,181	(2,215)
Stock-based compensation	1,747	2,077
Net cash provided by operating activities	198,484	138,977
Cash flows from investing activities
Purchase of property and equipment and oil and natural gas properties	(382,167)	(379,069)
Proceeds from dispositions of property and equipment and oil and natural gas properties	91,788	45,023
Settlement of non-hedge derivative instruments	13,097	24,309
Other	(664)	23
Net cash used in investing activities	(277,946)	(309,714)
Cash flows from financing activities
Proceeds from long-term debt	133,208	156,457
Repayment of long-term debt and capital lease obligations	(51,416)	(37,608)
Proceeds from Senior Notes	0	400,000
Repayment of Senior Notes	0	(325,000)
Proceeds from capital lease obligations	5,203	0
Principal payments under capital lease obligations	(38)	(10)
Payment of debt issuance costs and other financing fees	0	(8,867)
Payment of debt extinguishment costs	0	(15,827)
Net cash provided by financing activities	86,957	169,145
Net increase (decrease) in cash and cash equivalents	7,495	(1,592)
Cash and cash equivalents at beginning of period	29,819	34,589
Cash and cash equivalents at end of period	$ 37,314	$ 32,997

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Supplemental disclosures to the consolidated statements of cash flows

9 Months Ended

Sep. 30, 2013

Supplemental Cash Flow Elements [Abstract]

Supplemental disclosures to the consolidated statements of cash flows

Supplemental disclosures to the consolidated statements of cash flows

Supplemental disclosures to the consolidated statements of cash flows are presented below:

	Nine months ended September 30,
	2013			2012
Net cash provided by operating activities included:
Cash payments for interest	$	70,735		$	71,475
Interest capitalized	(11,670		)	(3,311		)
Cash payments for interest, net of amounts capitalized	$	59,065		$	68,164
Cash payments for income taxes	$	240		$	100
Non-cash investing activities included:
Asset retirement costs capitalized	$	1,036		$	551
Oil and natural gas properties acquired through increase in accounts payable and accrued liabilities	$	8,298		$	38,184

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Fair value measurements

9 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Fair value measurements

Fair value measurements

Fair value is defined by the 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.

Fair value measurements 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 as follows:

• Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.

• Level 2 inputs include quoted prices for identical or similar instruments in markets that are not active and inputs other than quoted prices that are observable for the asset or liability. 

• 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.

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.

Recurring fair value measurements

Our financial instruments recorded at fair value on a recurring basis consist of commodity derivative contracts (see Note 4). We have no Level 1 assets or liabilities as of September 30, 2013 or December 31, 2012. Our derivative contracts classified as Level 2 as of September 30, 2013 and December 31, 2012 consist of commodity price swaps and basis protection swaps, which are valued using an income approach. 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.

As of September 30, 2013, our derivative contracts classified as Level 3 consisted of three-way collars, enhanced swaps, and purchased puts. As of December 31, 2012, our derivative contracts classified as Level 3 consisted of three-way collars. The fair value of these contracts is developed by a third-party pricing service using a proprietary valuation model, which we believe incorporates the assumptions that market participants would have made at the end of each period. Observable inputs include contractual terms, published forward pricing curves, and yield curves. Significant unobservable inputs are implied volatilities. Significant increases (decreases) in implied volatilities in isolation would result in a significantly higher (lower) fair value measurement. We review these valuations and the changes in the fair value measurements for reasonableness.

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. If available, we use our counterparties’ credit default swap values or the spread between the risk-free interest rate and the yield on our counterparties’ publicly traded debt having similar maturities to our derivative contracts as the measure of our counterparties’ nonperformance risk. As of September 30, 2013 and December 31, 2012, the rate reflecting our nonperformance risk was 1.50% and 1.50%, respectively. The weighted average rate reflecting our counterparties’ nonperformance risk was approximately 0.44% and 0.32% as of September 30, 2013 and December 31, 2012, respectively.

The fair value hierarchy for our financial assets and liabilities is shown by the following table:

	As of September 30, 2013									As of December 31, 2012
	Derivative assets			Derivative liabilities			Net assets (liabilities)			Derivative assets			Derivative liabilities			Net assets (liabilities)
Significant other observable inputs (Level 2)	$	10,080		$	(5,989	)	$	4,091		$	18,599		$	(4,425	)	$	14,174
Significant unobservable inputs (Level 3)	6,164			(8,767		)	(2,603		)	27,411			(1,180		)	26,231
Netting adjustments (1)	(7,763		)	7,763			—			(2,977		)	2,977			—
	$	8,481		$	(6,993	)	$	1,488		$	43,033		$	(2,628	)	$	40,405

(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 our derivative instruments classified as Level 3 in the fair value hierarchy during the nine months ended September 30, 2013 and 2012 were: 

	For the nine months ended September 30,
Net derivative assets (liabilities)	2013			2012
Beginning balance	$	26,231		$	5,049
Realized and unrealized (losses) gains included in non-hedge derivative (losses) gains	(18,198		)	26,191
Purchases	664			—
Settlements received	(11,300		)	(5,711		)
Ending balance	$	(2,603	)	$	25,529
(Losses) gains relating to instruments still held at the reporting date included in non-hedge derivative (losses) gains for the period	$	(8,776	)	$	21,033

Nonrecurring fair value measurements

Additions to the asset and liability associated with our asset retirement obligations are measured at fair value on a nonrecurring basis. 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 nine months of 2013 and 2012 were escalated using an annual inflation rate of 2.95% and 2.95%, respectively, and discounted using our credit-adjusted risk-free interest rate of 6.90% and 6.70%, respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. During the nine months ended September 30, 2013 and 2012, additions to our asset retirement obligations were $1,036 and $551, respectively. See Note 6 for additional information regarding our asset retirement obligations.

Fair value of other financial instruments

Our significant financial instruments, other than derivatives, consist primarily of cash and cash equivalents, accounts receivable, accounts payable, and long-term debt. We believe the carrying values of cash and cash equivalents, accounts receivable, and accounts payable approximate fair values due to the short-term maturities of these instruments.

The carrying value and estimated fair value of our long-term debt at September 30, 2013 and December 31, 2012 were as follows:

	September 30, 2013				December 31, 2012
Level 2	Carrying value		Estimated fair value		Carrying value		Estimated fair value
9.875% Senior Notes due 2020	$	294,419	$	338,625	$	294,031	$	341,250
8.25% Senior Notes due 2021	400,000		424,000		400,000		434,000
7.625% Senior Notes due 2022	555,942		566,500		556,631		574,750
Senior secured revolving credit facility	108,000		108,000		25,000		25,000
Other secured long-term debt and capital leases	21,697		21,697		17,740		17,740
	$	1,380,058	$	1,458,822	$	1,293,402	$	1,392,740

The fair value of our Senior Notes was estimated based on quoted market prices. The carrying value of our senior secured revolving credit facility approximates fair value because it has a variable interest rate and incorporates a measure of our credit risk. The carrying value of our other secured long-term debt approximates fair value because the rates are comparable to those at which we could currently borrow under similar terms.

Counterparty credit risk

Our derivative contracts are executed with institutions, or affiliates of institutions, that are parties to our senior secured revolving credit facility at the time of execution, and we believe the credit risks associated with all of these institutions are acceptable. We do not require collateral or other security from counterparties to support derivative instruments. Master agreements are in place with each of our derivative counterparties which provide for net settlement in the event of default or termination of the contracts under each respective agreement. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivatives. Our loss is further limited as any amounts due from a defaulting counterparty that is a lender, or an affiliate of a lender, under our senior secured revolving credit facility can be offset against amounts owed to such counterparty lender under our senior secured revolving credit facility. As of September 30, 2013, the counterparties to our open derivative contracts consisted of ten financial institutions, of which nine were subject to our rights of offset under our senior secured revolving credit facility.

