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, 2015

OR

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

For the transition period from to

Commission file number: 333-134748

____________________________

Chaparral Energy, Inc.

(Exact name of registrant as specified in its charter)

 ____________________________

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

(405) 478-8770

(Registrant’s telephone number, including area code)

____________________________

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

(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of the Securities Exchange Act of 1934.)

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 12, 2015:

Class	Number of shares
Class A Common Stock, $0.01 par value	348,507
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, 2015 (unaudited) and December 31, 2014	6
Consolidated statements of operations for the three months ended March 31, 2015 and 2014 (unaudited)	8
Consolidated statements of cash flows for the three months ended March 31, 2015 and 2014 (unaudited)	9
Condensed notes to consolidated financial statements (unaudited)	10
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Overview	25
Results of operations	27
Liquidity and capital resources	34
Non-GAAP financial measure and reconciliation	38
Critical accounting policies	38
Recent accounting pronouncements	38
Item 3. Quantitative and Qualitative Disclosures about Market Risk	39
Item 4. Controls and Procedures	42
Part II. Other Information	42
Item 1. Legal Proceedings	42
Item 1A. Risk Factors	42
Item 5. Other Information	43
Item 6. Exhibits	43
Signatures	44
EX-10.1 Fifteenth Amendment to the Eight Restated Credit Agreement dated as of April 1, 2015
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, 2014. Specifically, some factors that could cause actual results to differ include:

• volatility and declines in oil and natural gas prices

• worldwide supply of and demand for oil and natural gas;

• the significant amount of our debt;

• drilling plans (including scheduled and budgeted wells);

• the number, timing or results of any wells;

• changes in wells operated and in reserve estimates;

• supply of CO₂;

• future growth and expansion;

• future exploration;

• integration of existing and new technologies into operations;

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

• borrowings and capital resources and liquidity;

• changes in strategy and business discipline;

• future tax matters;

• any loss of key personnel;

• future seismic data (including timing and results);

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

• geopolitical events affecting oil and natural gas prices;

• outcome, effects or timing of legal proceedings;

• the effect of litigation and contingencies;

• the ability to generate additional prospects; and

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

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

4

GLOSSARY OF OIL AND NATURAL GAS TERMS

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

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

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

• BBtu. One billion British thermal units.

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

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

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

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

• CO₂. Carbon dioxide.

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

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

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

• MBoe. One thousand barrels of crude oil equivalent.

• Mcf. One thousand cubic feet of natural gas.

• MMBtu. One million British thermal units.

• MMcf. One million cubic feet of natural gas.

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

• NYMEX. The New York Mercantile Exchange.

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

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

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

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

• SEC. The Securities and Exchange Commission.

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

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

5

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets

	March 31, 2015			December 31, 2014
(dollars in thousands, except share data)	(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	42,173		$	31,492
Accounts receivable, net	102,581			98,444
Inventories, net	27,162			25,557
Prepaid expenses	3,321			4,484
Derivative instruments	166,873			179,921
Total current assets	342,110			339,898
Property and equipment—at cost, net	64,397			66,561
Oil and natural gas properties, using the full cost method:
Proved	3,825,904			3,735,817
Unevaluated (excluded from the amortization base)	265,109			288,425
Accumulated depreciation, depletion, amortization and impairment	(1,763,747		)	(1,701,851		)
Total oil and natural gas properties	2,327,266			2,322,391
Derivative instruments	70,228			71,710
Other assets	30,120			31,256
	$	2,834,121		$	2,831,816
The accompanying notes are an integral part of these consolidated financial statements.

6

Chaparral Energy, Inc. and subsidiaries Consolidated balance sheets—continued
	March 31, 2015		December 31, 2014
(dollars in thousands, except share data)	(unaudited)
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	90,916	$	191,957
Accrued payroll and benefits payable	13,550		21,654
Accrued interest payable	33,724		24,106
Revenue distribution payable	17,869		24,467
Current maturities of long-term debt and capital leases	5,138		5,377
Derivative instruments	—		77
Deferred income taxes	60,072		60,728
Total current liabilities	221,269		328,366
Long-term debt and capital leases, less current maturities	1,730,166		1,628,425
Stock-based compensation	537		3,131
Asset retirement obligations	45,020		43,277
Deferred income taxes	119,967		116,759
Commitments and contingencies (Note 8)
Stockholders’ equity:
Preferred stock, 600,000 shares authorized, none issued and outstanding	—		—
Class A Common stock, $0.01 par value, 10,000,000 shares authorized and 352,792 and 364,896 shares issued and outstanding as of March 31, 2015 and December 31, 2014, respectively	4		4
Class B Common stock, $0.01 par value, 10,000,000 shares authorized and 344,859 shares issued and outstanding	3		3
Class C Common stock, $0.01 par value, 10,000,000 shares authorized and 209,882 shares issued and outstanding	2		2
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 shares issued and outstanding	—		—
Additional paid in capital	430,734		429,678
Retained earnings	286,414		282,166
	717,162		711,858
	$	2,834,121	$	2,831,816

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

7

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of operations

	Three months ended
	March 31,
(in thousands)	2015			2014
	(unaudited)
Revenues:
Commodity sales	$	93,079		$	173,339
Total revenues	93,079			173,339
Costs and expenses:
Lease operating	31,632			33,655
Transportation and processing	2,372			1,366
Production taxes	4,484			6,643
Depreciation, depletion and amortization	65,211			55,750
General and administrative	9,194			13,387
Cost reduction initiatives	8,774			—
Total costs and expenses	121,667			110,801
Operating income	(28,588		)	62,538
Non-operating income (expense):
Interest expense	(26,712		)	(26,459		)
Non-hedge derivative gains (losses)	61,431			(29,199		)
Other income, net	674			160
Net non-operating income (expense)	35,393			(55,498		)
Income before income taxes	6,805			7,040
Income tax expense	2,557			2,635
Net income	$	4,248		$	4,405

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

8

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows

	Three months ended
	March 31,
(in thousands)	2015			2014
	(unaudited)
Cash flows from operating activities
Net income	$	4,248		$	4,405
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion & amortization	65,211			55,750
Deferred income taxes	2,553			2,485
Non-hedge derivative (gains) losses	(61,431		)	29,199
Gain on sale of assets	(79		)	(84		)
Other	1,221			492
Change in assets and liabilities
Accounts receivable	(8,126		)	(15,762		)
Inventories	(6,431		)	(4,234		)
Prepaid expenses and other assets	1,116			669
Accounts payable and accrued liabilities	(2,808		)	2,303
Revenue distribution payable	(6,598		)	(1,679		)
Stock-based compensation	(1,898		)	695
Net cash (used in) provided by operating activities	(13,022		)	74,239
Cash flows from investing activities
Expenditures for property, plant, and equipment and oil and natural gas properties	(156,798		)	(138,669		)
Proceeds from asset dispositions	3,068			16,997
Settlement of non-hedge derivative instruments	75,885			(8,755		)
Net cash used in investing activities	(77,845		)	(130,427		)
Cash flows from financing activities
Proceeds from long-term debt	103,000			50,603
Repayment of long-term debt	(860		)	(3,783		)
Principal payments under capital lease obligations	(592		)	(570		)
Net cash provided by financing activities	101,548			46,250
Net increase (decrease) in cash and cash equivalents	10,681			(9,938		)
Cash and cash equivalents at beginning of period	31,492			48,595
Cash and cash equivalents at end of period	$	42,173		$	38,657

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

9

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. Our properties are located primarily in Oklahoma and Texas.

Interim financial statements

The accompanying unaudited consolidated interim financial statements of the Company have been prepared in accordance with the rules and regulations of the SEC and do not include all of the financial information and disclosures required by accounting principles generally accepted in the United States of America (“GAAP”) for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2014.

The financial information as of March 31, 2015, and for the three months ended March 31, 2015 and 2014, respectively, is unaudited. The financial information as of December 31, 2014 has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2014. 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, 2015 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2015.

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, 2015, cash with a recorded balance totaling $38,551 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 our assessment of the owner’s ability to pay its obligation, among other things.

10

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

We write off accounts receivable when they are determined to be uncollectible. Recovered amounts previously written off are offset against the allowance and reduce expense in the year of recovery.

Accounts receivable consisted of the following at March 31, 2015 and December 31, 2014:

	March 31, 2015			December 31, 2014
Joint interests	$	21,844		$	30,648
Accrued commodity sales	37,968			45,667
Derivative settlements	41,092			19,678
Other	2,014			2,738
Allowance for doubtful accounts	(337		)	(287		)
	$	102,581		$	98,444

Inventories

Inventories are comprised of equipment used in developing oil and natural gas properties and oil and natural gas product inventories. Equipment inventory is carried at the lower of cost or market using the average cost method. Oil and natural gas product inventories are stated at the lower of production cost or market. Inventories are shown net of a provision for obsolescence, commensurate with known or estimated exposure, which is reflected in the valuation allowance disclosed below. Inventories at March 31, 2015 and December 31, 2014 consisted of the following:

	March 31, 2015			December 31, 2014
Equipment inventory	$	25,518		$	24,169
Commodities	2,821			2,575
Inventory valuation allowance	(1,177		)	(1,187		)
	$	27,162		$	25,557

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, 2015, include $188,562 of capital costs incurred for undeveloped acreage, $72,046 for the construction of CO₂ delivery pipelines and facilities for which there are no reserves, and $4,501 for wells and facilities in progress pending determination. As of December 31, 2014, work-in-progress costs included capital costs incurred of $190,356 for undeveloped acreage, $72,046 for the construction of CO₂ delivery pipelines and facilities for which there are no reserves, and $26,023 for wells and facilities in progress pending determination.

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

11

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

Ceiling Test. In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related PV-10 value, net of tax considerations, plus the cost of unproved properties not being amortized.

Our estimates of oil and natural gas reserves as of March 31, 2015 were prepared using an average price for oil and natural gas of each month for the prior twelve months as required by the SEC. The cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties as of March 31, 2015, and no ceiling test impairment was recorded.

Due to the substantial decline of commodity prices in late 2014, which have remained low into the second quarter of 2015, we anticipate that we will have a ceiling test write-down, which could occur as early as the second quarter of 2015, if prices remain at their depressed levels. The amount of any future impairment is difficult to predict, and will depend on the average oil and natural gas prices during each period, the incremental proved reserves added during each period, and additional capital spent.

Stock-based compensation

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

The estimated fair value of the phantom stock and RSU awards are remeasured at the end of each reporting period until settlement. The estimated fair market value of these awards is calculated based on our total asset value less total liabilities, with both assets and liabilities being adjusted to fair value in accordance with the terms of the Phantom Stock Plan and the Non-Officer Restricted Stock Unit Plan. The primary adjustment required is the adjustment of oil and natural gas properties from net book value to the discounted and risk-adjusted reserve value based on internal reserve reports priced on NYMEX forward strips. Compensation cost associated with the phantom stock awards and RSU awards is recognized over the vesting period using the straight-line method and the accelerated method, respectively. The fair value of our restricted stock awards that include a service condition is based upon the estimated fair market value of our common equity per share on a minority, non-marketable basis on the date of grant, and is remeasured at the end of each reporting period until settlement. We recognize compensation cost over the requisite service period using the accelerated method for awards with graded vesting.

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

The costs associated with our stock-based compensation programs is calculated net of forfeitures, which are estimated based on our historical and expected turnover rates. If our actual forfeiture rate is materially different from our estimate, the stock-based compensation cost could be different from what we have recorded in the current period.

Cost reduction initiatives

Cost reduction initiatives include expenses related to our efforts to reduce our capital, operating and administrative costs in response to the recent deterioration of commodity prices. Included in our $8,774 of expenses for cost reduction initiatives are $6,524 in one-time severance and termination benefits in connection with our reduction in force that was implemented in February 2015. The remaining expense is a result of third party legal and professional services we have engaged to assist in our cost savings initiatives.

12

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

Recently adopted accounting pronouncements

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

Recently issued accounting pronouncements

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

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

In April 2015, the FASB issued authoritative guidance that amends the presentation of the cost of issuing debt on the balance sheet. The amendment requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendment. This guidance is effective for fiscal periods after December 15, 2015 and interim periods thereafter. We are currently evaluating the effect the new standard will have 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,
	2015			2014
Net cash provided by operating activities included:
Cash payments for interest	$	19,073		$	18,794
Interest capitalized	(3,462		)	(2,942		)
Cash payments for interest, net of amounts capitalized	$	15,611		$	15,852
Non-cash investing activities included:
Asset retirement obligation additions and revisions	$	539		$	139
Oil and natural gas properties acquired through increase in accounts payable and accrued liabilities	$	—		$	18,629

13

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, 2015		December 31, 2014
9.875% Senior Notes due 2020, net of discount of $4,706 and $4,861, respectively	$	295,294	$	295,139
8.25% Senior Notes due 2021	400,000		400,000
7.625% Senior Notes due 2022, including premium of $4,666 and $4,869, respectively	554,666		554,869
Senior secured revolving credit facility	450,000		347,000
Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 2.54% to 5.46%, due August 2021 through December 2028; collateralized by real property	10,577		10,705
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.85% to 5.95% , due April 2015 through February 2018; collateralized by automobiles, machinery and equipment	3,522		4,252
Capital lease obligations	21,245		21,837
	1,735,304		1,633,802
Less current maturities	5,138		5,377
	$	1,730,166	$	1,628,425

Senior Notes

The senior notes, which, as of March 31, 2015, 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 ended March 31, 2015, we borrowed $103,000 on our senior secured revolving credit facility. As of March 31, 2015, the weighted average interest rate was 2.2% on outstanding borrowings under the senior secured revolving credit facility.

Availability under our senior secured revolving credit facility is subject to a borrowing base which is set by the banks semiannually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination and in the event of early termination of our derivative contracts. Our first semiannual borrowing base redetermination for the current year was finalized ahead of schedule in conjunction with an amendment to our senior secured revolving credit facility (the “Fifteenth Amendment”), effective on April 1, 2015. As of result of our semiannual redetermination, our borrowing base was decreased from $650,000 to $550,000 effective on April 1, 2015.

In connection with the Fifteenth Amendment, the Consolidated Net Debt to Consolidated EBITDAX covenant required by our senior secured revolving credit facility will be replaced by a covenant based on the ratio of Consolidated Net Secured Debt to Consolidated EBITDAX, as defined in the amendment. Under this covenant, we are required to maintain a ratio of Consolidated Net Secured Debt to Consolidated EBITDAX no greater than 2.25 to 1.0 for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter. For the same applicable periods, the Fifteenth Amendment also requires us to maintain an Interest Coverage Ratio, as defined in the amendment, of no less than 2.00 to 1.0. Under the Fifteenth Amendment, we are allowed to incur an additional $300,000 in Additional Permitted Debt, as revised in the amendment to now include both secured and unsecured debt.

14

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

We believe we were in compliance with all covenants under our senior secured revolving credit facility as of March 31, 2015.

Capital Leases

During 2013, we entered into lease financing agreements with U.S. Bank National Association for $24,500 through the sale and subsequent leaseback of existing compressors owned by us. The carrying value of these compressors is included in our oil and natural gas full cost pool. The lease financing obligations are for 84-month terms and include the option to purchase the equipment for a specified price at 72 months as well as an option to purchase the equipment at the end of the lease term for its then-current fair market value. Lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.8%. Minimum lease payments are approximately $3,181 annually.

Note 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, natural gas. and natural gas liquids. 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. We enter into crude oil derivative contracts to hedge a portion of our natural gas liquids production.

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.

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 pay 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. A put spread may also be constructed by entering into separate sold put and purchased put contracts.

Put options may be purchased from the counterparty by paying a cash premium at the time the put options are purchased or deferring payment until the put options settle. If the market price is below the put strike price at the settlement date, we will receive a payment from the counterparty. Purchased put options are designed to provide a fixed price floor in an environment where prices have declined. In such an environment, put options may also be purchased to offset the downside from sold puts that are originally associated with enhanced swaps or three-way collars. The fair value of our put options include any deferred premiums that are payable under the contract.

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

15

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

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.

The following table summarizes our crude oil derivatives outstanding as of March 31, 2015:

		Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls	Swaps		Sold puts		Purchased puts		Sold calls		Average premium
2015
Swaps	450	$	95.25	$	—	$	—	$	—	$	—
Swaps with deferred premium (1)	4,028	$	92.78	$	—	$	—	$	—	$	13.80
2016
Three-way collars	240	$	—	$	84.00	$	92.00	$	101.01	$	—
Enhanced swaps (2)	3,720	$	92.94	$	80.52	$	—	$	—	$	—
Purchased puts (2)	3,720	$	—	$	—	$	60.00	$	—	$	5.54

___________

(1) As a result of the deferred premiums, the above 4,028,000 barrels of crude oil production in 2015 are hedged at an effective price of $78.98/barrel.

(2) Total premiums of $20,609 for the purchased puts were paid at contract inception in December 2014. Excluding the premiums and utilizing an average NYMEX strip price of $57.74 for 2016 as of March 31, 2015, the average realized price from our 3,720,000 barrels of hedged production that have associated sold puts and purchased puts is $72.42/barrel. This effective price is also the floor on the realized price we would receive in the event of any crude oil price decline below$60.00/barrel. Upon settlement, in the event that prices increase above $60.00/barrel, our effective price would increase by a commensurate amount of the price increase until prices reach the sold put price after which we would receive the swap price.

The following tables summarize our natural gas derivative instruments outstanding as of March 31, 2015:

Period and type of contract	Volume BBtu	Weighted average fixed price per MMBtu
2015
Natural gas swaps	12,240	$	4.15
Natural gas basis protection swaps	10,800	$	0.24
2016
Natural gas swaps	14,000	$	4.19
Natural gas basis protection swaps	8,400	$	0.36
2017
Natural gas swaps	12,700	$	3.64
2018
Natural gas swaps	8,250	$	3.83

On March 26, 2015, we entered into early settlements of certain oil and natural gas derivative contracts originally scheduled to settle between 2015 to 2017 covering 495,000 barrels of oil and 12,280 Bbtu of natural gas, receiving net proceeds of $15,395, in order to maintain compliance with the hedging limits imposed by covenants under our senior secured credit facility. The proceeds are included in non-hedge derivative gains (losses) disclosed below.

16

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, 2015						As of December 31, 2014
	Assets		Liabilities		Net value		Assets		Liabilities			Net value
Natural gas swaps	$	37,843	$	—	$	37,843	$	32,939	$	—		$	32,939
Oil swaps	19,168		—		19,168		23,465		—			23,465
Oil collars	1,700		—		1,700		1,175		—			1,175
Oil enhanced swaps	91,362		—		91,362		100,724		—			100,724
Oil purchased puts	85,987		—		85,987		93,268		—			93,268
Natural gas basis differential swaps	1,041		—		1,041		292		(309		)	(17		)
Total derivative instruments	237,101		—		237,101		251,863		(309		)	251,554
Less:
Netting adjustments (1)	—		—		—		232		(232		)	—
Current portion asset (liability)	166,873		—		166,873		179,921		(77		)	179,844
	$	70,228	$	—	$	70,228	$	71,710	$	—		$	71,710

___________

(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 at March 31, 2015 and December 31, 2014 were as follows:

	March 31, 2015		December 31, 2014
Derivative settlements receivable included in accounts receivable	$	41,092	$	19,678

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.

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

	Three months ended
	March 31,
	2015			2014
Change in fair value of commodity price swaps	$	606		$	(5,193	)
Change in fair value of collars	525			(2,863		)
Change in fair value of enhanced swaps and put options	(16,643		)	(10,527		)
Change in fair value of natural gas basis differential contracts	1,058			(1,861		)
Receipts from (payments on) settlement of commodity price swaps	19,027			(5,850		)
Payments on settlement of collars	—			(41		)
Receipts from (payments on) settlement of enhanced swaps and put options	56,949			(1,992		)
Payments on settlement of natural gas basis differential contracts	(91		)	(872		)
	$	61,431		$	(29,199	)

17

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

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, 2015 or December 31, 2014. Our derivative contracts classified as Level 2 as of March 31, 2015 and December 31, 2014 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, 2015 and December 31, 2014, our derivative contracts classified as Level 3 consisted of three-way collars, enhanced swaps, sold puts and purchased puts. The fair value of these contracts is developed by a third-party pricing service using a proprietary valuation model, which we believe incorporates the assumptions that market participants would have made at the end of each period. Observable inputs include contractual terms, published forward pricing curves, and yield curves. Significant unobservable inputs are implied volatilities. Significant increases (decreases) in implied volatilities in isolation would result in a significantly higher (lower) fair value measurement. We review these valuations and the changes in the fair value measurements for reasonableness. All derivative instruments are recorded at fair value and include a measure of our own nonperformance risk for derivative liabilities or that of our counterparties for derivative assets.

