Chaparral Energy, Inc. - FORM 10-Q

Attached files

file	filename
EX-31.2 - CERTIFICATION BY CFO REQUIRED BY RULE 13A-14(A) AND 15D-14(A) - Chaparral Energy, Inc.	dex312.htm
EX-32.2 - CERTIFICATION OF CFO PURSUANT TO SECTION 906 - Chaparral Energy, Inc.	dex322.htm
EX-32.1 - CERTIFICATION BY CEO PURSUANT TO SECTION 906 - Chaparral Energy, Inc.	dex321.htm
EX-31.1 - CERTIFICATION BY CEO REQUIRED BY RULE 13A-14(A) AND 15D-14(A) - Chaparral Energy, Inc.	dex311.htm
EX-10.22 - SECOND AMENDED & RESTATED PHANTOM STOCK PLAN - Chaparral Energy, Inc.	dex1022.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2009

¨	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 x No ¨

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

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

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

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

877,000 shares of the registrant’s common stock were outstanding as of November 10, 2009.

CHAPARRAL ENERGY, INC.

Index to Form 10-Q


		Page
Part I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of December 31, 2008 and September 30, 2009 (Unaudited)		5
Consolidated Statements of Operations for the three and nine months ended September 30, 2008 and 2009 (Unaudited)		6
Consolidated Statements of Cash Flows for the nine months ended September 30, 2008 and 2009 (Unaudited)		7
Notes to Consolidated Financial Statements (Unaudited)		9
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		25
Overview		25
Liquidity and Capital Resources		29
Results of Operations		35
Non-GAAP Financial Measures and Reconciliations		41
Critical Accounting Policies and Estimates		42
Recent Accounting Pronouncements		44
Item 3. Quantitative and Qualitative Disclosures About Market Risk		44
Item 4. Controls and Procedures		47
Part II. OTHER INFORMATION		47
Item 1. Legal Proceedings		47
Item 1A. Risk Factors		48
Item 6. Exhibits		50
Signatures		51
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 NOTE

REGARDING FORWARD-LOOKING STATEMENTS

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

•

ability to complete, integrate, and obtain the expected benefits from the pending merger with United Refining Energy Corp.;

•

the growth of the market for our services;

•

the actual quantities of our proved reserves of oil and gas;

•

our future levels of production of oil and gas;

•

the results of our future exploration, development and exploitation activities;

•

the future operating and developmental costs of our oil and gas properties;

•

the future price and demand for oil and gas;

•

our continued compliance with government regulations;

•

legislation or regulatory environments, requirements or changes adversely affecting our business;

•

our ability to obtain a new credit facility or an amendment to our existing credit facility to service our existing debt and the results of our future financing efforts;

•

our plans, objectives, expectations and intentions contained herein that are not historical;

•

the amount and timing of our capital expenditures; and

•

our ability to develop and carry out our business strategy, including expansion plans and opportunities.

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

•

our revenues and operating performance;

•

changes in overall economic conditions;

•

risks and costs associated with regulation of corporate governance and disclosure standards (including pursuant to Section 404 of the Sarbanes-Oxley Act of 2002); and

•

other risks referenced from time to time in our filings with the Securities and Exchange Commission.

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

GLOSSARY OF OIL AND GAS TERMS

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

•

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

•

BBtu. One billion British thermal units.

•

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

•

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

•

Enhanced oil recovery (EOR). The use of any improved recovery method, including injection of CO2 or polymer, to remove additional oil after secondary recovery.

•

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

•

MBoe. One thousand barrels of crude oil equivalent.

•

Mcf. One thousand cubic feet of natural gas.

•

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

•

MMBoe. One million barrels of crude oil equivalent.

•

MMcf. One million cubic feet of natural gas.

•

NYMEX. The New York Mercantile Exchange.

•

PDP. Proved developed producing.

•

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

PART I — FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets


(Dollars in thousands, except per share data )	December 31, 2008			September 30, 2009 (unaudited)
Assets
Current assets:
Cash and cash equivalents	$	52,112		$	85,242
Accounts receivable, net		63,957			44,181
Production tax benefit		13,685			19
Inventories		13,552			10,692
Prepaid expenses		4,114			4,901
Derivative instruments		51,412			27,709
Assets held for sale		19,531			3,691

Total current assets		218,363			176,435
Property and equipment—at cost, net		65,759			60,742
Oil & gas properties, using the full cost method:
Proved		1,751,096			1,871,906
Unproved (excluded from the amortization base)		16,865			16,943
Work in progress (excluded from the amortization base)		31,893			7,948
Accumulated depreciation, depletion, amortization and impairment		(573,233	)		(885,563	)

Total oil & gas properties		1,226,621			1,011,234
Funds held in escrow		2,350			1,662
Derivative instruments		157,720			11,291
Deferred income taxes		—			67,166
Assets held for sale		7,744			2,457
Other assets		34,279			17,278

	$	1,712,836		$	1,348,265

Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	89,744		$	45,477
Accrued payroll and benefits payable		9,215			10,662
Accrued interest payable		15,408			14,090
Revenue distribution payable		19,827			18,453
Current maturities of long-term debt and capital leases		5,536			4,738
Derivative instruments		—			5,340
Deferred income taxes		19,696			8,462
Liabilities associated with discontinued operations		3,697			1,188

Total current liabilities		163,123			108,410
Long-term debt and capital leases, less current maturities		615,936			525,568
Senior notes, net		647,675			647,825
Derivative instruments		3,388			20,630
Deferred compensation		762			901
Asset retirement obligations		33,075			35,443
Deferred income taxes		42,699			—
Liabilities associated with discontinued operations		1,778			149
Commitments and contingencies (note 8)
Stockholders’ equity:
Preferred stock, 600,000 shares authorized, none issued and outstanding		—			—
Common stock, $.01 par value, 3,000,000 shares authorized; 877,000 shares issued and outstanding as of December 31, 2008 and September 30, 2009, respectively		9			9
Additional paid in capital		100,918			100,918
Retained earnings (accumulated deficit)		21,340			(125,594	)
Accumulated other comprehensive income, net of taxes		82,133			34,006

		204,400			9,339

	$	1,712,836		$	1,348,265

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

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of operations


	Three months ended September 30,						Nine months ended September 30,
(Dollars in thousands, except per share data )	2008 (unaudited)			2009 (unaudited)			2008 (unaudited)			2009 (unaudited)
Revenues:
Oil and gas sales	$	148,669		$	77,753		$	427,365		$	200,684
Gain (loss) from oil and gas hedging activities		(2,315	)		1,143			(91,670	)		22,834

Total revenues		146,354			78,896			335,695			223,518
Costs and expenses:
Lease operating		32,290			21,980			86,202			72,945
Production tax		9,822			5,367			28,338			14,168
Depreciation, depletion and amortization		25,129			24,700			73,774			80,100
Loss on impairment of oil & gas properties		—			—			—			240,790
Loss on impairment of ethanol plant		2,900			—			2,900			—
Litigation settlement		—			—			—			2,928
General and administrative		4,879			5,854			18,960			18,128

Total costs and expenses		75,020			57,901			210,174			429,059
Operating income (loss)		71,334			20,995			125,521			(205,541	)
Non-operating income (expense):
Interest expense		(21,661	)		(22,471	)		(64,282	)		(67,655	)
Non-hedge derivative gains (losses)		77,186			(5,000	)		10,005			12,308
Other income		514			434			1,668			14,184

Net non-operating income (expense)		56,039			(27,037	)		(52,609	)		(41,163	)
Income (loss) from continuing operations before income taxes		127,373			(6,042	)		72,912			(246,704	)
Income tax expense (benefit)		49,265			(1,572	)		28,334			(94,189	)

Income (loss) from continuing operations		78,108			(4,470	)		44,578			(152,515	)
Income from discontinued operations, net of related taxes		396			84			907			5,581

Net income (loss)	$	78,504		$	(4,386	)	$	45,485		$	(146,934	)

Net income (loss) per share (basic and diluted)
Continuing operations	$	89.06		$	(5.10	)	$	50.83		$	(173.90	)
Discontinued operations		0.45			0.10			1.03			6.36

Net income (loss) per share (basic and diluted)	$	89.51		$	(5.00	)	$	51.86		$	(167.54	)

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

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

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows


	Nine months ended September 30,
(Dollars in thousands )	2008 (unaudited)			2009 (unaudited)
Cash flows from operating activities
Net income (loss)	$	45,485		$	(146,934	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion & amortization		73,774			80,100
Depreciation, depletion & amortization of discontinued operations		970			626
Loss on impairment of oil and gas properties		—			240,790
Loss on impairment of ethanol plant		2,900			—
Litigation settlement		—			2,928
Deferred income taxes		28,910			(90,742	)
Gain from hedge ineffectiveness and reclassification adjustments		(6,565	)		(20,360	)
Change in fair value of non-hedge derivative instruments		(10,005	)		(12,308	)
Gain on sale of ESP Division of GCS and other assets		(281	)		(9,010	)
Other		1,246			1,999
Change in assets and liabilities
Accounts receivable		(312	)		40,519
Inventories		(5,884	)		3,519
Prepaid expenses and other assets		3,809			10,332
Accounts payable and accrued liabilities		5,923			(8,687	)
Revenue distribution payable		5,092			(1,374	)
Deferred compensation		1,031			47

Net cash provided by operating activities		146,093			91,445
Cash flows from investing activities
Purchase of property and equipment and oil and gas properties		(243,544	)		(135,135	)
Proceeds from sale of ESP Division of GCS		—			24,650
Proceeds from dispositions of property and equipment and oil and gas properties		1,767			467
Settlement of non-hedge derivative instruments		(5,953	)		146,898
Cash in escrow		1,066			388

Net cash provided by (used in) investing activities		(246,664	)		37,268
Cash flows from financing activities
Proceeds from long-term debt		101,925			25
Repayment of long-term debt		(3,845	)		(93,258	)
Principal payments under capital lease obligations		(167	)		(190	)
Settlement of derivative instruments acquired		144			—
Fees paid related to financing activities		(1,633	)		(2,160	)

Net cash provided by (used in) financing activities		96,424			(95,583	)

Net increase (decrease) in cash and cash equivalents		(4,147	)		33,130
Cash and cash equivalents at beginning of period		11,687			52,112

Cash and cash equivalents at end of period	$	7,540		$	85,242

Supplemental cash flow information
Cash paid (received) during the period for:
Interest, net of capitalized interest	$	62,492		$	65,835
Income taxes		—			(1	)

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

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows—(Continued)

Supplemental disclosure of investing and financing activities

During the nine months ended September 30, 2008 and 2009, we entered into capital lease obligations of $586 and $111, respectively, for the purchase of machinery and equipment.

