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, 2014

OR

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

For the transition period from to

Commission file number: 333-134748

____________________________

Chaparral Energy, Inc.

(Exact name of registrant as specified in its charter)

 ____________________________

Delaware	73-1590941
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
701 Cedar Lake Boulevard Oklahoma City, Oklahoma	73114
(Address of principal executive offices)	(Zip code)

(405) 478-8770

(Registrant’s telephone number, including area code)

____________________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ¨    No  ý

(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of the Securities Exchange Act of 1934. However, during the preceding 12 months, the registrant has filed all reports that it would have been

required to file by Section 13 or 15(d) of the Securities Act of 1934 if the registrant was subject to the filing requirements of the Securities Exchange Act of 1934.)

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  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 7, 2014:

Class	Number of shares
Class A Common Stock, $0.01 par value	364,891
Class B Common Stock, $0.01 par value	344,859
Class C Common Stock, $0.01 par value	209,882
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	2

CHAPARRAL ENERGY, INC.

Index to Form 10-Q

	Page
Part I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated balance sheets as of September 30, 2014 (unaudited) and December 31, 2013	6
Consolidated statements of operations for the three and nine months ended September 30, 2014 and 2013 (unaudited)	8
Consolidated statement of comprehensive income (loss) for the three and nine months ended September 30, 2014 and 2013 (unaudited)	9
Consolidated statements of cash flows for the nine months ended September 30, 2014 and 2013 (unaudited)	10
Condensed notes to consolidated financial statements (unaudited)	11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Overview	28
Results of operations	29
Liquidity and capital resources	36
Non-GAAP financial measure and reconciliation	41
Critical accounting policies	41
Recent accounting pronouncements	41
Item 3. Quantitative and Qualitative Disclosures about Market Risk	42
Item 4. Controls and Procedures	45
Part II. OTHER INFORMATION	45
Item 1. Legal Proceedings	45
Item 1A. Risk Factors	46
Item 6. Exhibits	47
Signatures	48
EX-10.1 Employment Agreement, dated as of September 22, 2014, by and among the Company and Dave Winchester
EX-10.2 Letter Agreement to Eighth Restated Credit Agreement dated as of November 5, 2014
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 laws. 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. They are subject to a number of assumptions, risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the forward-looking statements. Forward-looking statements in this report may include, for example, statements about:

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

• the amount, nature and timing of capital expenditures;

• drilling, completion and performance of wells;

• competition and government regulations;

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

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

• 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 for the year ended December 31, 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 the forward-looking statements contained herein. 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:

• Basin. A low region or natural depression in the earth’s crust where sedimentary deposits accumulate.

• Bbl. One stock tank barrel of 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.

• Boe/d. Barrels of oil equivalent per day.

• 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.

• Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.

• CO₂. Carbon dioxide.

• Enhanced oil recovery (EOR). The use of any improved recovery method, including injection of CO₂or polymer, to remove additional oil after secondary recovery.

• Field. An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

• 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.

• MMBtu. One million British thermal units.

• MMcf. One million cubic feet of natural gas.

• Natural gas liquids (NGLs). Those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption or other methods in gas processing or cycling plants. Natural gas liquids primarily include propane, butane, isobutane, pentane, hexane and natural gasoline.

• NYMEX. The New York Mercantile Exchange.

• Play. A term describing an area of land following the identification by geologists and geophysicists of reservoirs with potential oil and natural gas reserves.

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

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

• 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.

• Secondary recovery. The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Secondary recovery methods are often applied when production slows due to depletion of the natural pressure.

• Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.

5

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets

	September 30, 2014			December 31, 2013
(dollars in thousands, except share data)	(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	19,712		$	48,595
Accounts receivable, net	111,573			96,515
Inventories, net	24,025			16,137
Prepaid expenses	2,754			3,998
Derivative instruments	27,797			2,152
Deferred income taxes	—			9,260
Total current assets	185,861			176,657
Property and equipment—at cost, net	68,805			69,426
Oil and natural gas properties, using the full cost method:
Proved	3,512,036			3,258,661
Unevaluated (excluded from the amortization base)	327,495			321,477
Accumulated depreciation, depletion, amortization and impairment	(1,640,113		)	(1,470,090		)
Total oil and natural gas properties	2,199,418			2,110,048
Derivative instruments	16,274			6,403
Other assets	32,184			35,348
	$	2,502,542		$	2,397,882
The accompanying notes are an integral part of these consolidated financial statements.

6

Chaparral Energy, Inc. and subsidiaries Consolidated balance sheets—continued
	September 30, 2014		December 31, 2013
(dollars in thousands, except share data)	(unaudited)
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	161,302	$	134,811
Accrued payroll and benefits payable	26,392		24,246
Accrued interest payable	33,661		24,225
Revenue distribution payable	30,583		25,138
Current maturities of long-term debt and capital leases	5,677		5,334
Derivative instruments	246		8,234
Deferred income taxes	2,128		—
Total current liabilities	259,989		221,988
Long-term debt and capital leases, less current maturities	1,514,673		1,557,528
Derivative instruments	27		—
Stock-based compensation	5,209		4,942
Asset retirement obligations and other	43,787		53,305
Deferred income taxes	98,361		62,855
Commitments and contingencies (Note 11)
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 370,741 and 70,117 shares issued and outstanding as of September 30, 2014 and December 31, 2013, respectively	4		—
Class B Common stock, $0.01 par value, 10,000,000 shares authorized and 344,859 and 357,882 shares issued and outstanding as of September 30, 2014 and December 31, 2013, respectively.	3		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 nil and 279,999 shares issued and outstanding as of September 30, 2014 and December 31, 2013, respectively	—		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 and 2 and 3 shares issued and outstanding as of September 30, 2014 and December 31, 2013, respectively	—		—
Additional paid in capital	428,124		424,377
Retained earnings	152,358		72,873
	580,496		497,264
	$	2,502,542	$	2,397,882

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,
(in thousands)	2014			2013			2014			2013
				(unaudited)
Revenues:
Commodity sales	$	179,383		$	161,623		$	545,698		$	433,489
Gain from oil hedging activities	—			9,032			—			28,544
Total revenues	179,383			170,655			545,698			462,033
Costs and expenses:
Lease operating	42,077			37,306			113,662			104,232
Production taxes	7,133			8,831			21,935			25,299
Depreciation, depletion and amortization	61,527			47,582			180,631			139,439
Loss on impairment of other assets	—			1,090			—			1,090
General and administrative	14,820			13,065			43,199			38,626
Total costs and expenses	125,557			107,874			359,427			308,686
Operating income	53,826			62,781			186,271			153,347
Non-operating income (expense):
Interest expense	(25,434		)	(24,074		)	(78,096		)	(72,565		)
Non-hedge derivative gains (losses)	104,413			(43,830		)	17,218			(26,484		)
Other income, net	442			425			1,407			837
Net non-operating income (expense)	79,421			(67,479		)	(59,471		)	(98,212		)
Income (loss) before income taxes	133,247			(4,698		)	126,800			55,135
Income tax expense (benefit)	49,734			(2,130		)	47,315			19,993
Net income (loss)	$	83,513		$	(2,568	)	$	79,485		$	35,142

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

8

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of comprehensive income (loss)

	Three months ended					Nine months ended
	September 30,					September 30,
(in thousands)	2014		2013			2014		2013
			(unaudited)
Net income (loss)	$	83,513	$	(2,568	)	$	79,485	$	35,142
Other comprehensive loss
Reclassification adjustment for hedge gains included in gain from oil hedging activities in the consolidated statements of operations	—		(9,032		)	—		(28,544		)
Income tax benefit related to other comprehensive loss	—		3,306			—		10,766
Other comprehensive loss, net of tax	—		(5,726		)	—		(17,778		)
Comprehensive income (loss)	$	83,513	$	(8,294	)	$	79,485	$	17,364

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,
(in thousands)	2014			2013
	(unaudited)
Cash flows from operating activities
Net income	$	79,485		$	35,142
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion & amortization	180,631			139,439
Loss on impairment of other assets	—			1,090
Deferred income taxes	46,894			19,398
Gain on hedge reclassification adjustments	—			(28,544		)
Non-hedge derivative (gains) losses	(17,218		)	26,484
Gain on sale of assets	(1,007		)	(556		)
Other	3,033			3,395
Change in assets and liabilities
Accounts receivable	(14,442		)	(20,858		)
Inventories	(7,287		)	(1,689		)
Prepaid expenses and other assets	998			561
Accounts payable and accrued liabilities	(906		)	17,694
Revenue distribution payable	5,446			5,181
Stock-based compensation	3,504			1,747
Net cash provided by operating activities	279,131			198,484
Cash flows from investing activities
Expenditures for property, plant, and equipment and oil and natural gas properties	(499,255		)	(382,167		)
Proceeds from asset dispositions	258,578			91,788
Settlement of non-hedge derivative instruments	(25,038		)	13,097
Other	—			(664		)
Net cash used in investing activities	(265,715		)	(277,946		)
Cash flows from financing activities
Proceeds from long-term debt	186,999			133,208
Repayment of long-term debt	(227,572		)	(51,416		)
Proceeds from capital lease obligations	—			5,203
Principal payments under capital lease obligations	(1,726		)	(38		)
Net cash (used in) provided by financing activities	(42,299		)	86,957
Net (decrease) increase in cash and cash equivalents	(28,883		)	7,495
Cash and cash equivalents at beginning of period	48,595			29,819
Cash and cash equivalents at end of period	$	19,712		$	37,314

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

10

Chaparral Energy, Inc. and subsidiaries

Condensed 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 and Texas.

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, 2013.

The financial information as of September 30, 2014, and for the three and nine months ended September 30, 2014 and 2013, is unaudited. The financial information as of December 31, 2013 has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2013. 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, 2014 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2014.

Certain reclassifications have been made to prior period financial statements to conform to current period presentation. The reclassifications had no effect on our previously reported results of operations.

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, 2014, cash with a recorded balance totaling $17,457 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 establish our allowance for doubtful accounts 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.

11

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

We write off accounts receivable when they are determined to be uncollectible. Recovered amounts previously written off are offset against the allowance and reduce expense in the year of recovery. Accounts receivable consisted of the following at September 30, 2014 and December 31, 2013:

	September 30, 2014			December 31, 2013
Joint interests	$	36,644		$	31,335
Accrued commodity sales	65,304			60,768
Derivative settlements	1,041			4,616
Production tax credit	2,703			694
Other	6,192			698
Allowance for doubtful accounts	(311		)	(1,596		)
	$	111,573		$	96,515

Inventories

Inventories are comprised of equipment used in developing oil and natural gas properties and oil and natural gas product 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. Inventories are shown net of a provision for obsolescence, commensurate with known or estimated exposure, which is reflected in the valuation allowance disclosed below. Inventories at September 30, 2014 and December 31, 2013 consisted of the following:

	September 30, 2014			December 31, 2013
Equipment inventory	$	22,503		$	13,657
Commodities	2,433			3,186
Inventory valuation allowance	(911		)	(706		)
	$	24,025		$	16,137

Oil and natural gas properties

Capitalized Costs. 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 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, 2014, include $240,019 of capital costs incurred for undeveloped acreage, $72,046 for the construction of CO₂ delivery pipelines and facilities for which there are no reserves, and $15,430 for wells and facilities in progress pending determination. As of December 31, 2013, work-in-progress costs included capital costs incurred of $196,227 for undeveloped acreage, $115,828 for the construction of CO₂ delivery pipelines and facilities for which there are no reserves, and $9,422 for wells and facilities in progress pending determination.

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties are provided using the units-of-production method based on estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. Our cost basis for depletion includes estimated future development costs to be incurred on proved undeveloped properties. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs, and the anticipated proceeds from salvaging equipment.

12

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

Ceiling Test. 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.

Our estimates of oil and natural gas reserves as of September 30, 2014 were prepared using an average price for oil and natural gas of each month for the prior twelve months as required by the SEC. The cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties as of September 30, 2014, and no ceiling test impairment was recorded.

A decline in oil and natural gas prices subsequent to September 30, 2014 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.

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 are 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 awards 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 equity per share on a minority, non-marketable basis 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. Compensation cost associated with restricted stock awards that include a market condition is recognized over the requisite service period using the straight-line method. The assumptions used to value our stock-based compensation awards reflect our best estimates, but they involve inherent uncertainties based on market conditions generally outside of our control. As a result, stock-based compensation expense could have been significantly impacted if other assumptions had been used.

The costs associated with our stock-based compensation programs 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.

Recently adopted accounting pronouncements

In July 2011, the Financial Accounting Standards Board (“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, which was effective and adopted by us in the first quarter of 2014, did not have a material impact on our financial statements and results of operations.

13

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

Recently issued accounting pronouncements

In May 2014, the FASB issued authoritative guidance that supersedes previous revenue recognition requirements and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This guidance is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. We are currently evaluating the effect the new standard will have on our financial statements and results of operations.

In August 2014, the FASB issued authoritative guidance that requires entities to evaluate whether there is substantial doubt about their ability to continue as a going concern and requires additional disclosures if certain criteria are met. This guidance is effective for fiscal periods after December 15, 2016 and interim periods thereafter. We do not expect this guidance to materially impact our financial statements or results of operations.

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,
	2014			2013
Net cash provided by operating activities included:
Cash payments for interest	$	74,446		$	70,735
Interest capitalized	(9,957		)	(11,670		)
Cash payments for interest, net of amounts capitalized	$	64,489		$	59,065
Cash payments for income taxes	$	591		$	240
Non-cash investing activities included:
Asset retirement obligation additions and revisions	$	7,118		$	1,036
Oil and natural gas properties acquired through increase in accounts payable and accrued liabilities	$	22,458		$	8,298

Note 3: Acquisitions and divestitures

During the second quarter of 2014, we closed on the sales of two of the five property packages that comprise our plan to divest our assets in Ark-La-Tex, Permian Basin, Gulf Coast, and North Texas. The five packages include: (i) our Fort Worth Basin package located in North Texas; (ii) our Delaware Basin package; (iii) our Central Basin Platform package; (iv) our Ark-La-Tex package; and (v) our Gulf Coast package. In May 2014, we sold our Fort Worth Basin package to Scout Energy Group I, LP, for cash proceeds of $23,702, net of post-closing adjustments, and we sold our Delaware Basin package to RKI Exploration & Production, LLC for cash proceeds of $124,717, net of post-closing adjustments.

During the third quarter of 2014, we closed on the sales of two additional property packages. Our Ark-La-Tex and Central Basin Platform property packages, both of which were sold to RAM Energy, LLC (“RAM”), closed in July 2014 for cash proceeds of $48,495 and $45,854, respectively. These proceeds are subject to post-closing adjustments. As these properties did not represent a material portion of our oil and natural gas reserves, individually or in the aggregate, we did not record any gain or loss on the sales and instead, reduced our full cost pool by the amount of the net proceeds without significant alteration to our depletion rate.

In addition to the packages discussed above, we had various other divestitures during the nine months ended September 30,2014, for cash proceeds of $22,215. These divestitures included properties predominantly located in Andrews County, Texas, which comprised part of our Permian Basin properties, and Osage County, Oklahoma.

14

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

In December 2013, we acquired certain oil and natural gas properties in the Panhandle Marmaton play from Cabot Oil & Gas Corporation (the “Cabot Acquisition”). The acquisition qualified as a business combination for accounting purposes and, as such, we estimated the fair value of the acquired properties as of the acquisition date and allocated the purchase price to the assets and liabilities acquired based on their fair values. During the second quarter of 2014, we finalized the post-closing adjustments related to the Cabot Acquisition with no material changes to the purchase price allocation.

Note 4: Long-term debt

As of the dates indicated, long-term debt consisted of the following:

	September 30, 2014		December 31, 2013
9.875% Senior Notes due 2020, net of discount of $5,013 and $5,444, respectively	$	294,987	$	294,556
8.25% Senior Notes due 2021	400,000		400,000
7.625% Senior Notes due 2022, including premium of $5,076 and $5,719, respectively	555,076		555,719
Senior secured revolving credit facility	232,000		272,000
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	10,832		11,202
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.85% to 5.95% , due October 2014 through February 2018; collateralized by automobiles, machinery and equipment	5,032		5,235
Capital lease obligations	22,423		24,150
	1,520,350		1,562,862
Less current maturities	5,677		5,334
	$	1,514,673	$	1,557,528

Senior Notes

The senior notes, which, as of September 30, 2014, include our 9.875% senior notes due 2020, our 8.25% senior notes due 2021, and our 7.625% senior notes due 2022 (collectively, our “Senior Notes”) are our senior unsecured obligations, rank equally in right of payment with all our existing and future senior debt, and rank senior to all of our existing and future subordinated debt.

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. During the nine months ended September 30, 2014, we borrowed $185,000 and repaid $225,000 on our senior secured revolving credit facility. As of September 30, 2014, the weighted average interest rate was 1.9% on outstanding borrowings under the senior secured revolving credit facility.

Availability under our senior secured revolving credit facility is subject to a borrowing base which is set by the banks semiannually 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.

On May 19, 2014, we entered into a Limited Consent and Fourteenth Amendment to our senior secured revolving credit facility which provides for a series of automatic reductions in the borrowing base under the senior secured revolving credit facility as the divestitures of our oil and natural gas properties are completed (see Note 3—Acquisitions and divestitures). As a result of two divestitures that closed during the second quarter and two additional divestitures that closed during the third quarter, our borrowing base was reduced to $484,500 effective July 18, 2014. As of result of our semiannual redetermination, effective November 5, 2014, our borrowing base was increased to $650,000.

15

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

Availability under our senior secured revolving credit facility was further reduced by 10% of the borrowing base through August 15, 2014 under the Limited Consent and Fourteenth Amendment to compensate for temporary over-hedging of our production in excess of covenant limits which was caused by our asset divestitures referenced above. On August 14, 2014, we entered into a Letter Agreement with our lenders to extend the waiver of temporary hedging noncompliance until November 1, 2014, which was subsequently extended further until May 1, 2015, the date of our next scheduled borrowing base redetermination. In conjunction with the extension, the 10% reduction in availability was replaced with a requirement to maintain a level of availability on our senior secured credit facility that is calculated based on our overhedged position. The requirement specifies that, in the event the market value of our derivative contracts for a given commodity is a liability, the level of availability on our senior secured revolving credit facility must be no less than two times the liability on the overhedged production. As of September 30, 2014, we were overhedged on our projected natural gas production; however, since the market value of our natural gas derivative contracts, based on prior day settlement prices, was an asset on that date, there was no restriction on the availability under our senior secured credit facility.

We believe we were in compliance with all covenants under our senior secured revolving credit facility as of September 30, 2014.

Capital Leases

During 2013, we entered into lease financing agreements with U.S. Bank National Association for $24,500 through the sale and subsequent leaseback of existing compressors owned by us. The carrying value of these compressors is included in our oil and natural gas full cost pool. The lease financing obligations are for 84-month terms and include the 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 3.8%. Minimum lease payments are approximately $3,181 annually.

Note 5: 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, enhanced 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 paying a cash premium at the time the put options are purchased or paying later when the put options settle. 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.

16

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

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 enter into crude oil derivative contracts for a portion of our natural gas liquids production. The following table summarizes our crude oil derivatives outstanding as of September 30, 2014:

		Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls	Swaps		Sold puts		Purchased puts		Sold calls
2014
Swaps	187	$	93.13	$	—	$	—	$	—
Three-way collars	600	$	—	$	75.50	$	93.25	$	101.94
Enhanced swaps	210	$	97.58	$	80.00	$	—	$	—
Put spread enhanced swaps	745	$	93.87	$	80.00	$	60.00	$	—
Purchased puts (1)	210	$	—	$	—	$	60.00	$	—
2015
Swaps	600	$	96.02	$	—	$	—	$	—
Enhanced swaps	6,058	$	92.92	$	80.00	$	—	$	—
Purchased puts (1)	5,548	$	—	$	—	$	60.00	$	—
2016
Three-way collars	240	$	—	$	84.00	$	92.00	$	101.01
Enhanced swaps	3,720	$	92.94	$	80.52	$	—	$	—

___________

(1) Puts covering 840 Mbbls in 2014 were purchased during the second quarter of 2013 for $664. The 2015 puts were purchased during the second quarter of 2014 for $1,220.