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

	As of March 31, 2015						As of December 31, 2014
	Derivative assets		Derivative liabilities		Net assets (liabilities)		Derivative assets			Derivative liabilities			Net assets (liabilities)
Significant other observable inputs (Level 2)	$	58,052	$	—	$	58,052	$	56,696		$	(309	)	$	56,387
Significant unobservable inputs (Level 3)	179,049		—		179,049		195,167			—			195,167
Netting adjustments (1)	—		—		—		(232		)	232			—
	$	237,101	$	—	$	237,101	$	251,631		$	(77	)	$	251,554

___________

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

18

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

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, 2015 and 2014 were: 

	Three months ended March 31,
Net derivative assets (liabilities)	2015			2014
Beginning balance	$	195,167		$	3,622
Realized and unrealized gains (losses) included in non-hedge derivative losses	40,831			(15,423		)
Settlements (received) paid	(56,949		)	2,033
Ending balance	$	179,049		$	(9,768	)
Gains relating to instruments still held at the reporting date included in non-hedge derivative gains (losses) for the period	$	14,639		$	(15,324	)

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 2015 and 2014 were escalated using an annual inflation rate of 2.91% and 2.95%, respectively, and discounted using our credit-adjusted risk-free interest rate of 12.40% and 5.80%, respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. 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, 2015 and December 31, 2014 were as follows:

	March 31, 2015				December 31, 2014
Level 2	Carrying value		Estimated fair value		Carrying value		Estimated fair value
9.875% Senior Notes due 2020	$	295,294	$	228,480	$	295,139	$	269,091
8.25% Senior Notes due 2021	400,000		278,000		400,000		270,000
7.625% Senior Notes due 2022	554,666		368,500		554,869		379,775
Senior secured revolving credit facility	450,000		450,000		347,000		347,000
Other secured long-term debt	14,099		14,099		14,957		14,957
	$	1,714,059	$	1,339,079	$	1,611,965	$	1,280,823

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.

19

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

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, 2015, the counterparties to our open derivative contracts consisted of eight financial institutions, of which eight 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)			Derivatives(1)		Amounts outstanding under senior secured revolving credit facility			Net amount
As of March 31, 2015
Derivative assets	$	237,101		$	—		$	237,101		$	—	$	(140,962	)	$	96,139
Derivative liabilities	—			—			—			—		—			—
	$	237,101		$	—		$	237,101		$	—	$	(140,962	)	$	96,139
As of December 31, 2014
Derivative assets	$	251,863		$	(232	)	$	251,631		$	—	$	(118,430	)	$	133,201
Derivative liabilities	(309		)	232			(77		)	—		—			(77		)
	$	251,554		$	—		$	251,554		$	—	$	(118,430	)	$	133,124

___________

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

We did not post additional collateral under any of these contracts as all of our counterparties are secured by the collateral under our senior secured revolving credit facility. Payment on our derivative contracts would be accelerated in the event of a default on our senior secured revolving credit facility. The aggregate fair value of our derivative liabilities subject to acceleration in the event of default was nil at March 31, 2015.

20

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

Note 6: Asset retirement obligations

The following table provides a summary of our asset retirement obligation activity during the three months ended March 31, 2015 and 2014.

	Three months ended March 31,
	2015			2014
Beginning balance	$	47,424		$	55,179
Liabilities incurred in current period	141			139
Liabilities settled and disposed in current period	(3,030		)	(170		)
Revisions in estimated cash flows	398			—
Accretion expense	931			1,074
Ending balance	45,864			56,222
Less current portion included in accounts payable and accrued liabilities	844			1,874
	$	45,020		$	54,348

See Note 5—Fair value measurements for additional information regarding fair value assumptions associated with our asset retirement obligations.

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.

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

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

21

Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

A summary of our phantom stock and RSU activity during the three months ended March 31, 2015 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, 2015	$	20.18	23,179				$	9.91	569,160
Granted	—		—				15.26		52,711
Vested	24.48		(6,649	)	$	25	10.58		(206,332	)	$	790
Forfeited	17.99		(4,907	)			9.62		(105,159	)
Unvested and outstanding at March 31, 2015	$	18.64	11,623				$	10.48	310,380

Based on an estimated fair value of $2.92 per phantom share and RSU as of March 31, 2015, the aggregate intrinsic value of the unvested phantom shares and RSUs outstanding was $940.

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 whereby CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively “CCMP”) receive cash upon the sale of its class E common stock (a “Transaction” as defined in the restricted stock agreements). 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.

Our 2010 Plan allows participants to elect, upon vesting of their Time Vested awards, to have us withhold shares having a fair market value greater than the minimum statutory withholding amounts for income and payroll taxes that would be due with respect to such vested shares. As a result of this provision, the Time Vested awards are classified as liability awards under accounting guidance and remeasured to fair value at the end of each reporting period. The Performance Vested awards are classified as equity awards and are not remeasured to fair value at the end of each reporting period subsequent to grant date.

We have previously modified the vesting conditions of awards granted under the 2010 Plan. Please see “Note 10—Stock-based compensation” in Item 8. Financial Statement and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2014, for a discussion of the modifications.

A summary of our restricted stock activity during the three months ended March 31, 2015 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, 2015	$	791.52	25,834				$	292.92	38,943
Granted	533.80		610				306.50		599
Vested	794.40		(6,354	)	$	3,392	—		—
Forfeited	764.16		(3,190	)			310.57		(8,719	)
Unvested and total outstanding at March 31, 2015	$	786.30	16,900				$	288.19	30,823

22

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Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

During the three months ended March 31, 2015 and 2014, respectively, we repurchased and canceled 1,404 and 1,068 vested shares, primarily for tax withholding, and we expect to repurchase and cancel approximately 2,000 restricted shares vesting during the next twelve months. Based on an estimated fair value of $533.80 per Time Vested restricted share, the aggregate intrinsic value of the unvested Time Vested restricted shares outstanding was $9,021 as of March 31, 2015.

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,
	2015			2014
Stock-based compensation cost	$	(1,500	)	$	2,531
Less: stock-based compensation cost capitalized	415			(962		)
Stock-based compensation expense	$	(1,085	)	$	1,569
Payments for stock-based compensation	$	812		$	874

We recorded a credit to our stock-based compensation expense for the three months ended March 31, 2015, due to forfeitures that occurred in conjunction with our workforce reduction in February 2015 and due to a decrease in the per-unit value of our phantom stock and RSU awards. As of March 31, 2015 and December 31, 2014, accrued payroll and benefits payable included $4,056 and $4,830, respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized compensation cost of approximately $14,793 is expected to be recognized over a weighted average period of 2.3 years.

Note 8: 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 $874 and $920 as of March 31, 2015 and December 31, 2014, 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, 2015 or 2014.

Litgation and Claims

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, an alleged class action was filed against us in the United States District Court for the Western District of Oklahoma (“Naylor Farms Case”) alleging that we improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners as categorized in the petition from crude oil and natural gas wells located in Oklahoma. The purported class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. The plaintiffs have alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. We have responded to the Naylor Farms petition, denied the allegations and raised arguments and defenses. Discovery is ongoing and information and documents continue to be exchanged. The class has not been certified, but the motion for class certification is due in the fourth quarter of 2015. We are not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the Naylor Farms Case will have on our financial condition, results of operations or cash flows due to the preliminary status of the matters, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, and the ultimate potential outcome of the matter. Plaintiffs in the Naylor Farms Case have indicated that, if the class is certified, they seek damages in excess of

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) –continued

(dollars in thousands, unless otherwise noted)

$5,000 which may increase with the passage of time, a majority of which would be comprised of interest. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.

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, (“Dodson Case”) with allegation similar to those asserted in the Naylor Farms case related to post-production deductions, and include clams for breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. The alleged class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. We have responded to the Dodson petition, denied the allegations and raised a number of affirmative defenses. At this time, a class has not been certified and discovery has not yet commenced. We are not currently able to estimate a reasonable possible loss or range of loss or what impact, if any, the Dodson Case will have on its financial condition, results of operations or cash flows due to the preliminary status of the matter, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, and the ultimate potential outcome of the matter. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.

Martha Donelson and John Friend, on behalf of themselves and on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On August 11, 2014, an alleged class action was filed against us, as well as several other operators in Osage County, in the United States District Court for the Northern District of Oklahoma (“Donelson Case”), alleging claims on behalf of the named plaintiffs and all similarly situated Osage County land owners and surface lessees. The plaintiffs assert claims seeking recovery for trespass, nuisance, negligence and unjust enrichment. Relief sought includes declaring oil and natural gas leases and drilling permits obtained in Osage County without a prior NEPA study void ab initio, removing us from all properties owned by the class members, disgorgement of profits, and compensatory and punitive damages. We have joined in Motions to Dismiss filed by the other defendants. At this time, a class has not been certified and discovery has yet to begin. As such, we are not yet able to estimate a possible loss, or range of possible loss, if any. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.

We are involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, employment claims, and other matters which arise in the ordinary course of business. While the outcome of these legal proceedings cannot be predicted with certainty, we do not expect any of them individually to have a material 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 CO₂ recycle compressors at our EOR facilities and 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, 2015, there were no material changes to our contractual commitments since December 31, 2014.

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

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

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

Overview

Founded in 1988, we are an independent oil and natural gas exploration and production company headquartered in Oklahoma City, Oklahoma and are one of the largest oil producers in the state. In recent years, we have capitalized on our sustained success in our Mid-Continent area, expanding our holdings to become a leading player in both the liquids-rich Northern Oklahoma Mississippian and the oil-rich Panhandle Marmaton plays. In addition, we have a leadership position in CO₂ Enhanced Oil Recovery (“EOR”) and are now the third largest CO₂ EOR operator in the United States based on 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 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, 2014 reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 21%, 14% and 12% for the next three years. To grow our production and cash flow, we must find, develop and acquire new oil and natural gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire oil and natural gas reserves.

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

• cash flow available for capital expenditures;

• ability to borrow and raise additional capital;

• ability to service debt;

• quantity of oil and natural gas we can produce;

• quantity of oil and natural gas reserves; and

• operating results for oil and natural gas activities.

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Business and Industry Outlook

Crude oil prices decreased significantly in the latter part of 2014 and have continued to trend lower in 2015, dropping to their lowest levels since March 2009. Management's plans and related capital projections for 2015 are reflective of lower commodity prices.

In response to the decrease in crude oil prices, in February 2015 we began implementation of a Company-wide effort to decrease our capital, operating and administrative costs. Our cost reduction initiatives included a reduction in our workforce by 180 employees, of which 121 were located in the Oklahoma City headquarters office and 59 were located at various field offices. In connection with our workforce reduction, we recorded a charge of $6.5 million during the first quarter of 2015 related to one-time severance and termination benefits.

Given the weak commodity price environment, we have aggressively pursued price concessions from third-party service vendors. Based on expected cost reductions from service providers and improved operational efficiencies, we anticipate decreases of 20% - 30% in drilling and completion costs and 15% - 20% in lease operating expenses for 2015. We are continuing negotiations with our vendors to receive the best possible pricing.

As part of our cost reduction initiatives, we engaged third party legal and professional services for which we have incurred expenses of approximately $2.3 million for the three months ended March 31, 2015. As discussed below in “Liquidity and capital resources,” we are allowed to exclude up to $25.0 million of expenses incurred in connection with our cost reduction initiatives, including costs related to our workforce reduction, from our EBITDA-based covenant under our senior secured revolving credit facility.

We have significantly reduced our 2015 capital expenditures budget to $177.3 million, nearly one quarter the amount spent in 2014. We expect our operated rig count to average 2 rigs for full-year 2015, down from 10 operated rigs at December 31, 2014. As of April 7, 2015, we are operating one rig. While we have scaled back our 2015 drilling, we plan to continue the momentum of our long-term growth projects in our Mid-Continent area by focusing our drilling efforts in core areas of those plays that have the greatest potential to improve recoveries and rates of return.

Our 2015 capital budget was established based on an expectation of spending within available cash flows from operations, which included additional borrowings under our credit agreement during the first quarter as we reduced our accounts payable, with expected pay-down of those borrowings beginning in the second quarter. We will continue to monitor our capital spending closely based on actual and projected cash flows and could scale back our 2015 spending further should commodity prices fall further. Conversely, a significant improvement in crude oil prices could result in an increase in our capital expenditures.

We deal with volatility in commodity prices primarily by maintaining flexibility in our capital investment program with a diversified drilling portfolio and limited long-term commitments, which enables us to respond quickly to industry price volatility, as well as by aggressively pursuing cost reductions in a market downturn. However, price volatility impacts our business in various other ways, including our full cost ceiling test calculation. The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending on the balance sheet date. For the year ended December 31, 2014, those prices were $94.99 per Bbl for oil and $4.35 per MMBtu for natural gas, while the unweighted arithmetic average prices of crude oil and natural as of the first day of each month for the 12-month period through March 2015 were $82.72 per Bbl and $3.88 per MMBtu, respectively. Prices have remained low into the second quarter. If commodity prices remain at the current level, the average prices used in the ceiling test calculation will decline and will likely cause write-downs of our oil and natural gas properties, which could occur as early as the second quarter of 2015. Continued write-downs of oil and natural gas properties may occur until such time as commodity prices recover, and remain at recovered levels, so as to meaningfully increase the 12-month average price used in the ceiling test calculation. In addition to commodity prices, our production rates, levels of proved reserves, estimated future operating expenses, estimated future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

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2015 Highlights

During the first quarter of 2015, production increased9% to 2,826 MBoe compared to production of 2,591 MBoe during the first quarter of 2014, primarily due to our drilling activity and increased EOR production response partially offset by our significant property divestitures. Despite production increases, revenue from commodity sales was $(80.3) million lower in the first quarter of 2015 compared to the first quarter in 2014 as a result of the 51% decrease in average realized prices. Additionally, due primarily to downward changes in the NYMEX forward commodity price curves, we had a non-hedge derivative gain of $61.4 million in the first quarter of 2015 compared to $29.2 million of non-hedge derivative losses during the same period last year. As a result of these and other factors, we reported a net gain of $4.2 million during the first quarter of 2015 compared to a net gain of $4.4 million for the comparable period in 2014.

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:

• Capital expenditures. Our oil and natural gas property capital expenditure budget for 2015 is set at $177.3 million. Our capital expenditures during the three months ended March 31, 2015 were $71.6 million, consisting primarily of $44.9 million in drilling and completion expenditures in our E&P Areas, $13.8 million for our EOR Project Areas (excluding acquisitions) and $9.2 million for the acquisition of oil and natural gas properties and leasehold.

• Senior secured revolving credit facility and liquidity. We have entered into an amendment to our senior secured revolving credit facility effective April 1, 2015, pursuant to which our borrowing base was redetermined to $550.0 million and certain covenants were revised as discussed further in “Liquidity and Capital Resources—Senior secured revolving credit facility” and “Note 3—Long-term debt” in Item 1. Financial Statements and Supplementary Data of this report.

Results of operations

Production

Production volumes by area were as follows (MBoe):

	Three months ended		Percent change
	March 31,
	2015	2014
E&P Areas
Mississippian	810	526	54.0	%
Panhandle Marmaton	244	185	31.9	%
Woodford Shale	151	23	556.5	%
Oswego	112	64	75.0	%
Legacy Production Areas	647	689	(6.1	)%
Total E&P Areas	1,964	1,487	32.1	%
EOR Project Areas
Active EOR Projects	538	395	36.2	%
Potential EOR Projects	317	342	(7.3	)%
Total EOR Project Areas	855	737	16.0	%
Non-Core Properties	7	367	(98.1	)%
Total	2,826	2,591	9.1	%

E&P Areas

E&P Areas includes our Mississippian, Panhandle Marmaton, Oswego and Woodford Shale plays, which are our repeatable resource 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.

The increase in production in our E&P Areas for the three months ended March 31, 2015 compared to the same period in 2014 is primarily due to our drilling and development activities in our Mississippian and Woodford Shale plays, slightly offset by decreased production in our Legacy Production Areas. The Mississippian and Woodford Shale plays accounted for

27

approximately 34%, and 21% of our total production during the three months ended March 31, 2015 and 2014, respectively. The decrease in production in our Legacy Production Areas is primarily due to strategic divestitures within these areas and normal production decline in the last twelve months concentrated in our Anadarko Cleveland Sand and Granite Wash plays.

EOR Project Areas

Our EOR Project Areas include both currently Active EOR Projects and Potential EOR Projects. Potential EOR Projects have no current EOR production or reserves at March 31, 2015. 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 for the three months ended March 31, 2015 compared to the same period in 2014 were primarily due to production response in our North Burbank Unit and in our Farnsworth Unit.

Non-Core Properties

As discussed in our Annual Report on Form 10-K for the year ended December 31, 2014, we sold most of our our Ark-La-Tex, Permian Basin, and North Texas properties during 2014. Production decreases in our Non-Core Properties were primarily due to divestitures within these areas. The remaining production within our Non-Core Properties is primarily attributable to properties we still own in our Gulf Coast areas.

Revenues

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

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

	Three months ended				Increase / (Decrease)			Percent change
	March 31,
	2015		2014
Commodity sales (in thousands)
Oil	$	71,765	$	135,119	$	(63,354	)	(46.9	)%
Natural gas	14,147		25,152		(11,005		)	(43.8	)%
Natural gas liquids	7,167		13,068		(5,901		)	(45.2	)%
Total commodity sales	$	93,079	$	173,339	$	(80,260	)	(46.3	)%
Production
Oil (MBbls)	1,573		1,415		158			11.2	%
Natural gas (MMcf)	4,958		5,173		(215		)	(4.2	)%
Natural gas liquids (MBbls)	427		314		113			36.0	%
MBoe	2,826		2,591		235			9.1	%
Average daily production (Boe/d)	31,400		28,789		2,611			9.1	%
Average sales prices (excluding derivative settlements)
Oil per Bbl	$	45.62	$	95.49	$	(49.87	)	(52.2	)%
Natural gas per Mcf	$	2.85	$	4.86	$	(2.01	)	(41.4	)%
NGLs per Bbl	$	16.78	$	41.62	$	(24.84	)	(59.7	)%
Average sales price per Boe	$	32.94	$	66.90	$	(33.96	)	(50.8	)%

Our total commodity sales decreased significantly during the three months ended March 31, 2015 compared to the three months ended March 31, 2014 as a result of a 51%decrease in the average price per Boe offset slightly by a 9%increase in production volumes sold.

Average production volumes sold increased by 2,611 Boe per day, or 9%, during the three months ended March 31, 2015 compared to the three months ended March 31, 2014. The increase in average production volumes sold was primarily a result of new production from wells that were completed during the twelve months ended March 31, 2015 plus response from our EOR Project Areas which more than offset the decrease due to the strategic divestitures of our Non-Core properties during the period

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and the decline in production in wells that were producing as of March 31, 2014. Average daily production volumes sold in our Mississippian and Woodford Shale plays increased by approximately 3,156 Boe per day, and 1,422 Boe per day, respectively, during the first quarter of 2015 compared to the first quarter of 2014, primarily as a result of our recent well completions. Average daily production volumes sold in our Active EOR project areas increased by approximately 1,589 Boe per day during the first quarter of 2015 compared to the first quarter of 2014, primarily as a result of production response in our North Burbank Unit and in our Farnsworth Unit. These increases were partially offset by a decrease in average production volumes sold in our Non-Core Properties and our Legacy Production Areas primarily due to strategic divestitures combined with declines in production and reduced 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,
	2015 vs. 2014
(in thousands)	Sales change			Percentage change in sales
Change in oil sales due to:
Prices	$	(78,441	)	(58.1	)%
Production	15,087			11.2	%
Total change in oil sales	$	(63,354	)	(46.9	)%
Change in natural gas sales due to:
Prices	$	(9,960	)	(39.6	)%
Production	(1,045		)	(4.2	)%
Total change in natural gas sales	$	(11,005	)	(43.8	)%
Change in natural gas liquids sales due to:
Prices	$	(10,604	)	(81.2	)%
Production	4,703			36.0	%
Total change in natural gas liquids sales	$	(5,901	)	(45.2	)%

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,
	2015			2014
Oil (per Bbl)(1):
Before derivative settlements	$	39.47		$	85.71
After derivative settlements (2)	$	66.61		$	83.86
Post-settlement to pre-settlement price	168.8		%	97.8		%
Natural gas (per Mcf):
Before derivative settlements	$	2.85		$	4.86
After derivative settlements (2)	$	4.11		$	3.79
Post-settlement to pre-settlement price	144.2		%	78.0		%

(1) Includes natural gas liquids.

(2) Does not include settlements received from the early monetization of our derivative contracts discussed below.

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, 2015		December 31, 2014
Derivative assets (liabilities):
Natural gas swaps	$	37,843	$	32,939
Oil swaps	19,168		23,465
Oil collars	1,700		1,175
Oil enhanced swaps	91,362		100,724
Oil purchased puts	85,987		93,268
Natural gas basis differential swaps	1,041		(17		)
Net derivative assets	$	237,101	$	251,554

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,
	2015						2014
(in thousands)	Non-cash fair value adjustment			Cash receipts (payments)			Non-cash fair value adjustment			Cash receipts (payments)
Non-hedge derivative gains (losses):
Oil swaps, collars, enhanced swaps and puts	$	(20,415	)	$	64,403		$	(14,040	)	$	(3,194	)
Natural gas swaps	4,903			11,573			(4,543		)	(4,689		)
Natural gas basis differential contracts	1,058			(91		)	(1,861		)	(872		)
Non-hedge derivative (losses) gains	$	(14,454	)	$	75,885		$	(20,444	)	$	(8,755	)

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 our consolidated statements of operations. Non-hedge derivative gains (losses) were $61.4 million during the three months ended March 31, 2015 compared to $(29.2) million during the three months ended March 31, 2014. 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.

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On March 26, 2015, we entered into early settlements of certain oil and natural gas derivative contracts originally scheduled to settle between 2015 to 2017 covering 495,000 barrels of oil and 12,280 Bbtu of natural gas for net proceeds of $15,395 in order to maintain compliance with the hedging limits imposed by covenants under our senior secured credit facility. The proceeds are included in the cash receipts related to the gains (losses) from derivative activities in the table above.