During the nine months ended September 30, 2008, oil and gas property additions of $3,288 were recorded as increases to accounts payable and accrued expenses, and were reflected in cash used in investing activities in the periods that the payables were settled. Non-cash additions to property and equipment as of September 30, 2008 also include $1,707 related to final settlement of the Green Country Supply acquisition. During the nine months ended September 30, 2009, oil and gas property additions of $37,631 previously included in accounts payable and accrued expenses were settled and are reflected in cash used in investing activities.

During the nine months ended September 30, 2008 and 2009, we recorded an asset and related liability of $655 and $306, respectively, associated with the asset retirement obligation on the acquisition and/or development of oil and gas properties.

Interest of $1,167 and $629 was capitalized during the nine months ended September 30, 2008 and 2009, respectively, primarily related to unproved oil and gas leaseholds.

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

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

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

Interim financial statements

The accompanying unaudited consolidated interim financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X and do not include all of the financial information and disclosures required by GAAP. The financial information as of September 30, 2009, and for the three and nine months ended September 30, 2008 and 2009, is unaudited. In the opinion of management, such information contains all adjustments, consisting only of normal recurring accruals, considered necessary for a fair presentation of the results of the interim periods. The results of operations for the three and nine months ended September 30, 2009, are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2009.

The consolidated interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto, together with management’s discussion and analysis of financial condition and results of operations contained in our Form 10-K filed with the Securities and Exchange Commission on March 31, 2009.

Principles of consolidation

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

Reclassifications

Certain reclassifications have been made to prior period financial statements to conform to current period presentation.

Use of estimates

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

Cash and cash equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of September 30, 2009, cash and funds held in escrow with a recorded balance totaling $82,522 was held at JP Morgan Chase Bank, N.A. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts.

Fair value measurements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued new authoritative guidance which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.

As permitted by the FASB’s one-year deferral, we adopted the new fair value guidance for our financial assets and financial liabilities measured at fair value on January 1, 2008, and we adopted the new guidance for our nonfinancial assets and nonfinancial liabilities measured at fair value on a non-recurring basis on January 1, 2009. With the exception of incorporating the impact of nonperformance risk on derivative instruments, we did not change our method of calculating the fair value of assets or liabilities. The primary impact from adoption was additional disclosures.

Assets and liabilities recorded at fair value in the balance sheet are categorized according to the fair value hierarchy defined by the FASB. The hierarchical levels are based upon the level of judgment associated with the inputs used to measure the fair value of the assets and liabilities. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the asset or liability is categorized based on the lowest level input that is significant to the fair value measurement in its entirety. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 inputs include adjusted quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities included in this category are derivatives with fair values based on published forward commodity price curves and other observable inputs. Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Assets recognized at fair value and included in this category are certain financial derivatives and additions to our asset retirement obligations.

In April 2009, the FASB provided additional application guidance regarding “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” requiring “Interim Disclosures about Fair Value of Financial Instruments,” and clarifying “Recognition and Presentation of Other-Than-Temporary Impairments.” This guidance is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We adopted this guidance for the period ending March 31, 2009, which resulted in additional disclosures, but did not have an impact on our financial position or results of operations.

Net income (loss) per share

Basic net income (loss) per share is computed by dividing net income (loss) 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 net income (loss) per share is determined in the same manner as basic net income (loss) per share except that the number of shares is increased to assume exercise of potentially dilutive securities outstanding during the periods presented. There were no potentially dilutive securities outstanding during the periods presented.

Accounts receivable

Accounts receivable consisted of the following at December 31, 2008 and September 30, 2009:


	December 31, 2008			September 30, 2009
Joint interests	$	21,136		$	12,231
Accrued oil and gas sales		27,432			26,972
Hedge settlements		15,315			5,685
Other		654			174
Allowance for doubtful accounts		(580	)		(881	)

	$	63,957		$	44,181

Inventories

Inventories are comprised of equipment used in developing oil and gas properties and oil and gas production inventories. Equipment inventory is carried at the lower of cost or market using the average cost method. Oil and gas product inventories are stated at the lower of production cost or market. We regularly review inventory quantities on hand and record provisions for excess or obsolete inventory, if necessary. Inventories at December 31, 2008 and September 30, 2009 consisted of the following:


	December 31, 2008			September 30, 2009
Equipment inventory	$	10,484		$	8,320
Oil and gas product		3,467			3,215
Inventory valuation allowance		(399	)		(843	)

	$	13,552		$	10,692

Oil and gas properties

We use the full cost method of accounting for oil and gas properties and activities. Accordingly, we capitalize all costs incurred in connection with the exploration for and development of oil and gas reserves. Proceeds from the disposition of oil and gas properties are accounted for as a reduction in capitalized costs, with no gain or loss generally recognized unless such dispositions involve a significant alteration in the depletion rate. We capitalize internal costs that can be directly identified with exploration and development activities, but do not include any costs related to production, general corporate overhead or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and gas wells, including salaries, benefits and other internal costs directly attributable to these activities.

In accordance with the full cost method of accounting, the net capitalized costs of oil and gas properties are not to exceed their related estimated future net revenues discounted at 10% (“PV-10 value”), as adjusted for our cash flow hedge positions and net of tax considerations, plus the lower of cost or estimated fair value of unproved properties. During the first quarter of 2009, gas prices declined significantly as compared to the December 31, 2008 spot price of $5.62 per Mcf. Based on March 31, 2009, spot prices of $49.66 per Bbl of oil and $3.63 per Mcf of gas, the internally estimated PV-10 value of our reserves declined by 13.5% compared to the PV-10 value at December 31, 2008. As a result, we recorded a ceiling test impairment of oil and gas properties of $240,790 during the first quarter of 2009. The effect of derivative contracts accounted for as cash flow hedges, based on the March 31, 2009 spot prices, increased the full cost ceiling by $169,013, thereby reducing the ceiling test write down by the same amount.

As of September 30, 2009, the cost center ceiling exceeded the net capitalized cost of our oil and gas properties, and no ceiling test impairment was recorded during the third quarter of 2009. The internally estimated PV-10 value of our reserves was estimated based on spot prices of $70.21 per Bbl of oil and $3.24 per Mcf of gas at September 30, 2009. The effect of derivative contracts accounted for as cash flow hedges, based on these September 30, 2009 spot prices, reduced the full cost ceiling by $10,687. The qualifying cash flow hedges as of September 30, 2009, which consisted of commodity price swaps, covered 3,954 MBbls of oil production for the period from October 2009 through December 2011.

A decline in oil and gas prices subsequent to September 30, 2009, could result in additional ceiling test write downs in future periods. In addition, our reserve estimate as of December 31, 2009 will be prepared using an average price for oil and gas based upon the first day of each month for the prior twelve months as required by SEC Release No. 33-8995, Modernization of Oil and Gas Reporting. Because of the low oil prices prevalent through the first half of 2009, we expect this average price for oil to be lower than the price used in our reserve calculation as of September 30, 2009, which could cause both our reserve volumes and our PV-10 value as of December 31, 2009 to be lower than they were as of September 30, 2009. The amount of any future impairment is difficult to predict, and will depend on the oil and gas prices at the end of or during each period, the incremental proved reserves added during each period, and additional capital spent.

Production tax benefit asset

During 2006, we purchased interests in two venture capital limited liability companies resulting in a total investment of $15,000. Our return on the investment was the receipt of $2 of Oklahoma tax credits for every $1 invested and was recouped from our Oklahoma production taxes. The investments are accounted for as a production tax benefit asset and are netted against tax credits realized in other income using the effective yield method over the expected recovery period. As of December 31, 2008 and September 30, 2009, the carrying value of the production tax benefit asset was $13,685 and $19, respectively. Oklahoma production tax credits of $23 and $0, respectively, for the three months ended September 30, 2008 and 2009 and $711 and $13,544, respectively, for the nine months ended September 30, 2008 and 2009 were included in other income in the consolidated statements of operations.

Funds held in escrow

We have funds held in escrow that are restricted as to withdrawal or usage. The restricted amounts consisted of the following:


	December 31, 2008		September 30, 2009
Escrow from acquisitions	$	692	$	—
Plugging and abandonment escrow		1,658		1,662

	$	2,350	$	1,662

We are entitled to make quarterly withdrawals from the plugging escrow account equal to one-half of the interest earnings for the period and as reimbursement for actual plugging and abandonment expenses incurred on the North Burbank Unit, provided that written documentation has been provided. The balance is not intended to reflect our total future financial obligation for the plugging and abandonment of these wells.

Impairment of long-lived assets

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

We owned a 66.67% interest in Oklahoma Ethanol LLC, a joint venture to construct and operate an ethanol production plant in Blackwell, Oklahoma. Oklahoma Ethanol LLC retained a financial advisor to arrange project financing to fund construction costs and for related start-up working capital. Because financing did not close by September 15, 2008, the minority owner, Oklahoma Sustainable Energy LLC, is no longer able to participate in the joint venture, and we now own 100% of Oklahoma Ethanol, LLC. The City of Blackwell has also been unable to obtain financing for the railroad upgrades and storage facilities that would be necessary to support ethanol production. During the third quarter of 2008, we determined that we will be unlikely to obtain equity capital or new project financing for an ethanol plant, and accordingly recorded an impairment charge of $2,900, which was the amount of our investment in the ethanol plant.

