Chaparral Energy 10Q 2010 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended March 31, 2010

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

For the transition period from to

Commission file number: 333-134748

Chaparral Energy, Inc.

(Exact name of registrant as specified in its charter)


Delaware		73-1590941
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

701 Cedar Lake Boulevard Oklahoma City, Oklahoma		73114
(Address of principal executive offices)		(Zip code)

(405) 478-8770

(Registrant’s telephone number, including area code)

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

(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of the Securities Exchange Act of 1934. However, during the preceding 12 months, the registrant has filed all reports that it would have been required to file by Section 13 or 15(d) of the Securities Act of 1934 if the registrant was subject to the filing requirements of the Securities Exchange Act of 1934.)

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ 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 x 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 x

1,401,376 shares of the registrant’s Common Stock were outstanding as of May 13, 2010.

CHAPARRAL ENERGY, INC.

Index to Form 10-Q


		Page
Part I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated balance sheets as of March 31, 2010 (unaudited) and December 31, 2009		6
Consolidated statements of operations for the three months ended March 31, 2010 and 2009 (unaudited)		7
Consolidated statements of cash flows for the three months ended March 31, 2010 and 2009 (unaudited)		8
Notes to consolidated financial statements (unaudited)		10
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		34
Overview		34
Liquidity and capital resources		36
Results of operations		42
Non-GAAP financial measure and reconciliation		49
Critical accounting policies and estimates		50
Recent accounting pronouncements		52
Item 3. Quantitative and qualitative disclosures about market risk		53
Item 4. Controls and procedures		56
Part II. OTHER INFORMATION		56
Item 1. Legal Proceedings		56
Item 1A. Risk Factors		56
Item 6. Exhibits		57
Signatures		58
EX-31.1 (Certification by CEO required by rule 13a-14(a)/15d-14(a))
EX-31.2 (Certification by CFO required by rule 13a-14(a)/15d-14(a))
EX-32.1 (Certification by CEO pursuant to section 906)
EX-32.2 (Certification by CFO pursuant to section 906)

CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

The statements contained in this report that are not purely historical are forward-looking statements. The forward-looking statements include, but are not limited to, statements regarding our expectations, hopes, beliefs, intentions or strategies regarding the future. In addition, any statements that refer to projections, forecasts or other characterizations of future events or circumstances, including any underlying assumptions, are forward-looking statements. The words “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “possible,” “potential,” “predict,” “project,” “should,” “would” and similar expressions may identify forward-looking statements, but the absence of these words does not mean that a statement is not forward-looking. 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 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;

•

increases 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.

The forward-looking statements contained in this report are based on our current expectations and beliefs concerning future developments and their potential effects. There can be no assurance that future developments affecting us will be those that we have anticipated. These forward-looking statements involve a number of risks, uncertainties (some of which are beyond our control) and other assumptions that may cause actual results or performance to be materially different from those expressed or implied by these 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 14, 2010. Specifically, some factors that could cause actual results to differ include:

•

the significant amount of our debt;

•

worldwide 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;

•

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; and

•

the ability to generate additional prospects.

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.

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.

•

Bcf. One billion cubic feet of natural gas.

•

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 CO₂ or 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.

•

MMcf. One million cubic feet of natural gas.

•

NYMEX. The New York Mercantile Exchange.

•

PDP. Proved developed producing.

•

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

•

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

•

SEC. The Securities and Exchange Commission.

PART I — FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets


(dollars in thousands, except per share data)	March 31, 2010 (unaudited)			December 31, 2009
Assets
Current assets:
Cash and cash equivalents	$	68,222		$	73,417
Accounts receivable, net		54,029			51,969
Inventories		10,427			10,551
Prepaid expenses		4,006			5,729
Derivative instruments		28,620			18,226
Deferred income taxes		—			1,790

Total current assets		165,304			161,682
Property and equipment—at cost, net		60,776			62,197
Oil and natural gas properties, using the full cost method:
Proved		1,948,813			1,910,583
Unproved (excluded from the amortization base)		20,277			19,728
Work in progress (excluded from the amortization base)		22,675			19,206
Accumulated depreciation, depletion, amortization and impairment		(928,077	)		(906,584	)

Total oil and natural gas properties		1,063,688			1,042,933
Funds held in escrow		1,656			1,672
Derivative instruments		6,881			5,794
Deferred income taxes		49,994			62,422
Other assets		16,965			17,220

	$	1,365,264		$	1,353,920

Liabilities and stockholders’ equity (deficit)
Current liabilities:
Accounts payable and accrued liabilities	$	47,142		$	48,283
Accrued payroll and benefits payable		10,216			10,849
Accrued interest payable		14,090			14,394
Revenue distribution payable		17,832			18,673
Current maturities of long-term debt and capital leases		4,391			4,653
Derivative instruments		18,357			20,677
Deferred income taxes		3,127			—

Total current liabilities		115,155			117,529
Long-term debt and capital leases, less current maturities		523,699			524,477
Senior notes, net		647,931			647,877
Derivative instruments		16,835			30,163
Deferred compensation		974			1,142
Asset retirement obligations		37,622			37,165
Commitments and contingencies (Note 8)
Stockholders’ equity (deficit):
Preferred stock, 600,000 shares authorized, none issued and outstanding		—			—
Common stock, $.01 par value, 3,000,000 shares authorized; 877,000 shares issued and outstanding as of March 31, 2010 and December 31, 2009, respectively		9			9
Additional paid in capital		100,918			100,918
Accumulated deficit		(97,514	)		(122,978	)
Accumulated other comprehensive income, net of taxes		19,635			17,618

		23,048			(4,433	)

	$	1,365,264		$	1,353,920

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

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of operations


	Three months ended March 31,
(dollars in thousands, except per share data)	2010 (unaudited)			2009 (unaudited)
Revenues:
Oil and natural gas sales	$	100,375		$	53,867
Gain (loss) from oil and natural gas hedging activities		(4,985	)		15,503
Other revenues		871			668

Total revenues		96,261			70,038
Costs and expenses:
Lease operating		24,419			27,503
Production taxes		6,990			3,860
Depreciation, depletion, and amortization		24,521			30,218
Loss on impairment of oil and natural gas properties		—			240,790
General and administrative		6,440			6,368
Litigation settlement		—			2,928
Other expenses		704			281

Total costs and expenses		63,074			311,948

Operating income (loss)		33,187			(241,910	)
Non-operating income (expense):
Interest expense		(22,552	)		(22,464	)
Non-hedge derivative gains		31,057			50,327
Financing costs		(297	)		—
Other income		138			10,967

Net non-operating income		8,346			38,830

Income (loss) from continuing operations before income taxes		41,533			(203,080	)
Income tax expense (benefit)		16,069			(78,348	)

Income (loss) from continuing operations		25,464			(124,732	)
Loss from discontinued operations, net of related taxes		—			(92	)

Net income (loss)	$	25,464		$	(124,824	)

Earnings (loss) per share (basic and diluted)
Continuing operations	$	29.04		$	(142.23	)
Discontinued operations		—			(0.10	)

Net earnings (loss) per share (basic and diluted)	$	29.04		$	(142.33	)

Weighted average number of shares used in calculation of basic and diluted net earnings (loss) per share		877,000			877,000

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

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows


	Three months ended March 31,
(dollars in thousands)	2010 (unaudited)			2009 (unaudited)
Cash flows from operating activities
Net income (loss)	$	25,464		$	(124,824	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion & amortization		24,521			30,443
Loss on impairment of oil and natural gas properties		—			240,790
Litigation settlement		—			2,928
Deferred income taxes		16,074			(78,406	)
Unrealized gain on ineffective portion of hedges and reclassification adjustments		(519	)		(10,872	)
Non-hedge derivative gains		(31,057	)		(50,327	)
Other		215			478
Change in assets and liabilities
Accounts receivable		276			18,025
Inventories		170			1,471
Prepaid expenses and other assets		2,393			1,595
Accounts payable and accrued liabilities		(3,360	)		14,007
Revenue distribution payable		(841	)		(1,833	)
Deferred compensation		166			156

Net cash provided by operating activities		33,502			43,631
Cash flows from investing activities
Purchase of property and equipment and oil and natural gas properties		(44,858	)		(64,616	)
Proceeds from dispositions of property and equipment and oil and natural gas properties		284			295
Return of prepaid production tax asset		—			10,860
Settlement of non-hedge derivative instruments		7,736			21,579
Other		16			387

Net cash used in investing activities		(36,822	)		(31,495	)
Cash flows from financing activities
Proceeds from long-term debt		270			—
Repayment of long-term debt		(1,246	)		(1,677	)
Principal payments under capital lease obligations		(64	)		(58	)
Fees paid related to financing activities		(835	)		—

Net cash used in financing activities		(1,875	)		(1,735	)

Net increase (decrease) in cash and cash equivalents		(5,195	)		10,401
Cash and cash equivalents at beginning of period		73,417			52,112

Cash and cash equivalents at end of period	$	68,222		$	62,513

Supplemental cash flow information
Cash paid (received) during the period for:
Interest, net of capitalized interest	$	21,421		$	22,854
Income taxes		(5	)		—

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

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows—(Continued)

(dollars in thousands, unless otherwise noted)

Supplemental disclosure of investing and financing activities

During the three months ended March 31, 2010 and 2009, oil and natural gas property additions of $1,340 and $24,115, respectively, previously included in accounts payable and accrued expenses were settled and are reflected in cash used in investing activities.

During the three months ended March 31, 2010 and 2009, we recorded an asset and related liability of $4 and $286, respectively, associated with the asset retirement obligation on the acquisition and/or development of oil and natural gas properties.

Interest of $388 and $202 was capitalized during the three months ended March 31, 2010 and 2009, respectively, primarily related to unproved oil and natural gas leaseholds.

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

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

Chaparral Energy, Inc. and subsidiaries, (collectively, “we”, “our”, “us”, or the “Company”) is 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, Montana, Kansas, and Wyoming.

Interim financial statements

The accompanying unaudited consolidated interim financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X and do not include all of the financial information and disclosures required by GAAP. The financial information as of March 31, 2010 and for the three months ended March 31, 2010 and 2009 is unaudited. In the opinion of management, 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, 2010 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2010.

The consolidated interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto, together with management’s discussion and analysis of financial condition and results of operations contained in our
Form 10-K filed with the Securities and Exchange Commission on April 14, 2010.

Principles of consolidation

The unaudited consolidated financial statements include the accounts of Chaparral Energy, Inc. and its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated.

Reclassifications

Certain reclassifications have been made to prior year amounts to conform to current year presentation.

Use of estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. Significant estimates affecting these financial statements include estimates for quantities of proved oil and natural gas reserves, deferred income taxes, asset retirement obligations, fair value of derivative instruments, and others, and are subject to change.

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, 2010, cash and funds held in escrow with a recorded balance totaling $66,832 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.

Fair value measurements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued new authoritative guidance which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. Fair value is defined 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.

Assets and liabilities recorded at fair value in the balance sheet 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. 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.

Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 inputs include adjusted quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities included in this category are derivatives with fair values based on published forward commodity price curves and other observable inputs. 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. Assets carried at fair value and included in this category are certain financial derivatives, additions to our asset retirement obligations, and assets acquired through a non-monetary exchange transaction.

