Chaparral Energy (CHAP) 10-Q 2006 Q2 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 June 30, 2006

OR

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

For the transition period from            to            

Commission file number: 333-134748

Chaparral Energy, Inc.

(Exact name of registrant as specified in its charter)

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

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

(405) 478-8770

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Act). (Check one)

Large Accelerated Filer  ¨    Accelerated Filer  ¨    Non-Accelerated Filer  x

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

877,000 shares of the registrant’s Common Stock were outstanding as of July 10, 2007.

CHAPARRAL ENERGY, INC.

Index to Form 10-Q

		Page
Part I. FINANCIAL INFORMATION		5
Item 1.	Financial Statements	5
	Consolidated Balance Sheets as of June 30, 2006 and December 31, 2005	5
	Consolidated Statements of Operations for the three months and six months ended June 30, 2006 and 2005	6
	Consolidated Statements of Cash Flows for the six months ended June 30, 2006 and 2005	7
	Notes to Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	15
	Overview	15
	Results of Operations	16
	Liquidity and Capital Resources	18
	Critical Accounting Policies and Estimates	21
	Recent Accounting Pronouncements	22
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	23
Item 4.	Controls and Procedures	24
Part II. OTHER INFORMATION		24
Item 1.	Legal Proceedings	24
Item 1A.	Risk Factors	25
Item 6.	Exhibits	31
Signatures		33
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)

EXPLANATORY NOTE

This Form 10-Q includes information previously contained in the registrant’s post-effective amendment on Form S-4 filed with the SEC on August 11, 2006. No securities registered pursuant to such registration statement were issued as of the date of the post-effective amendment or as of the date such post-effective amendment was declared effective.

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CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

This report includes statements that constitute forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties. These statements may relate to, but are not limited to, information or assumptions about capital and other expenditures, dividends, financing plans, capital structure, cash flow, pending legal and regulatory proceedings and claims, including environmental matters, future economic performance, operating income, cost savings, management’s plans, strategies, goals and objectives for future operations and growth.

These forward-looking statements generally are accompanied by words such as “intend,” “anticipate,” “believe,” “estimate,” “expect,” “should,” “seek,” “project,” “plan” or similar expressions. It should be understood that these forward-looking statements are necessarily estimates reflecting the best judgment of our senior management, not guarantees of future performance. They are subject to a number of assumptions, risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the forward-looking statements.

Forward-looking statements may relate to various financial and operational matters, including, among other things:

• fluctuations in demand or the prices received for our 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 our 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 or property acquisitions;

• marketing of oil and natural gas; and

• general economic conditions and the other risks and uncertainties discussed in this report.

Undue reliance should not be placed on forward-looking statements, which speak only as of the date of this report. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of certain terms commonly used in the oil and natural gas industry and in this Report:

• Bbl.One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

• Bcfe. One billion cubic feet of natural gas equivalents.

• MBbl.One thousand Bbls.

• Mcf.One thousand cubic feet of natural gas.

• Mcfe.One thousand cubic feet of natural gas equivalents.

• MMBbl.One million Bbls.

• MMcf.One million cubic feet of natural gas.

• MMcfe. One million cubic feet of natural gas equivalents.

• NYMEX.The New York Mercantile Exchange.

• PDP. Proved developed producing.

• Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

• 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.

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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets

(Dollars in thousands, except share data)	December 31, 2005			June 30, 2006 (unaudited)
Assets
Current assets:
Cash and cash equivalents	$	1,598		$	10,817
Accounts receivable, net		42,431			38,175
Inventories		6,788			7,726
Deferred income taxes		23,831			16,372
Prepaid expenses		1,591			765
Derivative instruments		1,016			3,301
Total current assets		77,255			77,156
Property and equipment—at cost, net		22,428			23,600
Oil & gas properties, using the full cost method:
Proved		600,185			693,583
Unproved		10,150			15,322
Accumulated depletion and depreciation		(74,799	)		(95,799	)
Total oil & gas properties		535,536			613,106
Other assets		12,160			11,978
	$	647,379		$	725,840
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	44,183		$	52,388
Revenue distribution payable		8,858			16,368
Current maturities of long-term debt and capital leases		3,126			3,521
Derivative instruments		63,125			39,463
Total current liabilities		119,292			111,740
Long-term debt and capital leases, less current maturities		118,418			168,719
8 1/2% Senior notes, due 2015		325,000			325,000
Derivative instruments		32,001			17,239
Deferred compensation		645			802
Asset retirement obligation		15,450			16,371
Deferred income taxes		26,406			41,133
Commitments and contingencies (note 7)
Stockholders’ equity:
Common stock, $.01 par value-5,000 shares authorized; 1,000 shares issued and outstanding as of December 31, 2005 and June 30, 2006		1			1
Retained earnings		58,133			73,938
Accumulated other comprehensive loss, net of taxes		(47,967	)		(29,103	)
		10,167			44,836
	$	647,379		$	725,840

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

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Chaparral Energy, Inc. and subsidiaries

Consolidated statements of operations

	Three months ended June 30,						Six months ended June 30,
(dollars in thousands, except share and per share data)	2005 (unaudited)			2006 (unaudited)			2005 (unaudited)			2006 (unaudited)
Revenues:
Oil and gas sales	$	42,334		$	60,969		$	78,483		$	122,264
Loss from oil and gas hedging activities		(8,574	)		(5,526	)		(17,413	)		(6,679	)
Total revenues		33,760			55,443			61,070			115,585
Costs and expenses:
Lease operating		10,027			16,100			18,663			31,233
Production tax		2,997			4,886			5,648			9,544
Depreciation, depletion and amortization		7,051			12,143			13,302			23,196
General and administrative		1,860			3,250			4,160			6,655
Total costs and expenses		21,935			36,379			41,773			70,628
Operating income		11,825			19,064			19,297			44,957
Non-operating income (expense):
Interest expense		(2,703	)		(9,492	)		(5,048	)		(18,657	)
Non-hedge derivative losses		—			(112	)		—			(112	)
Other income		145			421			318			525
Net non-operating expense		(2,558	)		(9,183	)		(4,730	)		(18,244	)
Income from before income taxes and minority interest		9,267			9,881			14,567			26,713
Income tax expense		3,622			3,819			5,659			10,279
Minority interest		—			(71	)		—			(71	)
Net income	$	5,645		$	6,133		$	8,908		$	16,505
Earnings per share
Net income per share (basic and diluted)	$	5,645		$	6,133		$	8,908		$	16,505
Weighted average number of shares used in calculation of basic and diluted earnings per share		1,000			1,000			1,000			1,000

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

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Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows

	Six months ended June 30,
(Dollars in thousands)	2005 (unaudited)			2006 (unaudited)
Cash flows from operating activities
Net income (loss)	$	8,908		$	16,505
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion & amortization		13,302			23,196
Deferred income taxes		5,619			10,287
Unrealized (gain) loss on ineffective portion of hedges		4,447			(10,056	)
Non-cash change in fair value of derivative instruments		—			112
Other		65			409
Change in assets and liabilities
Accounts receivable		(1,481	)		4,091
Inventories		(71	)		(939	)
Prepaid expenses and other assets		234			855
Accounts payable and accrued liabilities		5,884			8,189
Revenue distribution payable		938			7,509
Net cash provided by operating activities		37,845			60,158
Cash flows from investing activities
Purchase of property and equipment and oil and gas properties		(71,092	)		(105,397	)
Proceeds from dispositions of property and equipment and oil and gas properties		338			4,903
Other		54			—
Net cash used in investing activities		(70,700	)		(100,494	)
Cash flows from financing activities
Proceeds from long-term debt		33,925			52,071
Repayment of long-term debt		(860	)		(1,301	)
Proceeds from long-term bonds		—			—
Principal payments under capital lease obligations		(376	)		(73	)
Dividends		(2,709	)		(700	)
Fees paid related to financing activities		—			(442	)
Net cash provided by financing activities		29,980			49,555
Net increase (decrease) in cash and cash equivalents		(2,875	)		9,219
Cash and cash equivalents at beginning of period		13,842			1,598
Cash and cash equivalents at end of period	$	10,967		$	10,817
Supplemental cash flow information
Cash paid (received) during the period for:
Interest, net of capitalized interest	$	4,602		$	18,282
Income taxes		39			(8	)

The accompanying notes are an integral part of these statements.