The following tables summarize our natural gas derivative instruments outstanding as of September 30, 2014:

Period and type of contract	Volume BBtu	Weighted average fixed price per MMBtu
2014
Natural gas swaps	5,090	$	4.11
Natural gas basis protection swaps	5,200	$	0.24
2015
Natural gas swaps	22,170	$	4.20
Natural gas basis protection swaps	2,400	$	0.18
2016
Natural gas swaps	7,800	$	4.33

17

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

Effect of derivative instruments on the consolidated balance sheets

All derivative financial instruments are recorded on the balance sheet at fair value. See Note 6—Fair value measurements 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, 2014								As of December 31, 2013
	Assets		Liabilities			Net value			Assets		Liabilities			Net value
Natural gas swaps	$	6,595	$	(216	)	$	6,379		$	1,457	$	(3,706	)	$	(2,249	)
Oil swaps	5,472		—			5,472			112		(2,807		)	(2,695		)
Oil collars	2,877		—			2,877			2,776		(4		)	2,772
Oil enhanced swaps	28,745		(179		)	28,566			6,988		(6,212		)	776
Oil purchased puts	1,026		—			1,026			74		—			74
Natural gas basis differential swaps	—		(522		)	(522		)	1,706		(63		)	1,643
Total derivative instruments	44,715		(917		)	43,798			13,113		(12,792		)	321
Less:
Netting adjustments (1)	644		(644		)	—			4,558		(4,558		)	—
Current portion asset (liability)	27,797		(246		)	27,551			2,152		(8,234		)	(6,082		)
	$	16,274	$	(27	)	$	16,247		$	6,403	$	—		$	6,403

___________

(1) Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with a counterparty are netted only to the extent that they relate to the same current versus noncurrent classification on the balance sheet.

We discontinued hedge accounting effective April 1, 2010. Net derivative gains (losses) attributable to derivatives previously subject to hedge accounting were deferred through accumulated other comprehensive income (loss) (“AOCI”). As of December 31, 2013, there are no longer any deferred gains in AOCI as all the previously deferred gains (losses) have been reclassified into earnings upon the sale of the hedged production.

Derivative settlements outstanding at September 30, 2014 and December 31, 2013 were as follows:

	September 30, 2014		December 31, 2013
Derivative settlements receivable included in accounts receivable	$	1,041	$	4,616
Derivative settlements payable included in accounts payable and accrued liabilities	$	75	$	377

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 upon settlement of the contracts.

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Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

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

	Three months ended						Nine months ended
	September 30,						September 30,
	2014			2013			2014			2013
Change in fair value of commodity price swaps	$	20,039		$	(7,795	)	$	16,794		$	(12,115	)
Change in fair value of collars	6,870			(16,057		)	106			(22,795		)
Change in fair value of enhanced swaps and put options	80,717			(17,499		)	28,019			(6,703		)
Change in fair value of natural gas basis differential contracts	9			342			(2,165		)	2,032
Amortization of put premium	(166		)	—			(498		)	—
(Payments on) receipts from settlement of commodity price swaps	(1,030		)	(2,510		)	(12,653		)	2,327
(Payments on) receipts from settlement of collars	(77		)	(256		)	(1,338		)	11,300
Payments on settlement enhanced swaps	(1,664		)	—			(10,657		)	—
Payments on settlement of natural gas basis differential contracts	(285		)	(55		)	(390		)	(530		)
	$	104,413		$	(43,830	)	$	17,218		$	(26,484	)

Note 6: 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 5—Derivative instruments). We have no Level 1 assets or liabilities as of September 30, 2014 or December 31, 2013. Our derivative contracts classified as Level 2 as of September 30, 2014 and December 31, 2013 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.

19

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

As of September 30, 2014 and December 31, 2013, our derivative contracts classified as Level 3 consisted of three-way collars, enhanced swaps, and purchased puts. 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 recorded at fair value and include a measure of our own nonperformance risk for derivative liabilities or that of our counterparties for derivative assets.

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

	As of September 30, 2014								As of December 31, 2013
	Derivative assets			Derivative liabilities			Net assets (liabilities)		Derivative assets			Derivative liabilities			Net assets (liabilities)
Significant other observable inputs (Level 2)	$	12,067		$	(738	)	$	11,329	$	3,275		$	(6,576	)	$	(3,301	)
Significant unobservable inputs (Level 3)	32,648			(179		)	32,469		9,838			(6,216		)	3,622
Netting adjustments (1)	(644		)	644			—		(4,558		)	4,558			—
	$	44,071		$	(273	)	$	43,798	$	8,555		$	(8,234	)	$	321

___________

(1) Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with a counterparty are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification.

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, 2014 and 2013 were: 

	Nine months ended September 30,
Net derivative assets (liabilities)	2014		2013
Beginning balance	$	3,622	$	26,231
Realized and unrealized gains (losses) included in non-hedge derivative losses	15,632		(18,198		)
Purchases	1,220		664
Settlements paid (received)	11,995		(11,300		)
Ending balance	$	32,469	$	(2,603	)
Gains relating to instruments still held at the reporting date included in non-hedge derivative gains (losses) for the period	$	24,156	$	8,776

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 2014 and 2013 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 6.60% and 6.90%, respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. See Note 7—Asset retirement obligations 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.

20

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

The carrying value and estimated fair value of our long-term debt at September 30, 2014 and December 31, 2013 were as follows:

	September 30, 2014				December 31, 2013
Level 2	Carrying value		Estimated fair value		Carrying value		Estimated fair value
9.875% Senior Notes due 2020	$	294,987	$	321,000	$	294,556	$	340,140
8.25% Senior Notes due 2021	400,000		419,000		400,000		437,000
7.625% Senior Notes due 2022	555,076		566,500		555,719		583,275
Senior secured revolving credit facility	232,000		232,000		272,000		272,000
Other secured long-term debt	15,864		15,864		16,437		16,437
	$	1,497,927	$	1,554,364	$	1,538,712	$	1,648,852

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, 2014, the counterparties to our open derivative contracts consisted of eleven financial institutions, of which ten were subject to our rights of offset under our senior secured revolving credit facility.

21

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

The following table summarizes our derivative assets and liabilities which are offset in the consolidated balance sheets 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)			Derivatives(1)			Amounts outstanding under senior secured revolving credit facility			Net amount
As of September 30, 2014
Derivative assets	$	44,715		$	(644	)	$	44,071		$	—		$	(44,071	)	$	—
Derivative liabilities	(917		)	644			(273		)	—			—			(273		)
	$	43,798		$	—		$	43,798		$	—		$	(44,071	)	$	(273	)
As of December 31, 2013
Derivative assets	$	13,113		$	(4,558	)	$	8,555		$	(3,484	)	$	(4,211	)	$	860
Derivative liabilities	(12,792		)	4,558			(8,234		)	3,484			—			(4,750		)
	$	321		$	—		$	321		$	—		$	(4,211	)	$	(3,890	)

___________

(1) Since positive and negative positions with a counterparty are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification, these represent remaining amounts that could have been offset under our master netting agreements.

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 subject to acceleration in the event of default was $917 at September 30, 2014.

Note 7: Asset retirement obligations

The following table provides a summary of our asset retirement obligation activity during the nine months ended September 30, 2014 and 2013.

	Nine months ended September 30,
	2014			2013
Beginning balance	$	55,179		$	49,214
Liabilities incurred in current period	4,844			1,036
Liabilities settled and disposed in current period	(16,807		)	(4,969		)
Revisions in estimated cash flows	2,274			—
Accretion expense	2,991			2,968
Ending balance	48,481			48,249
Less current portion included in accounts payable and accrued liabilities	4,997			2,900
	$	43,484		$	45,349

See Note 6—Fair value measurements for additional information regarding fair value assumptions associated with our asset retirement obligations.

22

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

Note 8: 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”). Under the Phantom Plan, awards vest at the end of five years, 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.

Under the RSU Plan, restricted stock units may be awarded to Participants in an aggregate amount of 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, 2014 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, 2014	$	17.01	53,162				$	13.53	325,297
Granted	—		—				8.52		504,752
Vested	12.61		(22,041	)	$	212	13.96		(118,400	)	$	1,094
Forfeited	19.54		(6,223	)			9.85		(105,214	)
Unvested and outstanding at September 30, 2014	$	20.26	24,898				$	9.91	606,435

Based on an estimated fair value of $13.76 per phantom share and RSU as of September 30, 2014, the aggregate intrinsic value of the unvested phantom shares and RSUs outstanding was $8,687.

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.

The awards granted under the 2010 Plan consist of shares that are subject to service vesting conditions (the “Time Vested” awards) and shares that are subject to market and performance vested conditions (the “Performance Vested” awards). Except as noted below, 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 whereby CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively “CCMP”) receive cash upon the sale of its class E common stock (a “Transaction” as defined in the 2010 Plan). Prior to October 1, 2014, 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.

23

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

A summary of our restricted stock activity during the nine months ended September 30, 2014 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, 2014	$	634.67	19,246				$	307.45	46,701
Granted	818.50		5,245				204.90		10,033
Vested	649.18		(4,517	)	$	3,697	—		—
Forfeited	638.06		(1,399	)			338.51		(4,468	)
Unvested and total outstanding at September 30, 2014	$	682.80	18,575				$	285.11	52,266

During the nine months ended September 30, 2014 and 2013, respectively, we repurchased and canceled 1,810 and 873 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 $969.00 per Time Vested restricted share, the aggregate intrinsic value of the unvested Time Vested restricted shares outstanding was $17,999 as of September 30, 2014.

Effective October 1, 2014, we terminated all outstanding grants of Performance Vested awards and issued new grants of Performance Vested awards to reflect that (i) a certain number of shares which would vest if CCMP receives net proceeds from a Transaction that yields a return of at least 350% per share were removed from the initial Performance Vested awards and an equal amount were granted effective as of October 1, 2014, under Time Vesting awards (which vest on January 1, 2015, 2016, 2017 and 2018); and (ii) the remaining number of shares subject to the previous Performance Vested awards were reallocated among three targets for vesting. These vesting targets will apply for any new grants of Performance Vested awards. Any shares of Performance Vested awards not vested on a Separation Date will be forfeited as of the Separation Date.

Return on Investment Target	Target Shares Vested
175% per share	33% of shares multiplied by the Vesting Fraction
200% per share	33% of shares multiplied by the Vesting Fraction
250% per share	33% of shares multiplied by the Vesting Fraction

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,
	2014			2013			2014			2013
Stock-based compensation cost	$	2,309		$	2,045		$	9,026		$	4,620
Less: stock-based compensation cost capitalized	(289		)	(505		)	(2,735		)	(1,440		)
Stock-based compensation expense	$	2,020		$	1,540		$	6,291		$	3,180

Payments for stock-based compensation were $699 and $135 during the third quarters of 2014 and 2013, respectively, and were $2,787 and $1,433 during the nine months ended September 30, 2014 and 2013, respectively. As of September 30, 2014 and December 31, 2013, accrued payroll and benefits payable included $7,305 and $5,080, respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized compensation cost of approximately $19,982 is expected to be recognized over a weighted average period of 2.3 years.

24

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

Note 9: Common stock

The following is a summary of the changes in our common shares outstanding during the nine months ended September 30, 2014:

	Common Stock
	Class A		Class B		Class C	Class D		Class E	Class F	Class G		Total
Shares outstanding at January 1, 2014	70,117		357,882		209,882	279,999		504,276	1	3		1,422,160
Stock transfers (1)	293,023		(13,023	)	—	(279,999	)	—	—	(1	)	—
Restricted stock issuances	15,278		—		—	—		—	—	—		15,278
Restricted stock repurchased	(1,810	)	—		—	—		—	—	—		(1,810	)
Restricted stock forfeitures	(5,867	)	—		—	—		—	—	—		(5,867	)
Shares outstanding at September 30, 2014	370,741		344,859		209,882	—		504,276	1	2		1,429,761

_______________

(1) In this transaction, Healthcare of Ontario Pension Plan Trust Fund (“HOOPP”) purchased 280,000 shares of Class A common stock converted from Class D and Class G common stock held by CHK Energy Holdings, Inc. (“CHK Energy Holdings”) effective January 13, 2014. An additional 15,078 shares of Class A common stock was purchased by HOOPP from various other stockholders of which 13,023 shares were converted from Class B common stock.

Note 10: Related party transactions

CHK Energy Holdings, an indirect wholly owned subsidiary of Chesapeake Energy Corporation (“Chesapeake”), previously owned 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			Nine months ended
	September 30, 2013			September 30, 2013
Revenues	$	2,449		$	5,289
Joint interest billings	$	(453	)	$	(1,764	)

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			Nine months ended
	September 30, 2013			September 30, 2013
Revenues	$	(1,549	)	$	(3,248	)
Joint interest billings	$	1,084		$	8,969

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

	December 31, 2013
Amounts receivable from Chesapeake	$	466
Amounts payable to Chesapeake	$	64

On January 13, 2014, CHK Energy Holdings sold all of its equity interest in us to Healthcare of Ontario Pension Plan Trust Fund. The sale by CHK Energy Holdings was in compliance with terms and conditions of the Stockholders Agreement implemented on April 12, 2010.

25

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

Note 11: 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 and $920 as of September 30, 2014 and December 31, 2013, respectively. 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, 2014 or 2013.

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 in the United States District Court for the Western District of Oklahoma, 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 the due date of Plaintiff’s Motion for Class Certification has been extended to July 15, 2015. 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 in the District Court of Mayes County, Oklahoma, 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.

Martha Donelson and John Friend, on behalf of themselves and on behalf of all similarly situated persons v. Chaparral Energy, L.L.C.

On August 11, 2014, Martha Donelson and John Friend (the “Plaintiffs”), filed a complaint against us in the United States District Court for the Northern District of Oklahoma, alleging claims on behalf of themselves and all similarly situated Osage County land owners and surface lessees. The Plaintiffs assert class claims seeking recovery for trespass, nuisance, negligence and unjust enrichment. Relief sought includes declaring our oil and natural gas leases and drilling permits obtained in Osage County without a prior NEPA study void ab initio, removing us from all properties owned by the class members, disgorgement of profits, and compensatory and punitive damages. We have joined in Motions to Dismiss filed by the Defendants. 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.

26

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases, capital leases and purchase obligations. In June 2014, we entered into two non-cancelable operating leases for CO₂ recycle compressors at our EOR facilities. As of September 30, 2014, total minimum payments over the remaining life of the leases, which expire in 2021, were $6,500. The remaining operating leases primarily relate to office equipment while our capital leases are related to the sale and subsequent leaseback of compressors. Our purchase obligations primarily relate to contracts for the purchase of CO₂, drilling rig services, pipe and equipment. Other than the two new operating leases and net debt repayments during the nine months ended September 30, 2014, there were no material changes to our contractual commitments since December 31, 2013.

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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 are one of the largest oil producers in the state. In recent years, we have capitalized on our sustained success in our 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 operator 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.

Beginning in 2011, we have increased our focus on acquisition of leasehold acreage and exploration in resource plays with repeatable drilling opportunities. Our focus is concentrated in the Mid-Continent region, with most of our capital dollars being spent in the Panhandle Marmaton, Mississippian and Woodford Shale plays. By concentrating in these core areas, we are developing a significant resource base to achieve production and reserve growth.

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, 2013 reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 19%, 14% and 11% 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.

28

During the third quarter of 2014, production increased12% to 2,767 MBoe compared to production of 2,477 MBoe during the third quarter of 2013, primarily due to our drilling activity and EOR production gains, both partially offset by our significant property divestitures. As a result, revenue from commodity sales was $17.8 million higher in the third quarter of 2014 compared to the third quarter in 2013. Additionally, due primarily to downward changes in the NYMEX forward commodity price curves, we had a non-hedge derivative gain of $104.4 million in the third quarter of 2014 compared to $43.8 million of non-hedge derivative losses during the same period last year. As a result of these and other factors, we reported a net gain of $83.5 million during the third quarter of 2014 compared to a net loss of $2.6 million for the comparable period in 2013.

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:

• Our oil and natural gas property capital expenditure budget for 2014 is set at $660.0 million. Our capital expenditures during the nine months ended September 30, 2014 were $529.0 million, consisting primarily of $307.7 million in drilling and completion expenditures in our E&P Areas, $137.5 million for our EOR Project Areas (excluding acquisitions) and $64.0 million for the acquisition of oil and natural gas properties and leasehold.

• We completed the sale of two separate divestiture packages of non-core properties during the second quarter of 2014 for $148.4 million in cash, net of post-closing adjustments. In July 2014, we completed the sale of two additional divestiture packages of non-core properties for $94.3 million in cash, before post-closing adjustments. The properties included in these four sales accounted for approximately 8% and 15% of our total production during the nine months ended September 30, 2014 and 2013, respectively. In addition to the packages described above, we also received approximately $22.2 million in cash for various other property divestitures during the nine months ended September 30, 2014.

Results of operations

Production

Production volumes by area were as follows (MBoe):

	Three months ended		Percent change		Nine months ended		Percent change
	September 30,				September 30,
	2014	2013			2014	2013
E&P Areas
Mississippian	663	417	59.0	%	1,861	907	105.2	%
Panhandle Marmaton	331	129	156.6	%	724	197	267.5	%
Woodford Shale	148	21	604.8	%	306	56	446.4	%
Legacy Production Areas	840	859	(2.2	)%	2,531	2,852	(11.3	)%
Total E&P Areas	1,982	1,426	39.0	%	5,422	4,012	35.1	%
EOR Project Areas
Active EOR Projects	503	377	33.4	%	1,356	1,135	19.5	%
Potential EOR Projects	240	274	(12.4	)%	759	816	(7.0	)%
Total EOR Project Areas	743	651	14.1	%	2,115	1,951	8.4	%
Non-Core Properties	42	400	(89.5	)%	680	1,236	(45.0	)%
Total	2,767	2,477	11.7	%	8,217	7,199	14.1	%

E&P Areas

E&P Areas includes our Mississippian, Panhandle Marmaton and Woodford Shale plays. E&P Areas also includes our Legacy Production Areas which primarily include mature properties with low production decline curves. The majority of the properties in our Legacy Production Areas are located in and hold leasehold acreage for future exploration in our existing repeatable resource plays.

29

Production in our Mississippian play increased for the three and nine months ended September 30, 2014, compared to the same periods in 2013 primarily due to our drilling and development activity in our NOMP for the twelve months ended September 30, 2014. Production in our Panhandle Marmaton play increased primarily due to our drilling and development activity for the twelve months ended September 30, 2014 and production from newly acquired fields, specifically the Cabot Acquisition in December 2013. Production in our Legacy Production Areas decreased slightly for the three months ended September 30, 2014 compared to the same period in 2013 primarily due to normal production decline during the last twelve months concentrated in our Granite Wash and Cleveland Sand plays and strategic divestitures within these areas. Production in our Legacy Production Areas decreased for the nine months ended September 30, 2014 compared to the same period in 2013 primarily due to normal production decline during the last twelve months concentrated in our Granite Wash and Cleveland Sand plays and strategic divestitures within these areas.

EOR Project Areas

Our EOR Project Areas include both currently Active EOR Projects and Potential EOR Projects with no current EOR production or reserves at September 30, 2014. Our Active EOR Project areas include properties that have proved EOR reserves, ongoing EOR operations, or that have an approved authorization for expenditure for EOR operations. Production increases in our Active EOR Projects were primarily due to ongoing drilling and CO₂ injection activities in our Farnsworth Unit and a more pronounced EOR production response in our North Burbank Unit. We realized our first EOR production response from the North Burbank Unit in the fourth quarter of 2013 with more significant response developing during the second and third quarters of 2014.

Non-Core Properties

As discussed in our Annual Report on Form 10-K for the year ended December 31, 2013, our Board approved selling our Ark-La-Tex, Permian Basin, Gulf Coast, and North Texas properties. Production decreases in our Non-Core Properties were primarily due to strategic divestitures within these areas combined with the natural production decline in wells producing during the last twelve months. See “Asset divestitures and alternative capital sources” below for further discussion on our divestitures.

30

Revenues

Our commodity sales are derived from the sale of oil, natural gas and natural gas liquids production. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

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

	Three months ended				Increase / (Decrease)			Percent change		Nine months ended				Increase / (Decrease)		Percent change
	September 30,									September 30,
	2014		2013							2014		2013
Commodity sales (in thousands)
Oil	$	146,320	$	132,932	$	13,388		10.1	%	$	434,714	$	347,331	$	87,383	25.2	%
Natural gas	18,949		16,989		1,960			11.5	%	68,881		53,362		15,519		29.1	%
Natural gas liquids	14,114		11,702		2,412			20.6	%	42,103		32,796		9,307		28.4	%
Total commodity sales	$	179,383	$	161,623	$	17,760		11.0	%	$	545,698	$	433,489	$	112,209	25.9	%
Production
Oil (MBbls)	1,528		1,288		240			18.6	%	4,471		3,644		827		22.7	%
Natural gas (MMcf)	4,986		4,956		30			0.6	%	15,781		15,210		571		3.8	%
Natural gas liquids (MBbls)	408		363		45			12.4	%	1,116		1,020		96		9.4	%
MBoe	2,767		2,477		290			11.7	%	8,217		7,199		1,018		14.1	%
Average daily production (Boe/d)	30,076		26,924		3,152			11.7	%	30,099		26,370		3,729		14.1	%
Average sales prices (excluding derivative settlements)
Oil per Bbl	$	95.76	$	103.21	$	(7.45	)	(7.2	)%	$	97.23	$	95.32	$	1.91	2.0	%
Natural gas per Mcf	$	3.80	$	3.43	$	0.37		10.8	%	$	4.36	$	3.51	$	0.85	24.2	%
NGLs per Bbl	$	34.59	$	32.24	$	2.35		7.3	%	$	37.73	$	32.15	$	5.58	17.4	%
Average sales price per Boe	$	64.83	$	65.25	$	(0.42	)	(0.6	)%	$	66.41	$	60.22	$	6.19	10.3	%

Our total commodity sales increased significantly during the three months ended September 30, 2014 as compared to the three months ended September 30, 2013 as a result of a 12%increase in production volumes sold offset slightly by a 1%decrease in the average price per Boe. Our total commodity sales increased significantly during the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013 as a result of a 14%increase in production volumes sold combined with a 10%increase in the average price per Boe.

