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 March 31, 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: 333-187868

____________________________

Chaparral Energy, Inc.

(Exact name of registrant as specified in its charter)

 ____________________________

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

(405) 478-8770

(Registrant’s telephone number, including area code)

____________________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ¨    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 May 5, 2014:

Class	Number of shares
Class A Common Stock, $0.01 par value	366,685
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 March 31, 2014 (unaudited) and December 31, 2013	7
Consolidated statements of operations for the three months ended March 31, 2014 and 2013 (unaudited)	9
Consolidated statements of comprehensive income (loss) for the three months ended March 31, 2014 and 2013 (unaudited)	10
Consolidated statements of cash flows for the three months ended March 31, 2014 and 2013 (unaudited)	11
Condensed notes to consolidated financial statements (unaudited)	12
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	35
Non-GAAP financial measure and reconciliation	39
Critical accounting policies	39
Recent accounting pronouncements	39
Item 3. Quantitative and Qualitative Disclosures about Market Risk	40
Item 4. Controls and Procedures	43
Part II. OTHER INFORMATION	43
Item 1. Legal Proceedings	43
Item 1A. Risk Factors	44
Item 6. Exhibits	45
Signatures	46
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.

• Dry well or dry hole. An exploratory, development or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

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

• Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to produce oil or natural gas in another reservoir.

• 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.

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

• MMBoe. One million barrels of crude oil equivalent.

• MMBtu. One million British thermal units.

• MMcf. One million cubic feet of natural gas.

• 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.

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

• NYMEX. The New York Mercantile Exchange.

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

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

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

• SEC. The Securities and Exchange Commission.

5

• 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.

• Unit. The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

6

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets

	March 31, 2014			December 31, 2013
(dollars in thousands, except per share data)	(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	38,657		$	48,595
Accounts receivable, net	116,387			96,515
Inventories, net	22,078			16,137
Prepaid expenses	3,268			3,998
Derivative instruments	—			2,152
Deferred income taxes	15,599			9,260
Total current assets	195,989			176,657
Property and equipment—at cost, net	69,775			69,426
Oil and natural gas properties, using the full cost method:
Proved	3,372,416			3,258,661
Unevaluated (excluded from the amortization base)	346,372			321,477
Accumulated depreciation, depletion, amortization and impairment	(1,522,249		)	(1,470,090		)
Total oil and natural gas properties	2,196,539			2,110,048
Derivative instruments	2,847			6,403
Other assets	34,285			35,348
	$	2,499,435		$	2,397,882
The accompanying notes are an integral part of these consolidated financial statements.

7

Chaparral Energy, Inc. and subsidiaries Consolidated balance sheets—continued
	March 31, 2014		December 31, 2013
(dollars in thousands, except per share data)	(unaudited)
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	157,911	$	134,811
Accrued payroll and benefits payable	19,196		24,246
Accrued interest payable	33,441		24,225
Revenue distribution payable	23,458		25,138
Current maturities of long-term debt and capital leases	5,502		5,334
Derivative instruments	22,830		8,234
Total current liabilities	262,338		221,988
Long-term debt and capital leases, less current maturities	1,603,532		1,557,528
Derivative instruments	140		—
Stock-based compensation	3,514		4,942
Asset retirement obligations, net of current portion	54,348		53,305
Deferred income taxes	71,680		62,855
Commitments and contingencies (Note 10)
Stockholders’ equity:
Preferred stock, 600,000 shares authorized, none issued and outstanding	—		—
Class A Common stock, $0.01 par value, 10,000,000 shares authorized and 366,685 and 70,117 shares issued and outstanding as of March 31, 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 March 31, 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 March 31, 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 March 31, 2014 and December 31, 2013, respectively	—		—
Additional paid in capital	426,591		424,377
Retained earnings	77,278		72,873
	503,883		497,264
	$	2,499,435	$	2,397,882

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

8

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of operations

	Three months ended
	March 31,
	2014			2013
(in thousands)	(unaudited)			(unaudited)
Revenues:
Commodity sales	$	173,339		$	127,512
Gain from oil hedging activities	—			10,003
Total revenues	173,339			137,515
Costs and expenses:
Lease operating	35,021			33,977
Production taxes	6,643			7,880
Depreciation, depletion and amortization	55,750			43,916
General and administrative	13,387			14,008
Total costs and expenses	110,801			99,781
Operating income	62,538			37,734
Non-operating income (expense):
Interest expense	(26,459		)	(24,291		)
Non-hedge derivative losses	(29,199		)	(15,546		)
Other income, net	160			226
Net non-operating expense	(55,498		)	(39,611		)
Income (loss) before income taxes	7,040			(1,877		)
Income tax expense (benefit)	2,635			(687		)
Net income (loss)	$	4,405		$	(1,190	)

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

9

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of comprehensive income (loss)

	Three months ended
	March 31,
	2014		2013
(in thousands)	(unaudited)		(unaudited)
Net income (loss)	$	4,405	$	(1,190	)
Other comprehensive loss
Reclassification adjustment for hedge gains included in gain from oil hedging activities in the consolidated statements of operations	—		(10,003		)
Income tax benefit related to other comprehensive loss	—		3,818
Other comprehensive loss, net of tax	—		(6,185		)
Comprehensive income (loss)	$	4,405	$	(7,375	)

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

10

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows

	Three months ended
	March 31,
	2014			2013
(in thousands)	(unaudited)			(unaudited)
Cash flows from operating activities
Net income (loss)	$	4,405		$	(1,190	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion & amortization	55,750			43,916
Deferred income taxes	2,485			(746		)
Gain on hedge reclassification adjustments	—			(10,003		)
Non-hedge derivative losses	29,199			15,546
Gain on sale of assets	(84		)	(95		)
Other	492			1,197
Change in assets and liabilities
Accounts receivable	(15,762		)	(210		)
Inventories	(4,234		)	(4,985		)
Prepaid expenses and other assets	669			923
Accounts payable and accrued liabilities	2,303			1,879
Revenue distribution payable	(1,679		)	699
Stock-based compensation	695			1,245
Net cash provided by operating activities	74,239			48,176
Cash flows from investing activities
Expenditures for property, plant, and equipment	(138,669		)	(109,779		)
Proceeds from asset dispositions	16,997			6,833
Settlement of non-hedge derivative instruments	(8,755		)	9,896
Net cash used in investing activities	(130,427		)	(93,050		)
Cash flows from financing activities
Proceeds from long-term debt	50,603			24,868
Repayment of long-term debt	(3,783		)	(1,752		)
Principal payments under capital lease obligations	(570		)	—
Net cash provided by financing activities	46,250			23,116
Net decrease in cash and cash equivalents	(9,938		)	(21,758		)
Cash and cash equivalents at beginning of period	48,595			29,819
Cash and cash equivalents at end of period	$	38,657		$	8,061

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

11

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, Texas, New Mexico, Louisiana, Arkansas, and Kansas.

Interim financial statements

The accompanying unaudited consolidated interim financial statements of the Company have been prepared in accordance with the rules and regulations of the SEC and do not include all of the financial information and disclosures required by accounting principles generally accepted in the United States of America (“GAAP”) for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2013.

The financial information as of March 31, 2014, and for the three months ended March 31, 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 months ended March 31, 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 March 31, 2014, cash with a recorded balance totaling $36,695 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.

12

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. Bad debt expense was $(553) and $250 for the three months endedMarch 31, 2014 and 2013, respectively. Recovered amounts previously written off are offset against the allowance and reduce expense in the year of recovery. During the first quarter, we recovered $755 of amounts previously deemed uncollectible in conjunction with a settlement with the counterparty. Accounts receivable consisted of the following at March 31, 2014 and December 31, 2013:

	March 31, 2014			December 31, 2013
Joint interests	$	40,454		$	31,335
Accrued commodity sales	73,370			60,768
Derivative settlements	156			4,616
Other	2,913			1,392
Allowance for doubtful accounts	(506		)	(1,596		)
	$	116,387		$	96,515

Inventories

Inventories are comprised of equipment used in developing oil and natural gas properties, oil and natural gas product inventories, and equipment for resale. Inventory and equipment for resale are carried at the lower of cost or market using the average cost method. Oil and natural gas product inventories are stated at the lower of production cost or market. 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 March 31, 2014 and December 31, 2013 consisted of the following:

	March 31, 2014			December 31, 2013
Equipment inventory	$	19,437		$	13,657
Commodities	3,347			3,186
Inventory valuation allowance	(706		)	(706		)
	$	22,078		$	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 March 31, 2014, include $218,369 of capital costs incurred for undeveloped acreage, $117,018 for the construction of CO₂ delivery pipelines and facilities for which there are no reserves, and $10,985 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.

13

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

Divestitures and acquisitions.We have entered into three separate purchase and sale agreements (the “Agreements”) during April 2014 with Scout Energy Group I, LP, RKI Exploration & Production, LLC, and RAM Energy, LLC, whereby we will sell, in aggregate, our ownership interests in our Delaware Basin, Ft. Worth Basin and Arkansas-Louisiana-Texas (“Ark-La-Tex”) properties. Under the Agreements, the total sales price for the divested properties is approximately $201,150 subject to customary pre- and post-closing adjustments as described in the Agreements. The sale and purchase of the divested properties are expected to close in late May and June 2014 and are effective as of March 1, 2014. We have received a total of approximately $17,015 as performance deposits which will be applied to the various purchase prices at closing or released to us or the buyer(s), as the case may be, if a closing fails to occur and either the buyer(s) or we terminate the Agreements. Based on the amount of oil and natural gas reserves associated with these properties, we do not anticipate these divestitures to significantly alter the relationship between capitalized costs and proved reserves, and hence, do not expect to record any gain or loss upon the sale of the properties.

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.

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 March 31, 2014 were prepared using an average price for oil and natural gas of each month for the prior twelve months as required by the Securities Exchange Commission (“SEC”). The cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties as of March 31, 2014, and no ceiling test impairment was recorded.

A decline in oil and natural gas prices subsequent to March 31, 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.

14

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

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, if other assumptions had been used, stock-based compensation expense could have been significantly impacted.

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.

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

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

	Three months ended March 31,
	2014			2013
Net cash provided by operating activities included:
Cash payments for interest	$	18,794		$	16,787
Interest capitalized	(2,942		)	(3,628		)
Cash payments for interest, net of amounts capitalized	$	15,852		$	13,159
Non-cash investing activities included:
Asset retirement obligation additions and revisions	$	139		$	76
Oil and natural gas properties acquired through increase in accounts payable and accrued liabilities	$	18,629		$	18,502

15

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

Note 3: Long-term debt

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

	March 31, 2014		December 31, 2013
9.875% Senior Notes due 2020, net of discount of $5,304 and $5,444, respectively	$	294,695	$	294,556
8.25% Senior Notes due 2021	400,000		400,000
7.625% Senior Notes due 2022, including premium of $5,501 and $5,719, respectively	555,501		555,719
Senior secured revolving credit facility	319,000		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	11,081		11,202
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.85% to 5.99%, due April 2014 through February 2018 collateralized by automobiles, machinery and equipment	5,178		5,235
Capital lease obligations	23,579		24,150
	1,609,034		1,562,862
Less current maturities	5,502		5,334
	$	1,603,532	$	1,557,528

Senior Notes

The senior notes, which, as of March 31, 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 three months endedMarch 31, 2014, we had borrowings of $50,000 and repayments of $3,000 on our senior secured revolving credit facility. The increased borrowings were utilized to fund our capital expenditures and for general corporate purposes.

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. Effective April 22, 2014, our borrowing base was reaffirmed at $600,000.

We believe we were in compliance with all covenants under our senior secured revolving credit facility as of March 31, 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 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.

16

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

Note 4: Derivative instruments

Overview

Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into various types of derivative instruments, including commodity price swaps, 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 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.

17

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

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 March 31, 2014:

		Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls	Swaps		Sold puts		Purchased puts		Sold calls
2014
Swaps	581	$	92.30	$	—	$	—	$	—
Three-way collars	1,800	$	—	$	75.50	$	93.25	$	101.94
Enhanced swaps	630	$	98.24	$	80.00	$	—	$	—
Put spread enhanced swaps	2,072	$	93.85	$	80.00	$	60.00	$	—
Purchased puts	630	$	—	$	—	$	60.00	$	—
2015
Enhanced swaps	6,058	$	92.92	$	80.00	$	—	$	—

The following tables summarize our natural gas derivative instruments outstanding as of March 31, 2014:

Period and type of contract	Volume BBtu	Weighted average fixed price per MMBtu
2014
Natural gas swaps	15,640	$	4.01
Natural gas basis protection swaps	16,120	$	0.24
2015
Natural gas swaps	22,170	$	4.20
Natural gas basis protection swaps	2,400	$	0.18

18

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 5—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 March 31, 2014								As of December 31, 2013
	Assets		Liabilities			Net value			Assets		Liabilities			Net value
Natural gas swaps	$	665	$	(7,457	)	$	(6,792	)	$	1,457	$	(3,706	)	$	(2,249	)
Oil swaps	—		(3,345		)	(3,345		)	112		(2,807		)	(2,695		)
Oil collars	733		(824		)	(91		)	2,776		(4		)	2,772
Oil enhanced swaps	1,621		(11,308		)	(9,687		)	6,988		(6,212		)	776
Oil purchased puts	10		—			10			74		—			74
Natural gas basis differential swaps	71		(289		)	(218		)	1,706		(63		)	1,643
Total derivative instruments	3,100		(23,223		)	(20,123		)	13,113		(12,792		)	321
Less:
Netting adjustments (1)	253		(253		)	—			4,558		(4,558		)	—
Current portion asset (liability)	—		(22,830		)	(22,830		)	2,152		(8,234		)	(6,082		)
	$	2,847	$	(140	)	$	2,707		$	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 March 31, 2014 and December 31, 2013 were as follows:

	March 31, 2014		December 31, 2013
Derivative settlements receivable included in accounts receivable	$	156	$	4,616
Derivative settlements payable included in accounts payable and accrued liabilities	$	5,339	$	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.