The following table summarizes our derivative assets and liabilities which are offset in the balance sheet under our master netting agreements. It also reflects the amounts outstanding under our senior secured revolving credit facility that are available to offset our net derivative assets due from counterparties that are lenders under our senior secured revolving credit facility.

	Offset in the consolidated balance sheets									Gross amounts not offset in the consolidated balance sheets
	Gross assets (liabilities)			Offsetting assets (liabilities)			Net assets (liabilities)			Amounts outstanding under senior secured revolving credit facility			Net amount
As of September 30, 2013
Derivative assets	$	16,244		$	(8,459	)	$	7,785		$	(7,239	)	$	546
Derivative liabilities	(14,756		)	8,459			(6,297		)	—			(6,297		)
	$	1,488		$	—		$	1,488		$	(7,239	)	$	(5,751	)
As of December 31, 2012
Derivative assets	$	46,010		$	(4,721	)	$	41,289		$	(9,180	)	$	32,109
Derivative liabilities	(5,605		)	4,721			(884		)	—			(884		)
	$	40,405		$	—		$	40,405		$	(9,180	)	$	31,225

We did not post additional collateral under any of these contracts as all of our counterparties are secured by the collateral under our senior secured revolving credit facility. Payment on our derivative contracts would be accelerated in the event of a default on our senior secured revolving credit facility. The aggregate fair value of our derivative liabilities was $14,756 at September 30, 2013.

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Long-term debt

9 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Long-term debt

Long-term debt

Long-term debt at September 30, 2013 and December 31, 2012, consisted of the following:

	September 30, 2013		December 31, 2012
9.875% Senior Notes due 2020, net of discount of $5,581 and $5,969 at September 30, 2013 and December 31, 2012, respectively	$	294,419	$	294,031
8.25% Senior Notes due 2021	400,000		400,000
7.625% Senior Notes due 2022, including premium of $5,942 and $6,631 at September 30, 2013 and December 31, 2012, respectively	555,942		556,631
Senior secured revolving credit facility	108,000		25,000
Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 2.54% to 5.46%, due August 2021 through December 2028; collateralized by real property	11,322		12,596
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.94% to 6.79%, due November 2013 through February 2018; collateralized by automobiles, machinery and equipment	5,210		5,144
Capital lease obligations	5,165		—
	1,380,058		1,293,402
Less current maturities	3,322		3,746
	$	1,376,736	$	1,289,656

Senior Notes

The Senior Notes, which, as of September 30, 2013, include our 9.875% Senior Notes due 2020, our 8.25% Senior Notes due 2021, and our 7.625% Senior Notes due 2022, 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 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;

• incur liens on assets;

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

• engage in transactions with 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 indentures 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.

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 Chaparral Biofuels, LLC.

Senior secured revolving credit facility

In April 2010, we entered into an Eighth Restated Credit Agreement (our “senior secured revolving credit facility”), which is collateralized by our oil and natural gas properties and, as amended, matures on November 1, 2017. The Thirteenth Amendment, effective October 29, 2013, amended our senior secured revolving credit facility to (a) increase our borrowing base from $500,000 to $550,000, (b) automatically increase the borrowing base to $600,000 upon the consummation of the Cabot Acquisition and (c) allow for the incurrence of $300,000 of unsecured senior or subordinated debt meeting the definition of “Additional Permitted Debt” under our senior secured revolving credit facility, (d) permit entering into swap agreements on production from to-be-acquired properties, including the assets to be acquired in the Cabot Acquisition, in notional amounts up to 80% of anticipated proved developed producing production therefrom if otherwise meeting additional necessary requirements under our senior secured revolving credit facility, and (e) increase permitted other debt from $40,000 to $50,000.

Amounts borrowed under our senior secured revolving credit facility are subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base (the “utilization percentage”) and (2) whether we elect to borrow at the Eurodollar rate or the Alternate Base Rate (“ABR”). The entire balance outstanding at September 30, 2013 was subject to the Eurodollar rate. Subsequent to September 30, 2013, we have drawn down an additional $14,000 under our senior secured revolving credit facility. On November 12, 2013, we committed to borrow an additional $25,000 and will receive the funds on November 15, 2013.

The Eurodollar rate 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 that varies depending on our utilization percentage. During the nine months ended September 30, 2013, the applicable margin was 1.50%. 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 loans subject to the ABR 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 0.50%, or (3) the Adjusted LIBO Rate, as defined in our senior secured revolving credit facility, plus 1%, plus a margin that varies depending on our utilization percentage.

Commitment fees range from 0.375% to 0.50%, depending on our utilization percentage. During the nine months ended September 30, 2013, commitment fees accrued at the rate of 0.375% on the unused portion of the borrowing base amount, and were 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 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 4.5 to 1.0 for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter.

We believe we were in compliance with all covenants under our senior secured revolving credit facility as of September 30, 2013.

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.

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.

Capital Leases

During the third quarter of 2013, we entered into a lease financing agreement with U.S. Bank National Association for approximately $5,200 through the sale and subsequent leaseback of an existing compressor owned by us. The lease financing obligation is for an 84-month term and includes an option to purchase the equipment for a specified price at 72 months as well as an option to purchase the equipment at the end of the lease term for its then-current fair market value. Lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.4%. Minimum lease payments are approximately $625 annually. In October 2013, we finalized an additional lease financing agreement with U.S. Bank National Association for approximately $11,900 on the sale and subsequent leaseback of compressors.

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Fair value measurements - Carrying Value and Estimated Fair Value of Long-Term Debt (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Fair Value of Other Financial Instruments [Line Items]
Senior secured revolving credit facility	$ 108,000	$ 25,000
Total long-term debt	1,380,058	1,293,402
9.875% Senior Notes due 2020
Fair Value of Other Financial Instruments [Line Items]
Senior Notes	294,419	294,031
8.25% Senior Notes due 2021
Fair Value of Other Financial Instruments [Line Items]
Senior Notes	400,000	400,000
7.625% Senior Notes due 2022
Fair Value of Other Financial Instruments [Line Items]
Senior Notes	555,942	556,631
Significant other observable inputs (Level 2) | Carrying value
Fair Value of Other Financial Instruments [Line Items]
Senior secured revolving credit facility	108,000	25,000
Other secured long-term debt	21,697	17,740
Total long-term debt	1,380,058	1,293,402
Significant other observable inputs (Level 2) | Carrying value | 9.875% Senior Notes due 2020
Fair Value of Other Financial Instruments [Line Items]
Senior Notes	294,419	294,031
Significant other observable inputs (Level 2) | Carrying value | 8.25% Senior Notes due 2021
Fair Value of Other Financial Instruments [Line Items]
Senior Notes	400,000	400,000
Significant other observable inputs (Level 2) | Carrying value | 7.625% Senior Notes due 2022
Fair Value of Other Financial Instruments [Line Items]
Senior Notes	555,942	556,631
Significant other observable inputs (Level 2) | Estimated fair value
Fair Value of Other Financial Instruments [Line Items]
Senior secured revolving credit facility	108,000	25,000
Other secured long-term debt	21,697	17,740
Total long-term debt	1,458,822	1,392,740
Significant other observable inputs (Level 2) | Estimated fair value | 9.875% Senior Notes due 2020
Fair Value of Other Financial Instruments [Line Items]
Senior Notes	338,625	341,250
Significant other observable inputs (Level 2) | Estimated fair value | 8.25% Senior Notes due 2021
Fair Value of Other Financial Instruments [Line Items]
Senior Notes	424,000	434,000
Significant other observable inputs (Level 2) | Estimated fair value | 7.625% Senior Notes due 2022
Fair Value of Other Financial Instruments [Line Items]
Senior Notes	$ 566,500	$ 574,750

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Nature of operations and summary of significant accounting policies Nature of operations and summary of significant accounting policies (Details 2) (USD $) In Thousands, unless otherwise specified	9 Months Ended		1 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Nov. 12, 2013 Subsequent Event	Oct. 11, 2013 Subsequent Event Cabot Acquisition
Subsequent Event [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 90,530	$ 44,523	$ 12,500
Significant Acquisitions, Proposed Acquisition Costs				160,128
Significant Acquisitions, Earnest Deposit				$ 16,013