7

Chaparral Energy, Inc. and subsidiaries

Consolidated Statements of Cash Flows—(Continued)

Supplemental disclosure of non-cash investing and financing activities

During the six months ended June 30, 2005 and 2006, the Company recorded an asset and related liability of $1,956 and $360, respectively associated with the asset retirement obligation on the acquisition and/or development of oil and gas properties.

Interest of $0 and $404 was capitalized during the six months ended June 30, 2005 and 2006, respectively, primarily related to the acquisition of unproved oil and gas leaseholds.

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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 gas properties. Properties are located primarily in Oklahoma, Texas, New Mexico, Louisiana, Arkansas, Montana 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 June 30, 2006 and for the three months and six months ended June 30, 2005 and 2006 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 and six months ended June 30, 2006 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2006.

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 S-4 registration statement, as amended, filed with the Securities and Exchange Commission which became effective on August 11, 2006.

Principles of Consolidation

The unaudited consolidated financial statements include the accounts of Chaparral Energy, Inc. and its wholly and majority owned subsidiaries. All significant intercompany balances and transactions have been eliminated. The loss from operations related to the minority interest of Oklahoma Ethanol, LLC is shown separately in the statement of operations. As the minority interests’ share of the losses has exceeded their equity and there is no obligation for the minority interest holders to fund those losses, the minority interest balance is reported as zero in the consolidated balance sheet and is therefore charged against the Company. If future earnings materialize, the Company will recognize all earnings up to the amount of those losses previously recorded.

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 gas reserves, deferred income taxes, asset retirement obligations, fair value of derivative instruments, and others, and are subject to change.

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.

Inventories

Inventories consist of equipment used in developing oil and gas properties of $5,029 and $5,820 at December 31, 2005 and June 30, 2006, respectively, and product of $1,759 and $1,906 at December 31, 2005 and June 30, 2006, respectively. Equipment inventory is carried at the lower of cost or market using the specific identification method. Product inventories are stated at the lower of production cost or market.

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Recently Issued Accounting Standards

The FASB issued SFAS No. 155,Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140, in February 2006. SFAS No. 155 addresses accounting for beneficial interests in securitized financial instruments. The guidance allows fair value remeasurement for any hybrid financial instrument containing an embedded derivative that would otherwise require bifurcation and clarifies which interest-only and principal-only strips are not subject to SFAS No. 133. SFAS No. 155 also established a requirement to evaluate interests in securitized financial assets to identify any interests that are either freestanding derivatives or contain an embedded derivative requiring bifurcation. The statement is effective for all financial instruments issued or acquired after the beginning of the first fiscal year that begins after September 15, 2006. Management does not expect this statement will have a material impact on our financial position, results of operations or cash flows.

In June 2006, the FASB issued interpretation No. 48,Accounting for Uncertainty in Income Taxes—an Interpretation of FASB statement No. 109,(“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109,Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 is effective for fiscal years beginning after December 15, 2006. We will adopt FIN 48 on January 1, 2007 and are currently reviewing this new standard to determine its effects, if any, on our financial position, results of operations or cash flows.

Note 2: Derivative Financial Instruments

The Company’s results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of and demand for oil and gas. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, the Company enters into swap agreements. For swap instruments, the Company receives a fixed price for the hedged commodity and pays 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.

The Company also uses derivative financial instruments 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 gas from a specified delivery point. The Company receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. We do not believe that these instruments qualify as hedges pursuant to SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activity” (“SFAS 133”), as amended. Therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative gains (losses).

All derivative financial instruments are recorded on the balance sheet at fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying forward market price at the determination date considering the time value of money.

The estimated fair values of derivative instruments are provided below. The carrying amounts of these instruments are equal to the estimated fair values.

	December 31, 2005			June 30, 2006
Derivative assets (liabilities):
Gas swaps	$	(60,158	)	$	(9,634	)
Oil swaps		(33,952	)		(43,655	)
Natural gas basis differential swaps		—			(112	)
	$	(94,110	)	$	(53,401	)

Changes in the fair value of effective cash flow hedges are recorded as a component of accumulated other comprehensive income (loss), 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

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flows from the item hedged. The ineffective portion of the hedge derivatives and the settlement of effective cash flow hedges is included in gain (loss) on oil and gas hedging activities in the consolidated statements of operations and is comprised of the following:

	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2006			2005			2006
Reclassification of settled contracts	$	(8,494	)	$	(8,190	)	$	(12,966	)	$	(16,735	)
Gain (loss) on ineffective portion of derivatives qualifying for hedge accounting		(80	)		2,664			(4,447	)		10,056
	$	(8,574	)	$	(5,526	)	$	(17,413	)	$	(6,679	)

Based upon market prices at June 30, 2006 the Company expects to charge $19,815 of the balance in accumulated other comprehensive loss to income during the next 12 months when the forecasted transactions actually occur. All forecasted transactions hedged as of June 30, 2006 are expected to be settled by December 2008.

The changes in fair value and settlement of derivative contracts that do not qualify as hedges in accordance with SFAS 133 are recognized as non-hedge derivative losses. Non-hedge derivative losses for the three and six months ended June 30, 2006 related unrealized losses of $112 on natural gas basis differential contracts.

Hedge settlement payments of $8,088 and $5,480 were included in accounts payable and accrued liabilities at December 31, 2005 and June 30, 2006, respectively.

Note 3: Asset Retirement Obligation

The Company’s asset retirement obligations relate to estimated future plugging and abandonment expenses or disposal of its oil and gas properties and related facilities. These obligations to abandon and restore properties are based upon estimated future costs which may change based upon future inflation rates and changes in statutory remediation rules. The following table provides a summary of the Company’s asset retirement obligations for the six months ended June 30, 2006:

	Six Months Ended June 30, 2006
Beginning balance	$	15,796
Liabilities incurred in current period		360
Liabilities settled in current period		(113	)
Accretion expense		687
	$	16,730
Less current portion		359
	$	16,371

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Note 4: Long-term debt

Long-term debt at December 31, 2005 and June 30, 2006 consisted of the following:

	December 31, 2005		June 30, 2006
Revolving credit line with banks (1)	$	109,000	$	159,000
Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 6.04% to 7.77%, due July 2006 through May 2017; collateralized by real property		6,942		6,968
Installment notes payable, principal and interest payable quarterly in varying amounts, non-interest bearing (discounted at 5.6% at December 31, 2005 and June 30, 2006, respectively), due July 2006 through December 2007		1,764		1,542
Non-interest bearing forgivable government loan (2)		—		250
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.62% to 8.61%, due January 2006 through May 2011; collateralized by automobiles, machinery and equipment		3,501		4,217
		121,207		171,977
Less current maturities		2,991		3,404
	$	118,216	$	168,573

(1) In 2005, the Company entered into a Sixth Restated Credit Agreement, which provides for a revolving credit line equal to the lesser of $450,000 or the borrowing base. The borrowing base has been determined based on reserve value, among other factors. Under the Sixth Restated Credit Agreement, the borrowing base was $172,500 at December 31, 2005, matured in June 2009 and interest was paid at least every three months on $94,000 and $15,000 based upon various LIBOR options as of December 31, 2005 (effective rate of 5.94% and 5.88%, respectively). Effective May 25, 2006, the borrowing base was adjusted to $200,000. Interest is paid at least every three months on $159,000 based upon LIBOR as of June 30, 2006 (effective rate of 7.19%) The credit line is collateralized by the Company’s oil and gas properties. The agreement has certain negative and affirmative covenants that require, among other things, maintaining financial covenants for current and debt service ratios and financial reporting. The Company believes it was in compliance with the financial covenants at June 30, 2006.

