UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 ____________________________

Form 10-Q

____________________________

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

For the quarterly period ended September 30, 2013

OR

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

For the transition period from to

Commission file number: 333-187868

____________________________

Chaparral Energy, Inc.

(Exact name of registrant as specified in its charter)

 ____________________________

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

(405) 478-8770

(Registrant’s telephone number, including area code)

____________________________

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

(Explanatory Note: Prior to April 24, 2013, the effective date of the registrant’s Registration Statement on Form S-4, the registrant was a voluntary filer and was not subject to the filing requirements of the Securities Exchange Act of 1934. However, during the preceding 12 months, the registrant has filed all reports that it would have been required to file by Section 13 or 15(d) of the Securities Act of 1934 if the registrant was subject to the filing requirements of the Securities Exchange Act of 1934.)

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    No  ¨

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

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

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

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

Class	Number of shares
Class A Common Stock, $0.01 par value	70,145
Class B Common Stock, $0.01 par value	357,882
Class C Common Stock, $0.01 par value	209,882
Class D Common Stock, $0.01 par value	279,999
Class E Common Stock, $0.01 par value	504,276
Class F Common Stock, $0.01 par value	1
Class G Common Stock, $0.01 par value	3

CHAPARRAL ENERGY, INC.

Index to Form 10-Q

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

2

CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

This report includes statements that constitute forward-looking statements within the meaning of the federal securities law. These statements are subject to risks and uncertainties. These statements may relate to, but are not limited to, information or assumptions about us, our capital and other expenditures, dividends, financing plans, capital structure, cash flow, pending legal and regulatory proceedings and claims, including environmental matters, future economic performance, operating income, cost savings, and management’s plans, strategies, goals and objectives for future operations and growth. These forward-looking statements generally are accompanied by words such as “intend,” “anticipate,” “believe,” “estimate,” “expect,” “should,” “seek,” “project,” “plan” or similar expressions. Any statement that is not a historical fact is a forward-looking statement. It should be understood that these forward-looking statements are necessarily estimates reflecting the best judgment of senior management, not guarantees of future performance. Forward-looking statements in this report may include, for example, statements about:

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

• the amount, nature and timing of capital expenditures;

• drilling, completion and performance of wells;

• competition and government regulations;

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

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

• changes in proved reserves;

• operating costs and other expenses;

• cash flow and anticipated liquidity;

• estimates of proved reserves;

• exploitation of property acquisitions; and

• marketing of oil and natural gas.

3

These forward-looking statements represent intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside of our control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. These risks and uncertainties include those factors described under the heading “Risk Factors” in our Annual Report on Form 10-K filed with the SEC on April 1, 2013. Specifically, some factors that could cause actual results to differ include:

• the significant amount of our debt;

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

• volatility and declines in oil and natural gas prices;

• drilling plans (including scheduled and budgeted wells);

• the number, timing or results of any wells;

• changes in wells operated and in reserve estimates;

• supply of CO₂;

• future growth and expansion;

• future exploration;

• integration of existing and new technologies into operations;

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

• borrowings and capital resources and liquidity;

• changes in strategy and business discipline;

• future tax matters;

• any loss of key personnel;

• future seismic data (including timing and results);

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

• geopolitical events affecting oil and natural gas prices;

• outcome, effects or timing of legal proceedings;

• the effect of litigation and contingencies;

• the ability to generate additional prospects; and

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

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

4

GLOSSARY OF OIL AND NATURAL GAS TERMS

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

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

• BBtu. One billion British thermal units.

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

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

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

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

• MBoe. One thousand barrels of crude oil equivalent.

• Mcf. One thousand cubic feet of natural gas.

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

• MMBoe. One million barrels of crude oil equivalent.

• MMBtu. One million British thermal units.

• MMcf. One million cubic feet of natural gas.

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

• NYMEX. The New York Mercantile Exchange.

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

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

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

• SEC. The Securities and Exchange Commission.