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Long-term debt (Details) (USD $) In Thousands, unless otherwise specified				9 Months Ended				9 Months Ended			9 Months Ended			9 Months Ended		9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 Senior Notes	Sep. 30, 2013 Mortgages	Sep. 30, 2013 Secured Debt	Sep. 30, 2013 9.875% Senior Notes due 2020	Dec. 31, 2012 9.875% Senior Notes due 2020	Sep. 30, 2013 9.875% Senior Notes due 2020 Senior Notes	Sep. 30, 2013 8.25% Senior Notes due 2021	Dec. 31, 2012 8.25% Senior Notes due 2021	Sep. 30, 2013 8.25% Senior Notes due 2021 Senior Notes	Sep. 30, 2013 7.625% Senior Notes due 2022	Dec. 31, 2012 7.625% Senior Notes due 2022	Sep. 30, 2013 7.625% Senior Notes due 2022 Senior Notes	Sep. 30, 2013 Eurodollar Rate	Sep. 30, 2013 Minimum Mortgages	Sep. 30, 2013 Minimum Secured Debt	Sep. 30, 2013 Maximum Mortgages	Sep. 30, 2013 Maximum Secured Debt
Debt Instrument [Line Items]
Stated interest rate, miminum				2.54%	2.94%
Stated interest rate, maximum				5.46%	6.79%
Unamortized discount						$ 5,581	$ 5,969
Debt instrument, unamortized premium												5,942	6,631
Long-term debt [Abstract]
Senior Notes						294,419	294,031		400,000	400,000		555,942	556,631
Senior secured revolving credit facility	108,000	25,000													108,000
Real estate mortgage notes payable	11,322	12,596
Installment notes payable	5,210	5,144
Capital Lease Obligations	5,165	0
Total long-term debt	1,380,058	1,293,402
Less current maturities		3,746
Long-term debt, less current maturities	$ 1,376,736	$ 1,289,656
Senior Notes [Abstract]
Stated interest rate								9.875%			8.25%			7.625%
Debt instrument, maturity date								2020			2021			2022		08/2021	11/2013	12/2028	02/2018
Debt instrument redemption price at Change of Control event as percentage of principal amount			101.00%

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Fair value measurements - Inputs (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2012
Fair Value Disclosures [Abstract]
Rate reflecting our nonperformance risk	1.50%	1.50%
Weighted-average rate reflecting our counterparties' nonperformance risk	0.44%	0.32%

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Commitments and contingencies (Details) (USD $) In Thousands, unless otherwise specified			1 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Jun. 30, 2011 Pending Litigation Minimum
Loss Contingencies [Line Items]
Letters of credit outstanding	$ 920	$ 920
Damages sought			$ 5,000

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Stock-based compensation (Details) (USD $) In Thousands, except Share data, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Stock-Based Compensation Arrangement Rollforward
Restricted stock used for tax withholding	873
Common Class A
Stock-Based Compensation Arrangement Rollforward
Restricted stock used for tax withholding	873
Phantom Shares | Phantom Stock Plan
Stock-Based Compensation [Line Items]
Maximum percentage of fair market value of the Company available for share-based awards	2.00%
Maximum individual award as a percentage of shares available for award	5.00%
Days from vesting date to cash settlement	120 days
Stock-Based Compensation Arrangement Rollforward
Unvested and outstanding at beginning of period	$ 16.87
Unvested and outstanding at beginning of period (in shares)	84,764
Granted	$ 0.00
Granted (in shares)	0
Vested	$ 16.20
Vested (in shares)	(21,260)
Vest Date Fair Value	$ 273
Forfeited	$ 17.52
Forfeited (in shares)	(9,388)
Unvested and outstanding at end of period	$ 17.03
Unvested and outstanding at end of period (in shares)	54,116
Phantom Shares | Time Vested | Phantom Stock Plan
Stock-Based Compensation [Line Items]
Award vesting period	5 years
Restricted Stock Units (RSU)
Stock-Based Compensation [Line Items]
Award vesting period	3 years
Restricted Stock Units (RSU) | Non-Officer Restricted Stock Unit Plan
Stock-Based Compensation [Line Items]
Maximum percentage of fair market value of the Company available for share-based awards	2.00%
Days from vesting date to cash settlement	120 days
Stock-Based Compensation Arrangement Rollforward
Unvested and outstanding at beginning of period	$ 17.12
Unvested and outstanding at beginning of period (in shares)	151,909
Granted	$ 12.45
Granted (in shares)	291,253
Vested	$ 17.12
Vested (in shares)	(50,246)
Vest Date Fair Value	626
Forfeited	$ 14.35
Forfeited (in shares)	(55,051)
Unvested and outstanding at end of period	$ 13.54
Unvested and outstanding at end of period (in shares)	337,865
Phantom Stock and RSU | Phantom Stock Plan And Restricted Stock Unit Plan
Stock-Based Compensation Arrangement Rollforward
Estimated fair value per share at end of period	$ 10.68
Aggregate intrinisc value of unvested Time Vested restricted shares	4,186
Restricted Stock | 2010 Equity Incentive Plan | Common Class A
Stock-Based Compensation Arrangement Rollforward
Shares reserved for issuance under the 2010 Plan	86,301
Restricted stock used for tax withholding	873	764
Shares expected to be repurchased during the next twelve months	2,000
Restricted Stock | Time Vested | 2010 Equity Incentive Plan | Common Class A
Stock-Based Compensation Arrangement Rollforward
Unvested and outstanding at beginning of period	$ 651.97
Unvested and outstanding at beginning of period (in shares)	9,481
Granted	$ 626.02
Granted (in shares)	2,839
Vested	$ 679.09
Vested (in shares)	(2,030)
Vest Date Fair Value	1,256
Forfeited	$ 620.01
Forfeited (in shares)	(1,779)
Modified	$ 626.00
Modified (in Shares)	11,169
Unvested and outstanding at end of period	$ 633.58
Unvested and outstanding at end of period (in shares)	19,680
Estimated fair value per share at end of period	$ 626.00
Aggregate intrinisc value of unvested Time Vested restricted shares	$ 12,320
Restricted Stock | Market and Performance Vesting Conditions | 2010 Equity Incentive Plan | Common Class A
Stock-Based Compensation Arrangement Rollforward
Unvested and outstanding at beginning of period	$ 324.48
Unvested and outstanding at beginning of period (in shares)	55,824
Granted	$ 181.59
Granted (in shares)	5,217
Vested	$ 0.00
Vested (in shares)	0
Forfeited	$ 340.23
Forfeited (in shares)	(3,171)
Modified	$ 324.47
Modified (in Shares)	(11,169)
Unvested and outstanding at end of period	$ 307.45
Unvested and outstanding at end of period (in shares)	46,701
Maximum | Restricted Stock Units (RSU)
Stock-Based Compensation [Line Items]
Award vesting period	3 years
Maximum | Restricted Stock | Time Vested | 2010 Equity Incentive Plan
Stock-Based Compensation [Line Items]
Award vesting period	5 years
Maximum | Restricted Stock | Performance Vested | 2010 Equity Incentive Plan
Stock-Based Compensation [Line Items]
Award vesting period	5 years

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Consolidated balance sheets (Parenthetical) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Preferred stock, shares authorized	600,000	600,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common Class A
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	10,000,000	10,000,000
Common stock, shares issued	70,224	67,991
Common stock, shares outstanding	70,224	67,991
Common Class B
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	10,000,000	10,000,000
Common stock, shares issued	357,882	357,882
Common stock, shares outstanding	357,882	357,882
Common Class C
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	10,000,000	10,000,000
Common stock, shares issued	209,882	209,882
Common stock, shares outstanding	209,882	209,882
Common Class D
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	10,000,000	10,000,000
Common stock, shares issued	279,999	279,999
Common stock, shares outstanding	279,999	279,999
Common Class E
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	10,000,000	10,000,000
Common stock, shares issued	504,276	504,276
Common stock, shares outstanding	504,276	504,276
Common Class F
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	1	1
Common stock, shares issued	1	1
Common stock, shares outstanding	1	1
Common Class G
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	3	3
Common stock, shares issued	3	3
Common stock, shares outstanding	3	3