Asset retirement obligations

We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of oil and gas properties. The accretion of the asset retirement obligations is included in depreciation, depletion and amortization on the consolidated statements of operations. Our asset retirement obligations consist of the estimated present value of future costs to plug and abandon or otherwise dispose of our oil and gas properties and related facilities. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, inflation rates, and well life, all of which are Level 3 inputs according to the fair value hierarchy. These estimates may change based upon future inflation rates and changes in statutory remediation rules.

Deferred income taxes

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

If applicable, we would report a liability for tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return, and would recognize interest and penalties related to uncertain tax positions in interest expense. As of December 31, 2008 and September 30, 2009, we have not recorded a liability or accrued interest related to uncertain tax positions.

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

Discontinued operations

Certain amounts have been reclassified to present the operations of Green Country Supply, Inc. (“GCS”), a wholly owned subsidiary, as discontinued operations. Unless otherwise indicated, information presented in the notes to the financial statements relates only to our continuing operations. See Note 2 for additional information relating to discontinued operations.

Recently issued accounting standards

In December 2007, the FASB issued new authoritative guidance regarding “Business Combinations” which is effective for acquisitions that occur in an entity’s fiscal year that begins after December 15, 2008. This guidance establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. This guidance also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. We adopted this guidance effective January 1, 2009. The guidance will apply prospectively to future business combinations, and did not have an effect on our reported financial position or results of operations.

In March 2008, the FASB issued new authoritative guidance regarding “Disclosures about Derivative Instruments and Hedging Activities” which is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. This guidance addresses concerns that the existing disclosure requirements do not provide adequate information about how derivative and hedging activities affect an entity’s financial position, financial performance, and cash flows. Accordingly, it requires enhanced disclosures about an entity’s derivative and hedging activities and thereby improves the transparency of financial reporting. We adopted these disclosure requirements beginning January 1, 2009, and their adoption did not have an impact on our financial position or results of operations.

In December 2008, the SEC issued Release No. 33-8995, Modernization of Oil and Gas Reporting, which revises disclosure requirements for oil and gas companies. The new disclosure requirements permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The new disclosure requirements also require companies to include nontraditional resources such as oil sands, shale, coal beds or other nonrenewable natural resources in reserves if they are intended to be upgraded to synthetic oil and gas. Currently the SEC requires that reserve volumes are determined using prices on the last day of the reporting period; however, the new disclosure requirements provide for reporting oil and gas reserves using an average price based upon the first day of each month for the prior twelve months rather than year-end prices. The new requirements will also allow companies to disclose their probable and possible reserves to investors, and will require them to report the independence and qualifications of their reserves preparer or auditor. The new rule is effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, pending the potential alignment of certain accounting standards by the FASB with the new rule. We will adopt the provisions of the new rule in connection with our December 31, 2009 Form 10-K filing. We are currently evaluating the impact of the rule on our financial statements.

In May 2009, the FASB issued new authoritative guidance regarding “Subsequent Events” which is effective for interim or annual periods ending after June 15, 2009. This guidance establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued, and requires the disclosure of the date through which an entity has evaluated subsequent events. Although there is new terminology, the guidance is based on the same principles as those that currently exist. We adopted the guidance for the period ending June 30, 2009, and its adoption did not have an impact on our financial position or results of operations.

In June 2009, the FASB issued new authoritative guidance regarding the “FASB Accounting Standards Codification,” which became the source of authoritative GAAP for nongovernmental entities effective for financial statements issued for interim and annual periods ending after September 15, 2009. We adopted the new guidance on July 1, 2009. The guidance did not have an impact on our financial position or results of operations, but it did affect the way we reference GAAP in our consolidated financial statements and accounting policies.

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

Note 2: Discontinued operations

During the second quarter of 2009, we committed to a plan to sell the assets of GCS, a wholly owned subsidiary that provides oilfield supplies, oilfield chemicals, downhole electric submersible pumps, and related services to oil and gas operators primarily in Oklahoma, Texas, and Wyoming.

On May 14, 2009, we entered into an agreement to sell the assets of the Electric Submersible Pumps Division of GCS (the “ESP Division”) to Global Oilfield Services, Inc. (“Global”) for a cash price of $26,000, subject to working capital adjustments as provided in the agreement. On June 8, 2009, we received $24,650 in conjunction with the closing of the ESP Division sale to Global. The amount received reflected a reduction of $1,350 due to working capital changes as of March 31, 2009. We paid off notes payable attributed to certain assets sold to Global in the amount of $1,605. The purchase price is subject to a final working capital adjustment, which is expected to be settled before December 31, 2009. For the nine months ended September 30, 2009, we recorded a pre-tax gain associated with the sale of $9,004. All taxable income associated with such gain was offset by existing net operating losses.


	Three months ended September 30,						Nine months ended June 30,
	2008			2009			2008			2009
Revenues	$	9,532		$	1,606		$	25,602		$	9,719
Operating expenses		(8,879	)		(1,515	)		(24,119	)		(9,696	)
Gain on sale		—			—			—			9,004

Income before income taxes		653			91			1,483			9,027
Income tax provision		(257	)		(7	)		(576	)		(3,446	)

Income from discontinued operations	$	396		$	84		$	907		$	5,581

At December 31, 2008 and September 30, 2009, the assets and liabilities of GCS are classified as assets held for sale and liabilities associated with discontinued operations, respectively, on our consolidated balance sheets.

Note 3: Derivative activities and financial instruments

Derivative activities

Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and gas. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into commodity price swaps, costless collars, and basis protection swaps. For commodity price swaps, we receive a fixed price for the hedged commodity and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty.

Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party. Our collars have not been designated as hedges. Therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative gains (losses). This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices.

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

As part of the Calumet acquisition, we assumed the existing Calumet swaps on October 31, 2006 and designated these as cash flow hedges. These derivative positions were recorded at fair value in the purchase price allocation as a liability of $838. Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed result in adjustments to our oil and gas revenues upon settlement. For example, if the fair value of the derivative positions assumed does not change, then upon the sale of the underlying production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no adjustment to oil and gas revenues related to the derivative positions. If, however, the actual sales price is different from the price assumed in the original fair value calculation, the difference would be reflected as either a decrease or increase in oil and gas revenues, depending upon whether the sales price was higher or lower, respectively, than the price assumed in the original fair value calculation.

The change in fair value of the acquired cash flow hedges from the date of acquisition is recorded as a component of accumulated other comprehensive income. In addition, the hedge instruments are deemed to contain a significant financing element, and all cash flows associated with these positions are reported as a financing activity in the consolidated statement of cash flows for the periods in which settlement occurs. All of these positions were settled as of December 31, 2008.

Our outstanding oil and gas derivative instruments as of September 30, 2009, are summarized below:


	Oil derivatives
	Swaps			Collars
	Volume MBbl	Weighted average fixed price to be received		Volume MBbl	Weighted average range
2009	643	$	67.29	60	$	110.00 - $164.28
2010	2,357		67.45	240		110.00 - 168.55
2011	1,785		65.60	204		110.00 - 152.71

	4,785			504


	Gas derivatives						Natural gas basis protection swaps
	Swaps			Collars			Natural gas basis protection swaps
	Volume BBtu	Weighted average fixed price to be received		Volume BBtu	Weighted average range		Volume BBtu	Weighted average fixed price to be paid
2009	2,900	$	7.91	990	$	10.00 - $13.85	4,440	$	0.94
2010	12,600		7.43	3,360		10.00 - 11.53	16,600		0.81
2011	10,200		7.38	—			12,990		0.74

	25,700			4,350			34,030

All derivative financial instruments are recorded on the balance sheet at fair value. The fair value of swaps is generally determined based on the difference between the fixed contract price and the underlying published forward market price. The fair value of collars is determined using an option pricing model which takes into account market volatility, market prices, and contract parameters. Derivative instruments are discounted using a rate that incorporates our nonperformance risk for derivative liabilities, and our counterparties’ credit risk for derivative assets. Our derivative contracts have been executed with the institutions that are parties to our revolving credit facility. We believe the credit risks associated with all of these institutions are acceptable. None of our derivative contracts have margin requirements, collateral provisions, or other credit-risk-related contingent features that would require funding prior to the scheduled cash settlement date.