5

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets

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

6

Chaparral Energy, Inc. and subsidiaries Consolidated balance sheets—continued
	September 30, 2013		December 31, 2012
(dollars in thousands, except per share data)	(unaudited)
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	116,225	$	101,598
Accrued payroll and benefits payable	22,293		19,655
Accrued interest payable	33,390		24,131
Revenue distribution payable	23,333		18,152
Current maturities of long-term debt and capital leases	3,322		3,746
Derivative instruments	6,971		436
Deferred income taxes	—		26,872
Total current liabilities	205,534		194,590
Long-term debt and capital leases, less current maturities	1,376,736		1,289,656
Derivative instruments	22		2,192
Stock-based compensation	3,133		3,042
Asset retirement obligations, net of current portion	45,349		46,314
Deferred income taxes	45,394		8,901
Commitments and contingencies (Note 10)
Stockholders’ equity:
Preferred stock, 600,000 shares authorized, none issued and outstanding	—		—
Class A Common stock, $0.01 par value, 10,000,000 shares authorized and 70,224 and 67,991 shares issued and outstanding as of September 30, 2013 and December 31, 2012, respectively	—		—
Class B Common stock, $0.01 par value, 10,000,000 shares authorized and 357,882 shares issued and outstanding	4		4
Class C Common stock, $0.01 par value, 10,000,000 shares authorized and 209,882 shares issued and outstanding	2		2
Class D Common stock, $0.01 par value, 10,000,000 shares authorized and 279,999 shares issued and outstanding	3		3
Class E Common stock, $0.01 par value, 10,000,000 shares authorized and 504,276 shares issued and outstanding	5		5
Class F Common stock, $0.01 par value, 1 share authorized, issued, and outstanding	—		—
Class G Common stock, $0.01 par value, 3 shares authorized, issued, and outstanding	—		—
Additional paid in capital	423,993		422,434
Retained earnings	52,328		17,186
Accumulated other comprehensive income, net of taxes	5,445		23,223
	481,780		462,857
	$	2,157,948	$	2,007,552

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

7

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of operations

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

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

8

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of comprehensive (loss) income

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

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

9

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows

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

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

10

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements (unaudited)

(dollars in thousands, unless otherwise noted)

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

Nature of operations

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

Interim financial statements

The accompanying unaudited consolidated interim financial statements of the Company have been prepared in accordance with the rules and regulations of the SEC and do not include all of the financial information and disclosures required by accounting principles generally accepted in the United States of America (“GAAP”) for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2012.

The financial information as of September 30, 2013, and for the three and nine months ended September 30, 2013 and 2012, is unaudited. In management’s opinion, such information contains all adjustments, consisting only of normal recurring accruals, considered necessary for a fair presentation of the results of the interim periods. The results of operations for the three and nine months ended September 30, 2013 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2013.

Cash and cash equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of September 30, 2013, cash with a recorded balance totaling $36,259 was held at JP Morgan Chase Bank, N.A. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts.

Accounts receivable

We have receivables from joint interest owners and oil and natural gas purchasers which are generally uncollateralized. We generally review our oil and natural gas purchasers for credit worthiness and general financial condition. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties of which we are the operator. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts. Accounts receivable are generally due within 30 days and accounts outstanding longer than 60 days are considered past due. We determine our allowance by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate, and the owner’s ability to pay its obligation, among other things.

We write off accounts receivable when they are determined to be uncollectible. Accounts receivable consisted of the following at September 30, 2013 and December 31, 2012:

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

11

Inventories

Inventories are comprised of equipment used in developing oil and natural gas properties and oil and natural gas production inventories. Equipment inventory is carried at the lower of cost or market using the average cost method. Oil and natural gas product inventories are stated at the lower of production cost or market. We regularly review inventory quantities on hand and record provisions for excess or obsolete inventory, if necessary. Inventories at September 30, 2013 and December 31, 2012 consisted of the following:

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

Oil and natural gas properties

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

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

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

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

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

12

Assets Held for Sale

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

Stock-based compensation

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

The estimated fair value of the phantom stock and RSU awards is remeasured at the end of each reporting period until settlement. The estimated fair market value of these awards is calculated based on our total asset value less total liabilities, with both assets and liabilities being adjusted to fair value in accordance with the terms of the Phantom Stock Plan and the Non-Officer Restricted Stock Unit Plan. The primary adjustment required is the adjustment of oil and natural gas properties from net book value to the discounted and risk-adjusted reserve value based on internal reserve reports priced on NYMEX forward strips. Compensation cost associated with the phantom stock and RSU awards is recognized over the vesting period using the straight-line method and the accelerated method, respectively.

