Chaparral Energy, Inc. (Form: 10-Q, Received: 11/16/2015 07:29:15)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________________

Form 10-Q

____________________________



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

For the quarterly period ended September 30, 2015



¨	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 November 16, 2015 :



Class		Number of shares
Class A Common Stock, $0.01 par value		345,289
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

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CHAPARRAL ENERGY, INC.

Index to Form 10-Q




	Page
Part I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated balance sheets as of September 30, 2015 (unaudited) and December 31, 2014	6
Consolidated statements of operations for the three and nine months ended September 30, 2015 and 2014 (unaudited)	8
Consolidated statements of cash flows for the nine months ended September 30, 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	27
Overview	27
Results of operations	29
Liquidity and capital resources	38
Non-GAAP financial measure and reconciliation	42
Critical accounting policies	43
Recent accounting pronouncements	43
Item 3. Quantitative and Qualitative Disclosures about Market Risk	43
Item 4. Controls and Procedures	46
Part II. O THER INFORMATION
Item 1. Legal Proceedings	46
Item 1A. Risk Factors	46
Item 5. Other Information	47
Item 6. Exhibits	47
Signatures	48
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

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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.

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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 in Item 1A of this report and 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 CO ₂ ;


•	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.

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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.


•	CO ₂ . Carbon dioxide.


•	Enhanced oil recovery (EOR). The use of any improved recovery method, including injection of CO ₂ or 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.


•	STACK . An acronym standing for Sooner Trend Anadarko Canadian Kingfisher. A play in the Anadarko Basin of Oklahoma in which we operate.


•	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.

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PART I — FINANCIAL INFORMATION


ITEM 1.	FINANCIAL STATEMENTS

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets



	September 30, 2015			December 31, 2014
(dollars in thousands, except share data)	(unaudited)			December 31, 2014
Assets
Current assets:
Cash and cash equivalents	$	37,783		$	31,492
Accounts receivable, net	77,583			98,444
Inventories, net	17,020			25,557
Prepaid expenses	2,055			4,484
Derivative instruments	142,944			179,921
Total current assets	277,385			339,898
Property and equipment—at cost, net	53,669			66,561
Oil and natural gas properties, using the full cost method:
Proved	4,049,859			3,735,817
Unevaluated (excluded from the amortization base)	98,032			288,425
Accumulated depreciation, depletion, amortization and impairment	(2,820,454		)	(1,701,851		)
Total oil and natural gas properties	1,327,437			2,322,391
Derivative instruments	40,766			71,710
Deferred income taxes	35,622			—
Other assets	29,019			31,256
	$	1,763,898		$	2,831,816

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

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Chaparral Energy, Inc. and subsidiaries Consolidated balance sheets—continued

	September 30, 2015			December 31, 2014
(dollars in thousands, except share data)	(unaudited)			December 31, 2014
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	50,608		$	191,957
Accrued payroll and benefits payable	10,485			21,654
Accrued interest payable	33,578			24,106
Revenue distribution payable	12,023			24,467
Current maturities of long-term debt and capital leases	4,619			5,377
Derivative instruments	39			77
Deferred income taxes	51,629			60,728
Total current liabilities	162,981			328,366
Long-term debt and capital leases, less current maturities	1,671,920			1,628,425
Stock-based compensation	1,620			3,131
Asset retirement obligations	46,518			43,277
Deferred income taxes	—			116,759
Commitments and contingencies (Note 9)
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 345,336 and 364,896 shares issued and outstanding as of September 30, 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	430,609			429,678
Retained earnings	(549,764		)	282,166
	(119,141		)	711,858
	$	1,763,898		$	2,831,816

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

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Chaparral Energy, Inc. and subsidiaries

Consolidated statements of operations



	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2015			2014			2015			2014
				(unaudited)
Revenues:
Commodity sales	$	74,512		$	179,383		$	261,801		$	545,698
Total revenues	74,512			179,383			261,801			545,698
Costs and expenses:
Lease operating	24,881			38,915			83,921			107,650
Transportation and processing	1,902			3,162			6,246			6,012
Production taxes	2,795			7,133			11,123			21,935
Depreciation, depletion and amortization	52,027			61,527			173,694			180,631
Loss on impairment of oil and gas assets	737,758			—			955,320			—
Loss on impairment of other assets	—			—			13,311			—
General and administrative	7,389			14,820			25,843			43,199
Cost reduction initiatives	603			—			9,739			—
Total costs and expenses	827,355			125,557			1,279,197			359,427
Operating (loss) income	(752,843		)	53,826			(1,017,396		)	186,271
Non-operating income (expense):
Interest expense	(28,598		)	(25,434		)	(83,202		)	(78,096		)
Non-hedge derivative gains	85,415			104,413			105,266			17,218
Other income, net	108			442			2,088			1,407
Net non-operating income (expense)	56,925			79,421			24,152			(59,471		)
(Loss) income before income taxes	(695,918		)	133,247			(993,244		)	126,800
Income tax (benefit) expense	(48,776		)	49,734			(161,314		)	47,315
Net (loss) income	$	(647,142	)	$	83,513		$	(831,930	)	$	79,485

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

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Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows



	Nine months ended
	September 30,
(in thousands)	2015			2014
	(unaudited)
Cash flows from operating activities
Net (loss) income	$	(831,930	)	$	79,485
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	173,694			180,631
Loss on impairment of assets	968,631			—
Deferred income taxes	(161,480		)	46,894
Non-hedge derivative gains	(105,266		)	(17,218		)
Gain on sale of assets	(1,448		)	(1,007		)
Other	4,013			3,033
Change in assets and liabilities
Accounts receivable	16,625			(14,442		)
Inventories	(3,642		)	(7,287		)
Prepaid expenses and other assets	2,258			998
Accounts payable and accrued liabilities	(15,012		)	(906		)
Revenue distribution payable	(12,444		)	5,446
Stock-based compensation	(4,355		)	3,504
Net cash provided by operating activities	29,644			279,131
Cash flows from investing activities
Expenditures for property, plant, and equipment and oil and natural gas properties	(267,203		)	(499,255		)
Proceeds from asset dispositions	29,251			258,578
Settlement of non-hedge derivative instruments	173,149			(25,038		)
Net cash used in investing activities	(64,803		)	(265,715		)
Cash flows from financing activities
Proceeds from long-term debt	120,000			186,999
Repayment of long-term debt	(75,354		)	(227,572		)
Principal payments under capital lease obligations	(1,792		)	(1,726		)
Payment of other financing fees	(1,404		)	—
Net cash provided by (used in) financing activities	41,450			(42,299		)
Net increase (decrease) in cash and cash equivalents	6,291			(28,883		)
Cash and cash equivalents at beginning of period	31,492			48,595
Cash and cash equivalents at end of period	$	37,783		$	19,712

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

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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 September 30, 2015 , and for the three and nine months ended September 30, 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 and nine months ended September 30, 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 September 30, 2015 , cash with a recorded balance totaling $36,124 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. When we recover amounts that were previously written off, those amounts are offset against the allowance and reduce expense in the year of recovery.

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

Accounts receivable consisted of the following at September 30, 2015 and December 31, 2014 :



	September 30, 2015			December 31, 2014
Joint interests	$	10,928		$	30,648
Accrued commodity sales	28,060			45,667
Derivative settlements	37,388			19,678
Other	1,694			2,738
Allowance for doubtful accounts	(487		)	(287		)
	$	77,583		$	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. We recorded a lower of cost or market adjustment of nil and $7,296 on our equipment inventory for the three and nine months ended September 30, 2015 , respectively. The adjustment, recorded during the second quarter of 2015, was to reflect lower market prices resulting from a decline in demand for such equipment as drilling activity has decreased in the current low commodity price environment. The adjustment is reflected in “Loss on impairment of other assets” in our consolidated statements of operations.We did not record any significant inventory adjustments in the prior year periods. Inventories at September 30, 2015 and December 31, 2014 consisted of the following:



	September 30, 2015			December 31, 2014
Equipment inventory	$	23,050		$	24,169
Commodities	1,839			2,575
Inventory valuation allowance	(7,869		)	(1,187		)
	$	17,020		$	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 September 30, 2015 , include $95,325 of capital costs incurred for undeveloped acreage and $2,707 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 CO ₂ delivery pipelines and facilities for which there are no reserves, and $26,023 for wells and facilities in progress pending determination. Our work-in-progress balance at September 30, 2015 no longer includes amounts related to the construction of CO ₂ delivery pipelines and facilities as those have been reclassified to the full-cost amortization base during the third quarter of 2015 in conjunction with our recognition of proved reserves from the development of all remaining phases at our North Burbank Unit.

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

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

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

Our estimates of oil and natural gas reserves as of September 30, 2015 were prepared using an average price for oil and natural gas on the first day of each month for the prior twelve months as required by the SEC.

Due to the substantial decline of commodity prices that began in late 2014 and which remained low through September 30, 2015 , the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties, resulting in a ceiling test write-down during the three and nine months ended September 30, 2015 of $737,758 and $955,320 , respectively. Further write-downs are expected to occur in significant amounts if prices remain at their depressed levels. The amount of any future impairment is generally 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.

Impairment of long-lived assets

Impairment losses are recorded on property and equipment used in operations and other long-lived assets held and used when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. Impairment losses are also recorded on assets classified as held for sale when there is an excess of carrying value over fair value less costs to sell.

We recorded impairment losses of nil and $6,015 related to four drilling rigs not currently in use for the three and nine months ended September 30, 2015 . One of the rigs was last deployed in January 2015 while the remaining three have been stacked for two to three years. As a result of the recent deterioration in commodity prices and drilling activity, the value of such equipment has declined while utilizing third party equipment has become more cost effective, resulting in us impairing the value of the rigs to their estimated fair value during the second quarter of 2015. These losses are reflected in “Loss on impairment of other assets” in our consolidated statements of operations. We had previously recorded $3,490 and $1,500 of impairment related to these rigs during the years ended December 31, 2013 and 2012, respectively.

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. We consider the measurement of fair value of our phantom stock, RSU and restricted stock awards, discussed below, to be a Level 3 measurement within the fair value hierarchy.

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 assets 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.

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

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

Income Taxes

For 2015, our annual estimated effective tax rate is forecasted to be a benefit of 28.7% , exclusive of discrete items. We expect to incur both a book and tax loss in year 2015. We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective tax rate to our year-to-date income, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs. For the quarter ended September 30, 2015, our overall effective tax rate on operations was different than the federal statutory rate of 35% due primarily to valuation allowances and state income tax apportionment. In forecasting the 2015 annual estimated effective tax rate, we believe that it should limit any tax benefit suggested by the tax effect of the forecasted book loss such that no net deferred tax asset is recorded in 2015. We reached this conclusion considering several factors such as: (i) projected future tax losses, (ii) the lack of carryback potential resulting in a tax refund, and (iii) in light of current commodity pricing uncertainty, there is insufficient external evidence to suggest that net tax attribute carryforwards are collectible beyond offsetting existing deferred tax liabilities inherent in our balance sheet (which are primarily related to derivative instruments). At this time, the estimated valuation allowance to be recorded in 2015 would be approximately $225,000 including $126,000 recorded as a discrete item associated with our federal and state net operating loss carryforwards for the year ended December 31, 2014.

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 $9,739 of expenses for cost reduction initiatives for the nine months ended September 30, 2015, are $ 6,524 , $347 and $596 recorded during the first, second and third quarters of 2015, respectively, for one-time severance and termination benefits in connection with our reduction in force that we began implementing 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 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. The FASB recently approved a delay which will make the updated guidance effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is not permitted. We are currently evaluating the effect the new standard will have on our financial statements and results of operations.