Average production volumes sold increased by 3,152 Boe per day, or 12%, during the three months ended September 30, 2014 compared to the three months ended September 30, 2013. The increase in average production volumes sold was primarily a result of new production from wells that were completed during the twelve months ended September 30, 2014, offsetting the decrease due to the decline in production in wells that were producing as of September 30, 2013, and property divestitures during the period. Average daily production in our Mississippian, Panhandle Marmaton and Woodford Shale plays increased by approximately 2,674 Boe per day, 2,196 Boe per day, and 1,380 Boe per day, respectively, during the third quarter of 2014 compared to the third quarter of 2013, primarily as a result of our recent well completions and production from newly acquired fields, specifically our Cabot Acquisition in December 2013. Average daily production in our Active EOR project areas increased by approximately 1,370 Boe per day during the third quarter of 2014 compared to the third quarter of 2013, primarily as a result of ongoing drilling and CO₂ injection activities in our Farnsworth Unit and a more pronounced EOR production response in our North Burbank Unit. These increases were partially offset by a decrease in average production volumes sold in our Legacy Production Areas and our Non-Core Properties primarily due to strategic divestitures combined with a combination of declines in production and reduced drilling activity in these areas.

Average production volumes sold increased by 3,729 Boe per day, or 14%, during the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013. The increase in average production volumes sold was primarily a result of our well completions during the twelve months ended September 30, 2014, offsetting the decrease due to the decline in

31

production in wells that were producing as of September 30, 2013, and property divestitures during the period. Average daily production in our Mississippian, Panhandle Marmaton and Woodford Shale plays increased by approximately 3,495 Boe per day, 1,930 Boe per day, and 916 Boe per day, respectively, during the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013 primarily as a result of our recent well completions and production from newly acquired fields, specifically our Cabot Acquisition in December 2013. Average daily production in our Active EOR project areas increased by approximately 810 Boe per day during the nine months ended September 30, 2014 compared to the same period in 2013, primarily as a result of ongoing drilling and CO₂ injection activities in our Farnsworth Unit and a more pronounced EOR production response in our North Burbank Unit. These increases were partially offset by a decrease in average production volumes sold in our Legacy Production Areas and our Non-Core Properties primarily due to strategic divestitures combined with declines in production as a result of decreased drilling activity in these areas.

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

	Three months ended September 30,					Nine months ended September 30,
	2014 vs. 2013					2014 vs. 2013
(in thousands)	Sales change			Percentage change in sales		Sales change		Percentage change in sales
Change in oil sales due to:
Prices	$	(11,382	)	(8.5	)%	$	8,557	2.5	%
Production	24,770			18.6	%	78,826		22.7	%
Total change in oil sales	$	13,388		10.1	%	$	87,383	25.2	%
Change in natural gas sales due to:
Prices	$	1,857		10.9	%	$	13,516	25.3	%
Production	103			0.6	%	2,003		3.8	%
Total change in natural gas sales	$	1,960		11.5	%	$	15,519	29.1	%
Change in natural gas liquids sales due to:
Prices	$	961		8.2	%	$	6,220	19.0	%
Production	1,451			12.4	%	3,087		9.4	%
Total change in natural gas liquids sales	$	2,412		20.6	%	$	9,307	28.4	%

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.

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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,
	2014			2013			2014			2013
Oil (per Bbl)(1):
Before derivative settlements	$	82.87		$	87.60		$	85.34		$	81.50
After derivative settlements	$	81.66		$	84.12		$	82.51		$	82.97
Post-settlement to pre-settlement price	98.5		%	96.0		%	96.7		%	101.8		%
Natural gas (per Mcf):
Before derivative settlements	$	3.80		$	3.43		$	4.36		$	3.51
After derivative settlements	$	3.66		$	4.02		$	3.78		$	3.92
Post-settlement to pre-settlement price	96.3		%	117.2		%	86.7		%	111.7		%

___________

(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, 2014			December 31, 2013
Derivative assets (liabilities):
Natural gas swaps	$	6,379		$	(2,249	)
Oil swaps	5,472			(2,695		)
Oil collars	2,877			2,772
Oil enhanced swaps	28,566			776
Oil purchased puts	1,026			74
Natural gas basis differential swaps	(522		)	1,643
Net derivative assets	$	43,798		$	321

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,
	2014						2013
(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		$	—
Non-hedge derivative gains (losses):
Oil swaps, collars, enhanced swaps and puts	$	97,291		$	(2,343	)	$	(40,714	)	$	(5,754	)
Natural gas swaps	10,335			(428		)	(637		)	2,988
Natural gas basis differential contracts	9			(285		)	342			(55		)
Amortization of put premium	(166		)	—			—			—
Non-hedge derivative gains (losses)	$	107,469		$	(3,056	)	$	(41,009	)	$	(2,821	)
Total gains (losses) from derivative activities	$	107,469		$	(3,056	)	$	(31,977	)	$	(2,821	)

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	Nine months ended September 30,
	2014						2013
(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		$	—
Non-hedge derivative gains (losses):
Oil swaps, collars, enhanced swaps and puts	$	36,291		$	(15,842	)	$	(38,357	)	$	6,837
Natural gas swaps	8,628			(8,806		)	(3,256		)	6,790
Natural gas basis differential contracts	(2,165		)	(390		)	2,032			(530		)
Amortization of premium put	(498		)	—			—			—
Non-hedge derivative gains (losses)	$	42,256		$	(25,038	)	$	(39,581	)	$	13,097
Total gains (losses) from derivative activities	$	42,256		$	(25,038	)	$	(11,037	)	$	13,097

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 our consolidated statements of operations. Gain from oil hedging activities, which is a component of total revenues in our consolidated statements of operations, of $9.0 million and $28.5 million for the three and nine months ended September 30, 2013, respectively, consists of the reclassification of hedge gains on discontinued oil hedges from accumulated other comprehensive income into net income.

We recognized net non-hedge derivative gains (losses) of $104.4 million during the three months ended September 30, 2014 compared to $(43.8) million during the three months ended September 30, 2013. Non-hedge derivative gains (losses) were $17.2 million during the nine months ended September 30, 2014 compared to $(26.5) million during the nine months ended September 30, 2013. 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.

Lease operating expenses

	Three months ended September 30,				Increase / (Decrease)		Percent change		Nine months ended September 30,				Increase / (Decrease)			Percent change
	2014		2013						2014		2013
Lease operating expenses (in thousands)	$	42,077	$	37,306	$	4,771	12.8	%	$	113,662	$	104,232	$	9,430		9.0	%
Lease operating expenses per Boe	$	15.21	$	15.06	$	0.15	1.0	%	$	13.83	$	14.48	$	(0.65	)	(4.5	)%

Lease operating costs are sensitive to changes in demand for field equipment, services, and qualified operational personnel, which is driven by demand for oil and natural gas. However, the timing of changes in operating costs may lag behind changes in commodity prices. Our EOR projects are more expensive to operate than traditional industry operations due to the nature of operations along with the costs of recovery and recycling of CO₂.

Our lease operating expenses increased during the three months ended September 30, 2014 compared to the three months ended September 30, 2013 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 high operating cost assets.

Our lease operating expenses increased during the nine months ended September 30, 2014, compared to the nine months ended September 30, 2013 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 high operating cost assets.

Our lease operating expenses on a Boe basis, however, decreased during the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013. The decrease on a Boe basis is primarily attributable to the increase in overall production volumes between periods.

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Production taxes (which include ad valorem taxes)

	Three months ended September 30,				Increase / (Decrease)			Percent change		Nine months ended September 30,				Increase / (Decrease)			Percent change
	2014		2013							2014		2013
Production taxes (in thousands)	$	7,133	$	8,831	$	(1,698	)	(19.2	)%	$	21,935	$	25,299	$	(3,364	)	(13.3	)%
Production taxes per Boe	$	2.58	$	3.57	$	(0.99	)	(27.7	)%	$	2.67	$	3.51	$	(0.84	)	(23.9	)%

Production taxes generally change in proportion to commodity sales. Some states offer exemptions or reduced production tax rates for horizontal drilling, enhanced recovery projects and high cost gas wells. In Oklahoma, new wells qualify for a tax incentive and are taxed at a lower rate during their initial months of production. After the incentive period expires, the tax rate reverts to the statutory rate.

Our production taxes decreased during the three months ended September 30, 2014 compared to the three months ended September 30, 2013 primarily due to our strategic divestitures of wells in our Non-Core Properties and Legacy Production Areas, which generally had higher tax rates, combined with reduced tax rates for horizontal drilling and high cost gas exemption tax credits, partially offset by the 12%increase in sales volumes. Our production taxes decreased during the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013 primarily due to our strategic divestitures of wells in our Non-Core Properties and Legacy Production Areas, which generally had higher tax rates, combined with reduced tax rates for horizontal drilling along with EOR and high cost gas exemption tax credits, partially offset by the 14%increase in sales volumes combined with the 10%increase in averaged realized prices.

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

	Three months ended September 30,				Increase / (Decrease)			Percent change		Nine months ended September 30,				Increase / (Decrease)			Percent change
	2014		2013							2014		2013
DD&A (in thousands):
Oil and natural gas properties	$	58,035	$	44,416	$	13,619		30.7	%	$	170,023	$	129,993	$	40,030		30.8	%
Property and equipment	2,564		2,206		358			16.2	%	7,617		6,478		1,139			17.6	%
Accretion of asset retirement obligation	928		960		(32		)	(3.3	)%	2,991		2,968		23			0.8	%
Total DD&A	$	61,527	$	47,582	$	13,945		29.3	%	$	180,631	$	139,439	$	41,192		29.5	%
DD&A per Boe:
Oil and natural gas properties	$	20.97	$	17.93	$	3.04		17.0	%	$	20.69	$	18.06	$	2.63		14.6	%
Other fixed assets	$	1.26	$	1.28	$	(0.02	)	(1.6	)%	$	1.29	$	1.31	$	(0.02	)	(1.5	)%
Total DD&A per Boe	$	22.23	$	19.21	$	3.02		15.7	%	$	21.98	$	19.37	$	2.61		13.5	%

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 for the three months ended September 30, 2014, compared to the three months ended September 30, 2013, of which $8.4 million was due to a higher rate per equivalent unit of production and $5.2 million was due to an increase in production. Our DD&A rate per equivalent unit of production increased for the three months ended September 30,2014 primarily due to higher estimated future development costs and higher cost reserve additions.

DD&A on oil and natural gas properties increased for the nine months ended September 30,2014, compared to the nine months ended September 30, 2013, of which $21.6 million was due to a higher rate per equivalent unit of production and $18.4 million was due to an increase in production. Our DD&A rate per equivalent unit of production increased for the nine months ended September 30,2014 primarily due to higher estimated future development costs and higher cost reserve additions.

Impairment of other assets. During the three and nine months ended September 30, 2014, we had no impairment losses. 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 which were being marketed for sale and their carrying values exceeded expected market pricing.

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General and administrative expenses (“G&A”)

	Three months ended September 30,						Increase / (Decrease)			Percent change		Nine months ended September 30,						Increase / (Decrease)			Percent change
	2014			2013								2014			2013
G&A (in thousands):
Gross G&A expenses	$	21,217		$	17,938		$	3,279		18.3	%	$	64,082		$	52,951		$	11,131		21.0	%
Capitalized exploration and development costs	(6,397		)	(4,873		)	(1,524		)	31.3	%	(20,883		)	(14,325		)	(6,558		)	45.8	%
Net G&A expenses	$	14,820		$	13,065		$	1,755		13.4	%	$	43,199		$	38,626		$	4,573		11.8	%
Average G&A expense per Boe	$	5.36		$	5.27		$	0.09		1.7	%	$	5.26		$	5.37		$	(0.11	)	(2.0	)%

Gross G&A expenses increased during the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013 primarily due to increased compensation and benefits costs related to the competitive nature of our market and our increased activity, along with other expenses and general inflation.

Capitalized exploration and development costs increased between periods primarily due to a higher proportion of compensation costs subject to capitalization. A larger proportion of our compensation costs are being capitalized compared to the prior period as a result of our shift in focus from acquiring developed properties to exploring and developing leasehold acreage in resource plays with repeatable drilling opportunities.

Our G&A expenses on a Boe basis, however, decreased for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013 primarily due to the increase in overall production volumes between periods and an increase in the proportion of general and administrative expenses capitalized in connection with our increased 2014 development and exploration activities.

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)	2014			2013			2014			2013
9.875% Senior Notes due 2020	$	7,698		$	7,668		$	23,071		$	22,985
8.25% Senior Notes due 2021	8,423			8,409			25,259			25,218
7.625% Senior Notes due 2022	10,545			10,524			31,618			31,552
Senior secured revolving credit facility	1,062			411			4,126			901
Bank fees and other interest	1,374			1,182			3,979			3,579
Capitalized interest	(3,668		)	(4,120		)	(9,957		)	(11,670		)
Total interest expense	$	25,434		$	24,074		$	78,096		$	72,565
Average long-term borrowings	$	1,490,584		$	1,362,118		$	1,543,346		$	1,338,863

Total interest expense for the three and nine months ended September 30, 2014 increased 6% and 8%, respectively, compared to the same periods in 2013 primarily due to increased levels of borrowing and reduced capitalized interest.

Liquidity and capital resources

Historically, our primary sources of liquidity have been cash generated from our operations, debt, private equity sales and proceeds from asset dispositions. As of September 30, 2014, we had cash and cash equivalents of $19.7 million and had borrowed $232.0 million under our senior secured revolving credit facility with a borrowing base of $484.5 million. As of November 7, 2014, we had borrowed $292.0 million under our senior secured revolving credit facility with a borrowing base of $650.0 million and $343.4 million of remaining availability.

We believe that we will have sufficient funds available through our cash from operations, proceeds from asset divestitures 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.

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All of our sources of liquidity can be impacted by the general condition of the broader economy and by fluctuations in commodity prices, operating costs, and volumes produced, all of which affect us and our industry. We have no control over the market prices for oil, gas, or NGLs, although we are able to influence the amount of our realized revenues from our oil, gas, and NGL sales through the use of derivative contracts as part of our commodity price risk management program. Historically, decreases in commodity prices have limited our industry’s access to capital markets. The borrowing base under our credit facility could be reduced as a result of lower commodity prices, divestitures of proved properties, or newly issued debt. We are closely monitoring the recent volatility in the oil and natural gas commodity markets, in particular the decline in oil prices. The profitability of the oil and gas operations and the ability to realize recorded asset values is dependent on the success of future development plans and projected long-term market conditions.

Sources and uses of cash

Our net change in cash is summarized as follows:

	Nine months ended						Increase / (Decrease)			Percent Change
	September 30,
(in thousands)	2014			2013
Cash flows provided by operating activities	$	279,131		$	198,484		$	80,647		40.6	%
Cash flows used in investing activities	(265,715		)	(277,946		)	12,231			(4.4	)%
Cash flows (used in) provided by financing activities	(42,299		)	86,957			(129,256		)	(148.6	)%
Net (decrease) increase in cash during the period	$	(28,883	)	$	7,495		$	(36,378	)	(485.4	)%

Our cash flows from operating activities is derived substantially from the production and sale of oil and natural gas. Our cash flows from operating activities were higher in the current year due to an increase in commodity sales as a result of higher production and prices on all our commodities. This was partially offset by higher operating expenses, interest charges and changes in working capital.

We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. For the nine months ended September 30, 2014 and 2013, cash flows provided by operating activities were approximately 56% and 52%, respectively, of cash used for the acquisition and development of our property.

Our cash flows from investing activities is comprised primarily of cash inflows from asset dispositions and derivative settlement receipts offset by cash outflows for capital expenditures and derivative settlement payments.

Our actual costs incurred, including costs that we have accrued for, and our budgeted 2014 capital expenditures for oil and natural gas properties during the nine months ended September 30, 2014 are summarized in the following table:

(in thousands)	E&P Areas		EOR Project Areas		Non-Core Properties		Total		2014 Capital Expenditures Budget (1)(2)(3)
Acquisitions	$	57,276	$	3,900	$	2,855	$	64,031	$	67,000
Drilling	307,650		35,009		757		343,416		455,000
Enhancements	18,169		57,743		891		76,803		76,000
Pipeline and field infrastructure	—		26,802		—		26,802		41,000
CO2 purchases	—		17,969		—		17,969		21,000
Total	$	383,095	$	141,423	$	4,503	$	529,021	$	660,000

___________

(1) Includes $156.0 million allocated to our EOR project areas as follows: acquisitions of $3.0 million, drilling of $35.0 million, enhancements of $56.0 million, pipeline and field infrastructure of $41.0 million, and CO₂ purchases of $21.0 million.

(2) Budget categories presented include allocations of capitalized interest and general and administrative expenses.

(3) In August 2014, our Board approved a $35.0 million increase to our capital expenditures budget.

Net cash used in investing activities during the nine months ended September 30, 2014 was comprised of cash outflows for capital expenditure of $499.3 million and derivative settlement payments of $25.0 million partially offset by cash inflows from dispositions of non-core oil and natural gas properties of $258.6 million. The 2014 asset dispositions include the divestiture of our Delaware Basin, Ft. Worth Basin, Ark-La-Tex, and Central Basin properties. Net cash used in investing activities during the nine months ended September 30, 2013 was comprised primarily of cash outflows for capital expenditure

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of $382.2 million partially offset by cash inflows from asset dispositions of $91.8 million and derivative settlement receipts of $13.1 million.

Cash flows from financing activities is comprised primarily of cash inflows from long-term debt borrowings offset by cash outflows from repayments of long-term debt and capital leases. During the nine months ended September 30, 2014, we had borrowings of $187.0 million which were more than offset by repayments of $227.6 million on our long-term debt and $1.7 million on our capital leases. During the nine months ended September 30, 2013, we had borrowings on our long-term debt of $133.2 million offset by repayments of $51.4 million. During this time, we also had proceeds of $5.2 million from the sale and subsequent leaseback of a compressor.

Indebtedness

Long-term debt consists of the following as of the dates indicated:

(in thousands)	September 30, 2014		December 31, 2013
9.875% Senior Notes due 2020, net of discount of $5,013 and $5,444, respectively	$	294,987	$	294,556
8.25% Senior Notes due 2021	400,000		400,000
7.625% Senior Notes due 2022, including premium of $5,076 and $5,719, respectively	555,076		555,719
Senior secured revolving credit facility	232,000		272,000
Real estate mortgage notes	10,832		11,202
Installment notes	5,032		5,235
Capital lease obligations	22,423		24,150
	$	1,520,350	$	1,562,862

Please see “Note 4—Long-term debt” in Item 8. Financial Statement and Supplementary Data of our annual report on Form 10-K for the year ended December 31, 2013 for a discussion of material terms governing our senior notes and senior secured revolving credit facility.

Senior secured revolving credit facility

We maintain a senior secured revolving credit facility, which is collateralized by our oil and natural gas properties, and 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 banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. 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.

On May 19, 2014, we entered into a Limited Consent and Fourteenth Amendment to our senior secured revolving credit facility which provides for a series of automatic reductions in the borrowing base under the senior secured revolving credit facility as the divestitures of our oil and natural gas properties are completed (see “Asset divestitures and alternative capital sources” below). As a result of our Fort Worth Basin and Delaware Basin divestitures that closed in May 2014 and our Ark-La-Tex and Central Basin Platform divestitures that closed in July 2014, our borrowing base was reduced to $484.5 million effective July 18, 2014. We are still actively marketing the sale of our Gulf Coast properties whereupon a successful sale will trigger a further reduction in the borrowing base of $6.5 million. As of result of our semiannual redetermination, effective November 5, 2014, our borrowing base was increased to $650.0 million.

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The Limited Consent and Fourteenth Amendment also imposed an additional reduction in availability under our senior secured revolving credit facility equal to 10% of the borrowing base to compensate for the hedging of our production in excess of limits specified by covenants under the senior secured revolving credit facility. Outstanding hedges have temporarily exceeded the limits allowed under the senior secured revolving credit facility because of our recent asset divestitures. Our lenders previously waived any covenant violations resulting from our temporary hedging noncompliance until August 15, 2014. On August 14, 2014, we entered into a Letter Agreement with our lenders to extend the waiver of temporary hedging noncompliance until November 1, 2014, which was subsequently extended further until May 1, 2015, the date of our next scheduled borrowing base redetermination. In conjunction with this extension, the 10% reduction in availability discussed above was replaced with a requirement to maintain a level of availability on our senior secured credit facility that is calculated based on our overhedged position. The requirement specifies that, in the event the market value of our derivative contracts for a given commodity is a liability, the level of availability on our senior secured revolving credit facility must be no less than two times the liability on the overhedged production. As of November 7, 2014, we were overhedged on our projected natural gas production; however, since the market value of our natural gas derivative contracts, based on prior day settlement prices, was an asset on that date, there was no restriction on the availability under our senior secured credit facility.