In August 2009, the FASB issued new authoritative guidance regarding “Measuring Liabilities at Fair Value,” which is effective for the first reporting period (including interim periods) beginning after issuance. The new guidance provides additional clarification regarding how fair value should be measured when a quoted price in an active market for the identical liability is not available. We adopted the new guidance on October 1, 2009, and its adoption did not have an impact on our financial position or results of operations.

Earnings per share

Basic earnings per share is computed by dividing net income attributable to all classes of common shareholders by the weighted average number of shares of all classes of common stock outstanding during the applicable period. Diluted earnings per share is determined in the same manner as basic earnings per share except that the number of shares is increased to assume exercise of potentially dilutive securities outstanding during the periods presented. There were no potentially dilutive securities outstanding during the periods presented.

Accounts receivable

Accounts receivable consisted of the following at March 31, 2010 and December 31, 2009:


	March 31, 2010			December 31, 2009
Joint interests	$	10,800		$	11,986
Accrued oil and natural gas sales		38,631			33,600
Hedge settlements		4,087			5,977
Production tax benefit		—			19
Other		1,208			1,204
Allowance for doubtful accounts		(697	)		(817	)

	$	54,029		$	51,969

Inventories

Inventories are comprised of equipment used in developing oil and natural gas properties, oil and natural gas production inventories, and equipment for resale. Equipment inventory and inventory for resale are carried at the lower of cost or market using the average cost method. Oil and natural gas product inventories are stated at the lower of production cost or market. We regularly review inventory quantities on hand and record provisions for excess or obsolete inventory, if necessary. Inventories at March 31, 2010 and December 31, 2009 consisted of the following:


	March 31, 2010			December 31, 2009
Equipment inventory	$	6,500		$	6,673
Oil and natural gas product		2,500			2,642
Inventory for resale		2,537			2,356
Inventory valuation allowance		(1,110	)		(1,120	)

	$	10,427		$	10,551

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.

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”), as adjusted for our cash flow hedge positions and net of tax considerations, plus the lower of cost or estimated fair value of unproved properties. During the first quarter of 2009, natural gas prices declined significantly as compared to the December 31, 2008 spot price of $5.62 per Mcf. Based on March 31, 2009 spot prices of $49.66 per Bbl of oil and $3.63 per Mcf of natural gas, the internally estimated PV-10 value of our reserves declined by 13.5% compared to the PV-10 value at December 31, 2008. As a result, we recorded a ceiling test impairment of oil and natural gas properties of $240,790 during the first quarter of 2009. The effect of derivative contracts accounted for as cash flow hedges, based on the March 31, 2009 spot prices, increased the full cost ceiling by $169,013, thereby reducing the ceiling test write down by the same amount.

Our estimate of oil and natural gas reserves as of March 31, 2010 was prepared using an average price for oil and natural gas based upon the first day of each month for the prior twelve months as required by the SEC’sModernization of Oil and Gas Reporting and the FASB’s updated guidance relating toOil and Gas Reserve Estimation and Disclosures, which we adopted effective December 31, 2009.As of March 31, 2010, the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties and no additional ceiling test impairment was recorded. The PV-10 value of our reserves was estimated based on average prices of $69.64 per Bbl of oil and $3.98 per Mcf of gas for the twelve months ended March 31, 2010. A decline in oil and natural gas prices subsequent to March 31, 2010 could result in additional 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.

Production tax credits

During 2006, we purchased interests in two venture capital limited liability companies resulting in a total investment of $15,000. Our return on the investment was the receipt of $2 of Oklahoma tax credits for every $1 invested and was recouped from our Oklahoma production taxes. The investments were accounted for as a production tax benefit asset and were netted against tax credits realized in other income using the effective yield method over the expected recovery period. As of March 31, 2010 and December 31, 2009, the carrying value of the production tax benefit asset was $0 and $19, respectively, and was included in accounts receivable. Oklahoma production tax credits of $0 and $10,860 were included in other income in the consolidated statements of operations for the three months ended March 31, 2010 and 2009, respectively.

Funds held in escrow

We have funds held in escrow that are restricted as to withdrawal or usage. As of March 31, 2010 and December 31, 2009, the balance in escrow for plugging and abandonment was $1,656 and $1,672, respectively. We are entitled to make quarterly withdrawals from the plugging escrow account equal to one-half of the interest earnings for the period and as reimbursement for actual plugging and abandonment expenses incurred on the North Burbank field, provided that written documentation has been provided. The balance is not intended to reflect our total future financial obligation for the plugging and abandonment of these wells.

Impairment of long-lived assets

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

Asset retirement obligations

We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of oil and natural gas properties. The accretion of the asset retirement obligations is included in depreciation, depletion and amortization on the consolidated statements of operations. 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 quarter of 2010 were escalated using an annual inflation rate of 2.95%, and discounted using our credit-adjusted risk-free interest rate of 8.5%. These estimates may change based upon future inflation rates and changes in statutory remediation rules. See Note 3 for additional information regarding our asset retirement obligations.

Deferred income taxes

Deferred income taxes are provided for significant carryforwards and temporary differences between the tax basis of an asset or liability and its reported amount in the financial statements that will result in taxable or deductible amounts in future years. Deferred income tax assets or liabilities are determined by applying the presently enacted tax rates and laws. We record a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such assets will not be realized.

Realization of our deferred tax assets is dependent upon generating sufficient future taxable income. Although realization is not assured, we believe it is more likely than not that the deferred tax asset will be realized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near-term if estimates of future taxable income are reduced.

If applicable, we would report a liability for unrecognized tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return, and would recognize interest and penalties related to uncertain tax positions in interest expense. As of March 31, 2010 and December 31, 2009, we have not recorded a liability or accrued interest related to uncertain tax positions.

The tax years 1998 through 2009 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.

Discontinued operations

Certain amounts have been reclassified to present the operations of the Electric Submersible Pumps (“ESP”) and Chemicals divisions of Green Country Supply, Inc. (“GCS”), a wholly owned subsidiary, as discontinued operations. Unless otherwise indicated, information presented in the notes to the financial statements relates only to our continuing operations. See Note 7 for additional information relating to discontinued operations.

Recently issued accounting standards

In January 2010, the FASB issued new authoritative guidance regarding “Improving Disclosures about Fair Value Measurements and Disclosures” that requires additional disclosure of transfers in and out of Level 1 and 2 measurements and the reasons for the transfers, and a gross presentation of activity within the Level 3 roll forward. The guidance also includes clarifications to existing disclosure requirements on the level of disaggregation and disclosures regarding inputs and valuation techniques. The guidance is effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward information, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. We adopted the guidance on January 1, 2010, except for requirements regarding the gross presentation of Level 3 roll forward information, which we will adopt on January 1, 2011. Because this guidance only requires additional disclosures, it did not have an impact on our financial statements, nor is it expected to have an impact in future periods.

Note 2: Derivative activities and financial instruments

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, costless collars, and basis protection swaps. See Note 1 for additional information regarding our accounting policies for fair value measurements.

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

Collars contain a fixed floor price (put) and ceiling price (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. Our collars have not been designated as hedges. Therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative gains (losses). This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices.

We use basis protection swaps to reduce basis risk. Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. Natural gas basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified pricing point. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. We do not designate these instruments as hedges; therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative gains (losses).

Our outstanding oil and natural gas derivative instruments as of March 31, 2010 are summarized below:


	Oil derivatives
	Swaps			Collars
	Volume MBbl	Weighted average fixed price to be received		Volume MBbl	Weighted average range
2010	1,909	$	68.63	180	$	110.00 - $168.55
2011	2,155		68.89	204		110.00 - 152.71
2012	600		90.46	—		—

	4,664			384


	Natural gas derivatives						Natural gas basis protection swaps
	Swaps			Collars			Natural gas basis protection swaps
	Volume BBtu	Weighted average fixed price to be received		Volume BBtu	Weighted average range		Volume BBtu	Weighted average fixed price to be paid
2010	11,380	$	7.04	2,520	$	10.00 - $11.53	11,650	$	0.75
2011	12,150		7.24	—			12,990		0.74

	23,530			2,520			24,640

Our derivative contracts have been executed with the institutions that are parties to our revolving credit facility, and we believe the credit risks associated with all of these institutions are acceptable. We did not post collateral under any of these contracts as they are secured under our revolving credit facility. Payment on our derivative contracts would be accelerated in the event of a default on our revolving credit facility. The aggregate fair value of our derivative liabilities was $79,269 at March 31, 2010.

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, 2010								As of December 31, 2009
	Assets		Liabilities			Net value			Assets		Liabilities			Net value
Derivatives designated as cash flow hedges:
Oil swaps	$	2,051	$	(52,954	)	$	(50,903	)	$	172	$	(54,883	)	$	(54,711	)
Derivatives not designated as hedging instruments:
Oil swaps		—		(13,104	)		(13,104	)		—		(13,840	)		(13,840	)
Natural gas swaps		53,369		—			53,369			30,366		(26	)		30,340
Oil collars		9,816		—			9,816			12,290		—			12,290
Natural gas collars		14,342		—			14,342			14,065		—			14,065
Natural gas basis differential swaps		—		(13,211	)		(13,211	)		—		(14,964	)		(14,964	)

Total non-hedge instruments		77,527		(26,315	)		51,212			56,721		(28,830	)		27,891

Total derivative instruments		79,578		(79,269	)		309			56,893		(83,713	)		(26,820	)
Less:
Netting adjustments (1)		44,077		(44,077	)		—			32,873		(32,873	)		—
Current portion asset (liability)		28,620		(18,357	)		10,263			18,226		(20,677	)		(2,451	)

	$	6,881	$	(16,835	)	$	(9,954	)	$	5,794	$	(30,163	)	$	(24,369	)

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

Changes in the fair value of effective cash flow hedges are recorded as a component of accumulated other comprehensive income (“AOCI”), which is later transferred to earnings when the hedged transaction occurs. The ineffective portion is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged, and is included in gain (loss) from oil and natural gas hedging activities in the consolidated statements of operations. If it is probable the oil or natural gas sales which are hedged will not occur, hedge accounting is discontinued and the gain or loss reported in AOCI is immediately reclassified into income. If a derivative which qualified for cash flow hedge accounting ceases to be highly effective, or is liquidated or sold prior to maturity, hedge accounting is discontinued. The gain or loss associated with the discontinued hedges remains in AOCI and is reclassified into income as the hedged transactions occur.

Gains and losses associated with cash flow hedges are summarized below.


	Amount of gain (loss) recognized in AOCI (effective portion)						Amount of gain (loss) reclassified from AOCI in income (effective portion) (1)						Amount of gain (loss) recognized in income (ineffective portion) (1)
	Three months ended March 31,						Three months ended March 31,						Three months ended March 31,
	2010			2009			2010			2009			2010			2009
Oil swaps	$	(1,035	)	$	(1,500	)	$	(4,844	)	$	12,311		$	(660	)	$	305
Natural gas swaps		—			—			519			2,887			—			—
Income taxes		400			591			1,673			(5,984	)		—			—

	$	(635	)	$	(909	)	$	(2,652	)	$	9,214		$	(660	)	$	305

(1)	Included in gain (loss) from oil and natural gas hedging activities in the consolidated statements of operations.