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Common stock

9 Months Ended

Sep. 30, 2013

Equity [Abstract]

Common stock

Common stock

The following is a summary of the changes in our common shares outstanding during the nine months ended September 30, 2013:

	Common Stock
	Class A		Class B	Class C	Class D	Class E	Class F	Class G	Total
Shares outstanding at January 1, 2013	67,991		357,882	209,882	279,999	504,276	1	3	1,420,034
Restricted stock issuances	8,056		—	—	—	—	—	—	8,056
Restricted stock repurchased	(873	)	—	—	—	—	—	—	(873	)
Restricted stock forfeitures	(4,950	)	—	—	—	—	—	—	(4,950	)
Shares outstanding at September 30, 2013	70,224		357,882	209,882	279,999	504,276	1	3	1,422,267

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Consolidated statements of comprehensive (loss) income (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Comprehensive income
Net (loss) income	$ (2,568)	$ (4,946)	$ 35,142	$ 45,299
Other comprehensive loss
Reclassification adjustment for hedge gains included in gain from oil hedging activities in the consolidated statements of operations	(9,032)	(11,468)	(28,544)	(35,777)
Income tax benefit related to other comprehensive loss	3,306	4,129	10,766	14,717
Other comprehensive loss, net of tax	(5,726)	(7,339)	(17,778)	(21,060)
Comprehensive (loss) income	$ (8,294)	$ (12,285)	$ 17,364	$ 24,239

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Consolidated balance sheets (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Assets
Cash and cash equivalents	$ 37,314	$ 29,819
Accounts receivable, net	96,463	77,307
Inventories, net	12,069	10,510
Prepaid expenses	2,714	3,465
Derivative instruments	4,449	42,516
Deferred income taxes	989	0
Total current assets	153,998	163,617
Property and equipment—at cost, net	67,302	65,601
Oil and natural gas properties, using the full cost method:
Proved	3,062,399	2,860,611
Unevaluated (excluded from the amortization base)	250,026	162,921
Accumulated depreciation, depletion, amortization and impairment	(1,420,348)	(1,290,356)
Total oil and natural gas properties	1,892,077	1,733,176
Derivative instruments	4,032	517
Assets held for sale	4,599	5,689
Other assets	35,940	38,952
Total assets	2,157,948	2,007,552
Liabilities and stockholders' equity
Accounts payable and accrued liabilities	116,225	101,598
Accrued payroll and benefits payable	22,293	19,655
Accrued interest payable	33,390	24,131
Revenue distribution payable	23,333	18,152
Current maturities of long-term debt	3,322	3,746
Derivative instruments	6,971	436
Deferred income taxes	0	26,872
Total current liabilities	205,534	194,590
Long-term debt, less current maturities	1,376,736	1,289,656
Derivative instruments	22	2,192
Stock-based compensation	3,133	3,042
Asset retirement obligations, net of current portion	45,349	46,314
Deferred income taxes	45,394	8,901
Commitments and contingencies (Note 10)
Stockholders' equity:
Preferred stock, 600,000 shares authorized, none issued and outstanding	0	0
Additional paid in capital	423,993	422,434
Retained earnings	52,328	17,186
Accumulated other comprehensive income, net of taxes	5,445	23,223
Total stockholders' equity	481,780	462,857
Total liabilities and stockholders' equity	2,157,948	2,007,552
Common Class A
Stockholders' equity:
Common stock	0	0
Common Class B
Stockholders' equity:
Common stock	4	4
Common Class C
Stockholders' equity:
Common stock	2	2
Common Class D
Stockholders' equity:
Common stock	3	3
Common Class E
Stockholders' equity:
Common stock	5	5
Common Class F
Stockholders' equity:
Common stock	0	0
Common Class G
Stockholders' equity:
Common stock	$ 0	$ 0

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Nature of operations and summary of significant accounting policies Nature of operations and summary of significant accounting policies (Details 3) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Sep. 30, 2013	Dec. 31, 2012
Oil and Gas Property [Abstract]
Acquisition Costs, Cumulative	$ 95,358	$ 64,840
Development Costs, Cumulative	119,181	84,183
Exploration Costs, Cumulative	35,487	13,898
Impairment of Assets Held for Sale	$ 1,090

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Asset retirement obligations (Tables)

9 Months Ended

Sep. 30, 2013

Asset Retirement Obligation Disclosure [Abstract]

Asset retirement obligations

The following table provides a summary of our asset retirement obligation activity during the nine months ended September 30, 2013 and 2012.

	For the nine months ended September 30,
	2013			2012
Beginning balance	$	49,214		$	46,492
Liabilities incurred in current period	1,036			551
Liabilities settled and disposed in current period	(4,969		)	(1,484		)
Accretion expense	2,968			2,962
	48,249			48,521
Less current portion	2,900			2,900
	$	45,349		$	45,621

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Asset retirement obligations (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 49,214	$ 46,492
Liabilities incurred in current period	1,036	551
Liabilities settled in current period	(4,969)	(1,484)
Accretion expense	2,968	2,962
Ending balance	48,249	48,521
Less current portion	2,900	2,900
Asset retirement obligations, net of current portion	$ 45,349	$ 45,621	$ 46,314

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Fair value measurements - Level 3 Rollforward (Details) (Significant unobservable inputs (Level 3), Derivative, USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Significant unobservable inputs (Level 3) | Derivative
Level 3 Rollforward
Level 3 net derivative assets at beginning of period	$ 26,231	$ 5,049
Realized and unrealized (losses) gains included in non-hedge derivative (losses) gains	(18,198)	26,191
Purchases	664	0
Settlements received	(11,300)	(5,711)
Level 3 net derivative assets at end of period	(2,603)	25,529
(Losses) gains relating to instruments still held at the reporting date included in non-hedge derivative (losses) gains for the period	$ (8,776)	$ 21,033

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Derivative instruments - Estimated Fair Value of Derivative Instruments (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Derivative assets, gross	$ 16,244		$ 46,010
Current derivative assets, net	4,449		42,516
Long-term derivative assets, net	4,032		517
Derivative liabilities, gross	(14,756)		(5,605)
Current derivative liabilities, net	(6,971)		(436)
Long-term derivative liabilities, net	(22)		(2,192)
Derivative assets (liabilities), net	1,488		40,405
Current derivative assets (liabilities), net	(2,522)		42,080
Long-term derivative assets (liabilities), net	4,010		(1,675)
Oil Derivative | Swaps
Derivatives, Fair Value [Line Items]
Derivative assets, gross	122		4,957
Derivative liabilities, gross	(5,363)		(1,339)
Derivative assets (liabilities), net	(5,241)		3,618
Oil Derivative | Enhanced Swap
Derivatives, Fair Value [Line Items]
Derivative assets, gross	2,005
Derivative liabilities, gross	(8,229)
Derivative assets (liabilities), net	(6,224)
Oil Derivative | Put Options Purchased
Derivatives, Fair Value [Line Items]
Derivative assets, gross	185	[1]
Derivative liabilities, gross	0	[1]
Derivative assets (liabilities), net	185	[1]
Oil Derivative | Costless Collars
Derivatives, Fair Value [Line Items]
Derivative assets, gross	3,974		27,411
Derivative liabilities, gross	(538)		(1,180)
Derivative assets (liabilities), net	3,436		26,231
Natural Gas Derivative | Swaps
Derivatives, Fair Value [Line Items]
Derivative assets, gross	9,180		13,642
Derivative liabilities, gross	(281)		(1,487)
Derivative assets (liabilities), net	8,899		12,155
Natural Gas Derivative | Basis Protection Swaps
Derivatives, Fair Value [Line Items]
Derivative assets, gross	778		0
Derivative liabilities, gross	(345)		(1,599)
Derivative assets (liabilities), net	433		(1,599)
Netting adjustments
Derivatives, Fair Value [Line Items]
Derivative assets, gross	(7,763)	[2]	(2,977)	[2]
Derivative liabilities, gross	$ 7,763	[2]	$ 2,977	[2]

[1] Includes premiums of $664 paid during the second quarter of 2013.