19

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

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

	Three months ended
	March 31,
	2014			2013
Change in fair value of commodity price swaps	$	(5,193	)	$	(19,364	)
Change in fair value of collars	(2,863		)	(8,285		)
Change in fair value of enhanced swaps and put options	(10,361		)	2,031
Change in fair value of natural gas basis differential contracts	(1,861		)	176
Amortization of premium	(166		)	—
(Payments on) receipts from settlement of commodity price swaps	(5,850		)	4,525
(Payments on) receipts from settlement of collars	(41		)	5,731
(Payments on) receipts from settlement enhanced swaps	(1,992		)	—
Payments on settlement of natural gas basis differential contracts	(872		)	(360		)
	$	(29,199	)	$	(15,546	)

Note 5: Fair value measurements

Fair value is defined by the FASB as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.

Fair value measurements are categorized according to the fair value hierarchy defined by the FASB. The hierarchical levels are based upon the level of judgment associated with the inputs used to measure the fair value of the assets and liabilities as follows:

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

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

• Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability.

In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the asset or liability is categorized based on the lowest level input that is significant to the fair value measurement in its entirety. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Recurring fair value measurements

Our financial instruments recorded at fair value on a recurring basis consist of commodity derivative contracts (see Note 4—Derivative instruments). We have no Level 1 assets or liabilities as of March 31, 2014 or December 31, 2013. Our derivative contracts classified as Level 2 as of March 31, 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.

20

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

As of March 31, 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 discounted further using a rate that incorporates our nonperformance risk for derivative liabilities and our counterparties’ nonperformance risk for derivative assets. If available, we use our counterparties’ credit default swap values or the spread between the risk-free interest rate and the yield on our counterparties’ publicly traded debt having comparable maturities to our derivative contracts as the measure of our counterparties’ nonperformance risk. As of March 31, 2014 and December 31, 2013, the rate reflecting our nonperformance risk was 2.00% and 1.75%, respectively. The weighted average rate reflecting our counterparties’ nonperformance risk was approximately 0.25% and 0.31% as of March 31, 2014 and December 31, 2013, respectively.

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

	As of March 31, 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)	$	736		$	(11,091	)	$	(10,355	)	$	3,275		$	(6,576	)	$	(3,301	)
Significant unobservable inputs (Level 3)	2,364			(12,132		)	(9,768		)	9,838			(6,216		)	3,622
Netting adjustments (1)	(253		)	253			—			(4,558		)	4,558			—
	$	2,847		$	(22,970	)	$	(20,123	)	$	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.

Changes in the fair value of our derivative instruments classified as Level 3 in the fair value hierarchy during the three months ended March 31, 2014 and 2013 were: 

	Three months ended March 31,
Net derivative assets (liabilities)	2014			2013
Beginning balance	$	3,622		$	26,231
Realized and unrealized losses included in non-hedge derivative losses	(15,423		)	(523		)
Settlements paid (received)	2,033			(5,731		)
Ending balance	$	(9,768	)	$	19,977
(Losses) gains relating to instruments still held at the reporting date included in non-hedge derivative (losses) gains for the period	$	(15,324	)	$	1,393

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 three 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 5.80% and 6.40%, respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. During the three months ended March 31, 2014 and 2013, additions to our asset retirement obligations were $139 and $76, respectively. See Note 6—Asset retirement obligations for additional information regarding our asset retirement obligations.

21

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

Fair value of other financial instruments

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

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

	March 31, 2014				December 31, 2013
Level 2	Carrying value		Estimated fair value		Carrying value		Estimated fair value
9.875% Senior Notes due 2020	$	294,695	$	342,750	$	294,556	$	340,140
8.25% Senior Notes due 2021	400,000		437,872		400,000		437,000
7.625% Senior Notes due 2022	555,501		598,125		555,719		583,275
Senior secured revolving credit facility	319,000		319,000		272,000		272,000
Other secured long-term debt	16,259		16,259		16,437		16,437
	$	1,585,455	$	1,714,006	$	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 March 31, 2014, the counterparties to our open derivative contracts consisted of twelve financial institutions, of which eleven were subject to our rights of offset under our senior secured revolving credit facility.

22

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)			Amounts outstanding under senior secured revolving credit facility			Net amount
As of March 31, 2014
Derivative assets	$	3,100		$	(3,100	)	$	—		$	—		$	—
Derivative liabilities	(23,223		)	3,100			(20,123		)	—			(20,123		)
	$	(20,123	)	$	—		$	(20,123	)	$	—		$	(20,123	)
As of December 31, 2013
Derivative assets	$	13,113		$	(8,042	)	$	5,071		$	(4,211	)	$	860
Derivative liabilities	(12,792		)	8,042			(4,750		)	—			(4,750		)
	$	321		$	—		$	321		$	(4,211	)	$	(3,890	)

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 $23,223 at March 31, 2014.

Note 6: Asset retirement obligations

The following table provides a summary of our asset retirement obligation activity during the three months ended March 31, 2014 and 2013.

	Three months ended March 31,
	2014			2013
Beginning balance	$	55,179		$	49,214
Liabilities incurred in current period	139			76
Liabilities settled and disposed in current period	(170		)	(811		)
Accretion expense	1,074			1,007
Ending balance	56,222			49,486
Less current portion	1,874			2,900
	$	54,348		$	46,586

See Note 5—Fair value measurements for additional information regarding fair value measurements.

Note 7: Stock-based compensation

Phantom Stock Plan and Restricted Stock Unit Plan

Effective January 1, 2004, we implemented a Phantom Unit Plan, which was revised on December 31, 2008 as the Second Amended and Restated Phantom Stock Plan (the “Phantom Plan”), to provide deferred compensation to certain key employees (the “Participants”). 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.

23

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

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

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

A summary of our phantom stock and RSU activity during the three months ended March 31, 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	—		—				8.11		474,337
Vested	10.08		(15,996	)	$	128	14.52		(99,754	)	$	801
Forfeited	18.76		(897	)			13.08		(4,500	)
Unvested and outstanding at March 31, 2014	20.02		36,269				9.69		695,380

Based on an estimated fair value of $8.28 per phantom share and RSU as of March 31, 2014, the aggregate intrinsic value of the unvested phantom shares and RSUs outstanding was $6,058.

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). The Time Vested awards vest in equal annual installments over the five-year vesting period, but may also vest on an accelerated basis in the event of a Transaction (as defined in the 2010 Plan). The Performance Vested awards vest in the event of a Transaction that achieves certain market targets as defined in the 2010 Plan. Any shares of Performance Vested awards not vested on a Separation Date (as defined in the 2010 Plan) will be forfeited as of the Separation Date.

A summary of our restricted stock activity during the three months ended March 31, 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		1,615				204.90		2,998
Vested	633.14		(2,721	)	$	2,227	—		—
Unvested and total outstanding at March 31, 2014	651.27		18,140				301.26		49,699

24

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

During the three months ended March 31, 2014 and 2013, respectively, we repurchased and canceled 1,068 and 123 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 $818.50 per Time Vested restricted share, the aggregate intrinsic value of the unvested Time Vested restricted shares outstanding was $14,848 as of March 31, 2014.

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
	March 31,
	2014			2013
Stock-based compensation cost	$	2,531		$	1,893
Less: stock-based compensation cost capitalized	(962		)	(579		)
Stock-based compensation expense	$	1,569		$	1,314

Payments for stock-based compensation were $874 and $69 during the three months ended March 31, 2014 and 2013, respectively. As of March 31, 2014 and December 31, 2013, accrued payroll and benefits payable included $5,951 and $5,080, respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized compensation cost of approximately $19,103 is expected to be recognized over a weighted average period of 2.7 years.

Note 8: Common stock

The following is a summary of the changes in our common shares outstanding during the three months ended March 31, 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	4,613		—		—	—		—	—	—		4,613
Restricted stock repurchased	(1,068	)	—		—	—		—	—	—		(1,068	)
Shares outstanding at March 31, 2014	366,685		344,859		209,882	—		504,276	1	2		1,425,705

_______________

(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.

25

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

Note 9: 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
	March 31, 2013
Revenues	$	1,380
Joint interest billings	$	(923	)

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
	March 31, 2013
Revenues	$	(503	)
Joint interest billings	$	4,267

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.

Note 10: Commitments and contingencies

Standby letters of credit (“Letters”) available under our senior secured revolving credit facility are used in lieu of surety bonds with various organizations for liabilities relating to the operation of oil and natural gas properties. We had various Letters outstanding totaling $920 and $920 as of March 31, 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 three months ended March 31, 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 Plaintiff’s Motion for Class Certification is due August 10, 2014. Because a class has not been certified, we are not yet able to estimate a possible loss, or range of possible loss, if any.

26

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

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.

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.

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. Other than additional debt borrowings during the three months ended March 31, 2014, there were no material changes to our contractual commitments since December 31, 2013.

27

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.

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During the first quarter of 2014, production increased 15.5% to 2,591 MBoe compared to production of 2,243 MBoe during the first quarter of 2013, primarily due to our drilling activity. This increase in production, combined with a 17.7% increase in the average sales price before hedging, resulted in a 35.9% increase in revenue from commodity sales in the first quarter of 2014 compared to the same period in 2013. This increase was offset partially by a $13.7 million increase in our non-hedge derivative loss, which was primarily due to the significant volatility of oil and natural gas prices and to changes in our outstanding derivatives contracts during these periods. As a result of these and other factors, we reported net income of $4.4 million during the first quarter of 2014 compared to a net loss of $1.2 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 $625.0 million. Our capital expenditures during the three months ended March 31, 2014 were $155.6 million, consisting primarily of $86.6 million in drilling and completion expenditures in our E&P Areas, $36.0 million for our EOR Project Areas (excluding acquisitions) and $24.8 million for the acquisition of oil and gas properties and leasehold.

• During 2014, we have divested certain oil and gas properties for cash proceeds of approximately $20.7 million subject to post-closing adjustments which includes $2.5 million sold subsequent to March 31, 2014. The properties included in the sales accounted for approximately 0.4% and 0.6% of our total production during the three months ended March 31, 2014 and 2013, respectively.

• We executed three separate purchase and sale agreements in April 2014 to divest of our ownership positions in certain non-core properties for approximately $201.2 million in cash subject to pre- and post-closing adjustments. We received a total of approximately $17.0 million as performance deposits with the balance due upon closing, which is expected to occur during the second quarter of 2014. The properties included in these potential sales accounted for approximately 10.2% and 13.3% of our total production during the three months ended March 31, 2014 and 2013, respectively.

Results of operations

Production

Production volumes by area were as follows (MBoe):

	Three months ended		Percentage change
	March 31,
	2014	2013
E&P Areas
Mississippian	517	154	235.7	%
Panhandle Marmaton	186	20	830.0	%
Woodford Shale	30	37	(18.9	)%
Legacy Production Areas	824	977	(15.7	)%
Total E&P Areas	1,557	1,188	31.1	%
EOR Project Areas
Active EOR Projects	395	368	7.3	%
Potential EOR Projects	272	267	1.9	%
Total EOR Project Areas	667	635	5.0	%
Non-Core Properties	367	420	(12.6	)%
Total	2,591	2,243	15.5	%

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 project area increased primarily due to our drilling and development activity in our NOMP for the twelve months ended March 31, 2014. Production in our Panhandle Marmaton project area increased primarily due to our drilling and development activity for the twelve months ended March 31, 2014 and production from newly acquired fields, specifically our Cabot Acquisition in December 2013. Production in our Legacy Production Areas decreased primarily due to normal production decline concentrated in our Anadarko Granite Wash and Anadarko Cleveland Sand plays and strategic divestitures.

EOR Project Areas

Our EOR Project Areas include both currently Active EOR Projects and Potential EOR Properties with no current EOR production or reserves at March 31, 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 Area Unit offset partially by production decreases in our North Burbank Unit due to the expansion of our EOR floods in the area which caused existing production to be shut-in for a period while the field is being pressured up. We realized our first EOR production response from the North Burbank Unit in the fourth quarter of 2013 with a more significant response developing in March 2014. We anticipate production growth for this unit in the remainder of 2014 as we continue to develop the field.

Non-Core Properties

Our Non-Core Properties include our oil and natural gas properties in the Permian Basin, Ark-La-Tex, Gulf Coast and North Texas areas. Production decreases in our Non-Core Properties were primarily due to the natural production decline in wells producing during the last twelve months and strategic divestitures within these areas. These properties are included as part of an ongoing divestiture.