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

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

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. Adoption of this guidance will only affect the presentation of our consolidated balance sheets and will not have a material impact on our consolidated financial statements. The initial guidance released in April 2015 did not address presentation or subsequent measurement related to line-of-credit arrangements. Recent guidance issued in August 2015 clarifies the issue by allowing an entity to defer and present debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. As our current policy is consistent with the recent guidance, the update regarding debt issuance costs for line-of-credit arrangements will not impact our financial statements or results of operations.

In July 2015, the FASB issued authoritative guidance that amends and simplifies the ways businesses value inventory so that businesses that use the first-in, first-out (FIFO) or average cost method will measure inventory at the lower of its cost or net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. For public business entities, this guidance is effective for fiscal periods after December 15, 2016 and interim periods thereafter. We do not expect this guidance to materially impact our financial statements or results of operations.

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

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



	Nine months ended September 30,
	2015			2014
Net cash provided by operating activities included:
Cash payments for interest	$	77,437		$	74,446
Interest capitalized	(8,115		)	(9,957		)
Cash payments for interest, net of amounts capitalized	$	69,322		$	64,489
Cash payments for income taxes	$	639		$	591
Non-cash investing activities included:
Asset retirement obligation additions and revisions	$	3,637		$	7,118
Change in accrued oil and gas capital expenditures	$	(116,237	)	$	22,458

Note 3 : Acquisitions and divestitures

During the nine months ended September 30, 2015 we sold various non-core oil and gas properties for total proceeds of $26,868 . The properties sold include acreage in various counties in South-Central Oklahoma in the SCOOP play (“South-Central Oklahoma Oil Province”) and oil and gas properties in Osage County.

As these properties did not represent a material portion of our oil and natural gas reserves, individually or in the aggregate, we did not record any gain or loss on the sales and instead, reduced our full cost pool by the amount of the net proceeds without significant alteration to our depletion rate.

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

Note 4 : Long-term debt

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



	September 30, 2015		December 31, 2014
9.875% Senior Notes due 2020, net of discount of $4,382 and $4,861, respectively	$	295,618	$	295,139
8.25% Senior Notes due 2021	400,000		400,000
7.625% Senior Notes due 2022, including premium of $4,272 and $4,869, respectively	554,272		554,869
Senior secured revolving credit facility	394,000		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	10,315		10,705
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.85% to 5.95% , due October 2015 through February 2018; collateralized by automobiles, machinery and equipment	2,289		4,252
Capital lease obligations	20,045		21,837
	1,676,539		1,633,802
Less current maturities	4,619		5,377
	$	1,671,920	$	1,628,425

Senior Notes

The senior notes, which, as of September 30, 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 nine months ended September 30, 2015, we had additional net borrowings of $47,000 on our senior secured revolving credit facility. As of September 30, 2015 , the weighted average interest rate was 2.3% 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 a result of that semiannual redetermination, our borrowing base was decreased from $650,000 to $550,000 effective on April 1, 2015. Our semiannual borrowing base redetermination, which was effective on October 29, 2015, reaffirmed our borrowing base at $550,000 .

In connection with the Fifteenth Amendment, effective April 1, 2015, the Consolidated Net Debt to Consolidated EBITDAX covenant previously required by our senior secured revolving credit facility was 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

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

Debt, as revised in the amendment to now include both secured and unsecured debt. We incurred $1,404 in fees associated with the Fifteenth Amendment.

We believe we were in compliance with all covenants under our senior secured revolving credit facility as of September 30, 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 5 : Derivative instruments

Overview

Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil, 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, collars, put options, and basis protection swaps. We enter into crude oil derivative contracts to hedge a portion of our natural gas liquids production.

From time to time, we may enter into derivative contracts that are not costless but instead require payment of a premium such as purchased puts, collars and three-way collars. The cash premium can be paid at the time the contracts are initiated or deferred until the contracts settle. Payment of deferred premiums at the contract settlement date reduces the proceeds to be received upon settlement of the contracts. The fair value of our derivative contracts are reported net of any deferred premiums that are payable under the contracts.

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.

On a purchased put option, 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 collars.

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

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 September 30, 2015 :



		Weighted average fixed price per Bbl
Period and type of contract	Volume MBbls	Swaps		Sold puts		Purchased puts		Sold calls		Average deferred premium
2015
Swaps (1)	630	$	91.38	$	—	$	—	$	—	$	13.80
Collars (1)	130	$	—	$	—	$	47.50	$	57.50	$	1.71
Purchased puts (1)	695	$	—	$	—	$	43.05	$	—	$	2.96
2016
Three-way collars	240	$	—	$	84.00	$	92.00	$	101.01	$	—
Three-way collars (1)	480	$	—	$	40.00	$	52.50	$	72.50	$	2.95
Enhanced swaps (2)	3,720	$	92.94	$	80.52	$	—	$	—	$	—
Purchased puts (2)	3,720	$	—	$	—	$	60.00	$	—	$	—
2017
Three-way collars (1)	480	$	—	$	42.50	$	55.00	$	80.00	$	2.78

___________


(1)	These contracts include deferred premiums that are payable upon settlement.

(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 $48.70 for 2016 as of September 30, 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 September 30, 2015 :



Period and type of contract	Volume BBtu	Weighted average fixed price per MMBtu
2015
Natural gas swaps	3,940	$	4.24
Natural gas basis protection swaps	3,600	$	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

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

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 for the nine months ended September 30, 2015 .

Prior to July 2015, our derivative portfolio included certain outstanding swaps, scheduled to mature between September and December 2015, covering 1,100,000 barrels of production. Net of deferred premiums of $12,424 , the effective hedged price provided by these swaps was $82.34 per barrel. During the third quarter of 2015, we entered into offset positions on these swaps thereby locking in proceeds based on the difference between the contract price of the initial swaps and the contract price of the offset swaps, which we will receive as the contracts settle. Based on the September through December 2015 average NYMEX strip price of $45.70 per barrel at September 30, 2015, the average realized price, inclusive of the net locked-in proceeds for the 1,100,000 barrels of production, would be $82.68 per barrel. Any difference between settlement prices at contract maturity and the preceding average NYMEX price of $45.70 per barrel would result in a dollar for dollar impact on the realized price we receive. At September 30, 2015, 275,000 barrels of the locked-in swaps had matured for which net proceeds of $10,196 are to be received. Based on the October through December 2015 average NYMEX strip price of $45.77 , at September 30, 2015, the average realized price, inclusive of the net locked-in proceeds for the remaining 825,000 barrels of production, will yield an effective price of $82.72 . The 825,000 barrels of remaining locked-in swaps are not reflected in the derivatives outstanding table above as the anticipated proceeds no longer vary according to changes in crude oil pricing. However, the anticipated proceeds from the remaining locked-in swaps are reflected in the derivative asset and liability values disclosed in the table 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 6 — Fair value measurements for additional information regarding fair value measurements. The estimated fair values of derivative instruments are provided below. The carrying amounts of these instruments are equal to the estimated fair values.



	As of September 30, 2015								As of December 31, 2014
	Assets		Liabilities			Net value			Assets		Liabilities			Net value
Natural gas swaps	$	39,554	$	—		$	39,554		$	32,939	$	—		$	32,939
Oil swaps	9,386		(1,810		)	7,576			23,465		—			23,465
Oil collars (2)	3,483		—			3,483			1,175		—			1,175
Oil enhanced swaps	60,755		—			60,755			100,724		—			100,724
Oil purchased and sold puts	74,386		(924		)	73,462			93,268		—			93,268
Natural gas basis differential swaps	—		(1,159		)	(1,159		)	292		(309		)	(17		)
Total derivative instruments	187,564		(3,893		)	183,671			251,863		(309		)	251,554
Less:
Netting adjustments (1)	3,854		(3,854		)	—			232		(232		)	—
Current portion asset (liability)	142,944		(39		)	142,905			179,921		(77		)	179,844
	$	40,766	$	—		$	40,766		$	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.

(2) Includes collars and 3-way collars.

Derivative settlements outstanding at September 30, 2015 and December 31, 2014 were as follows:



	September 30, 2015		December 31, 2014
Derivative settlements receivable included in accounts receivable	$	37,388	$	19,678

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

Effect of derivative instruments on the consolidated statements of operations

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



	Three months ended						Nine months ended
	September 30,						September 30,
	2015			2014			2015			2014
Change in fair value of commodity price swaps	$	6,583		$	20,039		$	(9,274	)	$	16,794
Change in fair value of collars	1,803			6,870			2,307			106
Change in fair value of enhanced swaps and put options	23,590			80,551			(59,775		)	27,521
Change in fair value of natural gas basis differential contracts	(1,035		)	9			(1,141		)	(2,165		)
Receipts from (payments on) settlement of commodity price swaps	12,829			(1,030		)	43,806			(12,653		)
Receipts from (payments on) settlement of collars	42			(77		)	42			(1,338		)
Receipts from (payments on) settlement of enhanced swaps and put options	41,667			(1,664		)	129,245			(10,657		)
(Payments on) receipts from settlement of natural gas basis differential contracts	(64		)	(285		)	56			(390		)
	$	85,415		$	104,413		$	105,266		$	17,218

Note 6 : Fair value measurements

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

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


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


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


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

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

Recurring fair value measurements

Our financial instruments recorded at fair value on a recurring basis consist of commodity derivative contracts (see Note 5 — Derivative instruments ). We have no Level 1 assets or liabilities as of September 30, 2015 or December 31, 2014 . Our derivative contracts classified as Level 2 as of September 30, 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.

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

As of September 30, 2015 and December 31, 2014 , our derivative contracts classified as Level 3 consisted of collars, 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 September 30, 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)	$	48,940		$	(2,969	)	$	45,971	$	56,696		$	(309	)	$	56,387
Significant unobservable inputs (Level 3)	138,624			(924		)	137,700		195,167			—			195,167
Netting adjustments (1)	(3,854		)	3,854			—		(232		)	232			—
	$	183,710		$	(39	)	$	183,671	$	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 nine months ended September 30, 2015 and 2014 were:



	Nine months ended September 30,
Net derivative assets (liabilities)	2015			2014
Beginning balance	$	195,167		$	3,622
Realized and unrealized gains (losses) included in non-hedge derivative gains (losses)	4,660			15,632
Purchases	—			1,220
Settlements (received) paid	(62,127		)	11,995
Ending balance	$	137,700		$	32,469
Losses relating to instruments still held at the reporting date included in non-hedge derivative gains (losses) for the period	$	45,835		$	24,156

Nonrecurring fair value measurements

Asset retirement obligations. Additions to the asset and liability associated with our asset retirement obligations are measured at fair value on a nonrecurring basis. Our asset retirement obligations consist of the estimated present value of future costs to plug and abandon or otherwise dispose of our oil and natural gas properties and related facilities. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, inflation rates, discount rates, and well life, all of which are Level 3 inputs according to the fair value hierarchy. The estimated future costs to dispose of properties added during the first nine months of 2015 and 2014 were escalated using an annual inflation rate of 2.91% and 2.95% , respectively, and discounted using our weighted average credit-adjusted risk-free interest rate of 13.45% and 6.60% , respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. See Note 7 — Asset retirement obligations for additional information regarding our asset retirement obligations.

Impairment of long-lived assets. As discussed in Note 1 — Nature of operations and summary of significant accounting policies , we recorded an impairment on four of our stacked drilling rigs during the second quarter of 2015. The estimated fair value related to the impairment assessment for our four drilling rigs no longer in service was primarily based on internal and external estimates and, therefore, is classified within Level 3 of the fair value hierarchy.