During the fourth quarter of 2008, we determined that our natural gas swaps are no longer expected to be highly effective, primarily due to the increased volatility in the basis differentials between the contract price and the indexed price at the point of sale. As a result, we discontinued hedge accounting and applied mark-to-market accounting treatment to all outstanding natural gas swaps. The change in fair value related to these instruments, after hedge accounting was discontinued, is recorded immediately in non-hedge derivative gains (losses) in the consolidated statements of operations. In the past, a portion of the change in fair value would have been deferred through other comprehensive income and the ineffective portion would have been included in gain (loss) from oil and natural gas hedging activities.

In addition, we early settled certain oil and natural gas swaps and collars during the first half of 2009 and the fourth quarter of 2008. Certain swaps that were early settled had previously been accounted for as cash flow hedges. As of March 31, 2010 and December 31, 2009, accumulated other comprehensive income included $82,923 and $83,442, respectively, of deferred gains related to discontinued cash flow hedges that will be recognized as a gain from oil and natural gas hedging activities when the hedged production is sold. No oil and natural gas derivatives were early settled in the first quarter of 2010.

During the first quarter of 2010 and 2009, gains of $0 and $8,385, respectively, were reclassified into earnings as a result of the discontinuance of hedge accounting treatment for certain oil swaps, and gains of $519 and $2,887, respectively, were reclassified into earnings as a result of the discontinuance of hedge accounting treatment for our natural gas swaps. Gain (loss) from oil and natural gas hedging activities, which is a component of total revenues in the consolidated statements of operations, is comprised of the following:


	March 31, 2010			March 31, 2009
Oil hedges
Reclassification adjustment for hedge gains (losses) included in net income (loss)	$	(4,844	)	$	12,311
Gain (loss) on ineffective portion of derivatives qualifying for hedge accounting		(660	)		305
Natural gas hedges
Reclassification adjustment for hedge gains included in net income (loss)		519			2,887

	$	(4,985	)	$	15,503

Based upon market prices at March 31, 2010 and assuming no future change in the market, we expect to reclassify $19,109 of losses in accumulated other comprehensive income to income during the next 12 months when the forecasted transactions actually occur. All forecasted transactions hedged as of March 31, 2010 are expected to be settled by December 2012, however, deferred gains in AOCI related to discontinued cash flow hedges will continue to be reclassified into earnings through December 2013.

The changes in fair value and settlement of derivative contracts that do not qualify or have not been designated as hedges are recognized as non-hedge derivative gains (losses). All non-hedge derivative contracts outstanding at March 31, 2010 are expected to be settled by December 2011. Non-hedge derivative gains in the consolidated statements of operations are comprised of the following:


	March 31, 2010			March 31, 2009
Change in fair value of non-qualified commodity price swaps	$	23,765		$	29,912
Change in fair value of non-designated costless collars		(2,196	)		3,162
Change in fair value of natural gas basis differential contracts		1,752			(4,326	)
Receipts from (payments on) settlement of non-qualified commodity price swaps		6,434			14,730
Receipts from (payments on) settlement of non-designated costless collars		5,741			5,078
Receipts from (payments on) settlement of natural gas basis differential contracts		(4,439	)		1,771

	$	31,057		$	50,327

Derivative settlements receivable of $4,087 and $5,977 were included in accounts receivable at March 31, 2010 and December 31, 2009, respectively. Derivative settlements payable of $1,986 and $1,739 were included in accounts payable and accrued liabilities at March 31, 2010 and December 31, 2009, respectively.

All derivative financial instruments are recorded on the balance sheet at fair value. We estimate the fair value of our derivative instruments using a combined income and market valuation methodology. 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. The fair value of collars is determined using an option pricing model which takes into account market volatility as well as the inputs described above. 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. As of March 31, 2010 and December 31, 2009, the rate reflecting our nonperformance risk was 3.25% and 3.25%, respectively, and the weighted-average rate reflecting our counterparties’ nonperformance risk was approximately 1.57% and 1.49%, respectively.

We have no Level 1 assets or liabilities as of March 31, 2010. Our derivative contracts classified as Level 2 are valued using quotations provided by price index developers such as Platts and Oil Price Information Service. In certain less liquid markets, forward prices are not as readily available. In these circumstances, commodity swaps are valued using internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. These contracts are classified as Level 3. Due to unavailability of observable volatility data input, the fair value measurement of all our collars has been categorized as Level 3.

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


	As of March 31, 2010									As of December 31, 2009
	Derivative assets			Derivative liabilities			Net assets (liabilities)			Derivative assets			Derivative liabilities			Net assets (liabilities)
Significant other observable inputs (Level 2)	$	55,420		$	(79,269	)	$	(23,849	)	$	30,538		$	(83,713	)	$	(53,175	)
Significant unobservable inputs (Level 3)		24,158			—			24,158			26,355			—			26,355
Netting adjustments (1)		(44,077	)		44,077			—			(32,873	)		32,873			—

	$	35,501		$	(35,192	)	$	309		$	24,020		$	(50,840	)	$	(26,820	)

(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 net commodity derivatives classified as Level 3 in the fair value hierarchy for the first quarter of 2010 and 2009 were as follows:


Net derivative assets	March 31, 2010			March 31, 2009
Beginning balance	$	26,355		$	79,603
Realized and unrealized gains included in non-hedge derivative gains (losses)		3,544			8,325
Settlements		(5,741	)		(5,367	)

Ending balance	$	24,158		$	82,561

Gains relating to assets still held at the reporting date included in non-hedge derivative gains for the period	$	3,211		$	7,557

Fair value of financial instruments

The carrying values of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. The carrying value for long-term debt at March 31, 2010 and December 31, 2009 approximates fair value because substantially all debt carries variable market rates and incorporates a measure of our credit risk. The carrying value and estimated market value of our senior notes at March 31, 2010 and December 31, 2009 were as follows:


	March 31, 2010				December 31, 2009
	Carrying value		Estimated fair value		Carrying value		Estimated fair value
8¹/2% Senior Notes due 2015	$	325,000	$	306,912	$	325,000	$	281,125
8⁷/8% Senior Notes due 2017		322,931		304,782		322,877		281,125

	$	647,931	$	611,694	$	647,877	$	562,250

Fair value amounts have been estimated based on quoted market prices. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

Note 3: Asset retirement obligations

The following table provides a summary of our asset retirement obligations for March 31, 2010.


	Three Months Ended March 31, 2010
Beginning balance	$	37,465
Liabilities incurred in current period		4
Liabilities settled in current period		(335	)
Accretion expense		788

	$	37,922
Less current portion		300

	$	37,622

See Note 1 for additional information regarding our accounting policies for asset retirement obligations and fair value measurements.

Note 4: Long-term debt

Long-term debt at March 31, 2010 and December 31, 2009 consisted of the following:


	March 31, 2010		December 31, 2009
Revolving credit line with banks	$	507,001	$	507,001
Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 3.71% to 9.26%, due January 2017 through December 2028; collateralized by real property		13,357		13,465
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 4.50% to 9.25%, due April 2010 through January 2014; collateralized by automobiles, machinery and equipment		7,417		8,285

		527,775		528,751
Less current maturities		4,158		4,405

	$	523,617	$	524,346

In October 2006, we entered into a Seventh Restated Credit Agreement, which is scheduled to mature on October 31, 2010 and is collateralized by our oil and natural gas properties. Availability under our credit agreement 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 every six months. The borrowing base, which was reaffirmed effective November 23, 2009, is $513,001 as of March 31, 2010.

On March 23, 2010, we entered into a stock purchase agreement (the “Stock Purchase Agreement”) with CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively, “CCMP”). On April 12, 2010, we sold 475,043 shares of our common stock to CCMP for a purchase price of $325,000. Fees and other expenses of the transaction were approximately $11,700. In connection with the closing of the Stock Purchase Agreement, we entered into and closed an Eighth Restated Credit Agreement, which has an initial borrowing base of $450,000, is collateralized by our oil and natural gas properties, and is scheduled to mature on April 12, 2014. We used the proceeds from the sale of common stock to CCMP, along with proceeds available under the Eighth Restated Credit Agreement, to repay the amounts owing under our Seventh Restated Credit Agreement, and those amounts are classified as long-term debt as of March 31, 2010 and December 31, 2009. As of May 13, 2010, we had $172,000 outstanding and $275,330 of availability under our Eighth Restated Credit Agreement. See Note 10 for additional information regarding these transactions.

Interest was paid at least every three months during 2010 and 2009. The effective rate of interest on the entire outstanding balance was 6.118% and 6.081% as of March 31, 2010 and December 31, 2009, respectively, and was based upon LIBOR. Commitment fees of 0.50% accrue on the unused portion of the borrowing base amount, depending on the utilization percentage, and are included as a component of interest expense.

The Credit Agreement has certain negative and affirmative covenants that require, among other things, maintaining a specified current ratio and debt service ratio. The Credit Agreement, as amended effective May 21, 2009, requires us to maintain a Consolidated Senior Total Debt to Consolidated EBITDAX ratio, as defined in our Credit Agreement, of not greater than:

•

2.50 to 1.0 for the four consecutive fiscal quarters ending on March 31, 2009;

•

3.00 to 1.0 for the four consecutive fiscal quarters ending on June 30, 2009, September 30, 2009, December 31, 2009, and March 31, 2010; and

•

2.75 to 1.0 for the four consecutive fiscal quarters ending on June 30, 2010, September 30, 2010, and December 31, 2010.

For purposes of the amended ratio, Consolidated Senior Total Debt consists of all outstanding loans under the Credit Agreement, letters of credit and all obligations under capital leases, minus cash on hand in excess of accounts payable and accrued liabilities that are more than 90 days past the invoice date, as defined in the Fifth Amendment to our Credit Agreement.

We believe we were in compliance with all covenants under the Credit Agreement as of March 31, 2010.

The Credit Agreement 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 the Credit Agreement. An acceleration of our indebtedness under the Credit Agreement 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.

Note 5: Related party transactions

CHK Holdings L.L.C., an indirect wholly owned subsidiary of Chesapeake Energy Corporation (“Chesapeake”), owns 31.9% of our outstanding common stock. We participate in ownership of properties operated by Chesapeake, and we receive revenues and incur joint interest billings on these properties. In addition, Chesapeake participates in ownership of properties operated by us, and we pay revenues and record joint interest billings to Chesapeake on these properties.

The following table reflects our joint interest transactions with Chesapeake during the first quarter of 2010 and 2009:


	Three months ended March 31, 2010						Three months ended March 31, 2009
	Properties operated by Chesapeake			Properties operated by Chaparral			Properties operated by Chesapeake			Properties operated by Chaparral
Revenues	$	1,351		$	(404	)	$	1,664		$	(384	)
Joint interest billings		(2,590	)		184			(1,386	)		1,188

	$	(1,239	)	$	(220	)	$	278		$	804

Amounts receivable from and payable to Chesapeake were $1,973 and $834, respectively, as of March 31, 2010. Amounts receivable from and payable to Chesapeake were $2,506 and $241, respectively, as of December 31, 2009.

Note 6: Deferred compensation

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 “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 current 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. Upon vesting, participants are entitled to redeem their phantom stock for cash within 120 days of the vesting date.