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. The following table discloses the current ratio for our loan compliance compared to the ratio calculated per GAAP.

(dollars in thousands)	September 30, 2014			December 31, 2013
Current assets per GAAP	$	185,861		$	176,657
Plus—Availability under senior secured revolving credit facility	251,580			327,080
Less—Short-term derivative instruments	(27,797		)	(2,152		)
Less - Deferred tax asset on derivative instruments and asset retirement obligations	—			(2,908		)
Current assets as adjusted	$	409,644		$	498,677
Current liabilities per GAAP	$	259,989		$	221,988
Less—Short-term derivative instruments	(246		)	(8,234		)
Less—Short-term asset retirement obligations	(4,997		)	(1,874		)
Less—Deferred tax liability on derivative instruments and asset retirement obligations	(8,480		)	—
Current liabilities as adjusted	$	246,266		$	211,880
Current ratio for loan compliance	1.66			2.35
Current ratio per GAAP	0.71			0.80

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. As of September 30, 2014, availability under our senior secured revolving credit facility was limited to $251.6 million compared to the availability on November 7, 2014 which was $343.4 million.

Capital Leases

During 2013, we entered into lease financing agreements with U.S. Bank National Association for $24.5 million through the sale and subsequent leaseback of existing compressors owned by us. The carrying value of these compressors is included in our oil and natural gas full cost pool.The lease financing obligations are for 84-month terms and include the 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 payments and interest expense.

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Asset divestitures and alternative capital sources

As discussed in our Annual Report on Form 10-K for the year ended December 31, 2013, our Board approved selling our Ark-La-Tex, Permian Basin, Gulf Coast, and North Texas properties in five property packages to implement our strategy of focusing our operations in the Mid-Continent area. The five packages include: (i) our Fort Worth Basin package located in North Texas; (ii) our Delaware Basin package; (iii) our Central Basin Platform package; (iv) our Ark-La-Tex package; and (v) our Gulf Coast package.

During the second quarter of 2014, we closed on the sales of two of the five property packages in our divestiture plan. In May 2014, we sold our Fort Worth Basin package to Scout Energy Group I, LP, for cash proceeds of $23.7 million, net of post-closing adjustments, and we sold our Delaware Basin package to RKI Exploration & Production, LLC for cash proceeds of $124.7 million, net of post-closing adjustments.

During the third quarter of 2014, we closed on the sales of two additional property packages. Our Ark-La-Tex and Central Basin Platform property packages, both of which were sold to RAM Energy, LLC (“RAM”), closed in July 2014 for cash proceeds of $48.5 million and $45.9 million, respectively. These proceeds are subject to post-closing adjustments.

In addition to the packages discussed above, we had various other divestitures during the nine months ended September 30,2014 for cash proceeds of approximately $22.2 million. These divestitures included properties predominantly located in Andrews County, Texas, which comprised part of our Permian Basin properties, and Osage County, Oklahoma.

On October 31, 2014, we executed a purchase and sale agreement with an undisclosed buyer, whereby we will sell our leasehold interests, including the Eagle Ford Formation and below, in Brazos, Burleson, Fayette, Grimes and Washington Counties in Texas for a purchase price of $20.1 million, subject to customary purchase price adjustments. The sale of the non-producing properties is expected to close on or about December 12, 2014, and is effective as of September 1, 2014.

Proceeds from the property sales discussed above as well as any future divestitures provide us with an additional source of liquidity to pay down borrowings under our senior secured revolving credit facility, fund capital expenditures and for general corporate purposes. Our external sources of liquidity in the future may include 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.

Contractual Obligations

We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases, capital leases and purchase obligations. Our operating leases primarily relate to office equipment while our capital leases are related to the sale and subsequent leaseback of compressors. Our purchase obligations primarily relate to contracts for the purchase of CO₂, drilling rig services, pipe and equipment. In June 2014, we entered into two non-cancelable operating leases for compressors at our EOR facilities. As of September 30, 2014, total minimum payments over the remaining life of the leases, which expire in 2021, were $6.5 million.

Other than the two new operating leases for compressors and net repayment of debt during the nine months ended September 30, 2014, there were no material changes to our contractual commitments since December 31, 2013.

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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 (loss) to adjusted EBITDA for the specified periods:

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2014			2013			2014			2013
Net income (loss)	$	83,513		$	(2,568	)	$	79,485		$	35,142
Interest expense	25,434			24,074			78,096			72,565
Income tax expense (benefit)	49,734			(2,130		)	47,315			19,993
Depreciation, depletion, and amortization	61,527			47,582			180,631			139,439
Reclassification adjustment for hedge gains	—			(9,032		)	—			(28,544		)
Non-cash change in fair value of non-hedge derivative instruments	(107,635		)	41,009			(42,754		)	39,581
Interest income	(15		)	(52		)	(86		)	(206		)
Stock-based compensation expense	1,607			1,271			3,867			2,553
Gain on sale of assets	(196		)	(332		)	(1,007		)	(556		)
Loss on impairment of other assets	—			1,090			—			1,090
Adjusted EBITDA	$	113,969		$	100,912		$	345,547		$	281,057

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, 2013.

Also see the footnote disclosures included in “Note 1—Nature of operations and summary of significant accounting policies” in Item 1. Financial statements of this report.

Recent accounting pronouncements

See recently adopted and issued accounting standards in “Note 1—Nature of operations and summary of significant accounting policies” in Item 1. Financial statements of this report.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity 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, 2014, our gross revenues from oil and natural gas sales would change approximately $5.6 million for each $1.00 change in oil and natural gas liquid prices and $1.6 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, enhanced swaps, costless collars, put options, and basis protection swaps. We currently 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). In conjunction with the sale of our Non-Core Properties in 2014, we may also early settle a portion of our derivative contracts in order to align our hedged volumes with anticipated production from remaining proved reserves. 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.

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Our outstanding crude oil derivative instruments as of September 30, 2014 are summarized below:

		Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls	Swaps		Sold puts		Purchased puts		Sold calls
October - December 2014
Swaps	187	$	93.13	$	—	$	—	$	—
Three-way collars	600	$	—	$	75.50	$	93.25	$	101.94
Enhanced swaps	210	$	97.58	$	80.00	$	—	$	—
Put spread enhanced swaps	745	$	93.87	$	80.00	$	60.00	$	—
Purchased puts	210	$	—	$	—	$	60.00	$	—
January - March 2015						—
Swaps	150	$	98.33	$	—	$	—	$	—
Enhanced swaps	1,535	$	93.27	$	80.00	$	—	$	—
Purchased puts	1,370	$	—	$	—	$	60.00	$	—
April - June 2015
Swaps	150	$	96.60	$	—	$	—	$	—
Enhanced swaps	1,583	$	93.29	$	80.00	$	—	$	—
Purchased puts	1,418	$	—	$	—	$	60.00	$	—
July - September 2015
Swaps	150	$	95.12	$	—	$	—	$	—
Enhanced swaps	1,470	$	92.55	$	80.00	$	—	$	—
Purchased puts	1,380	$	—	$	—	$	60.00	$	—
October - December 2015
Swaps	150	$	94.03	$	—	$	—	$	—
Enhanced swaps	1,470	$	92.55	$	80.00	$	—	$	—
Purchased puts	1,380	$	—	$	—	$	60.00	$	—
January - March 2016
Three-way collars	60	$	—	$	84.00	$	92.00	$	101.01
Enhanced swaps	960	$	92.98	$	80.50	$	—	$	—
April - June 2016
Three-way collars	60	$	—	$	84.00	$	92.00	$	101.01
Enhanced swaps	960	$	92.98	$	80.50	$	—	$	—
July - September 2016
Three-way collars	60	$	—	$	84.00	$	92.00	$	101.01
Enhanced swaps	900	$	92.91	$	80.53	$	—	$	—
October - December 2016
Three-way collars	60	$	—	$	84.00	$	92.00	$	101.01
Enhanced swaps	900	$	92.91	$	80.53	$	—	$	—

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Our outstanding natural gas derivative instruments as of September 30, 2014 are summarized below:

Period and type of contract	Volume BBtu	Weighted average fixed price per MMBtu
October - December 2014
Natural gas swaps	5,090	$	4.11
Natural gas basis protection swaps	5,200	$	0.24
January - March 2015
Natural gas swaps	5,270	$	4.34
Natural gas basis protection swaps	600	$	0.18
April - June 2015
Natural gas swaps	4,740	$	4.11
Natural gas basis protection swaps	600	$	0.18
July - September 2015
Natural gas swaps	5,920	$	4.13
Natural gas basis protection swaps	600	$	0.18
October - December 2015
Natural gas swaps	6,240	$	4.22
Natural gas basis protection swaps	600	$	0.18
January - March 2016
Natural gas swaps	2,400	$	4.49
April - June 2016
Natural gas swaps	1,800	$	4.19
July - September 2016
Natural gas swaps	1,800	$	4.24
October - December 2016
Natural gas swaps	1,800	$	4.36

Subsequent to September 30, 2014, we entered into natural gas basis swaps covering 8,400 BBtu for the period from January 2016 through December 2016 at a fixed price of $0.26 per MMBtu.

Interest rates. All of the outstanding borrowings under our senior secured revolving facility as of September 30, 2014 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 $484.5 million, equal to our borrowing base at September 30, 2014, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $4.8 million.

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ITEM 4. CONTROLS AND PROCEDURES

Disclosure controls and procedures

We have established disclosure controls and procedures to ensure that material information relating to 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.

On May 14, 2013, the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") issued an updated version of its Internal Control - Integrated Framework ("2013 Framework"). Originally issued in 1992 ("1992 Framework"), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. As of September 30, 2014, we continue to utilize the 1992 Framework during our transition to the 2013 Framework by the end of 2014.

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 in the United States District Court for the Western District of Oklahoma, 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 the due date of Plaintiff’s Motion for Class Certification has been extended to July 15, 2015. 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 in the District Court of Mayes County, Oklahoma, 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.

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Martha Donelson and John Friend, on behalf of themselves and on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On August 11, 2014, Martha Donelson and John Friend (the “Plaintiffs”), filed a complaint against us in the United States District Court for the Northern District of Oklahoma, alleging claims on behalf of themselves and all similarly situated Osage County land owners and surface lessees. The Plaintiffs assert class claims seeking recovery for trespass, nuisance, negligence and unjust enrichment. Relief sought includes declaring our oil and natural gas leases and drilling permits obtained in Osage County without a prior NEPA study void ab initio, removing us from all properties owned by the class members, disgorgement of profits, and compensatory and punitive damages. We have joined in Motions to Dismiss filed by the Defendants. 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, 2013. There have been no material changes to the risk factors since the filing of such Form 10-K.

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ITEM 6. EXHIBITS

Exhibit No.	Description
10.1	Employment Agreement, dated as of September 22, 2014, by and among the Company and Dave Winchester
10.2	Letter Agreement to Eighth Restated Credit Agreement dated as of November 5, 2014
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

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SIGNATURES

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

CHAPARRAL ENERGY, INC.
By:	/s/ Mark A. Fischer
Name:	Mark A. Fischer
Title:	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 12, 2014

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EXHIBIT INDEX

Exhibit No.	Description
10.1	Employment Agreement, dated as of September 22, 2014, by and among the Company and Dave Winchester
10.2	Letter Agreement to Eighth Restated Credit Agreement dated as of November 5, 2014
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

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EX-10.1

EMPLOYMENT AGREEMENT

THIS EMPLOYMENT AGREEMENT (this “Agreement”), dated as of the 22^nd day of September, 2014, is entered into by and between CHAPARRAL ENERGY, INC., a Delaware corporation (the “Company”), CHAPARRAL ENERGY, LLC (the “Employer”) and Dave Winchester (“Executive”).

IN CONSIDERATION of the premises and the mutual covenants set forth below, and for other good and valuable consideration, the sufficiency of which is hereby acknowledged, the parties hereby agree as follows:

WHEREAS, the Company desires to retain Executive as its employee and believes it is necessary to enter into this Agreement to provide the proper incentive to Executive; and

1.Term. Subject to the provisions for earlier termination hereinafter provided, Executive’s employment with the Company under this Agreement shall be for a term (the “Term”) commencing upon September 22, 2014 (the “Effective Date”) and ending on the third-year anniversary of the Effective Date; provided, however, that commencing on the date that is the third anniversary of the Effective Date, the Term shall be automatically extended so as to terminate on the second anniversary of such date, and the Term shall be automatically extended so as to terminate on each anniversary thereafter (each such anniversary referred to as a “Renewal Date”). Notwithstanding the foregoing, if at least ninety (90) days prior to any Renewal Date, the Company gives Executive written notice that the Term will not be so extended, this Agreement will continue for the remainder of the then current Term and automatically expire upon its completion. The Term may be sooner terminated under Section 5 of this Agreement.

2.    Position and Duties. During the Term, Executive will serve as Senior Vice President of Drilling of the Company and will report directly to the President and Chief Operating Officer (the “Supervising Executive”). Executive shall devote Executive’s best efforts and full business time and attention to perform all services reasonably required to fully execute the duties and responsibilities associated with the Company, its subsidiaries and its affiliates as directed by the Supervising Executive. Notwithstanding the above, Executive will be permitted, to the extent such activities do not interfere with the performance by Executive of his duties and responsibilities under this Agreement or violate this Agreement, to (i) manage Executive’s personal, financial and legal affairs, and (ii) serve on industry, civic or charitable boards or committees. Executive agrees to observe and comply with the rules and policies of the Company, as in effect from time to time, including, without limitation, any rules and policies relating to Executive obligations to the Company upon a termination of employment.

3.    Place of Performance. During the Term, Executive’s place of employment will be the Company’s principal executive offices in Oklahoma City, Oklahoma (the “Principal Location”), except for travel to other locations as may be necessary to fulfill Executive’s duties and responsibilities hereunder.

A-1

LA\2083111.2

4.    Compensation and Related Matters.

(a)    Base Salary. During the Term, the Company will pay Executive a base salary of not less than $325,000.00 per year (“Base Salary”), in accordance with the Company’s customary payroll practices. Executive’s Base Salary may be increased, but not decreased unless the base salaries for all executive officers of the Company are decreased, pursuant to annual review by the Compensation Committee (the “Compensation Committee”) of the Board of Directors of the Company (the “Board”) in its discretion. In the event that Executive’s Base Salary is increased, the increased amount will then constitute the Base Salary for all purposes of this Agreement.

(b)    Annual Bonus Incentives. In addition to the Base Salary, Executive shall be eligible to participate in and earn an annual cash bonus under any annual incentive plan established by the Board so long as the terms of any such plan allow participation by the executive officers of the Company (“Annual Bonus”). The target Annual Bonus for Executive shall be equal to 70% of Executive’s current Base Salary, but the actual Annual Bonus shall be determined by the Compensation Committee, in consultation with the Supervising Executive, in accordance with the terms of such plan, in effect at that time, if any. The terms for the payment of any Annual Bonus shall be determined by the Compensation Committee, in consultation with the Supervising Executive, in accordance with the terms of such plan in effect at that time, if any.

(c)    Equity Grant. Subject to adoption by the Board and approval by Company’s shareholders of the Company’s Amended 2010 Equity Incentive Plan (the “Plan”), the Company shall grant to Executive shares of restricted stock (the “Restricted Stock”) under the Plan, consisting of 2,057 time-vesting shares (the “Time-Vested Restricted Stock”) and 3,984 performance-vesting shares (the “Performance-Vested Restricted Stock”). Consistent with the foregoing, the terms and conditions of the Time-Vested Restricted Stock shall be set forth in an award agreement (the “Time-Vested Restricted Stock Agreement”) substantially in the form attached hereto as Exhibit A, and the terms and conditions of the Performance-Vested Restricted Stock shall be set forth in an award agreement (the “Performance-Vested Restricted Stock Agreement” and, together with the Time-Vested Restricted Stock Agreement, the “Restricted Stock Agreements”) substantially in the form attached hereto as Exhibit B, which together shall evidence the grant of the Restricted Stock. Subject to this Section 4(c), the Time-Vested Restricted Stock and the Performance-Vested Restricted Stock shall be governed in all respects by the terms of the Plan and the applicable Restricted Stock Agreement.

(d)    Welfare, Pension and Incentive Benefit. During the Term, Executive (and Executive’s spouse and/or eligible dependents to the extent provided in the applicable plans and programs) will be eligible to participate in and be covered under all the welfare benefit plans or programs maintained by the Company or Employer for the benefit of its senior executive officers pursuant to the terms of such plans and programs including, without limitation, all medical, life, hospitalization, dental, disability, accidental death and dismemberment and travel accident insurance plans and programs. In addition, during the Term, Executive will be eligible to participate in all pensions, retirement, savings and other employee benefit plans and programs maintained from time to time by the Company or Employer for the benefit of its senior executive officers.

2

LA\2083111.2

(e)    Vacation. Executive shall be entitled to paid vacation in accordance with the Employer’s vacation policy during the Term. Executive may use his vacation in a reasonable manner based upon the business needs of the Company.

(f)    Fringe Benefits. During the Term, the Company will provide Executive with such other fringe benefits as commensurate with Executive’s position.

(g)    Expenses. Executive will be entitled to receive prompt reimbursement for all reasonable business expenses incurred by Executive in accordance with the Company’s and Employer’s expense reimbursement policy during the Term. All payments under this Section 4(g) shall be paid to Executive on or before the last day of Executive’s taxable year following the taxable year in which Executive incurred such expenses.

5.    Termination of Employment. Executive’s employment under this Agreement may be terminated during the Term under the following circumstances:

(a)    Death. Executive’s employment under this Agreement will terminate upon his death.

(b)    Disability. Upon Executive’s Disability, Executive will receive a Notice of Termination (as defined in Section 6(a)) from the Company. If Executive does not return to the substantial performance of his duties on a full-time basis within thirty (30) days of such Notice of Termination, the Company has the right to terminate Executive’s employment under this Agreement for Disability, and such termination will not be a breach of this Agreement by the Company. For purposes of this Agreement, “Disability” means Executive’s incapacity due to physical or mental illness whereby Executive is substantially unable to perform his duties under this Agreement (with or without reasonable accommodation, as defined under the Americans With Disabilities Act) for a period of six (6) consecutive months.

(c)    Cause. The Company has the right to terminate Executive’s employment for Cause by providing Executive with a Notice of Termination, and such termination will not be a breach of this Agreement by the Company. For purposes of this Agreement, “Cause” means the occurrence of any one or more of the following events: (i) Executive’s conviction of, or entry by Executive of a guilty or no contest plea to a felony or crime involving moral turpitude; (ii) Executive’s willful commission of an act of fraud or dishonesty resulting in economic or financial injury to the Company or any affiliate; (iii) Executive’s willful failure to substantially perform or gross neglect of Executive’s duties, including, but not limited to, the failure to follow any lawful directive of the Supervising Executive, within the reasonable scope of Executive’s duties; (iv) Executive’s performance of acts materially detrimental to the Company or any affiliate, unless otherwise approved in advance by the Board or the Compensation Committee; (v) Executive’s use of narcotics, alcohol, or illicit drugs in a manner that has or may reasonably be expected to have a detrimental effect on Executive’s performance of his duties as an employee of the Company or on the reputation of the Company or any affiliate; (vi) Executive’s commission of a material violation of any rule or policy sponsored by the Company which results in injury to the Company; or (vii) Executive’s material breach of this Agreement, including, but not limited to, Executive’s material breach of the covenants set forth in Section 9 hereof.

3

LA\2083111.2

(d)    Good Reason. Executive may terminate Executive’s employment with the Company for “Good Reason,” and such termination will not be a breach of this Agreement by Executive. For purposes of this Agreement, “Good Reason” shall mean the occurrence without the written consent of Executive, of one of the events set forth below:

(i)    a material diminution in Executive’s authority, duties or responsibilities combined with a demotion in Executive’s pay grade ranking;

(ii)    the reduction by the Company of Executive’s Base Salary by more than ten percent (10%) (unless done so for all executive officers of the Company);

(iii)    the requirement that Executive be based at any office or location that is more than 50 miles from the Principal Location, except for travel reasonably required in the performance of Executive’s responsibilities; or

(iv)    any other action or inaction that constitutes a material breach by the Company of this Agreement such as the failure of any successor to the Company to assume this Agreement pursuant to Section 14.

Notwithstanding the foregoing, Executive will not be deemed to have terminated for Good Reason unless (A) Executive provides written notice to the Company of the existence of one of the conditions described above within ninety (90) days after Executive has knowledge of the initial existence of the condition, (B) the Company fails to remedy the condition so identified within thirty (30) days after receipt of such notice (if capable of correction), (C) Executive provides a Notice of Termination to the Company within thirty (30) days of the expiration of the Company’s period to remedy the condition, and (D) Executive terminates employment within ninety (90) days after Executive provides written notice to the Company of the existence of the condition referred to in clause (A).