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				Percentage change
	March 31,
	2014		2013
Commodity sales (in thousands)
Oil	$	135,119	$	102,035	32.4	%
Natural gas	25,152		15,200		65.5	%
Natural gas liquids	13,068		10,277		27.2	%
Total commodity sales	$	173,339	$	127,512	35.9	%
Production
Oil (MBbls)	1,415		1,126		25.7	%
Natural gas (MMcf)	5,173		4,836		7.0	%
Natural gas liquids (MBbls)	314		311		1.0	%
MBoe	2,591		2,243		15.5	%
Average daily production (Boe/d)	28,793		24,928		15.5	%
Average sales prices (excluding derivative settlements)
Oil per Bbl	$	95.49	$	90.62	5.4	%
Natural gas per Mcf	$	4.86	$	3.14	54.8	%
NGLs per Bbl	$	41.62	$	33.05	25.9	%
Average sales price per Boe	$	66.90	$	56.85	17.7	%

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Our total commodity sales increased significantly during the three months ended March 31, 2014 as compared to the three months ended March 31, 2013 as a result of a 18% increase in the average price per Boe combined with a 16% increase in production volumes sold. Average production volumes sold increased by 3,865 Boe per day, or 16%, to 28,793 Boe per day during the three months ended March 31, 2014 compared to the three months ended March 31, 2013. The increase in average production volumes sold was primarily a result of our well completions during the twelve months ended March 31, 2014, offsetting the decline in production in wells that were producing as of March 31, 2013. Average daily production in our Mississippian and Panhandle Marmaton project areas increased by approximately 4,032 Boe per day and approximately 1,846 Boe per day, respectively, during the first quarter of 2014 compared to the first quarter of 2013 a result of our recent well completions. 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 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
	March 31, 2014 vs. 2013
(in thousands)	Sales change		Percentage change in sales
Change in oil sales due to:
Prices	$	6,896	6.7	%
Production	26,188		25.7	%
Total change in oil sales	$	33,084	32.4	%
Change in natural gas sales due to:
Prices	$	8,893	58.5	%
Production	1,059		7.0	%
Total change in natural gas sales	$	9,952	65.5	%
Change in natural gas liquids sales due to:
Prices	$	2,692	26.2	%
Production	99		1.0	%
Total change in natural gas liquids sales	$	2,791	27.2	%

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
	March 31,
	2014			2013
Oil (per Bbl)(1):
Before derivative settlements	$	85.71		$	78.16
After derivative settlements	$	83.86		$	82.55
Post-settlement to pre-settlement price	97.8		%	105.6		%
Natural gas (per Mcf):
Before derivative settlements	$	4.86		$	3.14
After derivative settlements	$	3.79		$	3.88
Post-settlement to pre-settlement price	78.0		%	123.6		%

___________

(1) Includes natural gas liquids.

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

(in thousands)	March 31, 2014			December 31, 2013
Derivative (liabilities) assets:
Natural gas swaps	$	(6,792	)	$	(2,249	)
Oil swaps	(3,345		)	(2,695		)
Oil collars	(91		)	2,772
Oil enhanced swaps	(9,687		)	776
Oil purchased puts	10			74
Natural gas basis differential swaps	(218		)	1,643
Net derivative (liabilities) assets	$	(20,123	)	$	321

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

	Three months ended March 31,
	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	$	—		$	—		$	10,003		$	—
Non-hedge derivative (losses) gains:
Oil swaps, collars, enhanced swaps and puts	$	(13,874	)	$	(3,194	)	$	(10,028	)	$	6,316
Natural gas swaps	(4,543		)	(4,689		)	(15,590		)	3,940
Natural gas basis differential contracts	(1,861		)	(872		)	176			(360		)
Amortization of premium put	(166		)	—			—			—
Non-hedge derivative (losses) gains	$	(20,444	)	$	(8,755	)	$	(25,442	)	$	9,896
Total (losses) gains from derivative activities	$	(20,444	)	$	(8,755	)	$	(15,439	)	$	9,896

We no longer apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as non-hedge derivative gains (losses) in the consolidated statements of operations.

Gain from oil hedging activities, which is a component of total revenues in the consolidated statements of operations, of $10.0 million for the three months ended March 31, 2013, consists of the reclassification of hedge gains on discontinued oil hedges from AOCI into net income.

32

We recognized net non-hedge derivative losses of $29.2 million during the three months ended March 31, 2014 compared to net non-hedge derivative losses of $15.5 million during the three months ended March 31, 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.

Total (losses) gains on derivative activities recognized in our consolidated statements of operations were $(29.2) million and $(5.5) million, respectively, during the three months ended March 31, 2014 and March 31, 2013.

Lease operating expenses 

	Three months ended March 31,				Percentage change
	2014		2013
Lease operating expenses (in thousands)	$	35,021	$	33,977	3.1	%
Lease operating expenses per Boe	$	13.52	$	15.15	(10.8	)%

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

Our lease operating expenses increased $1.0 million to $35.0 million during the three months ended March 31, 2014, compared to the three months ended March 31, 2013, primarily due to the incremental cost of oil field goods and services associated with net wells added, largely offset by decreased operating expenses due to the divestiture of certain non-core assets. Our lease operating expenses on a Boe basis, however, decreased to $13.52 during the three months ended March 31, 2014 from $15.15 during the three months ended March 31, 2013. The decrease of 11% on a Boe basis is primarily attributable to the increase in overall production volumes between periods and the divestiture of oil and gas properties with higher operating costs.

Production taxes (which include ad valorem taxes) 

	Three months ended March 31,				Percentage change
	2014		2013
Production taxes (in thousands)	$	6,643	$	7,880	(15.7	)%
Production taxes per Boe	$	2.56	$	3.51	(27.1	)%

Production taxes generally change in proportion to commodity sales. Our production taxes decreased 16% during the three months ended March 31, 2014 compared to the three months ended March 31, 2013 primarily due to EOR tax credits, partially offset by the 18% increase in averaged realized prices combined with the 16% increase in sales volumes. Production taxes per Boe during the three months ended March 31, 2014 decreased slightly compared to the three months ended March 31, 2013 primarily due to tax credits on our EOR wells, partially offset by the increase in averaged realized prices.

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

	Three months ended March 31,				Percentage change
	2014		2013
DD&A (in thousands):
Oil and natural gas properties	$	52,159	$	40,782	27.9	%
Property and equipment	2,517		2,127		18.3	%
Accretion of asset retirement obligation	1,074		1,007		6.7	%
Total DD&A	$	55,750	$	43,916	26.9	%
DD&A per Boe:
Oil and natural gas properties	$	20.13	$	18.18	10.7	%
Other fixed assets	$	1.39	$	1.40	(0.7	)%
Total DD&A per Boe	$	21.52	$	19.58	9.9	%

We adjust our DD&A rate on oil and natural gas properties each quarter for significant changes in our estimates of oil and natural gas reserves and costs, and thus our DD&A rate could change significantly in the future. DD&A on oil and natural gas properties increased $11.4 million for the three months ended March 31,2014 compared to the three months ended March 31, 2013, of which $5.1 million was due to a higher rate per equivalent unit of production and $6.3 million was due to an increase in production. Our DD&A rate per equivalent unit of production increased $1.95 to $20.13 per Boe for the three months ended March 31,2014 primarily due to higher estimated future development costs and higher cost reserve additions.

General and administrative expenses (“G&A”) 

	Three months ended March 31,						Percentage change
	2014			2013
G&A (in thousands):
Gross G&A expenses	$	20,140		$	19,005		6.0	%
Capitalized exploration and development costs	(6,753		)	(4,997		)	35.1	%
Net G&A expenses	$	13,387		$	14,008		(4.4	)%
Average G&A expense per Boe	$	5.17		$	6.25		(17.3	)%

G&A expenses for the three months ended March 31, 2014 increased 6% compared to the three months ended March 31, 2013 primarily due to higher compensation-related costs driven primarily from an increase in employee headcount and annual merit increases. Capitalized exploration and development costs increased between periods, primarily due to increased 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 decreased 17% for the three months ended March 31, 2014 compared to the same period in 2013 due primarily to the increase in overall production volumes between periods.

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Other income and expenses

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

	Three months ended
	March 31,
(in thousands)	2014			2013
9.875% Senior Notes due 2020	$	7,683		$	7,655
8.25% Senior Notes due 2021	8,416			8,402
7.625% Senior Notes due 2022	10,534			10,510
Senior secured revolving credit facility	1,419			127
Bank fees and other interest	1,349			1,225
Capitalized interest	(2,942		)	(3,628		)
Total interest expense	$	26,459		$	24,291
Average long-term borrowings	$	1,575,976		$	1,300,309

Total interest expense for the three months ended March 31, 2014 increased 9% compared to the same period in 2013 primarily due to increased levels of borrowing and a reduction in capitalized interest.

Liquidity and capital resources

Historically, our primary sources of liquidity have been cash generated from our operations, debt, and private equity sales. Our asset divestitures during 2013 and 2014 have recently provided us with an additional source of liquidity. As of March 31, 2014, we had cash and cash equivalents of $38.7 million and had borrowed $319.0 million under our senior secured revolving credit facility with a borrowing base of $600.0 million. As of May 5, 2014, outstanding borrowings under our senior secured revolving credit facility were $329.0 million with $270.1 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.

Sources and uses of cash

Our net decrease in cash is summarized as follows:

	Three months ended
	March 31,
(in thousands)	2014			2013
Cash flows provided by operating activities	$	74,239		$	48,176
Cash flows used in investing activities	(130,427		)	(93,050		)
Cash flows provided by financing activities	46,250			23,116
Net decrease in cash during the period	$	(9,938	)	$	(21,758	)

Substantially all of our cash flow from operating activities is from the production and sale of oil and natural gas. Cash flows from operating activities were $26.1 million or 54% higher in the three months ended March 31,2014 than they were in the same period of 2013 primarily due to the $45.8 million increase in commodity sales resulting from the 16% increase in production combined with the 18% increase in the average price per Boe. This increase was partially offset by changes in working capital primarily driven by an increase in accounts receivable.

We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. For the three months ended March 31, 2014 and 2013, cash flows provided by operating activities were approximately 54% and 44%, respectively, of cash used for the acquisition and development of our property.

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Our actual costs incurred, including costs that we have accrued for, during the three months ended March 31, 2014 and our budgeted 2014 capital expenditures for oil and natural gas properties are summarized in the following table:

(in thousands)	E&P Areas		EOR Project Areas		Non-Core Properties		Total		2014 Capital Expenditures Budget (1)(2)
Acquisitions	$	24,518	$	72	$	250	$	24,840	$	49,000
Drilling	86,646		11,521		2,425		100,592		434,000
Enhancements	5,206		12,915		538		18,659		71,000
Pipeline and field infrastructure	—		6,784		—		6,784		39,000
CO2 purchases	—		4,697		—		4,697		32,000
Total	$	116,370	$	35,989	$	3,213	$	155,572	$	625,000

___________

(1) Includes $168 million allocated to our EOR project areas as follows: drilling of $49 million, enhancements of $55 million, pipeline and field infrastructure of $32 million, and CO₂ purchases of $32 million.

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

We also received net proceeds of $17.0 million and $6.8 million during the three months ended March 31, 2014 and 2013, respectively, primarily from dispositions of certain non-strategic oil and natural gas properties and post-closing adjustments on previous dispositions.

During the three months ended March 31, 2014 and 2013, we (paid) received net derivative settlements totaling $(8.8) million and $9.9 million, respectively. Primarily as a result of our capital investments, asset dispositions and derivative settlements, cash flows used in investing activities were $130.4 million and $93.1 million during the three months ended March 31, 2014 and 2013, respectively.

Cash flows provided by financing activities were $46.3 million and $23.1 million during the three months ended March 31, 2014 and 2013, respectively, primarily due to net borrowings under our senior secured revolving credit facility. The borrowings were utilized to fund our capital expenditures and for general corporate purposes.

Indebtedness

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

	March 31, 2014		December 31, 2013
9.875% Senior Notes due 2020, net of discount of $5,304 and $5,444, respectively	$	294,695	$	294,556
8.25% Senior Notes due 2021	400,000		400,000
7.625% Senior Notes due 2022, including premium of $5,501 and $5,719, respectively	555,501		555,719
Senior secured revolving credit facility	319,000		272,000
Real estate mortgage notes	11,081		11,202
Installment notes	5,178		5,235
Capital lease obligations	23,579		24,150
	$	1,609,034	$	1,562,862

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Please see “Note 5—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. As of May 5, 2014, we have $329.0 million of outstanding borrowings under our 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 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. Effective April 22, 2014, our borrowing base was reaffirmed at $600.0 million; however, our borrowing base will be automatically reduced to $505 million upon closing the sale of our Delaware Basin, Ft. Worth Basin and Ark-La-Tex properties. We also expect the sale of the remaining two property packages to trigger a further reduction of the borrowing base upon closing to $478 million. During our next borrowing base redetermination, we can increase borrowing base capacity for new reserves added as a result of our increased drilling program, which is funded in part by the divestiture of these noncore properties. See “Asset divestitures and alternative capital sources” below for a discussion of our divestitures.