Lease operating expenses

	Three months ended March 31,				Increase / (Decrease)			Percent change
	2015		2014
Lease operating expenses (in thousands, except per Boe data)
E&P Areas	$	13,820	$	17,664	$	(3,844	)	(21.8	)%
EOR Project Areas	$	17,812	$	15,991	$	1,821		11.4	%
Total lease operating expense	$	31,632	$	33,655	$	(2,023	)	(6.0	)%
Lease operating expenses per Boe
E&P Areas	$	7.01	$	9.53	$	(2.52	)	(26.4	)%
EOR Project Areas	$	20.83	$	21.70	$	(0.87	)	(4.0	)%
Lease operating expenses per Boe	$	11.19	$	12.99	$	(1.80	)	(13.9	)%

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

Our E&P Areas lease operating expenses decreased during the three months ended March 31, 2015 compared to the three months ended March 31, 2014 primarily as a result of the divestiture of certain non-core assets with higher operating costs and temporary shut-in of marginal wells due to the current low price environment partially offset by the incremental cost associated with new wells added during the last twelve months. Our E&P Areas lease operating expenses on a per Boe basis decreased primarily as a result of the divestiture of certain non-core assets with higher operating costs combined with the overall increase in production volumes between periods.

Our EOR Project Areas lease operating expenses increased during the three months ended March 31, 2015 compared to the three months ended March 31, 2014 primarily due to additional costs associated with expansion of our EOR floods at our North Burbank and Farnsworth units. Our EOR Project Areas lease operating expenses on a per Boe basis decreased primarily as a result of the overall increase in production volumes between periods.

Transportation and processing expenses

	Three months ended March 31,				Increase / (Decrease)		Percent change
	2015		2014
Transportation and processing expenses (in thousands)	$	2,372	$	1,366	$	1,006	73.6	%
Transportation and processing expenses per Boe	$	0.84	$	0.53	$	0.31	58.5	%

Transportation and processing expenses principally consist of expenditures to prepare and transport production from the wellhead to a specified sales point and gas processing costs. Our transportation and processing expenses increased during the three months ended March 31, 2015 compared to the three months ended March 31, 2014 as a result of the overall increase in natural gas liquids volumes processed in between periods primarily from our participation interests in wells drilled in the Cana Woodford Shale during the last twelve months.

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Production taxes (which include ad valorem taxes)

	Three months ended March 31,				Increase / (Decrease)			Percent change
	2015		2014
Production taxes (in thousands)	$	4,484	$	6,643	$	(2,159	)	(32.5	)%
Production taxes per Boe	$	1.59	$	2.56	$	(0.97	)	(37.9	)%

Production taxes generally change in proportion to commodity sales. Some states offer exemptions or reduced production tax rates for horizontal drilling, enhanced recovery projects and high cost gas wells. In Oklahoma, new wells currently qualify for a tax incentive and are taxed at a lower rate of 1% during their initial 48 months of production. Recent legislation increases the tax incentive rate to 2% for the initial 36 months of production for wells spudded on or after July 1, 2015. After the incentive period expires, the tax rate reverts to the statutory rate.

Our production taxes decreased during the three months ended March 31, 2015 compared to the three months ended March 31, 2014 primarily due to our 51%decrease in the average price on our commodity sales. Also contributing to the decline were our strategic divestitures of wells in our Non-Core Properties and Legacy Production Areas, which generally had higher tax rates, and reduced tax rates for horizontal drilling and our EOR projects. These increases were partially offset by the 9%increase in sales volumes.

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

	Three months ended March 31,				Increase / (Decrease)			Percent change
	2015		2014
DD&A (in thousands):
Oil and natural gas properties	$	61,896	$	52,159	$	9,737		18.7	%
Property and equipment	2,384		2,517		(133		)	(5.3	)%
Accretion of asset retirement obligation	931		1,074		(143		)	(13.3	)%
Total DD&A	$	65,211	$	55,750	$	9,461		17.0	%
DD&A per Boe:
Oil and natural gas properties	$	21.90	$	20.13	$	1.77		8.8	%
Other fixed assets	$	1.17	$	1.39	$	(0.22	)	(15.8	)%
Total DD&A per Boe	$	23.07	$	21.52	$	1.55		7.2	%

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. Thus, our DD&A rate could change significantly in the future.

DD&A on oil and natural gas properties increased $9.7 million for the three months ended March 31,2015, compared to the three months ended March 31, 2014, of which $5.0 million was due to a higher rate per equivalent unit of production and $4.7 million was due to an increase in production. Our DD&A rate per equivalent unit of production increased for the three months ended March 31,2015 primarily due to higher cost reserve additions combined with an increase in our amortization base which included the transfer of amounts from unevaluated oil and gas properties to proved oil and natural gas properties in the fourth quarter of 2014.

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General and administrative expenses (“G&A”)

	Three months ended March 31,						Increase / (Decrease)			Percent change
	2015			2014
G&A and cost reduction initiatives (in thousands):
Gross G&A expenses	$	12,032		$	20,140		$	(8,108	)	(40.3	)%
Capitalized exploration and development costs	(2,838		)	(6,753		)	3,915			(58.0	)%
Net G&A expenses	$	9,194		$	13,387		$	(4,193	)	(31.3	)%
Cost reduction initiatives	$	8,774		$	—		$	8,774		n/a
Net G&A and cost reduction initiatives expense	$	17,968		$	13,387		$	4,581		34.2	%
Average G&A expense per Boe	$	3.25		$	5.17		$	(1.92	)	(37.1	)%
Average G&A and cost reduction initiatives expense per Boe	$	6.36		$	5.17		$	1.19		23.0	%

Gross G&A expenses decreased during the three months ended March 31, 2015, compared to the three months ended March 31, 2014, primarily due to forfeitures of deferred compensation awards and lower compensation and benefits costs. Compensation and benefits were lower due to lower headcount subsequent to our workforce reduction and due to the lower commodity price environment.

Capitalized exploration and development costs decreased between periods primarily due to a lower proportion of compensation costs subject to capitalization in our current lower commodity price environment.

Cost reduction initiatives includes expenses related to our efforts to reduce our capital, operating and administrative costs in response to the recent deterioration of commodity prices. Included in our expenses for cost reduction initiatives are $6.5 million in one-time severance and termination benefits in connection with our reduction in force that was implemented in February 2015. The remaining cost reduction expense is a result of third party legal and professional services we have engaged to assist in these initiatives. As discussed below in “Liquidity and capital resources,” we are allowed to exclude up to $25.0 million of expenses incurred in connection with our cost reduction initiatives, including costs related to our workforce reduction, from our EBITDA-based covenant under our senior secured revolving credit facility.

Our G&A expenses on a Boe basis decreased for the three months ended March 31, 2015 compared to the three months ended March 31, 2014 primarily due to these same factors combined with the increase in overall production volumes between periods.

Other income and expenses

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

	Three months ended
	March 31,
(in thousands)	2015			2014
9.875% Senior Notes due 2020	$	7,714		$	7,683
8.25% Senior Notes due 2021	8,431			8,416
7.625% Senior Notes due 2022	10,554			10,534
Senior secured revolving credit facility	2,164			1,419
Bank fees and other interest	1,311			1,349
Capitalized interest	(3,462		)	(2,942		)
Total interest expense	$	26,712		$	26,459
Average long-term borrowings	$	1,694,802		$	1,575,976

Total interest expense for the three months ended March 31, 2015 increased 1% compared to the three months ended March 31, 2014 primarily due to increased levels of borrowing on our senior secured revolving credit facility and reduced capitalized interest.

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Liquidity and capital resources

Historically, our primary sources of liquidity have been cash generated from our operations, debt, private equity sales and proceeds from asset dispositions. As of March 31, 2015, we had cash and cash equivalents of $42.2 million and had borrowed $450.0 million under our senior secured revolving credit facility with a borrowing base of $650.0 million. As of May 12, 2015, we had borrowed $450.0 million under our senior secured revolving credit facility with a borrowing base of $550.0 million.

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.

All of our sources of liquidity can be impacted by the general condition of the broader economy and by fluctuations in commodity prices, operating costs, and volumes produced, all of which affect us and our industry. We have no control over the market prices for oil, gas, or NGLs, although we are able to influence the amount of our realized revenues from our oil, gas, and NGL sales through the use of derivative contracts as part of our commodity price risk management program. Historically, decreases in commodity prices have limited our industry’s access to capital markets. The borrowing base under our credit facility has been and could be further reduced as a result of lower commodity prices and divestitures of proved properties. Beginning in the third quarter of 2014 and continuing into the present, oil, natural gas and NGL commodity prices declined significantly and are expected to fluctuate in the future. We deal with volatility in commodity prices primarily by our derivative hedging program and maintaining flexibility in our capital investment program with a diversified drilling portfolio and limited long-term commitments, which enables us to respond quickly to industry price volatility, as well as aggressively pursuing cost reductions in a market downturn. The profitability of the oil and gas operations and the ability to realize recorded asset values is dependent on the success of future development plans and projected long-term market conditions.

Sources and uses of cash

Our net change in cash is summarized as follows:

	Three months ended						Increase / (Decrease)			Percent Change
	March 31,
(in thousands)	2015			2014
Cash flows (used in) provided by operating activities	$	(13,022	)	$	74,239		$	(87,261	)	(117.5	)%
Cash flows used in investing activities	(77,845		)	(130,427		)	52,582			(40.3	)%
Cash flows provided by financing activities	101,548			46,250			55,298			119.6	%
Net increase (decrease) in cash during the period	$	10,681		$	(9,938	)	$	20,619		(207.5	)%

Our cash flows from operating activities is derived substantially from the production and sale of oil and natural gas. Our cash flows from operating activities were lower in the current year due to a decrease in commodity sales driven by lower prices on all our commodities and due to expenses associated with our cost reduction initiatives.

When available, we use the net cash provided by operations to partially fund our acquisition, exploration and development activities. Our acquisition, exploration and development activities and our payments of accounts payable for the three months ended March 31, 2015, were funded by settlement proceeds from our derivative instruments and borrowings from our senior secured borrowing credit facility. For the three months ended March 31, 2014 cash flows provided by operating activities were approximately 54%, of cash used for the acquisition and development of our property.

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

We expect our capital expenditure for 2015 to be more heavily-focused on the first half of the year with 40% of our annual budget incurred as of March 31, 2015 and approximately 60% to be incurred by mid-year. Our actual costs incurred, including costs that we have accrued for, and our budgeted 2015 capital expenditures for oil and natural gas properties during the three months ended March 31, 2015 are summarized in the following table:

(in thousands)	E&P Areas		EOR Project Areas		Non-Core Properties		Total		2015 Capital Expenditures Budget (1)(2)
Acquisitions	$	9,161	$	—	$	37	$	9,198	$	19,971
Drilling	44,875		—		—		44,875		97,703
Enhancements	3,562		3,307		188		7,057		26,386
Pipeline and field infrastructure	—		5,791		—		5,791		8,624
CO2 purchases	—		4,704		—		4,704		24,656
Total	$	57,598	$	13,802	$	225	$	71,625	$	177,340

___________

(1) Includes $49.6 million allocated to our EOR project areas as follows: enhancements of $16.3 million, pipeline and field infrastructure of $8.6 million, and CO₂ purchases of $24.7 million.

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

Net cash used in investing activities during the three months ended March 31, 2015 was comprised of cash outflows for capital expenditure of $156.8 million, partially offset by cash inflows from derivative settlement receipts of $75.9 million and asset dispositions of $3.1 million. Our cash outflows for capital expenditure is greater than our actual costs incurred for the period, disclosed in the table above, as a result of payments in the current period for expenditures accrued at the end of the prior year. Net cash used in investing activities during the three months ended March 31, 2014 was comprised primarily of cash outflows for capital expenditure of $138.7 million and derivative settlement payments of $8.8 million, partially offset by cash inflows from asset dispositions of $17.0 million.

Cash flows from financing activities is comprised primarily of cash inflows from long-term debt borrowings, offset by cash outflows from repayments of long-term debt and capital leases. During the three months ended March 31, 2015, we had borrowings of $103.0 million which were partially offset by repayments of $0.9 million on our long-term debt and $0.6 million on our capital leases. During the three months ended March 31, 2014, we had borrowings of $50.6 million, partially offset by repayments of $3.8 million on our long-term debt and $0.6 million on our capital leases.

Indebtedness

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

(in thousands)	March 31, 2015		December 31, 2014
9.875% Senior Notes due 2020, net of discount of $4,706 and $4,861, respectively	$	295,294	$	295,139
8.25% Senior Notes due 2021	400,000		400,000
7.625% Senior Notes due 2022, including premium of $4,666 and $4,869, respectively	554,666		554,869
Senior secured revolving credit facility	450,000		347,000
Real estate mortgage notes	10,577		10,705
Installment notes	3,522		4,252
Capital lease obligations	21,245		21,837
	$	1,735,304	$	1,633,802

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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, 2014 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 March 31, 2015, we have $450.0 million of outstanding borrowings under our senior secured revolving credit facility. Our borrowing base on the facility decreased from $650.0 million to $550.0 million effective April 1, 2015

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.

Our senior secured revolving credit facility requires us to maintain a current ratio, as defined in our senior secured revolving credit facility, of not less than 1.0 to 1.0. The definition of current assets and current liabilities used for determination of the current ratio computed for loan compliance purposes differs from current assets and current liabilities determined in compliance with GAAP. Since compliance with financial covenants is a material requirement under our senior secured revolving credit facility, we consider the current ratio calculated under our senior secured revolving credit facility to be a useful measure of our liquidity because it includes the funds available to us under our senior secured revolving credit facility and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. The following table discloses the current ratio for our loan compliance compared to the ratio calculated per GAAP.

(dollars in thousands)	March 31, 2015			December 31, 2014
Current assets per GAAP	$	342,110		$	339,898
Plus—Availability under senior secured revolving credit facility	199,126			302,080
Less—Short-term derivative instruments	(166,873		)	(179,921		)
Current assets as adjusted	$	374,363		$	462,057
Current liabilities per GAAP	$	221,269		$	328,366
Less—Short-term derivative instruments	—			(77		)
Less—Short-term asset retirement obligations	(844		)	(4,147		)
Less—Deferred tax liability on derivative instruments and asset retirement obligations	(62,394		)	(65,799		)
Current liabilities as adjusted	$	158,031		$	258,343
Current ratio for loan compliance	2.37			1.79
Current ratio per GAAP	1.55			1.04

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, 2015, availability under our senior secured revolving credit facility was limited to $199.1 million which was not limited by the Consolidated Net Debt to Consolidated EBITDAX ratio.

We have entered into an amendment to our senior secured revolving credit facility (the “Fifteenth Amendment”) effective April 1, 2015. Among other things, the amendment replaced the Consolidated Net Debt to Consolidated EBITDAX covenant described above with a covenant based on the ratio of Consolidated Net Secured Debt to Consolidated EBITDAX, as defined in the Fifteenth Amendment. Under this covenant, we are required to maintain a ratio of Consolidated Net Secured Debt to Consolidated EBITDAX no greater than 2.25 to 1.0 for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter. For the same applicable periods, the Fifteenth Amendment also requires us to maintain an Interest Coverage Ratio, as defined in the Fifteenth Amendment, of no less than 2.00 to 1.00. The Fifteenth Amendment revised the definition of Consolidated EBITDAX to exclude up to $25.0 million in expenses incurred subsequent to January 1, 2015, in connection with our cost reduction initiatives, transition, business optimization and other restructuring charges. The charges we

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have incurred to date under this category are described above under “Results of operations - General and administrative expenses.” Under the Fifteenth Amendment, we are also allowed to incur an additional $300.0 million in Additional Permitted Debt, as defined in the Fifteenth Amendment to now include both secured and unsecured debt.

Capital Leases

During 2013, we entered into lease financing agreements with U.S. Bank National Association for $24.5 million through the sale and subsequent leaseback of existing compressors owned by us. The carrying value of these compressors is included in our oil and natural gas full cost pool.The lease financing obligations are for 84-month terms and include the option to purchase the equipment for a specified price at 72 months as well as an option to purchase the equipment at the end of the lease term for its then-current fair market value. Lease payments related to the equipment are recognized as principal payments and interest expense.

Asset divestitures and alternative capital sources

As discussed in our Annual Report on Form 10-K for the year ended December 31, 2014, during 2014 we sold various oil and natural gas properties primarily located in our Ark-La-Tex, Permian Basin, and North Texas areas. Our asset sales in 2014 generated a total of $291.4 million in cash. Proceeds from our property sales provide us with an additional source of liquidity to pay down borrowings under our senior secured revolving credit facility, fund capital expenditures and for general corporate purposes. Our external sources of liquidity in the future may include asset sales, additional public or private issuances of common or preferred stock, or project financing. While we believe we would be able to obtain funds through one or more of these alternative sources if needed, we cannot provide assurance that these resources would be available on terms acceptable to us.

Contractual Obligations

We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases, capital leases and purchase obligations. Our operating leases primarily relate to CO₂ recycle compressors at our EOR facilities and 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 borrowings under our senior secured credit facility during the three months ended March 31, 2015, there were no material changes to our contractual commitments since December 31, 2014.

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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) non-cash change in fair value of non-hedge derivative instruments, (5) interest income, (6) stock-based compensation expense, (7) gain or loss on disposed assets, (8) upfront premiums paid on settled derivative contracts, (9) impairment charges, and (10) expenses associated with our cost reduction initiatives, transition, business optimization and other restructuring charges not to exceed $25.0 million in 2015 (as allowed under our senior secured revolving credit facility) and (11) other significant, unusual non-cash charges.

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

	Three months ended March 31,
(in thousands)	2015			2014
Net income (loss)	$	4,248		$	4,405
Interest expense	26,712			26,459
Income tax expense	2,557			2,635
Depreciation, depletion, and amortization	65,211			55,750
Non-cash change in fair value of non-hedge derivative instruments	14,454			20,444
Upfront premiums paid on settled derivative contracts	—			(166		)
Interest income	(123		)	(15		)
Stock-based compensation expense	(922		)	1,238
Gain on sale of assets	(79		)	(84		)
Cost reduction initiatives expense	8,774			—
Adjusted EBITDA	$	120,832		$	110,666

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, 2014.

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, 2015, our gross revenues from oil and natural gas sales would change approximately $2.0 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. Please see “Note 4—Derivative instruments” in Item 1. Financial statements of this report for further discussion of our derivative instruments.

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

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Our outstanding crude oil derivative instruments as of March 31, 2015 are summarized below:

		Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls	Swaps		Sold puts		Purchased puts		Sold calls		Average Premium
April - June 2015
Swaps	150	$	96.60	$	—	$	—	$	—	$	—
Swaps with deferred premium (1)	1,418	$	93.32	$	—	$	—	$	—	$	13.80
July - September 2015
Swaps	150	$	95.12	$	—	$	—	$	—	$	—
Swaps with deferred premium (1)	1,305	$	92.48	$	—	$	—	$	—	$	13.80
October - December 2015
Swaps	150	$	94.03	$	—	$	—	$	—	$	—
Swaps with deferred premium (1)	1,305	$	92.48	$	—	$	—	$	—	$	13.80
January - March 2016
Three-way collars	60	$	—	$	84.00	$	92.00	$	101.01	$	—
Enhanced swaps (2)	960	$	92.98	$	80.50	$	—	$	—	$	—
Purchased puts (2)	960	$	—	$	—	$	60.00	$	—	$	5.54
April - June 2016
Three-way collars	60	$	—	$	84.00	$	92.00	$	101.01	$	—
Enhanced swaps (2)	960	$	92.98	$	80.50	$	—	$	—	$	—
Purchased puts (2)	960	$	—	$	—	$	60.00	$	—	$	5.54
July - September 2016
Three-way collars	60	$	—	$	84.00	$	92.00	$	101.01	$	—
Enhanced swaps (2)	900	$	92.91	$	80.53	$	—	$	—	$	—
Purchased puts (2)	900	$	—	$	—	$	60.00	$	—	$	5.54
October - December 2016
Three-way collars	60	$	—	$	84.00	$	92.00	$	101.01	$	—
Enhanced swaps (2)	900	$	92.91	$	80.53	$	—	$	—	$	—
Purchased puts (2)	900	$	—	$	—	$	60.00	$	—	$	5.54

___________

(1) As a result of the deferred premiums, the above 4,028,000 barrels of crude oil production in 2015 are hedged at an average effective price of $78.98/barrel.

(2) Total premiums of $20,609 for the purchased puts were paid at contract inception in December 2014. Excluding the premiums and utilizing an average NYMEX strip price of $57.74 for 2016 as of March 31, 2015, the average realized price from our 3,720,000 barrels of hedged production that have associated sold puts and purchased puts is $72.42/barrel. This effective price is also the floor on the realized price we would receive in the event of any crude oil price decline below$60.00/barrel. Upon settlement, in the event that prices increase above $60.00/barrel, our effective price would increase by a commensurate amount of the price increase until prices reach the sold put price after which we would receive the swap price.