The fair value of our restricted stock awards that include a service condition is based upon the estimated fair market value of our common stock on the date of grant, and is remeasured at the end of each reporting period until settlement. We recognize compensation cost over the requisite service period using the accelerated method for awards with graded vesting.

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

13

Recently adopted accounting pronouncements

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

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

Recently issued accounting pronouncements

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

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

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

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

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Note 3: Long-term debt

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

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

Senior Notes

The Senior Notes, which, as of September 30, 2013, include our 9.875% Senior Notes due 2020, our 8.25% Senior Notes due 2021, and our 7.625% Senior Notes due 2022, are our senior unsecured obligations, rank equally in right of payment with all our existing and future senior debt, and rank senior to all of our existing and future subordinated debt. The indentures governing our Senior Notes contain certain covenants which limit our ability to:

• incur or guarantee additional debt and issue certain types of preferred stock;

• pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated debt;

• make investments;

• incur liens on assets;

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

• engage in transactions with affiliates;

• sell assets, including capital stock of our subsidiaries;

• consolidate, merge, or transfer assets; and

• enter into other lines of business.

If we experience a change of control (as defined in the indentures governing the Senior Notes), including making certain asset sales, subject to certain conditions, we must give holders of the Senior Notes the opportunity to sell us their Senior Notes at 101% of the principal amount, plus accrued and unpaid interest.

Chaparral Energy, Inc. is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding Senior Notes have been fully and unconditionally guaranteed, on a joint and several basis, by all of our wholly owned subsidiaries except for Chaparral Biofuels, LLC.

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Senior secured revolving credit facility

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

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

The Eurodollar rate is computed at the Adjusted LIBO Rate, defined as the rate applicable to dollar deposits in the London interbank market with a maturity comparable to the interest period (one, two, three or six months, selected by us) times a Statutory Reserve Rate multiplier, as defined in our senior secured revolving credit facility, plus a margin that varies depending on our utilization percentage. During the nine months ended September 30, 2013, the applicable margin was 1.50%. Interest payments on Eurodollar borrowings are due the last day of the interest period, if shorter than three months or every three months.

Interest on loans subject to the ABR is computed as the greater of (1) the Prime Rate, as defined in our senior secured revolving credit facility, (2) the Federal Funds Effective Rate, as defined in our senior secured revolving credit facility, plus 0.50%, or (3) the Adjusted LIBO Rate, as defined in our senior secured revolving credit facility, plus 1%, plus a margin that varies depending on our utilization percentage.

Commitment fees range from 0.375% to 0.50%, depending on our utilization percentage. During the nine months ended September 30, 2013, commitment fees accrued at the rate of 0.375% on the unused portion of the borrowing base amount, and were included as a component of interest expense. We have the right to make prepayments of the borrowings at any time without penalty or premium.

Our senior secured revolving credit facility has certain negative and affirmative covenants that require, among other things, maintaining a Current Ratio, as defined in our senior secured revolving credit facility, of not less than 1.0 to 1.0 and a Consolidated Net Debt to Consolidated EBITDAX ratio, as defined in our senior secured revolving credit facility, of not greater than 4.5 to 1.0 for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter.

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

Our senior secured revolving credit facility also specifies events of default, including non-payment, breach of warranty, non-performance of financial covenants, default on other indebtedness, certain adverse judgments, and change of control, among others. In addition, bankruptcy and insolvency events with respect to us or certain of our subsidiaries will result in an automatic acceleration of the indebtedness under our senior secured revolving credit facility. An acceleration of our indebtedness under our senior secured revolving credit facility could in turn result in an event of default under the indentures for our Senior Notes, which in turn could result in the acceleration of the Senior Notes.

If the outstanding borrowings under our senior secured revolving credit facility were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay a portion of our bank borrowings in the amount of the excess either in a lump sum within 30 days or in equal monthly installments over a six-month period, (2) to submit within 30 days additional oil and natural gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and natural gas properties within 30 days.