(2) A local economic development authority has issued a non-interest bearing note payable to Oklahoma Ethanol, L.L.C., a 67% owned unrestricted subsidiary of the Company, as incentive for the construction and operation of an ethanol plant. The note bears no interest and matures June 2012. The economic development authority will forgive payment of the note upon its maturity if certain requirements are met by June 2009 and maintained for three subsequent years, as set forth by the agreement.

Note 5: Related Party Transactions

Prior to the September 30, 2005 acquisition of the 99% limited partner’s interest, the Company managed, administered and operated the properties and business and affairs of CEI-Bristol Acquisition, L.P. (“CEI-Bristol”). The Company acted as operator of certain partnership wells and received overhead reimbursements as provided for in operating agreements. Fees received for these overhead reimbursements were $257 and $501 for the three and six months ended June 30, 2005, respectively. Additionally, the Company was compensated for management services provided to CEI Bristol through a management fee. Management fees earned by the Company were $34 and $76 for the three and six months ended June 30, 2005, respectively.

Note 6: Deferred Compensation

Effective January 1, 2004, the Company implemented a Phantom Unit Plan (the “Plan”) to provide deferred compensation to certain key employees (the “Participants”). Phantom units 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 units available for award. Generally, phantom units vest on the seventh anniversary of the award date of the phantom unit, but may also vest on a pro-rata basis following a participant’s termination of employment with the Company due to death, disability, retirement or termination by the Company without cause. Also, phantom units vest if a change of control event occurs. Upon vesting, participants are entitled to the value of their phantom units payable in cash immediately. Payment is not required by the participant upon redemption.

Prior to January 1, 2006, the Company accounted for our deferred compensation plans under the recognition and measurement provisions of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations, which requires that this award be measured at the end of each period based on the current calculated fair value of the award.

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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 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 units and is reflected in general and administrative expenses in the income statement.

Effective January 1, 2006, the Company adopted the fair value recognition provisions of SFAS No. 123(R), using the modified-prospective transition method. Under that transition method, compensation cost recognized in 2006 includes compensation costs for all phantom units granted prior to, but not yet vested as of January 1, 2006 and phantom units granted subsequent to January 1, 2006, based on the fair value estimated in accordance with SFAS No. 123(R). Since the phantom units are liability awards, fair value of the units is remeasured at the end of each reporting period until settlement. Prior to the settlement, the cost is recognized proportionately over the employees’ requisite service period, and once that period is over and the awards are fully vested, participants are paid the value of their phantom units in cash immediately. Results for prior periods have not been restated and the Company had no cumulative effect adjustment upon adoption of SFAS No. 123(R) under the modified-prospective method. The Company recognized deferred compensation expense of $50 and $160 resulting in a reduction in net income of $31 and $98 for the three and six months ended June 30, 2006, respectively.

Prior to the adoption of SFAS No. FAS123(R), the Company presented all tax benefits of deductions resulting from the phantom unit plan as operating cash flows in the Consolidated Statement of Cash Flows. SFAS No. 123(R) requires the cash flows resulting from tax benefits of tax deductions in excess of the compensation cost recognized (excess tax benefits) to be classified as financing cash flows.

A summary of the Company’s phantom unit activity as of December 31, 2005, and changes during the first six months of fiscal year 2006 is presented in the following table:

	Fair Value		Phantom Units		Weighted average remaining contract term	Aggregate intrinsic value
	(Per unit)
Unvested and total outstanding at December 31, 2005	$	17.89	164,906
Granted	$	17.89	21,357
Vested	$	17.89	(52	)
Forfeited	$	17.89	(21,575	)
Unvested and total outstanding at June 30, 2006	$	17.69	164,636		5.14	$	2,912

Upon vesting, the Company is required to redeem all units. Accordingly, the contract term and the vesting period are the same. There are no vested units as of June 30, 2006.

The fair value of each unit award is estimated on the date of grant and subsequently remeasured at the end of each reporting period using the Black-Scholes option pricing model. The assumptions used for the six months ended June 30, 2006 are as follows:

Dividend yield	0.0	%
Volatility	81.0	%
Risk-free interest rate	5.11	%
Expected life (in years)	4.50-6.50

The Company estimated volatility based on an average of the volatilities of similar public entities whose share prices are publicly available over the expected life of the granted units. The risk-free interest rate is based on the U.S. Treasury yield curve for the expected remaining term of the unit. The expected dividend yield is based on the Company’s current dividend yield and the best estimate of projected dividend yield for future periods within the expected life of the unit.

As of June 30, 2006, there was approximately $2,110 of total unrecognized compensation cost related to unvested phantom units that is expected to be recognized over a weighted-average period of 5.14 years.

Note 7: Commitments and Contingencies

Standby letters of credit (“Letters”) available under the revolving credit line are used in lieu of surety bonds with various city, state and federal agencies for liabilities relating to the operation of oil and gas properties. The Company had

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various Letters outstanding totaling $990 and $1,010 as of December 31, 2005 and June 30, 2006, respectively. Interest on each Letter accrues at the lender’s prime rate (effective rate of 8.25% at June 30, 2006) for all amounts paid by the lenders under the Letters. No interest was paid by the Company on the Letters during the three and six months ended June 30, 2005 and 2006.

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

Note 8: Comprehensive Income

Components of comprehensive income (loss), net of related tax, are as follows for the three and six months ended June 30, 2005 and 2006:

	Three months ended June 30,						Six months ended June 30,
	2005			2006			2005			2006
Net income	$	5,645		$	6,133		$	8,908		$	16,505
Unrealized gain (loss) on hedges		(27,913	)		(1,984	)		(59,370	)		8,592
Reclassification adjustment for hedge losses included in net income		5,213			5,027			7,958			10,272
Comprehensive income (loss)	$	(17,055	)	$	9,176		$	(42,504	)	$	35,369

Note 9: Subsequent Events

The Company paid a dividend on July 3, 2006 of $350.

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

You should read the following in conjunction with our financial statements contained herein and our Form S-4 registration statement, as amended, filed with the Securities and Exchange Commission which became effective on August 11, 2006.

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. Please refer to “Forward-Looking Statements” for an explanation of these types of statements. In addition, actual results may differ due to the factors set forth under Part II, Item 1A. “Risk Factors” included in this report.

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 enhanced oil recovery 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 gas reserves that are economically recoverable. The preparation of our financial statements in conformity with generally accepted accounting principles 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 gas activities.

