UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 ____________________________

Form 10-Q

____________________________

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

For the quarterly period ended March 31, 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  ¨    No  ý

(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 May 10, 2013:

Class	Number of shares
Class A Common Stock, $0.01 par value	72,794
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 March 31, 2013 (unaudited) and December 31, 2012	6
Consolidated statements of operations for the three months ended March 31, 2013 and 2012 (unaudited)	8
Consolidated statements of comprehensive (loss) income for the three months ended March 31, 2013 and 2012 (unaudited)	9
Consolidated statements of cash flows for the three months ended March 31, 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	29
Overview	29
Results of operations	31
Liquidity and capital resources	37
Non-GAAP financial measure and reconciliation	42
Critical accounting policies	42
Recent accounting pronouncements	42
Item 3. Quantitative and Qualitative Disclosures about Market Risk	43
Item 4. Controls and Procedures	46
Part II. OTHER INFORMATION	46
Item 1. Legal Proceedings	46
Item 1A. Risk Factors	46
Item 6. Exhibits	47
Signatures	48
EX-10.1 (Eleventh Amendment to Eighth Restated Credit Agreement dated as of April 17, 2013)
EX-10.2 (Twelfth Amendment to Eighth Restated Credit Agreement dated as of May 6, 2013)
EX-10.3 (Form of Amendment No. 1 to Employment Agreement for Corporate Officers)
EX-10.4 (Amended and Restated Form of Change of Control Severance Agreement for Corporate Officers)
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, 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.

• 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.

• SEC. The Securities and Exchange Commission.

5

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets

	March 31, 2013			December 31, 2012
(dollars in thousands, except per share data)	(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	8,061		$	29,819
Accounts receivable, net	83,034			77,307
Inventories, net	15,662			10,510
Prepaid expenses	2,438			3,465
Derivative instruments	16,914			42,516
Total current assets	126,109			163,617
Property and equipment—at cost, net	64,687			65,601
Oil and natural gas properties, using the full cost method:
Proved	2,923,695			2,860,611
Unevaluated (excluded from the amortization base)	220,011			162,921
Accumulated depreciation, depletion, amortization and impairment	(1,331,137		)	(1,290,356		)
Total oil and natural gas properties	1,812,569			1,733,176
Derivative instruments	3,289			517
Assets held for sale	5,689			5,689
Other assets	38,003			38,952
	$	2,050,346		$	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
	March 31, 2013		December 31, 2012
(dollars in thousands, except per share data)	(unaudited)
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	123,769	$	101,598
Accrued payroll and benefits payable	15,453		19,655
Accrued interest payable	33,839		24,131
Revenue distribution payable	18,851		18,152
Current maturities of long-term debt	2,803		3,746
Derivative instruments	3,495		436
Deferred income taxes	13,607		26,872
Total current liabilities	211,817		194,590
Long-term debt, less current maturities	1,313,610		1,289,656
Derivative instruments	1,745		2,192
Stock-based compensation	3,003		3,042
Asset retirement obligations, net of current portion	46,586		46,314
Deferred income taxes	17,603		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 73,117 and 67,991 shares issued and outstanding as of March 31, 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	422,934		422,434
Retained earnings	15,996		17,186
Accumulated other comprehensive income, net of taxes	17,038		23,223
	455,982		462,857
	$	2,050,346	$	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
	March 31,
	2013			2012
(in thousands)	(unaudited)			(unaudited)
Revenues:
Oil and natural gas sales	$	127,512		$	127,789
Gain from oil hedging activities	10,003			12,423
Total revenues	137,515			140,212
Costs and expenses:
Lease operating	33,977			30,949
Production taxes	7,880			8,290
Depreciation, depletion and amortization	43,916			36,932
General and administrative	14,008			13,449
Total costs and expenses	99,781			89,620
Operating income	37,734			50,592
Non-operating expense:
Interest expense	(24,291		)	(24,156		)
Non-hedge derivative losses	(15,546		)	(10,463		)
Other income, net	226			5
Net non-operating expense	(39,611		)	(34,614		)
(Loss) income before income taxes	(1,877		)	15,978
Income tax (benefit) expense	(687		)	6,196
Net (loss) income	$	(1,190	)	$	9,782

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
	March 31,
	2013			2012
(in thousands)	(unaudited)			(unaudited)
Net (loss) income	$	(1,190	)	$	9,782
Other comprehensive loss
Reclassification adjustment for hedge gains included in gain from oil hedging activities in the consolidated statements of operations	(10,003		)	(12,423		)
Income tax benefit related to other comprehensive loss	3,818			4,744
Other comprehensive loss, net of tax	(6,185		)	(7,679		)
Comprehensive (loss) income	$	(7,375	)	$	2,103

