Form 10-Q

10-Q 1 d10q.htm FORM 10-Q Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2006

¨	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 þ No ¨

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 þ

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

877,000 shares of the registrant’s Common Stock were outstanding as of November 10, 2006.

CHAPARRAL ENERGY, INC.

Index to Form 10-Q


		Page
Part I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2006 and December 31, 2005		5
Consolidated Statements of Income for the three months and nine months ended September 30, 2006 and 2005		6
Consolidated Statements of Cash Flows for the nine months ended September 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		19
Overview		19
Results of Operations		21
Liquidity and Capital Resources		26
Critical Accounting Policies and Estimates		30
Recent Accounting Pronouncements		33
Item 3. Quantitative and Qualitative Disclosures About Market Risk		33
Item 4. Controls and Procedures		35
Part II. OTHER INFORMATION		36
Item 1A. Risk Factors		36
Item 4. Submission of Matters to a Vote of Security Holders		44
Item 6. Exhibits		45
Signatures		47
EX-31.1 (Certification by CEO required by rule 13a-14(a)/15d-14(a))
EX-31.2 (Certification by CFO required by rule 13a-14(a)/15d-14(a))
EX-32.1 (Certification by CEO pursuant to section 906)
EX-32.2 (Certification by CFO pursuant to section 906)

CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

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.

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.

•

Bbl/d. One Bbl per day.

•

Bcfe. One billion cubic feet of natural gas equivalents.

•

MBbl. One thousand Bbls.

•

Mcf. One thousand cubic feet of natural gas.

•

Mcf/d. One Mcf per day.

•

Mcfe. One thousand cubic feet of natural gas equivalents.

•

MMcf. One million cubic feet of natural gas.

•

MMcfe/d. One million cubic feet of natural gas equivalents per day.

•

MMBbl. One million Bbls.

•

NYMEX. The New York Mercantile Exchange.

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			September 30, 2006 (unaudited)
Assets
Current assets:
Cash and cash equivalents	$	1,598		$	102,725
Accounts receivable, net		42,431			44,875
Inventories		6,788			8,067
Deferred income taxes		23,831			8,291
Prepaid expenses		1,591			1,259
Derivative instruments		1,016			7,331

Total current assets		77,255			172,548
Property and equipment—at cost, net		22,428			25,343
Oil & gas properties
Proven		600,185			744,068
Unproven		10,150			17,975
Accumulated depletion and depreciation		(74,799	)		(106,473	)

Total oil & gas properties		535,536			655,570

Other assets		12,160			19,748

	$	647,379		$	873,209

Liabilities and stockholders’ equity
Current liabilities
Accounts payable and accrued liabilities	$	44,183		$	54,438
Revenue distribution payable		8,858			15,021
Current maturities of long-term debt and Capital leases		3,126			3,837
Short-term derivative instruments		63,125			18,596

Total current liabilities		119,292			91,892
Long-term debt and Capital leases, less current maturities		118,418			211,587
8¹/2% Senior Notes due 2015		325,000			325,000
Derivative instruments		32,001			3,133
Deferred compensation		645			773
Asset retirement obligations		15,450			17,578
Deferred income taxes		26,406			50,337
Commitments and contingencies (note 7)
Stockholders’ equity
Preferred stock, 600,000 shares authorized, none issued and outstanding		—			—
Common stock, $.01 par value, 3,000,000 shares authorized; 775,000 and 877,000 shares issued and outstanding as of December 31, 2005 and September 30, 2006, respectively		8			9
Additional paid in Capital		—			100,918
Retained earnings		58,126			80,394
Accumulated other comprehensive loss, net of taxes		(47,967	)		(8,412	)

		10,167			172,909

	$	647,379		$	873,209

The accompanying notes are an integral part of these statements.

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of income


	Three months ended September 30,						Nine months ended September 30,
(dollars in thousands, except share and per share data)	2005 (unaudited)			2006 (unaudited)			2005 (unaudited)			2006 (unaudited)
Revenues:
Oil and gas sales	$	52,244		$	59,628		$	130,727		$	181,892
Gain (loss) from oil and gas hedging activities		(22,330	)		1,267			(39,743	)		(5,412	)

Total revenues		29,914			60,895			90,984			176,480
Costs and expenses:
Lease operating		9,893			15,719			28,556			46,951
Production tax		3,636			4,324			9,284			13,869
Depreciation, depletion and amortization		7,277			11,967			20,579			35,163
General and administrative		2,471			3,005			6,631			9,660

Total costs and expenses		23,277			35,015			65,050			105,643
Operating income		6,637			25,880			25,934			70,837
Non-operating income (expense):
Interest expense		(3,235	)		(10,335	)		(8,283	)		(28,993	)
Non-hedge derivative losses		—			(4,522	)		—			(4,634	)
Other income		206			30			524			556

Net non-operating expense		(3,029	)		(14,827	)		(7,759	)		(33,071	)
Income from before income taxes and minority interest		3,608			11,053			18,175			37,766
Income tax expense		1,013			4,241			6,672			14,520
Minority interest		—			—			—			(71	)

Net income	$	2,595		$	6,812		$	11,503		$	23,317

Earnings per share
Net income per share (basic and diluted)	$	3.35		$	8.76		$	14.84		$	30.06
Weighted average number of shares used in calculation of basic and diluted earnings per share		775,000			777,217			775,000			775,747

The accompanying notes are an integral part of these statements.

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows


	Nine months ended September 30,
(dollars in thousands)	2005 (unaudited)			2006 (unaudited)
Cash flows from operating activities
Net income	$	11,503		$	23,317
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion & amortization		20,579			35,163
Deferred income taxes		6,985			14,520
Unrealized (gain) loss on ineffective portion of hedges		11,680			(17,566	)
Non-cash change in fair value of derivative instruments		—			4,634
Gain on sale of assets		(226	)		(103	)
Other		411			827
Change in assets & liabilities
Accounts receivable		(10,250	)		(2,701	)
Inventories		(156	)		(1,279	)
Prepaid expenses and other assets		(121	)		25
Accounts payable and accrued liabilities		8,948			9,160
Revenue distribution payable		1,487			6,163

Net cash provided by operating activities		50,840			72,160
Cash flows from investing activities
Purchase of property and equipment and oil and gas properties		(109,398	)		(160,782	)
Acquisition of a business, net of cash acquired		(113,622	)		—
Proceeds from dispositions of property and equipment and oil and gas properties		981			5,557
Purchase of prepaid production tax asset		—			(5,000	)
Other		30			(4,986	)

Net cash used in investing activities		(222,009	)		(165,211	)
Cash flows from financing activities
Proceeds from long-term debt		81,736			95,805
Repayment of long-term debt		(1,797	)		(1,929	)
Proceeds from equity issuance		—			102,000
Proceeds from acquisition financing		132,000			—
Principal payments under Capital lease obligations		(402	)		(106	)
Distributions to members		(3,059	)		(1,050	)
Fees paid related to financing activities		(94	)		(542	)

Net cash provided by financing activities		208,384			194,178

Net increase in cash and cash equivalents		37,215			101,127
Cash and cash equivalents at beginning of period		13,842			1,598

Cash and cash equivalents at end of period	$	51,057		$	102,725

The accompanying notes are an integral part of these statements.