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Capital Leases

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

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Note 4: Derivative instruments

Overview

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

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

Collars contain a fixed floor price (purchased put) and ceiling price (sold call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party. A three-way collar contract consists of a standard collar contract plus a sold put with a price below the floor price of the collar. The sold put option requires us to make a payment to the counterparty if the market price is below the sold put option price. If the market price is greater than the sold put option price, the result is the same as it would have been with a standard collar contract only. By combining the collar contract with the sold put option, we are entitled to a net payment equal to the difference between the floor price of the standard collar and the sold put option price if the market price falls below the sold put option price. This strategy enables us to increase the floor and the ceiling price of the collar beyond the range of a traditional costless collar utilizing the value associated with the sale of a put option.

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

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

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

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

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

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

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

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Effect of derivative instruments on the consolidated balance sheets

All derivative financial instruments are recorded on the balance sheet at fair value. See Note 5 for additional information regarding fair value measurements. The estimated fair values of derivative instruments are provided below. The carrying amounts of these instruments are equal to the estimated fair values.

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

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

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

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

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

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

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Effect of derivative instruments on the consolidated statements of operations

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

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

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

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

Note 5: Fair value measurements

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

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

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

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

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

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

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Recurring fair value measurements

Our financial instruments recorded at fair value on a recurring basis consist of commodity derivative contracts (see Note 4). We have no Level 1 assets or liabilities as of September 30, 2013 or December 31, 2012. Our derivative contracts classified as Level 2 as of September 30, 2013 and December 31, 2012 consist of commodity price swaps and basis protection swaps, which are valued using an income approach. Future cash flows from the derivatives are estimated based on the difference between the fixed contract price and the underlying published forward market price, and are discounted at the LIBOR swap rate.

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

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

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

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

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

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

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

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Nonrecurring fair value measurements

Additions to the asset and liability associated with our asset retirement obligations are measured at fair value on a nonrecurring basis. Our asset retirement obligations consist of the estimated present value of future costs to plug and abandon or otherwise dispose of our oil and natural gas properties and related facilities. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, inflation rates, discount rates, and well life, all of which are Level 3 inputs according to the fair value hierarchy. The estimated future costs to dispose of properties added during the first nine months of 2013 and 2012 were escalated using an annual inflation rate of 2.95% and 2.95%, respectively, and discounted using our credit-adjusted risk-free interest rate of 6.90% and 6.70%, respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. During the nine months ended September 30, 2013 and 2012, additions to our asset retirement obligations were $1,036 and $551, respectively. See Note 6 for additional information regarding our asset retirement obligations.

Fair value of other financial instruments

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

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

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

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

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Counterparty credit risk

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

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

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

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

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Note 6: Asset retirement obligations

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

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

See Note 5 for additional information regarding fair value measurements.

Note 7: Stock-based compensation

Phantom Stock Plan and Restricted Stock Unit Plan

Effective January 1, 2004, we implemented a Phantom Unit Plan, which was revised on December 31, 2008 as the Second Amended and Restated Phantom Stock Plan (the “Phantom Plan”), to provide deferred compensation to certain key employees (the “Participants”). Phantom stock may be awarded to Participants in total up to 2% of the fair market value of the Company. No Participant may be granted, in the aggregate, more than 5% of the maximum number of phantom shares available for award. Under the Plan, awards vest on the fifth anniversary of the award date, but may also vest on a pro-rata basis following a Participant’s termination of employment with us due to death, disability, retirement or termination by us without cause. Also, phantom stock will vest if a change of control event occurs. Phantom shares are cash-settled within 120 days of the vesting date.

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

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

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

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

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

2010 Equity Incentive Plan

We adopted the Chaparral Energy, Inc. 2010 Equity Incentive Plan (the “2010 Plan”) on April 12, 2010. The 2010 Plan reserves a total of 86,301 shares of our class A common stock for awards issued under the 2010 Plan. All of our or our affiliates’ employees, officers, directors, and consultants, as defined in the 2010 Plan, are eligible to participate in the 2010 Plan.