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

9

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows

	Three months ended
	March 31,
	2013			2012
(in thousands)	(unaudited)			(unaudited)
Cash flows from operating activities
Net income (loss)	$	(1,190	)	$	9,782
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion & amortization	43,916			36,932
Deferred income taxes	(746		)	6,161
Gain from oil hedging activities	(10,003		)	(12,423		)
Non-hedge derivative losses	15,546			10,463
(Gain) loss on sale of assets	(95		)	95
Other	675			751
Change in assets and liabilities
Accounts receivable	(210		)	(1,830		)
Inventories	(4,985		)	(4,367		)
Prepaid expenses and other assets	1,445			1,559
Accounts payable and accrued liabilities	1,879			(4,539		)
Revenue distribution payable	699			(2,792		)
Stock-based compensation	1,245			1,089
Net cash provided by operating activities	48,176			40,881
Cash flows from investing activities
Purchase of property and equipment and oil and natural gas properties	(109,779		)	(98,403		)
Proceeds from dispositions of property and equipment and oil and natural gas properties	6,833			1,856
Settlement of non-hedge derivative instruments	9,896			2,257
Other	—			22
Net cash used in investing activities	(93,050		)	(94,268		)
Cash flows from financing activities
Proceeds from long-term debt	24,868			42,176
Repayment of long-term debt and capital lease obligations	(1,752		)	(877		)
Net cash provided by financing activities	23,116			41,299
Net decrease in cash and cash equivalents	(21,758		)	(12,088		)
Cash and cash equivalents at beginning of period	29,819			34,589
Cash and cash equivalents at end of period	$	8,061		$	22,501

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 March 31, 2013, and for the three months ended March 31, 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 months ended March 31, 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 March 31, 2013, cash with a recorded balance totaling $6,875 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 March 31, 2013 and December 31, 2012:

	March 31, 2013			December 31, 2012
Joint interests	$	29,508		$	19,282
Accrued oil and natural gas sales	46,713			50,814
Derivative settlements	7,796			8,013
Other	493			472
Allowance for doubtful accounts	(1,476		)	(1,274		)
	$	83,034		$	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 March 31, 2013 and December 31, 2012 consisted of the following:

	March 31, 2013			December 31, 2012
Equipment inventory	$	13,407		$	8,047
Oil and natural gas product	2,961			3,175
Inventory valuation allowance	(706		)	(712		)
	$	15,662		$	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 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. As of March 31, 2013, work in progress costs are included in unevaluated oil and natural gas properties since there are no reserves allocated to these properties. Costs not subject to amortization as of March 31, 2013 included $70,526 of capital costs incurred for undeveloped acreage, $102,427 for the construction of CO₂ delivery pipelines and facilities and $47,058 for wells and facilities in progress pending determination. As of December 31, 2012, costs not subject to amortization consisted of capital costs incurred for undeveloped acreage of $64,840, $84,183 for the construction of CO₂ delivery pipelines and facilities 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 estimated future net revenues discounted at 10% (“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 March 31, 2013 was estimated based on average first day of the month prices of $92.63 per Bbl of oil and $2.95 per Mcf of gas for the twelve months ended March 31, 2013. The cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties as of March 31, 2013, and no impairment was necessary. A decline in oil and natural gas prices subsequent to March 31, 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.

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.

12

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.

Recently adopted accounting pronouncements

In December 2011, the 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.

13

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

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

	Three months ended March 31,
	2013			2012
Net cash provided by operating activities included:
Cash payments for interest	$	16,787		$	31,233
Interest capitalized	(3,628		)	(710		)
Cash payments for interest, net of amounts capitalized	$	13,159		$	30,523
Non-cash investing activities included:
Asset retirement costs capitalized	$	76		$	20
Oil and natural gas properties acquired through increase (decrease) in accounts payable and accrued liabilities	$	18,502		$	17,505

14

Note 3: Long-term debt

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

	March 31, 2013		December 31, 2012
9.875% Senior Notes due 2020, net of discount of $5,843 and $5,969 at March 31, 2013 and December 31, 2012, respectively	$	294,157	$	294,031
8.25% Senior Notes due 2021	400,000		400,000
7.625% Senior Notes due 2022, including premium of $6,400 and $6,631 at March 31, 2013 and December 31, 2012, respectively	556,400		556,631
Senior secured revolving credit facility	49,000		25,000
Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 2.54% to 5.46%, due April 2013 through December 2028; collateralized by real property	11,557		12,596
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.00% to 6.99%, due April 2013 through February 2018; collateralized by automobiles, machinery and equipment	5,299		5,144
	1,316,413		1,293,402
Less current maturities	2,803		3,746
	$	1,313,610	$	1,289,656

Senior Notes

The Senior Notes, which as of March 31, 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. Effective April 17, 2013, the borrowing base was reaffirmed at $500,000 through November 1, 2013.

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 March 31, 2013 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 depending on our utilization percentage. During the three months ended March 31, 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 three months ended March 31, 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 March 31, 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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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 commodity price swaps, enhanced swaps, costless collars, 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.

An enhanced swap contract consists of an above-market swap contract plus a put option contract sold by us (sold put) with a price below the swap. The sold put requires us to make a payment to the counterparty if the market price is below the sold put price. 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. By combining the swap contract with the sold put option, we are entitled to a net payment equal to the difference between the swap price and the sold put option price if the market price falls below the sold put option price. This strategy enables us to increase the swap price beyond the range of a traditional swap utilizing the value associated with the sale of a put option.