(e)    Without Cause. The Company has the right to terminate Executive’s employment under this Agreement without Cause by providing Executive with a Notice of Termination. For purposes of Section 7 hereto, a “termination without Cause” shall include the Company’s failure to renew this Agreement pursuant to Section 1 prior to a Renewal Date.

(f)    Without Good Reason. Executive may voluntarily terminate employment with the Company without Good Reason at any time by providing the Company with a Notice of Termination.

6.    Termination Procedure.

(a)    Notice of Termination. Any termination of Executive’s employment by the Company or by Executive during the Term (other than termination pursuant to Section 5(a)) will be communicated by Notice of Termination to the other party in accordance with Section 15. For purposes of this Agreement, a “Notice of Termination” means a written notice which indicates the specific termination provision in this Agreement relied upon and sets forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of Executive’s employment.

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(b)    Date of Termination. “Date of Termination” shall mean (i) if Executive’s employment is terminated by his death, the date of his death, (ii) if Executive’s employment is terminated due to Disability pursuant to Section 5(b), thirty (30) days after Notice of Termination (provided that Executive has not returned to the substantial performance of his duties on a full-time basis during such thirty (30) day period), (iii) if Executive’s employment is terminated for Good Reason pursuant to Section 5(d), the date on which a Notice of Termination provided in accordance with such Section is given or any later date (within thirty (30) days after the giving of such Notice of Termination) set forth in such Notice of Termination, (iv) if Executive’s employment is terminated voluntarily by Executive without Good Reason pursuant to Section 5(f), thirty (30) days after Notice of Termination, or (v) if Executive’s employment is terminated for any other reason, the date on which a Notice of Termination is given or any later date (within thirty (30) days after the giving of such Notice of Termination) set forth in such Notice of Termination.

7.    Obligations of the Company Upon Termination. In the event Executive’s employment under this Agreement terminates during the Term and such termination constitutes a “separation from service” from the Company (within the meaning of Section 409A(a)(2)(A)(i) of the Internal Revenue Code of 1986, as amended (the “Code”), and Treasury Regulation Section 1.409A-1(h)) (“Separation from Service”), the Company will provide Executive with the payments and benefits set forth below.

(a)    Termination by Company Without Cause or by Executive for Good Reason Not Following Change in Control. If Executive’s employment is terminated by the Company without Cause or by Executive for Good Reason at any time that is not within two (2) years after the occurrence of a “Change in Control” (as defined below):

(i)    The Company will pay to Executive in a single lump sum payment within thirty (30) days after the Date of Termination, the aggregate amount of (A) any earned but unpaid Base Salary, (B) any Annual Bonus required to be paid to Executive pursuant to Section 4(b) for any fiscal year of the Company that ends on or before the Date of Termination to the extent not previously paid, (C) accrued but unpaid vacation pay through the Date of Termination, and (D) reasonable business expenses incurred but unpaid through the Date of Termination (together, the “Accrued Obligations”);

(ii)    Subject to Sections 7(f) and 10 below, the Company will pay to Executive an amount equal to 1.5 (the “Severance Multiple”) times the sum of (x) Executive’s Base Salary in effect on the Date of Termination plus (y) the Annual Bonus granted to Executive for the fiscal year of the Company immediately on or preceding the Date of Termination, payable in the form of a salary continuation for a period of months equal to the product of 12 times the Severance Multiple; provided, however, that the first such payment shall not be made until the Company’s first payroll date occurring on or after the 30th day following the Date of Termination (the “First Payroll Date”) and any amounts that would otherwise have been paid pursuant to this Section 7(a)(ii) prior to the First Payroll Date shall instead be paid on the First Payroll Date. Each payment under this Section 7(a)(ii) shall be treated as a separate payment for purposes of Section 409A of the Code.

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(iii)    Subject to Sections 7(f) and 10 below, the Company will maintain in full force and effect, for the continued benefit of Executive (and Executive’s spouse and/or eligible dependents, as applicable) for a period of eighteen (18) months following the Date of Termination, participation by Executive (and Executive’s spouse and/or eligible dependents, as applicable) in the medical, hospitalization, and dental programs maintained by the Company for the benefit of its senior executive officers as in effect on the Date of Termination, at such level and terms and conditions (including, without limitation, contributions required by Executive for such benefits) as in effect on the Date of Termination; provided, if Executive (or his spouse) is eligible for Medicare or a similar type of governmental medical benefit, such benefit shall be the primary provider before Company medical benefits are provided. However, if Executive becomes reemployed with another employer and is eligible to receive medical, hospitalization and dental benefits under another employer–provided plan, the medical, hospitalization and dental benefits described herein shall be secondary to those provided under such other plan during the applicable period. If any plan pursuant to which such benefits are provided is not, or ceases prior to the expiration of the period of continuation coverage to be, exempt from the application of Section 409A of the Code under Treasury Regulation Section 1.409A-1(a)(5), then an amount equal to each remaining premium payment shall thereafter be paid to Executive as currently taxable compensation in substantially equal monthly installments over the continuation coverage period (or the remaining portion thereof).

(iv)    For purposes of this Agreement, “Change in Control” shall mean:

(A)    The consummation of any transaction or series of related transactions involving the sale of the Company’s outstanding securities (but excluding a public offering of the Company’s capital stock) for securities or other consideration issued or paid or caused to be issued or paid by such other corporation or an affiliate thereof and which result in this Company’s shareholders (or their affiliates) immediately prior to such transaction not holding at least a majority of the voting power of the surviving or continuing entity following such transaction; or

(B)    The consummation by the Company (whether directly involving the Company or indirectly involving the Company through one or more intermediaries) of (x) a merger, consolidation, reorganization, or business combination or (y) a sale or other disposition of all or substantially all of the Company’s assets or (z) the acquisition of assets or stock of another entity, in each case, other than a transaction which results in the Company’s voting securities outstanding immediately before the transaction continuing to represent (either by remaining outstanding or by being converted into voting securities of the Company or the person that, as a result of the transaction, controls, directly or indirectly, the Company or owns, directly or indirectly, all or substantially all of the Company’s assets or otherwise succeeds to the business of the Company (the Company or such person, the “Successor Entity”)) directly or indirectly, at least a majority of the combined voting power of the Successor Entity’s outstanding voting securities immediately after the transaction.

(b)    Termination by Company Without Cause or by Executive for Good Reason Following Change in Control. If at any time within two (2) years after a Change in Control, Executive’s employment is terminated by the Company without Cause or by Executive for Good Reason, then Executive shall be entitled to the payments and benefits provided in Section 7(a) hereof, subject to the terms and conditions thereof (including, without limitation, the requirement that a condition to Executive’s right to receive the amounts provided for thereunder is that Executive execute, deliver and not revoke the Release as set forth in Section 10 below), except that for purposes of this Section 7(b),

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the Severance Multiple shall equal 2. To the extent a Change in Control occurs as a result of the sale or other disposition of all or substantially all of the Company’s assets, then, on or prior to the closing date of such Change in Control, the Company shall deposit in an irrevocable grantor trust an amount of money equal to the severance payments and benefits that will be payable to Executive under this Section 7(b) in the event of a termination of employment by the Company without Cause or by Executive for Good Reason within two (2) years after such Change in Control; provided, that such grantor trust shall be designated to constitute an unfunded arrangement commonly referred to as a “rabbi trust” so that the Executive shall not be in constructive receipt of income or incur an economic benefit solely on account of the adoption or maintenance of the trust.

(a)    Termination by Company for Cause or by Executive Without Good Reason. If Executive’s employment is terminated by the Company for Cause or by Executive without Good Reason, the Company will pay Executive within thirty (30) days after the Date of Termination the Accrued Obligations; provided, however, the amounts described in Section 7(a)(i)(D) shall not be paid to Executive if Executive’s employment was terminated by the Company for Cause due to Executive’s misappropriation of Company funds.

(b)    Disability. During any period that Executive fails to perform Executive’s duties under this Agreement as a result of incapacity due to physical or mental illness, Executive will continue to receive his full Base Salary set forth in Section 4(a) until his employment is terminated pursuant to Section 5(b). If Executive’s employment is terminated due to Disability pursuant to Section 5(b), subject to Sections 7(f) and 10 below, the Company will pay Executive within thirty (30) days after the Date of Termination the Accrued Obligations, plus a pro rata share of the Annual Bonus for the fiscal year of the Company in which the Date of Termination occurs.

(c)    Death. If Executive’s employment is terminated by death, the Company will pay to Executive’s beneficiary, or personal or legal representatives or estate, as the case may be, within thirty (30) days after the Date of Termination the Accrued Obligations, plus a pro rata share of the Annual Bonus for the fiscal year of the Company in which the Date of Termination occurs.

(d)    Six-Month Delay. Notwithstanding anything to the contrary in this Agreement, no compensation or benefits, including without limitation any severance payments or benefits payable under Section 7 hereof, shall be paid to Executive during the six (6)-month period following Executive’s Separation from Service if the Company determines that paying such amounts at the time or times indicated in this Agreement would be a prohibited distribution under Section 409A(a)(2)(B)(i) of the Code. If the payment of any such amounts is delayed as a result of the previous sentence, then on the first business day following the end of such six (6)-month period (or such earlier date upon which such amount can be paid under Section 409A of the Code without resulting in a prohibited distribution, including as a result of Executive’s death), the Company shall pay Executive a lump-sum amount equal to the cumulative amount that would have otherwise been payable to Executive during such period.

8.    Mitigation. Executive will not be required to mitigate amounts payable under this Agreement by seeking other employment or otherwise, and there will be no offset against amounts due Executive under this Agreement on account of subsequent employment except as specifically provided herein.

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9.    Confidential Information; Non-Solicitation; Non-Competition.

(a)    Nondisclosure of Confidential Information. Executive acknowledges that it is the policy of the Company to maintain as secret and confidential (i) all valuable and unique information, (ii) other information heretofore or hereafter acquired by the Company, or any affiliated entity and deemed by it to be confidential, and (iii) information developed or used by the Company or any affiliated entity relating to the business, operations, employees and customers of the Company or any affiliated entity including, but not limited to, any employee information (all such information described in clauses (i), (ii) and (iii) above, other than information which is known to the public or becomes known to the public through no fault of Executive, is hereinafter referred to as “Confidential Information”). The parties recognize that the services to be performed by Executive pursuant to this Agreement are special and unique and that by reason of his employment by the Company after the date hereof, Executive has acquired and will acquire Confidential Information. Executive recognizes that all such Confidential Information is the property of the Company. Accordingly, at any time during or after the Term, Executive shall not, except in the proper performance of his duties under this Agreement, directly or indirectly, without the prior written consent of the Company, disclose to any Person other than the Company, whether or not such Person is a competitor of the Company, and shall use his best efforts to prevent the publication or disclosure of any Confidential Information obtained by, or which has come to the knowledge of, Executive prior or subsequent to the date hereof. Notwithstanding the foregoing, Executive may disclose to other Persons, as part of his occupation, information with respect to the Company or any affiliated entity, which (i) is of a type generally not considered by standards of the oil and natural gas industry to be proprietary, or (ii) is otherwise consented to in writing by the Company.

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(b)    Non-Solicitation. Executive shall not, during the Term or for the period of months equal to the product of 12 times the Severance Multiple following the Date of Termination (the “Covered Period”), either personally or by or through his/her agent or by letters, circulars or advertisements and whether for himself/herself or on behalf of any other person or entity, hire, solicit or seek to hire any employee or consultant of the Company or any affiliated entity, or in any other manner attempt, directly or indirectly, to persuade any such employee or consultant to discontinue his/her status of employment or consultancy with the Company or any affiliated entity or to become hired in any business or activities likely to be competitive with the Company’s or an affiliated entity’s business. Additionally, during the Covered Period, Executive shall not, for himself/herself or on behalf of any person or entity, directly or indirectly, solicit, divert or attempt to solicit or divert any customer of the Company or any affiliated entity for the purpose of causing such customer to reduce or refrain from doing any business with the Company or any affiliated entity. Executive further agrees that, during the Covered Period, he/she will not, directly or indirectly, request or advise any customers of the Company or an affiliated entity to withdraw, curtail or cancel their business with the Company or any affiliated entity. For purposes of this Agreement, a “customer” of the Company or any affiliated entity shall mean those customers of the Company or an affiliated entity who held a deposit account or otherwise transacted business with the Company or an affiliated entity at any time within the twelve (12) months preceding termination of Executive’s employment. Nothing contained in this Agreement is intended to prohibit general advertising or solicitation not specifically directed at any or all of the Company’s or an affiliated entity’s customers or employees.

(c)    Non-Competition.

(i)    As part of the consideration for the compensation and benefits to be paid to Executive hereunder, to protect the trade secrets and Confidential Information of the Company and its customers and clients that have been and will be entrusted to Executive, the business goodwill of the Company and its subsidiaries that will be developed in and through Executive and the business opportunities that will be disclosed or entrusted to Executive by the Company and its subsidiaries, and as an additional incentive for the Company to enter into this Agreement, during the Covered Period, Executive shall not directly or indirectly, individually or on behalf of any other person or entity, manage, participate in, work for, consult with, render services for, or take an interest in (as an owner, stockholder, partner or lender) any Competitor in an area of Competing Business.

(ii)    For purposes of Section 9(c)(i):

(A)    “Competitor” means any business, company or individual which is in, or is actively seeking to be in the Competing Business.

(B)    “Competing Business” means the acquisition, exploration, exploitation, development, production and/or operation of oil and gas properties.

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(iii)    Executive acknowledges that each of the covenants of Section 9(c)(i) are in addition to, and shall not be construed as a limitation upon, any other covenant provided in Section 9. Executive agrees that the scope of prohibited activities and time duration of each of the covenants set forth in Section 9(c)(i) are reasonable in nature and are no broader than are necessary to maintain the confidentiality and the goodwill of the Company’s proprietary and Confidential Information, plans and services and to protect the other legitimate business interests of the Company, including without limitation the goodwill developed by Executive with the Company’s customers, suppliers, licensees and business relations. It is also the intent of the Company and Executive that such covenants be construed and enforced in accordance with the changing activities, business and locations of the Company throughout the term of this covenant, whether before or after the Date of Termination. Executive agrees not to challenge the enforceability, scope or reasonableness of the covenants in Section 9(c)(i). The covenants in Section 9(c)(i) are severable and separate, and the unenforceability of any specific covenant shall not affect the provisions of any other covenant. Moreover, in the event any court of competent jurisdiction shall determine that the scope or duration set forth are unreasonable, then it is the intention of the parties that such restrictions be enforced to the fullest extent which the court deems reasonable, and the Agreement shall thereby be reformed.

(iv)    If, during any portion of the Covered Period, Executive is not in compliance with the terms of Section 9(c)(i), the Company shall be entitled to, among other remedies, compliance by Executive with the terms of Section 9(c)(i) for an additional period of time (i.e., in addition to the Covered Period) that shall equal the period(s) over which such noncompliance occurred.

(v)    Nothing in this Section 9(c) shall prohibit: (A) direct or indirect ownership of publicly traded securities which are issued by a Competitor involved in or conducting a Competing Business, provided that Executive, directly or indirectly, does not own more than 5% of the outstanding equity or voting securities of such Competitor; (B) ownership of royalty interests where Executive owns the surface of the land covered by the royalty interest and the ownership of the royalty interest is incidental to the ownership of such surface estate, provided that any such surface estate does not adjoin, or is not near to, any property ownership interest held directly or indirectly by the Company; (C) direct or indirect ownership of royalty interests or overriding royalty interests owned prior to the Effective Date; or (D) direct or indirect ownership of working interests or other interests in oil and gas owned prior to the Effective Date and disclosed by Executive to the Company in writing. It is the intent of the Company that during the Term of this Agreement Executive is not acquiring additional oil and gas interests, directly or indirectly.

(d)    Obligations of Executive Upon Termination. Upon termination of Executive’s employment for any reason, Executive shall return to the Company all documents and copies, including hard and electronic copies, of documents in his possession relating to any Confidential Information including, but not limited to, internal and external business forms, manuals, correspondence, notes and computer programs, and Executive shall not make or retain any copy or extract of any of the foregoing. In addition, Executive shall resign from all positions held with the Company or any affiliated entities.

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(e)    Remedies. Executive acknowledges and understands that Sections 9(a), (b), (c) and (d) and the other provisions of this Agreement are of a special and unique nature, the loss of which cannot be adequately compensated for in damages by an action at law, and that the breach or threatened breach of the provisions of this Agreement would cause the Company irreparable harm. In the event of a breach or threatened breach by Executive of the provisions of this Agreement, the Company shall be entitled to an injunction restraining him from such breach. Nothing contained in this Agreement shall be construed as prohibiting the Company from pursuing, or limiting the Company’s ability to pursue, any other remedies available for any breach or threatened breach of this Agreement by Executive. The provision of Section 12 hereof relating to arbitration of disputes shall not be applicable to the Company to the extent it seeks an injunction in any court to restrain Executive from violating Sections 9(a), (b), (c) and (d) hereof.

(f)    Continuing Operation. Except as specifically provided in this Section 9, the termination of Executive’s employment or of this Agreement will have no effect on the continuing operation of this Section 9.

(g)    Additional Related Agreements. Executive agrees to sign and to abide by the provisions of any additional agreements, policies or requirements of the Company which are reasonable and related to the subject of this Section 9 which are in writing and are developed by the Company in the ordinary course of business.

10.    Release. Notwithstanding any other provisions of this Agreement, it shall be a condition to Executive’s right to receive the amounts provided for in Section 7(a), 7(b) or 7(d) of this Agreement, that Executive will execute and deliver to the Company a release of claims in substantially the form attached hereto as Exhibit C (the “Release”) within twenty-one (21) days following the Date of Termination and that Executive not revoke such release within seven (7) days thereafter. The form of the Release may be modified as needed to reflect changes in the applicable law or regulations that are needed to provide a legally enforceable and binding Release to all parties at the time of execution.

11.    Indemnification and Insurance. Executive shall be indemnified and held harmless by the Company during the term of this Agreement and following any termination of this Agreement for any reason whatsoever in the same manner as would any other key management employee of the Company with respect to acts or omissions occurring prior to (a) the termination of this Agreement or (b) the termination of employment of Executive. In addition, during the term of this Agreement and for a period of six years following the termination of this Agreement for any reason whatsoever, Executive shall be covered by a Company held liability insurance policy, covering acts or omissions occurring prior to (i) the termination of this Agreement or (ii) the termination of employment of Executive.

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12.    Arbitration; Legal Fees and Expenses. The parties agree that Executive’s employment and this Agreement relate to interstate commerce, and that any disputes, claims or controversies between Executive and the Company which may arise out of or relate to Executive’s employment relationship or this Agreement shall be settled by arbitration. This agreement to arbitrate shall survive the termination of this Agreement. Any arbitration shall be in accordance with the Rules of the American Arbitration Association and undertaken pursuant to the Federal Arbitration Act. Arbitration will be held in Oklahoma City, Oklahoma unless the parties mutually agree on another location. The decision of the arbitrator(s) will be enforceable in any court of competent jurisdiction. The parties agree that punitive, liquidated or indirect damages shall not be awarded by the arbitrator(s) unless such damages would have been awarded by a court of competent jurisdiction. Nothing in this agreement to arbitrate, however, shall preclude the Company from obtaining injunctive relief from a court of competent jurisdiction prohibiting any ongoing breaches by Executive of this Agreement including, without limitation, violations of Section 9. If any contest or dispute arises between the Company and Executive regarding any provision of this Agreement, the arbitrator may award to the prevailing party, the reasonable attorney fees, costs and expenses incurred by the prevailing party in connection with such contest or dispute.

13.    Maximum Payments by the Company.

(a)    It is the objective of this Agreement to maximize Executive’s Net After-Tax Benefit (as defined herein) if payments or benefits provided under this Agreement are subject to excise tax under Section 4999 of the Code. Notwithstanding any other provisions of this Agreement, in the event that any payment or benefit by the Company or otherwise to or for the benefit of Executive, whether paid or payable or distributed or distributable pursuant to the terms of this Agreement or otherwise, including, by example and not by way of limitation, acceleration by the Company or otherwise of the date of vesting or payment or rate of payment under any plan, program, arrangement or agreement of the Company (all such payments and benefits, including the payments and benefits under Section 7 hereof, being hereinafter referred to as the “Total Payments”), would be subject (in whole or in part) to the excise tax imposed by Section 4999 of the Code (the “Excise Tax”), then the cash severance payments shall first be reduced, and the non-cash severance payments shall thereafter be reduced, to the extent necessary so that no portion of the Total Payments shall be subject to the Excise Tax, but only if (i) the net amount of such Total Payments, as so reduced (and after subtracting the net amount of federal, state and local income taxes on such reduced Total Payments and after taking into account the phase out of itemized deductions and personal exemptions attributable to such reduced Total Payments), is greater than or equal to (ii) the net amount of such Total Payments without such reduction (but after subtracting the net amount of federal, state and local income taxes on such Total Payments and the amount of Excise Tax to which Executive would be subject in respect of such unreduced Total Payments and after taking into account the phase out of itemized deductions and personal exemptions attributable to such unreduced Total Payments).