Our senior secured revolving credit facility requires us to maintain a current ratio, as defined in our senior secured revolving credit facility, of not less than 1.0 to 1.0. The definition of current assets and current liabilities used for determination of the current ratio computed for loan compliance purposes differs from current assets and current liabilities determined in compliance with GAAP. Since compliance with financial covenants is a material requirement under our senior secured revolving credit facility, we consider the current ratio calculated under our senior secured revolving credit facility to be a useful measure of our liquidity because it includes the funds available to us under our senior secured revolving credit facility and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. At March 31, 2014 and December 31, 2013, our current ratio as computed using GAAP was 0.75 and 0.80, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 1.96 and 2.35, respectively. The following table reconciles our current assets and current liabilities using GAAP to the same items for purposes of calculating the current ratio for our loan compliance: 

(dollars in thousands)	March 31, 2014			December 31, 2013
Current assets per GAAP	$	195,989		$	176,657
Plus—Availability under senior secured revolving credit facility	280,080			327,080
Less - Deferred tax asset on derivative instruments and asset retirement obligations	(9,247		)	(2,908		)
Less—Short-term derivative instruments	—			(2,152		)
Current assets as adjusted	$	466,822		$	498,677
Current liabilities per GAAP	$	262,338		$	221,988
Less—Short term derivative instruments	(22,830		)	(8,234		)
Less—Short-term asset retirement obligations	(1,874		)	(1,874		)
Current liabilities as adjusted	$	237,634		$	211,880
Current ratio for loan compliance	1.96			2.35

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 March 31, 2014, our availability under the senior secured revolving credit facility was limited to $280.1 million.

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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 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.

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. As part of this divestiture, we entered into three separate purchase and sale agreements (the “Agreements”) during April 2014 with Scout Energy Group I, LP, RKI Exploration & Production, LLC, and Ram Energy, LLC, whereby we will sell, in aggregate, our ownership interests in our Delaware Basin, Ft. Worth Basin and Ark-La-Tex properties. Under the Agreements, the total purchase price for the divested properties is approximately $201.2 million subject to customary pre- and post-closing adjustments as described in the Agreements.

The sale and purchase of the divested properties are expected to close in late May and June, 2014, and are effective as of March 1, 2014. We have received a total of approximately $17.0 million as performance deposits which will be applied to the various purchase prices at closing or released to us or the buyer(s), as the case may be, if a closing fails to occur and either the buyer(s) or we terminate the Agreements. Divestiture of the remaining two property packages is ongoing.

In addition to the three property packages discussed above, we also certain sold properties in Andrews County, Texas, and Osage County, Oklahoma, during 2014 for approximately $20.7 million, subject to post-closing adjustments.

Proceeds from the sales of our non-core oil and natural gas properties as well as the planned sale of the remaining two property packages will provide us with an additional source of liquidity which we plan to use for capital expenditures and 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. Other than additional debt borrowings during the three months ended March 31, 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 to adjusted EBITDA for the specified periods:

	Three months ended March 31,
(in thousands)	2014			2013
Net (loss) income	$	4,405		$	(1,190	)
Interest expense	26,459			24,291
Income tax (benefit) expense	2,635			(687		)
Depreciation, depletion, and amortization	55,750			43,916
Reclassification adjustment for hedge gains	—			(10,003		)
Non-cash change in fair value of non-hedge derivative instruments	20,278			25,442
Amortization of put premium	166			—
Interest income	(15		)	(96		)
Stock-based compensation expense	1,238			1,314
Gain on disposed assets	(84		)	(95		)
Adjusted EBITDA	$	110,832		$	82,892

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 three months ended March 31, 2014, our gross revenues from oil and natural gas sales would change approximately $1.7 million for each $1.00 change in oil and natural gas liquid prices and $0.5 million for each $0.10 change in natural gas prices.

To mitigate a portion of our exposure to fluctuations in commodity prices, we enter into various types of derivative instruments, including commodity price swaps, 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 anticipated 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 March 31, 2014 are summarized below:

		Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls	Swaps		Sold puts		Purchased puts		Sold calls
April - June 2014
Swaps	212	$	93.01	$	—	$	—	$	—
Three-way collars	600	$	—	$	75.50	$	93.25	$	101.94
Enhanced swaps	210	$	98.94	$	80.00	$	—	$	—
Put spread enhanced swaps	657	$	93.70	$	80.00	$	60.00	$	—
Purchased puts	210	$	—	$	—	$	60.00	$	—
July - September 2014
Swaps	208	$	91.93	$	—	$	—	$	—
Three-way collars	600	$	—	$	75.50	$	93.25	$	101.94
Enhanced swaps	210	$	98.20	$	80.00	$	—	$	—
Put spread enhanced swaps	670	$	93.99	$	80.00	$	60.00	$	—
Purchased puts	210	$	—	$	—	$	60.00	$	—
October - December 2014
Swaps	161	$	91.83	$	—	$	—	$	—
Three-way collars	600	$	—	$	75.50	$	93.25	$	101.94
Enhanced swaps	210	$	97.58	$	80.00	$	—	$	—
Put spread enhanced swaps	745	$	93.87	$	80.00	$	60.00	$	—
Purchased puts	210	$	—	$	—	$	60.00	$	—
January - March 2015
Enhanced swaps	1,535	$	93.27	$	80.00	$	—	$	—
April - June 2015
Enhanced swaps	1,583	$	93.29	$	80.00	$	—	$	—
July - September 2015
Enhanced swaps	1,470	$	92.55	$	80.00	$	—	$	—
October - December 2015
Enhanced swaps	1,470	$	92.55	$	80.00	$	—	$	—

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Our outstanding natural gas derivative instruments as of March 31, 2014 are summarized below:

Period and type of contract	Volume BBtu	Weighted average fixed price per MMBtu
April - June 2014
Natural gas swaps	5,360	$	3.95
Natural gas basis protection swaps	5,680	$	0.24
July - September 2014
Natural gas swaps	5,190	$	3.98
Natural gas basis protection swaps	5,240	$	0.24
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

Subsequent to March 31, 2014, we entered into crude oil enhanced swaps covering 600 MBbls for the period from January 2016 through December 2016 at fixed swap prices ranging from $90.25 to $91.10 per Bbl and a weighted average sold put price of $80 per Bbl. We also entered into natural gas swaps covering 3,000 BBtu for the period from January 2016 through December 2016 at fixed prices ranging from $4.14 to $4.54 per MMBtu.

Interest rates. All of the outstanding borrowings under our senior secured revolving facility as of March 31, 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 $600.0 million, equal to our borrowing base at March 31, 2014, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $6.0 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 March 31, 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 Plaintiff’s Motion for Class Certification is due August 10, 2014. Because a class has not been certified, we are not yet able to estimate a possible loss, or range of possible loss, if any.

Amanda Dodson, individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On May 10, 2013, Amanda Dodson (the “Plaintiff”), filed a complaint against us 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.

In our opinion, there are no other material pending legal proceedings to which we are a party or of which any of our property is the subject. However, due to the nature of our business, certain legal or administrative proceedings may arise from time to time in the ordinary course of business. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to have a material adverse effect on our financial condition, results of operations or cash flows.

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ITEM 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
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

45

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: May 9, 2014

46

EXHIBIT INDEX

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

47

EX-31.1

Exhibit 31.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER PURSUANT TO

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

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

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

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

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

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

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

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

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

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

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

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

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

Date: May 9, 2014

/s/ Mark A. Fischer

Mark A. Fischer

Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

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

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

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

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

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

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

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

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

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

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

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

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

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

Date: May 9, 2014

/s/ Joseph O. Evans

Joseph O. Evans

Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER

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

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Chaparral Energy, Inc. (the “Company”) on Form 10-Q for the period ending March 31, 2014 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Mark A. Fischer, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

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

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

/s/ Mark A. Fischer

Mark A. Fischer

Chief Executive Officer

Date: May 9, 2014

EX-32.2

Exhibit 32.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

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

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Chaparral Energy, Inc. (the “Company”) on Form 10-Q for the period ending March 31, 2014 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Joseph O. Evans, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

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

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

/s/ Joseph O. Evans

Joseph O. Evans

Chief Financial Officer

Date: May 9, 2014

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Fair Value Measurements--Nonrecurring Fair Value Measurements (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Nonrecurring Fair Value Measurements [Line Items]
Liabilities incurred in current period	$ 139	$ 76
Significant unobservable inputs (Level 3) | Nonrecurring fair value measurements
Nonrecurring Fair Value Measurements [Line Items]
Annual inflation rate	2.95%	2.95%
Credit-adjusted risk-free interest rate	5.80%	6.40%
Liabilities incurred in current period	$ 139	$ 76

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Related party transactions (Details) (USD $) In Thousands, unless otherwise specified			3 Months Ended
	Dec. 31, 2013 Chesapeake	Dec. 31, 2013 Chesapeake Holdings Corporation	Mar. 31, 2013 Properties Operated by Chesapeake	Mar. 31, 2013 Properties Operated by Chaparral
Related Party Transaction [Line Items]
Chaparral common stock owned by Chesapeake		20.00%
Revenue from jointly owned properties			$ 1,380	$ (503)
Joint interest billings			(923)	4,267
Amounts receivable from Chesapeake	466
Amounts payable to Chesapeake	$ 64

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Stock-based compensation cost (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Stock-Based Compensation Expense [Abstract]
Stock-based compensation cost	$ 2,531	$ 1,893
Less: stock-based compensation cost capitalized	(962)	(579)
Stock-based compensation expense	1,569	1,314
Payments for stock-based compensation	874	69
Stock-based compensation costs included in accrued payroll and benefits payable	5,951		5,080
Unrecognized compensation cost	$ 19,103
Years over which unrecognized compensation cost is expected to be recognized	2 years 8 months 10 days

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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	3 Months Ended
	Mar. 31, 2014
U.S. Bank National Association | Capital Lease Obligations
Debt Instrument [Line Items]
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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Common stock (Tables)

3 Months Ended

Mar. 31, 2014

Equity [Abstract]

Common stock rollforward

The following is a summary of the changes in our common shares outstanding during the three months ended March 31, 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	4,613		—		—	—		—	—	—		4,613
Restricted stock repurchased	(1,068	)	—		—	—		—	—	—		(1,068	)
Shares outstanding at March 31, 2014	366,685		344,859		209,882	—		504,276	1	2		1,425,705

_______________

(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 Measurements--Derivatives Offset in the Consolidated Balance Sheets (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Fair Value Disclosures [Abstract]
Derivative assets, gross	$ 3,100	$ 13,113
Derivative assets, amounts offset	(3,100)	(8,042)
Derivative assets, net of offsetting liabilities	0	5,071
Credit facility balance available to offset net derivative assets	0	(4,211)
Derivative assets, net of offsetting amounts outstanding under credit facility, not offset	0	860
Derivative liabilities, gross	(23,223)	(12,792)
Derivative liabilities, amounts offset	3,100	8,042
Derivative liabilities, net of offsetting amounts	(20,123)	(4,750)
Derivative assets (liabilities), net	(20,123)	321
Derivative assets (liabilities), net of offsetting amounts outstanding under credit facility, not offset	$ (20,123)	$ (3,890)

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Fair Value Measurements--Recurring Fair Value Measurements (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2014		Dec. 31, 2013
Fair Value Disclosures [Abstract]
Rate reflecting our nonperformance risk	2.00%		1.75%
Weighted-average rate reflecting our counterparties' nonperformance risk	0.25%		0.31%
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis [Line Items]
Derivative assets, gross	$ 3,100		$ 13,113
Derivative liabilities, gross	(23,223)		(12,792)
Derivative assets (liabilities), net	(20,123)		321
Netting adjustments
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis [Line Items]
Derivative assets, gross	(253)	[1]	(4,558)	[1]
Derivative liabilities, gross	253	[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 [Line Items]
Derivative assets, net	2,847		8,555
Derivative liabilities, net	(22,970)		(8,234)
Derivative assets (liabilities), net	(20,123)		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 [Line Items]
Derivative assets, gross	736		3,275
Derivative liabilities, gross	(11,091)		(6,576)
Derivative assets (liabilities), net	(10,355)		(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 [Line Items]
Derivative assets, gross	2,364		9,838
Derivative liabilities, gross	(12,132)		(6,216)
Derivative assets (liabilities), net	(9,768)		3,622
Recurring Fair Value Measurements | Netting adjustments
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis [Line Items]
Derivative assets, gross	(253)	[2]	(4,558)	[2]
Derivative liabilities, gross	253	[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.