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Our outstanding natural gas derivative instruments as of March 31, 2015 are summarized below:

Period and type of contract	Volume BBtu	Weighted average fixed price per MMBtu
April - June 2015
Natural gas swaps	4,320	$	4.06
Natural gas basis protection swaps	3,600	$	0.24
July - September 2015
Natural gas swaps	3,980	$	4.15
Natural gas basis protection swaps	3,600	$	0.24
October - December 2015
Natural gas swaps	3,940	$	4.24
Natural gas basis protection swaps	3,600	$	0.24
January - March 2016
Natural gas swaps	3,950	$	4.30
Natural gas basis protection swaps	2,100	$	0.36
April - June 2016
Natural gas swaps	3,300	$	4.10
Natural gas basis protection swaps	2,100	$	0.36
July - September 2016
Natural gas swaps	3,300	$	4.13
Natural gas basis protection swaps	2,100	$	0.36
October - December 2016
Natural gas swaps	3,450	$	4.19
Natural gas basis protection swaps	2,100	$	0.36
January - March 2017
Natural gas swaps	3,730	$	3.72
April - July 2017
Natural gas swaps	2,790	$	3.52
July - September 2017
Natural gas swaps	3,300	$	3.58
October - December 2017
Natural gas swaps	2,880	$	3.71
January - March 2018
Natural gas swaps	2,390	$	3.98
April - July 2018
Natural gas swaps	2,010	$	3.68
July - September 2018
Natural gas swaps	1,960	$	3.74
October - December 2018
Natural gas swaps	1,890	$	3.90

Interest rates. All of the outstanding borrowings under our senior secured revolving facility as of March 31, 2015 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

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(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 $650.0 million, equal to our borrowing base at March 31, 2015, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $6.5 million.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure controls and procedures

We have established disclosure controls and procedures to ensure that material information relating to us, including our consolidated subsidiaries, is made known to the officers who certify our financial reports and to other members of senior management and the board of directors. Based on their evaluation as of the end of the period covered by this quarterly report, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and are effective to ensure that information required to be disclosed in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Internal control over financial reporting

There were no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We may make changes in our internal control procedures from time to time.

PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Please see “Note 8—Commitments and contingencies” in Item 1. Financial statements of this report for a discussion of our material legal proceedings. In our opinion, there are no other material pending legal proceedings to which we are a party or of which any of our property is the subject. However, due to the nature of our business, certain legal or administrative proceedings may arise from time to time in the ordinary course of business. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to have a material adverse effect on our financial condition, results of operations or cash flows.

ITEM 1A. RISK FACTORS

Studies by both state or federal agencies demonstrating a correlation between earthquakes and oil and natural gas activities could result in increased regulatory and operational burdens

In our Annual Report on Form 10-K for the year ended December 31, 2014, filed March 31, 2015, we stated that some parties believe there is a correlation between the operation of underground injection wells for the disposal of produced water and the increased occurrence of earthquakes in Oklahoma, but that the results of state and federal studies on the existence of a correlation are uncertain.  On April 21, 2015, the Oklahoma Geologic Survey (“OGS”) issued a document entitled “Statement of Oklahoma Seismicity,” in which the agency states “[t]he OGS considers it very likely that the majority of recent earthquakes, particularly those in central and north-central Oklahoma, are triggered by the injection of produced water in disposal wells.”  This development may result in additional levels of regulation, or increased complexity with respect to existing regulations, that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to inject produced water into disposal wells, and may increase our costs of compliance and doing business.

Information with respect to other risk factors that we may encounter is included under Item 1A. of our Annual Report on Form 10-K for the year ended December 31, 2014. Other than the above, there have been no material changes to the risk factors since the filing of such Form 10-K.

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ITEM 5. OTHER INFORMATION

On May 5, 2015, Kyle Vann’s resignation of his seat on the Company’s Board of Directors became effective. Mr. Vann served as a director since November 2012. He was one of the two board designees of the holders of our class E common stock. Mr. Vann’s resignation was not due to any disagreement with the Company on any matter relating to the Company’s operations, policies or practices.

On May 6, 2015, Will Jaudes was appointed to the Board as a designee of the holders of our class E common stock. Mr. Jaudes is a Principal in the Houston office of CCMP Capital Advisors, LLC. He focuses on making investments in the energy and industrial sectors. Prior to joining CCMP in 2013, Mr. Jaudes was a Principal at HM Capital Partners, where he concentrated on investing in upstream and midstream energy companies. Prior to joining HM Capital Partners, Mr. Jaudes was an Analyst in the Global Mergers & Acquisitions Group of Lehman Brothers. Mr. Jaudes holds a B.S. in Finance from Wake Forest University.

ITEM 6. EXHIBITS

Exhibit No.	Description
10.1	Fifteenth Amendment to Eighth Restated Credit Agreement dated as of April 1, 2015
31.1	Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2	Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1	Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURES

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

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

Date: May 12, 2015

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EXHIBIT INDEX

Exhibit No.	Description
10.1	Fifteenth Amendment to Eighth Restated Credit Agreement dated as of April 1, 2015
31.1	Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2	Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1	Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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EX-10.1

FIFTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

3363815v.9 CHA715/23015

This Fifteenth Amendment to Eighth Restated Credit Agreement (this “Fifteenth Amendment”) is effective as of April 1, 2015 (the “Fifteenth Amendment Effective Date”), by and among CHAPARRAL ENERGY, INC., a Delaware corporation (“Parent”),Borrowers, JPMORGAN CHASE BANK, N.A., a national banking association, as Administrative Agent (“Administrative Agent”), and each of the Lenders party hereto.

W I T N E S S E T H:

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

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

WHEREAS, the parties hereto desire to enter into this Fifteenth Amendment to (i) amend certain terms of the Credit Agreement as more specifically set forth herein and (ii) decrease the Borrowing Base from $650,000,000 to $550,000,000, in each case, to be effective on the Fifteenth Amendment Effective Date.

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

Section 1.Amendments. In reliance on the representations, warranties, covenants and agreements contained in this Fifteenth Amendment, and subject to the satisfaction of the conditions precedent set forth in Section 3 hereof, the Credit Agreement is hereby amended effective as of the Fifteenth Amendment Effective Date in the manner provided in this Section 1.

1.1Amended and Restated Definitions. The definitions of “Additional Permitted Debt”, “Consolidated Current Liabilities”, “Consolidated EBITDAX”, “Consolidated Net Interest Expense”, “Loan Documents” and “Reserve Report” contained in Section 1.02 of the Credit Agreement shall be amended to read in full as follows:

“Additional Permitted Debt” means secured or unsecured senior and unsecured subordinated Debt of Parent and/or any other Credit Party issued or incurred after the Tenth Amendment Effective Date so long as, in each case, (a) such Debt does not mature or require any scheduled principal payments of the principal amount thereof prior to the 181st day after the Maturity Date (other than (i) customary offers to purchase upon a change of control, asset sale or casualty or condemnation

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event prepayments and customary acceleration rights after an event of default and (ii) Debt incurred pursuant to a customary bridge facility so long as such Debt does not provide for any scheduled repayment, mandatory redemption or sinking fund obligation (except to the extent permitted pursuant to clause (i)) and such Debt converts at maturity to Debt which does not provide for any scheduled repayment, mandatory redemption or sinking fund obligation (except to the extent permitted pursuant to clause (i)) prior to the 181st day after the Maturity Date as in effect on the date of determination), (b) no indenture or other agreement governing such Debt contains (i) financial covenants that are more restrictive on Parent and its Restricted Subsidiaries than the financial covenants set forth in this Agreement; provided that any financial covenant(s) not contained in this Agreement prior to the incurrence of such Additional Permitted Debt will be incorporated into this Agreement and any financial covenant set forth in this Agreement that would otherwise be less restrictive will be amended to be at least as restrictive as the corresponding version contained in such Additional Permitted Debt, thereby satisfying the requirement under this clause (b)(i) for such Additional Permitted Debt (and, in each case, the Lenders hereby authorize, consent and instruct the Administrative Agent to enter into any amendment or other modification of this Agreement in order to add such additional financial covenant(s) or to make existing financial covenants in this Agreement more restrictive on Parent and its Restricted Subsidiaries, in each case to as set forth in any such indenture or other agreement governing such Debt) or (ii) covenants (other than financial covenants) or events of default that are, taken as a whole, more restrictive in any material respect on Parent or any of its Restricted Subsidiaries than those contained in this Agreement are on Parent and its Restricted Subsidiaries, (c) after giving effect to the issuance or incurrence of such Debt on a pro forma basis, the Parent shall be in compliance with all covenants set forth in Section 9.01 as of the last day of the applicable period covered by the certificate most recently delivered pursuant to Section 8.01(c) (for purposes of Section 9.01, as if such Debt, and all other Additional Permitted Debt issued or incurred since the first day of such applicable period, had been issued or incurred on the first day of such applicable period) and (d) in the case of any secured Debt, such Debt is secured on a junior priority basis and the administrative agent, trustee or collateral agent under the indenture or agreement governing such Debt, on behalf of itself and the holders or lenders of such Debt, enters into a customary intercreditor agreement with terms and provisions reasonably acceptable to the Administrative Agent as determined in its sole discretion.

“Consolidated Current Liabilities” means with respect to Parent and the Consolidated Restricted Subsidiaries, as of any date of determination, the sum of the current obligations of Parent and the Consolidated Restricted Subsidiaries at such time determined in accordance with GAAP, excluding therefrom (i) current maturities due on the Loan, and (ii) non-cash current obligations and liabilities under ASC Topic 815 and ASC Topic 410, including, in any event, any non-cash deferred premiums payable on or with respect to any derivative instruments.

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“Consolidated EBITDAX” means with respect to Parent and the Consolidated Restricted Subsidiaries for any applicable period: (a) Consolidated Net Income of Parent and the Consolidated Restricted Subsidiaries for such period, plus, to the extent deducted in the calculation of Consolidated Net Income, (b) the sum of (i) income or material franchise Taxes paid or accrued; (ii) Consolidated Net Interest Expense; (iii) amortization, depletion and depreciation expense; (iv) any non-cash losses or charges on any Swap Agreement, including those resulting from the requirements of ASC Topic 815, for that period; (v) other non-cash charges (excluding accruals for cash expenses made in the ordinary course of business), including, without limitation, non-cash employee compensation; (vi) costs and expenses associated with, and attributable to, oil and gas capital expenditures that are expensed rather than capitalized; (vii) charges, reserves and expenses attributable to and incurred on or after January 1, 2015 in connection with cost savings initiatives, transition, business optimization and other restructuring charges (including costs related to the costs relating to curtailments, strategic initiatives and contracts, consulting fees, legal expenses, severance payments, employee paid time off, healthcare gross up payments, modifications to pension and post-retirement employee benefit plans), in each case other than operating improvements resulting from operating expense reductions; provided that the maximum aggregate amount of such charges, reserves and expenses added back pursuant to this clause (vii) during the term of this Agreement shall not exceed $25,000,000 for all periods; (viii) reasonable and customary fees and expenses relating to the refinancing of the Permitted 2005 Bond Debt; and (ix) reasonable and customary fees and expenses relating to the refinancing of the Permitted 2007 Bond Debt; less, to the extent included in the calculation of Consolidated Net Income, (c) the sum of (i) the income of any Person (other than Wholly-Owned Subsidiaries of such Person) unless such income is received by such Person in a cash distribution; (ii) gains or losses from sales or other dispositions of assets (other than Hydrocarbons produced in the normal course of business); (iii) any non-cash gains on any Swap Agreement, including those resulting from the requirements of ASC Topic 815, for that period; (iv) any cash proceeds received from the termination or other monetization of any Swap Agreement (including, as applicable, any trade confirmations made pursuant thereto, but excluding, for the avoidance of doubt, any cash proceeds received upon the scheduled settlement of any Swap Agreement) unless such termination or other monetization was permitted under Section 9.12 hereof; and (v) extraordinary or non-recurring gains, but not net of extraordinary or non-recurring “cash” losses. Notwithstanding anything to the contrary contained herein, all calculations of Consolidated EBITDAX shall be (A) in all respects, acceptable to, and approved by, the Administrative Agent, (B) for any applicable period of determination during which a Credit Party has consummated an acquisition or disposition (to the extent permitted hereunder) of Properties, calculated and determined on a pro forma basis as if such acquisition or disposition was consummated on the first day of such applicable period, and (C) calculated, determined and adjusted for any applicable period to exclude any income, loss or other adjustments with respect to Unrestricted

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Subsidiaries determined in accordance with GAAP, except income received pursuant to a cash distribution shall be included in the calculation of Consolidated EBITDAX.

“Consolidated Net Interest Expense” means, with respect to Parent and the Consolidated Restricted Subsidiaries for any period, the remainder of the following for such period:

(a)    consolidated interest expense (including (i) amortization of original issue discount resulting from the issuance of Indebtedness at less than par, (ii) all commissions, discounts and other fees and charges owed with respect to letters of credit or bankers acceptances, (iii) non-cash interest payments (but excluding any non-cash interest expense attributable to the movement in the mark to market valuation of obligations under Swap Agreements or other derivative instruments pursuant to GAAP), (iv) the interest component of the liability in respect of any Capitalized Leases and (v) net payments, if any, made (less net payments, if any, received), pursuant to interest rate Swap Agreements with respect to Indebtedness, and excluding (vi) any prepayment premium or penalty, (vii) annual agency fees paid to the administrative agents and collateral agents under any credit facilities or other debt instruments or documents, (viii) costs associated with Swap Agreements and breakage costs in respect of Swap Agreements related to interest rates, (ix) any expense resulting from the discounting of any Indebtedness in connection with the application of recapitalization accounting or, if applicable, recapitalization or purchase accounting in connection with any acquisition (or purchase of assets), (x) penalties and interest relating to taxes and any other fees related to any acquisitions (or purchases of assets) after the Fifteenth Amendment Effective Date, (xi) any “additional interest” with respect to any securities, (xii) amortization or expensing of deferred financing fees, amendment and consent fees, debt issuance costs, commissions, fees and expenses, (xiii) any amortization or expensing of bridge, commitment and other financing fees and any other fees related to any acquisitions (or purchases of assets) after the Fifteenth Amendment Effective Date and (ix) any accretion of accrued interest on discounted liabilities (other than Debt except to the extent arising from the application of purchase or recapitalization accounting); plus

(b)    consolidated capitalized interest for such period, whether paid or accrued; minus

(c)    interest income.

For purposes of this definition, interest with respect to any Capitalized Leases shall be deemed to accrue at an interest rate reasonably determined by such Person to be the rate of interest implicit in such Capitalized Lease in accordance with GAAP.

“Loan Documents” means this Agreement, the First Amendment, the Second Amendment, the Third Amendment, the Fourth Amendment, the Fifth Amendment, the Sixth Amendment, the Seventh Amendment, the Eighth Amendment, the Ninth Amendment, the Tenth Amendment, the Eleventh Amendment, the Twelfth

4

Amendment, the Thirteenth Amendment, the Fourteenth Amendment, the Fifteenth Amendment, the Notes, the Letter of Credit Agreements, the Letters of Credit, the Certificate of Effectiveness, and the Security Instruments.

“Reserve Report” means a report, in form and substance reasonably satisfactory to the Administrative Agent, setting forth, as of each December 31st and June 30th (and such other date in the event of an Interim Redetermination or Optional Swap Unwind Redetermination) the oil and gas reserves attributable to the proved Oil and Gas Properties of the Credit Parties that the Borrowers desire to have included in the determination of the Borrowing Base (or as for Interim Redeterminations or Optional Swap Unwind Redeterminations, the proved Oil and Gas Properties of the Credit Parties acquired since the last redetermination of the Borrowing Base that the Borrowers desire to have included in the determination of the Borrowing Base), together with a projection of the rate of production and future net income, taxes, operating expenses and capital expenditures with respect thereto as of such date. Until superseded, the Initial Reserve Report shall be considered the Reserve Report.

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

“Borrowing Base Properties” shall mean the Oil and Gas Properties included in the Reserve Report delivered pursuant to Section 8.12 pursuant to which the then existing Borrowing Base was established.

“Consolidated Net Cash Interest Expense” means, with respect to Parent and the Consolidated Restricted Subsidiaries for any period, the remainder of the following for such period:

(a)    consolidated cash interest expense; plus

(b)    consolidated capitalized interest for such period, whether paid or accrued; minus

(c)    interest income.

“Consolidated Net Secured Debt” means, at any date, all Debt of Parent and the Consolidated Restricted Subsidiaries determined on a consolidated basis that is secured by a Lien on any Property of Parent or any Consolidated Restricted Subsidiary minus the amount, if any, by which (i) the amount of Excess Cash at the time of calculation exceeds (ii) an amount equal to seven percent (7%) of the Borrowing Base then in effect.

“Fifteenth Amendment” means that certain Fifteenth Amendment to Eighth Restated Credit Agreement dated effective as of April 1, 2015, among Parent, the Borrowers, Administrative Agent and the Lenders party thereto.

5

“Fifteenth Amendment Effective Date” means April 1, 2015.

1.3Amendment to Article I of the Credit Agreement. A new Section 1.06 is hereby added to the Credit Agreement immediately following Section 1.05 thereof, which Section 1.06 shall read in full as follows:

Section 1.06    Pro Forma and Other Calculations. Notwithstanding anything to the contrary herein, for purposes of determining compliance with any test or covenant contained in this Agreement, “pro forma” or “pro forma basis” means, as to any calculation of the ratio of Consolidated Net Secured Debt to Consolidated EBITDAX, the ratio of Consolidated Net Debt to Consolidated EBITDAX, the ratio of Consolidated EBITDAX to Consolidated Net Cash Interest Expense or the Current Ratio (including component definitions thereof), for any events as described below that occur subsequent to the commencement of any period of four consecutive fiscal quarters (the “Reference Period”) for which the financial effect of such events is being calculated, and giving effect to the events for which such calculation is being made, such calculation as will give pro forma effect to such events as if such events occurred as of the first day of the Reference Period (or, in the case of Current Ratio, as of the last day of such Reference Period) and that: (i) in making any determination on a pro forma basis, (x) all Debt (including Debt issued, incurred or assumed as a result of, or to finance, any relevant transactions and for which the financial effect is being calculated, whether incurred under this Agreement or otherwise, but excluding normal fluctuations in revolving Debt incurred for working capital purposes) issued, incurred, assumed or permanently repaid during the Reference Period (or, unless otherwise specified, occurring during the Reference Period or thereafter and through and including the date of determination, if applicable) shall be deemed to have been issued, incurred, assumed or permanently repaid at the beginning of such period, (y) interest charges attributable to interest on any Debt, for which pro forma effect is being given as provided in preceding clause (x), bearing floating interest rates shall be computed on a pro forma basis as if the rate that is or would be in effect with respect to such Indebtedness as at the relevant date of determination would have been in effect during the period for which pro forma effect is being given and (z) the acquisition or disposition of any assets included in calculating Current Ratio shall be deemed to have occurred as of the last day of the applicable Reference Period, and (ii) any designation of an Unrestricted Subsidiary as a Restricted Subsidiary, effect shall be given to such designation and all other designations of Unrestricted Subsidiaries as Restricted Subsidiaries after the first day of the relevant Reference Period and on or prior to the date of the then applicable designation of an Unrestricted Subsidiary as a Restricted Subsidiary, collectively. Notwithstanding anything to the contrary contained herein, all pro forma calculations shall be in all respects, acceptable to, and approved by, the Administrative Agent.

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1.4Amendment to Section 3.04(c) of the Credit Agreement. Section 3.04(c) of the Credit Agreement is hereby amended to add a new clause (vi) thereto immediately following clause (v) thereof, which clause (vi) shall read in full as follows:

(vi)    Promptly (and in any event within one Business Day) following any sale, lease, conveyance, disposition or other transfer by any Credit Party of any of its Property, or any termination or other monetization by any Credit Party of any Swap Agreement in respect of commodities, other than as permitted by Section 9.12, the Borrowers shall prepay the Loans in an aggregate amount equal to one hundred percent (100%) of the net proceeds of such sale, termination or other monetization. Nothing in this paragraph is intended to permit any Credit Party to sell Property other than pursuant to Section 9.12, and any such non-permitted sale will constitute a breach of this Agreement.

1.5Amendment to Section 7.16(a) of the Credit Agreement. Section 7.16(a) of the Credit Agreement is hereby amended and restated in its entirety to read in full as follows:

(a)    Except as disclosed in Schedule 7.16, each Credit Party has good and defensible title in all material respects to the Borrowing Base Properties (excluding, to the extent this representation and warranty is deemed to be made after the Effective Date, any Oil and Gas Properties sold or transferred in compliance with Section 9.12) and good title in all material respects to all its personal Properties, in each case, free and clear of all Liens except Liens permitted by Section 9.03. After giving full effect to the Excepted Liens, a Credit Party specified as the owner owns the net interests in production attributable to the Hydrocarbon Interests as reflected in the Reserve Report pursuant to which the then existing Borrowing Base was established, and the ownership of such Properties shall not in any material respect obligate such Credit Party to bear the costs and expenses relating to the maintenance, development and operations of each such Property in an amount in excess of the working interest of each Property set forth in the Reserve Report pursuant to which the then existing Borrowing Base was established that is not offset by a corresponding proportionate increase in such Credit Party’s net revenue interest in such Property.

1.6Amendments to Section 8.01 of the Credit Agreement.

(a)Section 8.01(d) of the Credit Agreement is hereby amended and restated in its entirety to read in full as follows:

(d)    Certificate of Financial Officer — Swap Agreements. Concurrently with the delivery of each Reserve Report hereunder and the delivery of the financial statements under Section 8.01(b) for the fiscal quarter ending June 30, 2014, a certificate of a Financial Officer of Borrower Representative, in form and substance reasonably satisfactory to the Administrative Agent, setting forth as of a recent date, a true and complete list of all Swap Agreements of each Credit Party, the material terms thereof (including the type, term, effective date, termination date and notional

7

amounts or volumes), the net mark-to-market value therefor, any new credit support agreements relating thereto not listed on Schedule 7.20, any margin required or supplied under any credit support document, the counterparty to each such agreement, and a reasonably detailed schedule (including such supporting information as the Administrative Agent may reasonably request) of the reasonably anticipated production from the proved Oil and Gas Properties of the Credit Parties not included in such Reserve Report.