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

We 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. Our outstanding derivative instruments as of March 31, 2013 are summarized below:

	Oil derivatives
	Swaps		Enhanced swaps					Three-way collars
	Volume MBbls	Weighted average fixed price per Bbl	Volume MBbls	Weighted average fixed price per Bbl				Volume MBbls	Weighted average fixed price per Bbl
				Sold puts		Swaps			Sold puts		Purchased puts		Sold calls
2013	980	96.11	—	$	—	$	—	2,780	$	77.82	$	99.89	$	114.22
2014	480	93.73	840	80.00		98.62		2,400	77.50		93.25		101.94
	1,460		840					5,180

	Natural gas swaps			Natural gas basis protection swaps
	Volume BBtu	Weighted average fixed price  per MMBtu		Volume BBtu	Weighted average fixed price  per MMBtu
2013	14,810	$	4.18	12,350	$	0.20
2014	17,520	4.01		14,090	0.23
2015	9,600	4.25		—	—
	41,930			26,440

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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 March 31, 2013								As of December 31, 2012
	Assets		Liabilities			Net value			Assets		Liabilities			Net value
Natural gas swaps	$	5,874	$	(9,309	)	$	(3,435	)	$	13,642	$	(1,487	)	$	12,155
Oil swaps	2,675		(2,831		)	(156		)	4,957		(1,339		)	3,618
Oil enhanced swaps	2,031		—			2,031			—		—			—
Oil collars	17,948		(2		)	17,946			27,411		(1,180		)	26,231
Natural gas basis differential swaps	—		(1,423		)	(1,423		)	—		(1,599		)	(1,599		)
Total derivative instruments	28,528		(13,565		)	14,963			46,010		(5,605		)	40,405
Less:
Netting adjustments (1)	8,325		(8,325		)	—			2,977		(2,977		)	—
Current portion asset (liability)	16,914		(3,495		)	13,419			42,516		(436		)	42,080
	$	3,289	$	(1,745	)	$	1,544		$	517	$	(2,192	)	$	(1,675	)

___________

(1) 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 March 31, 2013 and December 31, 2012, respectively, AOCI consists of deferred gains of $27,131 ($17,038 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 March 31, 2013 and December 31, 2012 were as follows:

	March 31, 2013		December 31, 2012
Derivative settlements receivable included in accounts receivable	$	7,796	$	8,013
Derivative settlements payable included in accounts payable and accrued liabilities	$	145	$	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 (loss) 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 in the consolidated statements of operations are comprised of the following:

	Three months ended
	March 31,
	2013			2012
Change in fair value of commodity price swaps	$	(19,364	)	$	(3,985	)
Change in fair value of enhanced swaps	2,031			—
Change in fair value of collars	(8,285		)	(9,108		)
Change in fair value of natural gas basis differential contracts	176			373
Receipts from settlement of commodity price swaps	4,525			2,701
Receipts from settlement of collars	5,731			33
Payments on settlement of natural gas basis differential contracts	(360		)	(477		)
	$	(15,546	)	$	(10,463	)

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.

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

Recurring fair value measurements

Our financial instruments recorded at fair value on a recurring basis consist of commodity derivative contracts (see Note 4). We have no Level 1 assets or liabilities as of March 31, 2013 or December 31, 2012. Our derivative contracts classified as Level 2 as of March 31, 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 March 31, 2013, our derivative contracts classified as Level 3 consisted of enhanced swaps and three-way collars. 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 March 31, 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 0.56% and 0.32% as of March 31, 2013 and December 31, 2012, respectively.

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

	As of March 31, 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)	$	8,549		$	(13,563	)	$	(5,014	)	$	18,599		$	(4,425	)	$	14,174
Significant unobservable inputs (Level 3)	19,979			(2		)	19,977			27,411			(1,180		)	26,231
Netting adjustments (1)	(8,325		)	8,325			—			(2,977		)	2,977			—
	$	20,203		$	(5,240	)	$	14,963		$	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 three months ended March 31, 2013 and 2012 were: 

	For the three months ended March 31,
Net derivative assets (liabilities)	2013			2012
Beginning balance	$	26,231		$	5,049
Realized and unrealized losses included in non-hedge derivative losses	(523		)	(9,075		)
Settlements received	(5,731		)	(33		)
Ending balance	$	19,977		$	(4,059	)
Gains (losses) relating to instruments still held at the reporting date included in non-hedge derivative losses for the period	$	1,393		$	(8,602	)

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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 three 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 6.40% and 7.50%, respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. During the three months ended March 31, 2013 and 2012, additions to our asset retirement obligations were $76 and $20, 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 March 31, 2013 and December 31, 2012 were as follows:

	March 31, 2013				December 31, 2012
Level 2	Carrying value		Estimated fair value		Carrying value		Estimated fair value
9.875% Senior Notes due 2020	$	294,157	$	347,625	$	294,031	$	341,250
8.25% Senior Notes due 2021	400,000		453,800		400,000		434,000
7.625% Senior Notes due 2022	556,400		600,970		556,631		574,750
Senior secured revolving credit facility	49,000		49,000		25,000		25,000
Other secured long-term debt	16,856		16,856		17,740		17,740
	$	1,316,413	$	1,468,251	$	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 March 31, 2013, the counterparties to our open derivative contracts consisted of nine financial institutions, of which eight were subject to our rights of offset under our senior secured revolving credit facility.