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Common stock (Details)	3 Months Ended			3 Months Ended		0 Months Ended	3 Months Ended		0 Months Ended				3 Months Ended						3 Months Ended		0 Months Ended
	Mar. 31, 2014	Mar. 31, 2014 Common Stock	Dec. 31, 2013 Common Stock	Mar. 31, 2014 Common Class A		Jan. 13, 2014 Common Class A Healthcare of Ontario Pension Plan Trust Fund	Mar. 31, 2014 Common Class B		Jan. 13, 2014 Common Class B Healthcare of Ontario Pension Plan Trust Fund		Mar. 31, 2014 Common Class C	Dec. 31, 2013 Common Class C	Mar. 31, 2014 Common Class D		Mar. 31, 2014 Common Class E	Dec. 31, 2013 Common Class E	Mar. 31, 2014 Common Class F	Dec. 31, 2013 Common Class F	Mar. 31, 2014 Common Class G		Jan. 13, 2014 C H K Energy Holdings Inc. Common Class A Healthcare of Ontario Pension Plan Trust Fund
Common stock rollforward
Shares outstanding at January 1, 2014		1,425,705	1,422,160	70,117			357,882				209,882	209,882	279,999		504,276	504,276	1	1	3
Stock transfers				293,023	[1]		(13,023)	[1]	(13,023)	[1]			(279,999)	[1]					(1)	[1]
Restricted stock issuances	4,613			4,613
Restricted stock repurchased	(1,068)			(1,068)
Shares outstanding at March 31, 2014		1,425,705	1,422,160	366,685			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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Long-term debt

3 Months Ended

Mar. 31, 2014

Debt Disclosure [Abstract]

Long-term debt

Long-term debt

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

	March 31, 2014		December 31, 2013
9.875% Senior Notes due 2020, net of discount of $5,304 and $5,444, respectively	$	294,695	$	294,556
8.25% Senior Notes due 2021	400,000		400,000
7.625% Senior Notes due 2022, including premium of $5,501 and $5,719, respectively	555,501		555,719
Senior secured revolving credit facility	319,000		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	11,081		11,202
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.85% to 5.99%, due April 2014 through February 2018 collateralized by automobiles, machinery and equipment	5,178		5,235
Capital lease obligations	23,579		24,150
	1,609,034		1,562,862
Less current maturities	5,502		5,334
	$	1,603,532	$	1,557,528

Senior Notes

The senior notes, which, as of March 31, 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 three months endedMarch 31, 2014, we had borrowings of $50,000 and repayments of $3,000 on our senior secured revolving credit facility. The increased borrowings were utilized to fund our capital expenditures and for general corporate purposes.

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. Effective April 22, 2014, our borrowing base was reaffirmed at $600,000.

We believe we were in compliance with all covenants under our senior secured revolving credit facility as of March 31, 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 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.

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Asset retirement obligations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 55,179	$ 49,214
Liabilities incurred in current period	139	76
Liabilities settled and disposed in current period	(170)	(811)
Accretion expense	1,074	1,007
Ending balance	56,222	49,486
Less current portion	1,874	2,900
Asset retirement obligations, net of current portion	$ 54,348	$ 46,586	$ 53,305

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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			1 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Apr. 30, 2014 Subsequent Event Delaware Basin, Ft. Worth Basin, and Ark-La-Tex Scout Energy Group I, LP, RKI Exploration and Production, LLC, and RAM Energy, LLC contract	Mar. 31, 2014 Uncompleted Wells Equipment and Facilities	Dec. 31, 2013 Uncompleted Wells Equipment and Facilities	Mar. 31, 2014 CO2 Delivery Pipelines and Facilities	Dec. 31, 2013 CO2 Delivery Pipelines and Facilities
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Capital costs for undeveloped acreage	$ 218,369	$ 196,227
Exploration and development costs excluded from amortization				10,985	9,422	117,018	115,828
Number of purchase and sale agreements			3
Price of divested properties			201,150
Proceeds from performance deposits			$ 17,015

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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	Mar. 31, 2014	Dec. 31, 2013
Inventory, Net [Abstract]
Equipment inventory	$ 19,437	$ 13,657
Commodities	3,347	3,186
Inventory valuation allowance	(706)	(706)
Inventories, net	$ 22,078	$ 16,137

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Stock-Based Compensation--Phantom Stock Plan and Restricted Stock Unit Plan (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014
Phantom Stock Plan | Phantom Shares
Stock-Based Compensation [Line Items]
Award vesting period	5 years
Days from vesting date to cash settlement	120 days
Weighted average grant date fair value ($ per share)
Unvested and outstanding at beginning of period	$ 17.01
Granted	$ 0.00
Vested	$ 10.08
Forfeited	$ 18.76
Unvested and outstanding at end of period	$ 20.02
Shares
Unvested and outstanding at beginning of period (in shares)	53,162
Granted (in shares)	0
Vested (in shares)	(15,996)
Forfeited (in shares)	(897)
Unvested and outstanding at end of period (in shares)	36,269
Vest date fair value
Vest date fair value	$ 128
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	$ 8.11
Vested	$ 14.52
Forfeited	$ 13.08
Unvested and outstanding at end of period	$ 9.69
Shares
Unvested and outstanding at beginning of period (in shares)	325,297
Granted (in shares)	474,337
Vested (in shares)	(99,754)
Forfeited (in shares)	(4,500)
Unvested and outstanding at end of period (in shares)	695,380
Vest date fair value
Vest date fair value	801
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	$ 8.28
Aggregate intrinsic value of unvested phantom shares and RSUs outstanding	$ 6,058

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Supplemental Disclosures to the Consolidated Statements of Cash Flows (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Net cash provided by operating activities included:
Cash payments for interest	$ 18,794	$ 16,787
Interest capitalized	(2,942)	(3,628)
Cash payments for interest, net of amounts capitalized	15,852	13,159
Non-cash investing activities included:
Asset retirement obligation additions and revisions	139	76
Oil and natural gas properties acquired through increase in accounts payable and accrued liabilities	$ 18,629	$ 18,502

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Long-Term Debt--Components of Long-Term Debt (Details) (USD $) In Thousands, unless otherwise specified					3 Months Ended			3 Months Ended			3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014 9.875% Senior Notes due 2020	Dec. 31, 2013 9.875% Senior Notes due 2020	Mar. 31, 2014 9.875% Senior Notes due 2020 Senior Notes	Mar. 31, 2014 8.25% Senior Notes due 2021	Dec. 31, 2013 8.25% Senior Notes due 2021	Mar. 31, 2014 8.25% Senior Notes due 2021 Senior Notes	Mar. 31, 2014 7.625% Senior Notes due 2022	Dec. 31, 2013 7.625% Senior Notes due 2022	Mar. 31, 2014 7.625% Senior Notes due 2022 Senior Notes	Mar. 31, 2014 Minimum Mortgages	Mar. 31, 2014 Minimum Secured Debt	Mar. 31, 2014 Maximum Mortgages	Mar. 31, 2014 Maximum Secured Debt
Long-term debt [Abstract]
Senior Notes			$ 294,695	$ 294,556		$ 400,000	$ 400,000		$ 555,501	$ 555,719
Senior secured revolving credit facility	319,000	272,000
Real estate mortgage notes payable	11,081	11,202
Installment notes payable	5,178	5,235
Capital lease obligations	23,579	24,150
Total long-term debt and capital lease obligations	1,609,034	1,562,862
Less current maturities	5,502	5,334
Long-term debt and capital leases, less current maturities	1,603,532	1,557,528
Stated interest rate					9.875%			8.25%			7.625%	2.54%	2.85%	5.46%	5.99%
Maturity date (year)					2020			2021			2022
Maturity date (month and year)												2021-08	2014-04	2028-12	2018-02
Unamortized discount			5,304	5,444
Unamortized premium									$ 5,501	$ 5,719

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Supplemental disclosures to the consolidated statements of cash flows

3 Months Ended

Mar. 31, 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:

	Three months ended March 31,
	2014			2013
Net cash provided by operating activities included:
Cash payments for interest	$	18,794		$	16,787
Interest capitalized	(2,942		)	(3,628		)
Cash payments for interest, net of amounts capitalized	$	15,852		$	13,159
Non-cash investing activities included:
Asset retirement obligation additions and revisions	$	139		$	76
Oil and natural gas properties acquired through increase in accounts payable and accrued liabilities	$	18,629		$	18,502

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Long-Term Debt--Senior Secured Revolving Credit Facility (Details) (Line of Credit, USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Apr. 22, 2014 Subsequent Event
Line of Credit Facility [Line Items]
Maturity date	Nov. 01, 2017
Proceeds from senior secured revolving credit facility	$ 50,000
Repayments on senior secured revolving credit facility	3,000
Borrowing base amount		$ 600,000

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Fair Value Measurements--Fair Value of Other Financial Instruments (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Fair Value of Other Financial Instruments [Line Items]
Senior secured revolving credit facility	$ 319,000	$ 272,000
9.875% Senior Notes due 2020
Fair Value of Other Financial Instruments [Line Items]
Senior Notes	294,695	294,556
8.25% Senior Notes due 2021
Fair Value of Other Financial Instruments [Line Items]
Senior Notes	400,000	400,000
7.625% Senior Notes due 2022
Fair Value of Other Financial Instruments [Line Items]
Senior Notes	555,501	555,719
Significant other observable inputs (Level 2) | Carrying value
Fair Value of Other Financial Instruments [Line Items]
Senior secured revolving credit facility	319,000	272,000
Other secured long-term debt	16,259	16,437
Total long-term debt	1,585,455	1,538,712
Significant other observable inputs (Level 2) | Carrying value | 9.875% Senior Notes due 2020
Fair Value of Other Financial Instruments [Line Items]
Senior Notes	294,695	294,556
Significant other observable inputs (Level 2) | Carrying value | 8.25% Senior Notes due 2021
Fair Value of Other Financial Instruments [Line Items]
Senior Notes	400,000	400,000
Significant other observable inputs (Level 2) | Carrying value | 7.625% Senior Notes due 2022
Fair Value of Other Financial Instruments [Line Items]
Senior Notes	555,501	555,719
Significant other observable inputs (Level 2) | Estimated fair value
Fair Value of Other Financial Instruments [Line Items]
Senior secured revolving credit facility	319,000	272,000
Other secured long-term debt	16,259	16,437
Total long-term debt	1,714,006	1,648,852
Significant other observable inputs (Level 2) | Estimated fair value | 9.875% Senior Notes due 2020
Fair Value of Other Financial Instruments [Line Items]
Senior Notes	342,750	340,140
Significant other observable inputs (Level 2) | Estimated fair value | 8.25% Senior Notes due 2021
Fair Value of Other Financial Instruments [Line Items]
Senior Notes	437,872	437,000
Significant other observable inputs (Level 2) | Estimated fair value | 7.625% Senior Notes due 2022
Fair Value of Other Financial Instruments [Line Items]
Senior Notes	$ 598,125	$ 583,275

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Consolidated balance sheets (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Assets
Cash and cash equivalents	$ 38,657	$ 48,595
Accounts receivable, net	116,387	96,515
Inventories, net	22,078	16,137
Prepaid expenses	3,268	3,998
Derivative instruments	0	2,152
Deferred income taxes	15,599	9,260
Total current assets	195,989	176,657
Property and equipment—at cost, net	69,775	69,426
Oil and natural gas properties, using the full cost method:
Proved	3,372,416	3,258,661
Unevaluated (excluded from the amortization base)	346,372	321,477
Accumulated depreciation, depletion, amortization and impairment	(1,522,249)	(1,470,090)
Total oil and natural gas properties	2,196,539	2,110,048
Derivative instruments	2,847	6,403
Other assets	34,285	35,348
Total assets	2,499,435	2,397,882
Liabilities and stockholders' equity
Accounts payable and accrued liabilities	157,911	134,811
Accrued payroll and benefits payable	19,196	24,246
Accrued interest payable	33,441	24,225
Revenue distribution payable	23,458	25,138
Current maturities of long-term debt and capital leases	5,502	5,334
Derivative instruments	22,830	8,234
Total current liabilities	262,338	221,988
Long-term debt and capital leases, less current maturities	1,603,532	1,557,528
Derivative instruments	140	0
Stock-based compensation	3,514	4,942
Asset retirement obligations, net of current portion	54,348	53,305
Deferred income taxes	71,680	62,855
Commitments and contingencies (Note 10)
Stockholders' equity:
Preferred stock, 600,000 shares authorized, none issued and outstanding	0	0
Additional paid in capital	426,591	424,377
Retained earnings	77,278	72,873
Total stockholders' equity	503,883	497,264
Total liabilities and stockholders' equity	2,499,435	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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Stock-Based Compensation--2010 Equity Incentive Plan (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Vest date fair value
Restricted stock used for tax withholding	1,068
Maximum | Time Vested | 2010 Equity Incentive Plan | Restricted Stock
Stock-Based Compensation [Line Items]
Award vesting period	5 years
Common Class A
Vest date fair value
Restricted stock used for tax withholding	1,068
Common Class A | 2010 Equity Incentive Plan | Restricted Stock
Stock-Based Compensation [Line Items]
Shares reserved for issuance under the 2010 Plan	86,301
Common Class A | Time Vested | 2010 Equity Incentive Plan | Restricted Stock
Weighted average grant date fair value ($ per share)
Unvested and outstanding at beginning of period	$ 634.67
Granted	$ 818.50
Vested	$ 633.14
Unvested and outstanding at end of period	$ 651.27
Shares
Unvested and outstanding at beginning of period (in shares)	19,246
Granted (in shares)	1,615
Vested (in shares)	(2,721)
Unvested and outstanding at end of period (in shares)	18,140
Vest date fair value
Vest date fair value	$ 2,227
Restricted stock used for tax withholding	1,068	123
Shares expected to be repurchased during the next twelve months	2,000
Estimated fair value per share at end of period	$ 818.50
Aggregate intrinsic value of unvested Time Vested restricted shares outstanding	$ 14,848
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
Unvested and outstanding at end of period	$ 301.26
Shares
Unvested and outstanding at beginning of period (in shares)	46,701
Granted (in shares)	2,998
Vested (in shares)	0
Unvested and outstanding at end of period (in shares)	49,699