Oil and gas prices fluctuate widely. The prices we receive for our oil and gas production affect our:

• cash flow available for capital expenditures;

• ability to borrow and raise additional capital;

• ability to service debt;

• quantity of oil and natural gas we can produce;

• quantity of oil and gas reserves; and

• operating results for oil and gas activities.

We generally hedge a substantial portion of our expected future oil and natural gas production to reduce our exposure to commodity price decreases. See “Quantitative and Qualitative Disclosures about Market Risk” below for a discussion of our derivative contracts.

Generally our producing properties have declining production rates. Our reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 15.8%, 12.4% and 10.2% during 2007, 2008 and 2009, respectively. 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.

We believe the most significant, subjective or complex estimates we make in preparation of our financial statements are:

• the amount of estimated revenues from oil and gas sales;

• the quantity of our proved oil and gas reserves;

• the timing of future drilling, development and abandonment activities;

• the value of our derivative positions;

• the realization of deferred tax assets; and

• the full cost ceiling limitation.

We base our estimates on historical experience and various assumptions that we believe are reasonable under the circumstances. Actual results may differ from these estimates.

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Net income increased 9% and 85% for the three and six months ended June 30, 2006, respectively over the comparative period in 2005. Production volumes increased 32% and 33% for the three and six months ended June 30, 2006, respectively, over the comparative period in 2005. Net cash provided by operating activities increased 59% to $60.2 million for the first six months of 2006.

We have an active hedging program in which we hedge up to five years of our existing forecasted proved developed production on a discretionary basis. We primarily use commodity swaps to mitigate commodity market fluctuations. Our gain (loss) from oil and gas hedging activities declined $3.0 million and $10.7 million for the three and six months ended June 30, 2006, respectively, over the comparative period in 2005, primarily as a result of lower NYMEX forward strip prices at June 30, 2006 and overall higher priced hedged positions. As of June 30, 2006, we have hedged approximately 2.2 MMBbls and 17,970 MMCf of our anticipated crude oil and natural gas production through the year 2008.

We have established a $210.0 million oil and gas property capital expenditure budget for 2006. Through June 2006, we spent $94.0 million on exploratory and development activities and approximately $11.8 million on acquisitions.

Results of Operations

Comparison of Three Months ended June 30, 2006 to Three Months ended June 30, 2005.

Oil and gas sales. Oil and gas sales before losses from hedging activity for the three months ended June 30, 2006 increased $18.6 million, or 44%, from the same period in 2005. The increase was due to average realized prices being 9% higher in the three months ended June 30, 2006, an increase of 32% in production volumes compared to the same period in 2005, and the favorable settlement of a disputed ownership interest in a non-operated property which resulted in the recognition of approximately $2.7 million in revenue. The average prices received for oil increased 32% to $65.47 per barrel and for gas decreased 2% to $6.02 per Mcf in the three months ended June 30, 2006 compared to the same period in 2005.

Our loss from oil and gas hedging activities in the three months ended June 30, 2006 decreased by $3.0 million from the same period in 2005. As a result of lower NYMEX forward strip prices at June 30, 2006, hedge ineffectiveness resulted in a gain of $2.7 million in the three months ended June 30, 2006 compared to a loss of $0.1 million in the same period of 2005. Hedge settlement losses decreased $0.3 million due to lower gas prices and higher average priced hedge contracts offset by increased production. The effect of our hedging program decreased average realized prices $0.68 per Mcfe in the three months ended June 30, 2006 compared to a decrease of $1.40 per Mcfe in the same period of 2005.

Production volumes increased 32% (1,980 MMcfe) in the three months ended June 30, 2006 compared to the same period in 2005 primarily due to the addition of volumes from acquisitions, our expanded drilling program, enhancements of our existing properties, and the favorable settlement of a disputed ownership interest that resulted in the one-time recognition of 393 mmcf, or 20% of the increase over the comparative period, for production from May 2005 to April 2006. Production volumes during the three months ended June 30, 2006 increased compared to the same period in 2005 by 23% (1,016 MMcfe) in the Mid-Continent, 23% (168 MMcfe) in the Permian Basin, 87% (453 MMcfe) in East Texas, 152% (237 MMcfe) in the Gulf Coast, 32% (58 MMcfe) in North Texas, and 26% (48 MMcfe) in the Rocky Mountains.

Lease operating expenses. Lease operating expenses during the three months ended June 30, 2006 increased $6.1 million, or 61%, compared to the same period in 2005 due to increases in the number of net producing wells and higher oilfield service costs. We incurred $1.8 million of costs associated with workovers in the three months ended June 30, 2006 compared to $1.4 million in the same period in 2005. On a per unit basis, lease operating expenses increased $0.35 per Mcfe primarily due to higher field level costs.

Production taxes. Production taxes, which include ad valorem taxes, are paid primarily based on oil and gas sales prices and increased during the three months ended June 30, 2006 by $1.9 million compared to the same period in 2005. This increase was caused by an 9% increase in prices and a 32% increase in oil and gas production. We also incurred $0.7 million in additional ad valorem taxes in the three months ended June 30, 2006 compared to the same period in 2005 due to an increased number of net wells and higher assessed property values. On a per Mcfe basis, production taxes increased from $0.49 to $0.60 due primarily to higher prices.

Depreciation, depletion and amortization (DD&A). DD&A increased during the three months ended June 30, 2006 by $5.1 million, or 72%, compared to the same period in 2005 primarily due to an increase in DD&A on oil and gas properties of $4.9 million. For oil and gas properties, $2.7 million of the increase was due to higher production volumes in 2006 and $2.2 million was due to an increase in the DD&A rate per equivalent unit of production. Our DD&A rate per equivalent unit of production increased by $0.36 to $1.36 per Mcfe primarily due to estimated higher future development costs for proved undeveloped reserves.

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General and administrative expenses (G&A). G&A expense increased during the three months ended June 30, 2006 by $1.4 million, or 75%, compared to the same period in 2005. The increase is due primarily to an increase in our office staff and related requirements caused by the increase in our level of activity. G&A expense is net of $2.0 million in the three months ended June 30, 2006 and $1.5 million in the same period in 2005 capitalized as part of our exploration and development activities. On a per unit basis, G&A expense increased from $0.30 per Mcfe in the three months ended June 30, 2005 to $0.40 per Mcfe in the three months ended June 30, 2006.

Interest expense. Interest expense increased during the three months ended June 30, 2006 by $6.8 million, or 251%, compared to the same period in 2005 primarily as a result of the issuance of our 8 ¹/2% Senior Notes on December 1, 2005.

Comparison of Six Months ended June 30, 2006 to Six Months ended June 30, 2005.

Oil and gas sales. Oil and gas sales before losses from hedging activity for the six months ended June 30, 2006 increased $43.8 million, or 56%, from the same period in 2005. The increase was due to average realized prices being 17% higher in the first six months of 2006, an increase of 33% in production volumes compared to the same period in 2005, and the favorable settlement of a disputed ownership interest in a non-operated property which resulted in the recognition of approximately $2.7 million in revenue. The average prices received for oil increased 29% to $62.56 per barrel and for gas increased 11% to $6.61 per Mcf in the first six months of 2006 compared to the same period in 2005.

Our loss from oil and gas hedging activities in the first six months of 2006 decreased by $10.7 million from the first six months of 2005. As a result of lower NYMEX forward strip prices at June 30, 2006 compared to December 31, 2005, hedge ineffectiveness resulted in a gain of $10.1 million in the first six months of 2006 compared to a loss of $4.5 million in the same period of 2005. Hedge settlement losses increased $3.8 million due to increased prices and production volumes. The effect of our hedging program decreased average realized prices $0.43 per Mcfe in the first six months of 2006 compared to a decrease of $1.49 per Mcfe in the first six months of 2005.