Since the phantom stock is a liability award, fair value of the stock is remeasured at the end of each reporting period until settlement. As prescribed by the Plan, fair market value is calculated based on the Company’s total asset value less total liabilities, with both assets and liabilities being adjusted to fair value. 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 expense is recognized over the vesting period of the phantom stock and is reflected in lease operating and general and administrative expenses in the consolidated statements of operations. Such expense is calculated net of forfeitures estimated based on our historical and expected turnover rates. We recognized deferred compensation expense as follows for the first quarter of 2010 and 2009:


	March 31, 2010			March 31, 2009
Deferred compensation cost	$	253		$	234
Less: deferred compensation cost capitalized		(87	)		(77	)

Deferred compensation expense	$	166		$	157

A summary of our phantom stock activity during the first quarter of 2010 is presented in the following table:


	Weighted average grant date fair value		Phantom shares		Vest date fair value		Weighted average amortization period remaining
	($ per share)						(years)
Unvested and outstanding at January 1, 2010	$	12.77	175,482
Granted	$	24.48	14,876
Vested	$	8.58	(53,279	)	$	1,304
Forfeited	$	—	—

Unvested and total outstanding at March 31, 2010	$	15.65	137,079				2.72

Payments for phantom shares were $0 and $1, respectively, during the first quarter of 2010 and 2009. As of March 31, 2010, there were 53,539 vested units outstanding with a weighted average fair value of $24.41 per share, and an aggregate intrinsic value of $1,307, which is included in accrued payroll and benefits payable. Based on an estimated fair value of $22.67 per phantom share as of March 31, 2010, the aggregate intrinsic value of the unvested phantom shares outstanding was $3,108, which includes approximately $1,705 of unrecognized compensation cost that is expected to be recognized over a weighted-average period of 2.72 years. As of March 31, 2010 and December 31, 2009, accrued payroll and benefits payable included $429 and $1,315, respectively, for deferred compensation costs vesting within the next twelve months.

Note 7: Discontinued operations

Discontinued operations consist of the third-party revenues and operating expenses of the ESP and Chemicals divisions of GCS. Revenues were generated through the sale of oilfield supplies, chemicals, downhole submersible pumps, and related services to oil and natural gas operators primarily in Oklahoma, Texas, and Wyoming. Operating expenses consisted of costs of sales related to product sales and general and administrative expenses.

In the second quarter of 2009, we committed to a plan to sell the assets of these divisions, and we subsequently sold them in two separate transactions during 2009. There was no activity associated with these divisions in the first quarter of 2010. The operating results of these divisions for the first quarter of 2009 have been reclassified as discontinued operations in the consolidated statements of operations as detailed in the table below.


	Three months ended March 31, 2009
Revenues	$	4,252
Operating expenses		(4,177	)
Depreciation, depletion, and amortization		(225	)

Loss before income taxes		(150	)
Income tax benefit		(58	)

Loss from discontinued operations, net of related taxes	$	(92	)

There were no assets held for sale or liabilities associated with discontinued operations as of March 31, 2010 or December 31, 2009.

Note 8: Commitments and contingencies

Standby letters of credit (“Letters”) available under the revolving credit line 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 $2,670 and $2,855 as of March 31, 2010 and December 31, 2009, respectively. Interest on each Letter accrues at the lender’s prime rate (effective rate of 6.118% at March 31, 2010 and 6.081% at December 31, 2009) for all amounts paid by the lenders under the Letters. We paid no interest on the Letters during the three months ended March 31, 2010 and 2009.

Various claims and lawsuits, incidental to the ordinary course of business, are pending both for and against us. In the opinion of management, all matters are not expected to have a material effect on our consolidated financial position or results of operations.

Effective April 15, 2009, we settled our pending lawsuit against John Milton Graves Trust u/t/a 6/11/2004, et al. This case was filed in the District Court of Tulsa County, State of Oklahoma, and related to (i) a post-closing adjustment of the price we paid for Calumet Oil Company (“Calumet”) in 2006 (the “Working Capital Adjustment”) and (ii) a contractual payment related to an election to be made by the sellers of Calumet (collectively, the “Sellers”) under the federal tax code (the “Tax Election”). As of December 31, 2008, the recorded receivable for the Working Capital Adjustment was $14,406, and the recorded payable related to the Tax Election was $4,378.

Pursuant to the settlement agreement, which was based upon net calculations of the receivable and payable, the Sellers paid us $7,100, which amount is intended to settle all claims related to both the Working Capital Adjustment and the Tax Election claims, and we retained $387 contained in an escrow account covering any losses incurred by us for title defects related to our purchase of Calumet. In addition, the parties issued mutual releases, dismissed with prejudice the pending litigation and the claims made therein, and the Sellers will take action to clear the title to certain properties purchased by us in the Calumet acquisition.

As a result of the settlement, as of March 31, 2009, the receivable related to the Working Capital Adjustment was written down to $7,100, the Tax Election payable was eliminated, the escrow cash account was reclassified to operating cash, and we recorded a charge to expense of $2,928.

Note 9: Comprehensive income (loss)

Components of comprehensive income (loss), net of related tax, are as follows for the three months ended March 31, 2010 and 2009:


	Three months ended March 31,
	2010			2009
Net income (loss)	$	25,464		$	(124,824	)
Unrealized loss on hedges		(635	)		(909	)
Reclassification adjustment for hedge (gains) losses included in net income (loss)		2,652			(9,214	)

Comprehensive income (loss)	$	27,481		$	(134,947	)

Note 10: Subsequent events

Stock Purchase Agreements

On March 23, 2010, we entered into a stock purchase agreement (the “Stock Purchase Agreement”) with CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively, “CCMP”), pursuant to which CCMP would purchase and we would sell 475,042 shares of our class E common stock, par value $0.01 per share, and one share of class F common stock, par value $0.01 per share, for a purchase price of $325,000. Fees and other expenses of the transaction were approximately $11,700. The closing date of the Stock Purchase Agreement (the “Closing Date”) was April 12, 2010.

In connection with the execution of the Stock Purchase Agreement, on April 12, 2010, two of the three principal stockholders of the Company, Fischer and Altoma, each executed a stock purchase agreement with CCMP pursuant to which CCMP purchased from such stockholder 14,617 shares of Company common stock for a purchase price of $10,000.

As a result of the closing of the Stock Purchase Agreement and the stock purchase agreements discussed above, CCMP owns approximately 36% of our total outstanding common stock as of May 13, 2010.

Amended and Restated Certificate of Incorporation. In connection with the execution of the Stock Purchase Agreement, we filed the Amended and Restated Certificate of Incorporation with the Delaware Secretary of State on April 12, 2010. The Amended and Restated Certificate of Incorporation creates seven classes of $0.01 par value per share common stock, classes A through G, with the rights and preferences summarized below. The class A common stock carries standard voting, dividend and liquidation rights. The class B, C and D common stock was issued to our existing stockholders, with a separate class issued to each stockholder. The class E and class F common stock was issued to CCMP. One share of class G common stock was issued to each of our existing stockholders. All shares of class B through G common stock will automatically convert to class A common stock upon consummation of an initial public offering of shares of class A common stock resulting in proceeds to us of at least $250,000, which is underwritten on a firm commitment basis by a nationally recognized investment banking firm, and which results in the initial listing or quotation of the class A common stock on any national securities exchange (a “Qualified IPO”).

Holders of class B, C and D common stock have the right, in aggregate, to designate three of our five directors. Holders of class E common stock have the right to designate the remaining two directors. Holders of each of the class B, C, D, and E common stock have designated their respective directors. All of the initial designees of the class B, C, D and E common stock were approved by the existing board of directors prior to being empanelled.

The class B, E, F and G common stock carry the following additional voting and consent rights:

•

So long as the class B holders own 80% or more of the common stock they owned as of the Closing Date, and without such holder’s prior consent, we may neither initiate nor consummate a sale of the Company, whether in the form of a stock sale, asset sale, merger or any other form whatsoever (a “Company Sale”), or a liquidation or dissolution of the Company, on or prior to the sixth anniversary of the Closing Date.

•

In certain circumstances, we are prohibited from incurring debt, consummating sales or acquisitions of assets, taking certain operational actions or engaging in other specified transactions without the prior consent of the holders of the class E common stock.

•

Upon the triggering of a Company Sale or a Demand IPO (each as summarized below) by holders of class E common stock, the voting and other rights related to the class F common stock will permit holders of class E common stock to cause any actions necessary to be taken by our board of directors or stockholders to consummate such Company Sale or Demand IPO.

•

Upon the triggering of a Demand IPO by a majority in interest of our existing stockholders, the voting and other rights related to the class G common stock will permit the majority of the holders of class G common stock to cause any actions necessary to be taken by the Company’s board of directors or stockholders to consummate such Demand IPO.

The rights and preferences of a holder of class B, C, D, E, F and G common stock terminate on the earlier of (x) the closing date of a Qualified IPO or (y) the date that such holder and its permitted transferees cease to beneficially own 5% or more of our fully-diluted common stock.

Stockholders Agreement. In connection with the closing of the Stock Purchase Agreement, the Company, CCMP and our existing stockholders executed the Stockholders Agreement on April 12, 2010. The Stockholders Agreement provides for certain general rights and restrictions, including board observer rights, informational rights, general restrictions on transfer of common stock, tag-along rights, preemptive rights, registration rights following a Qualified IPO and, subject to certain limited exceptions, prohibitions on the sale or acquisition of our common stock that would result in a change of control, as such term is defined under the indentures for our 8¹/2% senior notes due 2015 and our 8⁷/8% senior notes due 2017.

The Stockholders Agreement also provides for the following stockholder-specific rights or restrictions:

•

Prior to a Qualified IPO, Altoma Energy GP (“Altoma”) will not vote for the approval of (i) any merger, consolidation, conversion or a Demand IPO, (ii) certain amendments to our organizational documents, (iii) the sale of all or substantially all of our assets, or (iv) a termination of the business of or liquidation or dissolution of the Company, unless Fischer Investments, L.L.C. (“Fischer”) votes for such approval.

•

Other than pursuant to the exercise of preemptive rights, CHK Holdings, L.L.C. (“CHK”) may not acquire more than 25% of our outstanding common stock.

•

CCMP may sell up to 20% of its common stock owned on the Closing Date without restriction. Prior to a Qualified IPO and except in limited circumstances, CCMP is restricted from making further sales before the fourth anniversary of the Closing Date, and any sales thereafter (but before a Qualified IPO) will be subject to certain rights of first offer provisions set forth in the Stockholders Agreement (the “ROFO provisions”).

•

Fischer may sell up to 20% of its common stock owned immediately prior to the Closing Date subject to certain restrictions. Prior to a Qualified IPO and except in limited circumstances, Fischer is restricted from making further sales before the fourth anniversary of the Closing Date, and any sales thereafter (but before a Qualified IPO) will be subject to the ROFO provisions.

•

Prior to a Qualified IPO and except in limited circumstances, CHK is restricted from selling its common stock before the 30 month anniversary of the Closing Date, and any sales thereafter (but before a Qualified IPO) will be subject to the ROFO provisions.

•

If our common stock is not listed on a national securities exchange after August 15, 2011, Altoma may request to transfer its shares pursuant to a demand registration, but only after Altoma first offers such shares to the Company, and then to CHK, Fischer and CCMP in accordance with the procedures set forth in the Stockholders Agreement.