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Consolidated statements of cash flows (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Cash flows from operating activities
Net income (loss)	$ 4,405	$ (1,190)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion & amortization	55,750	43,916
Deferred income taxes	2,485	(746)
Gain on hedge reclassification adjustments	0	(10,003)
Non-hedge derivative losses	29,199	15,546
Gain on sale of assets	(84)	(95)
Other	492	1,197
Change in assets and liabilities
Accounts receivable	(15,762)	(210)
Inventories	(4,234)	(4,985)
Prepaid expenses and other assets	669	923
Accounts payable and accrued liabilities	2,303	1,879
Revenue distribution payable	(1,679)	699
Stock-based compensation	695	1,245
Net cash provided by operating activities	74,239	48,176
Cash flows from investing activities
Expenditures for property, plant, and equipment	(138,669)	(109,779)
Proceeds from asset dispositions	16,997	6,833
Settlement of non-hedge derivative instruments	(8,755)	9,896
Net cash used in investing activities	(130,427)	(93,050)
Cash flows from financing activities
Proceeds from long-term debt	50,603	24,868
Repayment of long-term debt	(3,783)	(1,752)
Principal payments under capital lease obligations	(570)	0
Net cash provided by financing activities	46,250	23,116
Net decrease in cash and cash equivalents	(9,938)	(21,758)
Cash and cash equivalents at beginning of period	48,595	29,819
Cash and cash equivalents at end of period	$ 38,657	$ 8,061

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Derivative Instruments--Effect of Derivative Instruments on the Consolidated Balance Sheets (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Derivative assets, gross	$ 3,100		$ 13,113
Current derivative assets, net	0		2,152
Long-term derivative assets, net	2,847		6,403
Derivative liabilities, gross	(23,223)		(12,792)
Current derivative liabilities, net	(22,830)		(8,234)
Long-term derivative liabilities, net	(140)		0
Derivative assets (liabilities), net	(20,123)		321
Current derivative assets (liabilities), net	(22,830)		(6,082)
Long-term derivative assets (liabilities), net	2,707		6,403
Derivative settlements receivable	156		4,616
Derivative settlements payable	5,339		377
Oil Derivative | Swaps
Derivatives, Fair Value [Line Items]
Derivative assets, gross	0		112
Derivative liabilities, gross	(3,345)		(2,807)
Derivative assets (liabilities), net	(3,345)		(2,695)
Oil Derivative | Costless Collars
Derivatives, Fair Value [Line Items]
Derivative assets, gross	733		2,776
Derivative liabilities, gross	(824)		(4)
Derivative assets (liabilities), net	(91)		2,772
Oil Derivative | Enhanced Swaps
Derivatives, Fair Value [Line Items]
Derivative assets, gross	1,621		6,988
Derivative liabilities, gross	(11,308)		(6,212)
Derivative assets (liabilities), net	(9,687)		776
Oil Derivative | Put Options Purchased
Derivatives, Fair Value [Line Items]
Derivative assets, gross	10		74
Derivative liabilities, gross	0		0
Derivative assets (liabilities), net	10		74
Natural Gas Derivative | Swaps
Derivatives, Fair Value [Line Items]
Derivative assets, gross	665		1,457
Derivative liabilities, gross	(7,457)		(3,706)
Derivative assets (liabilities), net	(6,792)		(2,249)
Natural Gas Derivative | Basis Protection Swaps
Derivatives, Fair Value [Line Items]
Derivative assets, gross	71		1,706
Derivative liabilities, gross	(289)		(63)
Derivative assets (liabilities), net	(218)		1,643
Netting adjustments
Derivatives, Fair Value [Line Items]
Derivative assets, gross	(253)	[1]	(4,558)	[1]
Derivative liabilities, gross	253	[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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Fair value measurements (Tables)

3 Months Ended

Mar. 31, 2014

Fair Value Disclosures [Abstract]

Fair value hierarchy for financial instruments measured at fair value on a recurring basis

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

	As of March 31, 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)	$	736		$	(11,091	)	$	(10,355	)	$	3,275		$	(6,576	)	$	(3,301	)
Significant unobservable inputs (Level 3)	2,364			(12,132		)	(9,768		)	9,838			(6,216		)	3,622
Netting adjustments (1)	(253		)	253			—			(4,558		)	4,558			—
	$	2,847		$	(22,970	)	$	(20,123	)	$	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.

Level 3 rollforward

Changes in the fair value of our derivative instruments classified as Level 3 in the fair value hierarchy during the three months ended March 31, 2014 and 2013 were: 

	Three months ended March 31,
Net derivative assets (liabilities)	2014			2013
Beginning balance	$	3,622		$	26,231
Realized and unrealized losses included in non-hedge derivative losses	(15,423		)	(523		)
Settlements paid (received)	2,033			(5,731		)
Ending balance	$	(9,768	)	$	19,977
(Losses) gains relating to instruments still held at the reporting date included in non-hedge derivative (losses) gains for the period	$	(15,324	)	$	1,393

Fair value of other financial instruments

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

	March 31, 2014				December 31, 2013
Level 2	Carrying value		Estimated fair value		Carrying value		Estimated fair value
9.875% Senior Notes due 2020	$	294,695	$	342,750	$	294,556	$	340,140
8.25% Senior Notes due 2021	400,000		437,872		400,000		437,000
7.625% Senior Notes due 2022	555,501		598,125		555,719		583,275
Senior secured revolving credit facility	319,000		319,000		272,000		272,000
Other secured long-term debt	16,259		16,259		16,437		16,437
	$	1,585,455	$	1,714,006	$	1,538,712	$	1,648,852

Offsetting Assets and Liabilities

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)			Amounts outstanding under senior secured revolving credit facility			Net amount
As of March 31, 2014
Derivative assets	$	3,100		$	(3,100	)	$	—		$	—		$	—
Derivative liabilities	(23,223		)	3,100			(20,123		)	—			(20,123		)
	$	(20,123	)	$	—		$	(20,123	)	$	—		$	(20,123	)
As of December 31, 2013
Derivative assets	$	13,113		$	(8,042	)	$	5,071		$	(4,211	)	$	860
Derivative liabilities	(12,792		)	8,042			(4,750		)	—			(4,750		)
	$	321		$	—		$	321		$	(4,211	)	$	(3,890	)

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Derivative Instruments--Effect of Derivative Instruments on the Consolidated Statements of Operations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Non-Hedge Derivative Gains (Losses) [Line Items]
Amortization of premium	$ (166)	$ 0
Non-hedge derivative losses	(29,199)	(15,546)
Swaps
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	(5,193)	(19,364)
(Payments on) receipts from settlement of non-hedge derivative instruments	(5,850)	4,525
Costless Collars
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	(2,863)	(8,285)
(Payments on) receipts from settlement of non-hedge derivative instruments	(41)	5,731
Enhanced Swaps
Non-Hedge Derivative Gains (Losses) [Line Items]
(Payments on) receipts from settlement of non-hedge derivative instruments	(1,992)	0
Enhanced Swaps and Put Options
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	(10,361)	2,031
Basis Protection Swaps
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	(1,861)	176
(Payments on) receipts from settlement of non-hedge derivative instruments	$ (872)	$ (360)

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Stock-based compensation (Tables)

3 Months Ended

Mar. 31, 2014

Share-based Compensation [Abstract]

Rollforward of unvested stock-based compensation awards

A summary of our phantom stock and RSU activity during the three months ended March 31, 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	—		—				8.11		474,337
Vested	10.08		(15,996	)	$	128	14.52		(99,754	)	$	801
Forfeited	18.76		(897	)			13.08		(4,500	)
Unvested and outstanding at March 31, 2014	20.02		36,269				9.69		695,380

A summary of our restricted stock activity during the three months ended March 31, 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		1,615				204.90		2,998
Vested	633.14		(2,721	)	$	2,227	—		—
Unvested and total outstanding at March 31, 2014	651.27		18,140				301.26		49,699

Stock-based compensation cost

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

	Three months ended
	March 31,
	2014			2013
Stock-based compensation cost	$	2,531		$	1,893
Less: stock-based compensation cost capitalized	(962		)	(579		)
Stock-based compensation expense	$	1,569		$	1,314

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Nature of operations and summary of significant accounting policies

3 Months Ended

Mar. 31, 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, Texas, New Mexico, Louisiana, Arkansas, and Kansas.

Interim financial statements

The accompanying unaudited consolidated interim financial statements of the Company have been prepared in accordance with the rules and regulations of the SEC and do not include all of the financial information and disclosures required by accounting principles generally accepted in the United States of America (“GAAP”) for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2013.

The financial information as of March 31, 2014, and for the three months ended March 31, 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 months ended March 31, 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 March 31, 2014, cash with a recorded balance totaling $36,695 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. Bad debt expense was $(553) and $250 for the three months endedMarch 31, 2014 and 2013, respectively. Recovered amounts previously written off are offset against the allowance and reduce expense in the year of recovery. During the first quarter, we recovered $755 of amounts previously deemed uncollectible in conjunction with a settlement with the counterparty. Accounts receivable consisted of the following at March 31, 2014 and December 31, 2013:

	March 31, 2014			December 31, 2013
Joint interests	$	40,454		$	31,335
Accrued commodity sales	73,370			60,768
Derivative settlements	156			4,616
Other	2,913			1,392
Allowance for doubtful accounts	(506		)	(1,596		)
	$	116,387		$	96,515

Inventories

Inventories are comprised of equipment used in developing oil and natural gas properties, oil and natural gas product inventories, and equipment for resale. Inventory and equipment for resale are carried at the lower of cost or market using the average cost method. Oil and natural gas product inventories are stated at the lower of production cost or market. 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 March 31, 2014 and December 31, 2013 consisted of the following:

	March 31, 2014			December 31, 2013
Equipment inventory	$	19,437		$	13,657
Commodities	3,347			3,186
Inventory valuation allowance	(706		)	(706		)
	$	22,078		$	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 March 31, 2014, include $218,369 of capital costs incurred for undeveloped acreage, $117,018 for the construction of CO₂ delivery pipelines and facilities for which there are no reserves, and $10,985 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.

Divestitures and acquisitions.We have entered into three separate purchase and sale agreements (the “Agreements”) during April 2014 with Scout Energy Group I, LP, RKI Exploration & Production, LLC, and RAM Energy, LLC, whereby we will sell, in aggregate, our ownership interests in our Delaware Basin, Ft. Worth Basin and Arkansas-Louisiana-Texas (“Ark-La-Tex”) properties. Under the Agreements, the total sales price for the divested properties is approximately $201,150 subject to customary pre- and post-closing adjustments as described in the Agreements. The sale and purchase of the divested properties are expected to close in late May and June 2014 and are effective as of March 1, 2014. We have received a total of approximately $17,015 as performance deposits which will be applied to the various purchase prices at closing or released to us or the buyer(s), as the case may be, if a closing fails to occur and either the buyer(s) or we terminate the Agreements. Based on the amount of oil and natural gas reserves associated with these properties, we do not anticipate these divestitures to significantly alter the relationship between capitalized costs and proved reserves, and hence, do not expect to record any gain or loss upon the sale of the properties.

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.

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 March 31, 2014 were prepared using an average price for oil and natural gas of each month for the prior twelve months as required by the Securities Exchange Commission (“SEC”). The cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties as of March 31, 2014, and no ceiling test impairment was recorded.

A decline in oil and natural gas prices subsequent to March 31, 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, if other assumptions had been used, stock-based compensation expense could have been significantly impacted.

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.

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Consolidated balance sheets (Parenthetical) (USD $)	Mar. 31, 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	366,685	70,117
Common stock, shares outstanding	366,685	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

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

3 Months Ended

Mar. 31, 2014

Accounting Policies [Abstract]

Nature of operations

Nature of operations

Chaparral Energy, Inc. and its subsidiaries, (collectively, “we”, “our”, “us”, or the “Company”) are involved in the acquisition, exploration, development, production and operation of oil and natural gas properties. Properties are located primarily in Oklahoma, Texas, New Mexico, Louisiana, Arkansas, and Kansas.

Interim financial statements

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 March 31, 2014, and for the three months ended March 31, 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 months ended March 31, 2014 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2014.

Reclassifications

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

Cash and cash equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured.

Accounts receivable

Accounts receivable

We have receivables from joint interest owners and oil and natural gas purchasers which are generally uncollateralized. We generally review our oil and natural gas purchasers for credit worthiness and general financial condition. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties of which we are the operator. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts. Accounts receivable are generally due within 30 days and accounts outstanding longer than 60 days are considered past due. We 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.

Inventories

Inventories

Inventories are comprised of equipment used in developing oil and natural gas properties, oil and natural gas product inventories, and equipment for resale. Inventory and equipment for resale are carried at the lower of cost or market using the average cost method. Oil and natural gas product inventories are stated at the lower of production cost or market. Inventories are shown net of a provision for obsolescence, commensurate with known or estimated exposure, which is reflected in the valuation allowance disclosed below

Oil and natural gas properties

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 March 31, 2014, include $218,369 of capital costs incurred for undeveloped acreage, $117,018 for the construction of CO₂ delivery pipelines and facilities for which there are no reserves, and $10,985 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.