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(b)    The Total Payments shall be reduced by the Company in the following order: (i) reduction of any cash severance payments otherwise payable to Executive that are exempt from Section 409A of the Code, (ii) reduction of any other cash payments or benefits otherwise payable to Executive that are exempt from Section 409A of the Code, but excluding any payments attributable to the acceleration of vesting or payments with respect to any equity award with respect to the Company’s common stock that is exempt from Section 409A of the Code, (iii) reduction of any other payments or benefits otherwise payable to Executive on a pro-rata basis or such other manner that complies with Section 409A of the Code, but excluding any payments attributable to the acceleration of vesting and payments with respect to any equity award with respect to the Company’s common stock that are exempt from Section 409A of the Code, and (iv) reduction of any payments attributable to the acceleration of vesting or payments with respect to any other equity award with respect to the Company’s common stock that are exempt from Section 409A of the Code.

(c)    For purposes of determining whether and the extent to which the Total Payments will be subject to the Excise Tax, (i) no portion of the Total Payments the receipt or enjoyment of which Executive shall have waived at such time and in such manner as not to constitute a “payment” within the meaning of Section 280G(b) of the Code shall be taken into account, (ii) no portion of the Total Payments shall be taken into account which, in the written opinion of independent auditors of nationally recognized standing (“Independent Advisors”) selected by the Company, does not constitute a “parachute payment” within the meaning of Section 280G(b)(2) of the Code (including by reason of Section 280G(b)(4)(A) of the Code) and, in calculating the Excise Tax, no portion of such Total Payments shall be taken into account which, in the opinion of Independent Advisors, constitutes reasonable compensation for services actually rendered, within the meaning of Section 280G(b)(4)(B) of the Code, in excess of the “base amount” (as defined in Section 280G(b)(3) of the Code) allocable to such reasonable compensation, and (iii) the value of any non-cash benefit or any deferred payment or benefit included in the Total Payments shall be determined by the Independent Advisors in accordance with the principles of Sections 280G(d)(3) and (4) of the Code. The costs of obtaining such determination shall be borne by the Company.

14.    Agreement Binding on Successors.

(a)    Company’s Successors. No rights or obligations of the Company under this Agreement may be assigned or transferred except that the Company will require any successor (whether direct or indirect, by purchase, merger, reorganization, sale, transfer of stock, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company to expressly assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no succession had taken place. As used in this Agreement, “Company” means the Company as herein defined, and any successor to its or the Company’s business and/or assets (by merger, purchase or otherwise) which executes and delivers the agreement provided for in this Section 14 or which otherwise becomes bound by all the terms and provisions of this Agreement by operation of law.

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(b)    Executive’s Successors. No rights or obligations of Executive under this Agreement may be assigned or transferred by Executive other than his rights to payments or benefits under this Agreement, which may be transferred only by will or the laws of descent and distribution. Upon Executive’s death, this Agreement and all rights of Executive under this Agreement shall inure to the benefit of and be enforceable by Executive’s beneficiary, or personal or legal representatives, or estate, to the extent any such person succeeds to Executive’s interests under this Agreement. In the event of Executive’s death or a judicial determination of his incompetence, reference in this Agreement to Executive shall be deemed, where appropriate, to refer to his estate or other legal representative(s). If Executive should die following his Date of Termination while any amounts would still be payable to him under this Agreement if he had continued to live, unless otherwise provided, all such amounts shall be paid in accordance with the terms of this Agreement to his beneficiary or personal or legal representatives or estate.

15.    Notice. For the purposes of this Agreement, notices, demands and all other communications provided for in this Agreement shall be in writing and shall be deemed to have been duly given when delivered either personally or by United States certified or registered mail, return receipt requested, postage prepaid, addressed as follows:

If to Executive:

At his last known address

evidenced on the Company’s

payroll records.

If to the Company:

Chaparral Energy, Inc.

701 Cedar Lake Boulevard

Oklahoma City, OK 73114

or to such other address as any party may have furnished to the other in writing in accordance with this Agreement, except that notices of change of address shall be effective only upon receipt.

16.    Section 409A.

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(a)    To the extent applicable, this Agreement shall be interpreted in accordance with Section 409A of the Code and Department of Treasury regulations and other interpretative guidance issued thereunder, including without limitation any such regulations or other such guidance that may be issued after the Effective Date (“Section 409A”). Notwithstanding any provision of this Agreement to the contrary, in the event that following the Effective Date, the Company determines in good faith that any compensation or benefits payable under this Agreement may not be either exempt from or compliant with Section 409A, the Company shall adopt such amendments to this Agreement or adopt other policies or procedures (including amendments, policies and procedures with retroactive effective), or take any other commercially reasonable actions necessary or appropriate to (i) preserve the intended tax treatment of the compensation and benefits payable hereunder, to preserve the economic benefits of such compensation and benefits, and/or to avoid less favorable accounting or tax consequences for the Company and/or (ii) to exempt the compensation and benefits payable hereunder from Section 409A or to comply with the requirements of Section 409A and thereby avoid the application of penalty taxes thereunder; provided, however, that this Section 17(a) does not, and shall not be construed so as to, create any obligation on the part of the Company to adopt any such amendments, policies or procedures or to take any other such actions or to indemnify Executive for any failure to do so.

(b)    Notwithstanding anything herein to the contrary, Executive acknowledges and agrees that in the event that any tax is imposed under Section 409A in respect to any compensation or benefits payable to Executive, whether under this Agreement or otherwise, then (i) the payment of such tax shall be solely Executive’s responsibility, (ii) neither the Company, its affiliates nor any of their respective past or present directors, officers, employees or agents shall have any liability for any such tax and (iii) Executive shall indemnify and hold harmless, to the greatest extent permitted under law, each of the foregoing from and against any claims or liabilities that may arise in respect of any such tax.

(c)    To the extent that any of the rights or potential rights to future payments under the Change of Control Severance Agreement constitute “nonqualified deferred compensation” (within the meaning of Section 409A), if any, the termination of such rights is undertaken in accordance with and as permitted under Internal Revenue Code Treasury Regulation § 1.409A-3(j)(ix)(B).

17.    Withholding. All payments hereunder will be subject to any required withholding of federal, state and local taxes pursuant to any applicable law or regulation

18.    Miscellaneous. No provisions of this Agreement may be amended, modified, or waived unless agreed to in writing and signed by Executive and by a duly authorized officer of the Company. No waiver by either party of any breach by the other party of any condition or provision of this Agreement shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time. The respective rights and obligations of the parties under this Agreement shall survive Executive’s termination of employment and the termination of this Agreement to the extent necessary for the intended preservation of such rights and obligations. The validity, interpretation, construction and performance of this Agreement shall be governed by the laws of the State of Oklahoma without regard to its conflicts of law principles.

19.    Validity. The invalidity or unenforceability of any provision or provisions of this Agreement will not affect the validity or enforceability of any other provision of this Agreement, which will remain in full force and effect.

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20.    Counterparts. This Agreement may be executed in one or more counterparts, each of which will be deemed to be an original but all of which together will constitute one and the same instrument.

21.    Section Headings. The section headings in this Agreement are for convenience of reference only, and they form no part of this Agreement and will not affect its interpretation.

22.    Entire Agreement. Except as provided elsewhere herein and except for the other documents and agreements contemplated in accordance herewith, this Agreement sets forth the entire agreement of the parties with respect to its subject matter and supersedes all prior agreements, promises, covenants, arrangements, communications, representations or warranties, whether oral or written, by any officer, employee or representative of any party to this Agreement with respect to such subject matter, including, without limitation the Change of Control Severance Agreement.

23.    Further Assurances. The parties hereby agree, without further consideration, to execute and deliver such other instruments or to take such other action as may reasonably be required to effectuate the terms and provisions of this Agreement.

[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK]

16

LA\2083111.2

IN WITNESS WHEREOF, the parties have executed this Agreement effective the date first above written.

“COMPANY”

CHAPARRAL ENERGY, INC.

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

“EXECUTIVE”

/s/ Dave Winchester

Dave Winchester

17

LA\2083111.2

EX-10.2

J.P.Morgan

November 5, 2014

Chaparral Energy, Inc.

Chaparral Energy, L.L.C.

701 Cedar Lake Blvd.

Oklahoma City, Oklahoma 73114

Attention: Mark A. Fischer

Re: Eighth Restated Credit Agreement dated as of April 12, 2010 (as amended, the “Credit Agreement”) by and among Chaparral Energy, Inc., a Delaware corporation (“Parent”), Chaparral Energy, L.L.C., an Oklahoma limited liability company, the other Borrowers party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent (“Administrative Agent”), the other Agents party thereto and the Lenders from time to time a party thereto; capitalized terms used but not defined herein are used with the meanings assigned to them in the Credit Agreement.

Ladies and Gentlemen:

1.Borrowing Base. This letter agreement constitutes a New Borrowing Base Notice delivered pursuant to Section 2.07(e) of the Credit Agreement. Pursuant to Section 2.07 of the Credit Agreement, and subject to the satisfaction of the conditions precedent set forth in Section 3 below, the Lenders hereby agree that the Borrowing Base shall be increased from $484,500,000 to $650,000,000 effective as of November [5], 2014, and continuing until the next Scheduled Redetermination, Interim Redetermination, Optional Swap Unwind Redetermination, or other adjustment of the Borrowing Base, as applicable, pursuant to the terms of the Credit Agreement. The parties hereto agree that the redetermination of the Borrowing Base provided for in this Section 1 shall be the November 1, 2014 Scheduled Redetermination and shall not be deemed or construed to be an Interim Redetermination or Optional Swap Unwind Redetermination for purposes of Section 2.07 of the Credit Agreement.

2.Extension of the Specified Period. Reference is made to that certain Limited Consent and Fourteenth Amendment to Eighth Restated Credit Agreement dated as of May 19, 2014 by and among Parent, Borrowers, Administrative Agent and the Lenders (as amended by the August 2014 Letter Agreement (as defined below), the “Limited Consent”) and that certain Letter Agreement dated as of August 14, 2014 by and among Parent, Borrowers, Administrative Agent and the Lenders (the “August 2014 Letter Agreement”). In consideration of the agreements contained herein and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged and confessed, and subject to the satisfaction of the conditions precedent set forth in Section 3 below, the Lenders hereby (a) extend the Specified Period (as defined in the Limited

3042971v.4 CHA715/23015

Chaparral Energy, Inc.

Chaparral Energy, L.L.C.November 5, 2014
Page 2

Consent and as extended in the August 2014 Letter Agreement) until the effective date of the May 1, 2015 Scheduled Redetermination pursuant to Section 2.07 of the Credit Agreement and (b) provide their limited consent to the Temporary Hedging Noncompliance (as defined in the Limited Consent) for the Specified Period as so extended.

3.Conditions Precedent to Borrowing Base Increase, Extension of Specified Period and Limited Consent. The increase of the Borrowing Base provided for in Section 1 hereof and the extension of the Specified Period and the limited consent provided for in Section 2 hereof shall be subject to the occurrence of each of the following conditions precedent:

(a)The Administrative Agent shall have received counterparts hereof duly executed by Parent, each Borrower and each Lender;

(b)The Administrative Agent and J.P. Morgan Securities LLC shall have received all fees and other amounts due and payable on or prior to the effective date of the increase of the Borrowing Base provided for in Section 1 and the extension of the Specified Period provided for in Section 2, including, without limitation, the upfront fees described in clause (c) below; and

(c)The Administrative Agent shall have received, for the account of each Increasing Lender (as defined below), an upfront fee in an amount, for each such Increasing Lender, equal to 30 basis points (0.30%) of such Increasing Lender’s Increased Commitment (as defined below). As used herein, “Increasing Lender” means each Lender whose Commitment, after giving effect to Section 1 hereof, exceeds such Lender’s Commitment on December 18, 2013 (after giving effect to the increase in the Borrowing Base to $600,000,000 on such date) and “Increased Commitment” means the amount of such excess.

4.Representations and Warranties. To induce the Administrative Agent and Lenders to enter into this letter agreement, each Credit Party hereby represents and warrants to the Lenders and Administrative Agent as follows:

(a) Each representation and warranty of such Credit Party contained in the Credit Agreement and the other Loan Documents is true and correct on the date hereof, except to the extent any 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.

(b) After giving effect to the extension of the Specified Period as contemplated hereunder and in the August 2014 Letter Agreement, 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.

5.Reaffirmation of Loan Documents. Any and all of the terms and provisions of the Credit Agreement, the Limited Consent, the August 2014 Letter Agreement and the other Loan Documents shall, except as amended and modified hereby, remain in full force and effect. Nothing contained herein shall limit or impair any Liens securing the Indebtedness, each of which are hereby ratified, affirmed and extended to secure the Indebtedness as they may be increased pursuant hereto. Each

3042971v.4 CHA715/23015

Chaparral Energy, Inc.

Chaparral Energy, L.L.C.November 5, 2014
Page 3

Guarantor party hereto consents and agrees to this letter agreement, and each Credit Party agrees that the Loan Documents to which it is a party (including, without limitation, in the case of the Guarantors, the Guaranty Agreement) shall remain in full force and effect and shall continue to be the legal, valid and binding obligation of such Credit Party, enforceable against it in accordance with its terms.

6.No Other Waiver. Except as explicitly set forth in Section 2, nothing contained in this letter agreement shall be construed as a waiver by the Administrative Agent or any Lender of any covenant or provision of the Credit Agreement, the other Loan Documents or any other contract or instrument between any Credit Party and the Administrative Agent or any Lender, and the failure of the Administrative Agent or any Lender at any time or times hereafter to require strict performance by the Credit Parties of any provision thereof shall not waive, affect or diminish any right of the Administrative Agent to thereafter require strict compliance therewith. The Administrative Agent and the Lenders shall have no obligation to grant any future waivers, consents, extensions or amendments with respect to the Credit Agreement or any other Loan Document.

7.Miscellaneous. (a) Parent and Borrowers hereby jointly and severally agree to pay on demand all reasonable fees and expenses incurred by the Administrative Agent (including, without limitation, reasonable fees and expenses of counsel to the Administrative Agent) in connection with the preparation, negotiation and execution of this letter agreement and all related documents; (b) this letter agreement may be executed in counterparts, and all parties need not execute the same counterpart; however, no party shall be bound by this letter agreement until a counterpart hereof has been executed by Parent, Borrowers, the Administrative Agent and each of the Lenders, and facsimiles or other electronic transmission (e.g., pdf) shall be effective as originals; (c) THIS LETTER AGREEMENT REPRESENTS THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR ORAL AGREEMENTS OF THE PARTIES, AND THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE PARTIES; (d) this letter agreement constitutes a “Loan Document” under and as defined in Section 1.02 of the Credit Agreement; and (e) this letter agreement shall be governed by, and construed in accordance with, the laws of the State of New York.

Please evidence your agreement to each of the provisions of this letter agreement by executing a counterpart hereof where indicated and returning a fully executed counterpart to Clay Hufft, counsel for the Administrative Agent, via facsimile to (214) 999-7742 or electronic e-mail to chufft@velaw.com.

[SIGNATURE PAGES TO FOLLOW]

3042971v.4 CHA715/23015

JPMORGAN CHASE BANK, N.A.,

as Administrative Agent and a Lender

By:    /s/ Patrick McWilliams

Patrick McWilliams,

Authorized Officer

[SIGNATURE PAGE TO LETTER AGREEMENT – NOVEMBER, 2014 – CHAPARRAL ENERGY, L.L.C.]

CAPITAL ONE, NATIONAL ASSOCIATION,

as a Lender

By:    /s/ Nancy M. Mak

Name:    Nancy M. Mak    

Title:    Senior Vice President    

[SIGNATURE PAGE TO LETTER AGREEMENT – NOVEMBER, 2014 – CHAPARRAL ENERGY, L.L.C.]

ROYAL BANK OF CANADA,

as a Lender

By:    /s/ Mark Lumpkin, Jr.

Name:    Mark Lumpkin, Jr.    

Title:    Authorized Signatory    

[SIGNATURE PAGE TO LETTER AGREEMENT – NOVEMBER, 2014 – CHAPARRAL ENERGY, L.L.C.]

UBS AG, STAMFORD BRANCH,

as a Lender

By:    /s/ Lana Gifas

Name:    Lana Gifas    

Title:    Director    

By:    /s/ Jennifer Anderson

Name:    Jennifer Anderson    

Title:    Associate Director    

[SIGNATURE PAGE TO LETTER AGREEMENT – NOVEMBER, 2014 – CHAPARRAL ENERGY, L.L.C.]

CREDIT AGRICOLE CORPORATE AND INVESTMENT BANK,

as a Lender

By:    /s/ Mark Roche

Name:    Mark Roche    

Title:    Managing Director    

By:    /s/ Michael Willis

Name:    Michael Willis    

Title:    Managing Director    

[SIGNATURE PAGE TO LETTER AGREEMENT – NOVEMBER, 2014 – CHAPARRAL ENERGY, L.L.C.]

SOCIÉTÉ GÉNÉRALE,

as a Lender

By:    /s/ David Bornstein

Name:    David Bornstein    

Title:    Director    

[SIGNATURE PAGE TO LETTER AGREEMENT – NOVEMBER, 2014 – CHAPARRAL ENERGY, L.L.C.]

WELLS FARGO BANK, N.A.,

as a Lender

By:    /s/ Catherine Cook

Name:    Catherine Cook    

Title:    Director    

[SIGNATURE PAGE TO LETTER AGREEMENT – NOVEMBER, 2014 – CHAPARRAL ENERGY, L.L.C.]

THE BANK OF NOVA SCOTIA,

as a Lender

By:     /s/ Alan Dawson    

Name:    Alan Dawson    

Title:    Director    

[SIGNATURE PAGE TO LETTER AGREEMENT – NOVEMBER, 2014 – CHAPARRAL ENERGY, L.L.C.]

COMERICA BANK,

as a Lender

By:    /s/ Devin S. Eaton

Name:    Devin Eaton    

Title:    Relationship Manager    

[SIGNATURE PAGE TO LETTER AGREEMENT – NOVEMBER, 2014 – CHAPARRAL ENERGY, L.L.C.]

NATIXIS, NEW YORK BRANCH,

as a Lender

By:    /s/ Louis P. LaVille

Name:    Louis P. LaVille, III    

Title:    Managing Director    

By:     /s/ Stuart Murray

Name:    Stuart Murray    

Title:    Managing Director    

[SIGNATURE PAGE TO LETTER AGREEMENT – NOVEMBER, 2014 – CHAPARRAL ENERGY, L.L.C.]

AMEGY BANK NATIONAL ASSOCIATION,

as a Lender

By:    /s/ Larry L. Sears

Name:    Larry L. Sears    

Title:    Senior Vice President    

[SIGNATURE PAGE TO LETTER AGREEMENT – NOVEMBER, 2014 – CHAPARRAL ENERGY, L.L.C.]

COMPASS BANK,

as a Lender

By:    /s/ Kathleen J. Bowen

Name:    Kathleen J. Bowen    

Title:    Senior Vice Presideng    

[SIGNATURE PAGE TO LETTER AGREEMENT – NOVEMBER, 2014 – CHAPARRAL ENERGY, L.L.C.]

CREDIT SUISSE AG, CAYMAN ISLANDS BRANCH,

as a Lender

By:    /s/ Michael Spaight

Name:    Michael Spaight    

Title:    Authorized Signatory

By:     /s/ Remy Riester

Name: Remy Riester

Title:     Authorized Signatory

[SIGNATURE PAGE TO LETTER AGREEMENT – NOVEMBER, 2014 – CHAPARRAL ENERGY, L.L.C.]

KEYBANK NATIONAL ASSOCIATION,

as a Lender

By:    /s/ George E. McKean

Name:    George E. McKean    

Title:    Senior Vice President    

[SIGNATURE PAGE TO LETTER AGREEMENT – NOVEMBER, 2014 – CHAPARRAL ENERGY, L.L.C.]

MUFG UNION BANK, N.A.,

as a Lender

By:    /s/ Rachel Bowman

Name:    Rachel Bowman    

Title:    Vice President    

[SIGNATURE PAGE TO LETTER AGREEMENT – NOVEMBER, 2014 – CHAPARRAL ENERGY, L.L.C.]

U.S. BANK NATIONAL ASSOCIATION,

as a Lender

By:    /s/ Nicholas T. Hanford

Name:    Nicholas T. Hanford    

Title:    Vice President    

[SIGNATURE PAGE TO LETTER AGREEMENT – NOVEMBER, 2014 – CHAPARRAL ENERGY, L.L.C.]