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

Fair value of other financial instruments

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

The carrying value and estimated fair value of our long-term debt at September 30, 2015 and December 31, 2014 were as follows:



	September 30, 2015				December 31, 2014
Level 2	Carrying value		Estimated fair value		Carrying value		Estimated fair value
9.875% Senior Notes due 2020	$	295,618	$	97,500	$	295,139	$	269,091
8.25% Senior Notes due 2021	400,000		122,000		400,000		270,000
7.625% Senior Notes due 2022	554,272		154,000		554,869		379,775
Senior secured revolving credit facility	394,000		394,000		347,000		347,000
Other secured long-term debt	12,604		12,604		14,957		14,957
	$	1,656,494	$	780,104	$	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 September 30, 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.

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

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



	Offset in the consolidated balance sheets									Gross amounts not offset in the consolidated balance sheets
	Gross assets (liabilities)			Offsetting assets (liabilities)			Net assets (liabilities)			Derivatives(1)		Amounts outstanding under senior secured revolving credit facility			Net amount
As of September 30, 2015
Derivative assets	$	187,564		$	(3,854	)	$	183,710		$	—	$	(114,282	)	$	69,428
Derivative liabilities	(3,893		)	3,854			(39		)	—		—			(39		)
	$	183,671		$	—		$	183,671		$	—	$	(114,282	)	$	69,389
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 $3,893 at September 30, 2015 .

Note 7 : Asset retirement obligations

The following table provides a summary of our asset retirement obligation activity during the nine months ended September 30, 2015 and 2014 .



	Nine months ended September 30,
	2015			2014
Beginning balance	$	47,424		$	55,179
Liabilities incurred in current period	1,852			4,844
Liabilities settled and disposed in current period	(4,886		)	(16,807		)
Revisions in estimated cash flows	1,785			2,274
Accretion expense	2,727			2,991
Ending balance	48,902			48,481
Less current portion included in accounts payable and accrued liabilities	2,384			4,997
	$	46,518		$	43,484

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

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

Note 8 : Stock-based compensation

Phantom Stock Plan and Restricted Stock Unit Plan

Effective January 1, 2004 , we implemented a Phantom Unit Plan, which was revised on December 31, 2008 as the Second Amended and Restated Phantom Stock Plan (the “Phantom Plan”), to provide deferred compensation to certain key employees (the “Participants”). Under the Phantom Plan, awards vest at the end of five years, but may also vest on a pro-rata basis following a Participant’s termination of employment with us due to death, disability, retirement or termination by us without cause. Also, phantom stock will vest if a change of control event occurs. Phantom shares are cash-settled within 120 days of the vesting date.

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

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

A summary of our phantom stock and RSU activity during the nine months ended September 30, 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	$	—	—				$	14.88	59,571
Vested	$	24.48	(6,456	)	$	25	$	10.73	(216,941	)	$	857
Forfeited	$	18.34	(6,032	)			$	9.62	(133,132	)
Unvested and outstanding at September 30, 2015	$	18.61	10,691				$	10.48	278,658

Due to the severe decline in commodity pricing, which has resulted in a steep decline in our estimated proved reserves, the estimated fair value per phantom share and RSU as of September 30, 2015 is $0.00 . The weighted average period until all remaining phantom shares and RSUs vest is 1.3 years .

2015 Cash Incentive Plan

We adopted the Long-Term Cash Incentive Plan (The “2015 Cash LTIP”) on August 7, 2015. The 2015 Cash LTIP provides additional cash compensation to certain employees of the Company in the form of awards that generally vest in equal annual increments over a four -year period. Since the awards do not vary according to the value of the Company’s equity, the awards are not considered “stock-based compensation” under accounting guidance. We awarded $3,297 of cash incentive awards in September 2015.

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).

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

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 nine months ended September 30, 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				$	113.90	599
Vested	$	778.81	(8,325	)	$	4,444	$	—	—
Forfeited	$	774.21	(3,997	)			$	323.53	(11,094	)
Unvested and outstanding at September 30, 2015	$	792.78	14,122				$	278.97	28,448

During the nine months ended September 30, 2015 and 2014 , we repurchased and canceled 5,678 and 1,810 vested shares respectively, 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 $373.10 per Time Vested restricted share, the aggregate intrinsic value of the unvested Time Vested restricted shares outstanding was $5,269 as of September 30, 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						Nine months ended
	September 30,						September 30,
	2015			2014			2015			2014
Stock-based compensation cost	$	(581	)	$	2,309		$	(143	)	$	9,026
Less: stock-based compensation cost capitalized	(49		)	(289		)	(352		)	(2,735		)
Stock-based compensation expense	$	(630	)	$	2,020		$	(495	)	$	6,291
Payments for stock-based compensation	$	333		$	699		$	3,977		$	2,787

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

Our stock-based compensation expense for the nine months ended September 30, 2015 includes a credit recorded in the first quarter due to forfeitures resulting from our workforce reduction in February 2015 and a credit recorded during the third quarter due to lower valuations of our liability-based awards. As of September 30, 2015 and December 31, 2014 , accrued payroll and benefits payable included $1,384 and $4,830 , respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized compensation cost of approximately $7,134 is expected to be recognized over a weighted average period of 1.8 years .

Note 9 : 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 September 30, 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 nine months ended September 30, 2015 or 2014 .

Litigation 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. The plaintiffs filed their motion for class certification on Tuesday, October 13, 2015. The plaintiffs also moved for partial summary judgment, asking the court to determine, as a matter of law, that natural gas is not marketable until it is in a condition and location to be transported in an interstate pipeline and other dispositive issues. The Company is preparing its response to both motions. 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 Plaintiff’s 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 our 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 Plaintiff’s 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

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

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. We are not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the Donelson Case will have on our 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 properties and agreements involved, and the ultimate potential outcome of the matter. We dispute plaintiffs’ claims, dispute that the Donelson 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 CO ₂ 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 CO ₂ , drilling rig services, pipe and equipment. In September 2015, we entered into an interim financing agreement with U.S. Bank for an additional CO ₂ recycle compressor for our EOR facilities. If we do not enter into a lease once the compressor has been manufactured, we will owe U.S. Bank most of the cost incurred by U.S. Bank for the compressor. Other than additional debt borrowings during the nine months ended September 30, 2015 , and our obligation under the interim financing agreement discussed above, 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 and headquartered in Oklahoma City, we are a pure play Mid-Continent independent oil and natural gas exploration and production company. We have capitalized on our sustained success in the Mid-Continent area in recent years by expanding our holdings to become a leading player in the liquids-rich Mississippi Lime and STACK, which is home to multiple oil-rich reservoirs including the Oswego, Meramec, Osage, Woodford and Hunton formations. We are also the nation’s third-largest carbon dioxide enhanced oil recovery (“EOR”) producer based on number of active projects. This position is underscored by our activity in our world-class North Burbank Unit in Osage County, Oklahoma, which is the largest oil recovery unit in the state.

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas and on our ability to find, develop and acquire oil and natural gas reserves that are economically recoverable. The preparation of our financial statements in conformity with generally accepted accounting principles (“GAAP”) requires us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved oil and natural gas reserves. We use the full cost method of accounting for our oil and natural gas activities.

Generally, our producing properties have declining production rates. Our reserve estimates as of December 31, 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.

Business and Industry Outlook

Crude oil prices decreased significantly in the latter part of 2014 and have remained low 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, ongoing since November 2014, 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 which to date has encompassed 200 employees, of which 131 were located in the Oklahoma City headquarters office and 69 were located at various field offices. In connection with our workforce reduction, we recorded charges of $6.5 million , $0.3 million and $ 0.6 million during the first, second and third quarters of 2015, respectively, related to one-time severance and termination benefits.

Given the depressed commodity price environment, we have aggressively pursued price concessions from third-party service vendors. We have achieved a target of $2.5 million to $3.0 million in drilling and completion costs per well as a result of cost reductions from service providers and improved operational efficiencies. In a further effort to fully capture gains associated with improved vendor price concessions, we delayed many of our completions of newly drilled wells into the second

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half of the year. Specifically, out of 20 wells drilled and rig-released during the first half of the year, three wells were completed in the first quarter, eight wells in the third quarter and seven wells are expected to be completed in the fourth quarter. We drilled an additional four wells during the third quarter with three completed in October 2015 and the remaining well is expected to be completed during the fourth quarter.

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 during the first quarter of 2015 and nil during the second and third quarter. 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 compared to the amount spent in 2014. We reduced our operated rig count from 10 operated rigs at December 31, 2014 to one rig as of April 7, 2015 and continuing currently. 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. We have budgeted the addition of a second rig in November and a third rig in December of 2015 and therefore plan to exit the year with three rigs operating. Approximately 85% - 90% of our planned 2015 non-acquisition related capital investments in our E&P Areas will be focused on the high-return STACK and Mississippian Lime plays.

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, followed by a partial pay-down of our borrowings in the second and third quarter. We expect to make further pay-downs on our senior secured credit facility during the fourth quarter of the year. We will continue to monitor our capital spending closely based on actual and projected cash flows and evaluate our liquidity and capital requirements accordingly.

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 gas of the first day of each month for the 12-month period through September 30, 2015 were $59.21 per Bbl and $3.06 per MMBtu, respectively. As a result of the decline in average prices, we recorded a ceiling test write-down of $955.3 million during the nine months ended September 30, 2015, of which $737.8 million was recorded during the third quarter and the remainder of which was recorded in the second quarter. Since the prices used in the cost ceiling are based on a trailing 12-month period, the full impact of a sudden price decline is not recognized immediately. As prices decline, the economic performance of certain properties in the reserve estimate may deteriorate to the point that they are removed from the proved reserve category, thus reducing the quantity and value of proved reserves. The use of a 12-month average will tend to spread the impact of the price change on the financial statements over several reporting periods. While the amount of any future impairment is generally difficult to predict, if commodity prices remain at the current level, the average prices used in the ceiling test calculation will decline further resulting in a further write-down in the fourth quarter of 2015, which we expect to be in the range of $400 million to $450 million. 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 third quarter of 2015 , production decreased 11% to 2,452 MBoe compared to production of 2,767 MBoe during the third quarter of 2014 , primarily due to the natural decline of certain wells, our decreased drilling activity, the temporary shut-in of marginal wells and our deferral of completions on wells that were drilled in the first half of the year. Revenue from commodity sales was $104.9 million lower in the third quarter of 2015 compared to the third quarter in 2014 , primarily as a result of the 53% decrease in average realized prices. During the third quarter of 2015 , we recorded a ceiling test impairment of oil and gas properties of $737.8 million which brings our total ceiling test write-down for the year to $955.3 million . The impairments are a result of the substantial decline in 12-month average commodity prices. Additionally, we had a non-hedge derivative gain of $85.4 million in the third quarter of 2015 compared to a $104.4 million non-hedge derivative gain during the same period last year. As a result of these and other factors, we reported a net loss of $647.1 million during the third quarter of 2015 compared to net income of $83.5 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 expected to range from $175.0 million to $225.0 million . Our capital expenditures during the nine months ended September 30, 2015 were $151.9 million , consisting primarily of $82.8 million in drilling and completion expenditures in our E&P Areas, $42.1 million for our EOR Project Areas and $17.7 million for the acquisition of oil and natural gas properties and leasehold.

•

Senior secured revolving credit facility and liquidity. We 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 4 — Long-term debt ” in Item 1. Financial Statements and Supplementary Data of this report. Our semi-annual redetermination effective October 29, 2015, kept the borrowing base at the same level.