The following table summarizes our derivative assets and liabilities which are offset in the 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 March 31, 2013
Derivative assets	$	28,528		$	(9,484	)	$	19,044		$	(8,188	)	$	10,856
Derivative liabilities	(13,565		)	9,484			(4,081		)	—			(4,081		)
	$	14,963		$	—		$	14,963		$	(8,188	)	$	6,775
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 $13,565 at March 31, 2013.

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Note 6: Asset retirement obligations

The following table provides a summary of our asset retirement obligation activity during the three months ended March 31, 2013 and 2012.

	For the three months ended March 31,
	2013			2012
Beginning balance	$	49,214		$	46,493
Liabilities incurred in current period	76			20
Liabilities settled in current period	(811		)	(254		)
Accretion expense	1,007			974
	49,486			47,233
Less current portion	2,900			2,900
	$	46,586		$	44,333

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 three months ended March 31, 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	$	—	—				$	12.83	248,361
Vested	$	16.52	(19,976	)	$	256	$	17.84	(43,354	)	$	556
Forfeited	$	19.02	(728	)			$	14.78	(4,801	)
Unvested and outstanding at March 31, 2013	$	16.96	64,060				$	14.04	352,115

Based on an estimated fair value of $12.91 per phantom share and RSU as of March 31, 2013, the aggregate intrinsic value of the unvested phantom shares and RSUs outstanding was $5,373.

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 resulted in incremental compensation cost of $4,397, which will be recognized over the five-year requisite service period using the accelerated method.

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A summary of our restricted stock activity during the three months ended March 31, 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	$	626.03	2,058				$	181.59	3,984
Vested	$	707.92	(237	)	$	134	$	—	—
Forfeited	$	603.57	(309	)			$	367.76	(484	)
Modified	$	626.00	11,166				$	324.47	(11,166	)
Unvested and total outstanding at March 31, 2013	$	636.55	22,159				$	312.22	48,158

During the three months ended March 31, 2013 and 2012, respectively, we repurchased and canceled 123 and 83 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 $13,872 as of March 31, 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
	March 31,
	2013			2012
Stock-based compensation cost	$	1,893		$	1,804
Less: stock-based compensation cost capitalized	(579		)	(653		)
Stock-based compensation expense	$	1,314		$	1,151

Payments for stock-based compensation were $69 and $62 during the three months ended March 31, 2013 and 2012, respectively. As of March 31, 2013 and December 31, 2012, accrued payroll and benefits payable included $3,999 and $2,636, respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized compensation cost of approximately $22,108 is expected to be recognized over a weighted-average period of 2.84 years.

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Note 8: Common stock

The following is a summary of the changes in our common shares outstanding during the three months ended March 31, 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	6,042		—	—	—	—	—	—	6,042
Restricted stock repurchased	(123	)	—	—	—	—	—	—	(123	)
Restricted stock forfeitures	(793	)	—	—	—	—	—	—	(793	)
Shares outstanding at March 31, 2013	73,117		357,882	209,882	279,999	504,276	1	3	1,425,160

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 March 31,
	2013			2012
Revenues	$	1,380		$	945
Joint interest billings	$	(923	)	$	(472	)

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

	Three months ended March 31,
	2013			2012
Revenues	$	(503	)	$	(623	)
Joint interest billings	$	4,267		$	1,537

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

	March 31, 2013		December 31, 2012
Amounts receivable from Chesapeake	$	3,378	$	2,071
Amounts payable to Chesapeake	$	364	$	864

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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 March 31, 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 three months ended March 31, 2013 or 2012.

Naylor Farms, Inc. 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 matter is currently stayed pending resolution of unrelated cases currently on appeal with the U.S. Court of Appeals for the Tenth Circuit. These cases are expected to influence the ruling on class certification in the Plaintiff’s case. At the time that the matter was stayed no class had been certified and discovery was ongoing. 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.

Note 11: Subsequent Events

We entered into an agreement on May 8, 2013, to purchase certain properties located in Oklahoma for a cash price of approximately $11,700. The purchase is expected to close by June 18, 2013.

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

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

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

Overview

We are a growing independent oil and natural gas production and exploitation company. Our core operations consist of drilling for and production of oil and natural gas from conventional and unconventional reservoirs as well as a focus on tertiary operations through enhanced oil recovery (“EOR”) projects utilizing CO₂ and polymer in the Mid-Continent and Permian Basin areas. We maintain a portfolio of proved and unproved reserves, development and exploratory drilling opportunities, and EOR projects.

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 first quarter of 2013, production increased 6% to 2,243 MBoe compared to production of 2,118 MBoe during the first quarter of 2012, primarily due to our EOR and drilling activity. This increase in production was offset by a 6% decrease in the average sales price before hedging and, as a result, revenue from oil and natural gas sales declined slightly in the first quarter of 2013 as compared to the same period in 2012. Additionally, due primarily to changes in the NYMEX forward commodity price curves, our loss on non-hedge derivatives increased to $15.5 million in the first quarter of 2013 compared to a loss of $10.5 million in the first quarter of 2012. As a result of these and other factors, we reported a net loss of $1.2 million during the first quarter of 2013 compared to net income of $9.8 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:

• Capital expenditures. Our oil and natural gas property capital expenditure budget for 2013 is set at $401.0 million. The 2013 capital expenditure budget continues our focus on the development of our EOR assets and drilling of horizontal wells in our repeatable resource plays. Investing in EOR reduces near-term growth opportunities but enhances longer-term growth and is consistent with our strategy of driving near-term growth through drilling and long-term growth through EOR development.