Divestitures and acquisitions.We have entered into three separate purchase and sale agreements (the “Agreements”) during April 2014 with Scout Energy Group I, LP, RKI Exploration & Production, LLC, and RAM Energy, LLC, whereby we will sell, in aggregate, our ownership interests in our Delaware Basin, Ft. Worth Basin and Arkansas-Louisiana-Texas (“Ark-La-Tex”) properties. Under the Agreements, the total sales price for the divested properties is approximately $201,150 subject to customary pre- and post-closing adjustments as described in the Agreements. The sale and purchase of the divested properties are expected to close in late May and June 2014 and are effective as of March 1, 2014. We have received a total of approximately $17,015 as performance deposits which will be applied to the various purchase prices at closing or released to us or the buyer(s), as the case may be, if a closing fails to occur and either the buyer(s) or we terminate the Agreements. Based on the amount of oil and natural gas reserves associated with these properties, we do not anticipate these divestitures to significantly alter the relationship between capitalized costs and proved reserves, and hence, do not expect to record any gain or loss upon the sale of the properties.

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.

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 March 31, 2014 were prepared using an average price for oil and natural gas of each month for the prior twelve months as required by the Securities Exchange Commission (“SEC”). The cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties as of March 31, 2014, and no ceiling test impairment was recorded.

A decline in oil and natural gas prices subsequent to March 31, 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

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, if other assumptions had been used, stock-based compensation expense could have been significantly impacted.

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 and issued accounting pronouncements

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.

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Document and Entity Information Document	3 Months Ended
	Mar. 31, 2014	May 05, 2014 Common Class A	May 05, 2014 Common Class B	May 05, 2014 Common Class C	May 05, 2014 Common Class E	May 05, 2014 Common Class F	May 05, 2014 Common Class G
Entity Information [Line Items]
Entity Registrant Name	Chaparral Energy, Inc.
Entity Central Index Key	0001346980
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		366,685	344,859	209,882	504,276	1	2

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

3 Months Ended

Mar. 31, 2014

Accounting Policies [Abstract]

Accounts receivable

Accounts receivable consisted of the following at March 31, 2014 and December 31, 2013:

	March 31, 2014			December 31, 2013
Joint interests	$	40,454		$	31,335
Accrued commodity sales	73,370			60,768
Derivative settlements	156			4,616
Other	2,913			1,392
Allowance for doubtful accounts	(506		)	(1,596		)
	$	116,387		$	96,515

Inventories

Inventories at March 31, 2014 and December 31, 2013 consisted of the following:

	March 31, 2014			December 31, 2013
Equipment inventory	$	19,437		$	13,657
Commodities	3,347			3,186
Inventory valuation allowance	(706		)	(706		)
	$	22,078		$	16,137

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Consolidated statements of operations (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Revenues:
Commodity sales	$ 173,339	$ 127,512
Gain from oil hedging activities	0	10,003
Total revenues	173,339	137,515
Costs and expenses:
Lease operating	35,021	33,977
Production taxes	6,643	7,880
Depreciation, depletion & amortization	55,750	43,916
General and administrative	13,387	14,008
Total costs and expenses	110,801	99,781
Operating income	62,538	37,734
Non-operating income (expense):
Interest expense	(26,459)	(24,291)
Non-hedge derivative losses	(29,199)	(15,546)
Other income, net	160	226
Net non-operating expense	(55,498)	(39,611)
Income (loss) before income taxes	7,040	(1,877)
Income tax expense (benefit)	2,635	(687)
Net income (loss)	$ 4,405	$ (1,190)

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Asset retirement obligations

3 Months Ended

Mar. 31, 2014

Asset Retirement Obligation Disclosure [Abstract]

Asset retirement obligations

Asset retirement obligations

The following table provides a summary of our asset retirement obligation activity during the three months ended March 31, 2014 and 2013.

	Three months ended March 31,
	2014			2013
Beginning balance	$	55,179		$	49,214
Liabilities incurred in current period	139			76
Liabilities settled and disposed in current period	(170		)	(811		)
Accretion expense	1,074			1,007
Ending balance	56,222			49,486
Less current portion	1,874			2,900
	$	54,348		$	46,586

See Note 5—Fair value measurements for additional information regarding fair value measurements.

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Fair value measurements

3 Months Ended

Mar. 31, 2014

Fair Value Disclosures [Abstract]

Fair value measurements

Fair value measurements

Fair value is defined by the FASB as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.

Fair value measurements are categorized according to the fair value hierarchy defined by the FASB. The hierarchical levels are based upon the level of judgment associated with the inputs used to measure the fair value of the assets and liabilities as follows:

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

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

• Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability.

In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the asset or liability is categorized based on the lowest level input that is significant to the fair value measurement in its entirety. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Recurring fair value measurements

Our financial instruments recorded at fair value on a recurring basis consist of commodity derivative contracts (see Note 4—Derivative instruments). We have no Level 1 assets or liabilities as of March 31, 2014 or December 31, 2013. Our derivative contracts classified as Level 2 as of March 31, 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.

As of March 31, 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 discounted further using a rate that incorporates our nonperformance risk for derivative liabilities and our counterparties’ nonperformance risk for derivative assets. If available, we use our counterparties’ credit default swap values or the spread between the risk-free interest rate and the yield on our counterparties’ publicly traded debt having comparable maturities to our derivative contracts as the measure of our counterparties’ nonperformance risk. As of March 31, 2014 and December 31, 2013, the rate reflecting our nonperformance risk was 2.00% and 1.75%, respectively. The weighted average rate reflecting our counterparties’ nonperformance risk was approximately 0.25% and 0.31% as of March 31, 2014 and December 31, 2013, respectively.

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

	As of March 31, 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)	$	736		$	(11,091	)	$	(10,355	)	$	3,275		$	(6,576	)	$	(3,301	)
Significant unobservable inputs (Level 3)	2,364			(12,132		)	(9,768		)	9,838			(6,216		)	3,622
Netting adjustments (1)	(253		)	253			—			(4,558		)	4,558			—
	$	2,847		$	(22,970	)	$	(20,123	)	$	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.

Changes in the fair value of our derivative instruments classified as Level 3 in the fair value hierarchy during the three months ended March 31, 2014 and 2013 were: 

	Three months ended March 31,
Net derivative assets (liabilities)	2014			2013
Beginning balance	$	3,622		$	26,231
Realized and unrealized losses included in non-hedge derivative losses	(15,423		)	(523		)
Settlements paid (received)	2,033			(5,731		)
Ending balance	$	(9,768	)	$	19,977
(Losses) gains relating to instruments still held at the reporting date included in non-hedge derivative (losses) gains for the period	$	(15,324	)	$	1,393

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 three 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 5.80% and 6.40%, respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. During the three months ended March 31, 2014 and 2013, additions to our asset retirement obligations were $139 and $76, respectively. See Note 6—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.

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

	March 31, 2014				December 31, 2013
Level 2	Carrying value		Estimated fair value		Carrying value		Estimated fair value
9.875% Senior Notes due 2020	$	294,695	$	342,750	$	294,556	$	340,140
8.25% Senior Notes due 2021	400,000		437,872		400,000		437,000
7.625% Senior Notes due 2022	555,501		598,125		555,719		583,275
Senior secured revolving credit facility	319,000		319,000		272,000		272,000
Other secured long-term debt	16,259		16,259		16,437		16,437
	$	1,585,455	$	1,714,006	$	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 March 31, 2014, the counterparties to our open derivative contracts consisted of twelve financial institutions, of which eleven were subject to our rights of offset under our senior secured revolving credit facility.

The following table summarizes our derivative assets and liabilities which are offset in the 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)			Amounts outstanding under senior secured revolving credit facility			Net amount
As of March 31, 2014
Derivative assets	$	3,100		$	(3,100	)	$	—		$	—		$	—
Derivative liabilities	(23,223		)	3,100			(20,123		)	—			(20,123		)
	$	(20,123	)	$	—		$	(20,123	)	$	—		$	(20,123	)
As of December 31, 2013
Derivative assets	$	13,113		$	(8,042	)	$	5,071		$	(4,211	)	$	860
Derivative liabilities	(12,792		)	8,042			(4,750		)	—			(4,750		)
	$	321		$	—		$	321		$	(4,211	)	$	(3,890	)

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 $23,223 at March 31, 2014.

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Asset retirement obligations (Tables)

3 Months Ended

Mar. 31, 2014

Asset Retirement Obligation Disclosure [Abstract]

Asset retirement obligations

The following table provides a summary of our asset retirement obligation activity during the three months ended March 31, 2014 and 2013.

	Three months ended March 31,
	2014			2013
Beginning balance	$	55,179		$	49,214
Liabilities incurred in current period	139			76
Liabilities settled and disposed in current period	(170		)	(811		)
Accretion expense	1,074			1,007
Ending balance	56,222			49,486
Less current portion	1,874			2,900
	$	54,348		$	46,586

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Supplemental disclosures to the consolidated statements of cash flows (Tables)

3 Months Ended

Mar. 31, 2014

Supplemental Cash Flow Elements [Abstract]

Supplemental disclosures to the consolidated statements of cash flows

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

	Three months ended March 31,
	2014			2013
Net cash provided by operating activities included:
Cash payments for interest	$	18,794		$	16,787
Interest capitalized	(2,942		)	(3,628		)
Cash payments for interest, net of amounts capitalized	$	15,852		$	13,159
Non-cash investing activities included:
Asset retirement obligation additions and revisions	$	139		$	76
Oil and natural gas properties acquired through increase in accounts payable and accrued liabilities	$	18,629		$	18,502

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Related party transactions

3 Months Ended

Mar. 31, 2014

Related Party Transactions [Abstract]

Related party transactions

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
	March 31, 2013
Revenues	$	1,380
Joint interest billings	$	(923	)

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
	March 31, 2013
Revenues	$	(503	)
Joint interest billings	$	4,267

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.

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Stock-based compensation

3 Months Ended

Mar. 31, 2014

Share-based Compensation [Abstract]

Stock-based compensation

Stock-based compensation

Phantom Stock Plan and Restricted Stock Unit Plan

Effective January 1, 2004, we implemented a Phantom Unit Plan, which was revised on December 31, 2008 as the Second Amended and Restated Phantom Stock Plan (the “Phantom Plan”), to provide deferred compensation to certain key employees (the “Participants”). 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.

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

A summary of our phantom stock and RSU activity during the three months ended March 31, 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	—		—				8.11		474,337
Vested	10.08		(15,996	)	$	128	14.52		(99,754	)	$	801
Forfeited	18.76		(897	)			13.08		(4,500	)
Unvested and outstanding at March 31, 2014	20.02		36,269				9.69		695,380

Based on an estimated fair value of $8.28 per phantom share and RSU as of March 31, 2014, the aggregate intrinsic value of the unvested phantom shares and RSUs outstanding was $6,058.

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). The Time Vested awards vest in equal annual installments over the five-year vesting period, but may also vest on an accelerated basis in the event of a Transaction (as defined in the 2010 Plan). The Performance Vested awards vest in the event of a Transaction that achieves certain market targets as defined in the 2010 Plan. Any shares of Performance Vested awards not vested on a Separation Date (as defined in the 2010 Plan) will be forfeited as of the Separation Date.

A summary of our restricted stock activity during the three months ended March 31, 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		1,615				204.90		2,998
Vested	633.14		(2,721	)	$	2,227	—		—
Unvested and total outstanding at March 31, 2014	651.27		18,140				301.26		49,699

During the three months ended March 31, 2014 and 2013, respectively, we repurchased and canceled 1,068 and 123 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 $818.50 per Time Vested restricted share, the aggregate intrinsic value of the unvested Time Vested restricted shares outstanding was $14,848 as of March 31, 2014.

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
	March 31,
	2014			2013
Stock-based compensation cost	$	2,531		$	1,893
Less: stock-based compensation cost capitalized	(962		)	(579		)
Stock-based compensation expense	$	1,569		$	1,314

Payments for stock-based compensation were $874 and $69 during the three months ended March 31, 2014 and 2013, respectively. As of March 31, 2014 and December 31, 2013, accrued payroll and benefits payable included $5,951 and $5,080, respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized compensation cost of approximately $19,103 is expected to be recognized over a weighted average period of 2.7 years.

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Common stock

3 Months Ended

Mar. 31, 2014

Equity [Abstract]

Common stock

Common stock

The following is a summary of the changes in our common shares outstanding during the three months ended March 31, 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	4,613		—		—	—		—	—	—		4,613
Restricted stock repurchased	(1,068	)	—		—	—		—	—	—		(1,068	)
Shares outstanding at March 31, 2014	366,685		344,859		209,882	—		504,276	1	2		1,425,705

_______________

(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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Commitments and contingencies

3 Months Ended

Mar. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and contingencies

Commitments and contingencies

Standby letters of credit (“Letters”) available under our senior secured revolving credit facility are used in lieu of surety bonds with various organizations for liabilities relating to the operation of oil and natural gas properties. We had various Letters outstanding totaling $920 and $920 as of March 31, 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 three months ended March 31, 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 Plaintiff’s Motion for Class Certification is due August 10, 2014. Because a class has not been certified, we are not yet able to estimate a possible loss, or range of possible loss, if any.