Production volumes increased 33% (3,860 MMcfe) in the first six months of 2006 compared to the same period in 2005 primarily due to the addition of volumes from acquisitions, our expanded drilling program, enhancements of our existing properties, and the favorable settlement of a disputed ownership interest that resulted in the one-time recognition of 393 mmcf, or 10% of the increase over the comparative period, for production from May 2005 to April 2006. Production volumes during the first six months of 2006 increased compared to the same period in 2005 by 20% (1,700 MMcfe) in the Mid-Continent, 31% (433 MMcfe) in the Permian Basin, 97% (990 MMcfe) in East Texas, 154% (469 MMcfe) in the Gulf Coast, 19% (73 MMcfe) in North Texas, and 73% (195 MMcfe) in the Rocky Mountains.

Lease operating expenses. Lease operating expenses during the first six months of 2006 increased $12.6 million, or 67%, compared to the same period in 2005 due to increases in the number of net producing wells and higher oilfield service costs. We incurred $3.8 million of costs associated with workovers in the first six months of 2006 compared to $2.2 million in the same period in 2005. On a per unit basis, lease operating expenses increased $0.41 per Mcfe primarily due to higher field level costs.

Production taxes. Production taxes, which include ad valorem taxes, are paid primarily based on oil and gas sales prices and increased during the first six months of 2006 by $3.9 million compared to the same period in 2005. This increase was caused by a 17% increase in prices and a 33% increase in oil and gas production. We also incurred $0.7 million in additional ad valorem taxes in the first six months of 2006 compared to the same period in 2005 due to an increased number of net wells and higher assessed property values. On a per Mcfe basis, production taxes increased from $0.48 to $0.61 due primarily to higher prices.

Depreciation, depletion and amortization (DD&A). DD&A increased during the first six months of 2006 by $9.9 million, or 74%, compared to the same period in 2005 primarily due to an increase in DD&A on oil and gas properties of $9.5 million. For oil and gas properties, $5.2 million of the increase was due to higher production volumes in 2006 and $4.3 million was due to an increase in the DD&A rate per equivalent unit of production. Our DD&A rate per equivalent unit of production increased by $0.37 to $1.35 per Mcfe primarily due to estimated higher future development costs for proved undeveloped reserves.

General and administrative expenses (G&A). G&A expense increased during the first six months of 2006 by $2.5 million, or 60%, compared to the same period in 2005. The increase is due primarily to an increase in our office staff and related requirements caused by the increase in our level of activity. G&A expense is net of $4.2 million in the first six months of 2006 and $2.8 million in the first six months of 2005 capitalized as part of our exploration and development activities. On a per unit basis, G&A expense increased from $0.36 per Mcfe in the first six months of 2005 to $0.43 per Mcfe in the first six months of 2006.

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Interest expense. Interest expense increased during the first six months of 2006 by $13.6 million, or 270%, compared to the same period in 2005 primarily as a result of the issuance of our 8 ¹/2% Senior Notes on December 1, 2005.

Liquidity and Capital Resources

Overview. Our primary needs for cash are for acquisition, exploration, development and production of oil and gas properties and the repayment of principal and interest on outstanding debt. We fund our exploration and development activities primarily through internally generated cash flows and debt financing. We adjust capital expenditures in response to changes in oil and natural gas prices, drilling results, availability of acquisition opportunities, equity funding and cash flow.

We have historically utilized net cash provided by operating activities, available cash, sale of equity and debt as capital resources to obtain necessary funding for all other cash needs. We believe that we will have sufficient funds available through our cash from operations and borrowing capacity under our revolving line of credit to meet our normal recurring operating needs, debt service obligations, capital requirements and contingencies for the next 12 months.

The net increase in cash is summarized as follows:

	Six Months Ended June 30,
(dollars in thousands)	2005			2006
Cash flows provided by operating activities	$	37,845		$	60,158
Cash flows used in investing activities		(70,700	)		(100,494	)
Cash flows provided by financing activities		29,980			49,555
Net increase (decrease) in cash during the period	$	(2,875	)	$	9,219

Sources and uses of cash. Substantially all of our cash flow from operating activities is from the production and sale of oil and gas, reduced or increased by associated hedging activities. For the six months ended June 31, 2006, net cash provided from operations increased 59% from the same period in the prior year and provided approximately 60% of our net cash outflows used in investing activities. The increase is due primarily to an increase in oil and gas sales revenue, partially offset by higher operating and interest expenses.

We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. Cash flow from operating activities and debt financing were primarily used during the first six months of 2006 to fund $109.2 million in cash expenditures for capital and exploration projects and property acquisitions.

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

(dollars in thousands)	Six Months Ended June 30, 2006		Percent of Total
Development activities:
Developmental drilling	$	65,212	61.6	%
Enhancements		16,465	15.6	%
Tertiary recovery		7,682	7.3	%
Acquisitions:
Proved properties		8,873	8.4	%
Unproved properties		2,950	2.8	%
Exploration activities		4,612	4.3	%
Total	$	105,794	100.0	%

In addition to the capital expenditures for oil and gas properties, we spent approximately $3.4 million for the acquisition and construction of new office and administrative facilities and equipment during the first six months of 2006.

During the first six months of 2006, we borrowed $50.0 million under our revolving credit facility.

As of June 30, 2006, we had cash and cash equivalents of $10.8 million and long-term debt obligations of $497.2 million.

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Our credit facility.As of June 30, 2006, we had $159.0 million outstanding under our Credit Agreement and the borrowing base was $200.0 million.

Our Credit Agreement requires us to maintain a Current Ratio, as defined in our Credit Agreement, of not less than 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 generally accepted accounting principles. 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 December 31, 2005 and June 30, 2006, our current ratio as computed using generally accepted accounting principles was 0.65 and 0.69, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 2.05 and 1.39, respectively. The following table reconciles our current assets and current liabilities using generally accepted accounting principles to the same items for purposes of calculating the current ratio for our loan compliance:

(dollars in thousands)	December 31, 2005			June 30, 2006
Current assets per GAAP	$	77,255		$	77,156
Plus—Availability under Credit Agreement		62,500			39,991
Less—Deferred tax asset on hedges and asset retirement obligation		(24,057	)		(14,099	)
Less—Short-term derivative instruments		(1,016	)		(3,301	)
Current assets as adjusted	$	114,682		$	99,747
Current liabilities per GAAP	$	119,292		$	111,740
Less—Short-term derivative instruments		(63,125	)		(39,463	)
Less—Short-term asset retirement obligation		(346	)		(359	)
Current liabilities as adjusted	$	55,821		$	71,918
Current ratio for loan compliance		2.05			1.39

We entered into a Sixth Restated Credit Agreement, which we refer to as our Credit Agreement, on June 22, 2005 which provides for a $450.0 million maximum commitment amount, is secured by our oil and gas properties and matures on June 22, 2009. Availability under our Credit Agreement is subject to a borrowing base set by the banks semi-annually on June 1 and December 1 of each year. In addition, the banks may request a borrowing base redetermination once every six months. If the outstanding borrowings under our 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 90 days additional oil and 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 gas properties within 90 days. Prior to the acquisition of CEI Bristol, the borrowing base was increased from $235.0 million to $270.0 million on September 30, 2005. At September 30, 2005 we had an outstanding balance of $243.5 million under our Credit Agreement, and the borrowing base was $270.0 million. The borrowing base under our Credit Agreement was reduced from $270.0 million to $172.5 million as a result of our additional debt issued in the offering of our 8 ¹/2% Senior Notes on December 1, 2005.