(b)Section 8.01(h) of the Credit Agreement is hereby amended by deleting the reference to “Section 9.12(h)” contained therein and inserting in lieu thereof a reference to “Section 9.12(h), Section 9.12(i) or Section 9.12(j)”.

1.7Amendment to Section 8.12 of the Credit Agreement. Clauses (a) and (b) of Section 8.12 of the Credit Agreement are hereby amended and restated in their entirety to read in full as follows:

(a)On or before April 1st and October 1st of each year, commencing October 1, 2010, the Borrowers shall furnish to the Administrative Agent and the Lenders a Reserve Report. The Reserve Report as of December 31st (to be furnished by April 1^st of the following year) of each year shall be prepared by (%4) one or more Approved Petroleum Engineers with respect to not less than eighty percent (80%) of the Recognized Value of the Borrowers’ proved Oil and Gas Properties that the Borrowers desire to be included in the determination of the Borrowing Base, and (%4) the chief engineer of the Borrowers with respect to the remaining twenty percent (20%) (or such lesser percentage as may not be covered pursuant to clause (i) above) of the Recognized Value of the Borrowers’ proved Oil and Gas Properties that the Borrowers desire to be included in the determination of the Borrowing Base, and the June 30^th Reserve Report (to be furnished by October 1st) of each year shall be prepared by or under the supervision of the chief engineer of the Borrowers. In each case, the chief engineer of the Borrowers shall certify that such Reserve Report is based on information that was prepared in good faith based upon assumptions believed to be reasonable at the time and to have been prepared in accordance with the procedures used in the immediately preceding Reserve Report.

(b)In the event of an Interim Redetermination or an Optional Swap Unwind Redetermination, the Borrowers shall furnish to the Administrative Agent and the Lenders a Reserve Report prepared by or under the supervision of the chief engineer of the Borrowers who shall certify such Reserve Report to be based on information that was prepared in good faith based upon assumptions believed to be reasonable at the time and to have been prepared in accordance with the procedures used in the immediately preceding Reserve Report except that the Properties covered by such report may, in the discretion of the Borrowers, be limited to the proved Oil and Gas Properties acquired since the last redetermination of the Borrowing Base that the Borrowers desire to have included in the determination of the Borrowing Base (provided, that, in connection with any Interim Redetermination requested by

8

the Administrative Agent pursuant to Section 2.07(b)(ii) (or any Optional Swap Unwind Redetermination requested by the Administrative Agent pursuant to Section 2.07(b)(iv), the Reserve Report shall cover such additional Oil and Gas Properties of the Borrowers as the Required Lenders may reasonably request so long as the Borrowers desire for such Oil and Gas Properties to be included in the determination of the Borrowing Base). For any Interim Redetermination requested by the Administrative Agent or the Borrowers pursuant to Section 2.07(b)(ii) or Section 2.07(b)(iii) or for any Optional Swap Unwind Redetermination requested by the Administrative Agent pursuant to Section 2.07(b)(iv), the Borrowers shall provide such Reserve Report with an “as of” date as required by the Administrative Agent as soon as possible, but in any event no later than forty-five (45) days following the receipt of such request. Each Reserve Report prepared by the chief engineer of the Borrowers and delivered to the Administrative Agent hereunder shall be accompanied by a reconciliation to the most recently delivered Reserve Report prepared by one or more Approved Petroleum Engineers.

1.8Amendment to Section 8.13 of the Credit Agreement. The second sentence of Section 8.13(c) of the Credit Agreement is hereby amended and restated in its entirety to read in full as follows:

To the extent that the Administrative Agent or the Required Lenders are not satisfied with title to any Collateral after the 90-day period has elapsed, such unacceptable Collateral shall not count towards the 80% requirement, and the Administrative Agent may send a notice to the Borrowers (or Borrower Representative) and the Lenders that the then outstanding Borrowing Base shall be reduced by an amount as determined by the Required Lenders to cause the Borrowers to be in compliance with the requirement to provide acceptable title information on 80% of the total Recognized Value of the proved Oil and Gas Properties evaluated in the most recent Reserve Report.

1.9Amendment to Section 8.14(e) of the Credit Agreement. Section 8.14(e) of the Credit Agreement is hereby amended and restated in its entirety to read in full as follows:

(e)    If Parent or the Borrowers desire to designate any Wholly-Owned Subsidiary which is then an Unrestricted Subsidiary to be a Restricted Subsidiary after the date hereof, Parent and the Borrowers shall cause such Person to comply with Section 8.14(c), at which time such Subsidiary shall cease to be an “Unrestricted Subsidiary” and shall become a “Restricted Subsidiary” for purposes of this Agreement and the other Loan Documents without any amendment, modification or other supplement to any of the foregoing.

1.10Amendments to Section 9.01 of the Credit Agreement.

(a)Section 9.01(b) of the Credit Agreement is hereby amended and restated in its entirety to read in full as follows:

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(b)    Consolidated Net Secured Debt to Consolidated EBITDAX. Commencing with the fiscal quarter ending June 30, 2015, Parent will not permit, as of the last day of any fiscal quarter, the ratio of Consolidated Net Secured Debt (on such date) to Consolidated EBITDAX (for each Rolling Period ending on such date) to be greater than 2.25 to 1.0.

(b)Section 9.01(c) of the Credit Agreement is hereby amended and restated in its entirety to read in full as follows:

(c)    Consolidated Net Debt to Consolidated EBITDAX. Commencing with the fiscal quarter ending June 30, 2010 and ending with the fiscal quarter ending March 31, 2015, Parent will not permit, as of the last day of any fiscal quarter, the ratio of Consolidated Net Debt (on such date) to Consolidated EBITDAX (for each Rolling Period ending on such date) to be greater than 4.50 to 1.0.

(c)A new Section 9.01(d) is hereby added to the Credit Agreement immediately following Section 9.01(c) thereof, which Section 9.01(d) shall read in full as follows:

(d)     Interest Coverage Ratio. Commencing with the fiscal quarter ending June 30, 2015, Parent will not permit, as of the last day of any fiscal quarter, the ratio of Consolidated EBITDAX (for each Rolling Period ending on such date) to Consolidated Net Cash Interest Expense (for each Rolling Period ending on such date) to be less than 2.0 to 1.00.

1.11Amendments to Section 9.02 of the Credit Agreement.

(a)Section 9.02(c) of the Credit Agreement is hereby amended and restated in its entirety to read in full as follows:

(c)     accounts payable and accrued expenses, liabilities or other obligations to pay the deferred purchase price of Property or services, from time to time incurred in the ordinary course of business, of which no more than $30,000,000 (in the aggregate) are delinquent or outstanding more than 90 days after the date of receipt or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP.

(b)Section 9.02(h) of the Credit Agreement is hereby amended and restated in its entirety to read in full as follows:

(h)    Additional Permitted Debt and guarantee obligations of any Credit Party in respect thereof; provided, that (i) the aggregate

10

principal amount of Additional Permitted Debt incurred on or after the Fifteenth Amendment Effective Date shall not exceed $300,000,000 and (ii) upon the issuance or incurrence of any Additional Permitted Debt, after giving effect to any Automatic Debt Issuance Redetermination required under Section 2.07(d) and any mandatory prepayment required under Section 3.04(c)(iii), the total Credit Exposures of all of the Lenders does not exceed the Borrowing Base.

1.12Amendment to Section 9.03 of the Credit Agreement. Section 9.03 of the Credit Agreement is hereby amended to add a new clause (e) thereto immediately following clause (d) thereof, which clause (e) shall read in full as follows:

(e)    Junior Liens on Property securing the Debt described in Section 9.02(h), but only to the extent that the Administrative Agent holds first priority Liens on such Property to secure the Indebtedness and such Liens are subject to a customary intercreditor agreement with terms and provisions acceptable to the Administrative Agent as determined in its sole discretion.

1.13Amendments to Section 9.12 of the Credit Agreement.

(a)Section 9.12(c) of the Credit Agreement is hereby amended and restated in its entirety to read in full as follows:

(c)    farmouts, sales or other dispositions of undeveloped acreage or other undeveloped Oil and Gas Properties not constituting Borrowing Base Properties and assignments in connection with such transactions;

(b)Section 9.12(h) of the Credit Agreement is hereby deleted and the following clauses (h), (i) and (j) are hereby inserted in lieu thereof:

(h)     provided no Default or Event of Default exists or would exist after giving effect to such sale or other disposition, and provided further that the total Credit Exposures of all of the Lenders does not exceed the Borrowing Base at the time of such sale or disposition of any such Oil and Gas Property, the sale or other disposition of any developed Oil and Gas Properties not constituting Borrowing Base Properties;

(i)    the unwinding or termination of any Swap Agreement:

(i)    with a scheduled expiration or termination date prior to November 1, 2015; provided that (A) no Default or Event of Default exists or would exist after giving effect to such unwinding

11

or termination, (B) the total Credit Exposures of all of the Lenders does not exceed the Borrowing Base at the time of such unwinding or termination, (C) the net cash proceeds received pursuant to any such unwind or termination shall be applied to the repayment of Loans, and (D) contemporaneously with the unwinding or termination of any such Swap Agreements with maturity dates more than 30 days after the date such Swap Agreements are unwound or terminated, the Borrowers shall enter into corresponding Swap Agreements, on equivalent notional volumes and tenors for each of oil, gas and natural gas liquids Swap Agreements unwound or terminated, as applicable, and with a call, put or other settlement price that is not more than $5.00 less than the then applicable market price for such commodity at the times such hedge is entered into; and

(ii)    as may be necessary to comply with Section 9.18, so long as no Swap Agreements are unwound or terminated pursuant to this clause (ii) other than Swap Agreements in respect of the minimum volumes necessary to achieve such compliance;

(j)    provided no Default or Event of Default exists or would exist after giving effect to such sale or other disposition, and provided further that the total Credit Exposures of all of the Lenders does not exceed the Borrowing Base at the time of such sale or disposition of any Oil and Gas Property or the termination of any Swap Agreement in respect of commodities (including, as applicable, any trade confirmations made pursuant thereto), the sale or other disposition of any Borrowing Base Property or the termination of any Swap Agreements in respect of commodities (including, as applicable, any trade confirmations made pursuant thereto) that is not otherwise permitted by the foregoing clauses (a) through (i); provided that:

(i)    the aggregate value (which, for purposes hereof, shall mean the value the Administrative Agent attributes to such Borrowing Base Property or Swap Agreement (including, as applicable, any trade confirmations made pursuant thereto) for purposes of the most recent redetermination of the Borrowing Base) of such Properties sold or disposed of pursuant to this clause (i) in any period between Scheduled Redeterminations shall not exceed five percent (5%) of the Borrowing Base then in effect, and

(ii)    upon any termination of any Swap Agreement pursuant to Section 9.12(i)(ii) or this Section 9.12(j) (including, as applicable, any trade confirmations made pursuant thereto), Administrative Agent may, by notifying the Borrowers (or the

12

Borrower Representative thereof), elect to cause the Borrowing Base to be redetermined between Scheduled Redeterminations and any such redetermination shall not be considered an Interim Redetermination.

1.14Amendments to Section 9.18 of the Credit Agreement.

(a)    Section 9.18(a)(i) of the Credit Agreement is hereby amended by deleting the following words from subclauses (B)(1) and (B)(2):

“set forth in the most recent Reserve Report delivered to Administrative Agent hereunder (as such report may be supplemented from time to time by the Credit Parties delivering to Administrative Agent updated well projections and other information reflecting the drilling activity, acquisitions, dispositions and other results of operations since the effective date of such Reserve Report)”.

(b)    Section 9.18(a)(iii) of the Credit Agreement is hereby amended by deleting the following words therefrom:

“as set forth in the most recent Reserve Report delivered to Administrative Agent hereunder (as such report may be supplemented from time to time by the Credit Parties delivering to Administrative Agent updated well projections and other information reflecting the drilling activity, acquisitions, dispositions and other results of operations completed since the effective date of such Reserve Report)”.

(c)    Section 9.18 of the Credit Agreement is hereby amended to add a new clause (d) thereto immediately following clause (c) thereof, which clause (d) shall read in full as follows:

(d)    For purposes of this Section 9.18, the reasonably anticipated production from Proved Reserves or Proved Developed Producing Reserves of Oil and Gas Properties of the Credit Parties (other than Acquisition Properties) shall be (i) with respect to Oil and Gas Properties that the Borrowers desire to be included in the determination of the Borrowing Base, such production as set forth in the most recent Reserve Report delivered to Administrative Agent hereunder (as such report may be supplemented from time to time by the Credit Parties delivering to Administrative Agent updated well projections and other information reflecting the drilling activity, acquisitions, dispositions and other results of operations completed since the effective date of such Reserve Report), and (ii) with respect

13

to Oil and Gas Properties not included in the most recent Reserve Report, such production as set forth in the most recent certificate delivered to the Administrative Agent pursuant to Section 8.01(d).

SECTION 2.Borrowing Base Decrease.    The Borrowing Base shall be decreased, effective as of the Fifteenth Amendment Effective Date, from $650,000,000 to $550,000,000 and shall remain at $550,000,000 until the next Scheduled Redetermination Date, Interim Redetermination Date or other redetermination or adjustment of the Borrowing Base thereafter, whichever occurs first pursuant to the Credit Agreement as amended hereby. The Borrowers, Parent and Lenders agree that the redetermination of the Borrowing Base provided for in this Section 2 shall be considered and deemed to be the Scheduled Redetermination scheduled for on or about May 1, 2015 for the purposes of Section 2.07 of the Credit Agreement.

SECTION 3.Conditions Precedent to this Fifteenth Amendment. The effectiveness of the amendments to the Credit Agreement contained in Section 1 hereof and the decrease in the Borrowing Base provided for in Section 2 hereof is subject to the satisfaction of each of the following conditions precedent:

3.1Counterparts. Administrative Agent shall have received counterparts hereof duly executed by each Borrower and the Required Lenders.

3.2Fees and Expenses. The Administrative Agent shall have received all fees and other amounts due and payable on or prior to the Fifteenth Amendment Effective Date, including the amendment fee referred to in Section 3.3 below.

3.3Amendment Fee. The Administrative Agent shall have received an amendment fee for the benefit of the Lenders executing this Fifteenth Amendment on or prior to the Fifteenth Amendment Effective Date in an amount for each such Lender equal to 20 basis points (0.20%) of the amount of such Lender's Applicable Percentage of the Borrowing Base as of the Fifteenth Amendment Effective Date (after giving effect to Section 2 hereof).

3.4Other Documents. Administrative Agent shall have been provided with such other documents, instruments and agreements, and Parent and Borrowers shall have taken such actions, as Administrative Agent or counsel to Administrative Agent may reasonably require in connection with this Fifteenth Amendment and the transactions contemplated hereby.

SECTION 4.Representations and Warranties of Borrowers. To induce the Lenders and Administrative Agent to enter into this Fifteenth Amendment, Parent and Borrowers hereby jointly and severally represent and warrant to the Lenders and Administrative Agent as follows:

4.1Reaffirm Existing Representations and Warranties. Each representation and warranty of each Credit Party contained in the Credit Agreement and the other Loan Documents is true and correct on the date hereof and will be true and correct after giving effect to the amendments set forth in Section 1 hereof, except to the extent such representations and warranties are expressly limited to an earlier date, in which case such representations and warranties shall be true and correct as of such specified earlier date.

14

4.2Due Authorization; No Conflict. The execution, delivery and performance by Parent and Borrowers of this Fifteenth Amendment are within Parent’s and Borrowers’ corporate and limited liability company powers (as applicable), have been duly authorized by all necessary action, require no action by or in respect of, or filing with, any governmental body, agency or official and do not violate or constitute a default under any provision of applicable law or any material agreement binding upon Parent, any Borrower or any other Credit Party or result in the creation or imposition of any Lien upon any of the assets of Parent, any Borrower or any other Credit Party except Excepted Liens.

4.3Validity and Enforceability. This Fifteenth Amendment constitutes the valid and binding obligation of Parent and Borrowers enforceable in accordance with its terms, except as (%3) the enforceability thereof may be limited by bankruptcy, insolvency or similar laws affecting creditor’s rights generally, and (%3) the availability of equitable remedies may be limited by equitable principles of general application.

4.4No Default, Event of Default or Borrowing Base Deficiency. No Default or Event of Default has occurred which is continuing and the total Credit Exposures of all Lenders do not exceed the Borrowing Base.

SECTION 5.Miscellaneous.

5.1Reaffirmation of Loan Documents; Extension of Liens. Any and all of the terms and provisions of the Credit Agreement and the Loan Documents shall, except as amended and modified hereby, remain in full force and effect. The amendments contemplated hereby shall not limit or impair any Liens securing the Indebtedness, each of which are hereby ratified, affirmed and extended to secure the Indebtedness after giving effect to this Fifteenth Amendment.

5.2Parties in Interest. All of the terms and provisions of this Fifteenth Amendment shall bind and inure to the benefit of the parties hereto and their respective successors and assigns.

5.3Legal Expenses. Parent and Borrowers hereby jointly and severally agree to pay on demand all reasonable fees and expenses of counsel to Administrative Agent incurred by Administrative Agent in connection with the preparation, negotiation and execution of this Fifteenth Amendment and all related documents.

5.4Counterparts. This Fifteenth Amendment may be executed in counterparts, and all parties need not execute the same counterpart; however, no party shall be bound by this Fifteenth Amendment until Parent, Borrowers and the Required Lenders have executed a counterpart. Facsimiles or other electronic transmission (e.g. .pdf) shall be effective as originals.

5.5Complete Agreement. THIS FIFTEENTH AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN OR AMONG THE PARTIES.

15

5.6Headings. The headings, captions and arrangements used in this Fifteenth Amendment are, unless specified otherwise, for convenience only and shall not be deemed to limit, amplify or modify the terms of this Fifteenth Amendment, nor affect the meaning thereof.

5.7Effectiveness. This Fifteenth Amendment shall be effective automatically and without necessity of any further action by Parent, Borrowers, Administrative Agent or Lenders when counterparts hereof have been executed by Parent, Borrowers, Administrative Agent and the Required Lenders, and all conditions to the effectiveness hereof set forth herein have been satisfied.

5.8Governing Law. This Fifteenth Amendment shall be governed by, and construed in accordance with, the laws of the State of New York.

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

[Signature pages to follow]

PARENT: CHAPARRAL ENERGY, INC.,
a Delaware corporation

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

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

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

GREEN COUNTRY SUPPLY, INC.

16

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

SIGNATURE PAGE

FIFTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

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

By: /s/ Anson Williams    Anson WIlliams,Authorized Officer

SIGNATURE PAGE

FIFTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: CAPITAL ONE, NATIONAL ASSOCIATION,
as a Lender

By:     /s/ Michael Higgins    

Name:    Michael Higgings    

Title:    Director    

SIGNATURE PAGE

FIFTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: ROYAL BANK OF CANADA,
as a Lender

By:     /s/ Mark Lumpkin, Jr.     

Name:    Mark Lumpkin, Jr.    

Title:    Authorized Signatory    

SIGNATURE PAGE

FIFTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: UBS AG, STAMFORD BRANCH,
as a Lender

By:    /s/ Darlene Arias    

Name:    Darlene Arias    

Title:    Director    

By:    /s/ Craig Pearson    

Name:    Craig Pearson    

Title:    Associate Director    

SIGNATURE PAGE

FIFTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

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

By:    /s/ Michael Willis    

Name:    Michael Willis    

Title:    Managing Director    

By:    /s/ Sharada Manne    

Name:    Sharada Manne    

Title:    Managing Director    

SIGNATURE PAGE

FIFTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: SOCIÉTÉ GÉNÉRALE,
as a Lender

By:    /s/ David M. Bornstein    

Name:    David M. Bornstein    

Title:    Director    

SIGNATURE PAGE

FIFTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

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

By:    /s/ Catherine Cook    

Name:    Catherine Cook    

Title:    Director    

SIGNATURE PAGE

FIFTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: THE BANK OF NOVA SCOTIA,
as a Lender

By:    /s/ Alan Dawson    

Name:    Alan Dawson    

Title:    Director    

SIGNATURE PAGE

FIFTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: COMERICA BANK,
as a Lender

By:    /s/ Devin S. Eaton    

Name:    Devin S. Eaton    

Title:    Relationship Manager    

SIGNATURE PAGE

FIFTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: NATIXIS, NEW YORK BRANCH,
as a Lender

By:    /s/ Stuart Murray    

Name:    Stuart Murray    

Title:    Managing Director    

By:    /s/ Louis P. Laville    

Name:    Louis P. Laville    

Title:    Managing Director    

SIGNATURE PAGE

FIFTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: AMEGY BANK NATIONAL ASSOCIATION,
as a Lender

By:    /s/ Larry Scars    

Name:    Larry Scars    

Title:    Senior Vice President    

SIGNATURE PAGE

FIFTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: COMPASS BANK,
as a Lender

By:    /s/ Ian Payne    

Name:    Ian Payne    

Title:    Vice President    

SIGNATURE PAGE

FIFTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: CREDIT SUISSE AG, CAYMAN ISLANDS BRANCH,

as a Lender

By:    /s/ Doreen Barr    

Name:    Doreen Barr    

Title:    Authorized Signatory    

By:    /s/ Remy Riester    

Name:    Remy Riester    

Title:    Authorized Signatory    

SIGNATURE PAGE

FIFTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: KEYBANK NATIONAL ASSOCIATION,
as a Lender

By:    /s/ John Dravenstott    

Name:    John Dravenstott    

Title:    Vice President    

SIGNATURE PAGE

FIFTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: MUFG UNION BANK, N.A. (f/k/a UNION BANK, N.A),
as a Lender

By:    /s/ Rachel Bowman    

Name:    Rachel Bowman    

Title:    Vice President    

SIGNATURE PAGE

FIFTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

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

By:    /s/ Nicholas T. Hanford    

Name:    Nicholas T. Hanford    

Title:    Vice President    

SIGNATURE PAGE

FIFTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

LENDER: GOLDMAN SACHS BANK USA,
as a Lender

By:    /s/ Jamie Minieri    

Name:    Jamie Minieri    

Title:    Authorized Signatory    

SIGNATURE PAGE

FIFTEENTH AMENDMENT TO EIGHTH RESTATED CREDIT AGREEMENT

CHAPARRAL ENERGY, INC.