•

At any time after the 18 month anniversary of the Closing Date, either (i) CCMP or (ii ) a majority in interest of our existing stockholders may demand that we engage in a Qualified IPO (a “Demand IPO”), if (a) the price per share to be received by the Company or such party or parties, as the case may be, in such Demand IPO is at least 1.75 times the price per share paid by CCMP for our common stock pursuant to the Stock Purchase Agreement and (b) certain other conditions are met.

•

At any time after the four year anniversary of the Closing Date, CCMP may demand a Demand IPO.

•

At any time after the sixth anniversary of the Closing Date, and so long as a Qualified IPO has not yet occurred, CCMP may demand a Company Sale, subject to a right of first offer to purchase the Company provided to Fischer.

With the exception of registration rights, the rights and preferences of a stockholder under the Stockholders Agreement will generally terminate on the earlier of (x) the closing date of a Qualified IPO or (y) the date that such holder and its permitted transferees cease to beneficially own 5% or more of our fully-diluted common stock.

Amended Bylaws. Our bylaws have been amended to conform to the provisions of the Amended and Restated Certificate of Incorporation.

Eighth Restated Credit Agreement

On April 12, 2010, we entered into and closed an Eighth Restated Credit Agreement, which has an initial borrowing base of $450,000, is collateralized by our oil and natural gas properties, and is scheduled to mature on April 12, 2014. We used the proceeds from the sale of common stock to CCMP, along with proceeds available under the Eighth Restated Credit Agreement, to repay the amounts owing under our Seventh Restated Credit Agreement. We expect to record expenses for derivative novation fees and the write off of prepaid bank fees associated with our Seventh Restated Credit Agreement of approximately $2,800, and to record deferred financing costs associated with the closing of our Eighth Restated Credit Agreement of approximately $10,700 during the second quarter of 2010.

Availability under the Eighth Restated Credit Agreement will be subject to a borrowing base which will be set by the banks semi-annually on May 1 and November 1 of each year beginning on November 1, 2010. 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. If we issue Additional Permitted Debt, as defined in the Eighth Restated Credit Agreement, the borrowing base will be automatically reduced by an amount equal to 25% of the aggregate stated principal amount of the debt issued. As of May 13, 2010, we had $172,000 outstanding and $275,330 of availability under our Eighth Restated Credit Agreement.

Borrowings under the Eighth Restated Credit Agreement will be made, at our option, as either Eurodollar loans or Alternate Base Rate (“ABR”) loans.

Interest on Eurodollar loans 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 the Eighth Restated Credit Agreement, plus a margin where the margin varies from 2.50% to 3.50% depending on the utilization percentage of the conforming borrowing base. From April 12, 2010 until October 12, 2010, the margin is fixed at 3.00%. 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 ABR loans is computed as the greater of (1) the Prime Rate, as defined in the Eighth Restated Credit Agreement, (2) the Federal Funds Effective Rate, as defined in Eighth Restated Credit Agreement, plus 1/2 of 1%, or (3) the Adjusted LIBO Rate, as defined in Eighth Restated Credit Agreement, plus 1%; plus a margin where the margin varies from 1.625% to 2.625%, depending on the utilization percentage of the borrowing base.

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

The Eighth Restated Credit Agreement 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.

The Eighth Restated Credit Agreement also has certain negative and affirmative covenants that require, among other things, maintaining a Current Ratio, as defined in the Eighth Restated Credit Agreement, of not less than 1.0 to 1.0. The Eighth Restated Credit Agreement also requires us to maintain a Consolidated Total Debt to Consolidated EBITDAX ratio, as defined in the Eighth Restated Credit Agreement, of not greater than:

•

4.50 to 1.0 for the annualized periods commencing on April 1, 2010 and ending on the last day of the fiscal quarter ending on June 30, 2010, September 30, 2010, and December 31, 2010;

•

4.25 to 1.0 for the four consecutive fiscal quarters ending on March 31, 2011, June 30, 2011, and September 30, 2011; and

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4.00 to 1.0 for the four consecutive fiscal quarters ending on December 31, 2011 and for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarters thereafter.

The Eighth Restated Credit Agreement also specifies events of default, including:

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our failure to pay principal or interest under the Eighth Restated Credit Agreement when due and payable;

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

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our failure to observe or perform certain covenants, conditions or agreements under the Eighth Restated Credit Agreement;

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

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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;

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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;

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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;

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a Change of Control (as defined in the Eighth Restated Credit Agreement); 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 the Eighth Restated Credit Agreement 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.

Derivative transactions

Five of the counterparties to our derivative contracts as of March 31, 2010 are no longer lenders under our Eighth Restated Credit Agreement, which closed on April 12, 2010. As a result, we have novated to counterparties who are lenders under our Eighth Restated Credit Agreement oil swaps covering a total of 1,860 MBbls from April 2010 through December 2012, natural gas swaps covering a total of 7,600 BBtu from May 2010 through December 2011, and natural gas basis swaps covering a total of 10,200 BBtu from May 2010 through December 2011. In addition, we have unwound oil swaps and collars covering a total of 570 MBbls from April 2010 through December 2011 and gas collars covering a total of 1,170 BBtu from April 2010 through December 2010 for net proceeds of approximately $248.

Effective April 1, 2010, we have elected to de-designate all of our commodity derivative contracts that had previously been designated as cash flow hedges and to discontinue hedge accounting prospectively. As a result, all gains and losses from changes in the fair value of our derivative contracts subsequent to March 31, 2010 will be recognized immediately in non-hedge derivative gains (losses) in the consolidated statement of operations. Prior to March 31, 2010, a portion of the change in fair value has been deferred through other comprehensive income. As of March 31, 2010, accumulated other comprehensive income consists of deferred net gains of $32,020 ($19,635 net of tax) that will be recognized as gains (losses) from oil and natural gas hedging activities through December 2013 as the hedged production is sold.

2010 Equity Incentive Plan

We adopted the Chaparral Energy, Inc. 2010 Long-Term 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 are eligible to participate in the 2010 Plan. On April 12, 2010, our Board of Directors approved initial awards of restricted stock under the 2010 Plan totaling 49,333 shares of our class A common stock. These initial awards will be subject to service and market vesting conditions. We are currently assessing the impact of these awards on our financial statements.

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 an independent oil and natural gas company engaged in the production, acquisition and exploitation of oil and natural gas properties. Our areas of operation include the Mid-Continent, Permian Basin, Gulf Coast, Ark-La-Tex, North Texas and the Rocky Mountains. 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, 2009 reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 14%, 11% and 9% 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:

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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.

During the first quarter of 2010, quarterly production was 1,868 MBoe, a 2% decrease from production levels in the first quarter of 2009, primarily due to the decline in production from the Bowdle 47 No. 2 well. However, a 90% increase in our average sales price before hedging resulted in an 86% increase in revenue from oil and natural gas sales in the first quarter of 2010 compared to the same period in 2009. In addition, total operating costs and expenses for the first quarter of 2010 decreased by 80% compared to the first quarter of 2009, primarily because we recorded a non-cash ceiling test impairment of our oil and natural gas properties of $240.8 million during the first quarter of 2009, and no such impairment was recorded during the first quarter of 2010. As a result of these and other factors, we reported net income of $25.5 million during the first quarter of 2010 compared to a net loss of $124.8 million for the comparable period in 2009.

The following are material events that are expected to impact liquidity and/or results of operations in future periods:

•

Stock purchase agreement. On April 12, 2010, we sold 475,043 shares of our common stock to CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively, “CCMP”) for a purchase price of $325.0 million. Fees and other expenses of the transaction were approximately $11.7 million. See Note 10 to our consolidated financial statements for additional information regarding this transaction.

•

Eighth Restated Credit Agreement.In connection with the closing of the sale of our common stock to CCMP, we entered into and closed an Eighth Restated Credit Agreement, which has an initial borrowing base of $450.0 million, is collateralized by our oil and natural gas properties, and is scheduled to mature on April 12, 2014. We used the proceeds from the sale of common stock to CCMP, along with proceeds available under the Eighth Restated Credit Agreement, to repay the amounts owing under our Seventh Restated Credit Agreement. We expect to record expenses for derivative novation fees and the write off of prepaid bank fees associated with our Seventh Restated Credit Agreement of approximately $2.8 million, and to record deferred financing costs associated with the closing of our Eighth Restated Credit Agreement of approximately $10.7 million during the second quarter of 2010.

•

2010 Equity Incentive Plan. We adopted the Chaparral Energy, Inc. 2010 Long-Term 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 are eligible to participate in the 2010 Plan. On April 12, 2010, our Board of Directors approved initial awards of restricted stock under the 2010 Plan totaling 49,333 shares of our class A common stock. These initial awards will be subject to service and market vesting conditions. We are currently assessing the impact of these awards on our financial statements.

Liquidity and capital resources

We pledge our producing oil and natural gas properties to secure our Credit Agreement. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. We utilize the available funds as needed to supplement our operating cash flows as a financing source for our capital expenditures. Our ability to fund our capital expenditures is dependent on the level of product prices and the success of our acquisition and development program in adding to our available borrowing base. 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 for our capital expenditures. 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.

Historically, our primary sources of liquidity have been cash generated from our operations and debt. At March 31, 2010, we had approximately $68.2 million of cash and cash equivalents and $3.3 million of availability under our revolving credit line with a borrowing base of $513.0 million.

On March 23, 2010, we entered into a stock purchase agreement (the “Stock Purchase Agreement”) with CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively, “CCMP”). On April 12, 2010, we sold 475,043 shares of our common stock to CCMP for a purchase price of $325.0 million. Fees and other expenses of the transaction were approximately $11.7 million. In connection with the closing of the Stock Purchase Agreement, we entered into and closed an Eighth Restated Credit Agreement, which has an initial borrowing base of $450.0 million, is collateralized by our oil and natural gas properties, and is scheduled to mature on April 12, 2014. We used the proceeds from the sale of common stock to CCMP, along with proceeds available under the Eighth Restated Credit Agreement, to repay the amounts owing under our Seventh Restated Credit Agreement. As of May 13, 2010, we had $172.0 million outstanding and $275.3 million of availability under our Eighth Restated Credit Agreement. See Note 10 to our consolidated financial statements for additional information regarding these transactions.

Covenants set forth in the indentures for our 8¹/2% Senior Notes and the 8⁷/8% Senior Notes, including 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.

Sources and uses of cash

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


	Three months ended March 31,
(dollars in thousands)	2010			2009
Cash flows provided by operating activities	$	33,502		$	43,631
Cash flows used in investing activities		(36,822	)		(31,495	)
Cash flows used in financing activities		(1,875	)		(1,735	)

Net increase (decrease) in cash during the period	$	(5,195	)	$	10,401

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. During the first quarter of 2009, operating cash flows also included production tax credits of $10.9 million. No such credits were received during the first quarter of 2010, and this source of cash will not be available in future periods. Primarily as a result of the decrease in production tax credits received, cash flows from operating activities decreased by 23% from 2009 to 2010.

We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. For the quarters ended March 31, 2010 and 2009, cash flows provided by operating activities were approximately 75% and 68%, respectively, of cash used for the purchase of property and equipment and oil and natural gas properties.