[2] Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty.

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Derivative instruments - Non-Hedge Derivative Gains (Losses) in the Consolidated Statements of Operations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Non-Hedge Derivative Gains (Losses) [Line Items]
Receipts from (payments on) settlement of non-hedge derivative instruments			$ (13,097)	$ (24,309)
Non-hedge derivative (losses) gains	(43,830)	(25,030)	(26,484)	37,035
Swaps
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	(7,795)	(22,167)	(12,115)	(7,451)
Receipts from (payments on) settlement of non-hedge derivative instruments	(2,510)	8,046	2,327	20,022
Costless Collars
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	(16,057)	(14,094)	(22,795)	20,480
Receipts from (payments on) settlement of non-hedge derivative instruments	(256)	3,079	11,300	5,711
Enhanced Swaps and Put Options
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	(17,499)	0	(6,703)	0
Basis Protection Swaps
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	342	526	2,032	(303)
Receipts from (payments on) settlement of non-hedge derivative instruments	$ (55)	$ (420)	$ (530)	$ (1,424)

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Stock-based compensation

9 Months Ended

Sep. 30, 2013

Share-based Compensation [Abstract]

Stock-based compensation

Stock-based compensation

Phantom Stock Plan and Restricted Stock Unit 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 “Phantom 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. Phantom shares are cash-settled within 120 days of the vesting date.

Effective March 1, 2012, we implemented a Non-Officer Restricted Stock Unit Plan (the “RSU Plan”) to create incentives to motivate Participants to put forth maximum effort toward the success and growth of the Company and to enable us to attract and retain experienced individuals who by their position, ability and diligence are able to make important contributions to the Company’s success. The RSU Plan is intended to replace the Phantom Plan. Although the Phantom Plan remains in effect, we do not expect to make any further awards under the Phantom Plan.

Restricted stock units may be awarded to Participants in total up to 2% of the fair market value of the Company. Under the RSU Plan, awards generally vest in equal annual increments over a three-year period. RSU awards may also vest following a Participant’s termination of employment in combination with the occurrence of a change of control event, as specified in the RSU Plan. RSU awards are cash-settled, generally within 120 days of the vesting date.

A summary of our phantom stock and RSU activity during the nine months ended September 30, 2013 is presented in the following table:

	Phantom Plan						RSU Plan
	Weighted average grant date fair value		Phantom shares		Vest date fair value		Weighted average grant date fair value		Restricted Stock Units		Vest date fair value
	($ per share)						($ per share)
Unvested and outstanding at January 1, 2013	$	16.87	84,764				$	17.12	151,909
Granted	$	—	—				$	12.45	291,253
Vested	$	16.20	(21,260	)	$	273	$	17.12	(50,246	)	$	626
Forfeited	$	17.52	(9,388	)			$	14.35	(55,051	)
Unvested and outstanding at September 30, 2013	$	17.03	54,116				$	13.54	337,865

Based on an estimated fair value of $10.68 per phantom share and RSU as of September 30, 2013, the aggregate intrinsic value of the unvested phantom shares and RSUs outstanding was $4,186.

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 Vested” awards) and shares that are subject to market and performance vesting conditions (the “Performance Vested” awards). The Time Vested 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 Vested awards vest in the event of a Transaction that achieves certain market targets as defined in the 2010 Plan. Any shares of Performance Vested awards not vested on a Separation Date (as defined in the 2010 Plan) will be forfeited as of the Separation Date.

Effective January 1, 2013, we amended and restated all outstanding Performance Vested awards to reflect that: (i) those shares which would vest if CCMP receives net proceeds from a Transaction that yields a return of at least 400% per share were removed from the initial Performance Vested awards and an equal number of Time Vested shares were granted effective as of January 1, 2013; and (ii) the return on investment targets applicable to the remaining number of Performance Vested shares and to any new grants of Performance Vested shares were set at the following levels:

Return on Investment Target	Target Shares Vested
175% per share	20% of shares multiplied by the Vesting Fraction
200% per share	20% of shares multiplied by the Vesting Fraction
250% per share	20% of shares multiplied by the Vesting Fraction
300% per share	20% of shares multiplied by the Vesting Fraction
350% per share	20% of shares multiplied by the Vesting Fraction

This modification changed the classification of the canceled and reissued awards from equity to liability instruments and resulted in estimated incremental compensation cost of $4,322, which will be recognized over the five-year requisite service period using the accelerated method. Incremental compensation cost is measured as the excess of the fair value of the modified award over the fair value of the original award immediately before the modification, and will be adjusted for changes in the fair value of the modified awards in each period until the awards are vested or forfeited.

A summary of our restricted stock activity during the nine months ended September 30, 2013 is presented below: 

	Time Vested						Performance Vested
	Weighted average grant date fair value		Restricted shares		Vest date fair value		Weighted average grant date fair value		Restricted shares
	($ per share)						($ per share)
Unvested and outstanding at January 1, 2013	$	651.97	9,481				$	324.48	55,824
Granted	$	626.02	2,839				$	181.59	5,217
Vested	$	679.09	(2,030	)	$	1,256	$	—	—
Forfeited	$	620.01	(1,779	)			$	340.23	(3,171	)
Modified	$	626.00	11,169				$	324.47	(11,169	)
Unvested and total outstanding at September 30, 2013	$	633.58	19,680				$	307.45	46,701

During the nine months ended September 30, 2013 and 2012, respectively, we repurchased and canceled 873 and 764 vested shares, primarily for tax withholding, and we expect to repurchase approximately 2,000 restricted shares vesting during the next twelve months. Based on an estimated fair value of $626.00 per Time Vested restricted share, the aggregate intrinsic value of the unvested Time Vested restricted shares outstanding was $12,320 as of September 30, 2013.

Stock-based compensation cost

Compensation cost is calculated net of forfeitures, which are estimated based on our historical and expected turnover rates. 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.

A portion of stock-based compensation cost associated with 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. We recognized stock-based compensation expense as follows for the periods indicated:

	Three months ended						Nine months ended
	September 30,						September 30,
	2013			2012			2013			2012
Stock-based compensation cost	$	2,045		$	1,725		$	4,620		$	4,773
Less: stock-based compensation cost capitalized	(505		)	(605		)	(1,440		)	(1,715		)
Stock-based compensation expense	$	1,540		$	1,120		$	3,180		$	3,058

Payments for stock-based compensation were $135 and $120 during the third quarters of 2013 and 2012, respectively, and were $1,433 and $981 during the nine months ended September 30, 2013 and 2012, respectively. As of September 30, 2013 and December 31, 2012, accrued payroll and benefits payable included $4,173 and $2,636, respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized compensation cost of approximately $17,383 is expected to be recognized over a weighted average period of 3.10 years.

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Nature of operations and summary of significant accounting policies (Details 4)	12 Months Ended
	Sep. 30, 2013
Oil
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Price before field differentials used in determining future net revenues	95.04
Natural Gas
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Price before field differentials used in determining future net revenues	3.60

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Fair value measurements - Counterparty Credit Risk (Details) (Concentration of Counterparty Credit Risk)	Sep. 30, 2013 financial_institutions
Concentration of Counterparty Credit Risk
Concentration Risk [Line Items]
Derivative contracts, number of counterparties	10
Derivative contracts, number of counterparties subject to offset under credit facility	9

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Commitments and contingencies

9 Months Ended

Sep. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and contingencies

Commitments and contingencies

Standby letters of credit (“Letters”) available under our senior secured revolving credit facility 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 September 30, 2013 and December 31, 2012. Interest on each Letter accrues at the lender’s prime rate plus applicable margin 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 nine months ended September 30, 2013 or 2012.