• Asset acquisition. We entered into an agreement on May 8, 2013, to purchase certain properties located in Oklahoma for a cash price of approximately $11.7 million. The purchase is expected to close by June 18, 2013.

• 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 $4.4 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
	March 31,
	2013		2012
Oil and natural gas sales (in thousands)
Oil (1)	$	112,312	$	116,303	(3.4	)%
Natural gas	15,200		11,486		32.3	%
Total	$	127,512	$	127,789	(0.2	)%
Production
Oil (MBbls) (1)	1,437		1,316		9.2	%
Natural gas (MMcf)	4,836		4,812		0.5	%
MBoe	2,243		2,118		5.9	%
Average sales prices (excluding derivative settlements)
Oil per Bbl (1)	$	78.16	$	88.38	(11.6	)%
Natural gas per Mcf	$	3.14	$	2.39	31.4	%
Boe	$	56.85	$	60.33	(5.8	)%

___________

(1) Includes natural gas liquids.

For the three months ended March 31, 2013 compared to the three months ended March 31, 2012, revenues from oil and natural gas sales were relatively flat primarily due to a 6% decrease in average price per Boe offset by the 6% increase in sales volumes. Production for the three months ended March 31, 2013 increased compared to the three months ended March 31, 2012 primarily due to our drilling and development activity in our EOR Project Areas, Cleveland Sand Play, Granite Wash Play and Northern Oklahoma Mississippi Play (“NOMP”).

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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
	March 31, 2013 vs. 2012
(in thousands)	Sales change			Percentage change in sales
Change in oil sales due to:
Prices	$	(14,685	)	(12.6	)%
Production	10,694			9.2	%
Total change in oil sales	$	(3,991	)	(3.4	)%
Change in natural gas sales due to:
Prices	$	3,657		31.8	%
Production	57			0.5	%
Total change in natural gas sales	$	3,714		32.3	%

Production volumes by area were as follows (MBoe):

	Three months ended		Percentage change
	March 31,
	2013	2012
Enhanced Oil Recovery Project Areas	368	325	13.2	%
Mid-Continent Area	1,417	1,253	13.1	%
Permian Basin Area	286	311	(8.0	)%
Other	172	229	(24.9	)%
Total	2,243	2,118	5.9	%

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 Cleveland Sand Play, Granite Wash Play and NOMP. 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 commodity price swaps, enhanced swaps, costless collars, 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
	March 31,
	2013			2012
Oil (per Bbl) (1):
Before derivative settlements	$	78.16		$	88.38
After derivative settlements	$	82.55		$	85.11
Post-settlement to pre-settlement price	105.6		%	96.3		%
Natural gas (per Mcf):
Before derivative settlements	$	3.14		$	2.39
After derivative settlements	$	3.88		$	3.75
Post-settlement to pre-settlement price	123.6		%	156.9		%

___________

(1) Includes natural gas liquids.

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

(in thousands)	March 31, 2013			December 31, 2012
Derivative assets (liabilities):
Natural gas swaps	$	(3,435	)	$	12,155
Oil swaps	(156		)	3,618
Oil enhanced swaps	2,031			—
Oil collars	17,946			26,231
Natural gas basis differential swaps	(1,423		)	(1,599		)
Net derivative assets	$	14,963		$	40,405

We discontinued hedge accounting effective April 1, 2010. Net derivative gains (losses) attributable to derivatives previously subject to hedge accounting were deferred through accumulated other comprehensive income (“AOCI”). As of March 31, 2013 and December 31, 2012, respectively, AOCI consists of deferred gains of $27.1 million ($17.0 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 (losses) gains 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 March 31,
	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	$	10,003		$	—		$	12,423		$	—
Non-hedge derivative (losses) gains:
Oil swaps, enhanced swaps, and collars	$	(10,028	)	$	6,316		$	(18,852	)	$	(4,297	)
Natural gas swaps	(15,590		)	3,940			5,759			7,031
Natural gas basis differential contracts	176			(360		)	373			(477		)
Non-hedge derivative (losses) gains	$	(25,442	)	$	9,896		$	(12,720	)	$	2,257
Total (losses) gains from derivative activities	$	(15,439	)	$	9,896		$	(297	)	$	2,257

During the three months ended March 31, 2013 and March 31, 2012, we reclassified into earnings gains of $10.0 million and $12.4 million, respectively. These gains were associated with oil swaps for which hedge accounting was previously discontinued.

We recognized net non-hedge derivative losses of $15.5 million and $10.5 million during the three months ended March 31, 2013 and March 31, 2012, respectively. The fluctuation in non-hedge derivative (losses) gains 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 $(5.5) million and $2.0 million during the three months ended March 31, 2013 and March 31, 2012, respectively.