Chaparral Energy, Inc. and subsidiaries

Consolidated Statements of Cash Flows—(Continued)


	Nine months ended September 30
(dollars in thousands)	2005			2006
	(unaudited)
Supplemental cash flow information
Cash paid (received) during the year for:
Interest, net of Capitalized interest	$	7,958		$	22,068
Income taxes		(314	)		2

Supplemental disclosure of non-cash investing and financing activities

During the nine months ended September 30, 2005 and 2006, the Company recorded an asset and related liability of $2,576 and $1,340, respectively associated with the asset retirement obligation on the acquisition and/or development of oil and gas properties.

Interest of $669 was Capitalized during the nine months ended September 30, 2006 related to non-producing leasehold costs.

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 September 30, 2006 and for the three months and nine months ended September 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 nine months ended September 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 it’s wholly and majority owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.

The loss from operations related to the minority interest of Oklahoma Ethanol, L.L.C. is shown separately in the statements of income. 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 sheets and all losses are therefore recognized by the Company. If future earnings materialize, the Company will recognize all earnings up to the amount of those losses previously absorbed.

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.

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.

Chaparral Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

(dollars in thousands, unless otherwise noted)

Inventories

Inventories consist of equipment used in developing oil and gas properties of $5,029 and $6,185 at December 31, 2005 and September 30, 2006, respectively, and product of $1,759 and $1,882 at December 31, 2005 and September 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.

Recently Issued Accounting Standards

In June 2006, the Financial Accounting Standards Board (“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 Statement of Financial Accounting Standards (“SFAS”) 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 are currently reviewing this new standard to determine its effects, if any, on our financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 clarifies the principle that fair value should be based on the assumptions market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under SFAS No. 157, fair value measurements would be separately disclosed by level within the fair value hierarchy. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We are currently reviewing this new standard to determine its effects, if any, on our financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” an amendment to SFAS No. 87, “Employers’ Accounting for Pensions,” SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” and SFAS No. 132(R), “Employers’ Disclosures about Pensions and Other Postretirement Benefits—an amendment of FASB Statements No. 87, 88, and 106.” SFAS No. 158 requires an employer to recognize a benefit plan’s funded status in its statement of financial position, measure a benefit plan’s assets and obligations as of the end of the employer’s fiscal year and recognize the changes in the benefit plan’s funded status in other comprehensive income in the year in which the changes occur. SFAS No. 158’s requirement to recognize the funded status of a benefit plan and the new disclosure requirements are effective as of the end of the fiscal year ending after December 15, 2006. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. We do not believe that this new standard will have a material effect on our financial position, results of operations or cash flows.

The Securities and Exchange Commission (SEC) issued Staff Accounting Bulleting No. 108 (“SAB 108”), “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” in September 2006. SAB 108 provides guidance regarding the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of materiality assessments. The method established by SAB 108 requires each of the Company’s financial statements and the related financial statement disclosures to be considered when quantifying and assessing the materiality of the misstatement. The

Chaparral Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

(dollars in thousands, unless otherwise noted)

provisions of SAB 108 will apply to the Company’s financial position and results of operations for the fiscal year ended December 31, 2006. The Company is currently assessing the impact of this statement but does not expect to record an adjustment.

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”, as amended. Therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative losses.

In connection with entering into a Securities Purchase Agreement with Calumet Oil Company on September 16, 2006, the Company entered into additional commodity swaps and swaption contracts to provide protection against a decline in the price of oil. The swaptions gave the Company the option, but not the obligation, to enter into fixed price oil swaps under which we would receive a fixed commodity price and pay a floating market price, resulting in a net amount due to or from the counterparty. The cost of the swaption contracts was $2,790. We do not believe that these instruments qualify as hedges pursuant to SFAS No. 133. Therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative 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, and/or the value confirmed by the counterparty.

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			September 30, 2006
Derivative assets (liabilities):
Gas swaps	$	(60,158	)	$	9,509
Oil swaps		(33,952	)		(21,968	)
Natural gas basis differential swaps		—			(1,816	)
Swaption		—			549

	$	(94,110	)	$	(13,726	)

Chaparral Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

(dollars in thousands, unless otherwise noted)

Changes in the fair value of effective cash flow hedges are recorded as a component of accumulated other comprehensive income, which is later transferred to earnings when the hedged transaction occurs. The ineffective portion is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. 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 income and is comprised of the following:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2006			2005			2006
Reclassification of settled contracts	$	(15,097	)	$	(6,244	)	$	(28,063	)	$	(22,978	)
Gain (loss) on ineffective portion of derivatives qualifying for hedge accounting		(7,233	)		7,511			(11,680	)		17,566

	$	(22,330	)	$	1,267		$	(39,743	)	$	(5,412	)

Based upon market prices at September 30, 2006 the Company expects to charge $7,027 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 September 30, 2006 are expected to be settled by December 2011.

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 in the consolidated statements of income is comprised of the following:


	Three Months Ended September 30, 2006		Nine Months Ended September 30, 2006
Unrealized loss on natural gas basis differential hedges	$	1,857	$	1,969
Unrealized loss on non-qualified derivative contracts		2,665		2,665

	$	4,522	$	4,634

Hedge settlement payments of $8,088 and $5,023 were included in accounts payable and accrued liabilities at December 31, 2005 and September 30, 2006, respectively. Hedge settlement receivables of $636 were included in accounts receivable at September 30, 2006. There were no hedge settlements included in accounts receivable at December 31, 2005.