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


	As of December 31, 2008							As of September 30, 2009
	Assets		Liabilities			Net Value		Assets		Liabilities			Net Value
Derivatives designated as cash flow hedges:
Oil swaps	$	116,311	$	(5,631	)	$	110,680	$	1,811	$	(31,189	)	$	(29,378	)
Derivatives not designated as hedging instruments:
Gas swaps		14,043		(731	)		13,312		28,597		(65	)		28,532
Oil swaps		2,424		(1,688	)		736		—		(8,515	)		(8,515	)
Gas collars		21,682		—			21,682		17,842		—			17,842
Oil collars		57,716		—			57,716		18,011		—			18,011
Natural gas basis differential swaps		2,093		(475	)		1,618		4		(13,466	)		(13,462	)

Total non-hedge instruments		97,958		(2,894	)		95,064		64,454		(22,046	)		42,408

Total derivative instruments		214,269		(8,525	)		205,744		66,265		(53,235	)		13,030
Less:
Netting adjustments (1)		5,137		(5,137	)		—		27,265		(27,265	)		—
Current portion asset (liability)		51,412		—			51,412		27,709		(5,340	)		22,369

	$	157,720	$	(3,388	)	$	154,332	$	11,291	$	(20,630	)	$	(9,339	)

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

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

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


	Three months ended September 30,						Nine months ended September 30,
	2008			2009			2008			2009
Amount of gain (loss) recognized in AOCI (effective portion)
Oil swaps	$	204,034		$	4,758		$	(99,718	)	$	(54,686	)
Gas swaps		34,895			—			(9,834	)		—
Income taxes		(92,414	)		(1,840	)		42,388			21,153

	$	146,515		$	2,918		$	(67,164	)	$	(33,533	)

Amount of gain (loss) reclassified from AOCI in income (effective portion)(1)
Oil swaps	$	(32,937	)	$	(1,518	)	$	(74,234	)	$	17,554
Gas swaps		(5,188	)		1,600			(11,403	)		6,245
Income taxes		14,756			(31	)		33,135			(9,205	)

	$	(23,369	)	$	51		$	(52,502	)	$	14,594

Amount of gain (loss) recognized in income (ineffective portion)(1)
Oil swaps	$	15,542		$	1,061		$	1,143		$	(965	)
Gas swaps		20,268			—			(7,176	)		—

	$	35,810		$	1,061		$	(6,033	)	$	(965	)

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

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

In addition, during the fourth quarter of 2008, we early settled oil and gas swaps and collars with original settlement dates from January through June of 2009 for proceeds of $32,589. During the first quarter of 2009, we early settled additional gas swaps with original settlement dates from May through October of 2009 for proceeds of $9,522. During the second quarter of 2009, we early settled additional oil swaps and collars with original settlement dates from January 2012 through December 2013 for proceeds of $102,352. Certain swaps that were early settled had previously been accounted for as cash flow hedges. As of December 31, 2008, and September 30, 2009, accumulated other comprehensive income included $23,662 and $84,835, respectively, of deferred gains related to discontinued cash flow hedges that will be recognized as a gain from oil and gas hedging activities when the hedged production is sold. No oil and gas derivatives were early settled during the first nine months of 2008.

Gains of $1,600 and $20,759 associated with derivatives for which hedge accounting had previously been discontinued were reclassified into earnings during the three and nine months ended September 30, 2009, respectively, as the hedged production was sold. There were no gains or losses associated with the discontinuance of hedge accounting treatment during the three and nine months ended September 30, 2008. Gain (loss) from oil and gas hedging activities, which is a component of total revenues in the consolidated statements of operations, is comprised of the following:


	Three months ended September 30,						Nine months ended September 30,
	2008			2009			2008			2009
Oil derivatives
Reclassification adjustment for hedge gains (losses) included in net income (loss)	$	(32,937	)	$	(1,518	)	$	(74,234	)	$	17,554
Gain (loss) on ineffective portion of derivatives qualifying for hedge accounting		15,542			1,061			1,143			(965	)
Gas derivatives
Reclassification adjustment for hedge gains (losses) included in net income (loss)		(5,188	)		1,600			(11,403	)		6,245
Gain (loss) on ineffective portion of derivatives qualifying for hedge accounting		20,268			—			(7,176	)		—

Total	$	(2,315	)	$	1,143		$	(91,670	)	$	22,834

Based upon market prices at September 30, 2009, and assuming no future change in the market, we expect to reclassify $4,904 of the balance in accumulated other comprehensive income to income during the next 12 months when the forecasted transactions actually occur. All forecasted transactions hedged as of September 30, 2009 are expected to be settled by December 2011.

The changes in fair value and settlement of derivative contracts that do not qualify or have not been designated as hedges are recognized as non-hedge derivative gains (losses). All non-hedge derivative contracts outstanding at September 30, 2009 are expected to be settled by December 2011. Non-hedge derivative gains (losses) in the consolidated statements of operations are comprised of the following:


	Three months ended September 30,						Nine months ended September 30,
	2008			2009			2008			2009
Change in fair value of non-qualified commodity price swaps	$	42,525		$	(7,210	)	$	(16,355	)	$	(75,963	)
Change in fair value of non-designated costless collars		37,682			(7,377	)		29,125			(43,546	)
Change in fair value of natural gas basis differential contracts		(1,627	)		(4,845	)		3,188			(15,081	)
Receipts from (payments on) settlement of non-qualified commodity price swaps		(3,021	)		7,791			(8,227	)		107,020
Receipts from settlement of non-designated costless collars		125			9,013			125			41,358
Receipts from (payments on) settlement of natural gas basis differential contracts		1,502			(2,372	)		2,149			(1,480	)

	$	77,186		$	(5,000	)	$	10,005		$	12,308

Derivative settlements receivable of $15,315 and $5,685 were included in accounts receivable at December 31, 2008 and September 30, 2009, respectively. Derivative settlements payable of $0 and $652 were included in accounts payable and accrued liabilities at December 31, 2008 and September 30, 2009, respectively.

We have no Level 1 assets or liabilities as of September 30, 2009. Our derivative contracts classified as Level 2 are valued using quotations provided by price index developers such as Platts and Oil Price Information Service. In certain less liquid markets, forward prices are not as readily available. In these circumstances, commodity swaps are valued using internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. These contracts are classified as Level 3. Due to unavailability of observable volatility data input, the fair value measurement of all our collars has been categorized as Level 3.

The fair value hierarchy for our financial assets and liabilities as of December 31, 2008 and September 30, 2009, accounted for at fair value on a recurring basis is shown by the following tables.


	As of December 31, 2008								As of September 30, 2009
	Derivative assets			Derivative liabilities			Net assets (liabilities)		Derivative assets			Derivative liabilities			Net assets (liabilities)
Significant other observable inputs (Level 2)	$	134,666		$	(8,525	)	$	126,141	$	30,412		$	(53,235	)	$	(22,823	)
Significant unobservable inputs (Level 3)		79,603			—			79,603		35,853			—			35,853
Netting adjustments (1)		(5,137	)		5,137			—		(27,265	)		27,265			—

	$	209,132		$	(3,388	)	$	205,744	$	39,000		$	(25,970	)	$	13,030

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

Changes in the fair value of net commodity derivatives classified as Level 3 in the fair value hierarchy at September 30, 2009, were:


Nine months ended September 30, 2009	Net derivative assets
Beginning balance	$	79,603
Total realized and unrealized gains included in non-hedge derivative gains (losses)		(2,102	)
Purchases, issuances, and settlements		(41,648	)

Ending balance	$	35,853

The amount of total gains for the period included in non-hedge derivative gains (losses) attributable to the change in unrealized gains relating to assets still held at the reporting date	$	1,289

Fair value of financial instruments

The carrying values of items comprising current assets and current liabilities, other than derivatives, approximate fair values due to the short-term maturities of these instruments. The carrying value for long-term debt at December 31, 2008, and September 30, 2009, approximates fair value because substantially all debt carries variable market rates. Based on market prices, at December 31, 2008, the fair value of the 8¹/2% Senior Notes and 8⁷/8% Senior Notes were $73,125 and $73,125, respectively. Based on market prices, at September 30, 2009, the fair value of the 8¹/2% Senior Notes and 8⁷/8% Senior Notes were $260,000 and $263,250, respectively.

Fair value amounts have been estimated using available market information. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

Note 4: Asset retirement obligations

The following table provides a summary of our asset retirement obligations for September 30, 2009.


	Nine months ended September 30, 2009
Beginning balance	$	33,375
Liabilities incurred in current period		306
Liabilities settled in current period		(104	)
Accretion expense		2,166

	$	35,743
Less current portion		300

	$	35,443

Note 5: Long-term debt

Long-term debt at December 31, 2008, and September 30, 2009, consisted of the following:


	December 31, 2008		September 30, 2009
Revolving credit line with banks	$	594,000	$	507,001
Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 3.71% to 9.256%, due January 2017 through December 2028; collateralized by real property		13,806		13,570
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 4.5% to 9.25%, due October 2009 through November 2013; collateralized by automobiles, machinery and equipment		13,140		9,288

		620,946		529,859
Less current maturities		5,301		4,476

	$	615,645	$	525,383

In October 2006, we entered into a Seventh Restated Credit Agreement, which is scheduled to mature on October 31, 2010, and is collateralized by our oil and gas properties. Availability under our credit agreement is subject to a borrowing base which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once every six months. As a result of our early settlement of derivatives in the second quarter of 2009, the borrowing base was reduced from $600,000 to $513,001 effective June 8, 2009. As part of the current redetermination process, we have requested that the lenders reaffirm the existing $513,001 borrowing base.

Interest was paid at least every three months during 2008 and 2009. The effective rate of interest on the entire outstanding balance was 5.299% and 6.081% as of December 31, 2008 and September 30, 2009, respectively, and was based upon LIBOR.

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

•

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

•

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

•

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

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

The Credit Agreement, as amended, also requires us to limit the aggregate amount of our capital expenditures incurred during the period beginning April 1, 2009 and ending December 31, 2009 to our discretionary cash flows for the period. Discretionary cash flows consist of Consolidated EBITDAX minus interest expense and taxes paid during the period, as defined in the Fifth Amendment to our Credit Agreement. As part of the current redetermination process, we have requested that the lenders amend this covenant to change the time period over which our aggregate capital expenditures are limited to the period beginning October 1, 2009 and ending June 30, 2010.

We believe we were in compliance with all covenants under the Credit Agreement as of September 30, 2009.

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

Our current Credit Agreement is scheduled to mature on October 31, 2010. Because we did not extend the maturity of our Credit Agreement before October 31, 2009, the entire balance then outstanding will be classified as a current liability for GAAP accounting purposes as of that date. Borrowings under our Credit Agreement are excluded from the Credit Agreement definition of current liabilities and therefore we do not expect the current classification of the borrowings to impact our current ratio as calculated for loan compliance. We are currently working with our lenders on a Proposed Replacement Credit Facility subject to the completion of our announced potential merger transaction with United Refining Energy Corp., (“United”). We have evaluated a number of potential public and private equity opportunities over the past year and chose United as the most beneficial to our shareholders.