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

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

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

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

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

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

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

Stock-based compensation cost

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

A portion of stock-based compensation cost associated with employees involved in our acquisition, exploration, and development activities has been capitalized as part of our oil and natural gas properties. The remaining cost is reflected in lease operating and general and administrative expenses in the consolidated statements of operations. We recognized stock-based compensation expense as follows for the periods indicated:

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

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

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Note 8: Common stock

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

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

Note 9: Related party transactions

CHK Energy Holdings, Inc., an indirect wholly owned subsidiary of Chesapeake Energy Corporation (“Chesapeake”), owns approximately 20% of our outstanding common stock. We participate in ownership of properties operated by Chesapeake, and we received revenues and incurred joint interest billings on these properties as follows:

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

In addition, Chesapeake participates in ownership of properties operated by us, and we paid revenues and recorded joint interest billings to Chesapeake on these properties as follows:

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

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

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

Note 10: Commitments and contingencies

Standby letters of credit (“Letters”) available under our senior secured revolving credit facility are used in lieu of surety bonds with various organizations for liabilities relating to the operation of oil and natural gas properties. We had various Letters outstanding totaling $920 as of September 30, 2013 and December 31, 2012. Interest on each Letter accrues at the lender’s prime rate plus applicable margin for all amounts paid by the lenders under the Letters. No amounts were paid by the lenders under the Letters, therefore we paid no interest on the Letters during the nine months ended September 30, 2013 or 2012.

Naylor Farms, Inc., individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C.

On June 7, 2011, Naylor Farms, Inc. (the “Plaintiff”), filed a complaint against us, alleging claims on behalf of itself and non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. The Plaintiff asserts class claims seeking recovery for underpayment of royalties, alleging damages in excess of $5,000. The Plaintiff also requests allowable interest, punitive damages, cancellation of leases, other equitable relief, and an award of attorney fees and costs. We have denied liability on the claims and raised arguments and defenses that, if accepted by the Court, will result in no loss to us. The case was stayed on August 9, 2012 to allow the U.S. Court of Appeals for the Tenth Circuit to decide two unrelated cases

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

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

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

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

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

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

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

Overview

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

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

Generally, our producing properties have declining production rates. Our reserve estimates as of December 31, 2012 reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 19%, 14% and 12% for the next three years. To grow our production and cash flow, we must find, develop and acquire new oil and natural gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire oil and natural gas reserves.

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

• cash flow available for capital expenditures;

• ability to borrow and raise additional capital;

• ability to service debt;

• quantity of oil and natural gas we can produce;

• quantity of oil and natural gas reserves; and

• operating results for oil and natural gas activities.

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

The following are material events that have impacted our liquidity or results of operations, and/or are expected to impact these items in future periods:

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

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

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

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

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

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Results of operations

Revenues and production

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

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

(1) Includes natural gas liquids.

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

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

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

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

Production volumes by area were as follows (MBoe):

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

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

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Derivative activities

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

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

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

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

(1) Includes natural gas liquids.

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

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

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

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

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

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

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

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

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

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

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Lease operating expenses 

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

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

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

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

Production taxes (which include ad valorem taxes) 

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

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

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

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

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

We adjust our DD&A rate on oil and natural gas properties each quarter for significant changes in our estimates of oil and natural gas reserves and costs, and thus our DD&A rate could change significantly in the future. DD&A on oil and natural gas properties increased $3.7 million for the third quarter of 2013 compared to the third quarter of 2012, of which $2.4 million was due to a higher rate per equivalent unit of production and $1.3 million was due to an increase in production. Our DD&A rate per equivalent unit of production increased $0.98 to $17.93 per Boe for the third quarter of 2013 primarily due to higher cost reserve additions and higher estimated future development costs for proved undeveloped reserves.

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

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

General and administrative expenses (“G&A”) 

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

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

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

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

Other income and expenses

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

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

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

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

Liquidity and capital resources

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

We believe that we will have sufficient funds available through our cash from operations and borrowing capacity under our revolving line of credit to meet our normal recurring operating needs, debt service obligations, capital requirements and contingencies for the next 12 months.

We pledge our producing oil and natural gas properties to secure our senior secured revolving credit facility. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. We have the capacity to utilize the available funds to supplement our operating cash flows as a financing source for our capital expenditures. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced, thus reducing funds available under the borrowing base. We mitigate a potential reduction in our borrowing base caused by a decrease in oil and natural gas prices through the use of commodity derivatives.