Chaparral Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

(dollars in thousands, unless otherwise noted)

Note 3: Asset Retirement Obligation

The Company’s asset retirement obligations relate to estimated future plugging and abandonment expenses on its oil and gas properties and related facilities disposal. 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 nine months ended September 30, 2006:


	Nine Months Ended September 30, 2006
Beginning balance	$	15,796
Liabilities incurred in current period		584
Liabilities settled in current period		(243	)
Accretion expense		1,045
Revisions of estimated cash flows		756

Ending ARO balance	$	17,938
Less current portion		360

	$	17,578

Chaparral Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

(dollars in thousands, unless otherwise noted)

Note 4: Long-term debt

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


	December 31, 2005		September 30, 2006
Revolving credit line with banks (1)	$	109,000	$	201,000
Real estate mortgage note, payable in monthly installments of $63, bearing interest at LIBOR plus 2.66% adjusted annually (effective rate of 5.79% and 7.77% at December 31, 2005 and September 30, 2006, respectively), due August 31, 2010; collateralized by real property		6,212		6,401
Real estate mortgage notes, payable in monthly installments, bearing interest at defined bank base rate plus 1% (effective rate of 7% at December 31, 2005 and September 30, 2006), adjusted and fixed every five years with a floor rate of 7%, due January and May 2017; collateralized by real property		330		315
Real estate mortgage notes, payable in monthly installments, bearing interest at 6.95% until August 2009; interest rate adjusted to the 3 year Treasury Index on August 2009 and every 36 months thereafter; due August 2021; collateralized by real property		—		216
Real estate mortgage note, payable in monthly installments of $2, bearing interest at 6.53%; balloon payment of unpaid balance due November, 2015; collateralized by real property		—		202
Real estate mortgage note, interest only monthly payments beginning August 5, 2005 at 6.04% with lump sum principal payment due at maturity, July 5, 2006; collateralized by real property		400		—
Installment note payable to bank, payable in monthly installments of $3, bearing interest at 8%, due July 15, 2006; collateralized by real property		22		—
Installment note payable, principal and interest payable quarterly in varying amounts, noninterest-bearing (discounted at 5.6% at December 31, 2005 and September 30, 2006, respectively), due December 2007		847		540
Installment note payable, principal and interest payable in annual installments of $550, noninterest-bearing (discounted at 5.6% at December 31, 2005 and September 30, 2006, respectively), due September 2007		895		895
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 8.612%, due January 2005 through August 2011; collateralized by automobiles, machinery and equipment		3,501		5,264

		121,207		215,083
Less current maturities		2,991		3,691

	$	118,216	$	211,392

(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. Under the restated credit agreement, the borrowing base was $172,500 at December 31, 2005 and was scheduled to mature in June 2009. During September 2006, the borrowing base was adjusted to $250,000. Under the restated credit agreement, interest is 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) and $186,000 and $15,000 based upon

Chaparral Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

(dollars in thousands, unless otherwise noted)

various LIBOR options as of September 30, 2006 (effective rates of 7.13%). The credit line is collateralized by the Company’s oil and gas properties. Under the terms of the agreement, dividends may not exceed $350 per quarter. 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 September 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 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 nine months ended September 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 $42 and $76 for the three and nine months ended September 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. 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, as defined. 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.

Effective January 1, 2006, we adopted the fair value recognition provisions of SFAS No. 123(R) “Share Based Payments”, 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 settlement, the cost is recognized

Chaparral Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

(dollars in thousands, unless otherwise noted)

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 transition method.

Prior to the adoption of SFAS No. 123(R), we 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 benefit) to be classified as financing cash flows.

The Company recognized deferred compensation expense of $75 and $225 resulting in a reduction in net income for the three and nine months ended September 30, 2005, respectively. The Company recognized a gain of $30 resulting in an increase in net income for the three months ending September 30, 2006 and an expense of $130 resulting in a reduction of net income for the nine months ended September 30, 2006.

A summary of the Company’s phantom unit activity as of December 31, 2005, and changes during the first nine 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	$	17.86	(25,823	)

Unvested and total outstanding at September 30, 2006	$	15.95	160,388		4.89	$	2,558

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 September 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 nine months ended September 30, 2006 are as follows:


Dividend yield		0.0%
Volatility		81.0%
Risk-free interest rate		4.60%
Expected life (in years)		4.25-6.25

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.

Chaparral Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

(dollars in thousands, unless otherwise noted)

As of September 30, 2006, there was approximately $1,785 of total unrecognized compensation cost related to unvested phantom units that is expected to be recognized over a weighted-average period of 4.89 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 various Letters outstanding totaling $990 and $1,010 as of December 31, 2005 and September 30, 2006, respectively. Interest on each Letter accrues at the lender’s prime rate (effective rate of 8.25% at September 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 nine months ended September 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: Capital Stock

On September 27, 2006, the Company effected a 775-for-1 stock split in the form of a stock dividend to shareholders of record as of September 26, 2006. As a result of the split, 774,000 additional shares were issued and retained earnings were reduced by $7. All share and per share amounts discussed and disclosed in this Quarterly Report on Form 10-Q reflect the effect of this stock split.

On September 29, 2006, the Company closed the sale of an aggregate of 102,000 shares of Chaparral’s common stock to Chesapeake Energy Corporation for an aggregate cash purchase price of $102,000. Proceeds from the sale after commissions and expenses were approximately $100,900 and are being used for general corporate and working Capital purposes and acquisition of oil and gas properties.

Note 9: Comprehensive Income

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


	Three months ended September 30,					Nine months ended September 30,
	2005			2006		2005			2006
Net income	$	2,595		$	6,812	$	11,503		$	23,317
Unrealized gain (loss) on hedges		(20,778	)		16,859		(80,148	)		25,451
Reclassification adjustment for hedge losses included in net income		9,267			3,832		17,225			14,104

Comprehensive income (loss)	$	(8,916	)	$	27,503	$	(51,420	)	$	62,872

Note 10: Subsequent Events

On October 31, 2006, the Company acquired all outstanding Capital stock of Calumet Oil Company and all of the limited partnership interests and membership interests of certain of its affiliates (“Calumet”) for an aggregate purchase price of approximately $500,000 in cash. The purchase price was paid in cash and financed through an increase in the Company’s existing senior revolving credit facility up to $750,000.

Chaparral Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements—(Continued)

(dollars in thousands, unless otherwise noted)

On October 31, 2006, we entered into a Seventh Restated Credit Agreement (“Credit Agreement”) in conjunction with the Calumet acquisition. The Credit Agreement provides for a $750,000 maximum commitment amount, is secured by our oil and gas properties and matures on October 31, 2010. Availability under the Credit Agreement is subject to a borrowing base which is initially set at $750,000 and a conforming borrowing base which is initially set at $650,000. As of October 31, 2006, upon the completion of the Calumet acquisition and the entry into the Credit Agreement, we had $629,000 outstanding under our Credit Agreement.