During the first quarter of 2010, cash used for the purchase of property and equipment and oil and natural gas properties decreased by 31% compared to the first quarter of 2009. However, these cash expenditures during the first quarter of 2009 represented 36% of the total expenditures for the 2009 fiscal year, as we completed projects begun during the fourth quarter of 2008. In contrast, these cash expenditures during the first quarter of 2010 represent only 17% of our budgeted capital expenditures for the 2010 fiscal year. As a result of the capital infusion from CCMP, we expect our capital investing activities to increase significantly beginning in the second quarter of 2010. Our budgeted capital expenditures for oil and natural gas properties for the 2010 fiscal year represent a 78% increase over the amounts spent during the 2009 fiscal year.

During the first quarter of 2010, we received no cash from the monetization of derivatives or the return of our prepaid production tax credits. During the first quarter of 2009, the return of our prepaid production tax credits provided investing cash inflows of $10.9 million, and the monetization of derivatives provided investing cash inflows of $9.5 million. See the “Results of operations” section for additional discussion of these transactions.

Capital expenditures

Our capital expenditures for oil and natural gas properties are detailed below:


(dollars in thousands)	Actual capital expenditures three months ended March 31, 2010		Percent of total		2010 budgeted capital expenditures		Percent of total
Development activities:
Developmental drilling	$	30,302	69	%	$	163,000	61	%
Enhancements		6,963	16	%		12,000	4	%
Tertiary recovery		3,955	9	%		63,000	24	%
Acquisitions:
Proved properties		806	2	%		20,000	7	%
Unproved properties		1,573	4	%		—	0	%
Exploration activities		23	0	%		10,000	4	%

	$	43,622	100	%	$	268,000	100	%

In addition to the capital expenditures for oil and natural gas properties, we spent approximately $1.0 million for property and equipment during the first quarter of 2010.

As of March 31, 2010, we had cash and cash equivalents of $68.2 million and long-term debt obligations of $1.2 billion.

Credit Agreements

As of March 31, 2010, we were party to a Seventh Restated Credit Agreement, which was scheduled to mature on October 31, 2010, and was collateralized by our oil and natural gas properties. The borrowing base, which was reaffirmed effective November 23, 2009, was $513.0 million as of March 31, 2010. We had $507.0 million outstanding under our Seventh Restated Credit Agreement as of March 31, 2010, and all of our borrowings were Eurodollar loans.

On April 12, 2010, in connection with the closing of our Stock Purchase Agreement with CCMP, we entered into and closed an Eighth Restated Credit Agreement, which has an initial borrowing base of $450.0 million, is collateralized by our oil and natural gas properties, and is scheduled to mature on April 12, 2014. We used the proceeds from the sale of common stock to CCMP, along with proceeds available under the Eighth Restated Credit Agreement, to repay the amounts owing under our Seventh Restated Credit Agreement. We expect to record expenses for derivative novation fees and the write-off of prepaid bank fees associated with our Seventh Restated Credit Agreement of approximately $2,800, and to record deferred financing costs associated with the closing of our Eighth Restated Credit Agreement of approximately $10,700 during the second quarter of 2010.

The terms of the Eighth Restated Credit Agreement are described below. The terms of the Seventh Restated Credit Agreement were substantially similar to those contained in the Eighth Restated Credit Agreement. All discussions of interest rates and ratios as of dates prior to April 12, 2010 relate to the Seventh Restated Credit Agreement. Availability under our Credit Agreement 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. If we issue Additional Permitted Debt, as defined in the Eighth Restated Credit Agreement, the borrowing base will be automatically reduced by an amount equal to 25% of the aggregate stated principal amount of the debt issued. As of May 13, 2010, we had $172.0 million outstanding and $275.3 million of availability under our Eighth Restated Credit Agreement.

The agreement has certain negative and affirmative covenants that require, among other things, maintaining a specified current ratio and debt service ratio. We believe we were in compliance with all covenants under the Credit Agreement as of March 31, 2010.

Borrowings under our Credit Agreement are made, at our option, as either Eurodollar loans or Alternate Base Rate (“ABR”) loans.

Interest on Eurodollar loans 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 the Credit Agreement, plus a margin where the margin varies from 2.50% to 3.50% depending on the utilization percentage of the conforming borrowing base. From April 12, 2010 until October 12, 2010, the margin is fixed at 3.00%. 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 ABR loans is computed as the greater of (1) the Prime Rate, as defined in our Credit Agreement, (2) the Federal Funds Effective Rate plus 1/2 of 1%, or (3) the Adjusted LIBO Rate, as defined in our Credit Agreement, plus 1%; plus a margin where the margin varies from 1.625% to 2.625%, depending on the utilization percentage of the borrowing base.

Commitment fees of 0.50% accrue on the unused portion of the borrowing base amount, depending on the utilization percentage, 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 Credit Agreement 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 Credit Agreement requires us to maintain a current ratio, as defined in our Credit Agreement, 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 Credit Agreement, we consider the current ratio calculated under our Credit Agreement to be a useful measure of our liquidity because it includes the funds available to us under our Credit Agreement and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. At March 31, 2010 and December 31, 2009, our current ratio as computed using GAAP was 1.44 and 1.38, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 1.51 and 1.51, 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, 2010			December 31, 2009
Current assets per GAAP	$	165,304		$	161,682
Plus—Availability under Credit Agreement		3,330			3,145
Less—Short-term derivative instruments		(28,620	)		(18,226	)
Less—Deferred tax asset on derivative instruments and asset retirement obligations		—			(1,079	)

Current assets as adjusted	$	140,014		$	145,522

Current liabilities per GAAP	$	115,155		$	117,529
Less—Short term derivative instruments		(18,357	)		(20,677	)
Less—Deferred tax liability on derivative instruments and asset retirement obligations		(3,838	)		—
Less—Short-term asset retirement obligation		(300	)		(300	)

Current liabilities as adjusted	$	92,660		$	96,552

Current ratio for loan compliance		1.51			1.51

The Eighth Restated Credit Agreement requires us to maintain a Consolidated Total Debt to Consolidated EBITDAX ratio, as defined in the Eighth Restated Credit Agreement, of not greater than:

•

4.50 to 1.0 for the annualized periods commencing on April 1, 2010 and ending on the last day of the fiscal quarter ending on June 30, 2010, September 30, 2010, and December 31, 2010;

•

4.25 to 1.0 for the four consecutive fiscal quarters ending on March 31, 2011, June 30, 2011, and September 30, 2011; and

•

The Credit Agreement also specifies events of default, including:

•

our failure to pay principal or interest under the Credit Agreement 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 the Credit Agreement;

•

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;

•

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 the Credit Agreement); and

•

If the outstanding borrowings under our Credit Agreement were to exceed the borrowing base as a result of the 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.

Results of operations

Revenues and production

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


	Three months ended March 31,				Percentage Change
	2010		2009		Percentage Change
Oil and natural gas sales (dollars in thousands)
Oil	$	71,440	$	35,113	103.5	%
Natural gas		28,935		18,754	54.3	%

Total	$	100,375	$	53,867	86.3	%
Production
Oil (MBbls)		974		963	1.1	%
Natural gas (MMcf)		5,364		5,637	(4.8	)%
MBoe		1,868		1,903	(1.8	)%
Average sales prices (excluding derivative settlements)
Oil per Bbl	$	73.35	$	36.46	101.2	%
Natural gas per Mcf	$	5.39	$	3.33	61.9	%
Boe	$	53.73	$	28.31	89.8	%

Oil and natural gas revenues increased $46.5 million, or 86%, during the first quarter of 2010 compared to the first quarter of 2009 due to a 90% increase in the average price per Boe, slightly offset by a 2% decrease in sales volumes. 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, 2010 vs. 2009
(dollars in thousands)	Sales increase (decrease)			Percentage increase (decrease) in sales
Change in oil sales due to:
Prices	$	35,926		102.4	%
Production		401		1.1	%

Total increase in oil sales	$	36,327		103.5	%

Change in natural gas sales due to:
Prices	$	11,089		59.1	%
Production		(908	)	(4.8	)%

Total increase in natural gas sales	$	10,181		54.3	%

Production volumes by area were as follows (MBoe):


	Three Months Ended March 31,		Percentage Change
	2010	2009	Percentage Change
Mid-Continent	1,319	1,223	7.8	%
Permian Basin	333	430	(22.6	)%
Gulf Coast	108	118	(8.5	)%
Ark-La-Tex	38	58	(34.5	)%
North Texas	39	42	(7.1	)%
Rocky Mountains	31	32	(3.1	)%

Totals	1,868	1,903	(1.8	)%

In 2009 we focused our capital expenditures in the Mid-Continent and Permian areas. As a result, production in our other areas has declined and is expected to continue to decline in 2010, because our planned capital expenditures for 2010 are also focused in our core areas of the Mid-Continent and Permian Basin. The increase in production in the Mid-Continent area is primarily due to our participation in six Atoka Wash wells, which came online during the first quarter of 2010.

The decrease in production in the Permian area is primarily due to the Bowdle 47 No. 2, which began selling natural gas in late November 2008 and accounted for approximately 9% of total production for the first quarter of 2009. During the first quarter of 2010, production from this well declined by approximately 28% compared to the first quarter of 2009. We have drilled and completed an offset, the Bowdle 47 No. 4, which came online in April of 2010 and is currently producing at a rate of approximately 11 MMcf per day. This well, combined with several other high impact wells that we are currently drilling or participating in, will support our production levels throughout 2010. However, we cannot accurately predict the timing or level of future production.

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, costless collars, and basis protection swaps. Certain commodity price swaps qualified and were designated as cash flow hedges. All of our derivative instruments are considered to be economic hedges regardless of whether they are designated as cash flow hedges for accounting purposes.

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, excluding derivative monetizations, on realized prices:


	Average Price				Post-settlement to pre-settlement price
	Before derivative settlements		After derivative settlements		Post-settlement to pre-settlement price
Oil (per Bbl):
Three months ended March 31, 2010	$	73.35	$	68.27	93.1	%
Three months ended March 31, 2009		36.46		43.87	120.3	%
Natural gas (per Mcf):
Three months ended March 31, 2010	$	5.39	$	6.73	124.9	%
Three months ended March 31, 2009		3.33		5.02	150.8	%

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.


(dollars in thousands)	March 31, 2010			December 31, 2009
Derivative assets (liabilities):
Oil swaps	$	(64,007	)	$	(68,551	)
Natural gas swaps		53,369			30,340
Oil collars		9,816			12,290
Natural gas collars		14,342			14,065
Natural gas basis differential swaps		(13,211	)		(14,964	)

Net derivative asset (liability)	$	309		$	(26,820	)

During the fourth quarter of 2008, we determined that our natural gas swaps were no longer expected to be highly effective, primarily due to the increased volatility in the basis differentials between the contract price and the indexed price at the point of sale. As a result, we discontinued hedge accounting and applied mark-to-market accounting treatment to all outstanding natural gas swaps. The change in fair value related to these instruments, after hedge accounting was discontinued, is recorded immediately in non-hedge derivative gains (losses) in the consolidated statements of operations. In the past, a portion of the change in fair value would have been deferred through other comprehensive income and the ineffective portion would have been included in gain (loss) from oil and natural gas hedging activities, which is a component of revenue.

In addition, we monetized certain oil and natural gas swaps and collars during the first half of 2009 and the fourth quarter of 2008. Certain swaps that were monetized had previously been accounted for as cash flow hedges. As of March 31, 2010 and December 31, 2009, accumulated other comprehensive income included $82.9 million and $83.4 million, respectively, of deferred gains related to discontinued cash flow hedges that will be recognized as a gain from oil and natural gas hedging activities when the hedged production is sold. No oil and natural gas derivatives were monetized in the first quarter of 2010.