The October 9, 2009 Agreement and Plan of Reorganization through which United, a publicly-held company, and Chaparral will merge in a reverse merger, is expected to close in December 2009. The Proposed Replacement Credit Facility now being negotiated is expected to have a maturity, terms, and other conditions that are standard in the oil and gas industry. If the transaction is consummated, we expect to receive approximately $250,000 in cash, which will be used to reduce the amount outstanding under our revolving senior secured credit facility, as well as for working capital and general corporate purposes.

We believe that we have more than sufficient collateral and assets to support the borrowing base for the Proposed Replacement Credit Facility or for a revised credit agreement outside of the merger transaction. If the transaction is not consummated, or our borrowing base amount is reduced by the banks, or if we expect to be unable to meet our required Current Ratio, or our required Consolidated Senior Total Debt to Consolidated EBITDAX ratio, we could reduce our debt amount by early settling additional derivative contracts, selling oil and gas assets, selling non-oil and gas assets or raising equity. We would continue to evaluate other opportunities from the capital markets as well as work with our lenders to enter into an Eighth Restated Credit Agreement, which we would expect to have an extended maturity, and terms and other conditions that are standard in the oil and gas industry. There is no assurance, however, that we will be able to sell our assets or equity at commercially reasonable terms or that any sales would generate enough cash to adequately reduce the borrowing base, or that we will be able to meet our future obligations to the banks.

Note 6: Related party transactions

In September 2006, Chesapeake Energy Corporation, now CHK Holdings, L.L.C., (“Chesapeake”) acquired a 31.9% beneficial interest in the Company through the sale of common stock. We participate in ownership of properties operated by Chesapeake and received revenues and incurred joint interest billings on these properties of: $2,055 and $854, respectively, for the three months ended September 30, 2008; $1,383 and $579 respectively, for the three months ended September 30, 2009; $6,523 and $2,184, respectively, for the nine months ended September 30, 2008; and $4,020 and $2,714 respectively, for the nine months ended September 30, 2009. In addition, Chesapeake participates in ownership of properties operated by us. We paid revenues and recorded joint interest billings to Chesapeake of: $1,238 and $713, respectively, during the three months ended September 30, 2008; $432 and $448, respectively, during the three months ended September 30, 2009; $2,351 and $2,188, respectively, during the nine months ended September 30, 2008, and $1,052 and $2,529, respectively, during the nine months ended September 30, 2009. Amounts receivable from and payable to Chesapeake were $1,914 and $1,188, respectively, as of December 31, 2008. Amounts receivable from and payable to Chesapeake were $1,250 and $311, respectively, as of September 30, 2009.

Note 7: Deferred compensation

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

Since the phantom stock is a liability award, fair value of the stock is remeasured at the end of each reporting period until settlement. As prescribed by the Plan, fair market value is calculated based on the Company’s total asset value less total liabilities, with both assets and liabilities being adjusted to fair value. The primary adjustment required is the adjustment of oil and gas properties from net book value to the discounted and risk adjusted reserve value based on internal reserve reports priced on NYMEX forward strips.

Compensation expense is recognized over the vesting period of the phantom stock and is reflected in lease operating and general and administrative expenses in the consolidated statements of operations. Such expense is calculated net of forfeitures estimated based on our historical and expected turnover rates. Due to a reduction in the fair value of the phantom stock from June 30, 2008 to September 30, 2008, we recognized a deferred compensation gain which increased net income for three months ended September 30, 2008. We recognized deferred compensation (gain) expense as follows:


	Three months ending						Nine months ending
	September 30, 2008			September 30, 2009			September 30, 2008			September 30, 2009
Deferred compensation (gain) cost	$	(2,033	)	$	295		$	1,532		$	1,235
Less: deferred compensation gain (cost) capitalized		671			(99	)		(501	)		(408	)

Deferred compensation (gain) expense	$	(1,362	)		196		$	1,031			827

A summary of our phantom unit activity as of December 31, 2008, and changes during the first nine months of 2009 are presented in the following table:


	Fair value		Phantom stock units		Weighted average remaining contract term	Aggregate intrinsic value
	(Per unit)
Unvested and total outstanding at December 31, 2008	$	10.22	219,658
Granted	$	11.91	40,294
Vested	$	10.08	(80,411	)
Forfeited	$	15.59	(4,037	)

Unvested and total outstanding at September 30, 2009	$	19.73	175,504		2.16	$	3,463

As of September 30, 2009, there was approximately $1,457 of total unrecognized compensation cost related to unvested phantom units that is expected to be recognized over a weighted-average period of 2.16 years. As of December 31, 2008 and September 30, 2009, accrued payroll and benefits payable included $789 and $1,105, respectively, for deferred compensation costs vesting within the next twelve months.

Note 8: Commitments and contingencies

Standby letters of credit (“Letters”) available under the revolving credit line are used in lieu of surety bonds with various city, state and federal agencies for liabilities relating to the operation of oil and gas properties. We had various Letters outstanding totaling $2,730 and $2,880 as of December 31, 2008, and September 30, 2009, respectively. Interest on each Letter accrues at the lender’s prime rate (effective rate of 5.299% at December 31, 2008, and 6.081% at September 30, 2009) for all amounts paid by the lenders under the Letters. We paid no interest on the Letters during the three and nine months ended September 30, 2008 and 2009.

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

Effective April 15, 2009, we settled our pending lawsuit against John Milton Graves Trust u/t/a 6/11/2004, et al. This case was filed in the District Court of Tulsa County, State of Oklahoma, and related to (i) a post-closing adjustment of the price we paid for Calumet Oil Company (“Calumet”) in 2006 (the “Working Capital Adjustment”) and (ii) a contractual payment related to an election to be made by the sellers of Calumet (collectively, the “Sellers”) under the federal tax code (the “Tax Election”). Pursuant to the settlement agreement, which was based upon net calculations of the receivable and payable, the Sellers paid us $7,100, which amount is intended to settle all claims related to both the Working Capital Adjustment and the Tax Election claims, and we retained $387 contained in an escrow account covering any losses incurred by us for title defects related to our purchase of Calumet. In addition, the parties issued mutual releases, dismissed with prejudice the pending litigation and the claims made therein, and the Sellers will take action to clear the title to certain properties purchased by us in the Calumet acquisition.

As of December 31, 2008, the recorded receivable for the Working Capital Adjustment was $14,406, and was included in other assets on the consolidated balance sheet. As of December 31, 2008, the recorded payable related to the Tax Election was $4,378, and was included in accounts payable and accrued liabilities on the consolidated balance sheet. As a result of the settlement, as of September 30, 2009, the receivable related to the Working Capital Adjustment and the Tax Election payable were eliminated, the escrow cash account was reclassified to operating cash, and we recorded a charge to expense of $2,928.

In February 2008, loss of well control occurred at the Bowdle 47 No. 2 well in Loving County, Texas. Total costs attributable to the loss of well control were approximately $10,648. Our insurance policy has covered 100% of these costs, with the $627 insurance retention and deductible being payable by us. As of September 30, 2009, we have received insurance proceeds of $10,021, and no further receipts are expected. Insurance proceeds received are recorded as a reduction of oil and gas properties on the balance sheet and in the statement of cash flows.

Note 9: Comprehensive income (loss)

Components of comprehensive income (loss), net of related tax, are as follows for the three and nine months ended September 30, 2008, and 2009:


	Three months ended September 30,					Nine months ended September 30,
	2008		2009			2008			2009
Net income (loss)	$	78,504	$	(4,386	)	$	45,485		$	(146,934	)
Unrealized gain (loss) on hedges		146,515		2,918			(67,164	)		(33,533	)
Reclassification adjustment for hedge (gains) losses included in net loss		23,369		(51	)		52,502			(14,594	)

Comprehensive income (loss)	$	248,388	$	(1,519	)	$	30,823		$	(195,061	)

Note 10: Subsequent events

On October 9, 2009 we signed an Agreement and Plan of Reorganization through which United, a publicly-held company, and Chaparral will merge in a reverse merger. The transaction is expected to close in December 2009.

Under the terms of the agreement, the stockholders of Chaparral will receive 63 million shares of United common stock, five million of which will be escrowed and subject to forfeiture if certain post-closing benchmarks are not achieved. The stockholders of Chaparral will receive up to an additional 15 million shares in the event certain post-closing benchmarks are achieved. Upon completion of the transaction, United will change its name to “Chaparral Energy, Inc.”

United is a special purpose acquisition company formed in 2007 for the purpose of acquiring through a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination one or more businesses or assets in the energy industry.

The consummation of the transaction is subject to approval of United’s stockholders, the approval by certain of United’s warrantholders of amendments to their warrant agreement, and other customary closing conditions. It is also a requirement that no more than 49.9% of the common stock issued in United’s initial public offering (the “Public shares”) be voted against the transaction and no more than 40% of the Public shares be voted in favor of conversion of such stock into a pro rata portion of the trust account held by United for the benefit of its public stockholders.

As of November 10, which is the date these financial statements were issued, there are no additional material subsequent events requiring additional disclosure in or amendment to these financial statements.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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

Overview

We are an independent oil and gas company engaged in the production, acquisition, and exploitation of oil and gas properties. Our areas of operation include the Mid-Continent, Permian Basin, Gulf Coast, Ark-La-Tex, North Texas, and the Rocky Mountains. We maintain a portfolio of proved and unproved reserves, development and exploratory drilling opportunities, and EOR projects.

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and 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 (“GAAP”) requires us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved oil and gas reserves. We use the full cost method of accounting for our oil and gas activities.