During September 2006, the Company purchased an interest in a venture Capital limited liability company for $5,000 and has subsequently purchased additional interests resulting in investments totaling $15,000 in two venture Capital limited liability companies. The Company’s expected return on the investment will be receipt of $2 of Oklahoma tax credits for every $1 invested to be recouped from our Oklahoma production taxes. The investments will be accounted for as a production tax benefit asset and will be amortized to other income using the effective yield method over the expected recovery period.

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, East Texas, 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;

•

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.

Net income increased 163% and 103% for the three and nine months ended September 30, 2006, respectively over the comparative period in 2005. Production volumes increased 23% and 29% for the three and nine months ended September 30, 2006, respectively, over the comparative period in 2005. Net cash provided by operating activities increased 42% to $72.1 million for the first nine 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 $23.6 million and $34.3 million for the three and nine months ended September 30, 2006, respectively, over the comparative period in 2005, primarily as a result of lower NYMEX forward strip prices at September 30, 2006 and overall higher priced hedged positions. As of September 30, 2006, we have hedged approximately 5.9 MMBbls and 14,640 MMCf of our anticipated crude oil and natural gas production through the year 2011.

We have established a $210.0 million oil and gas property Capital expenditure budget for 2006. Through September 2006, we spent $137.9 million on exploratory and development activities and approximately $19.0 million on acquisitions.

The following are recent material developments that have impacted the results of operations or liquidity discussed below, or are expected to impact these items in future periods:

•

Stock Split. On September 27, 2006, we effected a 775-for-1 stock split in the form of a stock dividend to shareholders of record as of September 26, 2006. All share and per share amounts discussed and disclosed within this report have been restated to reflect this stock split.

•

Private equity sale. On September 29, 2006, we closed the sale of an aggregate of 102,000 shares of Chaparral’s common stock to Chesapeake Energy Corporation for an aggregate purchase price of $102.0 million. Proceeds from the sale after commissions and expenses were approximately $100.9 million and are being used for general corporate and working Capital purposes and acquisitions of oil and gas properties.

•

Acquisition of Calumet Oil Company and affiliates. On September 16, 2006, we entered into a Securities Purchase Agreement with Calumet Oil Company to acquire all of its outstanding Capital stock and all of the limited partnership interests and membership interests of certain of its affiliates (“Calumet”). The acquisition was closed on October 31, 2006 for an aggregate purchase price of approximately $500.0 million.

Calumet owns properties principally located in Oklahoma and Texas, areas which are complementary to our existing core areas of operations. We estimate that proved reserves attributable to the acquisition are in excess of 410 Bcfe, which are producing approximately 28 Mmcfe/d, net. Calumet’s proved reserves are long-lived, have low production decline rates and are approximately 93% oil. In addition to increasing our current average net daily production, many of the properties have significant drilling and enhanced oil recovery opportunities.

In conjunction with the purchase of Calumet, we entered into a Seventh Restated Credit Agreement (“Credit Agreement”) which provides for a $750.0 million borrowing base. At September 30, 2006 we had an outstanding balance of $201.0 million under our prior Sixth Restated Credit Agreement, and the borrowing base was $250.0 million. As of October 31, 2006, upon the completion of the Calumet

acquisition and the entry into the Credit Agreement, we had $629.0 million outstanding under our Credit Agreement.

In September 2006, in conjunction with the Calumet acquisition, we entered into additional swaps for the anticipated production for the five years subsequent to closing to provide protection against a decline in the price of oil. The swaps cover 315 MBbls through December 2011 at an average price of $63.63. We also purchased swaption contracts for approximately $2.8 million that gave us the option, but not the obligation, to enter into fixed price oil swaps.

Additionally, as part of the transaction, we acquired Calumet’s hedging arrangements, which currently include hedge swaps of 75 MBbls of oil per month at $66.10 per barrel during 2006, 75 MBbls per month at $63.00 per barrel during 2007 and 30 MBbls per month at $68.10 during 2008. We will continue these swaps and will designate them as hedges in accordance with our hedging policy.

•

Production Tax Credit. During September 2006, we purchased an interest in a venture Capital limited liability company for $5.0 million and have subsequently purchased additional interests resulting in investments totaling $15.0 million in two venture Capital limited liability companies. Our expected return on the investment will be receipt of $2 of Oklahoma tax credits for every $1 invested to be recouped from our Oklahoma production taxes.

•

Oklahoma Ethanol. In August 2005, we entered a joint venture, Oklahoma Ethanol, L.L.C. to construct and operate an ethanol production plant in Oklahoma. We spent approximately $0.2 million toward the design for the construction of the plant in the three months ended September 30, 2006.

Results of Operations

Comparison of three months ended September 30, 2006 to three months ended September 30, 2005.

Revenues and Production. All of our revenues are derived from the sale of our oil and gas production, which is net of the effects of the settlement of qualifying hedging contracts associated with our production. Our revenues may vary significantly from period to period as a result of changes in commodity prices or production volumes. The following table presents information about our oil and gas sales before the effects of hedging:


	Three Months Ended September 30,				Percentage Increase (Decrease)
	2005		2006		Percentage Increase (Decrease)
Oil and gas sales (dollars in thousands)
Oil	$	21,828	$	27,533	26.1	%
Gas		30,416		32,095	5.5	%

Total	$	52,244	$	59,628	14.1	%
Production
Oil (MBbls)		364		416	14.3	%
Gas (MMcf)		4,021		5,109	27.1	%
MMcfe		6,205		7,605	22.6	%
Average sales prices (excluding hedging)
Oil per Bbl	$	59.97	$	66.19	10.4	%
Gas per Mcf		7.56		6.28	(16.9	%)
Mcfe		8.42		7.84	(6.9	%)

Oil sales increased 26.1% from $21.8 million during the three months ended September 30, 2006 to $27.5 million during the same period in 2006. This increase was due to a 14.3% increase in production volumes to 416

MBbls and a 10.4% increase in average oil prices to $66.19 per barrel. Natural gas sales revenues increased 5.5% from $30.4 million during the three months ended September 30, 2005 to $32.1 million during the same period in 2006. This increase was due to a 27.1% increase in production volumes to 5,109 MMcf, which was partially offset by 16.9% lower average gas prices of $6.28 per Mcf. Oil and gas production for the three months ended September 30, 2006 increased due primarily to the addition of volumes from acquisitions, our expanded drilling program and enhancements of our existing properties.