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Lease operating expenses 

	Three months ended March 31,				Percentage change
	2013		2012
Lease operating expenses (in thousands)	$	33,977	$	30,949	9.8	%
Lease operating expenses per Boe	$	15.15	$	14.61	3.7	%

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 $3.0 million, or $0.54 per Boe, during the three months ended March 31, 2013, compared to the three months ended March 31, 2012, primarily due to additional workovers, increased oilfield service costs and new wells being brought online. Workover and well work costs for operated properties increased to $8.5 million for the three months ended March 31, 2013 compared to $6.5 million for the same period in 2012.

Production taxes (which include ad valorem taxes) 

	Three months ended March 31,				Percentage change
	2013		2012
Production taxes (in thousands)	$	7,880	$	8,290	(4.9	)%
Production taxes per Boe	$	3.51	$	3.91	(10.2	)%

Production taxes generally change in proportion to oil and natural gas sales. The decreases in production taxes per Boe during the three months ended March 31, 2013 compared to the three months ended March 31, 2012 were primarily due to the decreases in average realized prices during the periods.

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

	Three months ended March 31,				Percentage change
	2013		2012
DD&A (in thousands):
Oil and natural gas properties	$	40,782	$	33,545	21.6	%
Property and equipment	2,127		2,413		(11.9	)%
Accretion of asset retirement obligation	1,007		974		3.4	%
Total DD&A	$	43,916	$	36,932	18.9	%
DD&A per Boe:
Oil and natural gas properties	$	18.18	$	15.84	14.8	%
Other fixed assets	$	1.40	$	1.60	(12.5	)%
Total DD&A per Boe	$	19.58	$	17.44	12.3	%

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 $7.2 million for the first quarter of 2013 compared to the first quarter of 2012, of which $5.2 million was due to a higher rate per equivalent unit of production and $2.0 million was due to an increase in production. Our DD&A rate per equivalent unit of production increased $2.34 to $18.18 per Boe for the first quarter of 2013 primarily due to a decrease in reserves resulting from lower commodity prices combined with higher estimated future development costs for proved undeveloped reserves and higher cost reserve additions.

As of March 31, 2013, our unevaluated properties excluded from amortization included costs of $102.4 million associated with the construction of gathering and compression facilities at Coffeyville, Kansas and a 68-mile pipeline to transport the CO₂ to the Burbank field (the “Coffeyville assets”). These assets are expected to be placed in operation during the second quarter of 2013. If the Coffeyville assets had been included in the amortization base at January 1, 2013, our DD&A rate on oil and natural gas properties would have been approximately $18.86 per Boe for the first quarter of 2013.

General and administrative expenses (“G&A”) 

	Three months ended March 31,						Percentage change
	2013			2012
G&A (in thousands):
Gross G&A expenses	$	19,005		$	18,044		5.3	%
Capitalized exploration and development costs	(4,997		)	(4,595		)	8.7	%
Net G&A expenses	$	14,008		$	13,449		4.2	%
Average G&A expense per Boe	$	6.25		$	6.35		(1.6	)%

G&A expenses increased 4.2% primarily due to increased compensation and benefit costs related to the competitive nature of our market and our increased activity, along with other expenses and general inflation offset partially by decreased professional services related to certain projects and initiatives that phased out by the end of 2012. G&A expenses decreased by $0.10 per Boe for the first quarter of 2013 compared to the first quarter of 2012 due primarily to the increase in production.

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Other income and expenses

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

	Three months ended
	March 31,
(in thousands)	2013			2012
8.875% Senior Notes due 2017	$	—		$	7,453
9.875% Senior Notes due 2020	7,655			7,630
8.25% Senior Notes due 2021	8,402			8,390
7.625% Senior Notes due 2022	10,510			—
Senior secured revolving credit facility	127			56
Bank fees and other interest	1,225			1,337
Capitalized interest	(3,628		)	(710		)
Total interest expense	$	24,291		$	24,156
Average long-term borrowings	$	1,300,309		$	1,052,511

Total interest expense for the three months endedMarch 31, 2013 was relatively flat compared to the same period in 2012 as our increased levels of borrowing were offset by higher capitalized interest, primarily associated with the construction of the Coffeyville assets. These assets are expected to be placed into operation during the second quarter of 2013, which will reduce capitalized interest and increase interest expense in future periods.

Liquidity and capital resources

Historically, our primary sources of liquidity have been cash generated from our operations, debt, and private equity sales. As of March 31, 2013, we had cash and cash equivalents of $8.1 million and had borrowed $49.0 million under our senior secured revolving credit facility with a borrowing base of $500.0 million. 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.

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 May 10, 2013, our availability under the borrowing base was limited to $218.1 million based on the Consolidated Net Debt to Consolidated EBITDAX ratio.

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Sources and uses of cash

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

	Three months ended
	March 31,
(in thousands)	2013			2012
Cash flows provided by operating activities	$	48,176		$	40,881
Cash flows used in investing activities	(93,050		)	(94,268		)
Cash flows provided by financing activities	23,116			41,299
Net decrease in cash during the period	$	(21,758	)	$	(12,088	)

Substantially all of our cash flow from operating activities is from the production and sale of oil and natural gas, reduced or increased by associated hedging activities. Cash flows from operating activities were 18% higher in the three months ended March 31, 2013 than they were in the same period of 2012 primarily due to timing differences of interest payments required in the first quarter.