GOLDMAN SACHS BANK USA,

as a Lender

By:    /s/ Rebecca Kratz

Name:    Rebecca Kratz    

Title:    Authorized Signatory    

[SIGNATURE PAGE TO LETTER AGREEMENT – NOVEMBER, 2014 – CHAPARRAL ENERGY, L.L.C.]

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 TO LETTER AGREEMENT – NOVEMBER, 2014 – CHAPARRAL ENERGY, L.L.C.]

EX-31.1

Exhibit 31.1

CERTIFICATION

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 12, 2014

/s/ Mark A. Fischer

Mark A. Fischer

Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

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 12, 2014

/s/ Joseph O. Evans

Joseph O. Evans

Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF PERIODIC REPORT

I, Mark A. Fischer, Chief Executive Officer of Chaparral Energy Inc. (the “Company”), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that, to the best of my knowledge:

(1) the Quarterly Report on Form 10-Q of the Company for the period ended September 30, 2014 (the “Report”) fully complies with the requirements of Section 13 (a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and

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

Date: November 12, 2014

/s/ Mark A. Fischer

Mark A. Fischer

Chief Executive Officer

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION OF PERIODIC REPORT

I, Joseph O. Evans, Chief Financial Officer of Chaparral Energy Inc. (the “Company”), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that, to the best of my knowledge:

(1) the Quarterly Report on Form 10-Q of the Company for the year ended September 30, 2014 (the “Report”) fully complies with the requirements of Section 13 (a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and

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

Date: November 12, 2014

/s/ Joseph O. Evans

Joseph O. Evans

Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Fair Value Measurements--Recurring Fair Value Measurements (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets, gross	$ 44,715		$ 13,113
Derivative assets, net	44,071		8,555
Derivative liabilities, gross	(917)		(12,792)
Derivative liabilities, net	(273)		(8,234)
Derivative assets (liabilities), net	43,798		321
Netting adjustments
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets, gross	(644)	[1]	(4,558)	[1]
Derivative liabilities, gross	644	[1]	4,558	[1]
Derivative assets (liabilities), net	0	[1]	0	[1]
Recurring Fair Value Measurements
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets, net	44,071		8,555
Derivative liabilities, net	(273)		(8,234)
Derivative assets (liabilities), net	43,798		321
Recurring Fair Value Measurements | Significant other observable inputs (Level 2)
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets, gross	12,067		3,275
Derivative liabilities, gross	(738)		(6,576)
Derivative assets (liabilities), net	11,329		(3,301)
Recurring Fair Value Measurements | Significant unobservable inputs (Level 3)
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets, gross	32,648		9,838
Derivative liabilities, gross	(179)		(6,216)
Derivative assets (liabilities), net	32,469		3,622
Recurring Fair Value Measurements | Netting adjustments
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets, gross	(644)	[2]	(4,558)	[2]
Derivative liabilities, gross	644	[2]	4,558	[2]
Derivative assets (liabilities), net	$ 0	[2]	$ 0	[2]

[1] Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with a counterparty are netted only to the extent that they relate to the same current versus noncurrent classification on the balance sheet.

[2] Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with a counterparty are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification.

XML

Stock-based compensation cost (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Stock-Based Compensation Expense [Abstract]
Stock-based compensation cost	$ 2,309	$ 2,045	$ 9,026	$ 4,620
Less: stock-based compensation cost capitalized	(289)	(505)	(2,735)	(1,440)
Stock-based compensation expense	2,020	1,540	6,291	3,180
Payments for stock-based compensation	699	135	2,787	1,433
Stock-based compensation costs included in accrued payroll and benefits payable	7,305		7,305		5,080
Unrecognized compensation cost	$ 19,982		$ 19,982
Years over which unrecognized compensation cost is expected to be recognized			2 years 3 months 1 day

XML

Stock-Based Compensation--Phantom Stock Plan and Restricted Stock Unit Plan (Details) (USD $) In Thousands, except Share data, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Phantom Stock Plan | Phantom Shares
Stock-Based Compensation [Line Items]
Award vesting period	5 years
Days from vesting date to cash settlement	120 days
Weighted average grant date fair value ($ per share)
Unvested and outstanding at beginning of period	$ 17.01
Granted	$ 0.00
Vested	$ 12.61
Forfeited	$ 19.54
Unvested and outstanding at end of period	$ 20.26
Shares
Unvested and outstanding at beginning of period (in shares)	53,162
Granted (in shares)	0
Vested (in shares)	(22,041)
Forfeited (in shares)	(6,223)
Unvested and outstanding at end of period (in shares)	24,898
Vest date fair value
Vest date fair value	$ 212
Non-Officer Restricted Stock Unit Plan | Restricted Stock Units (RSU)
Stock-Based Compensation [Line Items]
Days from vesting date to cash settlement	120 days
Maximum percentage of fair market value of the Company available for share-based awards	2.00%
Weighted average grant date fair value ($ per share)
Unvested and outstanding at beginning of period	$ 13.53
Granted	$ 8.52
Vested	$ 13.96
Forfeited	$ 9.85
Unvested and outstanding at end of period	$ 9.91
Shares
Unvested and outstanding at beginning of period (in shares)	325,297
Granted (in shares)	504,752
Vested (in shares)	(118,400)
Forfeited (in shares)	(105,214)
Unvested and outstanding at end of period (in shares)	606,435
Vest date fair value
Vest date fair value	1,094
Non-Officer Restricted Stock Unit Plan | Restricted Stock Units (RSU) | Maximum
Stock-Based Compensation [Line Items]
Award vesting period	3 years
Phantom Stock Plan And Restricted Stock Unit Plan | Phantom Stock and RSU
Vest date fair value
Estimated fair value per share at end of period	$ 13.76
Aggregate intrinsic value of unvested phantom shares and RSUs outstanding	$ 8,687

XML

Long-Term Debt--Components of Long-Term Debt (Details) (USD $) In Thousands, unless otherwise specified					9 Months Ended			9 Months Ended			9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014 9.875% Senior Notes due 2020	Dec. 31, 2013 9.875% Senior Notes due 2020	Sep. 30, 2014 9.875% Senior Notes due 2020 Senior Notes	Sep. 30, 2014 8.25% Senior Notes due 2021	Dec. 31, 2013 8.25% Senior Notes due 2021	Sep. 30, 2014 8.25% Senior Notes due 2021 Senior Notes	Sep. 30, 2014 7.625% Senior Notes due 2022	Dec. 31, 2013 7.625% Senior Notes due 2022	Sep. 30, 2014 7.625% Senior Notes due 2022 Senior Notes	Sep. 30, 2014 Minimum Mortgages	Sep. 30, 2014 Minimum Secured Debt	Sep. 30, 2014 Maximum Mortgages	Sep. 30, 2014 Maximum Secured Debt
Components of long-term debt
Senior Notes			$ 294,987	$ 294,556		$ 400,000	$ 400,000		$ 555,076	$ 555,719
Senior secured revolving credit facility	232,000	272,000
Real estate mortgage notes payable	10,832	11,202
Installment notes payable	5,032	5,235
Capital lease obligations	22,423	24,150
Total long-term debt and capital lease obligations	1,520,350	1,562,862
Less current maturities	5,677	5,334
Long-term debt and capital leases, less current maturities	1,514,673	1,557,528
Stated interest rate					9.875%			8.25%			7.625%	2.54%	2.85%	5.46%	5.95%
Maturity date (year)					2020			2021			2022
Maturity date (month and year)												2021-08	2014-10	2028-12	2018-02
Unamortized discount			5,013	5,444
Unamortized premium									$ 5,076	$ 5,719

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Stock-based compensation (Tables)

9 Months Ended

Sep. 30, 2014

Share-based Compensation [Abstract]

Rollforward of unvested stock-based compensation awards

A summary of our phantom stock and RSU activity during the nine months ended September 30, 2014 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, 2014	$	17.01	53,162				$	13.53	325,297
Granted	—		—				8.52		504,752
Vested	12.61		(22,041	)	$	212	13.96		(118,400	)	$	1,094
Forfeited	19.54		(6,223	)			9.85		(105,214	)
Unvested and outstanding at September 30, 2014	$	20.26	24,898				$	9.91	606,435

A summary of our restricted stock activity during the nine months ended September 30, 2014 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, 2014	$	634.67	19,246				$	307.45	46,701
Granted	818.50		5,245				204.90		10,033
Vested	649.18		(4,517	)	$	3,697	—		—
Forfeited	638.06		(1,399	)			338.51		(4,468	)
Unvested and total outstanding at September 30, 2014	$	682.80	18,575				$	285.11	52,266

Schedule of Share-based Compensation Arrangement by Share-based Payment Award, Performance-Based Units, Vested and Expected to Vest [Table Text Block]

Return on Investment Target	Target Shares Vested
175% per share	33% of shares multiplied by the Vesting Fraction
200% per share	33% of shares multiplied by the Vesting Fraction
250% per share	33% 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,
	2014			2013			2014			2013
Stock-based compensation cost	$	2,309		$	2,045		$	9,026		$	4,620
Less: stock-based compensation cost capitalized	(289		)	(505		)	(2,735		)	(1,440		)
Stock-based compensation expense	$	2,020		$	1,540		$	6,291		$	3,180

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Common stock (Details)	9 Months Ended				0 Months Ended				9 Months Ended				9 Months Ended						9 Months Ended
	Sep. 30, 2014 Common Stock		Sep. 30, 2014 Common Class A		Jan. 13, 2014 Common Class A Healthcare of Ontario Pension Plan Trust Fund	Jan. 13, 2014 Common Class A Class A Common Stock Converted from Class D and Class G Common Stock Healthcare of Ontario Pension Plan Trust Fund	Jan. 13, 2014 Common Class A Class A Common Stock Converted from Class B Common Stock Healthcare of Ontario Pension Plan Trust Fund		Sep. 30, 2014 Common Class B		Sep. 30, 2014 Common Class C	Dec. 31, 2013 Common Class C	Sep. 30, 2014 Common Class D		Sep. 30, 2014 Common Class E	Dec. 31, 2013 Common Class E	Sep. 30, 2014 Common Class F	Dec. 31, 2013 Common Class F	Sep. 30, 2014 Common Class G
Common stock rollforward
Shares outstanding at January 1, 2014	1,422,160		70,117						357,882		209,882	209,882	279,999		504,276	504,276	1	1	3
Stock transfers	0	[1]	293,023	[1]			13,023	[1]	(13,023)	[1]			(279,999)	[1]					(1)	[1]
Restricted stock issuances	15,278		15,278
Restricted stock repurchased	(1,810)		(1,810)
Restricted stock forfeitures	(5,867)		(5,867)
Shares outstanding at September 30, 2014	1,429,761		370,741						344,859		209,882	209,882	0		504,276	504,276	1	1	2
Company shares bought and sold by Company stockholders					15,078	280,000

[1] In this transaction, Healthcare of Ontario Pension Plan Trust Fund (“HOOPP”) purchased 280,000 shares of Class A common stock converted from Class D and Class G common stock held by CHK Energy Holdings, Inc. (“CHK Energy Holdings”) effective January 13, 2014. An additional 15,078 shares of Class A common stock was purchased by HOOPP from various other stockholders of which 13,023 shares were converted from Class B common stock.

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Fair Value Measurements--Fair Value of Other Financial Instruments (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Fair Value of Other Financial Instruments
Senior secured revolving credit facility	$ 232,000	$ 272,000
9.875% Senior Notes due 2020
Fair Value of Other Financial Instruments
Senior Notes	294,987	294,556
8.25% Senior Notes due 2021
Fair Value of Other Financial Instruments
Senior Notes	400,000	400,000
7.625% Senior Notes due 2022
Fair Value of Other Financial Instruments
Senior Notes	555,076	555,719
Significant other observable inputs (Level 2) | Carrying value
Fair Value of Other Financial Instruments
Senior secured revolving credit facility	232,000	272,000
Other secured long-term debt	15,864	16,437
Total long-term debt	1,497,927	1,538,712
Significant other observable inputs (Level 2) | Carrying value | 9.875% Senior Notes due 2020
Fair Value of Other Financial Instruments
Senior Notes	294,987	294,556
Significant other observable inputs (Level 2) | Carrying value | 8.25% Senior Notes due 2021
Fair Value of Other Financial Instruments
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
Senior Notes	555,076	555,719
Significant other observable inputs (Level 2) | Estimated fair value
Fair Value of Other Financial Instruments
Senior secured revolving credit facility	232,000	272,000
Other secured long-term debt	15,864	16,437
Total long-term debt	1,554,364	1,648,852
Significant other observable inputs (Level 2) | Estimated fair value | 9.875% Senior Notes due 2020
Fair Value of Other Financial Instruments
Senior Notes	321,000	340,140
Significant other observable inputs (Level 2) | Estimated fair value | 8.25% Senior Notes due 2021
Fair Value of Other Financial Instruments
Senior Notes	419,000	437,000
Significant other observable inputs (Level 2) | Estimated fair value | 7.625% Senior Notes due 2022
Fair Value of Other Financial Instruments
Senior Notes	$ 566,500	$ 583,275

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Derivative Instruments--Effect of Derivative Instruments on the Consolidated Balance Sheets (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Fair value of derivative instruments
Derivative assets, gross	$ 44,715		$ 13,113
Current derivative assets, net	27,797		2,152
Long-term derivative assets, net	16,274		6,403
Derivative liabilities, gross	(917)		(12,792)
Current derivative liabilities, net	(246)		(8,234)
Long-term derivative liabilities, net	(27)		0
Derivative assets (liabilities), net	43,798		321
Current derivative assets (liabilities), net	27,551		(6,082)
Long-term derivative assets (liabilities), net	16,247		6,403
Derivative settlements receivable	1,041		4,616
Derivative settlements payable	75		377
Oil Derivative | Swaps
Fair value of derivative instruments
Derivative assets, gross	5,472		112
Derivative liabilities, gross	0		(2,807)
Derivative assets (liabilities), net	5,472		(2,695)
Oil Derivative | Costless Collars
Fair value of derivative instruments
Derivative assets, gross	2,877		2,776
Derivative liabilities, gross	0		(4)
Derivative assets (liabilities), net	2,877		2,772
Oil Derivative | Enhanced Swaps
Fair value of derivative instruments
Derivative assets, gross	28,745		6,988
Derivative liabilities, gross	(179)		(6,212)
Derivative assets (liabilities), net	28,566		776
Oil Derivative | Purchased Puts
Fair value of derivative instruments
Derivative assets, gross	1,026		74
Derivative liabilities, gross	0		0
Derivative assets (liabilities), net	1,026		74
Natural Gas Derivative | Swaps
Fair value of derivative instruments
Derivative assets, gross	6,595		1,457
Derivative liabilities, gross	(216)		(3,706)
Derivative assets (liabilities), net	6,379		(2,249)
Natural Gas Derivative | Basis Protection Swaps
Fair value of derivative instruments
Derivative assets, gross	0		1,706
Derivative liabilities, gross	(522)		(63)
Derivative assets (liabilities), net	(522)		1,643
Netting adjustments
Fair value of derivative instruments
Derivative assets, gross	(644)	[1]	(4,558)	[1]
Derivative liabilities, gross	644	[1]	4,558	[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. Positive and negative positions with a counterparty are netted only to the extent that they relate to the same current versus noncurrent classification on the balance sheet.

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Commitments and contingencies (Details) (USD $) In Thousands, unless otherwise specified	1 Months Ended	9 Months Ended			1 Months Ended	9 Months Ended		1 Months Ended
	Aug. 09, 2012 court_case	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Jun. 07, 2011 Pending Litigation Minimum	Sep. 30, 2014 Letter of Credit	Sep. 30, 2013 Letter of Credit	Jun. 30, 2014 CO2 Compressor Lease	Sep. 30, 2014 CO2 Compressor
Loss Contingencies [Line Items]
Letters of credit outstanding		$ 920		$ 920
Interest paid		74,446	70,735			0	0
Damages sought					5,000
Number of court cases	2
Number of operating leases								2
Operating leases, future minimum payments due									$ 6,500

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Stock-Based Compensation--2010 Equity Incentive Plan (Details) (USD $) In Thousands, except Share data, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Maximum | Time Vested | 2010 Equity Incentive Plan | Restricted Stock
Stock-Based Compensation [Line Items]
Award vesting period	5 years
Common Class A
Vest date fair value
Restricted stock used for tax withholding	1,810
Common Class A | 2010 Equity Incentive Plan | Restricted Stock
Stock-Based Compensation [Line Items]
Shares reserved for issuance under the 2010 Plan	86,301
Common Class A | Time Vested | 2010 Equity Incentive Plan | Restricted Stock
Weighted average grant date fair value ($ per share)
Unvested and outstanding at beginning of period	$ 634.67
Granted	$ 818.50
Vested	$ 649.18
Forfeited	$ 638.06
Unvested and outstanding at end of period	$ 682.80
Shares
Unvested and outstanding at beginning of period (in shares)	19,246
Granted (in shares)	5,245
Vested (in shares)	(4,517)
Forfeited (in shares)	(1,399)
Unvested and outstanding at end of period (in shares)	18,575
Vest date fair value
Vest date fair value	$ 3,697
Restricted stock used for tax withholding	1,810	873
Shares expected to be repurchased during the next twelve months	2,000
Estimated fair value per share at end of period	$ 969.00
Aggregate intrinsic value of unvested Time Vested restricted shares outstanding	$ 17,999
Common Class A | Performance Vested | 2010 Equity Incentive Plan | Restricted Stock
Weighted average grant date fair value ($ per share)
Unvested and outstanding at beginning of period	$ 307.45
Granted	$ 204.90
Vested	$ 0.00
Forfeited	$ 338.51
Unvested and outstanding at end of period	$ 285.11
Shares
Unvested and outstanding at beginning of period (in shares)	46,701
Granted (in shares)	10,033
Vested (in shares)	0
Forfeited (in shares)	(4,468)
Unvested and outstanding at end of period (in shares)	52,266

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Acquisitions and divestitures

9 Months Ended

Sep. 30, 2014

Acquisitions and divestitures [Abstract]

Acquisitions and divestitures

Acquisitions and divestitures

During the second quarter of 2014, we closed on the sales of two of the five property packages that comprise our plan to divest our assets in Ark-La-Tex, Permian Basin, Gulf Coast, and North Texas. The five packages include: (i) our Fort Worth Basin package located in North Texas; (ii) our Delaware Basin package; (iii) our Central Basin Platform package; (iv) our Ark-La-Tex package; and (v) our Gulf Coast package. In May 2014, we sold our Fort Worth Basin package to Scout Energy Group I, LP, for cash proceeds of $23,702, net of post-closing adjustments, and we sold our Delaware Basin package to RKI Exploration & Production, LLC for cash proceeds of $124,717, net of post-closing adjustments.

During the third quarter of 2014, we closed on the sales of two additional property packages. Our Ark-La-Tex and Central Basin Platform property packages, both of which were sold to RAM Energy, LLC (“RAM”), closed in July 2014 for cash proceeds of $48,495 and $45,854, respectively. These proceeds are subject to post-closing adjustments. As these properties did not represent a material portion of our oil and natural gas reserves, individually or in the aggregate, we did not record any gain or loss on the sales and instead, reduced our full cost pool by the amount of the net proceeds without significant alteration to our depletion rate.

In addition to the packages discussed above, we had various other divestitures during the nine months ended September 30,2014, for cash proceeds of $22,215. These divestitures included properties predominantly located in Andrews County, Texas, which comprised part of our Permian Basin properties, and Osage County, Oklahoma.

In December 2013, we acquired certain oil and natural gas properties in the Panhandle Marmaton play from Cabot Oil & Gas Corporation (the “Cabot Acquisition”). The acquisition qualified as a business combination for accounting purposes and, as such, we estimated the fair value of the acquired properties as of the acquisition date and allocated the purchase price to the assets and liabilities acquired based on their fair values. During the second quarter of 2014, we finalized the post-closing adjustments related to the Cabot Acquisition with no material changes to the purchase price allocation.