Production volumes by area were as follows (MMcfe):


	Three Months Ended September 30,		Percentage Increase (Decrease)
	Three Months Ended September 30,
	2005	2006
Mid Continent	4,254	4,987	17.2	%
Permian	678	903	33.2	%
East Texas	748	886	18.4	%
North Texas	171	254	48.5	%
Rockies	214	242	13.1	%
Gulf Coast	140	333	137.9	%

Totals	6,205	7,605	22.6	%

Commodity prices are determined by factors that are outside of our control. Historically, commodity prices have been volatile and we expect them to remain volatile. Commodity prices are affected by changes in market demands, overall economic activity, weather, pipeline capacity constraints, storage levels, basis differentials and other factors.

We generally hedge a substantial portion of our expected future oil and natural gas production to reduce our exposure to commodity price decreases. The effects of hedging on our net revenues are as follows:


	Three Months Ended September 30,						Percentage Change
	Three Months Ended September 30,
	2005			2006
	(dollars in thousands)
Gain (loss) from oil and gas hedging activities:
Hedge settlements	$	(15,097	)	$	(6,244	)	141.8	%
Hedge ineffectiveness		(7,233	)		7,511		203.8	%

Total	$	(22,330	)	$	1,267		105.7	%

Our gain (loss) from oil and gas hedging activities in the third quarter of 2006 was primarily due to gains on hedge ineffectiveness. As a result of lower NYMEX forward strip gas prices at September 30, 2006 compared to June 30, 2006, hedge ineffectiveness resulted in a gain of $7.5 million compared to a loss of $7.2 million in the third quarter of 2005.

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


	Average Price				Hedged to Non-Hedged Price
	Without Hedge		With Hedge		Hedged to Non-Hedged Price
Oil (per Bbl):
Three months ended September 30, 2005	$	59.97	$	39.62	66.1	%
Three months ended September 30, 2006		66.19		50.41	76.2	%
Gas (per Mcf):
Three months ended September 30, 2005	$	7.56	$	3.85	50.9	%
Three months ended September 30, 2006		6.28		7.81	124.4	%

Derivative contracts that do not qualify for hedge accounting are included in other income and have no effect on our reported revenues or average realized prices.

Costs and Expenses. Generally, our proved reserves and production have grown steadily since our founding. As a result of this, increasing well count and higher oil field service costs, our operating expenses have also increased. The following table presents information about our operating expenses for the third quarter of 2005 and 2006:


	Amount						Per Mcfe
	Three months ended September 30,				Percent Increase		Three months ended September 30,				Percent Increase
	2005		2006		Percent Increase		2005		2006		Percent Increase
	(dollars in thousands)
Lease operating expenses	$	9,893	$	15,719	58.9	%	$	1.59	$	2.07	30.2	%
Production taxes		3,636		4,324	18.9	%		0.59		0.57	-3.4	%
Depreciation, depletion and amortization		7,277		11,967	64.4	%		1.17		1.57	34.2	%
General and administrative		2,471		3,005	21.6	%		0.40		0.40	0.0	%

Lease operating expenses – Increase was primarily due to increases in the net number of producing wells and higher oilfield service costs which was somewhat mitigated by a higher producing rate per well. Included in these figures are $2.2 million of costs associated with workovers in the third quarter of 2006 compared to $1.0 million in the same period of 2005.

Production taxes (which include ad valorem taxes) – Increase is primarily due to an increase of 22.6% in production volumes partially offset by 6.9% lower averaged realized prices compared to the same period in 2005. We also incurred $0.2 million in additional ad valorem taxes in the three months ended September 30, 2006 compared to the same period in 2005 due to an increased number of net wells and higher assessed property values.

Depreciation, depletion and amortization (“DD&A”) – Increase is primarily due to increase in DD&A on oil and gas properties. DD&A on oil and gas properties increased $2.0 million due to higher production volumes and $2.4 million due to an increase in the DD&A rate per equivalent unit of production. Our DD&A rate on oil and gas properties per equivalent unit of production increased $0.40 to $1.41 per Mcfe primarily due to estimated higher future development costs for proved undeveloped reserves.

General and administrative expenses – Increase in general and administrative expenses was primarily due to the growth in our workforce resulting from an increase in our level of activity. G&A expense is net of $2.1 million in the third quarter of 2006 and $1.6 million in the third quarter of 2005 Capitalized as it directly related to our exploration and development activities.

Interest Expense. Interest expense increased during the third quarter of 2006 by $7.1 million, or 220%, 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.

Non-hedge derivative losses. Non-hedge derivative losses were $4.5 million during the three months ended September 30, 2006 and are comprised of losses of $1.8 million on natural gas basis differential swaps and $2.7 million in non-qualified derivative contracts. There were no non-hedge derivative losses in the third quarter of 2005.

Comparison of nine months ended September 30, 2006 to nine months ended September 30, 2005.

Revenues and Production. All of our revenues are derived from the sale of our oil and gas production, which is net of the effects of the settlement of qualifying hedge contracts associated with our production. Our revenues may vary significantly from period to period as a result of changes in commodity prices or production volumes. The following table presents information about our oil and gas sales before the effects of hedging:


	Nine Months Ended September 30,				Percentage Increase (Decrease)
	2005		2006		Percentage Increase (Decrease)
Oil and gas sales (dollars in thousands)
Oil	$	54,824	$	80,462	46.8	%
Gas		75,903		101,430	33.6	%

Total	$	130,727	$	181,892	39.1	%
Production
Oil (MBbls)		1,042		1,262	21.1	%
Gas (MMcf)		11,652		15,592	33.8	%
MMcfe		17,904		23,164	29.4	%
Average sales prices (excluding hedging)
Oil per Bbl	$	52.61	$	63.76	21.2	%
Gas per Mcf		6.51		6.51	0.0	%
Mcfe		7.30		7.85	7.5	%

Oil sales increased 46.8% from $54.8 million during the nine months ended September 30, 2005 to $80.5 million during the same period in 2006. This increase was due to a 21.1% increase in production volumes to 1,262 MBbls and a 21.2% increase in average oil prices to $63.76 per barrel. Natural gas sales revenues increased 33.6% from $75.9 million during the nine months ended September 30, 2005 to $101.4 million during the same period in 2006. This increase was due to a 33.8% increase in production volumes to 15,592 MMcf. Average gas sales prices were $6.51 per Mcf during each of the nine months ended September 30, 2006 and 2005. Oil and gas production for the nine months ended September 30, 2006 increased due primarily to the addition of volumes from acquisitions, our expanded drilling program and enhancements of our existing properties.