•

Proved property impairments . Due to the substantial decline of commodity prices in late 2014, which remained low through September 30, 2015, the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties as of September 30, 2015 , resulting in a ceiling test write-down during the second quarter of $737.8 million as further discussed in “Results of operations” and “Note 1 — Nature of operations and summary of significant accounting policies ” 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		Nine months ended		Percent change
	September 30,				September 30,
	2015	2014			2015	2014
E&P Areas
Mississippi Lime	501	447	12.1	%	1,688	1,359	24.2	%
STACK	360	381	(5.5	)%	1,169	899	30.0	%
Panhandle Marmaton	122	331	(63.1	)%	497	724	(31.4	)%
Legacy Production Areas	612	775	(21.0	)%	1,917	2,886	(33.6	)%
Total E&P Areas	1,595	1,934	(17.5	)%	5,271	5,868	(10.2	)%
EOR Project Areas
Active EOR Projects	562	502	12.0	%	1,669	1,350	23.6	%
Potential EOR Projects	295	331	(10.9	)%	918	999	(8.1	)%
Total EOR Project Areas	857	833	2.9	%	2,587	2,349	10.1	%
Total	2,452	2,767	(11.4	)%	7,858	8,217	(4.4	)%

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E&P Areas

We have recently realigned the plays within our E&P areas to better highlight those areas where we are focusing our operations and where our current and future capital will be spent. E&P Areas include the following plays: the STACK, Mississippi Lime, Panhandle Marmaton and Legacy Production Areas. During the nine months ended September 30, 2015, capital expenditures on drilling in the Mississippi Lime and STACK plays accounted for 89% of our capital expenditures for drilling in our E&P Areas.

STACK Play - The STACK is an acronym for Sooner Trend Anadarko Canadian Kingfisher which is indicative of a play area in the Anadarko Basin of Oklahoma in which we operate. It is a horizontal drilling play in an area of previously drilled vertical wells with multiple productive reservoirs. It encompasses all or parts of Blaine, Canadian, Garfield, Kingfisher and Major counties in Oklahoma. The STACK’s borders include the Nemaha Ridge (East), the Chester outcrop (North), and deep gas bearing characteristics (South and West). This thick column (500’+) includes multiple, stacked, and productive reservoirs, each with high oil saturations (30-50%) and include the Hunton, Woodford, Osage, Meramec, Oswego, and other intervals within the STACK area. The organic-rich Woodford Shale is the primary source of hydrocarbon migration into and present in the target reservoirs, which act as natural conduits for the oil migration from the Woodford. These complex carbonate-silt-shale stratigraphic intervals have proven to be very conducive to horizontal drilling and completion techniques. We own approximately 100,000 net surface acres and have approximately 4,200 drilling locations in this play.

Mississippi Lime Play - Various Counties, Oklahoma. The Mississippi Lime, located in South-Central Kansas and North-Central Oklahoma, is a shallow carbonate play (mostly Limestone) with depths ranging from 3,000 feet to 6,000 feet. The Mississippian Lime is not a new play, but is now a horizontal development among and bordering on legacy vertical producing fields. This area has a long history of production from vertical wells and a well-developed infrastructure system to support further development. Several companies in the industry are devoting large amounts of capital toward horizontal drilling activities in further developing this shallow, cost-effective resource play. Our operations in the Mississippian Lime are focused in the northwest region of Oklahoma and consist of 48,500 net acres and 575 gross drilling locations.

Panhandle Marmaton Play - Texas and Oklahoma Panhandles. Our Panhandle Marmaton play development program began in 2012. Our leasehold position provides for horizontal drilling opportunities targeting the Marmaton lime, which consists of numerous productive carbonate benches. The multi-stage fracture stimulation jobs performed in the play have increased its productivity considerably. We currently own 89,000 net acres in this play. In addition, we own extensive infrastructure in this play, including saltwater disposal wells and electrical grids.

Legacy Production Areas - Our Legacy Production Areas primarily include mature properties with low production decline curves. These Areas also include our Ark-La-Tex, Permian Basin, and North Texas properties which we divested in 2014. The production volumes from the divested properties are reflected in production volumes for the prior year period. The remaining properties are located in and hold leasehold acreage for future exploration in our existing repeatable resource plays which include our Cleveland Sand and Granite Wash plays .

Production in our E&P Areas decreased for both the three and nine months ended September 30, 2015 compared to the same periods in 2014. The quarter-over-quarter decrease in production is primarily due to the natural decline of our wells, the temporary shut-in of marginal wells due to the current pricing environment and the decrease in our drilling activity. Also contributing to the decrease in production was our strategic delay in completing wells drilled in the first half of 2015 into the second half of the year in order to avail ourselves of cost savings from third-party price concessions as well as in anticipation of potentially improved pricing. The natural production decline was most pronounced in our Panhandle Marmaton and Legacy Production Areas for which we did not allocate significant drilling capital in the current year. Production in the STACK play was relatively flat as the natural decline of wells was only partially offset by current year drilling and development due to aforementioned strategic delays in completions of eight wells drilled in 2015. Our Mississippi Lime play had increased production in the current quarter over the prior year quarter as a result of our continued drilling and development activities in this play.

The year-over-year decrease in our E&P Areas is primarily due to our significant strategic divestitures in 2014 along with reduced capital spending and temporary shut-in of marginal wells due to the current pricing environment. These decreases were offset partially by the increased production due to our drilling and development activities in our STACK and Mississippi Lime plays.

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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 September 30, 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 and nine months ended September 30, 2015 compared to the same periods in 2014 were primarily due to production response in our North Burbank Unit and in our Farnsworth Unit. Production decreases in our Potential EOR Projects were due to natural decline and the temporary shut-in of marginal wells due to the current pricing environment.

On August 25, 2015, our pipeline carrying CO ₂ from our compressor station in Coffeyville, Kansas, to our North Burbank Unit developed a pinhole leak, releasing approximately 28 barrels of liquid CO ₂ which subsequently evaporated into the atmosphere. The leak was repaired within 36 hours. No injuries resulted from the leak, and the only property damage was to the pipe itself and the surface which was disturbed to access the pipe for repair. We promptly notified the National Response Center of the incident. On August 28, 2015, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a Corrective Action Order, requiring us to shut in the pipeline pending investigation of the cause of the leak. Our investigation revealed that the leak was caused by external corrosion in an area where the external coating of the pipe was damaged during installation. This was exacerbated by an electric current imbalance associated with cathodic protection systems that is typically easy to rectify. All affected areas of the pipeline were dug up and repaired and the line pressure tested to above normal operating conditions. Our Restart Plan was approved by PHMSA on September 18, 2015, and we have received approval and begun to re-establish CO ₂ delivery through the pipeline. Although no new CO ₂ was being delivered to the North Burbank Unit for over two months due to the pipeline shutdown, we continued to produce the unit with injection of recycled CO ₂ and water. We do not expect the required testing and repairs to have a material effect on our financial condition, results of operations or cash flows. We currently expect production levels at the North Burbank Unit at the end of 2015 to be approximately in the range of 2,900 to 3200 gross Boe/day.

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 production and commodity sales before the effects of commodity derivative settlements:



	Three months ended				Increase / (Decrease)			Percent change		Nine months ended				Increase / (Decrease)			Percent change
	September 30,									September 30,
	2015		2014							2015		2014
Commodity sales (in thousands)
Oil	$	58,353	$	146,320	$	(87,967	)	(60.1	)%	$	206,948	$	434,714	$	(227,766	)	(52.4	)%
Natural gas	11,402		18,949		(7,547		)	(39.8	)%	36,534		68,881		(32,347		)	(47.0	)%
Natural gas liquids	4,757		14,114		(9,357		)	(66.3	)%	18,319		42,103		(23,784		)	(56.5	)%
Total commodity sales	$	74,512	$	179,383	$	(104,871	)	(58.5	)%	$	261,801	$	545,698	$	(283,897	)	(52.0	)%
Production
Oil (MBbls)	1,328		1,528		(200		)	(13.1	)%	4,283		4,471		(188		)	(4.2	)%
Natural gas (MMcf)	4,624		4,986		(362		)	(7.3	)%	14,386		15,781		(1,395		)	(8.8	)%
Natural gas liquids (MBbls)	353		408		(55		)	(13.5	)%	1,177		1,116		61			5.5	%
MBoe	2,452		2,767		(315		)	(11.4	)%	7,858		8,217		(359		)	(4.4	)%
Average daily production (Boe/d)	26,652		30,076		(3,424		)	(11.4	)%	28,784		30,099		(1,315		)	(4.4	)%
Average sales prices (excluding derivative settlements)
Oil per Bbl	$	43.94	$	95.76	$	(51.82	)	(54.1	)%	$	48.32	$	97.23	$	(48.91	)	(50.3	)%
Natural gas per Mcf	$	2.47	$	3.80	$	(1.33	)	(35.0	)%	$	2.54	$	4.36	$	(1.82	)	(41.7	)%
NGLs per Bbl	$	13.48	$	34.59	$	(21.11	)	(61.0	)%	$	15.56	$	37.73	$	(22.17	)	(58.8	)%
Average sales price per Boe	$	30.39	$	64.83	$	(34.44	)	(53.1	)%	$	33.32	$	66.41	$	(33.09	)	(49.8	)%

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Our total commodity sales decreased significantly during the three months ended September 30, 2015 compared to the three months ended September 30, 2014 as a result of a decrease in the average price per Boe combined with a decrease in production volumes sold. Our total commodity sales decreased significantly during the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014 as a result of a decrease in the average price per Boe combined with a slight decrease in production volumes sold. Changes in our production compared to the prior year is discussed in the preceding section above while the impact of price and production volume changes on our commodity sales is disclosed in the table below.

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



	Three months ended September 30,					Nine months ended September 30,
	2015 vs. 2014					2015 vs. 2014
(in thousands)	Sales change			Percentage change in sales		Sales change			Percentage change in sales
Change in oil sales due to:
Prices	$	(68,815	)	(47.0	)%	$	(209,487	)	(48.2	)%
Production	(19,152		)	(13.1	)%	(18,279		)	(4.2	)%
Total change in oil sales	$	(87,967	)	(60.1	)%	$	(227,766	)	(52.4	)%
Change in natural gas sales due to:
Prices	$	(6,171	)	(32.5	)%	$	(26,258	)	(38.2	)%
Production	(1,376		)	(7.3	)%	(6,089		)	(8.8	)%
Total change in natural gas sales	$	(7,547	)	(39.8	)%	$	(32,347	)	(47.0	)%
Change in natural gas liquids sales due to:
Prices	$	(7,454	)	(52.8	)%	$	(26,085	)	(62.0	)%
Production	(1,903		)	(13.5	)%	2,301			5.5	%
Total change in natural gas liquids sales	$	(9,357	)	(66.3	)%	$	(23,784	)	(56.5	)%

Derivative activities

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

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

Our realized prices are impacted by realized gains and losses resulting from commodity derivatives contracts. The following table presents information about the effects of derivative settlements on realized prices:



	Three months ended						Nine months ended
	September 30,						September 30,
	2015			2014			2015			2014
Oil (per Bbl)(1):
Before derivative settlements	$	37.54		$	82.87		$	41.26		$	85.34
After derivative settlements (2)	$	66.72		$	81.66		$	66.85		$	82.51
Post-settlement to pre-settlement price	177.7		%	98.5		%	162.0		%	96.7		%
Natural gas (per Mcf):
Before derivative settlements	$	2.47		$	3.80		$	2.54		$	4.36
After derivative settlements (2)	$	3.64		$	3.66		$	3.79		$	3.78
Post-settlement to pre-settlement price	147.4		%	96.3		%	149.2		%	86.7		%


(1)	Includes natural gas liquids.