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Fair Value Measurements--Counterparty Credit Risk (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014
Counterparty Credit Risk
Derivative liabilities subject to acceleration	$ 917
Concentration of Counterparty Credit Risk
Counterparty Credit Risk
Derivative contracts, number of counterparties	11
Derivative contracts, number of counterparties subject to offset under credit facility	10

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Nature of operations and summary of significant accounting policies Nature of Operations and Summary of Significant Accounting Policies--Inventories (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Inventory, Net [Abstract]
Equipment inventory	$ 22,503	$ 13,657
Commodities	2,433	3,186
Inventory valuation allowance	(911)	(706)
Inventories, net	$ 24,025	$ 16,137

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Nature of operations and summary of significant accounting policies Nature of Operations and Summary of Significant Accounting Policies--Cash and Accounts Receivable (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Cash and accounts receivable
Period within which joint interest accounts receivable are due	30 days
Period within which joint interest accounts receivable are past due	60 days
Components of accounts receivable
Joint interests	$ 36,644	$ 31,335
Accrued commodity sales	65,304	60,768
Derivative settlements	1,041	4,616
Production tax credit	2,703	694
Other	6,192	698
Allowance for doubtful accounts	(311)	(1,596)
Accounts receivable, net	111,573	96,515
JP Morgan Chase Bank, N.A.
Cash and accounts receivable
Cash held at JP Morgan Chase Bank, N. A.	$ 17,457

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Fair value measurements Fair Value Measurements--Derivatives Offset in the Consolidated Balance Sheets (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Fair Value Disclosures [Abstract]
Derivative assets, gross	$ 44,715		$ 13,113
Derivative assets, amount offset	(644)		(4,558)
Derivative assets	44,071		8,555
Derivative assets, not offset	0	[1]	(3,484)	[1]
Credit facility balance available to offset net derivative assets	(44,071)		(4,211)
Derivative assets, net of offsetting amounts outstanding under credit facility, not offset	0		860
Derivative liabilities, gross	(917)		(12,792)
Derivative liabilities, amounts offset	644		4,558
Derivative liabilities	273		8,234
Derivative liabilities, not offset	0	[1]	3,484	[1]
Derivative liabilities, net of offsetting amounts	(273)		(4,750)
Derivative assets (liabilities), net	43,798		321
Derivative assets (liabilities), net of offsetting amounts outstanding under credit facility, not offset	$ (273)		$ (3,890)

[1] Since positive and negative positions with a counterparty are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification, these represent remaining amounts that could have been offset under our master netting agreements.

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Nature of operations and summary of significant accounting policies Nature of Operations and Summary of Significant Accounting Policies--Oil and Natural Gas Properties (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Capitalized costs of unproved properties excluded from amortization
Capital costs for undeveloped acreage	$ 240,019	$ 196,227
CO2 Delivery Pipelines and Facilities
Capitalized costs of unproved properties excluded from amortization
Exploration and development costs excluded from amortization	72,046	115,828
Uncompleted Wells Equipment and Facilities
Capitalized costs of unproved properties excluded from amortization
Exploration and development costs excluded from amortization	$ 15,430	$ 9,422

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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, 2014	Sep. 30, 2013
Net cash provided by operating activities included:
Cash payments for interest	$ 74,446	$ 70,735
Interest capitalized	(9,957)	(11,670)
Cash payments for interest, net of amounts capitalized	64,489	59,065
Cash payments for income taxes	591	240
Non-cash investing activities included:
Asset retirement obligation additions and revisions	7,118	1,036
Oil and Natural Gas Properties Acquired Through Increase (Decrease) in Accounts Payable and Accrued Liabilities	$ 22,458	$ 8,298

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Supplemental disclosures to the consolidated statements of cash flows

9 Months Ended

Sep. 30, 2014

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,
	2014			2013
Net cash provided by operating activities included:
Cash payments for interest	$	74,446		$	70,735
Interest capitalized	(9,957		)	(11,670		)
Cash payments for interest, net of amounts capitalized	$	64,489		$	59,065
Cash payments for income taxes	$	591		$	240
Non-cash investing activities included:
Asset retirement obligation additions and revisions	$	7,118		$	1,036
Oil and natural gas properties acquired through increase in accounts payable and accrued liabilities	$	22,458		$	8,298

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Acquisitions and divestitures Acquisitions and Divestitures (Details) (USD $) In Thousands, unless otherwise specified	1 Months Ended		3 Months Ended	9 Months Ended
	Jul. 31, 2014 Divestiture	May 31, 2014 Divestiture	Sep. 30, 2014 Divestiture	Sep. 30, 2014 Divestiture
Significant Acquisitions and Disposals [Line Items]
Number of planned divestitures				5
Number of divestitures closed	2	2	2
Andrews County, TX and Osage County, OK
Significant Acquisitions and Disposals [Line Items]
Proceeds from sale				$ 22,215
Scout Energy Group I, LP | Fort Worth Basin
Significant Acquisitions and Disposals [Line Items]
Price Of Divested Properties		23,702
RKI Exploration And Production, LLC | Delaware Basin
Significant Acquisitions and Disposals [Line Items]
Price Of Divested Properties		124,717
RAM Energy, LLC | Ark-La-Tex
Significant Acquisitions and Disposals [Line Items]
Price Of Divested Properties	48,495
RAM Energy, LLC | Central Basin
Significant Acquisitions and Disposals [Line Items]
Price Of Divested Properties	$ 45,854

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Fair Value Measurements--Level 3 Rollforward (Details) (Recurring Fair Value Measurements, Significant unobservable inputs (Level 3), Derivative, USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Recurring Fair Value Measurements | Significant unobservable inputs (Level 3) | Derivative
Level 3 Rollforward
Beginning balance	$ 3,622	$ 26,231
Realized and unrealized gains (losses) included in non-hedge derivative losses	15,632	(18,198)
Purchases	1,220	664
Settlements paid (received)	11,995	(11,300)
Ending balance	32,469	(2,603)
Gains relating to instruments still held at the reporting date included in non-hedge derivative gains (losses) for the period	$ 24,156	$ 8,776

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Consolidated balance sheets (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Assets
Cash and cash equivalents	$ 19,712	$ 48,595
Accounts receivable, net	111,573	96,515
Inventories, net	24,025	16,137
Prepaid expenses	2,754	3,998
Derivative instruments	27,797	2,152
Deferred income taxes	0	9,260
Total current assets	185,861	176,657
Property and equipment—at cost, net	68,805	69,426
Oil and natural gas properties, using the full cost method:
Proved	3,512,036	3,258,661
Unevaluated (excluded from the amortization base)	327,495	321,477
Accumulated depreciation, depletion, amortization and impairment	(1,640,113)	(1,470,090)
Total oil and natural gas properties	2,199,418	2,110,048
Derivative instruments	16,274	6,403
Other assets	32,184	35,348
Total assets	2,502,542	2,397,882
Liabilities and stockholders' equity
Accounts payable and accrued liabilities	161,302	134,811
Accrued payroll and benefits payable	26,392	24,246
Accrued interest payable	33,661	24,225
Revenue distribution payable	30,583	25,138
Current maturities of long-term debt and capital leases	5,677	5,334
Derivative instruments	246	8,234
Deferred income taxes	2,128	0
Total current liabilities	259,989	221,988
Long-term debt and capital leases, less current maturities	1,514,673	1,557,528
Derivative instruments	27	0
Stock-based compensation	5,209	4,942
Asset retirement obligations and other	43,787	53,305
Deferred income taxes	98,361	62,855
Commitments and contingencies (Note 11)
Stockholders' equity:
Preferred stock, 600,000 shares authorized, none issued and outstanding	0	0
Additional paid in capital	428,124	424,377
Retained earnings	152,358	72,873
Total stockholders' equity	580,496	497,264
Total liabilities and stockholders' equity	2,502,542	2,397,882
Common Class A
Stockholders' equity:
Common stock	4	0
Common Class B
Stockholders' equity:
Common stock	3	4
Common Class C
Stockholders' equity:
Common stock	2	2
Common Class D
Stockholders' equity:
Common stock	0	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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Asset retirement obligations (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 55,179	$ 49,214
Liabilities incurred in current period	4,844	1,036
Liabilities settled and disposed in current period	(16,807)	(4,969)
Revisions in estimated cash flows	2,274	0
Accretion expense	2,991	2,968
Ending balance	48,481	48,249
Less current portion included in accounts payable and accrued liabilities	4,997	2,900
Asset retirement obligations, net of current portion	$ 43,484	$ 45,349

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Consolidated statements of cash flows (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Cash flows from operating activities
Net income	$ 79,485	$ 35,142
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion & amortization	180,631	139,439
Loss on impairment of other assets	0	1,090
Deferred income taxes	46,894	19,398
Gain on hedge reclassification adjustments	0	(28,544)
Non-hedge derivative (gains) losses	(17,218)	26,484
Gain on sale of assets	(1,007)	(556)
Other	3,033	3,395
Change in assets and liabilities
Accounts receivable	(14,442)	(20,858)
Inventories	(7,287)	(1,689)
Prepaid expenses and other assets	998	561
Accounts payable and accrued liabilities	(906)	17,694
Revenue distribution payable	5,446	5,181
Stock-based compensation	3,504	1,747
Net cash provided by operating activities	279,131	198,484
Cash flows from investing activities
Expenditures for property, plant, and equipment and oil and natural gas properties	(499,255)	(382,167)
Proceeds from asset dispositions	258,578	91,788
Settlement of non-hedge derivative instruments	(25,038)	13,097
Other	0	(664)
Net cash used in investing activities	(265,715)	(277,946)
Cash flows from financing activities
Proceeds from long-term debt	186,999	133,208
Repayment of long-term debt	(227,572)	(51,416)
Proceeds from Long-term Capital Lease Obligations	0	5,203
Principal payments under capital lease obligations	(1,726)	(38)
Net cash (used in) provided by financing activities	(42,299)	86,957
Net (decrease) increase in cash and cash equivalents	(28,883)	7,495
Cash and cash equivalents at beginning of period	48,595	29,819
Cash and cash equivalents at end of period	$ 19,712	$ 37,314

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Long-term debt Long-Term Debt--Capital Leases (Details) (U.S. Bank National Association, Capital Lease Obligations, USD $) In Thousands, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
U.S. Bank National Association | Capital Lease Obligations
Capital leases
Proceeds from sale leaseback		$ 24,500
Lease term	84 months
Purchase option period	72 months
Implicit interest rate	3.80%
Minimum lease payments	$ 3,181

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Derivative instruments (Tables)

9 Months Ended

Sep. 30, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Outstanding derivative instruments

The following table summarizes our crude oil derivatives outstanding as of September 30, 2014:

		Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls	Swaps		Sold puts		Purchased puts		Sold calls
2014
Swaps	187	$	93.13	$	—	$	—	$	—
Three-way collars	600	$	—	$	75.50	$	93.25	$	101.94
Enhanced swaps	210	$	97.58	$	80.00	$	—	$	—
Put spread enhanced swaps	745	$	93.87	$	80.00	$	60.00	$	—
Purchased puts (1)	210	$	—	$	—	$	60.00	$	—
2015
Swaps	600	$	96.02	$	—	$	—	$	—
Enhanced swaps	6,058	$	92.92	$	80.00	$	—	$	—
Purchased puts (1)	5,548	$	—	$	—	$	60.00	$	—
2016
Three-way collars	240	$	—	$	84.00	$	92.00	$	101.01
Enhanced swaps	3,720	$	92.94	$	80.52	$	—	$	—

___________

(1) Puts covering 840 Mbbls in 2014 were purchased during the second quarter of 2013 for $664. The 2015 puts were purchased during the second quarter of 2014 for $1,220.

The following tables summarize our natural gas derivative instruments outstanding as of September 30, 2014:

Period and type of contract	Volume BBtu	Weighted average fixed price per MMBtu
2014
Natural gas swaps	5,090	$	4.11
Natural gas basis protection swaps	5,200	$	0.24
2015
Natural gas swaps	22,170	$	4.20
Natural gas basis protection swaps	2,400	$	0.18
2016
Natural gas swaps	7,800	$	4.33

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, 2014								As of December 31, 2013
	Assets		Liabilities			Net value			Assets		Liabilities			Net value
Natural gas swaps	$	6,595	$	(216	)	$	6,379		$	1,457	$	(3,706	)	$	(2,249	)
Oil swaps	5,472		—			5,472			112		(2,807		)	(2,695		)
Oil collars	2,877		—			2,877			2,776		(4		)	2,772
Oil enhanced swaps	28,745		(179		)	28,566			6,988		(6,212		)	776
Oil purchased puts	1,026		—			1,026			74		—			74
Natural gas basis differential swaps	—		(522		)	(522		)	1,706		(63		)	1,643
Total derivative instruments	44,715		(917		)	43,798			13,113		(12,792		)	321
Less:
Netting adjustments (1)	644		(644		)	—			4,558		(4,558		)	—
Current portion asset (liability)	27,797		(246		)	27,551			2,152		(8,234		)	(6,082		)
	$	16,274	$	(27	)	$	16,247		$	6,403	$	—		$	6,403

___________

(1) Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with a counterparty are netted only to the extent that they relate to the same current versus noncurrent classification on the balance sheet.

Derivative settlements outstanding

Derivative settlements outstanding at September 30, 2014 and December 31, 2013 were as follows:

	September 30, 2014		December 31, 2013
Derivative settlements receivable included in accounts receivable	$	1,041	$	4,616
Derivative settlements payable included in accounts payable and accrued liabilities	$	75	$	377

Non-hedge derivative gains (losses) in the consolidated statements of operations

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

	Three months ended						Nine months ended
	September 30,						September 30,
	2014			2013			2014			2013
Change in fair value of commodity price swaps	$	20,039		$	(7,795	)	$	16,794		$	(12,115	)
Change in fair value of collars	6,870			(16,057		)	106			(22,795		)
Change in fair value of enhanced swaps and put options	80,717			(17,499		)	28,019			(6,703		)
Change in fair value of natural gas basis differential contracts	9			342			(2,165		)	2,032
Amortization of put premium	(166		)	—			(498		)	—
(Payments on) receipts from settlement of commodity price swaps	(1,030		)	(2,510		)	(12,653		)	2,327
(Payments on) receipts from settlement of collars	(77		)	(256		)	(1,338		)	11,300
Payments on settlement enhanced swaps	(1,664		)	—			(10,657		)	—
Payments on settlement of natural gas basis differential contracts	(285		)	(55		)	(390		)	(530		)
	$	104,413		$	(43,830	)	$	17,218		$	(26,484	)

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Derivative Instruments--Outstanding Derivatives (Details) (USD $) In Thousands, unless otherwise specified												3 Months Ended
	Sep. 30, 2014 Swaps Derivatives Maturing in 2014 Oil Derivative bbl	Sep. 30, 2014 Swaps Derivatives Maturing in 2014 Natural Gas Derivative MMBTU	Sep. 30, 2014 Swaps Derivatives Maturing in 2015 Oil Derivative bbl	Sep. 30, 2014 Swaps Derivatives Maturing in 2015 Natural Gas Derivative MMBTU	Sep. 30, 2014 Swaps Derivatives Maturing in 2016 Natural Gas Derivative MMBTU	Sep. 30, 2014 Costless Collars Derivatives Maturing in 2014 Oil Derivative bbl	Sep. 30, 2014 Costless Collars Derivatives Maturing in 2016 Oil Derivative bbl	Sep. 30, 2014 Enhanced Swaps Derivatives Maturing in 2014 Oil Derivative bbl	Sep. 30, 2014 Enhanced Swaps Derivatives Maturing in 2015 Oil Derivative bbl	Sep. 30, 2014 Enhanced Swaps Derivatives Maturing in 2016 Oil Derivative bbl	Sep. 30, 2014 Put Spread Enhanced Swaps Derivatives Maturing in 2014 Oil Derivative bbl	Jun. 30, 2014 Purchased Puts Oil Derivative	Jun. 30, 2013 Purchased Puts Oil Derivative	Sep. 30, 2014 Purchased Puts Derivatives Maturing in 2014 Oil Derivative bbl		Jun. 30, 2013 Purchased Puts Derivatives Maturing in 2014 Oil Derivative bbl	Sep. 30, 2014 Purchased Puts Derivatives Maturing in 2015 Oil Derivative bbl		Sep. 30, 2014 Basis Protection Swaps Derivatives Maturing in 2014 Natural Gas Derivative MMBTU	Sep. 30, 2014 Basis Protection Swaps Derivatives Maturing in 2015 Natural Gas Derivative MMBTU
Derivative [Line Items]
Volume of derivative instruments held	187,000	5,090,000	600,000	22,170,000	7,800,000	600,000	240,000	210,000	6,058,000	3,720,000	745,000			210,000	[1]	840,000	5,548,000	[1]	5,200,000	2,400,000
Weighted average fixed price per unit, swaps	93.13	4.11	96.02	4.20	4.33			97.58	92.92	92.94	93.87								0.24	0.18
Weighted average fixed price per Bbl, sold puts						75.50	84.00	80.00	80.00	80.52	80.00
Weighted average fixed price per Bbl, purchased puts						93.25	92.00				60.00			60.00	[1]		60.00	[1]
Weighted average fixed price per Bbl, sold calls						101.94	101.01
Premium paid for put options on commodity derivative contracts												$ 1,220	$ 664

[1] Puts covering 840 Mbbls in 2014 were purchased during the second quarter of 2013 for $664. The 2015 puts were purchased during the second quarter of 2014 for $1,220.

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Asset retirement obligations (Tables)

9 Months Ended

Sep. 30, 2014

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, 2014 and 2013.

	Nine months ended September 30,
	2014			2013
Beginning balance	$	55,179		$	49,214
Liabilities incurred in current period	4,844			1,036
Liabilities settled and disposed in current period	(16,807		)	(4,969		)
Revisions in estimated cash flows	2,274			—
Accretion expense	2,991			2,968
Ending balance	48,481			48,249
Less current portion included in accounts payable and accrued liabilities	4,997			2,900
	$	43,484		$	45,349

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Nature of operations and summary of significant accounting policies

9 Months Ended

Sep. 30, 2014

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 and Texas.

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, 2013.

The financial information as of September 30, 2014, and for the three and nine months ended September 30, 2014 and 2013, is unaudited. The financial information as of December 31, 2013 has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2013. 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, 2014 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2014.

Certain reclassifications have been made to prior period financial statements to conform to current period presentation. The reclassifications had no effect on our previously reported results of operations.

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, 2014, cash with a recorded balance totaling $17,457 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 establish our allowance for doubtful accounts 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. Recovered amounts previously written off are offset against the allowance and reduce expense in the year of recovery. Accounts receivable consisted of the following at September 30, 2014 and December 31, 2013:

	September 30, 2014			December 31, 2013
Joint interests	$	36,644		$	31,335
Accrued commodity sales	65,304			60,768
Derivative settlements	1,041			4,616
Production tax credit	2,703			694
Other	6,192			698
Allowance for doubtful accounts	(311		)	(1,596		)
	$	111,573		$	96,515

Inventories

Inventories are comprised of equipment used in developing oil and natural gas properties and oil and natural gas product 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. Inventories are shown net of a provision for obsolescence, commensurate with known or estimated exposure, which is reflected in the valuation allowance disclosed below. Inventories at September 30, 2014 and December 31, 2013 consisted of the following:

	September 30, 2014			December 31, 2013
Equipment inventory	$	22,503		$	13,657
Commodities	2,433			3,186
Inventory valuation allowance	(911		)	(706		)
	$	24,025		$	16,137

Oil and natural gas properties

Capitalized Costs. 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 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, 2014, include $240,019 of capital costs incurred for undeveloped acreage, $72,046 for the construction of CO₂ delivery pipelines and facilities for which there are no reserves, and $15,430 for wells and facilities in progress pending determination. As of December 31, 2013, work-in-progress costs included capital costs incurred of $196,227 for undeveloped acreage, $115,828 for the construction of CO₂ delivery pipelines and facilities for which there are no reserves, and $9,422 for wells and facilities in progress pending determination.

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties are provided using the units-of-production method based on estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. Our cost basis for depletion includes estimated future development costs to be incurred on proved undeveloped properties. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs, and the anticipated proceeds from salvaging equipment.

Ceiling Test. 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.

Our estimates of oil and natural gas reserves as of September 30, 2014 were prepared using an average price for oil and natural gas of each month for the prior twelve months as required by the SEC. The cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties as of September 30, 2014, and no ceiling test impairment was recorded.

A decline in oil and natural gas prices subsequent to September 30, 2014 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.

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 are 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 awards 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 equity per share on a minority, non-marketable basis 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. Compensation cost associated with restricted stock awards that include a market condition is recognized over the requisite service period using the straight-line method. The assumptions used to value our stock-based compensation awards reflect our best estimates, but they involve inherent uncertainties based on market conditions generally outside of our control. As a result, stock-based compensation expense could have been significantly impacted if other assumptions had been used.

The costs associated with our stock-based compensation programs 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.

Recently adopted accounting pronouncements

In July 2011, the Financial Accounting Standards Board (“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, which was effective and adopted by us in the first quarter of 2014, did not have a material impact on our financial statements and results of operations.

Recently issued accounting pronouncements

In May 2014, the FASB issued authoritative guidance that supersedes previous revenue recognition requirements and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This guidance is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. We are currently evaluating the effect the new standard will have on our financial statements and results of operations.

In August 2014, the FASB issued authoritative guidance that requires entities to evaluate whether there is substantial doubt about their ability to continue as a going concern and requires additional disclosures if certain criteria are met. This guidance is effective for fiscal periods after December 15, 2016 and interim periods thereafter. We do not expect this guidance to materially impact our financial statements or results of operations.

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Consolidated balance sheets (Parenthetical) (USD $)	Sep. 30, 2014	Dec. 31, 2013
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	370,741	70,117
Common stock, shares outstanding	370,741	70,117
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	344,859	357,882
Common stock, shares outstanding	344,859	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	0	279,999
Common stock, shares outstanding	0	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	2	3
Common stock, shares outstanding	2	3