Naylor Farms, Inc., individually and as class representative on behalf of all similarly situated persons 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 natural 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 liability on the claims and raised arguments and defenses that, if accepted by the Court, will result in no loss to us. The case was stayed on August 9, 2012 to allow the U.S. Court of Appeals for the Tenth Circuit to decide two unrelated cases that had issues similar to this case. The Tenth Circuit issued its opinions in those unrelated cases on July 9, 2013 and mandates were issued July 31, 2013. On or about October 1, 2013, the Court lifted the stay and entered a new scheduling order. The parties are conducting additional discovery and Plaintiff’s Motion for Class Certification is due August 10, 2014. Because a class has not been certified, we are not yet able to estimate a possible loss, or range of possible loss, if any.

Amanda Dodson, individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C.

On May 10, 2013, Amanda Dodson (the “Plaintiff”), filed a complaint against us, alleging claims on behalf of herself and all non-governmental Oklahoma citizens who are royalty interest owners in oil and natural gas wells we operate in Oklahoma. The Petition was not served until July 2, 2013. The Plaintiff asserts class claims seeking recovery for underpayment of royalties, alleging entitlement to actual damages in an unspecified amount. The Plaintiff also requests allowable interest, punitive damages, injunctive relief, an accounting, disgorgement damages, and an award of attorney fees and costs. We have denied liability on the claims and raised arguments and defenses that, if accepted by the Court, will result in no loss to us. At this time, a class has not been certified and discovery has yet to begin. As such, we are not yet able to estimate a possible loss, or range of possible loss, if any.

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.

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Asset retirement obligations

9 Months Ended

Sep. 30, 2013

Asset Retirement Obligation Disclosure [Abstract]

Asset retirement obligations

Asset retirement obligations

The following table provides a summary of our asset retirement obligation activity during the nine months ended September 30, 2013 and 2012.

	For the nine months ended September 30,
	2013			2012
Beginning balance	$	49,214		$	46,492
Liabilities incurred in current period	1,036			551
Liabilities settled and disposed in current period	(4,969		)	(1,484		)
Accretion expense	2,968			2,962
	48,249			48,521
Less current portion	2,900			2,900
	$	45,349		$	45,621

See Note 5 for additional information regarding fair value measurements.

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Nature of operations and summary of significant accounting policies

9 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Nature of operations and summary of significant accounting policies

Nature of operations and summary of significant accounting policies

Nature of operations

Chaparral Energy, Inc. and its subsidiaries, (collectively, “we”, “our”, “us”, or the “Company”) are 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, and Kansas.

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, 2012.

The financial information as of September 30, 2013, and for the three and nine months ended September 30, 2013 and 2012, 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 nine months ended September 30, 2013 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2013.

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 September 30, 2013, cash with a recorded balance totaling $36,259 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. 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. Accounts receivable consisted of the following at September 30, 2013 and December 31, 2012:

	September 30, 2013			December 31, 2012
Joint interests	$	35,856		$	19,282
Accrued oil and natural gas sales	61,380			50,814
Derivative settlements	317			8,013
Other	546			472
Allowance for doubtful accounts	(1,636		)	(1,274		)
	$	96,463		$	77,307

Inventories

Inventories are comprised of equipment used in developing oil and natural gas properties and oil and natural gas production inventories. Equipment inventory is 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 September 30, 2013 and December 31, 2012 consisted of the following:

	September 30, 2013			December 31, 2012
Equipment inventory	$	9,688		$	8,047
Oil and natural gas product	3,087			3,175
Inventory valuation allowance	(706		)	(712		)
	$	12,069		$	10,510

Oil and natural gas properties

We use the full cost method of accounting for oil and natural gas properties and activities. Accordingly, we capitalize all costs incurred in connection with the exploration for and development of oil and natural gas reserves. Proceeds from the disposition of oil and natural gas properties are accounted for as a reduction in capitalized costs, with no gain or loss generally recognized unless such dispositions involve a significant alteration in the depletion rate. We sold certain oil and gas properties for total cash proceeds of approximately $90,530 and $44,523 subject to post-closing adjustments for the nine months ended September 30, 2013 and 2012, respectively, which did not have a significant impact on our depletion rate. After September 30, 2013, we also sold certain additional oil and gas properties for a total price of approximately $12,500 subject to post-closing adjustments.

On October 11, 2013, we entered into an agreement with Cabot Oil & Gas Corporation to acquire certain oil and gas properties and related assets in the Panhandle Marmaton Play for $160,128 subject to pre- and post-closing adjustments (the “Cabot Acquisition”). We paid $16,013 in earnest money for the Cabot Acquisition with the balance due upon closing, which is expected to occur in the fourth quarter of 2013.

We capitalize internal costs that can be directly identified with exploration and development activities, but do not include any costs related to production, general corporate overhead or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and natural gas wells, including salaries, benefits and other internal costs directly attributable to these activities.

The costs of unevaluated oil and natural gas properties are excluded from amortization until the properties are evaluated. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Work-in-progress costs are included in unevaluated oil and natural gas properties and as of September 30, 2013, include $95,358 of capital costs incurred for undeveloped acreage, $119,181 for the construction of CO₂ delivery pipelines and facilities for which there are no reserves, and $35,487 for wells and facilities in progress pending determination. As of December 31, 2012, work-in-progress costs included capital costs incurred for undeveloped acreage of $64,840 and $84,183 for the construction of CO₂ delivery pipelines and facilities for which there are no reserves and $13,898 for wells and facilities in progress pending determination.

In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related PV-10 value, net of tax considerations, plus the cost of unproved properties not being amortized. The PV-10 value of our reserves as of September 30, 2013 was estimated based on average first day of the month prices of $95.04 per Bbl of oil and $3.60 per Mcf of natural gas for the twelve months ended September 30, 2013. The cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties as of September 30, 2013, and no impairment was necessary. A decline in oil and natural gas prices subsequent to September 30, 2013 could result in ceiling test write-downs in future periods. The amount of any future impairment is difficult to predict, and will depend on the average oil and natural gas prices during each period, the incremental proved reserves added during each period, and additional capital spent.

Assets Held for Sale

In the third quarter of 2013, we reassessed the fair value of certain owned drilling rigs classified as assets held for sale. The accounting for these assets is in accordance with ASC 360-10, Property, Plant and Equipment, which requires assets to be carried on the balance sheet at their carrying value or fair value less cost to sell, whichever is less. In determining current fair value, management performed internal estimates of the value of these assets based on prices that would be received on the sale of each rig in an orderly transaction between market participants. As a result of determining current fair value on certain of the assets held for sale, an impairment loss was recorded in the third quarter of 2013 in the amount of $1,090, which was included in the loss on impairment of other assets in the consolidated statements of operations.

Stock-based compensation

Our stock-based compensation programs consist of phantom stock, restricted stock units (“RSU”), and restricted stock awards issued to employees. Generally, we use new shares to grant restricted stock awards, and we cancel restricted shares forfeited or repurchased for tax withholding. Canceled shares are available to be issued as new grants under our 2010 Equity Incentive Plan.

The estimated fair value of the phantom stock and RSU 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 and the Non-Officer Restricted Stock Unit 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 and RSU awards is recognized over the vesting period using the straight-line method and the accelerated method, respectively.

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.

Recently adopted accounting pronouncements

In December 2011, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance that requires enhanced disclosures that will enable financial statement users to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. In January 2013, additional guidance was issued which narrows the scope of the disclosure requirements to derivatives, securities borrowings, and securities lending transactions that are either offset or subject to a master netting arrangement. This guidance, which was effective and adopted by us in the first quarter of 2013, resulted in additional disclosures but had no financial impact.