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

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



(in thousands)	September 30, 2015			December 31, 2014
Derivative assets (liabilities):
Natural gas swaps	$	39,554		$	32,939
Oil swaps	7,576			23,465
Oil collars	3,483			1,175
Oil enhanced swaps	60,755			100,724
Oil purchased puts	73,462			93,268
Natural gas basis differential swaps	(1,159		)	(17		)
Net derivative assets	$	183,671		$	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 September 30,
	2015									2014
(in thousands)	Non-cash fair value adjustment			Cash receipts (payments)			Total gain (loss)			Non-cash fair value adjustment		Cash receipts (payments)			Total gain (loss)

Non-hedge derivative gains (losses):
Oil swaps, collars, enhanced swaps and puts	$	22,728		$	49,040		$	71,768		$	97,125	$	(2,343	)	$	94,782
Natural gas swaps	9,248			5,498			14,746			10,335		(428		)	9,907
Natural gas basis differential contracts	(1,035		)	(64		)	(1,099		)	9		(285		)	(276		)
Non-hedge derivative (losses) gains	$	30,941		$	54,474		$	85,415		$	107,469	$	(3,056	)	$	104,413



	Nine months ended September 30,
	2015								2014
(in thousands)	Non-cash fair value adjustment			Cash receipts (payments)		Total gain (loss)			Non-cash fair value adjustment			Cash receipts (payments)			Total gain (loss)

Non-hedge derivative gains (losses):
Oil swaps, collars, enhanced swaps and puts	$	(73,357	)	$	149,871	$	76,514		$	35,793		$	(15,842	)	$	19,951
Natural gas swaps	6,615			23,222		29,837			8,628			(8,806		)	(178		)
Natural gas basis differential contracts	(1,141		)	56		(1,085		)	(2,165		)	(390		)	(2,555		)
Non-hedge derivative (losses) gains	$	(67,883	)	$	173,149	$	105,266		$	42,256		$	(25,038	)	$	17,218

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. 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.

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.

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D uring the third quarter of 2015, we entered into offset positions on 1,100,000 barrels of outstanding swaps, scheduled to mature between September to December 2015, thereby locking-in the difference between the contract price of our prior swaps and the contract price of the offset swaps, which we will receive when the contracts settle. Please see Item 3. Quantitative and Qualitative Disclosures about Market Risk of this report for a further discussion of these transactions.

Lease operating expenses



	Three months ended September 30,				Increase / (Decrease)			Percent change		Nine months ended September 30,				Increase / (Decrease)			Percent change
	2015		2014		Increase / (Decrease)			Percent change		2015		2014		Increase / (Decrease)			Percent change
Lease operating expenses (in thousands, except per Boe data)
E&P Areas	$	10,461	$	19,365	$	(8,904	)	(46.0	)%	$	37,297	$	55,193	$	(17,896	)	(32.4	)%
EOR Project Areas	$	14,420	$	19,550	$	(5,130	)	(26.2	)%	$	46,624	$	52,457	$	(5,833	)	(11.1	)%
Total lease operating expense	$	24,881	$	38,915	$	(14,034	)	(36.1	)%	$	83,921	$	107,650	$	(23,729	)	(22.0	)%
Lease operating expenses per Boe
E&P Areas	$	6.56	$	10.01	$	(3.45	)	(34.5	)%	$	7.08	$	9.41	$	(2.33	)	(24.8	)%
EOR Project Areas	$	16.83	$	23.47	$	(6.64	)	(28.3	)%	$	18.02	$	22.33	$	(4.31	)	(19.3	)%
Lease operating expenses per Boe	$	10.15	$	14.06	$	(3.91	)	(27.8	)%	$	10.68	$	13.10	$	(2.42	)	(18.5	)%

Lease operating costs are sensitive to changes in demand for field equipment, services, and qualified operational personnel, which is driven by demand for oil and natural gas. However, the timing of changes in operating costs may lag behind changes in commodity prices. Our EOR projects are more expensive to operate than traditional industry operations due to the nature of operations along with the costs of recovery and recycling of CO ₂ .

Our E&P Areas lease operating expenses on an absolute dollar basis and a per Boe basis decreased during the three months and nine months ended September 30, 2015 compared to the three and nine months ended September 30, 2014 , primarily as a result of cost reductions from third party service providers and improved operational efficiencies which included temporary shut-in of marginal wells due to the current low price environment. Lower production volumes during the current year period also contributed to the decrease in expense. During 2014, we divested certain non-core assets with higher operating costs. These divestitures were largely completed by mid-July 2014, and have therefore contributed to a decrease in lease operating expense when comparing the nine months ended September 30, 2015 , to the prior year period.

Our EOR Project Areas lease operating expenses decreased during the three and nine months ended September 30, 2015 compared to the three and nine months ended September 30, 2014 , primarily as a result of cost reductions from third party service providers and improved operational efficiencies which included temporary shut-in of marginal wells due to the current low price environment. The savings were offset partially by additional costs associated with expansion of our EOR floods at our North Burbank and Farnsworth units during the last twelve months. Our EOR Project Areas lease operating expenses on a per Boe basis decreased, primarily as a result of these factors combined with the overall increase in production volumes between periods.

Transportation and processing expenses



	Three months ended September 30,				Increase / (Decrease)			Percent change		Nine months ended September 30,				Increase / (Decrease)		Percent change
	2015		2014		Increase / (Decrease)			Percent change		2015		2014		Increase / (Decrease)		Percent change
Transportation and processing expenses (in thousands)	$	1,902	$	3,162	$	(1,260	)	(39.8	)%	$	6,246	$	6,012	$	234	3.9	%
Transportation and processing expenses per Boe	$	0.78	$	1.14	$	(0.36	)	(31.6	)%	$	0.79	$	0.73	$	0.06	8.2	%

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Transportation and processing expenses principally consist of expenditures to prepare and transport production from the wellhead to a specified sales point and processing costs of gas into natural gas liquids. Our transportation and processing expenses decreased during the three months ended September 30, 2015 compared to the prior year quarter as a result of an overall decrease in natural gas liquids volumes processed due to the natural decline in gas production that was partially offset by production from new wells. Included in the decrease in natural gas liquids processed was a steep decline in production from certain non-operated wells that came online in mid-2014 that had substantially higher per unit processing costs. Transportation and processing expenses increased during the nine months ended September 30, 2015 compared to the prior year period primarily due to the overall increase natural gas liquids processed.

Production taxes (which include ad valorem taxes)



	Three months ended September 30,				Increase / (Decrease)			Percent change		Nine months ended September 30,				Increase / (Decrease)			Percent change
	2015		2014		Increase / (Decrease)			Percent change		2015		2014		Increase / (Decrease)			Percent change
Production taxes (in thousands)	$	2,795	$	7,133	$	(4,338	)	(60.8	)%	$	11,123	$	21,935	$	(10,812	)	(49.3	)%
Production taxes per Boe	$	1.14	$	2.58	$	(1.44	)	(55.8	)%	$	1.42	$	2.67	$	(1.25	)	(46.8	)%

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. Prior to July 1, 2015, new wells in Oklahoma previously qualified for a tax incentive and were taxed at a lower rate of 1% during their initial 48 months of production. As of July 1, 2015, the tax incentive rate for new wells has increased to 2% for the initial 36 months of production, although we have yet to see a substantial impact to date due to our reduced drilling activity. After the incentive period expires, the tax rate reverts to the statutory rate.

Our production taxes decreased during the three and nine months ended September 30, 2015 compared to the three and nine months ended September 30, 2014 primarily due to our significant decline in revenues as a result of depressed commodity prices in the current year. 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.

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



	Three months ended September 30,				Increase / (Decrease)			Percent change		Nine months ended September 30,				Increase / (Decrease)			Percent change
	2015		2014		Increase / (Decrease)			Percent change		2015		2014		Increase / (Decrease)			Percent change
DD&A (in thousands):
Oil and natural gas properties	$	49,522	$	58,035	$	(8,513	)	(14.7	)%	$	164,694	$	170,023	$	(5,329	)	(3.1	)%
Property and equipment	1,580		2,564		(984		)	(38.4	)%	6,273		7,617		(1,344		)	(17.6	)%
Accretion of asset retirement obligation	925		928		(3		)	(0.3	)%	2,727		2,991		(264		)	(8.8	)%
Total DD&A	$	52,027	$	61,527	$	(9,500	)	(15.4	)%	$	173,694	$	180,631	$	(6,937	)	(3.8	)%
DD&A per Boe:
Oil and natural gas properties	$	20.20	$	20.97	$	(0.77	)	(3.7	)%	$	20.96	$	20.69	$	0.27		1.3	%
Other fixed assets	$	1.02	$	1.26	$	(0.24	)	(19.0	)%	$	1.15	$	1.29	$	(0.14	)	(10.9	)%
Total DD&A per Boe	$	21.22	$	22.23	$	(1.01	)	(4.5	)%	$	22.11	$	21.98	$	0.13		0.6	%

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. As discussed below, the ceiling test write-downs we recorded during the second and third quarter have substantially lowered the carrying amount of our full cost amortization base. With a lower full cost amortization base, we expect the DD&A rate in the fourth quarter to be lower than the DD&A rate during the preceding three quarters of this year.

DD&A on oil and natural gas properties decreased for the three months ended September 30, 2015 , compared to the three months ended September 30, 2014 , of which $6.6 million was due to a decrease in production and $1.9 million was due to a

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lower rate per equivalent unit of production. Our DD&A rate per equivalent unit of production decreased for the three months ended September 30, 2015 primarily due to an increase in estimated reserves as a result of adding proved reserves in the third quarter of 2015 from the future development of remaining phases at our North Burbank Unit which more than offset decreases from production and lower prices. DD&A on oil and natural gas properties decreased for the nine months ended September 30, 2015 , compared to the nine months ended September 30, 2014 , of which $7.4 million was due to a decrease in production offset partially by $2.1 million due to a higher rate per equivalent unit of production. Our DD&A rate per equivalent unit of production increased for the nine months ended September 30, 2015 , primarily due to a decrease in our average reserves.

Asset impairments



	Three months ended September 30,				Increase / (Decrease)		Nine months ended September 30,				Increase / (Decrease)
	2015		2014		Increase / (Decrease)		2015		2014		Increase / (Decrease)
Asset impairments (in thousands)
Loss on impairment of oil and natural gas assets	$	737,758	$	—	$	737,758	$	955,320	$	—	$	955,320
Loss on impairment of other assets	—		—		—		13,311		—		13,311

Property impairments. Due to the substantial decline of commodity prices beginning in late 2014, and remaining low through September 30, 2015 , the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties at the end of June 30 and September 30, 2015 , resulting in ceiling test write-downs during the second and third quarter of 2015 of $217.6 million and $737.8 million , respectively. If commodity prices remain at the current level, the average prices used in the ceiling test calculation will decline further and we expect to record a write-down in the fourth quarter of 2015 in the range of $400 million to $450 million. 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.