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Covenants set forth in the indentures for our Senior Notes, including the Adjusted Consolidated Net Tangible Asset debt incurrence test (the “ACNTA test”), limit the amount of secured debt we can incur. Certain thresholds set forth in the ACNTA test are principally reliant upon the levels of commodity prices for crude oil and natural gas at specified dates. The amount of secured debt permitted under our Senior Notes is set at a minimum of $500.0 million. We have the ability to borrow under our senior secured revolving credit facility, subject to maintaining a Current Ratio, as defined in our senior secured revolving credit facility, of not less than 1.0 to 1.0 and a Consolidated Net Debt to Consolidated EBITDAX ratio, as defined in our senior secured revolving credit facility, of not greater than 4.50 to 1.0 for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter. As of November 14, 2013, our availability under the borrowing base was limited to $352.2 million based on the Consolidated Net Debt to Consolidated EBITDAX ratio.

Sources and uses of cash

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

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

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

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

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

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

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

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

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

Senior Notes

The Senior Notes, which, as of September 30, 2013, include our 9.875% Senior Notes due 2020, our 8.25% Senior Notes due 2021, and our 7.625% Senior Notes due 2022, are our senior unsecured obligations, rank equally in right of payment with all our existing and future senior debt, and rank senior to all of our existing and future subordinated debt. The payment of the principal, interest and premium on the Senior Notes is fully and unconditionally guaranteed on a senior unsecured basis by our material existing and future domestic restricted subsidiaries, as defined in the indentures.

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

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

We and our restricted subsidiaries are subject to certain negative and financial covenants under the indentures governing the Senior Notes. The provisions of the indentures limit our and our restricted subsidiaries’ ability to, among other things:

• incur or guarantee additional debt, or issue preferred stock;

• pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated debt;

• make investments;

• incur liens on assets;

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

• engage in transactions with our affiliates;

• sell assets, including capital stock of our subsidiaries;

• consolidate, merge or transfer assets; and

• enter into other lines of business.

If we experience a change of control (as defined in the indentures governing the Senior Notes), or make certain asset sales, subject to certain conditions, we must give holders of the Senior Notes the opportunity to sell us their Senior Notes at 101% of the principal amount, plus accrued and unpaid interest.

Senior secured revolving credit facility

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

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

The Eurodollar rate is computed at the Adjusted LIBO Rate, defined as the rate applicable to dollar deposits in the London interbank market with a maturity comparable to the interest period (one, two, three or six months, selected by us) times a Statutory Reserve Rate multiplier, as defined in our senior secured revolving credit facility, plus a margin that varies from 1.50% to 2.50%, depending on our utilization percentage. Interest payments on Eurodollar borrowings are due the last day of the interest period, if shorter than three months or every three months.

Interest on loans subject to the ABR is computed as the greater of (1) the Prime Rate, as defined in our senior secured revolving credit facility, (2) the Federal Funds Effective Rate, as defined in our senior secured revolving credit facility, plus 0.50%, or (3) the Adjusted LIBO Rate, as defined in our senior secured revolving credit facility, plus 1%, plus a margin that varies from 0.50% to 1.50%, depending on our utilization percentage.

Commitment fees of 0.375% to 0.50%, depending on our utilization percentage, accrue on the unused portion of the borrowing base amount and are included as a component of interest expense. We have the right to make prepayments of the borrowings at any time without penalty or premium.

Our senior secured revolving credit facility contains restrictive covenants that may limit our ability, among other things, to:

• incur additional indebtedness;

• create or incur additional liens on our oil and natural gas properties;

• pay dividends in cash or other property, redeem our capital stock or prepay certain indebtedness;

• make investments in or loans to others;

• change our line of business;

• enter into operating leases;

• merge or consolidate with another person, or lease or sell all or substantially all of our assets;

• sell, farm-out or otherwise transfer property containing proved reserves;

• enter into transactions with affiliates;

• issue preferred stock;

• enter into negative pledge agreements or agreements restricting the ability of our subsidiaries to pay dividends;

• enter into or terminate certain swap agreements;

• amend our organizational documents; and

• amend, modify or waive under our permitted bond documents (i) any covenants that would make the terms materially more onerous to us or (ii) certain other provisions.