As of June 30, 2009, we had estimated proved reserves of 145.6 MMBoe with a PV-10 value of approximately $1.5 billion, of which 66% were proved developed reserves and 62% were crude oil. Despite the decline in gas price from $5.62 per Mcf as of December 31, 2008 to $3.89 per Mcf as of June 30, 2009, our estimated proved reserves have increased significantly since December 31, 2008 due in part to an increase in oil price from $44.60 per Bbl as of December 31, 2008 to $69.89 per Bbl at June 30, 2009. As of December 31, 2008, we had estimated proved reserves of 113.3 MMBoe with a PV-10 value of $932.7 million, of which 74% were proved developed reserves and 45% were crude oil.

Our reserve estimate as of December 31, 2009 will be prepared using an average price for oil and gas based upon the first day of each month for the prior twelve months as required by SEC Release No. 33-8995, Modernization of Oil and Gas Reporting. Because of the low oil prices prevalent through the first half of 2009, we expect this average price for oil to be lower than the price used in our reserve calculation as of June 30, 2009, which could cause both our reserve volumes and our PV-10 value as of December 31, 2009 to be lower than they were as of June 30, 2009.

Generally our producing properties have declining production rates. Our reserve estimates as of June 30, 2009, reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 16.7%, 12.7%, and 10.1% for the next three years. To grow our production and cash flow we must find, develop, and acquire new oil and gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop, and acquire oil and gas reserves.

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

•

cash flow available for capital expenditures;

•

ability to borrow and raise additional capital;

•

ability to service debt;

•

quantity of oil and gas we can produce;

•

quantity of oil and gas reserves; and

•

operating results for oil and gas activities.

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

•

the amount of estimated future net revenues from oil and gas sales;

•

the quantity of our proved oil and gas reserves;

•

the timing and amount 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.

During the third quarter of 2009, quarterly production was 1,946 MBoe, an 11.2% increase over production levels in the third quarter of 2008, primarily due to our capital expenditures in the Permian and Mid Continent areas during 2008. However, a 53.0% decline in our average sales price before derivative settlements resulted in a 47.7% decrease in revenue from oil and gas sales in the third quarter of 2009 compared to the same period in 2008. Although total operating costs and expenses decreased by 22.8% in the third quarter of 2009 compared to the same period in 2008, the decrease was not commensurate with the decrease in revenue. In addition, due primarily to changes in the NYMEX forward commodity price curves, we had a $5.0 million loss on non-hedge derivatives in the third quarter of 2009 compared to a gain of $77.2 million in the third quarter of 2008. Primarily as a result of these factors, we had a net loss of $4.4 million during the third quarter of 2009 compared to net income of $78.5 million during the third quarter of 2008.

Lease operating expenses, production taxes, and depreciation, depletion, and amortization decreased on both an absolute and per Boe basis during the third quarter of 2009 compared to the same period in 2008 due to a reduction in activity and lower overall industry costs. Oil prices have recently started to improve, and if this upward trend continues, we expect operating costs to increase as well.

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 and debt. Due to the recent turmoil in the market and the sharp decline in oil and gas prices which began during the fourth quarter of 2008, we plan to keep our capital expenditures, other than acquisitions, within our discretionary cash flow for the period from April 1, 2009 to December 31, 2009.

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

•

Current market conditions. The credit markets are undergoing significant volatility. Many financial institutions have liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our exposure to the current credit market crisis includes our revolving credit facility, counterparty risks related to our trade credit and derivative instruments, and risks related to our cash investments.

Our cash accounts and deposits with any financial institution that exceed the amount insured by the Federal Deposit Insurance Corporation are at risk in the event one of these financial institutions should fail. As of September 30, 2009, cash with a recorded balance totaling $82.5 million was held at JP Morgan Chase Bank, N.A.

We sell our crude oil, natural gas and natural gas liquids to a variety of purchasers. Some of these parties may experience liquidity problems. Nonperformance by a trade creditor could result in losses. We also have significant net derivative assets that are held by affiliates of our lenders. As of September 30, 2009, net derivative assets totaling $32.6 million were held by JP Morgan Chase Bank, N.A., Calyon Credit Agricole CIB, The Royal Bank of Scotland plc, and Bank of Oklahoma.

Our oil and gas sales revenues are derived from the sale of oil, gas and natural gas liquids. We recognize revenues when our production is sold and title is transferred. Our revenues are highly dependent upon the prices of, and the demand for, oil and gas. Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and gas and our levels of production are subject to wide fluctuations and depend on numerous factors beyond our control, including supply and demand, economic conditions, foreign imports, the actions of OPEC, political conditions in other oil producing countries, and governmental regulation, legislation and policies.

Oil and gas prices declined significantly during the third quarter of 2009 compared to the third quarter of 2008, which will reduce our cash flows from operations in future periods in which prices remain at or below the current levels. The commodity price swaps and costless collars that cover approximately 78% of our expected PDP oil production through December 2011 and approximately 74% of our expected PDP gas production through December 2011 will, however, become more valuable if prices decline.

•

Credit Agreement. Our current Credit Agreement is a revolving credit facility in the amount of $513.0 million. At September 30, 2009, we had $507.0 million outstanding under the Credit Agreement and $2.9 million was utilized by outstanding letters of credit. The borrowing base is presently being redetermined. If the outstanding borrowings under the Credit Agreement were to exceed the borrowing base as a result of the redetermination, we would be required to eliminate this excess.

The Credit Agreement is scheduled to mature on October 31, 2010. Should current credit market volatility be prolonged, future extensions of our Credit Agreement may contain terms that are less favorable than those of our current Credit Agreement.

Because we did not extend the maturity of our Credit Agreement before October 31, 2009, the entire balance then outstanding will be classified as a current liability for GAAP accounting purposes as of that date. Borrowings under our Credit Agreement are excluded from the Credit Agreement definition of current liabilities and therefore we do not expect the current classification of the borrowings to impact our current ratio as calculated for loan compliance. We are currently working with our lenders on a Proposed Replacement Credit Facility subject to the completion of our announced potential merger transaction with United Refining Energy Corp., (“United”). We have evaluated a number of potential public and private equity opportunities over the past year and chose United as the most beneficial to our shareholders.

The October 9, 2009 Agreement and Plan of Reorganization through which United, a publicly-held company, and Chaparral will merge in a reverse merger, is expected to close in December 2009. The Proposed Replacement Credit Facility now being negotiated is expected to have a maturity, terms, and other conditions that are standard in the oil and gas industry. If the transaction is consummated, we expect to receive approximately $250.0 million in cash, which will be used to reduce the amount outstanding under our revolving senior secured credit facility, as well as for working capital and general corporate purposes.

Covenants set forth in the indentures for our 8¹/2% Senior Notes and the 8⁷/8% Senior Notes, including the Adjusted Consolidated Net Tangible Asset debt incurrence test (the “ACNTA test”), limit the amount of secured debt we can incur. Certain thresholds set forth in the ACNTA test are principally reliant upon the levels of commodity prices for oil and gas at specified dates. Based on the commodity prices for oil and gas at December 31, 2008, we will be unable to borrow additional amounts under our Credit Agreement during 2009, regardless of the availability under our Credit Agreement, unless our secured debt is reduced below approximately $320.0 million.

Our reserve estimate as of December 31, 2009 will be prepared using an average price for oil and gas based upon the first day of each month for the prior twelve months as required by SEC Release No. 33-8995, Modernization of Oil and Gas Reporting. Because oil prices have increased since December 31, 2008, we expect this average price for oil to be higher than the price used in our reserve calculation as of December 31, 2008. This could cause our PV-10 value to increase by approximately 30% as of December 31, 2009 compared to December 31, 2008, and provide greater borrowing flexibility under our ACNTA test for 2010.

•

Agreement and Plan of Reorganization. On October 9, 2009 we signed an Agreement and Plan of Reorganization through which United, a publicly held company, and Chaparral will merge in a reverse merger. The transaction is expected to close in December 2009.

•

Impairment of oil and gas properties. In accordance with the full cost method of accounting, the net capitalized costs of oil and gas properties are not to exceed their related estimated future net revenues discounted at 10% (“PV-10 value”), as adjusted for our cash flow hedge positions and net of tax considerations, plus the lower of cost or estimated fair value of unproved properties. During the first quarter of 2009, gas prices declined significantly as compared to the December 31, 2008 spot price of $5.62 per Mcf. Based on March 31, 2009 spot prices of $49.66 per Bbl of oil and $3.63 per Mcf of gas, the internally estimated PV-10 value of our reserves declined by 13.5% compared to the PV-10 value at December 31, 2008. As a result, we recorded a ceiling test impairment of oil and gas properties of $240.8 million during the first quarter of 2009. The effect of derivative contracts accounted for as cash flow hedges, based on the March 31, 2009 spot prices, increased the full cost ceiling by $169.0 million, thereby reducing the ceiling test write down by the same amount.

As of September 30, 2009, the cost center ceiling exceeded the net capitalized cost of our oil and gas properties, and no ceiling test impairment was recorded during the third quarter of 2009. The internally estimated PV-10 value of our reserves was estimated based on spot prices of $70.21 per Bbl of oil and $3.24 per Mcf of gas at September 30, 2009. The effect of derivative contracts accounted for as cash flow hedges, based on these September 30, 2009 spot prices, reduced the full cost ceiling by $10.7 million. The qualifying cash flow hedges as of September 30, 2009, which consisted of commodity price swaps, covered 3,954 MBbls of oil production for the period from October 2009 through December 2011.

A decline in oil and gas prices subsequent to September 30, 2009 could result in additional ceiling test write downs in future periods. In addition, our reserve estimate as of December 31, 2009 will be prepared using an average price for oil and gas based upon the first day of each month for the prior twelve months as required by SEC Release No. 33-8995, Modernization of Oil and Gas Reporting. Because of the low oil prices prevalent through the first half of 2009, we expect this average price for oil to be lower than the price used in our reserve calculation as of September 30, 2009, which could cause both our reserve volumes and our PV-10 value as of December 31, 2009 to be lower than they were as of September 30, 2009. The amount of any future impairment is difficult to predict, and will depend on the oil and gas prices at the end of or during each period, the incremental proved reserves added during each period, and additional capital spent.