The magnitude of our ceiling test write-down was impacted by two additional factors. The first were impairments of unevaluated non-producing leasehold, which resulted in a transfer of amounts from unevaluated oil and natural gas properties to the full cost amortization base. Impairments of non-producing leasehold of $108.4 million were recorded for the nine months ended September 30, 2015. The impairments were recorded as a result of changes in our drilling plans due to the low pricing environment and lower than expected results for certain exploratory activities primarily in our Panhandle Marmaton, which resulted in certain undeveloped properties not expected to be developed before lease expiration. The second factor was a reclassification of $72.0 million for the construction of CO ₂ delivery pipelines and facilities from unevaluated oil and natural gas properties to the full cost amortization base during the third quarter of 2015 in conjunction with our recognition of proved reserves from the future development of all remaining phases at our North Burbank Unit. Both factors combined to increase the carrying value of our full cost amortization base by $180.4 million and hence increased the ceiling test write-down by the same amount.

Impairment of other assets . There were no impairment losses on other assets for the three months ended September 30, 2014. Our impairment losses for the nine months ended September 30, 2015 consists of write-downs during the second quarter of 2015 of which $6.0 million related to impairments of our stacked drilling rigs and $7.3 million related to a market adjustment on our equipment inventory. We own four stacked drilling rigs of which one was last utilized in January 2015 while the remaining three have been stacked for two to three years. As a result of the recent deterioration in commodity prices and reduced drilling activity, the value of such equipment has declined while utilizing third party equipment has become more cost effective, resulting in us impairing the value of the rigs to their estimated fair value. We had previously recorded $3.5 million and $1.5 million of impairment related to these rigs during the years ended December 31, 2013 and 2012, respectively. The industry conditions described above have also caused the demand for equipment utilized in drilling to decrease, resulting in lower market prices for such equipment. The market adjustment on our equipment inventory reflects the decrease in market prices.

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General and administrative expenses (“G&A”)



	Three months ended September 30,						Increase / (Decrease)			Percent change		Nine months ended September 30,						Increase / (Decrease)			Percent change
	2015			2014			Increase / (Decrease)			Percent change		2015			2014			Increase / (Decrease)			Percent change
G&A and cost reduction initiatives (in thousands):
Gross G&A expenses	$	10,144		$	21,217		$	(11,073	)	(52.2	)%	$	34,668		$	64,082		$	(29,414	)	(45.9	)%
Capitalized exploration and development costs	(2,755		)	(6,397		)	3,642			(56.9	)%	(8,825		)	(20,883		)	12,058			(57.7	)%
Net G&A expenses	$	7,389		$	14,820		$	(7,431	)	(50.1	)%	$	25,843		$	43,199		$	(17,356	)	(40.2	)%
Cost reduction initiatives	$	603		$	—		$	603		n/a		$	9,739		$	—		$	9,739		n/a
Net G&A and cost reduction initiatives expense	$	7,992		$	14,820		$	(6,828	)	(46.1	)%	$	35,582		$	43,199		$	(7,617	)	(17.6	)%
Average G&A expense per Boe	$	3.01		$	5.36		$	(2.35	)	(43.8	)%	$	3.29		$	5.26		$	(1.97	)	(37.5	)%
Average G&A and cost reduction initiatives expense per Boe	$	3.26		$	5.36		$	(2.10	)	(39.2	)%	$	4.53		$	5.26		$	(0.73	)	(13.9	)%

Gross G&A expenses decreased during the three and nine months ended September 30, 2015 , compared to the three and nine months ended September 30, 2014 , primarily due to lower compensation and benefits costs and lower costs for equity-based compensation awards. Compensation and benefits were lower due to lower headcount subsequent to our workforce reduction and due to the lower commodity price environment. Expense for equity based awards was lower as a result of forfeitures and a decrease in the fair value of our liability awards due to the lower commodity price environment.

Capitalized exploration and development costs decreased between periods primarily due the overall decrease in G&A as well as a lower proportion of costs subject to capitalization as we have reduced our exploration, acquisition and development activities in this low commodity price environment.

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 expenses for cost reduction initiatives are $0.6 million and $7.5 million for the three and nine months ended September 30, 2015 , respectively, 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 and nine months ended September 30, 2015 compared to the three and nine months ended September 30, 2014 primarily due to these same factors offset partially by the decrease in overall production volumes between periods.

Income Taxes

I ncome taxes for the three and nine months ended September 30, 2015 were a benefit of $48.8 million and $161.3 million , respectively, compared to a provision of $49.7 million and $47.3 million , respectively, for the comparable periods in 2014. Our effective tax rate for the three months ended September 30, 2015 was a benefit of 7.0% as compared to a provision of 37.3% for the prior year quarter. Our effective tax rate was 16.2% for the nine months ended September 30, 2015 as compared to 37.3% for the prior year period. The decrease in our effective tax rates for 2015 reflect the effect of a valuation allowance recognized on deferred tax assets in 2015.

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Other income and expenses

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



	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2015			2014			2015			2014
9.875% Senior Notes due 2020	$	7,730		$	7,698		$	23,166		$	23,071
8.25% Senior Notes due 2021	8,439			8,423			25,305			25,259
7.625% Senior Notes due 2022	10,565			10,544			31,678			31,618
Senior secured revolving credit facility	2,435			1,062			7,378			4,126
Bank fees and other interest	1,272			1,374			3,790			3,979
Capitalized interest	(1,843		)	(3,667		)	(8,115		)	(9,957		)
Total interest expense	$	28,598		$	25,434		$	83,202		$	78,096
Average long-term borrowings	$	1,686,974		$	1,490,584		$	1,702,818		$	1,543,346

Total interest expense for the three and nine months ended September 30, 2015 increased 12% and 7% , respectively, compared to the same periods in 2014 primarily due to increased levels of borrowing on our senior secured revolving credit facility and reduced capitalized interest. Capitalized interest was lower as a result of a lower carrying amount of unevaluated non-producing leasehold subsequent to the leasehold impairments we recorded during the year.

Liquidity and capital resources

Historically, our primary sources of liquidity have been cash generated from our operations, debt, private equity sales and proceeds from asset dispositions. As of September 30, 2015 , we had cash and cash equivalents of $37.8 million and had borrowed $394.0 million under our senior secured revolving credit facility with a borrowing base of $550.0 million . As of November 16, 2015 , we had borrowed $389.0 million under our senior secured revolving credit facility.

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:



	Nine months ended						Increase / (Decrease)			Percent Change
	September 30,
(in thousands)	2015			2014
Cash flows provided by operating activities	$	29,644		$	279,131		$	(249,487	)	(89.4	)%
Cash flows used in investing activities	(64,803		)	(265,715		)	200,912			(75.6	)%
Cash flows provided by (used in) financing activities	41,450			(42,299		)	83,749			(198.0	)%
Net increase (decrease) in cash during the period	$	6,291		$	(28,883	)	$	35,174		(121.8	)%

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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 primarily by lower prices on all our commodities and, to a lesser extent, by a decrease in production volumes sold. Cash flows from operations were also lower due to higher interest charges and expenses associated with our cost reduction initiatives. These reductions in cash flows were partially offset by lower lease operating, general and administrative and production tax expenses.

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 nine months ended September 30, 2015 were funded by settlement proceeds from our derivative instruments, borrowings from our senior secured borrowing credit facility, proceeds from asset dispositions and cash flows from operations.

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

Our actual costs incurred, including costs that we have accrued for during the nine months ended September 30, 2015 , and our budgeted 2015 capital expenditures for oil and natural gas properties are summarized in the table below.



(in thousands)	E&P Areas		EOR Project Areas		Total		2015 Capital Expenditures Budget Range (1)(2)
(in thousands)	E&P Areas		EOR Project Areas		Total		Low		High
Acquisitions	$	17,653	$	—	$	17,653	15,000		$	20,000
Drilling	82,760		—		82,760		102,000		132,000
Enhancements	9,354		13,750		23,104		27,000		34,000
Pipeline and field infrastructure	—		15,797		15,797		13,000		16,000
CO ₂ purchases	—		12,569		12,569		18,000		23,000
Total	$	109,767	$	42,116	$	151,883	$	175,000	$	225,000

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(1)	Approximately two-thirds of our budgeted amount for enhancements and all of our budgeted amounts for pipeline and field infrastructure and CO ₂ purchases are allocated to our EOR project areas.


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

As discussed in our Annual Report on Form 10-K for the year ended December 31, 2014 , our initial estimate of capital expenditures by area and category were at the low end of our capital expenditures budget. We currently anticipate that our capital expenditures for 2015 will trend towards the mid-point of our capital expenditures budget with the most significant increase in drilling for funding participation interests in non-operated wells drilled in our STACK play.

Net cash used in investing activities during the nine months ended September 30, 2015 was comprised of cash outflows for capital expenditure and paydown of accounts payable of $267.2 million , partially offset by cash inflows from derivative settlement receipts of $173.1 million and asset dispositions of $29.3 million . Our paydown of accounts payable was a result of payments in the current year for capital expenditures accrued at the end of the prior year. Net cash used in investing activities during the nine months ended September 30, 2014 was comprised primarily of cash outflows for capital expenditure of $499.3 million and derivative settlement payments of $25.0 million , partially offset by cash inflows from asset dispositions of $258.6 million .

Cash flows from financing activities is comprised primarily of cash inflows from long-term debt borrowings, offset by cash outflows from repayments of long-term debt and capital leases. During the nine months ended September 30, 2015 , we borrowed $120.0 million on our long-term debt and made repayments of $75.4 million on our long-term debt and $1.8 million on our capital leases. Borrowings on our long-term debt occurred primarily during the first quarter, with the balance on our senior secured revolving credit facility reaching $450 million at the end of the first quarter, and repayments occurring thereafter, with the balance on our senior secured revolving credit facility reduced to $427 million and $394 million at the end of the the second and third quarter, respectively. We also paid $1.4 million in bank fees in connection with the amendment to our senior secured credit facility discussed below. During the nine months ended September 30, 2014 , we borrowed $187.0 million on our long-term debt and made repayments of $227.6 million on our long-term debt and $1.7 million on our capital leases.

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Indebtedness

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



(in thousands)	September 30, 2015		December 31, 2014
9.875% Senior Notes due 2020, net of discount of $4,382 and $4,861, respectively	$	295,618	$	295,139
8.25% Senior Notes due 2021	400,000		400,000
7.625% Senior Notes due 2022, including premium of $4,272 and $4,869, respectively	554,272		554,869
Senior secured revolving credit facility	394,000		347,000
Real estate mortgage notes	10,315		10,705
Installment notes	2,289		4,252
Capital lease obligations	20,045		21,837
	$	1,676,539	$	1,633,802

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 September 30, 2015 , we have $394.0 million of outstanding borrowings under our senior secured revolving credit facility while the outstanding balance was $389.0 million as of November 16, 2015. Our borrowing base on the facility decreased from $650.0 million to $550.0 million effective April 1, 2015 and remains at the same amount subsequent to our semi-annual redetermination on October 29, 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.

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



(dollars in thousands)	September 30, 2015			December 31, 2014
Current assets per GAAP	$	277,385		$	339,898
Plus—Availability under senior secured revolving credit facility	155,126			302,080
Less—Short-term derivative instruments	(142,944		)	(179,921		)
Current assets as adjusted	$	289,567		$	462,057
Current liabilities per GAAP	$	162,981		$	328,366
Less—Short-term derivative instruments	(39		)	(77		)
Less—Short-term asset retirement obligations	(2,384		)	(4,147		)
Less—Deferred tax liability on derivative instruments and asset retirement obligations	(53,667		)	(65,799		)
Current liabilities as adjusted	$	106,891		$	258,343
Current ratio for loan compliance	2.71			1.79
Current ratio per GAAP	1.70			1.04

We 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 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 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 planned capital expenditures for 2015 will be funded, in part, by approximately $42 million of anticipated proceeds we expect to generate from asset divestitures. As of September 30, 2015, we have received $29.3 million in proceeds from various asset sales while an additional $12.1 million of sales have closed as of November 16, 2015. 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

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cannot provide assurance that these resources would be available on terms acceptable to us.