Borrowings under our Credit Agreement are made, at our option, as either Eurodollar loans or Alternate Base Rate, or ABR, loans. At June 30, 2006 all of our borrowings were Eurodollar loans.

Interest on Eurodollar loans is computed at LIBOR, 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 agreement, plus a margin where the margin varies from 1.25% to 2.50% depending on the utilization percentage of the conforming borrowing base. At June 30, 2006, the LIBOR rate was 5.33%, the Statutory Reserve Rate multiplier was 100% and the applicable margin and commitment fee together were 2.14% resulting in an effective interest rate of 7.47% for Eurodollar borrowings. 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 the ABR loans is computed as the greater of (1) the Prime Rate, as defined in our Credit Agreement, or (2) the Federal Funds Effective Rate plus 1/2 of 1%; plus a margin where the margin varies from 0.00% to 0.50% depending on the utilization percentage of the borrowing base. At June 30, 2006, the applicable rate was 8.25% and the applicable margin was 0.25% resulting in an effective interest rate of 8.50% for ABR borrowings. Interest payments on ABR borrowings are due the last day of each March, June, September and December.

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Commitment fees of 0.25% to 0.375% 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 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 that constitutes more than 5% of our borrowing base;

• 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 certain swap agreements; 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 Credit Agreement also requires us to maintain a Consolidated Total Debt to Consolidated EBITDAX Ratio, as defined in our Credit Agreement, of not greater than:

• 5.00 to 1.0 for the annualized period commencing on January 1, 2007 and ending on the last day of the fiscal quarter ending on March 31, 2007;

• 4.75 to 1.0 for the annualized period commencing on January 1, 2007 and ending on the last day of the fiscal quarter ending on June 30, 2007;

• 4.50 to 1.0 for the annualized period commencing on January 1, 2007 and ending on the last day of the fiscal quarter ending on September 30, 2007;

• 4.25 to 1.0 for the four consecutive fiscal quarters ending on December 31, 2007; and

• 4.00 to 1.0 for the four consecutive fiscal quarters ending on March 31, 2008 and for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter thereafter.

We believe we are in compliance with all covenants under the Credit Agreement as of June 30, 2006.

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;

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

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

• the entry of a final, non-appealable judgment for the payment of money in excess of $5 million;

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• a Change of Control (as defined in the 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.

Alternative capital resources. We have historically used cash flow from operations and debt financing as our primary sources of capital. In the future we may use additional sources such as asset sales, 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.

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.

Revenue recognition. We derive almost all of our revenue from the sale of crude oil and natural gas produced from our oil and 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 crude oil and natural gas derivative contracts are designed to be treated as cash flow hedges under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activity”, as amended, or SFAS 133. 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. Pursuant to SFAS 133, the effective portion of the hedge gain or loss, meaning that the change in the fair value of the contract offsets the changes in the expected future cash flows from our forecasted 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) on oil and gas hedging activities” line in our consolidated statements of income. Until hedged production is reported in earnings and the contract settles, the 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) on oil and gas hedging activities” line item each period. Our derivative contracts that do not qualify for cash flow hedge treatment are marked to their period end market values and our consolidated statements of income could include large non-cash fluctuations, particularly in volatile pricing environments.

Oil and gas properties.

• Full cost accounting. We use the full cost method of accounting for our oil and gas properties. Under this method, all costs incurred in the exploration and development of oil and 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 gas reserves quantities. Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geologic and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. 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. We continually make revisions to reserve estimates throughout the year as additional information becomes available.

• Depreciation, depletion and amortization. The quantities of proved oil and 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 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 gas properties recorded on our balance sheet cannot exceed the estimated future net revenues discounted at 10% plus the lower

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of cost or fair market value of unevaluated properties. The ceiling calculation requires that prices and costs used to determine the estimated future net revenues are those in effect as of the last day of the quarter. If oil and gas prices decline or if we have downward revisions to our estimated reserve quantities, it is possible that write downs of our oil and 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 cost 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 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 judgements 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.

In accordance with Statement of Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”, we record a liability for the discounted fair value of an asset retirement obligation in the period in which it is incurred and the corresponding cost 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. The present value calculation requires us to make numerous assumptions and judgments, including 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. 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. We provide for income taxes in accordance with Statement on Financial Accounting Standards No. 109, “Accounting for 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. Generally we 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.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Oil and 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 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 gas prices with any degree of certainty. Sustained declines in oil and gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and 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 six months ended June 30, 2006 production, our gross revenues from oil and gas sales would change approximately $1.0 million for each $0.10 change in gas prices and $0.8 million for each $1.00 change in oil prices.

To mitigate a portion of our expose to fluctuations in commodity prices, we enter into swap agreements. For swap instruments, 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.

We also use derivative financial instruments 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 gas from a specified delivery point. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.

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Our outstanding oil and natural gas derivative instruments as of June 30, 2006 are summarized below:

	Natural Gas				Crude Oil
	Volume MMcf	Weighted average fixed price to be received	Percent of PDP production hedged(1)		Volume MBbl	Weighted average fixed price to be received	Percent of PDP production(1)
2Q 2006	3,330	7.06	71.6	%	315	45.00	76.9	%
4Q 2006	2,910	8.04	65.8	%	303	47.80	77.1	%
1Q 2007	2,610	8.61	61.8	%	279	49.93	74.1	%
2Q 2007	2,610	7.04	64.5	%	276	50.08	75.6	%
3Q 2007	2,610	7.05	68.7	%	267	54.65	79.9	%
4Q 2007	1,410	8.67	38.5	%	219	59.92	67.9	%
1Q 2008	960	10.07	27.3	%	177	65.26	57.5	%
2Q 2008	870	8.10	25.6	%	177	64.87	59.0	%
3Q 2008	510	8.21	15.5	%	142	64.79	48.5	%
4Q 2008	150	8.92	4.7	%	58	66.76	20.3	%
	17,970				2,213

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

Interest rates. All of the outstanding borrowings under our Credit Agreement as of June 30, 2006 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 discount rate established by the Federal Reserve Board. 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 $200.0 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 $2.0 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 the Company’s 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 the Company in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

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 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.

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ITEM 1A. RISK FACTORS

The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, financial condition or results of operation.

Oil and natural gas prices are volatile. A decline in oil and natural gas prices could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.

Our future financial condition, revenues, results of operations, rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prices we receive for our oil and natural gas production. Oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical conditions. This price volatility also affects the amount of our cash flow we have available for capital expenditures and our ability to borrow money or raise additional capital. The prices for oil and natural gas are subject to a variety of factors that are beyond our control. These factors include:

• the level of consumer demand for oil and natural gas;

• the domestic and foreign supply of oil and natural gas;

• commodity processing, gathering and transportation availability, and the availability of refining capacity;

• the price and level of foreign imports of oil and natural gas;

• the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

• domestic and foreign governmental regulations and taxes;

• the price and availability of alternative fuel sources;

• weather conditions;

• financial and commercial market uncertainty;

• political conditions or hostilities in oil and natural gas producing regions, including the Middle East and South America; and

• worldwide economic conditions.

These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements with any certainty. Declines in oil and natural gas prices would not only reduce our revenue, but could reduce the amount of oil and natural gas that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves. If the oil and natural gas industry experiences significant price declines, we may, among other things, be unable to meet our financial obligations, including payments on our 8 ¹/2% Senior Notes, or make planned capital expenditures.