We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. For the three months ended March 31, 2013 and 2012, cash flows provided by operating activities were approximately 44% and 42%, 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 three months ended March 31, 2013 are detailed below:

(in thousands)	EOR Project Areas		Mid-Continent Area		Permian Basin Area		Other		Total		Budgeted 2013 Capital Expenditures
Acquisitions	$	77	$	7,122	$	—	$	100	$	7,299	$	25,000
Drilling	1,653		70,992		1,009		—		73,654		234,000
Enhancements	10,437		4,578		1,586		737		17,338		55,000
Pipeline and field infrastructure	26,207		—		—		—		26,207		67,000
CO2 purchases	2,738		—		—		—		2,738		20,000
Total	$	41,112	$	82,692	$	2,595	$	837	$	127,236	$	401,000

In addition to the capital expenditures for oil and natural gas properties, we spent approximately $1.4 million for property and equipment during the three months ended March 31, 2013.

During the three months ended March 31, 2013 and 2012, we received net derivative settlements totaling $9.9 million and $2.3 million, respectively. Primarily as a result of our net capital investments and derivative settlements, cash flows used in investing activities were $93.1 million and $94.3 million during the three months ended March 31, 2013 and 2012, respectively.

Cash flows provided by financing activities were $23.1 million and $41.3 million during the three months ended March 31, 2013 and 2012, respectively, primarily due to borrowings under our senior secured revolving credit facility.

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Senior Notes

The Senior Notes, which as of March 31, 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. Effective April 17, 2013, the borrowing base was reaffirmed at $500.0 million through November 1, 2013.

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 March 31, 2013, the balance outstanding under our senior secured revolving credit facility was $49.0 million, all of which was subject to the Eurodollar rate. As of May 10, 2013, we have drawn down $99.0 million under our senior secured revolving credit facility.

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.

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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.

Our senior secured revolving credit facility requires us to maintain a current ratio, as defined in our senior secured revolving credit facility, of not less than 1.0 to 1.0. The definition of current assets and current liabilities used for determination of the current ratio computed for loan compliance purposes differs from current assets and current liabilities determined in compliance with GAAP. Since compliance with financial covenants is a material requirement under our senior secured revolving credit facility, we consider the current ratio calculated under our senior secured revolving credit facility to be a useful measure of our liquidity because it includes the funds available to us under our senior secured revolving credit facility and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. At March 31, 2013 and December 31, 2012, our current ratio as computed using GAAP was 0.60 and 0.84, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 2.97 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)	March 31, 2013			December 31, 2012
Current assets per GAAP	$	126,109		$	163,617
Plus—Availability under senior secured revolving credit facility	450,080			474,080
Less—Short-term derivative instruments	(16,914		)	(42,516		)
Current assets as adjusted	$	559,275		$	595,181
Current liabilities per GAAP	$	211,817		$	194,590
Less—Short term derivative instruments	(3,495		)	(436		)
Less—Short-term asset retirement obligations	(2,900		)	(2,900		)
Less—Deferred tax liability on derivative instruments and asset retirement obligations	(16,863		)	(32,051		)
Current liabilities as adjusted	$	188,559		$	159,203
Current ratio for loan compliance	2.97			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.

Alternative capital resources

We have historically used cash flow from operations, debt financing, and private issuances of common stock as our primary sources of capital. In the future we may use additional sources such as 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 March 31,
(in thousands)	2013			2012
Net (loss) income	$	(1,190	)	$	9,782
Interest expense	24,291			24,156
Income tax (benefit) expense	(687		)	6,196
Depreciation, depletion, and amortization	43,916			36,932
Reclassification adjustment for hedge gains	(10,003		)	(12,423		)
Non-cash change in fair value of non-hedge derivative instruments	25,442			12,720
Interest income	(96		)	(58		)
Stock-based compensation expense	1,314			1,151
(Gain) loss on disposed assets	(95		)	95
Adjusted EBITDA	$	82,892		$	78,551

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 three months ended March 31, 2013, our gross revenues from oil and natural gas sales would change approximately $1.4 million for each $1.00 change in oil and natural gas liquid prices and $0.5 million for each $0.10 change in natural gas prices.

To mitigate a portion of our exposure to fluctuations in commodity prices, we enter into commodity price swaps, enhanced swaps, costless collars, 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.

An enhanced swap contract consists of an above-market swap contract plus a put option contract sold by us (sold put) with a price below the swap. The sold put requires us to make a payment to the counterparty if the market price is below the sold put price. 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. By combining the swap contract with the sold put option, we are entitled to a net payment equal to the difference between the swap price and the sold put option price if the market price falls below the sold put option price. This strategy enables us to increase the swap price beyond the range of a traditional swap utilizing the value associated with the sale of a put option.