Contractual Obligations

In September 2015, we entered into an interim financing agreement with U.S. Bank for an additional CO ₂ recycle compressor for our EOR facilities. If we do not enter into a lease once the compressor has been manufactured, we will owe U.S. Bank most of the cost incurred by U.S. Bank for the compressor.

Other than additional borrowings under our senior secured credit facility during the nine months ended September 30, 2015 , and our obligation under the interim financing arrangement discussed above, there were no material changes to our contractual commitments since December 31, 2014 .

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) asset impairments, (2) interest and other financing costs, net of capitalized interest, (3) income taxes, (4) depreciation, depletion and amortization, (5) non-cash change in fair value of non-hedge derivative instruments, (6) interest income, (7) stock-based compensation expense, (8) gain or loss on disposed assets, (9) upfront premiums paid on settled derivative contracts, (10) impairment charges, and (11) 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 (12) other significant, unusual non-cash charges.

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



	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2015			2014			2015			2014
Net (loss) income	$	(647,142	)	$	83,513		$	(831,930	)	$	79,485
Interest expense	28,598			25,434			83,202			78,096
Income tax (benefit) expense	(48,776		)	49,734			(161,314		)	47,315
Depreciation, depletion, and amortization	52,027			61,527			173,694			180,631
Non-cash change in fair value of non-hedge derivative instruments	(30,941		)	(107,469		)	67,883			(42,256		)
Upfront premiums paid on settled derivative contracts	—			(166		)	—			(498		)
Interest income	(21		)	(15		)	(168		)	(86		)
Stock-based compensation expense	(20		)	1,607			(32		)	3,867
Gain on sale of assets	(77		)	(196		)	(1,448		)	(1,007		)
Loss on impairment of assets	737,758			—			968,631			—
Cost reduction initiatives expense	603			—			9,739			—
Adjusted EBITDA	$	92,009		$	113,969		$	308,257		$	345,547

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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.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity prices . Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. We cannot predict future oil and natural gas prices with any degree of certainty. Sustained declines in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and natural gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce our borrowing base under our senior secured revolving credit facility and adversely affect our liquidity and our ability to obtain capital for our acquisition, exploration and development activities. Based on our production for the nine months ended September 30, 2015 , our gross revenues from oil and natural gas sales would change approximately $5.5 million for each $1.00 change in oil and natural gas liquid prices and $1.4 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 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 5 — 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 September 30, 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 deferred premium

October - December 2015
Swaps (1)	630	$	91.38	$	—	$	—	$	—	$	13.80
Collars (1)	130	$	—	$	—	$	47.50	$	57.50	$	1.71
Purchased Puts (1)	695	$	—	$	—	$	43.05	$	—	$	2.96
January - March 2016
Three-way collars	60	$	—	$	84.00	$	92.00	$	101.01	$	—
Three-way collars (1)	120	$	—	$	40.00	$	52.50	$	72.50	$	2.95
Enhanced swaps (2)	960	$	92.98	$	80.50	$	—	$	—	$	—
Purchased puts (2)	960	$	—	$	—	$	60.00	$	—	$	—
April - June 2016
Three-way collars	60	$	—	$	84.00	$	92.00	$	101.01	$	—
Three-way collars (1)	120	$	—	$	40.00	$	52.50	$	72.50	$	2.95
Enhanced swaps (2)	960	$	92.98	$	80.50	$	—	$	—	$	—
Purchased puts (2)	960	$	—	$	—	$	60.00	$	—	$	—
July - September 2016
Three-way collars	60	$	—	$	84.00	$	92.00	$	101.01	$	—
Three-way collars (1)	120	$	—	$	40.00	$	52.50	$	72.50	$	2.95
Enhanced swaps (2)	900	$	92.91	$	80.53	$	—	$	—	$	—
Purchased puts (2)	900	$	—	$	—	$	60.00	$	—	$	—
October - December 2016
Three-way collars	60	$	—	$	84.00	$	92.00	$	101.01	$	—
Three-way collars (1)	120	$	—	$	40.00	$	52.50	$	72.50	$	2.95
Enhanced swaps (2)	900	$	92.91	$	80.53	$	—	$	—	$	—
Purchased puts (2)	900	$	—	$	—	$	60.00	$	—	$	—
January - March 2017
Three-way collars (1)	120	$	—	$	42.50	$	55.00	$	80.00	$	2.78
April - June 2017
Three-way collars (1)	120	$	—	$	42.50	$	55.00	$	80.00	$	2.78
July - September 2017
Three-way collars (1)	120	$	—	$	42.50	$	55.00	$	80.00	$	2.78
October - December 2017
Three-way collars (1)	120	$	—	$	42.50	$	55.00	$	80.00	$	2.78

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(1)	These contracts include deferred premiums that are payable upon settlement.

(2)

Total premiums of $20.6 million for the purchased puts were paid at contract inception in December 2014. Excluding the premiums and utilizing an average NYMEX strip price of $48.70 for 2016 as of September 30, 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 September 30, 2015 are summarized below:



Period and type of contract	Volume BBtu	Weighted average fixed price per MMBtu

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

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 $15.4 million , 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 for the nine months ended September 30, 2015 .

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realized price we receive. At September 30, 2015, 275,000 barrels of the locked-in swaps had matured for which net proceeds of $10.2 million are to be received. Based on the October through December 2015 average NYMEX strip price of $45.77 , at September 30, 2015, the average realized price, inclusive of the net locked-in proceeds for the remaining 825,000 barrels of production, will yield an effective price of $82.72 . The 825,000 barrels of remaining locked-in swaps are not reflected in the volumes hedged in the crude oil derivatives outstanding table above as the anticipated proceeds no longer vary according to changes in crude oil pricing. However, the anticipated proceeds from the remaining locked-in swaps are reflected in the derivative asset and liability values disclosed in the table below.

Interest rates . All of the outstanding borrowings under our senior secured revolving facility as of September 30, 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 (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 $550.0 million , equal to our borrowing base at September 30, 2015 , the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $5.5 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 9 — 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

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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.” The Oklahoma Corporation Commission (the “OCC”) has issued a directive affecting more than 500 disposal wells in 21 Oklahoma counties restricting injection of high volumes of water into formations below the Arbuckle formation into the crystalline basement. We operate 10 wells in the OCC “area of interest” and are fully compliant with all regulations relating to the disposal of produced water. 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.


ITEM 5.	OTHER INFORMATION

None.


ITEM 6.	EXHIBITS



Exhibit No.		Description

3.1*		Second Amended and Restated Certificate of Incorporation of Chaparral Energy, Inc. (the “Company”), dated as of April 12, 2010. (Incorporated by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K filed on April 14, 2010)

3.2*		Second Amended and Restated Bylaws of the Company, dated as of April 12, 2010. (Incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K filed on April 14, 2010)

10.1*		Fifteenth Amendment to Eighth Restated Credit Agreement dated as of April 1, 2015 (Incorporated by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q filed on May 12, 2015).

10.2		Chaparral Energy, LLC Long-Term Cash Incentive Plan Agreement

31.1		Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act

31.2		Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act

32.1		Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

* Incorporated by reference

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SIGNATURES

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



CHAPARRAL ENERGY, INC.

By:	/s/ Mark A. Fischer
Name:	Mark A. Fischer
Title:	Chief Executive Officer
	(Principal Executive Officer)

By:	/s/ Joseph O. Evans
Name:	Joseph O. Evans
Title:	Chief Financial Officer and Executive Vice President
	(Principal Financial Officer and Principal Accounting Officer)

Date: November 16, 2015

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EXHIBIT INDEX



Exhibit No.		Description

3.1*		Second Amended and Restated Certificate of Incorporation of Chaparral Energy, Inc. (the “Company”), dated as of April 12, 2010. (Incorporated by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K filed on April 14, 2010)

3.2*		Second Amended and Restated Bylaws of the Company, dated as of April 12, 2010. (Incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K filed on April 14, 2010)

10.1*		Fifteenth Amendment to Eighth Restated Credit Agreement dated as of April 1, 2015 (Incorporated by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q filed on May 12, 2015).

10.2		Chaparral Energy, LLC Long-Term Cash Incentive Plan Agreement

31.1		Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act

31.2		Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act

32.1		Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

* Incorporated by reference

CHAPARRAL ENERGY, LLC

LONG-TERM CASH INCENTIVE PLAN

ARTICLE I.
Name and Purpose of Plan

1.1 Establishment . Chaparral Energy, L.L.C. hereby adopts this Chaparral Energy, LLC Long-Term Cash Incentive Plan (“Plan”) effective August 7, 2015. The Plan is designed to retain and incentivize key employees of the Company or any Affiliate.

1.2 Type of Plan . This Plan shall be considered a “bonus plan” sponsored by the Company solely for the purpose of providing additional compensation to key employees who contribute materially to the continued growth, development and future business success of the Company. This Plan does not provide for retirement income or the deferral of compensation.

ARTICLE II.
Definitions and Construction

2.1 Definitions . Where the following capitalized words and phrases appear in this instrument, they shall have the respective meanings set forth below unless a different context is clearly expressed herein.

(a) “ Affiliate ” shall mean a corporation, trade or business that, together with the Company, is treated as a single employer under Code Section 414(b) or (c).

(b) “ Beneficiary ” shall mean that person designated by the Eligible Employee who would be entitled to receive amounts otherwise payable to such Eligible Employee under this Plan in the event of the death of the Eligible Employee.

(d) “ Incentive Award ” shall mean the amount, if any, earned by an Eligible Employee in accordance with Article III for a particular Plan Year.

(e) “ Cause ” means (A) Eligible Employee’s conviction by a court of competent jurisdiction as to which no further appeal can be taken of a crime involving moral turpitude or a felony or entering the plea of nolo contendere to such crime by the Eligible Employee; (B) the commission by an Eligible Employee of a material act of fraud upon the Company or any Affiliated Entity; (C) the material misappropriation of funds or property of the Company or any Affiliated Entity by an Eligible Employee; (D) the knowing violation of the Company’s Code of Business Conduct and Ethics by an Eligible Employee; or (E) the willful, material and repeated nonperformance of an Eligible Employee’s duties to the Company or any Affiliate (other than by reason of an Eligible Employee’s illness or incapacity).

(f) “ Change of Control ” means:

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

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

(g) “ Company ” shall mean Chaparral Energy, LLC, or its successor.

(h) “ Compensation Committee” means the Compensation Committee of the Board.

(i) “ Disability ” shall mean the Eligible Employee is unable to continue employment by reason of any medically determinable physical or mental impairment, which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months. For purposes of this Plan, the determination of Disability shall be made in the sole and absolute discretion of the Plan Committee.

(j) “ Eligible Employee ” shall mean an employee of the Company or an Affiliate who has been selected to be eligible for an Incentive Award in accordance with Section 3.1. For the purposes of the Plan, no Officer of the Company is an Eligible Employee.

(k) “ First Vesting ” shall mean the first vesting of an Incentive Award made in accordance with Section 3.3(a).

(l) “ Fourth Vesting ” shall mean the fourth vesting of an Incentive Award made in accordance with Section 3.3(d).

(m) “Granting Date” shall mean the first day of a Plan Year during which an Incentive Award is granted to an Eligible Employee in accordance with Section 3.1(a), or the employment date of a subsequently hired Eligible Employee in accordance with Section 3.1(b).