EX-31.1

Exhibit 31.1

CERTIFICATION

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

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

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

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

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

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

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

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

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

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

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

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

Date: May 12, 2015

/s/ Mark A. Fischer

Mark A. Fischer

Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

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

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

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

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

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

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

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

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

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

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

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

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

Date: May 12, 2015

/s/ Joseph O. Evans

Joseph O. Evans

Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF PERIODIC REPORT

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

(1) the Quarterly Report on Form 10-Q of the Company for the period ended March 31, 2015 (the “Report”) fully complies with the requirements of Section 13 (a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and

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

Date: May 12, 2015

/s/ Mark A. Fischer

Mark A. Fischer

Chief Executive Officer

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

EX-32.2

Exhibit 32.2

CERTIFICATION OF PERIODIC REPORT

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

(1) the Quarterly Report on Form 10-Q of the Company for the year ended March 31, 2015 (the “Report”) fully complies with the requirements of Section 13 (a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and

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

Date: May 12, 2015

/s/ Joseph O. Evans

Joseph O. Evans

Chief Financial Officer

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

XML

Fair value measurements (Derivatives Offset in the Consolidated Balance Sheets) (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Derivative assets, gross	$ 237,101	$ 251,863
Derivative assets, amount offset	0	(232)
Derivative assets	237,101	251,631
Derivative assets, not offset		0	[1]
Credit facility balance available to offset net derivative assets	(140,962)	(118,430)
Derivative asset, net	96,139	133,201
Derivative liabilities, gross	0	(309)
Derivative liabilities, amounts offset	0	232
Derivative liabilities	0	77
Derivative liabilities, not offset		0	[1]
Derivative liability, net	0	(77)
Derivative Asset (Liability), Fair Value, Gross Asset	237,101	251,554
Derivative Asset (Liability), Fair Value, Gross Liability	0	0
Derivative Asset (Liability), Net	237,101	251,554
Credit facility balance available to offset net derivative assets	(140,962)	(118,430)
Derivative asset (liability), net	$ 96,139	$ 133,124

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

XML

(Effect of Derivative Instruments on the Consolidated Statements of Operations) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Non-Hedge Derivative Gains (Losses) [Line Items]
Non-hedge derivative losses	$ 61,431	$ (29,199)
Swaps
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	606	(5,193)
(Payments on) receipts from settlement of non-hedge derivative instruments	19,027	(5,850)
Three-way collars
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	525	(2,863)
(Payments on) receipts from settlement of non-hedge derivative instruments	0	(41)
Enhanced Swaps and Put Options
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	(16,643)	(10,527)
(Payments on) receipts from settlement of non-hedge derivative instruments	56,949	(1,992)
Natural gas basis protection swaps
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	1,058	(1,861)
(Payments on) receipts from settlement of non-hedge derivative instruments	$ (91)	$ (872)

XML

Nature of operations and summary of significant accounting policies (Restructuring Charges) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Restructuring Cost and Reserve [Line Items]
Cost reduction initiatives	$ 8,774	$ 0
Severance and Termination Benefits
Restructuring Cost and Reserve [Line Items]
Cost reduction initiatives	$ 6,524

XML

Stock-based compensation (2010 Equity Incentive Plan) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Vest date fair value
Aggregate intrinsic value of unvested Time Vested restricted shares outstanding	$ 9,021
Restricted Stock | 2010 Equity Incentive Plan | Maximum | Service Vesting Conditions
Stock-Based Compensation [Line Items]
Award vesting period	5 years
Restricted Stock | 2010 Equity Incentive Plan | Common Class A
Stock-Based Compensation [Line Items]
Shares reserved for issuance under the 2010 Plan	86,301
Restricted Stock | 2010 Equity Incentive Plan | Common Class A | Service Vesting Conditions
Weighted average grant date fair value ($ per share)
Unvested and outstanding at beginning of period	$ 791.52
Granted	$ 533.80
Vested	$ 794.40
Forfeited	$ 764.16
Unvested and outstanding at end of period	$ 786.30
Shares
Unvested and outstanding at beginning of period (in shares)	25,834
Granted (in shares)	610
Vested (in shares)	(6,354)
Forfeited (in shares)	(3,190)
Unvested and outstanding at end of period (in shares)	16,900
Vest date fair value
Vest date fair value	$ 3,392
Restricted stock used for tax withholding	1,404	1,068
Shares expected to be repurchased during the next twelve months	2,000
Estimated fair value per share at end of period	$ 533.80
Restricted Stock | 2010 Equity Incentive Plan | Common Class A | Performance Vested
Weighted average grant date fair value ($ per share)
Unvested and outstanding at beginning of period	$ 292.92
Granted	$ 306.50
Vested	$ 0.00
Forfeited	$ 310.57
Unvested and outstanding at end of period	$ 288.19
Shares
Unvested and outstanding at beginning of period (in shares)	38,943
Granted (in shares)	599
Vested (in shares)	0
Forfeited (in shares)	(8,719)
Unvested and outstanding at end of period (in shares)	30,823

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Fair value measurements (Fair Value of Other Financial Instruments) (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Fair Value of Other Financial Instruments
Senior secured revolving credit facility	$ 450,000	$ 347,000
9.875% Senior Notes due 2020
Fair Value of Other Financial Instruments
Senior Notes	295,294	295,139
8.25% Senior Notes due 2021
Fair Value of Other Financial Instruments
Senior Notes	400,000	400,000
7.625% Senior Notes due 2022
Fair Value of Other Financial Instruments
Senior Notes	554,666	554,869
Significant other observable inputs (Level 2) | Carrying value
Fair Value of Other Financial Instruments
Senior secured revolving credit facility	450,000	347,000
Other secured long-term debt	14,099	14,957
Long-term debt	1,714,059	1,611,965
Significant other observable inputs (Level 2) | Carrying value | 9.875% Senior Notes due 2020
Fair Value of Other Financial Instruments
Senior Notes	295,294	295,139
Significant other observable inputs (Level 2) | Carrying value | 8.25% Senior Notes due 2021
Fair Value of Other Financial Instruments
Senior Notes	400,000	400,000
Significant other observable inputs (Level 2) | Carrying value | 7.625% Senior Notes due 2022
Fair Value of Other Financial Instruments
Senior Notes	554,666	554,869
Significant other observable inputs (Level 2) | Estimated fair value
Fair Value of Other Financial Instruments
Senior secured revolving credit facility	450,000	347,000
Other secured long-term debt	14,099	14,957
Long-term debt	1,339,079	1,280,823
Significant other observable inputs (Level 2) | Estimated fair value | 9.875% Senior Notes due 2020
Fair Value of Other Financial Instruments
Senior Notes	228,480	269,091
Significant other observable inputs (Level 2) | Estimated fair value | 8.25% Senior Notes due 2021
Fair Value of Other Financial Instruments
Senior Notes	278,000	270,000
Significant other observable inputs (Level 2) | Estimated fair value | 7.625% Senior Notes due 2022
Fair Value of Other Financial Instruments
Senior Notes	$ 368,500	$ 379,775

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Derivative instruments

3 Months Ended

Mar. 31, 2015

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, natural gas. and natural gas liquids. 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. We enter into crude oil derivative contracts to hedge a portion of our natural gas liquids production.

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.

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 pay 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. A put spread may also be constructed by entering into separate sold put and purchased put contracts.

Put options may be purchased from the counterparty by paying a cash premium at the time the put options are purchased or deferring payment until the put options settle. If the market price is below the put strike price at the settlement date, we will receive a payment from the counterparty. Purchased put options are designed to provide a fixed price floor in an environment where prices have declined. In such an environment, put options may also be purchased to offset the downside from sold puts that are originally associated with enhanced swaps or three-way collars. The fair value of our put options include any deferred premiums that are payable under the contract.

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.

The following table summarizes our crude oil derivatives outstanding as of March 31, 2015:

		Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls	Swaps		Sold puts		Purchased puts		Sold calls		Average premium
2015
Swaps	450	$	95.25	$	—	$	—	$	—	$	—
Swaps with deferred premium (1)	4,028	$	92.78	$	—	$	—	$	—	$	13.80
2016
Three-way collars	240	$	—	$	84.00	$	92.00	$	101.01	$	—
Enhanced swaps (2)	3,720	$	92.94	$	80.52	$	—	$	—	$	—
Purchased puts (2)	3,720	$	—	$	—	$	60.00	$	—	$	5.54

___________

(1) As a result of the deferred premiums, the above 4,028,000 barrels of crude oil production in 2015 are hedged at an effective price of $78.98/barrel.

(2) Total premiums of $20,609 for the purchased puts were paid at contract inception in December 2014. Excluding the premiums and utilizing an average NYMEX strip price of $57.74 for 2016 as of March 31, 2015, the average realized price from our 3,720,000 barrels of hedged production that have associated sold puts and purchased puts is $72.42/barrel. This effective price is also the floor on the realized price we would receive in the event of any crude oil price decline below$60.00/barrel. Upon settlement, in the event that prices increase above $60.00/barrel, our effective price would increase by a commensurate amount of the price increase until prices reach the sold put price after which we would receive the swap price.

The following tables summarize our natural gas derivative instruments outstanding as of March 31, 2015:

Period and type of contract	Volume BBtu	Weighted average fixed price per MMBtu
2015
Natural gas swaps	12,240	$	4.15
Natural gas basis protection swaps	10,800	$	0.24
2016
Natural gas swaps	14,000	$	4.19
Natural gas basis protection swaps	8,400	$	0.36
2017
Natural gas swaps	12,700	$	3.64
2018
Natural gas swaps	8,250	$	3.83

On March 26, 2015, we entered into early settlements of certain oil and natural gas derivative contracts originally scheduled to settle between 2015 to 2017 covering 495,000 barrels of oil and 12,280 Bbtu of natural gas, receiving net proceeds of $15,395, in order to maintain compliance with the hedging limits imposed by covenants under our senior secured credit facility. The proceeds are included in non-hedge derivative gains (losses) disclosed below.

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, 2015						As of December 31, 2014
	Assets		Liabilities		Net value		Assets		Liabilities			Net value
Natural gas swaps	$	37,843	$	—	$	37,843	$	32,939	$	—		$	32,939
Oil swaps	19,168		—		19,168		23,465		—			23,465
Oil collars	1,700		—		1,700		1,175		—			1,175
Oil enhanced swaps	91,362		—		91,362		100,724		—			100,724
Oil purchased puts	85,987		—		85,987		93,268		—			93,268
Natural gas basis differential swaps	1,041		—		1,041		292		(309		)	(17		)
Total derivative instruments	237,101		—		237,101		251,863		(309		)	251,554
Less:
Netting adjustments (1)	—		—		—		232		(232		)	—
Current portion asset (liability)	166,873		—		166,873		179,921		(77		)	179,844
	$	70,228	$	—	$	70,228	$	71,710	$	—		$	71,710

___________

(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 at March 31, 2015 and December 31, 2014 were as follows:

	March 31, 2015		December 31, 2014
Derivative settlements receivable included in accounts receivable	$	41,092	$	19,678

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.

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

	Three months ended
	March 31,
	2015			2014
Change in fair value of commodity price swaps	$	606		$	(5,193	)
Change in fair value of collars	525			(2,863		)
Change in fair value of enhanced swaps and put options	(16,643		)	(10,527		)
Change in fair value of natural gas basis differential contracts	1,058			(1,861		)
Receipts from (payments on) settlement of commodity price swaps	19,027			(5,850		)
Payments on settlement of collars	—			(41		)
Receipts from (payments on) settlement of enhanced swaps and put options	56,949			(1,992		)
Payments on settlement of natural gas basis differential contracts	(91		)	(872		)
	$	61,431		$	(29,199	)

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Stock-based compensation (Stock-based compensation cost) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Stock-Based Compensation Expense [Abstract]
Stock-based compensation cost	$ (1,500)	$ 2,531
Less: stock-based compensation cost capitalized	415	(962)
Stock-based compensation expense	(1,085)	1,569
Payments for stock-based compensation	812	874
Stock-based compensation costs included in accrued payroll and benefits payable	4,056		4,830
Unrecognized compensation cost	$ 14,793
Years over which unrecognized compensation cost is expected to be recognized	2 years 3 months 18 days

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Long-term debt (Capital Leases) (Details) (U.S. Bank National Association, Capital Lease Obligations, USD $) In Thousands, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2013
U.S. Bank National Association | Capital Lease Obligations
Capital leases
Proceeds from sale leaseback		$ 24,500
Lease term	84 months
Purchase option period	72 months
Implicit interest rate	3.80%
Minimum lease payments	$ 3,181

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(Senior Secured Revolving Credit Facility) (Details) (Line of Credit, USD $)	3 Months Ended
	Mar. 31, 2015	Apr. 01, 2015
Line of Credit Facility [Line Items]
Maturity date	Nov. 01, 2017
Proceeds from senior secured revolving credit facility	$ 103,000,000
Weighted average interest rate	2.20%
Borrowing base amount	650,000,000
Subsequent Event
Line of Credit Facility [Line Items]
Borrowing base amount		550,000,000
Additional borrowing capacity		$ 300,000,000
Minimum | Subsequent Event
Line of Credit Facility [Line Items]
Interest coverage charge ratio		2.0
Maximum | Subsequent Event
Line of Credit Facility [Line Items]
Ratio of consolidated secured net debt to consolidated EBITDAX covenant		2.25

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Commitments and contingencies (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		1 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Jun. 07, 2011	Dec. 31, 2014
Loss Contingencies [Line Items]
Letters of credit outstanding	$ 874			$ 920
Interest paid	19,073	18,794
Pending Litigation | Minimum
Loss Contingencies [Line Items]
Damages sought			5,000
Letter of Credit
Loss Contingencies [Line Items]
Interest paid	$ 0	$ 0

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Derivative instruments (Outstanding Derivatives) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended			1 Months Ended
	Mar. 31, 2015		Mar. 31, 2014	Dec. 31, 2014	Mar. 26, 2015 bbl
Derivative [Line Items]
Payments for (Proceeds from) Derivative Instrument, Investing Activities	$ (75,885)		$ 8,755
Swaps | Derivative Maturing in 2015 | Oil Derivative
Derivative [Line Items]
Volume MBbls	450,000
Weighted average fixed price per MMBtu	95.25
Swaps | Derivative Maturing in 2015 | Natural Gas Derivative
Derivative [Line Items]
Volume MBbls	12,240,000
Weighted average fixed price per MMBtu	4.15
Swaps | Derivative Maturing in 2016 | Natural Gas Derivative
Derivative [Line Items]
Volume MBbls	14,000,000
Weighted average fixed price per MMBtu	4.19
Swaps | Derivative Maturing in 2017 | Natural Gas Derivative
Derivative [Line Items]
Volume MBbls	12,700,000
Weighted average fixed price per MMBtu	3.64
Swaps | Derivative Maturing in 2018 | Natural Gas Derivative
Derivative [Line Items]
Volume MBbls	8,250,000
Weighted average fixed price per MMBtu	3.83
Swaps with Deferred Premium | Oil Derivative
Derivative [Line Items]
Volume MBbls	4,028,000	[1]
Average fixed price net of premiums	78.98
Swaps with Deferred Premium | Derivative Maturing in 2015 | Oil Derivative
Derivative [Line Items]
Weighted average fixed price per MMBtu	92.78	[1]
Weighted average fixed price per Bbl, purchased puts	0.00
Weighted average fixed price per Bbl, Average premium	13.80	[1]
Swaps with Deferred Premium | Derivative Maturing in 2016 | Oil Derivative
Derivative [Line Items]
Weighted average fixed price per Bbl, Average premium	5.54	[2]
Three-way collars | Derivative Maturing in 2016 | Oil Derivative
Derivative [Line Items]
Volume MBbls	240,000
Weighted average fixed price per MMBtu	0.00
Weighted average fixed price per Bbl, sold puts	84.00
Weighted average fixed price per Bbl, purchased puts	92.00
Weighted average fixed price per Bbl, sold calls	101.01
Enhanced Swaps | Derivative Maturing in 2016 | Oil Derivative
Derivative [Line Items]
Volume MBbls	3,720,000	[2]
Weighted average fixed price per MMBtu	92.94	[2]
Weighted average fixed price per Bbl, sold puts	80.52	[2]
Weighted average fixed price per Bbl, purchased puts	72.42
Floor price	60.00
Purchased Puts | Derivative Maturing in 2016
Derivative [Line Items]
Premium paid for put options on commodity derivative contracts				20,609
Average forward price	57.74
Purchased Puts | Derivative Maturing in 2016 | Oil Derivative
Derivative [Line Items]
Volume MBbls	3,720,000	[2]
Weighted average fixed price per Bbl, purchased puts	60.00	[2]
Natural gas basis protection swaps | Derivative Maturing in 2015 | Natural Gas Derivative
Derivative [Line Items]
Volume MBbls	10,800,000
Weighted average fixed price per MMBtu	0.24
Natural gas basis protection swaps | Derivative Maturing in 2016 | Natural Gas Derivative
Derivative [Line Items]
Volume MBbls	8,400,000
Weighted average fixed price per MMBtu	0.36
Early Settlement
Derivative [Line Items]
Payments for (Proceeds from) Derivative Instrument, Investing Activities	$ 15,395
Early Settlement | Oil Derivative
Derivative [Line Items]
Volume MBbls					495,000
Early Settlement | Natural Gas Derivative
Derivative [Line Items]
Volume MBbls					12,280,000

[1] .

[2] Total premiums of $20,609 for the purchased puts were paid at contract inception in December 2014. Excluding the premiums and utilizing an average NYMEX strip price of $57.74 for 2016 as of March 31, 2015, the average realized price from our 3,720,000 barrels of hedged production that have associated sold puts and purchased puts is $72.42/barrel. This effective price is also the floor on the realized price we would receive in the event of any crude oil price decline below$60.00/barrel. Upon settlement, in the event that prices increase above $60.00/barrel, our effective price would increase by a commensurate amount of the price increase until prices reach the sold put price after which we would receive the swap price.

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Derivative instruments (Effect of Derivative Instruments on the Consolidated Balance Sheets) (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Fair value of derivative instruments
Derivative assets, gross	$ 237,101	$ 251,863
Netting adjustments	0	232
Current derivative assets, net	166,873	179,921
Long-term derivative assets, net	70,228	71,710
Derivative liabilities, gross	0	(309)
Derivative Liability, Netting adjustments	0	(232)
Current derivative liabilities, net	0	(77)
Long-term derivative liabilities, net	0	0
Derivative assets (liabilities), net	237,101	251,554
Current derivative assets (liabilities), net	166,873	179,844
Long-term derivative assets (liabilities), net	70,228	71,710
Natural Gas Derivative | Swaps
Fair value of derivative instruments
Derivative assets, gross	37,843	32,939
Derivative liabilities, gross	0	0
Derivative assets (liabilities), net	37,843	32,939
Natural Gas Derivative | Natural gas basis protection swaps
Fair value of derivative instruments
Derivative assets, gross	1,041	292
Derivative liabilities, gross	0	(309)
Derivative assets (liabilities), net	1,041	(17)
Oil Derivative | Swaps
Fair value of derivative instruments
Derivative assets, gross	19,168	23,465
Derivative liabilities, gross	0	0
Derivative assets (liabilities), net	19,168	23,465
Oil Derivative | Three-way collars
Fair value of derivative instruments
Derivative assets, gross	1,700	1,175
Derivative liabilities, gross	0	0
Derivative assets (liabilities), net	1,700	1,175
Oil Derivative | Enhanced Swaps
Fair value of derivative instruments
Derivative assets, gross	91,362	100,724
Derivative liabilities, gross	0	0
Derivative assets (liabilities), net	91,362	100,724
Oil Derivative | Purchased Puts
Fair value of derivative instruments
Derivative assets, gross	85,987	93,268
Derivative liabilities, gross	0	0
Derivative assets (liabilities), net	$ 85,987	$ 93,268

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Long-term debt

3 Months Ended

Mar. 31, 2015

Debt Disclosure [Abstract]

Long-term debt

Long-term debt

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

	March 31, 2015		December 31, 2014
9.875% Senior Notes due 2020, net of discount of $4,706 and $4,861, respectively	$	295,294	$	295,139
8.25% Senior Notes due 2021	400,000		400,000
7.625% Senior Notes due 2022, including premium of $4,666 and $4,869, respectively	554,666		554,869
Senior secured revolving credit facility	450,000		347,000
Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 2.54% to 5.46%, due August 2021 through December 2028; collateralized by real property	10,577		10,705
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.85% to 5.95% , due April 2015 through February 2018; collateralized by automobiles, machinery and equipment	3,522		4,252
Capital lease obligations	21,245		21,837
	1,735,304		1,633,802
Less current maturities	5,138		5,377
	$	1,730,166	$	1,628,425

Senior Notes

The senior notes, which, as of March 31, 2015, 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 ended March 31, 2015, we borrowed $103,000 on our senior secured revolving credit facility. As of March 31, 2015, the weighted average interest rate was 2.2% on outstanding borrowings under the senior secured revolving credit facility.