Production volumes by area were as follows (MMcfe):


	Nine Months Ended September 30,		Percentage Increase (Decrease)
	2005	2006	Percentage Increase (Decrease)
Mid Continent	12,568	15,137	20.4	%
Permian	2,095	2,696	28.7	%
East Texas	1,767	2,801	58.5	%
North Texas	545	717	31.6	%
Rockies	483	704	45.8	%
Gulf Coast	446	1,109	148.7	%

Totals	17,904	23,164	29.4	%


	Nine Months Ended September 30,						Percentage Change
	2005			2006			Percentage Change
	(dollars in thousands)
Gain (loss) from oil and gas hedging activities:
Hedge settlements	$	(28,063	)	$	(22,978	)	18.1	%
Hedge ineffectiveness		(11,680	)		17,566		250.4	%

Total	$	(39,743	)	$	(5,412	)	86.4	%

Our loss from oil and gas hedging activities in the first nine months of 2006 decreased primarily due to gains on hedge ineffectiveness. As a result of lower NYMEX forward strip gas prices at September 30, 2006 compared to December 31, 2005, hedge ineffectiveness resulted in a gain of $17.6 million compared to a loss of $11.7 million in the third quarter of 2005.

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


	Average Price				Hedged to Non-Hedged Price
	Without Hedge		With Hedge		Hedged to Non-Hedged Price
Oil (per Bbl):
Nine months ended September 30, 2005	$	52.61	$	35.02	66.6	%
Nine months ended September 30, 2006		63.76		44.46	69.7	%
Gas (per Mcf):
Nine months ended September 30, 2005	$	6.51	$	4.68	71.9	%
Nine months ended September 30, 2006		6.51		7.72	118.6	%

Derivative contracts that do not qualify for hedge accounting are included in other income and have no effect on our reported revenues or average realized prices.

Costs and Expenses. The following table presents information about our operating expenses for the first nine months of 2005 and 2006:


	Amount						Per Mcfe
	Nine months ended September 30,				Percent Increase		Nine months ended September 30,				Percent Increase
	2005		2006		Percent Increase		2005		2006		Percent Increase
	(dollars in thousands)
Lease operating expenses	$	28,556	$	46,951	64.4	%	$	1.59	$	2.03	27.7	%
Production taxes		9,284		13,869	49.4	%		0.52		0.60	15.4	%
Depreciation, depletion and amortization		20,579		35,163	70.9	%		1.15		1.52	32.2	%
General and administrative		6,631		9,660	45.7	%		0.37		0.42	13.5	%

Lease operating expenses – Increase was primarily due to increases in the net number of producing wells and higher oilfield service costs which was then somewhat mitigated by a higher producing rate per well. Included in the figures are $6.0 million of costs associated with workovers in the first nine months of 2006 compared to $3.2 million in the same period of 2005.

Production taxes (which include ad valorem taxes) – Increase is primarily due to an increase of 29.4% in production volumes and average realized oil prices being 21% higher in the nine months ended September 30, 2006 compared to the same period in 2005. Ad valorem taxes increased $1.5 million due to an increase in the net number of wells and higher assessed property values.

Depreciation, depletion and amortization – Increase is primarily due to increase in DD&A on oil and gas properties. DD&A on oil and gas properties increased $7.2 million due to higher production volumes and $6.8 million due to an increase in the DD&A rate on oil and gas properties per equivalent unit of production. Our DD&A rate per equivalent unit of production increased $0.22 to $1.37 per Mcfe primarily due to estimated higher future development costs for proved undeveloped reserves.

General and administrative expense – Increase in general and administrative expenses was primarily due to the growth in our workforce resulting from an increase in our level of activity. G&A expense is net of $6.3 million in the first nine months of 2006 and $4.3 million in the first nine months of 2005 Capitalized as it directly related to our exploration and development activities.

Interest Expense. Interest expense increased during the first nine months of 2006 by $20.7 million, or 250%, 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.

Non-hedge derivative losses. Non-hedge derivative losses were $4.6 million during the nine months ended September 30, 2006 and are comprised of losses of $1.9 million on natural gas basis differential swaps and $2.7 on non-qualified derivative contracts. There were no non-hedge derivatives in the nine months ending September 30, 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:


	Nine Months Ended September 30,
(dollars in thousands)	2005			2006
Cash flows provided by operating activities	$	50,840		$	72,160
Cash flows used in investing activities		(222,009	)		(165,211	)
Cash flows provided by financing activities		208,384			194,178

Net increase in cash during the period	$	37,215		$	101,127

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 nine months ended September 30, 2006, net cash provided from operations increased 41.9% from the same period in the prior year and provided approximately 43.7% 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 nine months of 2006 to fund $162.5 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)	Nine Months Ended September 30, 2006		Percent of Total
Development activities:
Developmental drilling	$	98,683	62.9	%
Enhancements		22,771	14.5	%
Tertiary recovery		10,415	6.7	%
Acquisitions		19,029	12.1	%
Exploration activities		6,008	3.8	%

Total	$	156,906	100.0	%

In addition to the Capital expenditures for oil and gas properties, we spent approximately $5.6 million for acquisition and construction of new office and administrative facilities and equipment during 2006.

The purchase price for the $500.0 million Calumet acquisition, including amounts deposited in escrow, was funded through cash from our private equity sale and increased borrowings under our credit facility. Except for the Calumet acquisition, our Capital budget for the remainder of 2006 is expected to be funded primarily from cash flows from operations.

During the first nine months of 2006, we borrowed $92.0 million under our revolving credit facility. We also sold equity through a private offering for $102.0 million, netting approximately $100.9 million after expenses.

As of September 30, 2006, we had cash and cash equivalents of $102.7 million and long-term debt obligations of $540.4 million.

Our credit facility. As of September 30, 2006, we had $201.0 million outstanding under our Credit Agreement and the borrowing base was $250.0 million. We believe we are in compliance with all covenants under the Credit Agreement as of September 30, 2006.