We could incur a write-down of the carrying values of our properties in the future depending on oil and natural gas prices, which could negatively impact our net income and stockholder’s equity.

We utilize the full cost method of accounting for costs related to our oil and natural gas properties. Under this method, all costs incurred for both productive and nonproductive properties are capitalized and amortized on an aggregate basis using the unit-of-production method. However, these capitalized costs are subject to a ceiling test which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10% plus the lower of cost or market value of unproved properties. The full cost ceiling is evaluated at the end of each quarter using the prices for oil and natural gas at that date as adjusted for our cash flow hedge positions. A significant decline in oil and natural gas prices from current levels, or other factors, without other mitigating circumstances, could cause a future writedown of capitalized costs and a non-cash charge against future earnings.

The actual quantities and present value of our proved reserves may be lower than we have estimated.

Estimating quantities of proved oil and natural gas reserves is a complex process. It requires interpretations of available technical data and various estimates, including estimates based upon assumptions relating to economic factors such as commodity prices, production costs, severance and excise taxes, capital expenditures, workovers, remedial costs, and the assumed effect of governmental regulation. There are numerous uncertainties about when a property may have proved reserves as compared to possible or probable reserves, including with respect to our tertiary recovery operations. Reserve estimates are, therefore, inherently imprecise and, although we believe that we are reasonably certain of recovering the

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quantities we disclose as proved reserves, actual results most likely will vary from our estimates. Any significant variations from the interpretations or assumptions used in our estimates or changes of conditions could cause the estimated quantities and net present value of our reserves to differ materially. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production by operators on adjacent properties.

You should not assume that the present values referred to in this prospectus represent the current market value of our estimated oil and natural gas reserves. The timing of production and expenses from the development and production of oil and gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. In accordance with requirements of the Commission, the estimates of present values are based on prices and costs as of the date of the estimates. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of these estimates. In addition, the effects of derivative instruments are not reflected in these assumed prices.

Approximately 31% of our total proved reserves as of December 31, 2005 are undeveloped, and those reserves may not ultimately be developed.

As of December 31, 2005, approximately 31% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling and enhanced recovery operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully. While we are reasonably certain of our ability to make these expenditures and to conduct these operations under existing economic conditions, these assumptions may not prove correct.

Our level of indebtedness may adversely affect our operations and limit our growth. We may have difficulty making debt service payments on our indebtedness as such payments become due.

As of June 30, 2006, our total debt was $497.2 million and our total book capitalization was $542.1 million. Our maximum commitment amount and the borrowing base under our Credit Agreement was $450.0 million and $200.0 million, respectively. We may incur additional debt, including significant secured indebtedness, in order to make future acquisitions, to develop our properties or for other purposes, and we expect to continue to be highly leveraged in the foreseeable future.

Our level of indebtedness affects our operations in several ways, including the following:

• a significant portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;

• we may be at a competitive disadvantage as compared to similar companies that have less debt;

• the covenants contained in the agreements governing our outstanding indebtedness and future indebtedness may limit our ability to borrow additional funds, pay dividends and make certain investments and may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

• additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes may have higher costs and more restrictive covenants;

• changes in the credit ratings of our debt may negatively affect the cost, terms, conditions and availability of future financing, and lower ratings will increase the interest rate and fees we pay on our revolving bank credit facility; and

• we may be more vulnerable to general adverse economic and industry conditions.

If an event of default occurs under our Credit Agreement or our 8 ¹/2% Senior Notes, the lenders or noteholders may declare the principal of, premium, if any, accrued and unpaid interest, and liquidated damages, if any, on such indebtedness to be due and payable.

We may not have sufficient funds to repay bank borrowings if required as a result of a borrowing base redetermination.

Availability under our Credit Agreement is subject to a borrowing base set by the banks semi-annually on June 1 and December 1 of each year. In addition, the banks may request a borrowing base redetermination once every six months. If the outstanding borrowings under our 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 90 days additional oil and gas properties we own for consideration

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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 gas properties within 90 days. If we are forced to repay a portion of our bank borrowings, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

Competition in the oil and natural gas industry is intense, and many of our competitors have greater financial and other resources than we do.

We operate in the highly competitive areas of oil and natural gas production, acquisition, development and exploration. We face intense competition from both major and other independent oil and natural gas companies:

• seeking to acquire desirable producing properties or new leases for future development or exploration; and

• seeking to acquire the equipment and expertise necessary to operate and develop our properties.

Many of our competitors have financial and other resources substantially greater than ours, and some of them are fully integrated oil companies. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to develop our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, select suitable prospects and consummate transactions in this highly competitive environment.

Significant capital expenditures are required to replace our reserves.

Our development, exploration, and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations, debt and equity sales. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of oil and natural gas, and our success in developing and producing new reserves. If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may not be able to access additional bank debt or other methods of financing on an economic basis to meet these requirements. If revenue were to decrease as a result of lower oil and natural gas prices or decreased production, and our access to capital were limited, we would have a reduced ability to replace our reserves.

If we are not able to replace reserves, we may not be able to sustain production.

Our future success depends largely upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. In addition, approximately 31% of our total estimated proved reserves (by volume) at December 31, 2005 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling and enhanced recovery operations. Our reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 15.8%, 12.4% and 10.2% during 2007, 2008 and 2009, respectively. Thus, our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves.

Development and exploration drilling may not result in commercially productive reserves.

Drilling activities are subject to many risks, including the risk that commercially productive reservoirs will not be encountered. We cannot assure you that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or may be produced economically. Seismic imaging is an imaging tool used by geologists to generate an interpretation of certain geological structures, and different geologists may have materially different interpretations of the same seismic data. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit at then realized prices after deducting drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including:

• unexpected drilling conditions;

• title problems;

• pressure or lost circulation in formations;

• equipment failures or accidents;

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• adverse weather conditions;

• compliance with environmental and other governmental requirements; and

• increases in the cost of, or shortages or delays in the availability of, drilling rigs, equipment and services.

Shortages of oil field equipment, services and qualified personnel could reduce our cash flow and adversely affect results of operations.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs and other oilfield equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. It is beyond our control and ability to predict whether these conditions will exist in the future and, if so, what their timing and duration will be. These types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results, or restrict our ability to drill the wells and conduct the operations which we currently have planned and budgeted.

We are subject to complex laws and regulations, including environmental and safety regulations, that can adversely affect the cost, manner and feasibility of doing business.

Our operations and facilities are subject to certain federal, state, and local laws and regulations relating to the exploration for, and development, production and transportation of, oil and natural gas, as well as environmental and safety matters. Although we believe that we are in substantial compliance with all applicable laws and regulations, we cannot be certain that existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not harm our business, results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with environmental and other governmental regulations such as:

• land use restrictions;

• drilling bonds and other financial responsibility requirements;

• spacing of wells;

• unitization and pooling of properties;

• habitat and endangered species protection, reclamation and remediation, and other environmental protection;

• well stimulation processes;

• produced water disposal;

• safety precautions;

• operational reporting; and

• taxation.

Under these laws and regulations, we could be liable for:

• personal injuries;

• property and natural resource damages;

• oil spills and releases or discharges of hazardous materials;

• well reclamation costs;

• remediation and clean-up costs and other governmental sanctions, such as fines and penalties; and

• other environmental damages.

Our operations could be significantly delayed or curtailed and our costs of operations could significantly increase as a result of regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations.

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Our use of hedging arrangements could result in financial losses or reduce our income.