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Our senior secured revolving credit facility requires us to maintain a current ratio, as defined in our senior secured revolving credit facility, of not less than 1.0 to 1.0. The definition of current assets and current liabilities used for determination of the current ratio computed for loan compliance purposes differs from current assets and current liabilities determined in compliance with GAAP. Since compliance with financial covenants is a material requirement under our senior secured revolving credit facility, we consider the current ratio calculated under our senior secured revolving credit facility to be a useful measure of our liquidity because it includes the funds available to us under our senior secured revolving credit facility and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. At September 30, 2013 and December 31, 2012, our current ratio as computed using GAAP was 0.75 and 0.84, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 2.77 and 3.74, respectively. The following table reconciles our current assets and current liabilities using GAAP to the same items for purposes of calculating the current ratio for our loan compliance: 

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

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Our senior secured revolving credit facility, as amended, requires us to maintain a Consolidated Net Debt to Consolidated EBITDAX ratio, as defined in our senior secured revolving credit facility, of not greater than 4.50 to 1.0 for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter.

Our senior secured revolving credit facility also specifies events of default, including:

• our failure to pay principal or interest under our senior secured revolving credit facility when due and payable;

• our representations or warranties proving to be incorrect, in any material respect, when made or deemed made;

• our failure to observe or perform certain covenants, conditions or agreements under our senior secured revolving credit facility;

• our failure to make payments on certain other material indebtedness when due and payable;

• the occurrence of any event or condition that requires the redemption or repayment of, or an offer to redeem or repay, certain other material indebtedness prior to its scheduled maturity;

• the commencement of a voluntary or involuntary proceeding seeking liquidation, reorganization or other relief, or the appointment of a receiver, trustee, custodian or other similar official for us or our subsidiaries, and the proceeding or petition continues undismissed for 60 days or an order approving the foregoing is entered;

• our inability, admission or failure generally to pay our debts as they become due;

• the entry of a final, non-appealable judgment for the payment of money in excess of $5.0 million that remains undischarged for a period of 60 consecutive days;

• a Change of Control (as defined in our senior secured revolving credit facility); and

• the occurrence of a default under any permitted bond document, which such default continues unremedied or is not waived prior to the expiration of any applicable grace or cure under any permitted bond document.

If the outstanding borrowings under our senior secured revolving credit facility were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay a portion of our bank borrowings in the amount of the excess either in a lump sum within 30 days or in equal monthly installments over a six-month period, (2) to submit within 30 days additional oil and natural gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and natural gas properties within 30 days.

Capital Leases

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

Alternative capital resources

We have historically used cash flow from operations, debt financing, private issuances of common stock and asset sales as our primary sources of capital. In the future we may use additional sources such as additional asset sales, additional public or private issuances of common or preferred stock, or project financing. While we believe we would be able to obtain funds through one or more of these alternative sources, if needed, we cannot provide assurance that these resources would be available on terms acceptable to us.

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Non-GAAP financial measure and reconciliation

Management uses adjusted EBITDA as a supplemental financial measurement to evaluate our operational trends. Items excluded generally represent non-cash adjustments, the timing and amount of which cannot be reasonably estimated and are not considered by management when measuring our overall operating performance. In addition, adjusted EBITDA is generally consistent with the Consolidated EBITDAX calculation that is used in the covenant ratio required under our senior secured revolving credit facility described in the Liquidity and Capital Resources section of Management’s Discussion and Analysis of Financial Condition and Results of Operations. We consider compliance with this covenant to be material. Adjusted EBITDA is used as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to net income, as an indicator of our operating performance, as an alternative to cash flows from operating activities, or as a measure of liquidity. Adjusted EBITDA is not defined under GAAP and, accordingly, it may not be a comparable measurement to those used by other companies.

We define adjusted EBITDA as net income, adjusted to exclude (1) interest and other financing costs, net of capitalized interest, (2) income taxes, (3) depreciation, depletion and amortization, (4) unrealized (gain) loss on hedge reclassification adjustments, (5) non-cash change in fair value of non-hedge derivative instruments, (6) interest income, (7) stock-based compensation expense, (8) gain or loss on disposed assets, and (9) impairment charges and other significant, unusual non-cash charges.