Availability under our senior secured revolving credit facility is subject to a borrowing base which is set by the banks semiannually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination and in the event of early termination of our derivative contracts. Our first semiannual borrowing base redetermination for the current year was finalized ahead of schedule in conjunction with an amendment to our senior secured revolving credit facility (the “Fifteenth Amendment”), effective on April 1, 2015. As of result of our semiannual redetermination, our borrowing base was decreased from $650,000 to $550,000 effective on April 1, 2015.

In connection with the Fifteenth Amendment, the Consolidated Net Debt to Consolidated EBITDAX covenant required by our senior secured revolving credit facility will be replaced by a covenant based on the ratio of Consolidated Net Secured Debt to Consolidated EBITDAX, as defined in the amendment. Under this covenant, we are required to maintain a ratio of Consolidated Net Secured Debt to Consolidated EBITDAX no greater than 2.25 to 1.0 for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter. For the same applicable periods, the Fifteenth Amendment also requires us to maintain an Interest Coverage Ratio, as defined in the amendment, of no less than 2.00 to 1.0. Under the Fifteenth Amendment, we are allowed to incur an additional $300,000 in Additional Permitted Debt, as revised in the amendment to now include both secured and unsecured debt.

We believe we were in compliance with all covenants under our senior secured revolving credit facility as of March 31, 2015.

Capital Leases

During 2013, we entered into lease financing agreements with U.S. Bank National Association for $24,500 through the sale and subsequent leaseback of existing compressors owned by us. The carrying value of these compressors is included in our oil and natural gas full cost pool. The lease financing obligations are for 84-month terms and include the option to purchase the equipment for a specified price at 72 months as well as an option to purchase the equipment at the end of the lease term for its then-current fair market value. Lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.8%. Minimum lease payments are approximately $3,181 annually.

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Derivative instruments (Derivative Settlements Outstanding) (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative settlements receivable included in accounts receivable	$ 41,092	$ 19,678

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Asset retirement obligations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 47,424	$ 55,179
Liabilities incurred in current period	141	139
Liabilities settled and disposed in current period	(3,030)	(170)
Revisions in estimated cash flows	398	0
Accretion expense	931	1,074
Ending balance	45,864	56,222
Less current portion included in accounts payable and accrued liabilities	844	1,874
Asset retirement obligations	$ 45,020	$ 54,348	$ 43,277

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Consolidated balance sheets (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 42,173	$ 31,492
Accounts receivable, net	102,581	98,444
Inventories, net	27,162	25,557
Prepaid expenses	3,321	4,484
Derivative instruments	166,873	179,921
Total current assets	342,110	339,898
Property and equipment—at cost, net	64,397	66,561
Oil and natural gas properties, using the full cost method:
Proved	3,825,904	3,735,817
Unevaluated (excluded from the amortization base)	265,109	288,425
Accumulated depreciation, depletion, amortization and impairment	(1,763,747)	(1,701,851)
Total oil and natural gas properties	2,327,266	2,322,391
Derivative instruments	70,228	71,710
Other assets	30,120	31,256
Total assets	2,834,121	2,831,816
Liabilities and stockholders’ equity
Accounts payable and accrued liabilities	90,916	191,957
Accrued payroll and benefits payable	13,550	21,654
Accrued interest payable	33,724	24,106
Revenue distribution payable	17,869	24,467
Current maturities of long-term debt and capital leases	5,138	5,377
Derivative instruments	0	77
Deferred income taxes	60,072	60,728
Total current liabilities	221,269	328,366
Long-term debt and capital leases, less current maturities	1,730,166	1,628,425
Stock-based compensation	537	3,131
Asset retirement obligations	45,020	43,277
Deferred income taxes	119,967	116,759
Commitments and contingencies (Note 8)
Stockholders’ equity:
Preferred stock, 600,000 shares authorized, none issued and outstanding	0	0
Additional paid in capital	430,734	429,678
Retained earnings	286,414	282,166
Total stockholders' equity	717,162	711,858
Total liabilities and stockholders' equity	2,834,121	2,831,816
Common Class A
Stockholders’ equity:
Common stock	4	4
Common Class B
Stockholders’ equity:
Common stock	3	3
Common Class C
Stockholders’ equity:
Common stock	2	2
Common Class E
Stockholders’ equity:
Common stock	5	5
Common Class F
Stockholders’ equity:
Common stock	0	0
Common Class G
Stockholders’ equity:
Common stock	$ 0	$ 0

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Nature of operations and summary of significant accounting policies

3 Months Ended

Mar. 31, 2015

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. Our properties are located primarily in Oklahoma and Texas.

Interim financial statements

The accompanying unaudited consolidated interim financial statements of the Company have been prepared in accordance with the rules and regulations of the SEC and do not include all of the financial information and disclosures required by accounting principles generally accepted in the United States of America (“GAAP”) for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2014.

The financial information as of March 31, 2015, and for the three months ended March 31, 2015 and 2014, respectively, is unaudited. The financial information as of December 31, 2014 has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2014. 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, 2015 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2015.

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, 2015, cash with a recorded balance totaling $38,551 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 our assessment of the owner’s ability to pay its obligation, among other things.

We write off accounts receivable when they are determined to be uncollectible. Recovered amounts previously written off are offset against the allowance and reduce expense in the year of recovery.

Accounts receivable consisted of the following at March 31, 2015 and December 31, 2014:

	March 31, 2015			December 31, 2014
Joint interests	$	21,844		$	30,648
Accrued commodity sales	37,968			45,667
Derivative settlements	41,092			19,678
Other	2,014			2,738
Allowance for doubtful accounts	(337		)	(287		)
	$	102,581		$	98,444

Inventories

Inventories are comprised of equipment used in developing oil and natural gas properties and oil and natural gas product inventories. Equipment inventory is carried at the lower of cost or market using the average cost method. Oil and natural gas product inventories are stated at the lower of production cost or market. Inventories are shown net of a provision for obsolescence, commensurate with known or estimated exposure, which is reflected in the valuation allowance disclosed below. Inventories at March 31, 2015 and December 31, 2014 consisted of the following:

	March 31, 2015			December 31, 2014
Equipment inventory	$	25,518		$	24,169
Commodities	2,821			2,575
Inventory valuation allowance	(1,177		)	(1,187		)
	$	27,162		$	25,557

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, 2015, include $188,562 of capital costs incurred for undeveloped acreage, $72,046 for the construction of CO₂ delivery pipelines and facilities for which there are no reserves, and $4,501 for wells and facilities in progress pending determination. As of December 31, 2014, work-in-progress costs included capital costs incurred of $190,356 for undeveloped acreage, $72,046 for the construction of CO₂ delivery pipelines and facilities for which there are no reserves, and $26,023 for wells and facilities in progress pending determination.

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

Ceiling Test. In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related PV-10 value, net of tax considerations, plus the cost of unproved properties not being amortized.

Our estimates of oil and natural gas reserves as of March 31, 2015 were prepared using an average price for oil and natural gas of each month for the prior twelve months as required by the SEC. The cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties as of March 31, 2015, and no ceiling test impairment was recorded.

Due to the substantial decline of commodity prices in late 2014, which have remained low into the second quarter of 2015, we anticipate that we will have a ceiling test write-down, which could occur as early as the second quarter of 2015, if prices remain at their depressed levels. The amount of any future impairment is difficult to predict, and will depend on the average oil and natural gas prices during each period, the incremental proved reserves added during each period, and additional capital spent.

Stock-based compensation

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

The estimated fair value of the phantom stock and RSU awards are remeasured at the end of each reporting period until settlement. The estimated fair market value of these awards is calculated based on our total asset value less total liabilities, with both assets and liabilities being adjusted to fair value in accordance with the terms of the Phantom Stock Plan and the Non-Officer Restricted Stock Unit Plan. The primary adjustment required is the adjustment of oil and natural gas properties from net book value to the discounted and risk-adjusted reserve value based on internal reserve reports priced on NYMEX forward strips. Compensation cost associated with the phantom stock awards and RSU awards is recognized over the vesting period using the straight-line method and the accelerated method, respectively. The fair value of our restricted stock awards that include a service condition is based upon the estimated fair market value of our common equity per share on a minority, non-marketable basis on the date of grant, and is remeasured at the end of each reporting period until settlement. We recognize compensation cost over the requisite service period using the accelerated method for awards with graded vesting.

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

The costs associated with our stock-based compensation programs is calculated net of forfeitures, which are estimated based on our historical and expected turnover rates. If our actual forfeiture rate is materially different from our estimate, the stock-based compensation cost could be different from what we have recorded in the current period.

Cost reduction initiatives

Cost reduction initiatives include expenses related to our efforts to reduce our capital, operating and administrative costs in response to the recent deterioration of commodity prices. Included in our $8,774 of expenses for cost reduction initiatives are $6,524 in one-time severance and termination benefits in connection with our reduction in force that was implemented in February 2015. The remaining expense is a result of third party legal and professional services we have engaged to assist in our cost savings initiatives.

Recently adopted accounting pronouncements

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

Recently issued accounting pronouncements

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

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

In April 2015, the FASB issued authoritative guidance that amends the presentation of the cost of issuing debt on the balance sheet. The amendment requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendment. This guidance is effective for fiscal periods after December 15, 2015 and interim periods thereafter. We are currently evaluating the effect the new standard will have on our financial statements and results of operations.

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Fair value measurements (Level 3 Rollforward) (Details) (Recurring Fair Value Measurements, Significant unobservable inputs (Level 3), Derivative, USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Recurring Fair Value Measurements | Significant unobservable inputs (Level 3) | Derivative
Level 3 Rollforward
Beginning balance	$ 195,167	$ 3,622
Realized and unrealized gains (losses) included in non-hedge derivative losses	40,831	(15,423)
Settlements (received) paid	(56,949)	2,033
Ending balance	179,049	(9,768)
Gains relating to instruments still held at the reporting date included in non-hedge derivative gains (losses) for the period	$ 14,639	$ (15,324)

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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, 2015	Dec. 31, 2014
Cash and accounts receivable
Period within which joint interest accounts receivable are due	30 days
Period within which joint interest accounts receivable are past due	60 days
Components of accounts receivable
Joint interests	$ 21,844	$ 30,648
Accrued commodity sales	37,968	45,667
Derivative settlements	41,092	19,678
Other	2,014	2,738
Allowance for doubtful accounts	(337)	(287)
Accounts receivable, net	102,581	98,444
JP Morgan Chase Bank, N.A.
Cash and accounts receivable
Cash held at JP Morgan Chase Bank, N. A.	$ 38,551

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Fair value measurements (Nonrecurring Fair Value Measurements) (Details) (Significant unobservable inputs (Level 3), Nonrecurring fair value measurements)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Significant unobservable inputs (Level 3) | Nonrecurring fair value measurements
Nonrecurring Fair Value Measurements
Annual inflation rate	2.91%	2.95%
Credit-adjusted risk-free interest rate	12.40%	5.80%

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Nature of operations and summary of significant accounting policies (Oil and Natural Gas Properties) (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Capitalized costs of unproved properties excluded from amortization
Capital costs for undeveloped acreage	$ 188,562	$ 190,356
CO2 Delivery Pipelines and Facilities
Capitalized costs of unproved properties excluded from amortization
Exploration and development costs excluded from amortization	72,046	72,046
Uncompleted Wells Equipment and Facilities
Capitalized costs of unproved properties excluded from amortization
Exploration and development costs excluded from amortization	$ 4,501	$ 26,023

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Supplemental disclosures to the consolidated statements of cash flows

3 Months Ended

Mar. 31, 2015

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,
	2015			2014
Net cash provided by operating activities included:
Cash payments for interest	$	19,073		$	18,794
Interest capitalized	(3,462		)	(2,942		)
Cash payments for interest, net of amounts capitalized	$	15,611		$	15,852
Non-cash investing activities included:
Asset retirement obligation additions and revisions	$	539		$	139
Oil and natural gas properties acquired through increase in accounts payable and accrued liabilities	$	—		$	18,629

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Consolidated balance sheets (Parenthetical) (USD $)	Mar. 31, 2015	Dec. 31, 2014
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	352,792	364,896
Common stock, shares outstanding	352,792	364,896
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	344,859
Common stock, shares outstanding	344,859	344,859
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 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	2
Common stock, shares outstanding	2	2

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Long-term debt (Tables)

3 Months Ended

Mar. 31, 2015

Debt Disclosure [Abstract]

Components of long-term debt

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

	March 31, 2015		December 31, 2014
9.875% Senior Notes due 2020, net of discount of $4,706 and $4,861, respectively	$	295,294	$	295,139
8.25% Senior Notes due 2021	400,000		400,000
7.625% Senior Notes due 2022, including premium of $4,666 and $4,869, respectively	554,666		554,869
Senior secured revolving credit facility	450,000		347,000
Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 2.54% to 5.46%, due August 2021 through December 2028; collateralized by real property	10,577		10,705
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.85% to 5.95% , due April 2015 through February 2018; collateralized by automobiles, machinery and equipment	3,522		4,252
Capital lease obligations	21,245		21,837
	1,735,304		1,633,802
Less current maturities	5,138		5,377
	$	1,730,166	$	1,628,425

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Document and Entity Information Document	3 Months Ended
	Mar. 31, 2015	May 12, 2015
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, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Amendment Flag	false
Common Class A
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		348,507
Common Class B
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		344,859
Common Class C
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		209,882
Common Class E
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		504,276
Common Class F
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		1
Common Class G
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		2

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Derivative instruments (Tables)

3 Months Ended

Mar. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Outstanding derivative instruments

The following table summarizes our crude oil derivatives outstanding as of March 31, 2015:

		Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls	Swaps		Sold puts		Purchased puts		Sold calls		Average premium
2015
Swaps	450	$	95.25	$	—	$	—	$	—	$	—
Swaps with deferred premium (1)	4,028	$	92.78	$	—	$	—	$	—	$	13.80
2016
Three-way collars	240	$	—	$	84.00	$	92.00	$	101.01	$	—
Enhanced swaps (2)	3,720	$	92.94	$	80.52	$	—	$	—	$	—
Purchased puts (2)	3,720	$	—	$	—	$	60.00	$	—	$	5.54

___________

(1) As a result of the deferred premiums, the above 4,028,000 barrels of crude oil production in 2015 are hedged at an effective price of $78.98/barrel.

(2) Total premiums of $20,609 for the purchased puts were paid at contract inception in December 2014. Excluding the premiums and utilizing an average NYMEX strip price of $57.74 for 2016 as of March 31, 2015, the average realized price from our 3,720,000 barrels of hedged production that have associated sold puts and purchased puts is $72.42/barrel. This effective price is also the floor on the realized price we would receive in the event of any crude oil price decline below$60.00/barrel. Upon settlement, in the event that prices increase above $60.00/barrel, our effective price would increase by a commensurate amount of the price increase until prices reach the sold put price after which we would receive the swap price.

The following tables summarize our natural gas derivative instruments outstanding as of March 31, 2015:

Period and type of contract	Volume BBtu	Weighted average fixed price per MMBtu
2015
Natural gas swaps	12,240	$	4.15
Natural gas basis protection swaps	10,800	$	0.24
2016
Natural gas swaps	14,000	$	4.19
Natural gas basis protection swaps	8,400	$	0.36
2017
Natural gas swaps	12,700	$	3.64
2018
Natural gas swaps	8,250	$	3.83

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, 2015						As of December 31, 2014
	Assets		Liabilities		Net value		Assets		Liabilities			Net value
Natural gas swaps	$	37,843	$	—	$	37,843	$	32,939	$	—		$	32,939
Oil swaps	19,168		—		19,168		23,465		—			23,465
Oil collars	1,700		—		1,700		1,175		—			1,175
Oil enhanced swaps	91,362		—		91,362		100,724		—			100,724
Oil purchased puts	85,987		—		85,987		93,268		—			93,268
Natural gas basis differential swaps	1,041		—		1,041		292		(309		)	(17		)
Total derivative instruments	237,101		—		237,101		251,863		(309		)	251,554
Less:
Netting adjustments (1)	—		—		—		232		(232		)	—
Current portion asset (liability)	166,873		—		166,873		179,921		(77		)	179,844
	$	70,228	$	—	$	70,228	$	71,710	$	—		$	71,710

___________

(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, 2015 and December 31, 2014 were as follows:

	March 31, 2015		December 31, 2014
Derivative settlements receivable included in accounts receivable	$	41,092	$	19,678

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

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

	Three months ended
	March 31,
	2015			2014
Change in fair value of commodity price swaps	$	606		$	(5,193	)
Change in fair value of collars	525			(2,863		)
Change in fair value of enhanced swaps and put options	(16,643		)	(10,527		)
Change in fair value of natural gas basis differential contracts	1,058			(1,861		)
Receipts from (payments on) settlement of commodity price swaps	19,027			(5,850		)
Payments on settlement of collars	—			(41		)
Receipts from (payments on) settlement of enhanced swaps and put options	56,949			(1,992		)
Payments on settlement of natural gas basis differential contracts	(91		)	(872		)
	$	61,431		$	(29,199	)

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Consolidated statements of operations (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Revenues:
Commodity sales	$ 93,079	$ 173,339
Total revenues	93,079	173,339
Costs and expenses:
Lease operating	31,632	33,655
Transportation and processing	2,372	1,366
Production taxes	4,484	6,643
Depreciation, depletion & amortization	65,211	55,750
General and administrative	9,194	13,387
Cost reduction initiatives	8,774	0
Total costs and expenses	121,667	110,801
Operating income	(28,588)	62,538
Non-operating income (expense):
Interest expense	(26,712)	(26,459)
Non-hedge derivative gains (losses)	61,431	(29,199)
Other income, net	674	160
Net non-operating income (expense)	35,393	(55,498)
Income before income taxes	6,805	7,040
Income tax expense	2,557	2,635
Net income	$ 4,248	$ 4,405

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Stock-based compensation

3 Months Ended

Mar. 31, 2015

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.

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

A summary of our phantom stock and RSU activity during the three months ended March 31, 2015 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, 2015	$	20.18	23,179				$	9.91	569,160
Granted	—		—				15.26		52,711
Vested	24.48		(6,649	)	$	25	10.58		(206,332	)	$	790
Forfeited	17.99		(4,907	)			9.62		(105,159	)
Unvested and outstanding at March 31, 2015	$	18.64	11,623				$	10.48	310,380

Based on an estimated fair value of $2.92 per phantom share and RSU as of March 31, 2015, the aggregate intrinsic value of the unvested phantom shares and RSUs outstanding was $940.

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 whereby CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively “CCMP”) receive cash upon the sale of its class E common stock (a “Transaction” as defined in the restricted stock agreements). 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.

Our 2010 Plan allows participants to elect, upon vesting of their Time Vested awards, to have us withhold shares having a fair market value greater than the minimum statutory withholding amounts for income and payroll taxes that would be due with respect to such vested shares. As a result of this provision, the Time Vested awards are classified as liability awards under accounting guidance and remeasured to fair value at the end of each reporting period. The Performance Vested awards are classified as equity awards and are not remeasured to fair value at the end of each reporting period subsequent to grant date.

We have previously modified the vesting conditions of awards granted under the 2010 Plan. Please see “Note 10—Stock-based compensation” in Item 8. Financial Statement and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2014, for a discussion of the modifications.

A summary of our restricted stock activity during the three months ended March 31, 2015 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, 2015	$	791.52	25,834				$	292.92	38,943
Granted	533.80		610				306.50		599
Vested	794.40		(6,354	)	$	3,392	—		—
Forfeited	764.16		(3,190	)			310.57		(8,719	)
Unvested and total outstanding at March 31, 2015	$	786.30	16,900				$	288.19	30,823

During the three months ended March 31, 2015 and 2014, respectively, we repurchased and canceled 1,404 and 1,068 vested shares, primarily for tax withholding, and we expect to repurchase and cancel approximately 2,000 restricted shares vesting during the next twelve months. Based on an estimated fair value of $533.80 per Time Vested restricted share, the aggregate intrinsic value of the unvested Time Vested restricted shares outstanding was $9,021 as of March 31, 2015.

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,
	2015			2014
Stock-based compensation cost	$	(1,500	)	$	2,531
Less: stock-based compensation cost capitalized	415			(962		)
Stock-based compensation expense	$	(1,085	)	$	1,569
Payments for stock-based compensation	$	812		$	874

We recorded a credit to our stock-based compensation expense for the three months ended March 31, 2015, due to forfeitures that occurred in conjunction with our workforce reduction in February 2015 and due to a decrease in the per-unit value of our phantom stock and RSU awards. As of March 31, 2015 and December 31, 2014, accrued payroll and benefits payable included $4,056 and $4,830, respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized compensation cost of approximately $14,793 is expected to be recognized over a weighted average period of 2.3 years.

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Asset retirement obligations

3 Months Ended

Mar. 31, 2015

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, 2015 and 2014.