Effective April 1, 2010, we have elected to de-designate all of our commodity derivative contracts that had previously been designated as cash flow hedges and to discontinue hedge accounting prospectively. As a result, all gains and losses from changes in the fair value of our derivative contracts subsequent to March 31, 2010 will be recognized immediately in non-hedge derivative gains (losses) in the consolidated statement of operations. Prior to March 31, 2010, a portion of the change in fair value has been deferred through other comprehensive income. As of March 31, 2010, accumulated other comprehensive income consists of deferred net gains of $32.0 million ($19.6 million net of tax) that will be recognized as gains (losses) from oil and natural gas hedging activities through December 2013 as the hedged production is sold.

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


	Three months ended March 31,
	2010						2009
(dollars in thousands)	Non-cash fair value adjustment			Cash receipts (payments)			Non-cash fair value adjustment			Cash receipts (payments)
Gain (loss) from oil and natural gas hedging activities:
Oil swaps	$	—		$	(5,504	)	$	7,985		$	4,631
Natural gas swaps		519			—			2,887			—

Gain (loss) from oil and natural gas hedging activities	$	519		$	(5,504	)	$	10,872		$	4,631

Non-hedge derivative gains (losses):
Oil swaps and collars	$	(1,737	)	$	559		$	(1,868	)	$	2,505
Natural gas swaps and collars		23,306			11,616			34,986			7,781
Natural gas basis differential contracts		1,752			(4,439	)		(4,326	)		1,771
Derivative monetizations		—			—			(44	)		9,522

Non-hedge derivative gains	$	23,321		$	7,736		$	28,748		$	21,579

Total gains from derivative activities	$	23,840		$	2,232		$	39,620		$	26,210

During the first quarter of 2010, we recorded a loss on oil derivatives of $6.7 million, due primarily to improved oil prices during the period. There were no gains associated with discontinued oil hedges that were reclassified into earnings during the first quarter of 2010. We recorded a gain on oil derivatives of $13.2 million during the first quarter of 2009, due primarily to gains of $8.4 million associated with derivatives monetized during the fourth quarter of 2008 that were reclassified into earnings during the first quarter of 2009, and to the low oil prices prevalent during the period.

Due primarily to low natural gas prices prevalent during the first quarters of 2010 and 2009, and to lower average NYMEX forward strip gas prices as of March 31, 2010 and 2009 compared to December 31, 2009 and 2008, respectively, we recognized a gain on gas derivatives of $35.5 million and $45.7 million during the first quarters of 2010 and 2009, respectively. This included gains of $0.5 million and $2.9 million reclassified into earnings during the first quarters of 2010 and 2009, respectively, that were associated with derivatives for which hedge accounting was discontinued in 2008.

During the first quarter of 2010, losses on natural gas basis differential contracts were $2.7 million primarily due to lower than expected differentials. During the first quarter of 2009, losses on natural gas basis differential contracts were $2.6 million primarily due to lower differentials indicated by the forward commodity price curves as of March 31, 2009 compared to December 31, 2008.

In addition, during the first quarter of 2009, we monetized natural gas swaps with original settlement dates from May through October of 2009 for proceeds of $9.5 million. As a result of this transaction, gains of $9.5 million were recognized in earnings during the first quarter of 2009.

As a result of the above transactions, our statements of operations for the first quarter of 2010 and 2009 included total net gains on derivative activities of $26.1 million and $65.8 million, respectively.

Lease operating expenses


(dollars in thousands)	Three months ended March 31,				Percent decrease
(dollars in thousands)	2010		2009		Percent decrease
Lease operating expenses	$	24,419	$	27,503	(11.2	)%

Lease operating expenses per Boe	$	13.07	$	14.45	(9.6	)%

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. Due primarily to lower overall operating and service costs, lease operating expenses for the first quarter of 2010 decreased by $3.1 million, or $1.38 per Boe, compared to the first quarter of 2009. During the last half of 2009 and the first quarter of 2010, commodity prices have been improving, and if this upward trend continues, we expect absolute operating costs to increase as well.

Production taxes (which include ad valorem taxes)


	Three months ended March 31,				Percent increase
(dollars in thousands)	2010		2009		Percent increase
Production taxes	$	6,990	$	3,860	81.1	%

Production taxes per Boe	$	3.74	$	2.03	84.2	%

Production taxes generally change in proportion to oil and natural gas sales. The increase in production taxes during the first quarter of 2010 compared to the first quarter of 2009 was primarily due to the 90% increase in average realized prices, slightly offset by the 2% decrease in sales volumes.

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


	Three months ended March 31,				Percent increase (decrease)
(dollars in thousands)	2010		2009		Percent increase (decrease)
DD&A:
Oil and natural gas properties	$	21,493	$	27,338	(21.4	)%
Property and equipment		2,240		2,179	2.8	%
Accretion of asset retirement obligation		788		701	12.4	%

Total DD&A	$	24,521	$	30,218	(18.9	)%

DD&A per Boe:
Oil and natural gas properties	$	11.51	$	14.37	(19.9	)%
Other fixed assets		1.62		1.51	7.3	%

Total DD&A per Boe	$	13.13	$	15.88	(17.3	)%

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 decreased $5.8 million in the first quarter of 2010 compared to the first quarter of 2009, of which $5.3 million was due to a lower rate per equivalent unit of production and $0.5 million was due to the decrease in production. Our DD&A rate per equivalent unit of production decreased $2.86 to $11.51 per Boe primarily due to the increase in reserves resulting from higher commodity prices.

Impairment of oil and natural gas properties

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”), as adjusted for our cash flow hedge positions and net of tax considerations, plus the lower of cost or estimated fair value of unproved properties. During the first quarter of 2009, natural gas prices declined significantly as compared to the December 31, 2008 spot price of $5.62 per Mcf. Based on March 31, 2009 spot prices of $49.66 per Bbl of oil and $3.63 per Mcf of natural gas, the internally estimated PV-10 value of our reserves declined by 13.5% compared to the PV-10 value at December 31, 2008. As a result, we recorded a ceiling test impairment of oil and natural gas properties of $240.8 million during the first quarter of 2009. The effect of derivative contracts accounted for as cash flow hedges, based on the March 31, 2009 spot prices, increased the full cost ceiling by $169.0 million, thereby reducing the ceiling test write down by the same amount.

General and administrative expenses


	Three months ended March 31,						Percent increase
(dollars in thousands)	2010			2009			Percent increase
Gross G&A expenses	$	9,636		$	9,228		4.4	%
Capitalized exploration and development costs		(3,196	)		(2,860	)	11.7	%

Net G&A expenses	$	6,440		$	6,368		1.1	%

Average G&A cost per Boe	$	3.45		$	3.35		3.0	%

General and administrative expenses for the first quarter of 2010 increased by $0.10 per Boe compared to the first quarter of 2009 primarily due to increased compensation costs.

Litigation settlement

Effective April 15, 2009, we settled our pending lawsuit against John Milton Graves Trust u/t/a 6/11/2004, et al. This case was related to (i) a post-closing adjustment of the price we paid for Calumet Oil Company (“Calumet”) in 2006 (the “Working Capital Adjustment”) and (ii) a contractual payment related to an election to be made by the sellers of Calumet (collectively, the “Sellers”) under the federal tax code (the “Tax Election”). As of December 31, 2008, the recorded receivable for the Working Capital Adjustment was $14.4 million, and the recorded payable related to the Tax Election was $4.4 million.

Pursuant to the settlement agreement, which was based upon net calculations of the receivable and payable, the Sellers paid us $7.1 million, which amount is intended to settle all claims related to both the Working Capital Adjustment and the Tax Election claims, and we retained $0.4 million contained in an escrow account covering any losses incurred by us for title defects related to our purchase of Calumet. In addition, the parties issued mutual releases, dismissed with prejudice the pending litigation and the claims made therein, and the Sellers will take action to clear the title to certain properties purchased by us in the Calumet acquisition.

As a result of the settlement, as of March 31, 2009, the receivable related to the Working Capital Adjustment was written down to $7.1 million, the Tax Election payable was eliminated, the escrow cash account was reclassified to operating cash, and we recorded a charge to expense of $2.9 million.

Interest expense

The following table presents interest expense for the first quarter of 2010 and 2009:


	Three months ended March 31,
(dollars in thousands)	2010		2009
Revolver interest	$	6,267	$	6,852
8¹/2% Senior Notes due 2015		7,115		7,097
8⁷/8% Senior Notes due 2017		7,411		7,394
Bank fees and other interest		1,759		1,121

Total interest expense	$	22,552	$	22,464

Average long-term borrowings	$	1,176,285	$	1,270,485

Production tax credits

During 2006, we purchased interests in two venture capital limited liability companies resulting in a total investment of $15.0 million. Our return on the investment was the receipt of $2 of Oklahoma tax credits for every $1 invested and was recouped from our Oklahoma production taxes. The investments were accounted for as a production tax benefit asset and were netted against tax credits realized in other income using the effective yield method over the expected recovery period. Other income for the first quarter of 2010 and 2009 included Oklahoma production tax credits of $0 and $10.9 million, respectively. This source of income will not be available in future periods.

Discontinued operations

Discontinued operations consist of the third-party revenues and operating expenses of the Electric Submersible Pumps (“ESP”) and Chemicals divisions of Green Country Supply, Inc. (“GCS”), a wholly owned subsidiary. Revenues were generated through the sale of oilfield supplies, chemicals, downhole submersible pumps, and related services to oil and natural gas operators primarily in Oklahoma, Texas, and Wyoming. Operating expenses consisted of costs of sales related to product sales and general and administrative expenses.


(dollars in thousands)	Three months ended March 31, 2009
Revenues	$	4,252
Operating expenses		(4,177	)
Depreciation, depletion, and amortization		(225	)

Loss before income taxes		(150	)
Income tax benefit		(58	)

Loss from discontinued operations, net of related taxes	$	(92	)

There were no assets held for sale or liabilities associated with discontinued operations as of March 31, 2010 or December 31, 2009.

Non-GAAP financial measure and reconciliation

We define adjusted EBITDA as net income (loss), 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 ineffective portion of hedges and reclassification adjustments, (5) non-cash change in fair value of non-hedge derivative instruments, (6) interest income, (7) deferred compensation expense (gain), (8) gain or loss on disposed assets, and (9) impairment charges and other significant, unusual non-cash charges. Any cash proceeds received from the monetization of derivatives with a scheduled maturity date more than 12 months following the date of such monetization are excluded from the calculation of adjusted EBITDA.

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 the financial measurement that is used in the covenant calculation required under our Credit Agreement 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. The following table provides a reconciliation of net loss to adjusted EBITDA for the specified periods:


	Three months ended March 31,
(dollars in thousands)	2010			2009
Net income (loss)	$	25,464		$	(124,824	)
Interest expense		22,552			22,464
Income tax expense (benefit)		16,069			(78,406	)
Depreciation, depletion, and amortization		24,521			30,443
Unrealized gains on ineffective portion of hedges and reclassification adjustments		(519	)		(10,872	)
Non-cash change in fair value of non-hedge derivative instruments		(23,321	)		(28,748	)
Interest income		(92	)		(101	)
Non-cash deferred compensation expense		166			156
Gain on disposed assets		(42	)		(1	)
Loss on impairment of oil and natural gas properties		—			240,790
Loss on litigation settlement		—			2,928

Adjusted EBITDA	$	64,798		$	53,829

Critical accounting policies and estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements. The preparation of these statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. We base our estimates on historical experience and other sources that we believe are reasonable at the time. Actual results may differ from the estimates and assumptions we used in preparation of our financial statements. We evaluate our estimates and assumptions on a regular basis. Described below are the most significant policies and the related estimates and assumptions we apply in the preparation of our financial statements. See Note 1 to our consolidated financial statements for an additional discussion of accounting policies and estimates made by management.