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

We 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 oil and natural gas derivative instruments as of March 31, 2013, are summarized below:

	Oil derivatives
	Swaps			Enhanced Swaps					Three-way collars
					Weighted average fixed price per Bbl					Weighted average  fixed price per Bbl
	Volume MBbls	Weighted average fixed price per Bbl		Volume MBbls	Sold puts		Swaps		Volume MBbls	Sold puts		Purchased puts		Sold calls		Percent of production(1)
2Q 2013	320	$	96.22	—	$	—	$	—	950	$	77.89	$	99.92	$	114.06	82.4	%
3Q 2013	315	96.25		—	—		—		930	77.74		99.81		114.11		80.6	%
4Q 2013	345	95.88		—	—		—		900	77.83		99.94		114.49		85.8	%
1Q 2014	120	95.22		210	80.00		99.76		600	75.50		93.25		101.94		63.7	%
2Q 2014	120	94.16		210	80.00		98.94		600	75.50		93.25		101.94		55.7	%
3Q 2014	120	93.16		210	80.00		98.20		600	75.50		93.25		101.94		54.0	%
4Q 2014	120	92.37		210	80.00		97.58		600	75.50		93.25		101.94		52.9	%
	1,460			840					5,180

	Natural gas swaps					Natural gas basis protection swaps
	Volume BBtu	Weighted average fixed price per MMBtu		Percent of production(1)		Volume BBtu	Weighted average fixed price per MMBtu
2Q 2013	5,030	$	4.06	95.1	%	4,250	$	0.20
3Q 2013	4,890	4.15		93.1	%	4,050	0.20
4Q 2013	4,890	4.34		101.6	%	4,050	0.20
1Q 2014	4,200	4.02		88.0	%	3,750	0.23
2Q 2014	4,260	3.90		82.2	%	3,620	0.23
3Q 2014	4,530	3.97		87.5	%	3,360	0.23
4Q 2014	4,530	4.12		85.4	%	3,360	0.23
1Q 2015	2,400	4.36		45.9	%	—	—
2Q 2015	2,400	4.11		47.4	%	—	—
3Q 2015	2,400	4.18		41.0	%	—	—
4Q 2015	2,400	4.33		43.2	%	—	—
	41,930					26,440

____________

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

Subsequent to March 31, 2013, we purchased oil put options for 840 MBbls with a weighted average price of $60.00 per Bbl for 2014. The premium paid for these contracts was $0.7 million, and we will receive a payment from the counterparty if the market price is below the put option price at the settlement date. Purchased put options are designed to provide a fixed price floor with the opportunity for upside if commodity prices increase.

We also entered into three-way enhanced swaps for 600 MBbls for 2014. A three-way enhanced swap provides additional downside protection by adding a purchased put to an enhanced swap. If the market price falls below the purchased put option price, we would receive the difference between the purchased put option price and the market price plus the difference between the swap price and the sold put option price. The three-way enhanced swaps we entered into subsequent to March 31, 2013 have a weighted average swap price of $93.46 per Bbl, a weighted average sold put price of $80.00 per Bbl, and a weighted average purchased put price of $60.00 per Bbl.

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In addition to the purchased put options and three way enhanced swaps, we entered into the following derivative instruments subsequent to March 31, 2013:

	Oil derivatives
	Swaps			Enhanced swaps
					Weighted average fixed price per Bbl
	Volume MBbls	Weighted average fixed price per Bbl		Volume MBbls	Sold puts		Swaps
2Q 2013	78	$	93.43	—	$	—	$	—
3Q 2013	127	93.14		—	—		—
4Q 2013	51	91.99		—	—		—
1Q 2014	—	—		150	80.00		93.05
2Q 2014	—	—		150	80.00		93.05
3Q 2014	—	—		150	80.00		93.05
4Q 2014	—	—		150	80.00		93.05
1Q 2015	—	—		600	80.00		93.41
2Q 2015	—	—		600	80.00		93.41
3Q 2015	—	—		600	80.00		93.41
4Q 2015	—	—		600	80.00		93.41
	256			3,000

	Natural gas swaps
	Volume BBtu	Weighted average fixed price per MMBtu
2Q 2013	200	$	4.37
3Q 2013	300	4.44
1Q 2014	540	4.45
2Q 2014	360	4.45
1Q 2015	300	4.53
2Q 2015	300	4.20
3Q 2015	300	4.25
4Q 2015	300	4.41
	2,600

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

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 matter is currently stayed pending resolution of unrelated cases currently on appeal with the U.S. Court of Appeals for the Tenth Circuit.  These cases are expected to influence the ruling on class certification in the Naylor Farms, Inc. case.  At the time that the matter was stayed no class had been certified and discovery was ongoing.  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	Eleventh Amendment to Eighth Restated Credit Agreement dated as of April 17, 2013
10.2	Twelfth Amendment to Eighth Restated Credit Agreement dated as of May 6, 2013
10.3	Form of Amendment No. 1 to Employment Agreement for Corporate Officers
10.4	Amended and Restated Form of Change of Control Severance Agreement for Corporate Officers
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: May 10, 2013

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EXHIBIT INDEX

Exhibit No.	Description
10.1	Eleventh Amendment to Eighth Restated Credit Agreement dated as of April 17, 2013
10.2	Twelfth Amendment to Eighth Restated Credit Agreement dated as of May 6, 2013
10.3	Form of Amendment No. 1 to Employment Agreement for Corporate Officers
10.4	Amended and Restated Form of Change of Control Severance Agreement for Corporate Officers
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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