	Three months ended March 31,
	2015			2014
Beginning balance	$	47,424		$	55,179
Liabilities incurred in current period	141			139
Liabilities settled and disposed in current period	(3,030		)	(170		)
Revisions in estimated cash flows	398			—
Accretion expense	931			1,074
Ending balance	45,864			56,222
Less current portion included in accounts payable and accrued liabilities	844			1,874
	$	45,020		$	54,348

See Note 5—Fair value measurements for additional information regarding fair value assumptions associated with our asset retirement obligations.

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Nature of operations and summary of significant accounting policies (Inventories) (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Inventory, Net [Abstract]
Equipment inventory	$ 25,518	$ 24,169
Commodities	2,821	2,575
Inventory valuation allowance	(1,177)	(1,187)
Inventories, net	$ 27,162	$ 25,557

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Fair value measurements (Tables)

3 Months Ended

Mar. 31, 2015

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, 2015						As of December 31, 2014
	Derivative assets		Derivative liabilities		Net assets (liabilities)		Derivative assets			Derivative liabilities			Net assets (liabilities)
Significant other observable inputs (Level 2)	$	58,052	$	—	$	58,052	$	56,696		$	(309	)	$	56,387
Significant unobservable inputs (Level 3)	179,049		—		179,049		195,167			—			195,167
Netting adjustments (1)	—		—		—		(232		)	232			—
	$	237,101	$	—	$	237,101	$	251,631		$	(77	)	$	251,554

___________

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

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, 2015 and 2014 were: 

	Three months ended March 31,
Net derivative assets (liabilities)	2015			2014
Beginning balance	$	195,167		$	3,622
Realized and unrealized gains (losses) included in non-hedge derivative losses	40,831			(15,423		)
Settlements (received) paid	(56,949		)	2,033
Ending balance	$	179,049		$	(9,768	)
Gains relating to instruments still held at the reporting date included in non-hedge derivative gains (losses) for the period	$	14,639		$	(15,324	)

Fair value of other financial instruments

The carrying value and estimated fair value of our long-term debt at March 31, 2015 and December 31, 2014 were as follows:

	March 31, 2015				December 31, 2014
Level 2	Carrying value		Estimated fair value		Carrying value		Estimated fair value
9.875% Senior Notes due 2020	$	295,294	$	228,480	$	295,139	$	269,091
8.25% Senior Notes due 2021	400,000		278,000		400,000		270,000
7.625% Senior Notes due 2022	554,666		368,500		554,869		379,775
Senior secured revolving credit facility	450,000		450,000		347,000		347,000
Other secured long-term debt	14,099		14,099		14,957		14,957
	$	1,714,059	$	1,339,079	$	1,611,965	$	1,280,823

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)			Derivatives(1)		Amounts outstanding under senior secured revolving credit facility			Net amount
As of March 31, 2015
Derivative assets	$	237,101		$	—		$	237,101		$	—	$	(140,962	)	$	96,139
Derivative liabilities	—			—			—			—		—			—
	$	237,101		$	—		$	237,101		$	—	$	(140,962	)	$	96,139
As of December 31, 2014
Derivative assets	$	251,863		$	(232	)	$	251,631		$	—	$	(118,430	)	$	133,201
Derivative liabilities	(309		)	232			(77		)	—		—			(77		)
	$	251,554		$	—		$	251,554		$	—	$	(118,430	)	$	133,124

___________

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

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

3 Months Ended

Mar. 31, 2015

Accounting Policies [Abstract]

Components of accounts receivable

Accounts receivable consisted of the following at March 31, 2015 and December 31, 2014:

	March 31, 2015			December 31, 2014
Joint interests	$	21,844		$	30,648
Accrued commodity sales	37,968			45,667
Derivative settlements	41,092			19,678
Other	2,014			2,738
Allowance for doubtful accounts	(337		)	(287		)
	$	102,581		$	98,444

Components of inventory

Inventories at March 31, 2015 and December 31, 2014 consisted of the following:

	March 31, 2015			December 31, 2014
Equipment inventory	$	25,518		$	24,169
Commodities	2,821			2,575
Inventory valuation allowance	(1,177		)	(1,187		)
	$	27,162		$	25,557

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Commitments and contingencies

3 Months Ended

Mar. 31, 2015

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 $874 and $920 as of March 31, 2015 and December 31, 2014, 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, 2015 or 2014.

Litgation and Claims

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, an alleged class action was filed against us in the United States District Court for the Western District of Oklahoma (“Naylor Farms Case”) alleging that we improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners as categorized in the petition from crude oil and natural gas wells located in Oklahoma. The purported class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. The plaintiffs have alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. We have responded to the Naylor Farms petition, denied the allegations and raised arguments and defenses. Discovery is ongoing and information and documents continue to be exchanged. The class has not been certified, but the motion for class certification is due in the fourth quarter of 2015. We are not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the Naylor Farms Case will have on our financial condition, results of operations or cash flows due to the preliminary status of the matters, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, and the ultimate potential outcome of the matter. Plaintiffs in the Naylor Farms Case have indicated that, if the class is certified, they seek damages in excess of $5,000 which may increase with the passage of time, a majority of which would be comprised of interest. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.

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, (“Dodson Case”) with allegation similar to those asserted in the Naylor Farms case related to post-production deductions, and include clams for breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. The alleged class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. We have responded to the Dodson petition, denied the allegations and raised a number of affirmative defenses. At this time, a class has not been certified and discovery has not yet commenced. We are not currently able to estimate a reasonable possible loss or range of loss or what impact, if any, the Dodson Case will have on its financial condition, results of operations or cash flows due to the preliminary status of the matter, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, and the ultimate potential outcome of the matter. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.

Martha Donelson and John Friend, on behalf of themselves and on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On August 11, 2014, an alleged class action was filed against us, as well as several other operators in Osage County, in the United States District Court for the Northern District of Oklahoma (“Donelson Case”), alleging claims on behalf of the named plaintiffs and all similarly situated Osage County land owners and surface lessees. The plaintiffs assert claims seeking recovery for trespass, nuisance, negligence and unjust enrichment. Relief sought includes declaring oil and natural gas leases and drilling permits obtained in Osage County without a prior NEPA study void ab initio, removing us from all properties owned by the class members, disgorgement of profits, and compensatory and punitive damages. We have joined in Motions to Dismiss filed by the other defendants. At this time, a class has not been certified and discovery has yet to begin. As such, we are not yet able to estimate a possible loss, or range of possible loss, if any. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.

We are involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, employment claims, and other matters which arise in the ordinary course of business. While the outcome of these legal proceedings cannot be predicted with certainty, we do not expect any of them individually to have a material 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 CO₂ recycle compressors at our EOR facilities and 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, 2015, there were no material changes to our contractual commitments since December 31, 2014.

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

3 Months Ended

Mar. 31, 2015

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. Our properties are located primarily in Oklahoma and Texas.

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, 2014.

The financial information as of March 31, 2015, and for the three months ended March 31, 2015 and 2014, respectively, is unaudited. The financial information as of December 31, 2014 has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2014. 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, 2015 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2015.

Reclassification

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 our assessment of the owner’s ability to pay its obligation, among other things.

We write off accounts receivable when they are determined to be uncollectible. Recovered amounts previously written off are offset against the allowance and reduce expense in the year of recovery.

Inventories

Inventories

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

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, 2015, include $188,562 of capital costs incurred for undeveloped acreage, $72,046 for the construction of CO₂ delivery pipelines and facilities for which there are no reserves, and $4,501 for wells and facilities in progress pending determination. As of December 31, 2014, work-in-progress costs included capital costs incurred of $190,356 for undeveloped acreage, $72,046 for the construction of CO₂ delivery pipelines and facilities for which there are no reserves, and $26,023 for wells and facilities in progress pending determination.

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

Ceiling Test. In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related PV-10 value, net of tax considerations, plus the cost of unproved properties not being amortized.

Our estimates of oil and natural gas reserves as of March 31, 2015 were prepared using an average price for oil and natural gas of each month for the prior twelve months as required by the SEC. The cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties as of March 31, 2015, and no ceiling test impairment was recorded.

Due to the substantial decline of commodity prices in late 2014, which have remained low into the second quarter of 2015, we anticipate that we will have a ceiling test write-down, which could occur as early as the second quarter of 2015, if prices remain at their depressed levels. 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, stock-based compensation expense could have been significantly impacted if other assumptions had been used.

The costs associated with our stock-based compensation programs is calculated net of forfeitures, which are estimated based on our historical and expected turnover rates. If our actual forfeiture rate is materially different from our estimate, the stock-based compensation cost could be different from what we have recorded in the current period.

Cost reduction initiatives

Cost reduction initiatives

Cost reduction initiatives include expenses related to our efforts to reduce our capital, operating and administrative costs in response to the recent deterioration of commodity prices. Included in our $8,774 of expenses for cost reduction initiatives are $6,524 in one-time severance and termination benefits in connection with our reduction in force that was implemented in February 2015. The remaining expense is a result of third party legal and professional services we have engaged to assist in our cost savings initiatives.

Recently adopted and recently 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.

Recently issued accounting pronouncements

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

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

In April 2015, the FASB issued authoritative guidance that amends the presentation of the cost of issuing debt on the balance sheet. The amendment requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendment. This guidance is effective for fiscal periods after December 15, 2015 and interim periods thereafter. We are currently evaluating the effect the new standard will have on our financial statements and results of operations.

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

3 Months Ended

Mar. 31, 2015

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,
	2015			2014
Net cash provided by operating activities included:
Cash payments for interest	$	19,073		$	18,794
Interest capitalized	(3,462		)	(2,942		)
Cash payments for interest, net of amounts capitalized	$	15,611		$	15,852
Non-cash investing activities included:
Asset retirement obligation additions and revisions	$	539		$	139
Oil and natural gas properties acquired through increase in accounts payable and accrued liabilities	$	—		$	18,629

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Fair value measurements (Recurring Fair Value Measurements) (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015		Dec. 31, 2014
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets, gross	$ 237,101		$ 251,863
Derivative liabilities, gross	0		(309)
Derivative assets (liabilities), net	237,101		251,554
Derivative assets, amount offset	0		(232)
Derivative liabilities, amounts offset	0		232
Derivative assets, net	237,101		251,631
Derivative liabilities, net	0		(77)
Recurring Fair Value Measurements
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets (liabilities), net	237,101		251,554
Derivative assets, amount offset	0	[1]	(232)	[1]
Derivative liabilities, amounts offset	0	[1]	232	[1]
Derivative assets, net	237,101		251,631
Derivative liabilities, net	0		(77)
Recurring Fair Value Measurements | Significant other observable inputs (Level 2)
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets, gross	58,052		56,696
Derivative liabilities, gross	0		(309)
Derivative assets (liabilities), net	58,052		56,387
Recurring Fair Value Measurements | Significant unobservable inputs (Level 3)
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets, gross	179,049		195,167
Derivative liabilities, gross	0		0
Derivative assets (liabilities), net	$ 179,049		$ 195,167

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

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Stock-based compensation (Tables)

3 Months Ended

Mar. 31, 2015

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, 2015 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, 2015	$	20.18	23,179				$	9.91	569,160
Granted	—		—				15.26		52,711
Vested	24.48		(6,649	)	$	25	10.58		(206,332	)	$	790
Forfeited	17.99		(4,907	)			9.62		(105,159	)
Unvested and outstanding at March 31, 2015	$	18.64	11,623				$	10.48	310,380

A summary of our restricted stock activity during the three months ended March 31, 2015 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, 2015	$	791.52	25,834				$	292.92	38,943
Granted	533.80		610				306.50		599
Vested	794.40		(6,354	)	$	3,392	—		—
Forfeited	764.16		(3,190	)			310.57		(8,719	)
Unvested and total outstanding at March 31, 2015	$	786.30	16,900				$	288.19	30,823

Stock-based compensation cost

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

	Three months ended
	March 31,
	2015			2014
Stock-based compensation cost	$	(1,500	)	$	2,531
Less: stock-based compensation cost capitalized	415			(962		)
Stock-based compensation expense	$	(1,085	)	$	1,569
Payments for stock-based compensation	$	812		$	874

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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, 2015	Mar. 31, 2014
Net cash provided by operating activities included:
Cash payments for interest	$ 19,073	$ 18,794
Interest capitalized	(3,462)	(2,942)
Cash payments for interest, net of amounts capitalized	15,611	15,852
Non-cash investing activities included:
Asset retirement obligation additions and revisions	539	139
Oil and natural gas properties acquired through increase in accounts payable and accrued liabilities	$ 0	$ 18,629

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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, 2015
Vest date fair value
Aggregate intrinsic value of unvested phantom shares and RSUs outstanding	$ 9,021
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	$ 20.18
Granted	$ 0.00
Vested	$ 24.48
Forfeited	$ 17.99
Unvested and outstanding at end of period	$ 18.64
Shares
Unvested and outstanding at beginning of period (in shares)	23,179
Granted (in shares)	0
Vested (in shares)	(6,649)
Forfeited (in shares)	(4,907)
Unvested and outstanding at end of period (in shares)	11,623
Vest date fair value
Vest date fair value	25
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	$ 9.91
Granted	$ 15.26
Vested	$ 10.58
Forfeited	$ 9.62
Unvested and outstanding at end of period	$ 10.48
Shares
Unvested and outstanding at beginning of period (in shares)	569,160
Granted (in shares)	52,711
Vested (in shares)	(206,332)
Forfeited (in shares)	(105,159)
Unvested and outstanding at end of period (in shares)	310,380
Vest date fair value
Vest date fair value	790
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	$ 2.92
Aggregate intrinsic value of unvested phantom shares and RSUs outstanding	$ 940

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Consolidated statements of cash flows (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Cash flows from operating activities
Net income	$ 4,248	$ 4,405
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion & amortization	65,211	55,750
Deferred income taxes	2,553	2,485
Non-hedge derivative (gains) losses	(61,431)	29,199
Gain on sale of assets	(79)	(84)
Other	1,221	492
Change in assets and liabilities
Accounts receivable	(8,126)	(15,762)
Inventories	(6,431)	(4,234)
Prepaid expenses and other assets	1,116	669
Accounts payable and accrued liabilities	(2,808)	2,303
Revenue distribution payable	(6,598)	(1,679)
Stock-based compensation	(1,898)	695
Net cash (used in) provided by operating activities	(13,022)	74,239
Cash flows from investing activities
Expenditures for property, plant, and equipment and oil and natural gas properties	(156,798)	(138,669)
Proceeds from asset dispositions	3,068	16,997
Settlement of non-hedge derivative instruments	75,885	(8,755)
Net cash used in investing activities	(77,845)	(130,427)
Cash flows from financing activities
Proceeds from long-term debt	103,000	50,603
Repayment of long-term debt	(860)	(3,783)
Principal payments under capital lease obligations	(592)	(570)
Net cash provided by financing activities	101,548	46,250
Net increase (decrease) in cash and cash equivalents	10,681	(9,938)
Cash and cash equivalents at beginning of period	31,492	48,595
Cash and cash equivalents at end of period	$ 42,173	$ 38,657

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Fair value measurements

3 Months Ended

Mar. 31, 2015

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, 2015 or December 31, 2014. Our derivative contracts classified as Level 2 as of March 31, 2015 and December 31, 2014 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, 2015 and December 31, 2014, our derivative contracts classified as Level 3 consisted of three-way collars, enhanced swaps, sold puts and purchased puts. The fair value of these contracts is developed by a third-party pricing service using a proprietary valuation model, which we believe incorporates the assumptions that market participants would have made at the end of each period. Observable inputs include contractual terms, published forward pricing curves, and yield curves. Significant unobservable inputs are implied volatilities. Significant increases (decreases) in implied volatilities in isolation would result in a significantly higher (lower) fair value measurement. We review these valuations and the changes in the fair value measurements for reasonableness. All derivative instruments are recorded at fair value and include a measure of our own nonperformance risk for derivative liabilities or that of our counterparties for derivative assets.

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

	As of March 31, 2015						As of December 31, 2014
	Derivative assets		Derivative liabilities		Net assets (liabilities)		Derivative assets			Derivative liabilities			Net assets (liabilities)
Significant other observable inputs (Level 2)	$	58,052	$	—	$	58,052	$	56,696		$	(309	)	$	56,387
Significant unobservable inputs (Level 3)	179,049		—		179,049		195,167			—			195,167
Netting adjustments (1)	—		—		—		(232		)	232			—
	$	237,101	$	—	$	237,101	$	251,631		$	(77	)	$	251,554

___________

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

Changes in the fair value of our derivative instruments classified as Level 3 in the fair value hierarchy during the three months ended March 31, 2015 and 2014 were: 

	Three months ended March 31,
Net derivative assets (liabilities)	2015			2014
Beginning balance	$	195,167		$	3,622
Realized and unrealized gains (losses) included in non-hedge derivative losses	40,831			(15,423		)
Settlements (received) paid	(56,949		)	2,033
Ending balance	$	179,049		$	(9,768	)
Gains relating to instruments still held at the reporting date included in non-hedge derivative gains (losses) for the period	$	14,639		$	(15,324	)

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 2015 and 2014 were escalated using an annual inflation rate of 2.91% and 2.95%, respectively, and discounted using our credit-adjusted risk-free interest rate of 12.40% and 5.80%, respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. 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, 2015 and December 31, 2014 were as follows:

	March 31, 2015				December 31, 2014
Level 2	Carrying value		Estimated fair value		Carrying value		Estimated fair value
9.875% Senior Notes due 2020	$	295,294	$	228,480	$	295,139	$	269,091
8.25% Senior Notes due 2021	400,000		278,000		400,000		270,000
7.625% Senior Notes due 2022	554,666		368,500		554,869		379,775
Senior secured revolving credit facility	450,000		450,000		347,000		347,000
Other secured long-term debt	14,099		14,099		14,957		14,957
	$	1,714,059	$	1,339,079	$	1,611,965	$	1,280,823

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, 2015, the counterparties to our open derivative contracts consisted of eight financial institutions, of which eight 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)			Derivatives(1)		Amounts outstanding under senior secured revolving credit facility			Net amount
As of March 31, 2015
Derivative assets	$	237,101		$	—		$	237,101		$	—	$	(140,962	)	$	96,139
Derivative liabilities	—			—			—			—		—			—
	$	237,101		$	—		$	237,101		$	—	$	(140,962	)	$	96,139
As of December 31, 2014
Derivative assets	$	251,863		$	(232	)	$	251,631		$	—	$	(118,430	)	$	133,201
Derivative liabilities	(309		)	232			(77		)	—		—			(77		)
	$	251,554		$	—		$	251,554		$	—	$	(118,430	)	$	133,124

___________

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

We did not post additional collateral under any of these contracts as all of our counterparties are secured by the collateral under our senior secured revolving credit facility. Payment on our derivative contracts would be accelerated in the event of a default on our senior secured revolving credit facility. The aggregate fair value of our derivative liabilities subject to acceleration in the event of default was nil at March 31, 2015.

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(Components of Long-Term Debt) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Components of long-term debt
Senior secured revolving credit facility	450,000	$ 347,000
Real estate mortgage notes payable	10,577	10,705
Installment notes payable	3,522	4,252
Capital lease obligations	21,245	21,837
Total long-term debt and capital lease obligations	1,735,304	1,633,802
Less current maturities	5,138	5,377
Long-term debt and capital leases, less current maturities	1,730,166	1,628,425
Mortgages | Minimum
Components of long-term debt
Stated interest rate	2.54%
Maturity date (month and year)	2021-08
Mortgages | Maximum
Components of long-term debt
Stated interest rate	5.46%
Maturity date (month and year)	2028-12
Secured Debt | Minimum
Components of long-term debt
Stated interest rate	2.85%
Maturity date (month and year)	2015-04
Secured Debt | Maximum
Components of long-term debt
Stated interest rate	5.95%
Maturity date (month and year)	2018-02
9.875% Senior Notes due 2020
Components of long-term debt
Senior Notes	295,294	295,139
Unamortized discount	4,706	4,861
9.875% Senior Notes due 2020 | Senior Notes
Components of long-term debt
Stated interest rate	9.875%
Maturity date (year)	2020
8.25% Senior Notes due 2021
Components of long-term debt
Senior Notes	400,000	400,000
8.25% Senior Notes due 2021 | Senior Notes
Components of long-term debt
Stated interest rate	8.25%
Maturity date (year)	2021
7.625% Senior Notes due 2022
Components of long-term debt
Senior Notes	554,666	554,869
Unamortized premium	4,666	$ 4,869
7.625% Senior Notes due 2022 | Senior Notes
Components of long-term debt
Stated interest rate	7.625%
Maturity date (year)	2022

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Fair value measurements (Counterparty Credit Risk) (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015
Counterparty Credit Risk
Derivative liabilities subject to acceleration	$ 0
Concentration of Counterparty Credit Risk
Counterparty Credit Risk
Derivative contracts, number of counterparties	8
Derivative contracts, number of counterparties subject to offset under credit facility	8

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Asset retirement obligations (Tables)

3 Months Ended

Mar. 31, 2015

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, 2015 and 2014.

	Three months ended March 31,
	2015			2014
Beginning balance	$	47,424		$	55,179
Liabilities incurred in current period	141			139
Liabilities settled and disposed in current period	(3,030		)	(170		)
Revisions in estimated cash flows	398			—
Accretion expense	931			1,074
Ending balance	45,864			56,222
Less current portion included in accounts payable and accrued liabilities	844			1,874
	$	45,020		$	54,348