Revenue recognition. We derive almost all of our revenue from the sale of crude oil and natural gas produced from our oil and natural gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and actual payment received for all prior months are recorded in the month payment is received.

Derivative instruments. Certain of our oil and natural gas derivative contracts are designed to be treated as cash flow hedges under GAAP. This policy significantly impacts the timing of revenue or expense recognized from this activity, as our contracts are adjusted to their fair value at the end of each month. The effective portion of the hedge gain or loss, meaning the portion of the change in the fair value of the contract that offsets the change in the expected future cash flows from our forecasted sales of production, is recognized in income when the hedged production is reported as revenue. We reflect this as an adjustment to our revenue in the “Gain (loss) from oil and natural gas hedging activities” line in our consolidated statements of operations. Until hedged production is reported in earnings and the contract settles, the effective portion of change in the fair value of the contract is reported in the “Accumulated other comprehensive income (loss)” line item in stockholders’ equity. The ineffective portion of the hedge gain or loss is reported in the “Gain (loss) from oil and natural gas hedging activities” line item each period. Our derivative contracts that do not qualify for cash flow hedge treatment, or have not been designated as cash flow hedges, are marked to their period end market values and the change in the fair value of the contracts is included in the “Non-hedge derivative gains (losses)” line in our consolidated statements of operations. As a result, our reported earnings could include large non-cash fluctuations, particularly in volatile pricing environments.

We determine the fair value of our crude oil, natural gas, and basis swaps by reference to forward pricing curves for oil and natural gas futures contracts. The difference between the forward price curve and the contractual fixed price is discounted to the measurement date using a credit risk adjusted discount rate. In certain less liquid markets, forward prices are not as readily available. In these circumstances, swaps are valued using internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. These contracts are classified as Level 3 in accordance with the fair value hierarchy defined by the Financial Accounting Standards Board (“FASB”). We have determined that the fair value methodology described above for the remainder of our swaps is consistent with observable market inputs and have categorized them as Level 2. We determine fair value for our oil and natural gas collars using an option pricing model which takes into account market volatility, market prices, contract parameters, and credit risk. Due to unavailability of observable volatility data input for our collars, we have determined that all of our collars’ fair value measurements are categorized as Level 3. Derivative instruments are discounted using a rate that incorporates our nonperformance risk for derivative liabilities, and our counterparties’ credit risk for derivative assets. Our derivative contracts have been executed with the institutions that are parties to our revolving credit facility. We believe the credit risks associated with all of these institutions are acceptable.

Oil and natural gas properties.

•

Full cost accounting. We use the full cost method of accounting for our oil and natural gas properties. Under this method, all costs incurred in the exploration and development of oil and natural gas properties are capitalized into a cost center. These costs include drilling and equipping productive wells, dry hole costs, seismic costs and delay rentals. Capitalized costs also include salaries, employee benefits, consulting services and other expenses that directly relate to our exploration and development activities.

•

Proved oil and natural gas reserves quantities. Proved oil and natural gas reserves are the quantities of crude oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. The estimates of proven reserves for a given reservoir may change significantly over time as a result of changing prices, operating cost, additional development activity and the actual operating performance.

•

Depreciation, depletion and amortization. The quantities of proved oil and natural gas reserves are a significant component of our calculation of depreciation, depletion and amortization expense and revisions in such estimates may alter the rate of future expense. The depreciation, depletion and amortization rate is determined using the units-of-production method based on estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based on the relative energy content.

•

Full cost ceiling limitation. Under the full cost method, the net capitalized costs of oil and natural gas properties recorded on our balance sheet cannot exceed the estimated future net revenues discounted at 10%, adjusted for the impact of derivatives accounted for as cash flow hedges, plus the lower of cost or fair market value of unproved properties. The ceiling calculation requires that prices and costs used to determine the estimated future net revenues exclude escalations based upon future conditions. If oil and natural gas prices decline or if we have downward revisions to our estimated reserve quantities, it is possible that write downs of our oil and natural gas properties could occur in the future.

•

Costs not subject to amortization. Costs of unevaluated properties are excluded from our amortization base until we have evaluated the properties. The costs associated with unevaluated leasehold acreage and seismic data, exploratory wells currently drilling, and capitalized interest are initially excluded from our amortization base. Leasehold costs are either transferred to the amortization base with the costs of drilling a well or are assessed quarterly for possible impairment. Our future depreciation, depletion and amortization rate would increase if costs are transferred to the amortization base without any associated reserves.

•

Future development and abandonment costs. Our future development costs include costs to be incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to plug and abandon our oil and natural gas properties and related facilities. We develop estimates of these costs for each of our properties based on their location, type of facility, market demand for equipment and currently available procedures. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make numerous judgments. These judgments are subject to future revisions from changing technology and regulatory requirements. We review our assumptions and estimates of future development and future abandonment costs on a quarterly basis.

We record a liability for the estimated fair value of an asset retirement obligation in the period in which it is incurred and the corresponding cost is capitalized by increasing the carrying value of the related asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset.

We use the present value of estimated cash flows related to our asset retirement obligation to determine the fair value. Significant assumptions used in estimating such obligations include estimates of the ultimate costs of dismantling and site restoration, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments, all of which are Level 3 inputs in the fair value hierarchy. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment will be required for the related asset. We believe the estimates and judgments reflected in our financial statements are reasonable but are necessarily subject to the uncertainties we have just described. Accordingly, any significant variance in any of the above assumptions or factors could materially affect our estimated future cash flows.

Income taxes. Deferred income taxes are provided for the difference between the tax basis of assets and liabilities and the carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled. Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities. We record adjustments to actual in the period we file our tax returns.

Valuation allowance for NOL carryforwards. In computing our income tax expense, we assess the need for a valuation allowance on deferred tax assets, which consist primarily of net operating loss, or NOL, carryforwards. For federal income tax purposes these NOL carryforwards expire 15 to 20 years from the year of origination. We generally assess our ability to fully utilize these carryforwards by estimating expected future taxable income based on the assumption that we will produce our existing reserves, as scheduled for production in our reserve report and by analyzing the expected reversal of existing deferred tax liabilities. These computations are imprecise due to the extensive use of estimates and assumptions. Each quarter we assess our ability to utilize NOL carryforwards. We will record a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such asset will not be realized.

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

Recent accounting pronouncements

See recently adopted and issued accounting standards in Part I, Item 1. Financial Statements, Note 1: Nature of operations and summary of significant accounting policies.

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 Credit Agreement and adversely affect our liquidity and our ability to obtain capital for our acquisition, exploration and development activities. Based on our three months ended March 31, 2010 production, our gross revenues from oil and natural gas sales would change approximately $0.5 million for each $0.10 change in natural gas prices and $1.0 million for each $1.00 change in oil prices.

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

Our outstanding oil and natural gas derivative instruments as of March 31, 2010 are summarized below:


	Crude Oil Swaps						Crude Oil Collars			Percent of PDP production (1)
	Hedge			Non-hedge			Non-hedge
	Volume MBbl	Weighted average fixed price to be received		Volume MBbl	Weighted average fixed price to be received		Volume MBbl	Weighted average range
2Q 2010	564	$	69.04	90	$	65.47	60	$	110.00 - $168.55	81.4	%
3Q 2010	547		69.32	90		65.10	60		110.00 - 168.55	81.8	%
4Q 2010	528		69.29	90		64.75	60		110.00 - 168.55	81.5	%
1Q 2011	459		70.56	99		64.24	51		110.00 - 152.71	74.9	%
2Q 2011	459		70.49	90		63.93	51		110.00 - 152.71	75.2	%
3Q 2011	439		69.61	90		63.61	51		110.00 - 152.71	74.1	%
4Q 2011	429		69.03	90		63.30	51		110.00 - 152.71	74.1	%
1Q 2012	150		89.90	—		—	—		—	20.1	%
2Q 2012	150		90.27	—		—	—		—	20.6	%
3Q 2012	150		90.65	—		—	—		—	21.0	%
4Q 2012	150		91.01	—		—	—		—	21.4	%

	4,025			639			384


	Natural Gas Swaps Non-hedge			Natural Gas Collars Non-hedge			Percent of PDP production (1)
	Volume BBtu	Weighted average fixed price to be received		Volume BBtu	Weighted average range		Percent of PDP production (1)
2Q 2010	4,230	$	6.64	840	$	10.00 - $11.53	82.8	%
3Q 2010	3,700		7.01	840		10.00 - 11.53	81.4	%
4Q 2010	3,450		7.55	840		10.00 - 11.53	81.8	%
1Q 2011	3,150		7.66	—		—	63.2	%
2Q 2011	3,000		6.86	—		—	62.9	%
3Q 2011	3,000		7.03	—		—	65.3	%
4Q 2011	3,000		7.39	—		—	67.6	%

	23,530			2,520


	Natural Gas Basis Protection Swaps Non-hedge
	Volume BBtu	Weighted average fixed price to be paid
2Q 2010	4,120	$	0.73
3Q 2010	3,930		0.74
4Q 2010	3,600		0.79
1Q 2011	3,600		0.80
2Q 2011	3,260		0.71
3Q 2011	3,120		0.71
4Q 2011	3,010		0.72

	24,640

(1)	Based on our most recent internally estimated PDP production for such periods.

Subsequent to March 31, 2010, we entered into additional oil swaps for 1,100 Mbls for the periods of May 2010 through December 2012 with a weighted average price of $91.15.

Interest rates. All of the outstanding borrowings under our Credit Agreement as of March 31, 2010 are subject to market rates of interest as determined from time to time by the banks. We may designate borrowings under our Credit Agreement as either ABR loans or Eurodollar loans. ABR loans bear interest at a fluctuating rate that is linked to the greater of (1) the Prime Rate, as defined in our Credit Agreement, (2) the Federal Funds Effective Rate plus¹/2 of 1%, or (3) the Adjusted LIBO rate, as defined in our Credit Agreement, plus 1%. Eurodollar loans bear interest at a fluctuating rate that is linked to LIBOR. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $513.0 million, equal to our borrowing base, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $5.1 million.

ITEM 4.

CONTROLS AND PROCEDURES

Disclosure controls and procedures

We have established disclosure controls and procedures to ensure that material information relating to the Company, including its 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 Chairman, President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 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.

PART II—OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

In the opinion of management, there are no other material pending legal proceedings to which we or any of our subsidiaries 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.

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, 2009. There have been no material changes to the risk factors since the filing of such Form 10-K.

ITEM 6.

EXHIBITS


Exhibit No.		Description

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

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

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

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

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 13, 2010

EXHIBIT INDEX


Exhibit No.		Description

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

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

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

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

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	H.S. freshman Avg

Chaparral Energy (CHAP) 10-Q2010 Q1 Quarterly report

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