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 September 30, 2006, our current ratio as computed using generally accepted accounting principles was 0.65 and 1.88, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 2.05 and 2.87, 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			September 30, 2006
Current assets per GAAP	$	77,255		$	172,548
Plus—Availability under Credit Agreement		62,500			49,000
Less—Deferred tax asset on hedges and asset retirement obligation		(24,057	)		(4,531	)
Less—Short-term derivative instruments		(1,016	)		(7,331	)

Current assets as adjusted	$	114,682		$	209,686

Current liabilities per GAAP	$	119,292		$	91,892
Less—Short-term derivative instruments		(63,125	)		(18,596	)
Less—Short-term asset retirement obligation		(346	)		(360	)

Current liabilities as adjusted	$	55,821		$	72,936

Current ratio for loan compliance		2.05			2.87

On October 31, 2006, we entered into a Seventh Restated Credit Agreement in conjunction with the Calumet acquisition. The Credit Agreement provides for a $750.0 million maximum commitment amount, is secured by our oil and gas properties and matures on October 31, 2010. Obligations under the Credit Agreement are also secured by pledges by us and each of the borrowers of equity interests in other subsidiaries owned by us and them, excluding specified entities. Availability under our Credit Agreement is subject to a borrowing base, which is initially $750.0 million and which is set by the banks semi-annually on May 1 and November 1 of each year, and a conforming borrowing base, which is initially $650.0 million . In addition, the banks may request a borrowing base and a conforming borrowing base redetermination once every six months. Also, on February 1, 2007, the borrowing base and the conforming borrowing base will each reduce to $700.0 million and $630.0 million (less certain further reductions in the event that permitted additional bond debt has been issued), respectively, and on May 1, 2007, the borrowing base and the conforming borrowing base will each reduce to $610.0 million (less certain further reductions in the event that permitted additional bond debt has been issued). 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.

Borrowings under our Credit Agreement are made, at our option, as either Eurodollar loans or Alternate Base Rate, or ABR, loans. At October 31, 2006, $114.0 million of our borrowings were Eurodollar loans and $515.0 million were Alternate Base Rate loans. Effective November 3, 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 October 31, 2006, the LIBOR rate was 5.32%, the Statutory Reserve Rate multiplier was 100% and the applicable margin and commitment fee together were 2.51% resulting in an effective interest rate of 7.83% 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 1.00% depending on the utilization percentage of the borrowing base. At October 31, 2006 the applicable rate was 8.25% and the applicable margin was 0.50% resulting in an effective interest rate of 8.75% for ABR borrowings. Interest payments on ABR borrowings are due the last day of each March, June, September and December.

Commitment fees of 0.25% to 0.50% accrue on the unused portion of the borrowing base amount, depending on the utilization percentage, and are included as a component of interest expense. We have the right to make prepayments of the borrowings at any time without penalty or premium.

Our Credit Agreement contains restrictive covenants that may limit our ability, among other things, to:

•

incur additional indebtedness;

•

create or incur additional liens on our oil and 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 requires us to maintain a Current Ratio, as defined in our Credit Agreement, of not less than 1.0 and 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 October 31, 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;

•

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.

As of October 31, 2006, upon the completion of the Calumet acquisition and the entry into the Credit Agreement, we had $629.0 million outstanding under our Credit Agreement.

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.

Hedging. 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 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.

The accounting for future abandonment costs changed on January 1, 2003 with our adoption of Statement on Financial Accounting Standards No. 143. This standard requires that a liability for the discounted fair value of an asset retirement obligation be recorded 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.

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 nine months ended September 30, 2006 production, our gross revenues from oil and gas sales would change approximately $1.6 million for each $0.10 change in gas prices and $1.3 million for each $1.00 change in oil prices.

The 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, we enter into swap agreements. For swap instruments, we receive 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.

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.

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 market price at the determination date, and/or the value confirmed by the counterparty.

Changes in the fair value of effective cash flow hedges are recorded as a component of accumulated other comprehensive income, which is later transferred to earnings when the hedged transaction occurs. The ineffective portion is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. 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 income statement. 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.

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


	Natural gas					Crude Oil
Contract type and period	Volume MMcf	Weighted average fixed price to be received		Percent of PDP production hedged		Volume MBbl	Weighted average fixed price to be received		Percent of PDP production hedged
Swaps
4Q 2006	2,910	$	8.04	65.8	%	312	$	48.63	72.7	%
1Q 2007	2,610		8.61	61.8	%	402		55.30	85.9	%
2Q 2007	2,610		7.04	64.5	%	393		55.32	86.9	%
3Q 2007	2,610		7.05	68.7	%	372		58.10	85.8	%
4Q 2007	1,410		8.67	38.5	%	342		63.09	82.4	%
1Q 2008	960		10.07	27.3	%	318		67.29	81.2	%
2Q 2008	870		8.10	25.6	%	318		66.97	90.2	%
3Q 2008	510		8.14	15.5	%	313		67.36	91.8	%
4Q 2008	150		8.92	4.7	%	277		68.30	84.1	%
1Q 2009	—		—	—		270		67.51	89.2	%
2Q 2009	—		—	—		270		67.08	92.1	%
3Q 2009	—		—	—		270		66.66	95.0	%
4Q 2009	—		—	—		270		66.23	97.9	%
1Q 2010	—		—	—		240		65.88	88.7	%
2Q 2010	—		—	—		240		65.60	91.0	%
3Q 2010	—		—	—		240		65.09	95.1	%
4Q 2010	—		—	—		240		64.70	97.5	%
1Q 2011	—		—	—		210		64.46	87.4	%
2Q 2011	—		—	—		210		64.09	89.9	%
3Q 2011	—		—	—		210		63.71	92.8	%
4Q 2011	—		—	—		210		63.39	95.1	%
Basis protection swaps
4Q 2006	1,660	$	1.41
1Q 2007	1,470		1.05
2Q 2007	1,440		1.16
3Q 2007	1,590		1.14
4Q 2007	1,290		1.01
1Q 2008	1,140		1.12
2Q 2008	1,290		1.20
3Q 2008	1,190		1.16
4Q 2008	1,190		1.03
1Q 2009	1,140		0.89
2Q 2009	540		0.82

In connection with entering into a Securities Purchase Agreement with Calumet Oil Company on September 16, 2006, we entered into additional crude oil swaps and swaption contracts to provide protection against a decline in the price of oil. The swaptions gave us the option, but not the obligation, to enter into fixed price oil swaps for 400 MBbls in 2008 and 1,800 MBbls in 2009 through 2011 under which we would receive a fixed commodity price and pay a floating market price, resulting in a net amount due to or from the counterparty. The fixed commodity prices ranged from $64.63 in 2008 to $59.72 in 2011. The cost of the swaption contracts was approximately $2.8 million. The additional crude oil swaps were for 60 MBbls in 2009 and 2010 and 180 MBbls in 2011 at an average price of $63.63. We do not believe that these instruments qualify as hedges pursuant to SFAS No. 133. Therefore, 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.

Interest rates. All of the outstanding borrowings under our Credit Agreement as of September 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 $250.0 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 $2.5 million.

ITEM 4.