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

On May 10, 2013, Amanda Dodson (the “Plaintiff”), filed a complaint against us 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.

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.

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. Other than additional debt borrowings during the three months ended March 31, 2014, there were no material changes to our contractual commitments since December 31, 2013.

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Derivative Instruments--Outstanding Derivatives (Details)	Mar. 31, 2014 bbl
Swaps | Derivatives Maturing In 2014 | Oil Derivative
Derivative [Line Items]
Volume of derivative instruments held	581,000
Weighted average fixed price per unit, swaps	92.30
Swaps | Derivatives Maturing In 2014 | Natural Gas Derivative
Derivative [Line Items]
Volume of derivative instruments held	15,640,000
Weighted average fixed price per unit, swaps	4.01
Swaps | Derivatives maturing in 2015 | Natural Gas Derivative
Derivative [Line Items]
Volume of derivative instruments held	22,170,000
Weighted average fixed price per unit, swaps	4.20
Costless Collars | Derivatives Maturing In 2014 | Oil Derivative
Derivative [Line Items]
Volume of derivative instruments held	1,800,000
Weighted average fixed price per Bbl, sold puts	75.50
Weighted average fixed price per Bbl, purchased puts	93.25
Weighted average fixed price per Bbl, sold calls	101.94
Enhanced Swaps | Derivatives Maturing In 2014 | Oil Derivative
Derivative [Line Items]
Volume of derivative instruments held	630,000
Weighted average fixed price per unit, swaps	98.24
Weighted average fixed price per Bbl, sold puts	80.00
Enhanced Swaps | Derivatives maturing in 2015 | Oil Derivative
Derivative [Line Items]
Volume of derivative instruments held	6,058,000
Weighted average fixed price per unit, swaps	92.92
Weighted average fixed price per Bbl, sold puts	80.00
Put Spread Enhanced Swaps | Derivatives Maturing In 2014 | Oil Derivative
Derivative [Line Items]
Volume of derivative instruments held	2,072,000
Weighted average fixed price per unit, swaps	93.85
Weighted average fixed price per Bbl, sold puts	80.00
Weighted average fixed price per Bbl, purchased puts	60.00
Put Options Purchased | Derivatives Maturing In 2014 | Oil Derivative
Derivative [Line Items]
Volume of derivative instruments held	630,000
Weighted average fixed price per Bbl, purchased puts	60.00
Basis Protection Swaps | Derivatives Maturing In 2014 | Natural Gas Derivative
Derivative [Line Items]
Volume of derivative instruments held	16,120,000
Weighted average fixed price per unit, swaps	0.24
Basis Protection Swaps | Derivatives maturing in 2015 | Natural Gas Derivative
Derivative [Line Items]
Volume of derivative instruments held	2,400,000
Weighted average fixed price per unit, swaps	0.18

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Derivative instruments (Tables)

3 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Outstanding derivative instruments

The following table summarizes our crude oil derivatives outstanding as of March 31, 2014:

		Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls	Swaps		Sold puts		Purchased puts		Sold calls
2014
Swaps	581	$	92.30	$	—	$	—	$	—
Three-way collars	1,800	$	—	$	75.50	$	93.25	$	101.94
Enhanced swaps	630	$	98.24	$	80.00	$	—	$	—
Put spread enhanced swaps	2,072	$	93.85	$	80.00	$	60.00	$	—
Purchased puts	630	$	—	$	—	$	60.00	$	—
2015
Enhanced swaps	6,058	$	92.92	$	80.00	$	—	$	—

The following tables summarize our natural gas derivative instruments outstanding as of March 31, 2014:

Period and type of contract	Volume BBtu	Weighted average fixed price per MMBtu
2014
Natural gas swaps	15,640	$	4.01
Natural gas basis protection swaps	16,120	$	0.24
2015
Natural gas swaps	22,170	$	4.20
Natural gas basis protection swaps	2,400	$	0.18

Derivative instruments recorded on the balance sheet at fair value

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

	As of March 31, 2014								As of December 31, 2013
	Assets		Liabilities			Net value			Assets		Liabilities			Net value
Natural gas swaps	$	665	$	(7,457	)	$	(6,792	)	$	1,457	$	(3,706	)	$	(2,249	)
Oil swaps	—		(3,345		)	(3,345		)	112		(2,807		)	(2,695		)
Oil collars	733		(824		)	(91		)	2,776		(4		)	2,772
Oil enhanced swaps	1,621		(11,308		)	(9,687		)	6,988		(6,212		)	776
Oil purchased puts	10		—			10			74		—			74
Natural gas basis differential swaps	71		(289		)	(218		)	1,706		(63		)	1,643
Total derivative instruments	3,100		(23,223		)	(20,123		)	13,113		(12,792		)	321
Less:
Netting adjustments (1)	253		(253		)	—			4,558		(4,558		)	—
Current portion asset (liability)	—		(22,830		)	(22,830		)	2,152		(8,234		)	(6,082		)
	$	2,847	$	(140	)	$	2,707		$	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 March 31, 2014 and December 31, 2013 were as follows:

	March 31, 2014		December 31, 2013
Derivative settlements receivable included in accounts receivable	$	156	$	4,616
Derivative settlements payable included in accounts payable and accrued liabilities	$	5,339	$	377

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

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

	Three months ended
	March 31,
	2014			2013
Change in fair value of commodity price swaps	$	(5,193	)	$	(19,364	)
Change in fair value of collars	(2,863		)	(8,285		)
Change in fair value of enhanced swaps and put options	(10,361		)	2,031
Change in fair value of natural gas basis differential contracts	(1,861		)	176
Amortization of premium	(166		)	—
(Payments on) receipts from settlement of commodity price swaps	(5,850		)	4,525
(Payments on) receipts from settlement of collars	(41		)	5,731
(Payments on) receipts from settlement enhanced swaps	(1,992		)	—
Payments on settlement of natural gas basis differential contracts	(872		)	(360		)
	$	(29,199	)	$	(15,546	)

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Related party transactions (Tables)

3 Months Ended

Mar. 31, 2014

Related Party Transactions [Abstract]

Related party transactions

We participate in ownership of properties operated by Chesapeake, and we received revenues and incurred joint interest billings on these properties as follows:

	Three months ended
	March 31, 2013
Revenues	$	1,380
Joint interest billings	$	(923	)

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
	March 31, 2013
Revenues	$	(503	)
Joint interest billings	$	4,267

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

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Commitments and contingencies (Details) (USD $) In Thousands, unless otherwise specified	1 Months Ended	3 Months Ended			1 Months Ended	3 Months Ended
	Aug. 09, 2012 court_case	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013	Jun. 07, 2011 Pending Litigation Minimum	Mar. 31, 2014 Letter of Credit	Mar. 31, 2013 Letter of Credit
Loss Contingencies [Line Items]
Letters of credit outstanding		$ 920		$ 920
Interest paid		18,794	16,787			0	0
Damages sought					$ 5,000
Number of court cases	2

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Fair Value Measurements--Counterparty Credit Risk (Details) (Concentration of Counterparty Credit Risk)	Mar. 31, 2014 financial_institutions
Concentration of Counterparty Credit Risk
Concentration Risk [Line Items]
Derivative contracts, number of counterparties	12
Derivative contracts, number of counterparties subject to offset under credit facility	11

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Consolidated statements of comprehensive (loss) income (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Comprehensive income
Net income (loss)	$ 4,405	$ (1,190)
Other comprehensive loss
Reclassification adjustment for hedge gains included in gain from oil hedging activities in the consolidated statements of operations	0	(10,003)
Income tax benefit related to other comprehensive loss	0	3,818
Other comprehensive loss, net of tax	0	(6,185)
Comprehensive income (loss)	$ 4,405	$ (7,375)

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Derivative instruments

3 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative instruments

Derivative instruments

Overview

Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into various types of derivative instruments, including commodity price swaps, 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 our payment of a cash premium. If the market price is below the put strike price at the settlement date, we will receive a payment from the counterparty. Purchased put options are designed to provide a fixed price floor with the opportunity for upside if commodity prices increase.

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

We use basis protection swaps to reduce basis risk. Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. Natural gas basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified pricing point. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract.

We 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 March 31, 2014:

		Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls	Swaps		Sold puts		Purchased puts		Sold calls
2014
Swaps	581	$	92.30	$	—	$	—	$	—
Three-way collars	1,800	$	—	$	75.50	$	93.25	$	101.94
Enhanced swaps	630	$	98.24	$	80.00	$	—	$	—
Put spread enhanced swaps	2,072	$	93.85	$	80.00	$	60.00	$	—
Purchased puts	630	$	—	$	—	$	60.00	$	—
2015
Enhanced swaps	6,058	$	92.92	$	80.00	$	—	$	—

The following tables summarize our natural gas derivative instruments outstanding as of March 31, 2014:

Period and type of contract	Volume BBtu	Weighted average fixed price per MMBtu
2014
Natural gas swaps	15,640	$	4.01
Natural gas basis protection swaps	16,120	$	0.24
2015
Natural gas swaps	22,170	$	4.20
Natural gas basis protection swaps	2,400	$	0.18

Effect of derivative instruments on the consolidated balance sheets

All derivative financial instruments are recorded on the balance sheet at fair value. See Note 5—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 March 31, 2014								As of December 31, 2013
	Assets		Liabilities			Net value			Assets		Liabilities			Net value
Natural gas swaps	$	665	$	(7,457	)	$	(6,792	)	$	1,457	$	(3,706	)	$	(2,249	)
Oil swaps	—		(3,345		)	(3,345		)	112		(2,807		)	(2,695		)
Oil collars	733		(824		)	(91		)	2,776		(4		)	2,772
Oil enhanced swaps	1,621		(11,308		)	(9,687		)	6,988		(6,212		)	776
Oil purchased puts	10		—			10			74		—			74
Natural gas basis differential swaps	71		(289		)	(218		)	1,706		(63		)	1,643
Total derivative instruments	3,100		(23,223		)	(20,123		)	13,113		(12,792		)	321
Less:
Netting adjustments (1)	253		(253		)	—			4,558		(4,558		)	—
Current portion asset (liability)	—		(22,830		)	(22,830		)	2,152		(8,234		)	(6,082		)
	$	2,847	$	(140	)	$	2,707		$	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 March 31, 2014 and December 31, 2013 were as follows:

	March 31, 2014		December 31, 2013
Derivative settlements receivable included in accounts receivable	$	156	$	4,616
Derivative settlements payable included in accounts payable and accrued liabilities	$	5,339	$	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.

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

	Three months ended
	March 31,
	2014			2013
Change in fair value of commodity price swaps	$	(5,193	)	$	(19,364	)
Change in fair value of collars	(2,863		)	(8,285		)
Change in fair value of enhanced swaps and put options	(10,361		)	2,031
Change in fair value of natural gas basis differential contracts	(1,861		)	176
Amortization of premium	(166		)	—
(Payments on) receipts from settlement of commodity price swaps	(5,850		)	4,525
(Payments on) receipts from settlement of collars	(41		)	5,731
(Payments on) receipts from settlement enhanced swaps	(1,992		)	—
Payments on settlement of natural gas basis differential contracts	(872		)	(360		)
	$	(29,199	)	$	(15,546	)

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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	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Period within which joint interest accounts receivable are due	30 days
Period within which joint interest accounts receivable are past due	60 days
Bad debt expense	$ (553)	$ 250
Recovery of bad debts	755
Receivables [Abstract]
Joint interests	40,454		31,335
Accrued commodity sales	73,370		60,768
Derivative settlements	156		4,616
Other	2,913		1,392
Allowance for doubtful accounts	(506)		(1,596)
Accounts receivable, net	116,387		96,515
JP Morgan Chase Bank, N.A.
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Cash held at JP Morgan Chase Bank, N. A.	$ 36,695

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Fair Value Measurements--Level 3 Rollforward (Details) (Significant unobservable inputs (Level 3), Derivative, USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Significant unobservable inputs (Level 3) | Derivative
Level 3 Rollforward
Beginning balance	$ 3,622	$ 26,231
Realized and unrealized losses included in non-hedge derivative losses	(15,423)	(523)
Settlements paid (received)	2,033	(5,731)
Ending balance	(9,768)	19,977
(Losses) gains relating to instruments still held at the reporting date included in non-hedge derivative (losses) gains for the period	$ (15,324)	$ 1,393

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Long-term debt (Tables)

3 Months Ended

Mar. 31, 2014

Debt Disclosure [Abstract]

Components of long-term debt

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

	March 31, 2014		December 31, 2013
9.875% Senior Notes due 2020, net of discount of $5,304 and $5,444, respectively	$	294,695	$	294,556
8.25% Senior Notes due 2021	400,000		400,000
7.625% Senior Notes due 2022, including premium of $5,501 and $5,719, respectively	555,501		555,719
Senior secured revolving credit facility	319,000		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	11,081		11,202
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.85% to 5.99%, due April 2014 through February 2018 collateralized by automobiles, machinery and equipment	5,178		5,235
Capital lease obligations	23,579		24,150
	1,609,034		1,562,862
Less current maturities	5,502		5,334
	$	1,603,532	$	1,557,528