•

Production tax credit. During 2006, we purchased interests in two venture capital limited liability companies resulting in a total investment of $15.0 million. Our return on the investment was the receipt of $2 of Oklahoma tax credits for every $1 invested and was recouped from our Oklahoma production taxes. The investments are accounted for as a production tax benefit asset and are netted against tax credits realized in other income using the effective yield method over the expected recovery period. As of September 30, 2009, we had received $30.0 million of proceeds from the Oklahoma tax credits.

During the three and nine months ended September 30, 2009, we received cash of $0 and $27.2 million, respectively, from application of these tax credits. This source of cash received will not be available in future periods.

•

Discontinued Operations – During the second quarter of 2009, we committed to a plan to sell the assets of Green Country Supply, Inc. (“GCS”), a wholly owned subsidiary that provides oilfield supplies, oilfield chemicals, downhole electric submersible pumps, and related services to oil and gas operators primarily in Oklahoma, Texas, and Wyoming.

On May 14, 2009, we entered into an agreement to sell the assets of the ESP Division of GCS to Global Oilfield Services, Inc. (“Global”) for a cash price of $26.0 million, subject to working capital adjustments as provided in the agreement. On June 8, 2009, we received $24.7 million in conjunction with the closing of the ESP Division sale to Global. The amount received reflected a reduction of $1.3 million due to working capital changes as of March 31, 2009. We paid off notes payable attributed to certain assets sold to Global in the amount of $1.6 million. The purchase price is subject to a final working capital adjustment, which is expected to be settled before December 31, 2009. For the nine months ended September 30, 2009, we recorded a pre-tax gain associated with the sale of $9.0 million. All taxable income associated with such gain was offset by existing net operating losses.

•

Monetization of derivative assets. During the first quarter of 2009, we monetized certain derivative instruments with original settlement dates from May through October of 2009. Net proceeds received from this monetization were $9.5 million. None of the monetized derivatives were incorporated into the determination of the borrowing base under our Credit Agreement. During the second quarter of 2009, we monetized additional derivative instruments with original settlement dates from January 2012 through December 2013 for proceeds of $102.4 million. As a result of this monetization, effective June 8, 2009, the borrowing base was reduced from $600.0 million to $513.0 million, resulting in a payment to the banks of $87.0 million. The remaining proceeds of $15.4 million increased our cash balance. As of September 30, 2009, we have a net derivative asset of $13.0 million.

•

Capital expenditure budget. We have expanded our oil and gas property capital expenditure budget for 2009 reflecting an increased amount of cash available primarily from higher oil prices, the receipt of proceeds from derivative monetizations, the sale of the ESP Division of GCS, and production tax credits. Our capital expenditures for oil and gas properties were $40.3 million, $23.9 million, and $33.8 million, respectively, during the first, second, and third quarters of 2009. We incurred significant costs during the first quarter of 2009 as we completed projects begun during the fourth quarter of 2008. Our projected capital expenditures, other than acquisitions, for the rest of 2009 are between $21.0 million and $31.0 million, which, combined with our actual capital expenditures for the second and third quarters of 2009, are within our projected discretionary cash flows for the period beginning April 1, 2009 and ending December 31, 2009, as required by our Credit Agreement. Discretionary cash flows consist of Consolidated EBITDAX minus interest expense and taxes paid during the period, as defined in the Fifth Amendment to our Credit Agreement. As part of the current redetermination process, we have requested that the lenders amend this covenant to change the time period over which our aggregate capital expenditures are limited to the period beginning October 1, 2009 and ending June 30, 2010, and if the change is approved, we expect to remain in compliance with the covenant as of December 31, 2009.

The expanded 2009 capital budget represents a reduction in capital expenditures of approximately 60% from our 2008 levels. Despite this reduction, we expect production for 2009 to be approximately 7,400 to 7,600 MBoe as a result of capital investments made in 2008 and the first quarter of 2009. We plan to drill or participate in several high impact wells in the fourth quarter of 2009, which, if successful, could maintain our production levels throughout 2010. However, we cannot accurately predict the timing or level of future production.

•

Insurance proceeds. In February 2008, loss of well control occurred at the Bowdle 47 No. 2 well in Loving County, Texas. Total costs attributable to the loss of well control were approximately $10.6 million. Our insurance policy has covered 100% of these costs, with the $0.6 million insurance retention and deductible being payable by us. As of September 30, 2009, we have received insurance proceeds of $10.0 million, and no further receipts are expected. Insurance proceeds received are recorded as a reduction of oil and gas properties on the balance sheet and in the statement of cash flows.

Liquidity and capital resources

Crude oil and natural gas prices have fallen significantly from their peak levels during the second and third quarters of 2008. Lower oil and gas prices decrease our revenues. An extended decline in oil or gas prices may materially and adversely affect our future business, liquidity or ability to finance planned capital expenditures. Lower oil and gas prices may also reduce the amount of our borrowing base under our Credit Agreement, which is determined at the discretion of the lenders based on the collateral value of our proved reserves that have been mortgaged to the lenders.

Historically, our primary sources of liquidity have been cash generated from our operations and debt. At September 30, 2009, we had approximately $85.2 million of cash and cash equivalents and $3.1 million of availability under our revolving credit line with a borrowing base of $513.0 million.

Covenants set forth in the indentures for our 8¹/2% Senior Notes and the 8⁷/8% Senior Notes, including the ACNTA test, limit the amount of secured debt we can incur. Certain thresholds set forth in the ACNTA test are principally reliant upon the levels of commodity prices for oil and gas at specified dates. Based on the commodity prices for oil and gas at December 31, 2008, we will be unable to borrow additional amounts under our Credit Agreement during 2009, regardless of the availability under our revolver, unless our secured debt is reduced below approximately $320.0 million.

Our reserve estimate as of December 31, 2009 will be prepared using an average price for oil and gas based upon the first day of each month for the prior twelve months as required by SEC Release No. 33-8995, Modernization of Oil and Gas Reporting. Because oil prices have increased since December 31, 2008, we expect this average price for oil to be higher than the price used in our reserve calculation as of December 31, 2008. This could cause our PV-10 value to increase by approximately 30% as of December 31, 2009 compared to December 31, 2008, and provide greater borrowing flexibility under our ACNTA test for 2010.

We believe that we will have sufficient funds available through our cash from operations to meet our normal recurring operating needs, debt service obligations, capital requirements and contingencies for the next 12 months. We may adjust our planned capital expenditures depending on the timing and amount of any equity funding received and the availability of acquisition opportunities that meet our investment criteria.

We generally have had a working capital deficit as our capital expenditures have historically exceeded our cash flow, and we rely on our borrowing base for additional capital. Because of the ACNTA test limitation under our indentures, and its impact on our ability to utilize our revolving credit in 2009, we drew down substantially all our remaining availability under our Credit Agreement prior to December 31, 2008. During the fourth quarter of 2008, we also monetized certain derivative instruments with original settlement dates from January through June of 2009, which generated net proceeds of $32.6 million. During the first quarter of 2009, we monetized certain derivative instruments with original settlement dates from May through October of 2009, which generated net proceeds of $9.5 million. During the second quarter of 2009, we monetized additional derivative instruments with original settlement dates from January 2012 through December 2013 for proceeds of $102.4 million. As a result of this monetization, effective June 8, 2009, the borrowing base was reduced from $600.0 million to $513.0 million, resulting in a payment to the banks of $87.0 million. The remaining proceeds of $15.4 million increased our cash balance. We have changed our cash management activities to target a minimum balance of cash on hand, which we maintain in highly liquid investments.

We pledge our producing oil and gas properties to secure our Credit Agreement. The banks establish a borrowing base by making an estimate of the collateral value of our oil and gas properties. We utilize the available funds as needed to supplement our operating cash flows as a financing source for our capital expenditures. Our ability to fund our capital expenditures is dependent on the level of product prices and the success of our acquisition and development program in adding to our available borrowing base. If oil and gas prices decrease from the amounts used in estimating the collateral value of our oil and gas properties, the borrowing base may be reduced, thus reducing funds available for our capital expenditures. We mitigate a potential reduction in our borrowing base caused by a decrease in oil and gas prices through the use of commodity derivatives.

Sources and uses of cash. The net increase (decrease) in cash is summarized as follows:


	Nine months ended September 30,
(dollars in thousands)	2008			2009
Cash flows provided by operating activities	$	146,093		$	91,445
Cash flows provided by (used in) investing activities		(246,664	)		37,268
Cash flows provided by (used in) financing activities		96,424			(95,583	)

Net increase (decrease) in cash during the period	$	(4,147	)	$	33,130

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, 2009, net cash provided from operations decreased 37.4% from the same period in the prior year primarily due to the decrease in revenue from oil and gas sales.

We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. Cash flows provided by investing activities for the nine months ended September 30, 2009 included proceeds of $111.9 million from the monetization of derivatives and proceeds of $24.7 million from the sale of the ESP Division of GCS. A portion of the proceeds was used to pay down borrowings under our Credit Agreement.

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


(dollars in thousands)	Nine months ended September 30, 2009		Percent of total
Development activities:
Developmental drilling	$	48,560	49.6	%
Enhancements		29,257	29.9	%
Tertiary recovery		11,401	11.6	%
Acquisitions:
Proved properties		743	0.8	%
Unproved properties		3,070	3.1	%
Exploration activities		4,937	5.0	%

Total	$	97,968	100.0	%

In addition to the capital expenditures for oil and gas properties, we spent approximately $1.8 million for the acquisition and construction of new office and administrative facilities and equipment during the first nine months of 2009.

As of September 30, 2009, we had cash and cash equivalents of $85.2 million and long-term debt obligations of $1.2 billion.