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that material information relating to 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 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 8¹/2% 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 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 September 30, 2006, our total debt was $540.4 million and our total book Capitalization was $713.3 million. Our maximum commitment amount and the borrowing base under our Credit Agreement was $450.0 million and $250.0 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 8¹/2% 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, which is initially $750.0 million and which is set by the banks semi-annually on May 1 and November 1 of each year, and a conforming borrowing base, which is initially $650.0 million. In addition, the banks may request a borrowing base and a conforming borrowing base redetermination once every six months. Also, on February 1, 2007, the borrowing base and the conforming borrowing base will each reduce to $700.0 million and $630.0 million (less certain further reductions in the event that permitted additional bond debt has been issued), respectively, and on May 1, 2007, the borrowing base and the conforming borrowing base will each reduce to $610.0 million (less certain further reductions in the event that permitted additional bond debt has been issued). 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. 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. 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;

•

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.

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. As of September 30, 2006, we had hedged 14,640 MMcf of our natural gas production for 2006 through 2008 at average monthly prices ranging from $7.04 to $10.07 per Mcf of natural gas. As of September 30 2006, we had 5,927 MBbl of our crude oil production for 2006 through 2011 at average monthly prices ranging from $48.63 to $68.30 per Bbl of oil. As of September 30, 2006, we had basis protection swaps for 13,940 Mcf for 2006 through 2009 at average monthly prices ranging from $0.82 to $1.41 per mcf. Additionally, we had swaps and swaptions entered into in conjunction with an acquisition. The additional crude oil swaps were for 300 MBbls for 2009 through 2011 at a weighted average price $63.63 and the swaptions allows us the option, but not the obligation to enter into fixed price commodity swaps for 2,200 MBbls for 2008 through 2011 at prices ranging from $59.72 to $64.63 per Mbl. The fair value of our oil and natural gas derivative instruments outstanding as of September 30, 2006 was a liability of approximately $13.7 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.

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 September 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 $250.0 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 $2.5 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.

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 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On September 25, 2006, our stockholders acted by unanimous written consent to approve our amended and restated certificate of incorporation in connection with our 775-for-1 stock split effected as stock dividend paid on September 27, 2006. A total of 1,000 shares of our common stock, representing all of our then-issued and outstanding shares of common stock, approved this amendment.

On September 28, 2006, we held our annual meeting of stockholders in Oklahoma City, Oklahoma to elect three directors. A total of 775,000 shares of our common stock were present at the meeting, representing all of our then-issued and outstanding shares of common stock after giving effect to the 775-for-1 stock split.

Director nominees were elected at the annual meeting based on the following vote tabulation:


	Votes in Favor	Votes Withheld
Mark A. Fischer	775,000	—
Charles A. Fischer, Jr.	775,000	—
Joseph O. Evans	775,000	—

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		Amended and Restated Certificate of Incorporation of the Company, dated as of September 26, 2006.

3.3	*	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)

3.4		Amended and Restated Bylaws of the Company, dated as of September 26, 2006.

4.1	*	Form of 8¹/2% 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)

4.3	*	First Supplemental Indenture, dated as of August 24, 2006, to Indenture dated as of December 1, 2005 among the Company, as Issuer, the Guarantors named therein and Wells Fargo Bank, National Association, as Trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on August 28, 2006)

4.4	*	Second Supplemental Indenture, dated as of October 31, 2006, to Indenture dated as of December 1, 2005 among the Company, as Issuer, the Guarantors named therein and Wells Fargo Bank, National Association, as Trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on November 6, 2006)

10.1		Common Stock Purchase Agreement, dated as of September 1, 2006, by and among the Company, Chesapeake Energy Corporation, Altoma Energy and Fischer Investments, L.L.C.

10.2		Stockholders’ Agreement, dated as of September 29, 2006, by and among the Company, Chesapeake Energy Corporation, Altoma Energy and Fischer Investments, L.L.C.

10.3	*	Seventh Restated Credit Agreement, dated as of October 31, 2006, by and among the Company, Chaparral Energy, L.L.C., in its capacity as Borrower Representative for the Borrowers, JPMorgan Chase Bank, N.A., as Administrative Agent, and each of the Lenders named therein. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on November 6, 2006)

10.4	*	Securities Purchase Agreement, dated as of September 16, 2006, by and among the Company, Calumet Oil Company, JMG Oil & Gas, L.P., J.M. Graves L.L.C. and each of the Sellers party thereto. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on November 6, 2006)

10.5	*	First Amendment to Securities Purchase Agreement, dated as of October 31, 2006, by and among the Company, Calumet Oil Company, JMG Oil & Gas, L.P., J.M. Graves L.L.C. and each of the Sellers party thereto. (Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on November 6, 2006)


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

SIGNATURES

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


CHAPARRAL ENERGY, INC.

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

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

Date:		November 14, 2006

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		Amended and Restated Certificate of Incorporation of the Company, dated as of September 26, 2006.

3.3	*	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)

3.4		Amended and Restated Bylaws of the Company, dated as of September 26, 2006.

4.1	*	Form of 8¹/2% 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)

4.3	*	First Supplemental Indenture, dated as of August 24, 2006, to Indenture dated as of December 1, 2005 among the Company, as Issuer, the Guarantors named therein and Wells Fargo Bank, National Association, as Trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on August 28, 2006)

4.4	*	Second Supplemental Indenture, dated as of October 31, 2006, to Indenture dated as of December 1, 2005 among the Company, as Issuer, the Guarantors named therein and Wells Fargo Bank, National Association, as Trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on November 6, 2006)

10.1		Common Stock Purchase Agreement, dated as of September 1, 2006, by and among the Company, Chesapeake Energy Corporation, Altoma Energy and Fischer Investments, L.L.C.

10.2		Stockholders’ Agreement, dated as of September 29, 2006, by and among the Company, Chesapeake Energy Corporation, Altoma Energy and Fischer Investments, L.L.C.

10.3	*	Seventh Restated Credit Agreement, dated as of October 31, 2006, by and among the Company, Chaparral Energy, L.L.C., in its capacity as Borrower Representative for the Borrowers, JPMorgan Chase Bank, N.A., as Administrative Agent, and each of the Lenders named therein. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on November 6, 2006)

10.4	*	Securities Purchase Agreement, dated as of September 16, 2006, by and among the Company, Calumet Oil Company, JMG Oil & Gas, L.P., J.M. Graves L.L.C. and each of the Sellers party thereto. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on November 6, 2006)

10.5	*	First Amendment to Securities Purchase Agreement, dated as of October 31, 2006, by and among the Company, Calumet Oil Company, JMG Oil & Gas, L.P., J.M. Graves L.L.C. and each of the Sellers party thereto. (Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on November 6, 2006)


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