(n) “ Plan ” shall mean the Chaparral Energy, LLC Long-Term Cash Incentive Plan, as set forth in this instrument, and as hereafter amended from time to time.

(o) “ Plan Committee ” shall mean the Executive Committee of the Company.

(p) “ Plan Year ” shall begin September 1 and end August 31 of the following year.

(q) “ Second Vesting ” shall mean the second vesting of an Incentive Award made in accordance with Section 3.3(b).

(r) “ Separation from Service ” shall mean a termination of employment that constitutes a “separation from service” as defined by, and determined by the Plan Committee in accordance with, Section 409A of the Internal Revenue Code.

(s) “ Third Vesting ” shall mean the third vesting of an Incentive Award made in accordance with Section 3.3(c).

2.2 Construction . The masculine gender, where appearing in the Plan, shall be deemed to include the feminine gender, unless the context clearly indicates to the contrary. Any word appearing herein in the plural shall include the singular, where appropriate, and likewise the singular shall include the plural, unless the context clearly indicates to the contrary.

2.3 Participation Consideration for Future Services . Selection of an employee by the Plan Committee for participation in any Plan Year will be deemed to be for all purposes in consideration of future services to be rendered by the employee to the Company or an Affiliate.

ARTICLE III.
Determination, Vesting and Payment of Incentive Awards

3.1 Selection for Participation .

(a) In General . Selection of employees for participation in the Plan shall be in the sole and absolute discretion of the Plan Committee. Participation in the Plan for one Plan Year does not ensure selection for participation in another Plan Year. Incentive Awards will be granted on the first day of the Plan Year, or as otherwise expressly set out in the Plan, and will vest as described in Section 3.3.

(b) New Hires . The Plan Committee may select a newly hired employee of the Company or any affiliate for participation in the Plan Year in which such employee is hired. If an Eligible Employee is selected to participate in the Plan after the first day of the Plan Year, the Incentive Award for that Plan Year will be prorated based upon the number of days the Eligible Employee worked for the Company after selection for participation during the Plan Year.

3.2 Determination of Incentive Award . On an annual basis the Plan Committee shall determine the potential Incentive Award for each Eligible Employee selected to receive an Incentive Award for the Plan Year consistent with the position of the Eligible Employee.

3.3 Vesting and Payment of Incentive Award . To the extent an Eligible Employee satisfies the conditions set forth in Section 3.4, an Incentive Award granted for a Plan Year shall vest over a four year period as follows:

(a) First Vesting. One-fourth (1/4) of the Incentive Award shall vest on the last day of the first Plan Year during which the grant is made (“First Vesting Date”). Payment of the first vested portion of the Inventive Award will be made within thirty (30) days of the First Vesting Date.

(b) Second Vesting. One-fourth (1/4) of the Incentive Award shall vest on the last day of the second Plan Year following the Granting Date (“Second Vesting Date”). Payment of the second vested portion of the Inventive Award will be made within thirty (30) days of the Second Vesting Date.

(c) Third Vesting. One-fourth (1/4) of the Incentive Award shall vest on the last day of the third Plan Year following the Granting Date (“Third Vesting Date”). Payment of the third vested portion of the Inventive Award will be made within thirty (30) days of the Third Vesting Date.

(d) Fourth Vesting. One-fourth (1/4) of the Incentive Award shall vest on the last day of the fourth Plan Year following the Granting Date (“Fourth Vesting Date”). Payment of the fourth vested portion of the Inventive Award will be made within thirty (30) days of the Fourth Vesting Date.

3.4 Forfeiture/Vesting of Incentive Award Installments .

(a) Forfeiture of Incentive Award . If an Eligible Employee is not employed by the Company on the last day of the Plan Year, no Incentive Award shall be earned and no Incentive Award shall vest for such Plan Year. Any Incentive Award that does not vest because the Eligible Employee is no longer employed by the company on the Vesting Date is forever forfeited by the Eligible Employee.

(b) Employment Required for Vesting . An Eligible Employee must continuously remain employed with the Company or an Affiliate (i) through the First Vesting Date to be entitled to payment of the First Vesting of the Incentive Award; (ii) through the Second Vesting Date to be entitled to receive payment of the Second Vesting of an Incentive Award; (iii) through the Third Vesting Date to be entitled to receive payment of the Third Vesting of an Incentive Award; and (iv) through the Fourth Vesting Date to be entitled to receive payment of the Fourth Vesting of an Incentive Award.

(c) Accelerated Vesting . Notwithstanding anything in the contrary in this Section 3.4, if an Incentive Award for a Plan Year has been awarded and earned under Section 3.4 but is not fully vested and paid, upon (i) an Eligible Employee’s death; (ii) an Eligible Employee’s involuntary Separation from Service without Cause subsequent to a Change of Control; or (iii) an Eligible Employee’s Separation from Service due to Disability, the Eligible Employee or the Beneficiary or personal representative of a deceased Eligible Employee, as applicable, any unvested portion of such Incentive Award shall be immediately vested and such amounts will be paid in a lump sum within 60 days of the occurrence of the event. Separation from Service for any other reason prior to the vesting date will result in forfeiture of all unvested Incentive Awards.

ARTICLE IV.
General Benefit Provisions

4.1 Restrictions on Alienation of Benefits . No right or benefit under this Plan shall be subject in any manner to garnishment, attachment, anticipation, alienation, sale, transfer, assignment, pledge, encumbrance, levy, execution or the claims of creditors, either voluntarily or involuntarily, and any attempt to so garnish, attach, anticipate, alienate, sell, transfer, assign, pledge, encumber, levy or execute on the same shall be null and void, and neither shall such benefits or beneficial interests be liable for or subject to the debts, contracts, liabilities, engagements or torts of any person to whom such benefits or funds are payable. If any Eligible Employee under this Plan should become bankrupt or attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge any right to any Incentive Award earned under the Plan, then such Incentive Award may, in the sole discretion of the Plan Committee, be forfeited and canceled for all purposes.

4.2 No Trust . No action under this Plan by the Company, the Board or Plan Committee shall be construed as creating a trust, escrow or other secured or segregated fund in favor of the Eligible Employee, his Beneficiary, or any other persons otherwise entitled to his Incentive Award. The status of the Eligible Employee and his Beneficiary with respect to any liabilities assumed by the Company hereunder shall be solely those of unsecured creditors of the Company. Any asset acquired or held by the Company in connection with liabilities assumed by it hereunder shall not be deemed to be held under any trust, escrow or other secured or segregated fund for the benefit of the Eligible Employee or his Beneficiaries, or to be security for the performance of the obligations of the Company or any Affiliate, but shall be, and remain a general, unpledged and unrestricted asset of the Company, at all times subject to the claims of general creditors of the Company.

4.3 Withholding for Income and Employment Taxes . Since all amounts to be paid hereunder are to be considered a supplemental compensation paid for services rendered by the Eligible Employee, the Company shall comply with all federal and state laws and regulations respecting the withholding, deposit and payment of any income, employment or other taxes relating to any payments made under this Plan, and accordingly, all amounts payable under this Plan shall be subject to and reduced by the amount of such taxes.

4.4 No Interest on Incentive Award . All Incentive Awards will be paid without interest or investment earnings of any kind whatsoever.

ARTICLE V.
Provisions Relating to Eligible Employees

5.1 Information Required of Eligible Employees . Payment of Incentive Awards shall begin as of the payment date(s) provided in this Plan and no formal claim shall be required. The Plan Committee may make reasonable requests of Eligible Employees and Beneficiaries to furnish information, which is reasonably necessary and appropriate to the orderly administration of the Plan.

5.2 Benefits Payable to Incompetents . Any benefits payable hereunder to a minor or other person under legal disability may be made, at the discretion of the Plan Committee, (i) directly to said person, or (ii) to a parent, spouse, relative by blood or marriage, or the legal representative of said person. The Plan Committee shall not be required to see to the application of any such payment and the payee’s receipt shall be a full and final discharge of the Plan Committee’s responsibility hereunder.

5.3 Conditions of Employment Not Affected by Plan . The establishment and maintenance of the Plan shall not be construed as conferring any legal rights upon any Eligible Employee to the continuation of employment with the Company or any Affiliate, nor shall the Plan interfere with the rights of the Company or any Affiliate to discharge any Eligible Employee with or without cause.

ARTICLE VI.
Administration

6.1 Administration of the Plan . The Plan shall be administered by the Plan Committee.

Subject to the provisions of the Plan, the Plan Committee shall have exclusive power to:

(d) Select Eligible Employees for a Plan Year.

(e) Determine the amount of Incentive Award, but generally in accordance with the compensation table established by the grade level classification of the employee.

(f) Determine the terms, conditions, restrictions and/or limitations, if any, of an Incentive Award.

(g) Take any and all other action they deem necessary or advisable for the proper operation or administration of the Plan.

6.2 Plan Committee to Make Rules and Interpret Plan . The Plan Committee in its sole discretion shall have the authority, subject to the provisions of the Plan, to make all such determinations relating to the Plan as it may deem necessary or advisable for the administration of the Plan, including any calculations necessary to determine the amount or existence of an Eligible Employee’s Incentive Award. The Plan Committee’s interpretation of the Plan and all decisions and determinations by the Plan Committee with respect to the Plan shall be final, binding, and conclusive on all parties.

ARTICLE VII.
Amendment, Termination and Forfeiture

7.1 Right to Amend Plan . The Plan may be amended by the Company from time to time in any respect whatever by resolution of the Compensation Committee adopting such amendment. Any amendments may be made retroactively, where in the judgment of the Compensation Committee retroactive application is necessary or advisable.

7.2 Right to Terminate Plan . The Company expressly reserves the right to terminate this Plan in whole or in part at any time. The Company shall determine a proposed date of termination, and the Plan Committee shall notify the Eligible Employees. Provided, the termination of the Plan shall not interfere with the continued vesting and payment of a previously granted Incentive Award in accordance with the provisions of the Plan, assuming the Plan had continued in existence. Such rights shall continue to be governed by the terms and provisions of this Plan after such date of termination.

ARTICLE VIII.
Miscellaneous Provisions

8.1 Articles and Section Titles and Headings . The titles and headings at the beginning of each Article and Section shall not be considered in construing the meaning of any provisions in this Plan.

8.2 Supersedes Prior Plans . This Plan, when executed, replaces, supersedes and nullifies any previously adopted Long Term Cash Incentive Plan adopted by the Company.

8.3 Laws of Oklahoma to Govern . The provisions of this Plan shall be construed, administered and enforced according to the laws of the State of Oklahoma.

The Compensation Committee has adopted this Plan, to be effective the ___ day of August 2015.

CHAPARRAL ENERGY, LLC

By:

Mark A. Fischer

Manager & Chief Executive Officer

Exhibit 31.1

CERTIFICATION

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


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


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


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


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


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


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


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


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


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


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


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

Date: November 16, 2015

/s/ Mark A. Fischer

Mark A. Fischer

Chief Executive Officer

Exhibit 31.2

CERTIFICATION

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


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


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


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


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


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


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


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


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


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


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


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

Date: November 16, 2015

/s/ Joseph O. Evans

Joseph O. Evans

Chief Financial Officer

Exhibit 32.1

CERTIFICATION OF PERIODIC REPORT

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


(1)	the Quarterly Report on Form 10-Q of the Company for the period ended September 30, 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: November 16, 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.

Exhibit 32.2

CERTIFICATION OF PERIODIC REPORT

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


(1)	the Quarterly Report on Form 10-Q of the Company for the year ended September 30, 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: November 16, 2015

/s/ Joseph O. Evans

Joseph O. Evans

Chief Financial Officer