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

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

Critical accounting policies

For a discussion of our critical accounting policies, which remain unchanged, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2012.

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

Recent accounting pronouncements

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

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Oil and natural gas prices. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. We cannot predict future oil and natural gas prices with any degree of certainty. Sustained declines in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and natural gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce our borrowing base under our senior secured revolving credit facility and adversely affect our liquidity and our ability to obtain capital for our acquisition, exploration and development activities. Based on our production for the nine months ended September 30, 2013, our gross revenues from oil and natural gas sales would change approximately $4.7 million for each $1.00 change in oil and natural gas liquid prices and $1.5 million for each $0.10 change in natural gas prices.

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

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

Collars contain a fixed floor price (purchased put) and ceiling price (sold call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party. A three-way collar contract consists of a standard collar contract plus a sold put with a price below the floor price of the collar. The sold put option requires us to make a payment to the counterparty if the market price is below the sold put option price. If the market price is greater than the sold put option price, the result is the same as it would have been with a standard collar contract only. By combining the collar contract with the sold put option, we are entitled to a net payment equal to the difference between the floor price of the standard collar and the sold put option price if the market price falls below the sold put option price. This strategy enables us to increase the floor and the ceiling price of the collar beyond the range of a traditional costless collar utilizing the value associated with the sale of a put option.

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

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

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

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

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

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

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

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

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

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

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

Interest rates. All of the outstanding borrowings under our senior secured revolving facility as of September 30, 2013 are subject to market rates of interest as determined from time to time by the banks. We may elect to borrow under our senior secured revolving credit facility at either Eurodollar rate, which is linked to LIBOR, or the ABR. Loans subject to the ABR bear interest at a fluctuating rate that is linked to the greater of (1) the Prime Rate, as defined in our senior secured revolving credit facility, (2) the Federal Funds Effective Rate, as defined in the senior secured revolving credit facility, plus 0.50%, or (3) the Adjusted LIBO rate, as defined in our senior secured revolving credit facility, plus 1%. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $500.0 million, equal to our borrowing base at September 30, 2013, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $5.0 million.

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ITEM 4. CONTROLS AND PROCEDURES

Disclosure controls and procedures

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

Internal control over financial reporting

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

PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Naylor Farms, Inc., individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C.

On June 7, 2011, Naylor Farms, Inc. (the “Plaintiff”), filed a complaint against us, alleging claims on behalf of itself and non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. The Plaintiff asserts class claims seeking recovery for underpayment of royalties, alleging damages in excess of $5.0 million. The Plaintiff also requests allowable interest, punitive damages, cancellation of leases, other equitable relief, and an award of attorney fees and costs. We have denied liability on the claims and raised arguments and defenses that, if accepted by the Court, will result in no loss to us. The case was stayed on August 9, 2012 to allow the U.S. Court of Appeals for the Tenth Circuit to decide two unrelated cases that had issues similar to this case. The Tenth Circuit issued its opinions in those unrelated cases on July 9, 2013 and mandates were issued July 31, 2013. On or about October 1, 2013, the Court lifted the stay and entered a new scheduling order. The parties are conducting additional discovery and Planitff’s Motion for Class Certification is due August 10, 2014. Because a class has not been certified, we are not yet able to estimate a possible loss, or range of possible loss, if any.

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

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

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

ITEM 1A. RISK FACTORS

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

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ITEM 6. EXHIBITS

Exhibit No.	Description
10.1	Asset Purchase Agreement dated as of October 11, 2013, by and between Chaparral Energy L.L.C. and Cabot Oil & Gas Corporation
10.2	Thirteenth Amendment to Eighth Restated Credit Agreement dated as of October 29, 2013
31.1	Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2	Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1	Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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

Date: November 14, 2013

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EXHIBIT INDEX

Exhibit No.	Description
10.1	Asset Purchase Agreement dated as of October 11, 2013, by and between Chaparral Energy L.L.C. and Cabot Oil & Gas Corporation
10.2	Thirteenth Amendment to Eighth Restated Credit Agreement dated as of October 29, 2013
31.1	Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2	Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1	Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

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