In February 2013, the FASB issued authoritative guidance that requires disclosures of the amounts reclassified out of accumulated other comprehensive income (“AOCI”) by component, including the respective line items of net income if the amount is required to be reclassified to net income in its entirety in the same reporting period. This additional guidance was effective and adopted by us in the first quarter of 2013. As our entire balance in AOCI consists of deferred hedge gains, implementation of the guidance had no significant impact on our financial statement presentation and disclosures.

Recently issued accounting pronouncements

In July 2011, the FASB issued authoritative guidance regarding how health insurers should recognize and classify in their income statements the fees mandated by the Health Care and Education Reconciliation Act (“HCERA”). The HCERA imposes an annual fee upon health insurers for each calendar year beginning on or after January 1, 2014. The annual fee will be allocated to individual entities providing health insurance to employees based on a ratio, as provided for in the HCERA, and is not tax deductible. This guidance specifies that once the entity has provided qualifying health insurance in the calendar year in which the fee is payable, the liability for the entity’s fee should be estimated and recorded in full with a corresponding deferred cost that is amortized to expense on a straight line basis, unless another method better allocates the fee over the calendar year that it is payable. This guidance is effective for calendar years beginning after December 15, 2013, once the fee is instituted. We are currently assessing the impact that this fee and the adoption of the related authoritative guidance will have on our financial statements.

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Stock-based compensation cost (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Stock-Based Compensation Expense [Abstract]
Stock-based compensation cost	$ 2,045	$ 1,725	$ 4,620	$ 4,773
Less: stock-based compensation cost capitalized	(505)	(605)	(1,440)	(1,715)
Stock-based compensation expense	1,540	1,120	3,180	3,058
Payments for stock-based compensation	135	120	1,433	981
Stock-based compensation costs included in accrued payroll and benefits payable	4,173		4,173		2,636
Unrecognized compensation cost	$ 17,383		$ 17,383
Years over which unrecognized compensation cost is expected to be recognized			3 years 1 month 6 days

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Long-term debt - Senior Secured Revolving Credit Facility (Details) (USD $)					9 Months Ended			9 Months Ended									0 Months Ended	1 Months Ended		3 Months Ended		3 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Oct. 29, 2013 Maximum Subsequent Event	Sep. 30, 2013 Eurodollar Rate	Sep. 30, 2013 Line of Credit	Oct. 29, 2013 Line of Credit Subsequent Event	Oct. 29, 2013 Line of Credit Subsequent Event Cabot Acquisition	Sep. 30, 2013 Line of Credit Election One	Sep. 30, 2013 Line of Credit Election Two	Sep. 30, 2013 Line of Credit Election Three	Sep. 30, 2013 Line of Credit Minimum	Sep. 30, 2013 Line of Credit Maximum	Sep. 30, 2013 Line of Credit Eurodollar Rate	Sep. 30, 2013 Line of Credit Prime Rate	Sep. 30, 2013 Line of Credit Federal Funds Effective Rate	Sep. 30, 2013 Line of Credit Adjusted LIBO Rate	Nov. 12, 2013 Revolving Credit Facility Subsequent Event	Nov. 12, 2013 Revolving Credit Facility Subsequent Event	Oct. 29, 2013 Unsecured Senior or Subordinated Debt Subsequent Event	Sep. 30, 2013 Capital Lease Obligations U.S. Bank National Association Sale Leaseback, Compressor	Oct. 31, 2013 Capital Lease Obligations Subsequent Event U.S. Bank National Association Sale Leaseback, Compressor	Sep. 30, 2013 Capital Lease Obligations Minimum U.S. Bank National Association Sale Leaseback, Compressor
Line of Credit Facility [Line Items]
Debt instrument, maturity date					Nov. 01, 2017
Borrowing base amount					$ 500,000,000	$ 550,000,000	$ 600,000,000
Debt Instrument, Unused Borrowing Capacity, Amount																			300,000,000
Derivative, Nonmonetary Notional Amount, Percent of Required Need, Coverage			80.00%
Other Long-term Debt					40,000,000	50,000,000
Proceeds from Lines of Credit																		14,000,000
Proceeds from Lines of Credit, Commitments For Additional Borrowings																	25,000,000
Senior secured revolving credit facility	108,000,000	25,000,000		108,000,000
One month interest period													1 month
Two month interest period													2 months
Three month interest period													3 months
Six month interest period													6 months
Basis spread on variable rate													1.50%		0.50%	1.00%
Description of variable rate basis														the Prime Rate	the Federal Funds Effective Rate	the Adjusted LIBO Rate
Commitment fee on unused portion of the borrowing base					0.375%						0.375%	0.50%
Current Ratio covenant					1
Ratio Of Consolidated Net Debt To Consolidated EBITDAX covenant					4.50
Days to elect method to eliminate borrowings in excess of borrowing base					10 days
Days to eliminate borrowings in excess of borrowing base								30 days	30 days	30 days
Months over which borrowings in excess of borrowing base may be repaid in equal monthly installments								6 months
Capital Leases
Sale Leaseback Transaction Arrangement																				5,200,000	11,900,000
Sale Leaseback Transaction, Lease Term																				84 months
Sale Leaseback Transaction, Lease, Option Purchase Period																				72 months
Sale Leaseback Transaction, Imputed Interest Rate																				3.40%
Sale Leaseback Transaction, Annual Rental Payments																						$ 625,000

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Supplemental disclosures to the consolidated statements of cash flows (Tables)

9 Months Ended

Sep. 30, 2013

Supplemental Cash Flow Elements [Abstract]

Supplemental disclosures to the consolidated statements of cash flows

Supplemental disclosures to the consolidated statements of cash flows are presented below:

	Nine months ended September 30,
	2013			2012
Net cash provided by operating activities included:
Cash payments for interest	$	70,735		$	71,475
Interest capitalized	(11,670		)	(3,311		)
Cash payments for interest, net of amounts capitalized	$	59,065		$	68,164
Cash payments for income taxes	$	240		$	100
Non-cash investing activities included:
Asset retirement costs capitalized	$	1,036		$	551
Oil and natural gas properties acquired through increase in accounts payable and accrued liabilities	$	8,298		$	38,184

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Related party transactions

9 Months Ended

Sep. 30, 2013

Related Party Transactions [Abstract]

Related party transactions

Related party transactions

CHK Energy Holdings, Inc., 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 September 30,						Nine months ended September 30,
	2013			2012			2013			2012
Revenues	$	2,449		$	831		$	5,289		$	2,600
Joint interest billings	$	(453	)	$	(828	)	$	(1,764	)	$	(4,295	)

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 September 30,						Nine months ended September 30,
	2013			2012			2013			2012
Revenues	$	(1,549	)	$	(1,062	)	$	(3,248	)	$	(2,521	)
Joint interest billings	$	1,084		$	3,093		$	8,969		$	7,737

Amounts receivable from and payable to Chesapeake at September 30, 2013 and December 31, 2012 were as follows:

	September 30, 2013		December 31, 2012
Amounts receivable from Chesapeake	$	1,568	$	2,071
Amounts payable to Chesapeake	$	87	$	864

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Fair value measurements (Tables)

9 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Fair value hierarchy for financial instruments measured at fair value on a recurring basis

The fair value hierarchy for our financial assets and liabilities is shown by the following table:

	As of September 30, 2013									As of December 31, 2012
	Derivative assets			Derivative liabilities			Net assets (liabilities)			Derivative assets			Derivative liabilities			Net assets (liabilities)
Significant other observable inputs (Level 2)	$	10,080		$	(5,989	)	$	4,091		$	18,599		$	(4,425	)	$	14,174
Significant unobservable inputs (Level 3)	6,164			(8,767		)	(2,603		)	27,411			(1,180		)	26,231
Netting adjustments (1)	(7,763		)	7,763			—			(2,977		)	2,977			—
	$	8,481		$	(6,993	)	$	1,488		$	43,033		$	(2,628	)	$	40,405