To reduce our exposure to decreases in the price of oil and natural gas, we may use fixed-price swaps, collars and option contracts traded on the New York Mercantile Exchange, or NYMEX, over-the-counter options and price and basis swaps with other natural gas merchants and financial institutions or other similar transactions. Under our current hedging policy, we may hedge up to 80% of our anticipated monthly production for a maximum three-year period. As of June 30, 2006, we had hedged 17,970 MMcf and 2,213 MBbl of our natural gas and oil production for 2006 through 2008 at average monthly prices ranging from $6.97 to $10.15 per Mcf of natural gas and $42.43 to $67.88 per Bbl of oil. The fair value of our oil and natural gas derivative instruments outstanding as of June 30, 2006 was a liability of approximately $53.4 million. Hedging arrangements expose us to risk of financial loss in some circumstances, including when:

• our production is less than expected;

• the counter-party to the hedging contract defaults on its contract obligations; or

• there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement.

In addition, these hedging arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas.

Our working capital could be adversely affected if we enter into derivative instruments that require cash collateral.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. Although we currently do not, and do not anticipate that we will in the future, enter into derivative contracts that require an initial deposit of cash collateral, our working capital could be impacted if we enter into derivative instruments that require cash collateral and commodity prices change in a manner adverse to us. Future collateral requirements are uncertain and will depend on arrangements with our counterparties and highly volatile oil and natural gas prices.

Properties that we acquire may not produce as projected and we may be unable to accurately predict reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.

Acquisitions of producing and undeveloped properties have been an important part of our historical growth. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, including recoverable reserves, exploration or development potential, future oil and gas prices, operating costs, and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform an engineering, geological and geophysical review of the acquired properties, which we believe is generally consistent with industry practices. However, such a review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not physically inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. Our review prior to signing a definitive purchase agreement may be even more limited. Often we are not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities associated with acquired properties. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. We could incur significant unknown liabilities, including environmental liabilities, or experience losses due to title defects, in our acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, we may acquire oil and natural gas properties that contain economically recoverable reserves which are less than predicted.

The loss of our Chief Executive Officer or other key personnel could adversely affect our business.

We depend, and will continue to depend in the foreseeable future, on the services of Mark A. Fischer, our CEO, and other officers and key employees with extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and gas production, and developing and executing financing and hedging strategies. Our ability to hire and retain our officers and key employees is important to our continued success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business.

If Mark A. Fischer ceases to be either our Chairman, CEO or President in connection with a change of control, such event could also result in a change of control event occurring under our Phantom Unit Plan.

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Oil and natural gas drilling and producing operations can be hazardous and may expose us to environmental or other liabilities.

Oil and natural gas operations are subject to many risks, including well blowouts, cratering, explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, and other environmental hazards and risks. Our drilling operations involve risks from high pressures and from mechanical difficulties such as stuck pipes, collapsed casings and separated cables. If any of these events occur, we could sustain substantial losses as a result of:

• injury or loss of life;

• severe damage to or destruction of property, natural resources and equipment;

• pollution or other environmental damage;

• clean-up responsibilities;

• regulatory investigations and administrative, civil and criminal penalties; and

• injunctions or other proceedings that suspend, limit or prohibit operations.

Our liability for environmental hazards includes those created either by the previous owners of properties that we purchase or lease prior to the date we acquire them. While we maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities. Moreover, in the future, we may not be able to obtain such insurance coverage at premium levels that justify its purchase.

Costs of environmental liabilities could exceed our estimates.

Our operations are subject to numerous environmental laws and regulations, which obligate us to install and maintain pollution controls and to clean up various sites at which regulated materials may have been disposed of or released. It is not possible for us to estimate reliably the amount and timing of all future expenditures related to environmental matters because of:

• the uncertainties in estimating clean up costs;

• the discovery of additional contamination or contamination more widespread than previously thought;

• the uncertainty in quantifying liability under environmental laws that impose joint and several liability on all potentially responsible parties; and

• future changes to environmental laws and regulations.

Although we have not accrued for any material environmental violations, we could be required to make expenditures and set aside reserves in the future due to these uncertainties.

We are subject to financing and interest rate exposure risks.

Our future success depends on our ability to access capital markets and obtain financing at cost-effective rates. Our ability to access financial markets and obtain cost-effective rates in the future are dependent on a number of factors, many of which we cannot control, including changes in:

• our credit ratings;

• interest rates;

• the structured and commercial financial markets;

• market perceptions of us or the oil and natural gas exploration and production industry; and

• tax rates due to new tax laws.

All of the outstanding borrowings under the Credit Agreement as of June 30, 2006 are subject to market rates of interest as determined from time to time by the banks. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $200.0 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 $2.0 million.

The concentration of accounts for our oil and gas sales, joint interest billings or hedging with third parties could expose us to credit risk.

Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. The concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, we have not experienced any material credit losses on our receivables, but we may incur an immaterial loss in connection with the bankruptcy of Entergy New Orleans, Inc. Future concentration of sales of oil and natural gas commensurate with decreases in commodity prices could result in adverse effects.

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In addition, our oil and natural gas swaps or other hedging contracts expose us to credit risk in the event of nonperformance by counterparties. Generally, these contracts are with major investment grade financial institutions and historically we have not experienced any credit losses. We believe that the guarantee of a fixed price for the volume of oil and gas hedged reduces volatility in our reported results of operations, financial position and cash flows from period to period and lowers our overall business risk. However, as also discussed along with other risks specific to hedging activities, we may be exposed to greater credit risk in the future.

ITEM 6. EXHIBITS

Exhibit No.	Description
3.1*	Certificate of Incorporation of Chaparral Energy, Inc. (the “Company”), dated as of September 14, 2005. (Incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement on Form S-4 (SEC File No. 333-134748), filed on June 6, 2006)
3.2*	Bylaws of the Company, dated as of September 14, 2005. (Incorporated by reference to Exhibit 3.2 of the Company’s Registration Statement on Form S-4 (SEC File No. 333-134748), filed on June 6, 2006)
4.1*	Form of 8 1/2% Senior Note due 2015 (included in Exhibit 4.2). (incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-130749), filed on December 29, 2005)
4.2*	Indenture, dated as of December 1, 2005, among the Company, as Issuer, the subsidiaries of the Company party thereto as Guarantors and Wells Fargo Bank, National Association, as Trustee. (incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-130749), filed on December 29, 2005)

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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

* Incorporated by reference

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SIGNATURES

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

CHAPARRAL ENERGY, INC.
By:	/s/ Mark A. Fischer
Name:	Mark A. Fischer
Title:	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:	July 26, 2007

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EXHIBIT INDEX

Exhibit No.	Description
3.1*	Certificate of Incorporation of Chaparral Energy, Inc. (the “Company”), dated as of September 14, 2005. (Incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement on Form S-4 (SEC File No. 333-134748), filed on June 6, 2006)
3.2*	Bylaws of the Company, dated as of September 14, 2005. (Incorporated by reference to Exhibit 3.2 of the Company’s Registration Statement on Form S-4 (SEC File No. 333-134748), filed on June 6, 2006)
4.1*	Form of 8 1/2% Senior Note due 2015 (included in Exhibit 4.2). (incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-130749), filed on December 29, 2005)
4.2*	Indenture, dated as of December 1, 2005, among the Company, as Issuer, the subsidiaries of the Company party thereto as Guarantors and Wells Fargo Bank, National Association, as Trustee. (incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-130749), filed on December 29, 2005)

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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

* Incorporated by reference

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