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

Level 3 rollforward

Changes in the fair value of our derivative instruments classified as Level 3 in the fair value hierarchy during the nine months ended September 30, 2013 and 2012 were: 

	For the nine months ended September 30,
Net derivative assets (liabilities)	2013			2012
Beginning balance	$	26,231		$	5,049
Realized and unrealized (losses) gains included in non-hedge derivative (losses) gains	(18,198		)	26,191
Purchases	664			—
Settlements received	(11,300		)	(5,711		)
Ending balance	$	(2,603	)	$	25,529
(Losses) gains relating to instruments still held at the reporting date included in non-hedge derivative (losses) gains for the period	$	(8,776	)	$	21,033

Fair value of other financial instruments

The carrying value and estimated fair value of our long-term debt at September 30, 2013 and December 31, 2012 were as follows:

	September 30, 2013				December 31, 2012
Level 2	Carrying value		Estimated fair value		Carrying value		Estimated fair value
9.875% Senior Notes due 2020	$	294,419	$	338,625	$	294,031	$	341,250
8.25% Senior Notes due 2021	400,000		424,000		400,000		434,000
7.625% Senior Notes due 2022	555,942		566,500		556,631		574,750
Senior secured revolving credit facility	108,000		108,000		25,000		25,000
Other secured long-term debt and capital leases	21,697		21,697		17,740		17,740
	$	1,380,058	$	1,458,822	$	1,293,402	$	1,392,740

Offsetting Assets and Liabilities

The following table summarizes our derivative assets and liabilities which are offset in the balance sheet under our master netting agreements. It also reflects the amounts outstanding under our senior secured revolving credit facility that are available to offset our net derivative assets due from counterparties that are lenders under our senior secured revolving credit facility.

	Offset in the consolidated balance sheets									Gross amounts not offset in the consolidated balance sheets
	Gross assets (liabilities)			Offsetting assets (liabilities)			Net assets (liabilities)			Amounts outstanding under senior secured revolving credit facility			Net amount
As of September 30, 2013
Derivative assets	$	16,244		$	(8,459	)	$	7,785		$	(7,239	)	$	546
Derivative liabilities	(14,756		)	8,459			(6,297		)	—			(6,297		)
	$	1,488		$	—		$	1,488		$	(7,239	)	$	(5,751	)
As of December 31, 2012
Derivative assets	$	46,010		$	(4,721	)	$	41,289		$	(9,180	)	$	32,109
Derivative liabilities	(5,605		)	4,721			(884		)	—			(884		)
	$	40,405		$	—		$	40,405		$	(9,180	)	$	31,225

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Long-term debt (Tables)

9 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Components of long-term debt

Long-term debt at September 30, 2013 and December 31, 2012, consisted of the following:

	September 30, 2013		December 31, 2012
9.875% Senior Notes due 2020, net of discount of $5,581 and $5,969 at September 30, 2013 and December 31, 2012, respectively	$	294,419	$	294,031
8.25% Senior Notes due 2021	400,000		400,000
7.625% Senior Notes due 2022, including premium of $5,942 and $6,631 at September 30, 2013 and December 31, 2012, respectively	555,942		556,631
Senior secured revolving credit facility	108,000		25,000
Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 2.54% to 5.46%, due August 2021 through December 2028; collateralized by real property	11,322		12,596
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.94% to 6.79%, due November 2013 through February 2018; collateralized by automobiles, machinery and equipment	5,210		5,144
Capital lease obligations	5,165		—
	1,380,058		1,293,402
Less current maturities	3,322		3,746
	$	1,376,736	$	1,289,656

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Document and Entity Information Document	9 Months Ended
	Sep. 30, 2013	Nov. 14, 2013 Common Class A	Nov. 14, 2013 Common Class B	Nov. 14, 2013 Common Class C	Nov. 14, 2013 Common Class D	Nov. 14, 2013 Common Class E	Nov. 14, 2013 Common Class F	Nov. 14, 2013 Common Class G
Entity Information [Line Items]
Entity Registrant Name	Chaparral Energy, Inc.
Entity Central Index Key	0001346980
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		70,145	357,882	209,882	279,999	504,276	1	3

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Derivative instruments (Tables)

9 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Outstanding derivative instruments

The following table summarizes our crude oil derivatives outstanding as of September 30, 2013:

		Weighted average fixed price per Bbl
Period and Type of Contract	Volume MBbls	Swaps		Sold puts		Purchased puts		Sold calls
2013
Swaps	510	$	95.54	$	—	$	—	$	—
Three-way collars	900	$	—	$	77.83	$	99.94	$	114.49
2014
Swaps	739	$	92.51	$	—	$	—	$	—
Three-way collars	2,400	$	—	$	75.50	$	93.25	$	101.94
Enhanced swaps	840	$	98.62	$	80.00	$	—	$	—
Put spread enhanced swaps	2,225	$	93.64	$	80.00	$	60.00	$	—
Purchased puts	840	$	—	$	—	$	60.00	$	—
2015
Enhanced swaps	4,918	$	93.35	$	80.00	$	—	$	—

The following tables summarize our natural gas derivative instruments outstanding as of September 30, 2013:

Period and Type of Contract	Volume BBtu	Weighted average fixed price per MMBtu
2013
Natural gas swaps	4,890	$	4.34
Natural gas basis protection swaps	5,390	$	0.20
2014
Natural gas swaps	18,420	$	4.03
Natural gas basis protection swaps	21,550	$	0.24
2015
Natural gas swaps	10,800	$	4.26
Natural gas basis protection swaps	2,400	$	0.18

Derivative instruments recorded on the balance sheet at fair value

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 September 30, 2013								As of December 31, 2012
	Assets		Liabilities			Net value			Assets		Liabilities			Net value
Natural gas swaps	$	9,180	$	(281	)	$	8,899		$	13,642	$	(1,487	)	$	12,155
Oil swaps	122		(5,363		)	(5,241		)	4,957		(1,339		)	3,618
Oil collars	3,974		(538		)	3,436			27,411		(1,180		)	26,231
Oil enhanced swaps	2,005		(8,229		)	(6,224		)	—		—			—
Oil purchased puts (1)	185		—			185			—		—			—
Natural gas basis differential swaps	778		(345		)	433			—		(1,599		)	(1,599		)
Total derivative instruments	16,244		(14,756		)	1,488			46,010		(5,605		)	40,405
Less:
Netting adjustments (2)	7,763		(7,763		)	—			2,977		(2,977		)	—
Current portion asset (liability)	4,449		(6,971		)	(2,522		)	42,516		(436		)	42,080
	$	4,032	$	(22	)	$	4,010		$	517	$	(2,192	)	$	(1,675	)

(1) Includes premiums of $664 paid during the second quarter of 2013. No additional premiums have been paid.

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

Derivative settlements outstanding

Derivative settlements outstanding at September 30, 2013 and December 31, 2012 were as follows:

	September 30, 2013		December 31, 2012
Derivative settlements receivable included in accounts receivable	$	317	$	8,013
Derivative settlements payable included in accounts payable and accrued liabilities	$	3,393	$	41

Non-hedge derivative gains (losses) in the consolidated statements of operations

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

	Three months ended						Nine months ended
	September 30,						September 30,
	2013			2012			2013			2012
Change in fair value of commodity price swaps	$	(7,795	)	$	(22,167	)	$	(12,115	)	$	(7,451	)
Change in fair value of collars	(16,057		)	(14,094		)	(22,795		)	20,480
Change in fair value of enhanced swaps and put options	(17,499		)	—			(6,703		)	—
Change in fair value of natural gas basis differential contracts	342			526			2,032			(303		)
(Payments on) receipts from settlement of commodity price swaps	(2,510		)	8,046			2,327			20,022
(Payments on) receipts from settlement of collars	(256		)	3,079			11,300			5,711
Payments on settlement of natural gas basis differential contracts	(55		)	(420		)	(530		)	(1,424		)
	$	(43,830	)	$	(25,030	)	$	(26,484	)	$	37,035