Our Credit Agreement. In October 2006, we entered into a Seventh Restated Credit Agreement, which is scheduled to mature on October 31, 2010, and is collateralized by our oil and gas properties. Availability under our Credit Agreement is subject to a borrowing base which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once every six months.

As a result of our derivative monetization in the second quarter of 2009, the borrowing base was reduced from $600.0 million to $513.0 million effective June 8, 2009. As part of the current redetermination process, we have requested that the lenders reaffirm the existing $513.0 million borrowing base.

We had $507.0 million outstanding under our Credit Agreement at September 30, 2009.

The agreement has certain negative and affirmative covenants that require, among other things, maintaining a specified current ratio and debt service ratio. We believe we were in compliance with all covenants under the Credit Agreement as of September 30, 2009.

Borrowings under our Credit Agreement are made, at our option, as either Eurodollar loans or Alternate Base Rate (“ABR”) loans. At September 30, 2009, all of our borrowings were Eurodollar loans.

Interest on Eurodollar loans is computed at the Adjusted LIBO Rate, defined as the greater of 2% or the rate applicable to dollar deposits in the London interbank market with a maturity comparable to the interest period (one, two, three or six months, selected by us) times a Statutory Reserve Rate multiplier, as defined in the Credit Agreement, plus a margin where the margin varies from 2.500% to 4.250% depending on the utilization percentage of the conforming borrowing base. At September 30, 2009, the Adjusted LIBO rate, as defined, was 2.000%, the Statutory Reserve Rate multiplier was 100%, and the applicable margin and commitment fee together were 4.081% resulting in an effective interest rate of 6.081% 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 ABR loans is computed as the greater of (1) the Prime Rate, as defined in our Credit Agreement, (2) the Federal Funds Effective Rate, as defined in our Credit Agreement, plus 1/2 of 1%, or (3) the Adjusted LIBO Rate, as defined in our Credit Agreement, plus 1%; plus a margin where the margin varies from 1.625% to 3.375%, depending on the utilization percentage of the borrowing base.

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

Interest was paid at least every three months during 2008 and 2009. The effective rate of interest on the entire outstanding balance was 5.299% and 6.081% as of December 31, 2008, and September 30, 2009, respectively, and was based upon LIBOR.

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;

•

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.

Our Credit Agreement requires us to maintain a current ratio, as defined in our Credit Agreement, of not less than 1.0 to 1.0. The definition of current assets and current liabilities used for determination of the current ratio computed for loan compliance purposes differs from current assets and current liabilities determined in compliance with GAAP. Since compliance with financial covenants is a material requirement under our Credit Agreement, we consider the current ratio calculated under our Credit Agreement to be a useful measure of our liquidity because it includes the funds available to us under our Credit Agreement and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. At December 31, 2008 and September 30, 2009, our current ratio as computed using GAAP was 1.34 and 1.63, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 1.19 and 1.61, respectively. The following table reconciles our current assets and current liabilities using GAAP to the same items for purposes of calculating the current ratio for our loan compliance:


(dollars in thousands)	December 31, 2008			September 30, 2009
Current assets per GAAP	$	218,363		$	176,435
Plus—Availability under credit agreement		3,270			3,120
Less—Short-term derivative instruments		(51,412	)		(27,709	)

Current assets as adjusted	$	170,221		$	151,846

Current liabilities per GAAP	$	163,123		$	108,410
Less—Deferred tax liability on derivative instruments and asset retirement obligations		(19,755	)		(8,521	)
Less—Short-term asset retirement obligations		(300	)		(300	)
Less—Short-term derivative instruments		—			(5,340	)

Current liabilities as adjusted	$	143,068		$	94,249

Current ratio for loan compliance		1.19			1.61

The monetization of derivatives in December 2008 and the first and second quarters of 2009 allowed us to exceed our required current ratio by a higher margin.

The October 9, 2009 Agreement and Plan of Reorganization through which United, a publicly-held company, and Chaparral will merge in a reverse merger, is expected to close in December 2009. The Proposed Replacement Credit Facility now being negotiated is expected to have a maturity, terms, and other conditions that are standard in the oil and gas industry. If the transaction is consummated, we expect to receive approximately $250.0 million in cash, which will be used to reduce the amount outstanding under our revolving senior secured credit facility, as well as for working capital and general corporate purposes.

The Credit Agreement, as amended effective May 21, 2009, requires us to maintain a Consolidated Senior Total Debt to Consolidated EBITDAX ratio, as defined in our Credit Agreement, of not greater than:

•

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

•

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

•

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

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 $5.0 million that remains undischarged for a period of 60 consecutive days;

•

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.

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.

Alternative capital resources. We have historically used cash flow from operations, debt financing, and derivative monetizations 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.

Results of operations

Comparison of three and nine months ended September 30, 2009 to three and nine months ended September 30, 2008.

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


	Three months ended September 30,				change		Nine months ended September 30,				change
	2008		2009		change		2008		2009		change
Oil and gas sales (dollars in thousands)
Oil	$	106,816	$	59,539	(44.3	)%	$	297,143	$	145,435	(51.1	)%
Gas		41,853		18,214	(56.5	)%		130,222		55,249	(57.6	)%

Total	$	148,669	$	77,753	(47.7	)%	$	427,365	$	200,684	(53.0	)%
Production
Oil (MBbls)		962		984	2.3	%		2,785		2,888	3.7	%
Gas (MMcf)		4,730		5,773	22.1	%		14,583		17,460	19.7	%
MBoe		1,750		1,946	11.2	%		5,216		5,798	11.2	%
Average sales prices (excluding derivative settlements)
Oil per Bbl	$	111.04	$	60.51	(45.5	)%	$	106.69	$	50.36	(52.8	)%
Gas per Mcf		8.85		3.16	(64.3	)%		8.93		3.16	(64.6	)%
Boe		84.95		39.96	(53.0	)%		81.93		34.61	(57.8	)%

Oil and gas revenues decreased by 47.7% and 53.0%, respectively, during the three and nine months ended September 30, 2009, due to a decrease in average price per Boe. Oil and gas prices declined significantly during the three and nine months ended September 30, 2009 as compared to the same periods of 2008. Because of this decline in oil and gas prices, our revenues in 2009 are expected to be significantly lower than the amounts reported in 2008.

Oil sales decreased 44.3% from $106.8 million during the third quarter of 2008 to $59.5 million during the same period in 2009. This decrease was due to a 45.5% decrease in average oil prices from $111.04 to $60.51 per Bbl, partially offset by a 2.3% increase in production volumes to 984 MBbls. Gas sales decreased 56.5% from $41.9 million during the third quarter of 2008 to $18.2 million during the same period in 2009. This decrease was due to a 64.3% decrease in average gas prices, partially offset by a 22.1% increase in gas production volumes to 5,773 MMcf.

Oil sales decreased 51.1% from $297.1 million during the nine months ended September 30, 2008 to $145.4 million during the same period in 2009. This decrease was due to a 52.8% decrease in average oil prices from $106.69 to $50.36 per Bbl, partially offset by a 3.7% increase in production volumes to 2,888 MBbls. Gas sales decreased 57.6% from $130.2 million during the nine months ended September 30, 2008 to $55.2 million during the same period in 2009. This decrease was due to a 64.6% decrease in average gas prices, partially offset by a 19.7% increase in gas production volumes to 17,460 MMcf.

Production volumes by area were as follows (MBoe):


	Three months ended September 30,		Percentage change		Nine months ended September 30,		Percentage change
	2008	2009	Percentage change		2008	2009	Percentage change
Mid Continent	1,202	1,301	8.2	%	3,506	3,765	7.4	%
Permian	266	386	45.1	%	812	1,264	55.7	%
Gulf Coast	134	113	(15.7	)%	423	347	(18.0	)%
Ark-La-Tex	70	68	(2.9	)%	220	196	(10.9	)%
North Texas	40	41	2.5	%	137	124	(9.5	)%
Rocky Mountains	38	37	(2.6	)%	118	102	(13.6	)%

Totals	1,750	1,946	11.2	%	5,216	5,798	11.2	%

Oil and gas production for the three and nine months ended September 30, 2009 increased primarily due to our drilling program and enhancements of our existing properties, much of which was accomplished in 2008 and the first quarter of 2009. We have focused our capital expenditures on the Mid Continent and Permian areas. As a result, production in our growth areas has declined and is expected to continue to decline, since our planned capital expenditures for the remainder of 2009 are also focused in our core areas of the Mid Continent and Permian Basin.

The increase in production in the Permian area is primarily due to the Bowdle 47 No. 2, which began selling gas in late November 2008 and accounted for approximately 9% of total production for the three and nine months ended September 30, 2009. We expect production from this well to decline during the fourth quarter of 2009. Production from the Bowdle 47 No. 2 for the fourth quarter of 2009 is expected to be approximately 78% of its production for the third quarter of 2009, and its production in 2010 is expected to be approximately 48% of its total production in 2009. We are currently drilling an offset, the Bowdle 47 No. 4, which is expected to come online in the first quarter of 2010. If successful, this well combined with several other high impact wells we are drilling or participating in during the fourth quarter of 2009, could maintain our production levels throughout 2010. However, we cannot accurately predict the timing or the level of future production.

Our 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 commodity price swaps, costless collars, and basis protection swaps. Certain commodity price swaps qualified and were designated as cash flow hedges.

In addition, during the fourth quarter of 2008, we monetized oil and gas swaps and collars with original settlement dates from January through June of 2009 for proceeds of $32.6 million. During the first quarter of 2009, we monetized additional gas swaps with original settlement dates from May through October of 2009 for proceeds of $9.5 million. During the second quarter of 2009, we monetized additional oil swaps and collars with original settlement dates from January 2012 through December 2013 for proceeds of $102.4 million. Certain swaps that were monetized had previously been accounted for as cash flow hedges. As of December 31, 2008 and September 30, 2009, accumulated other comprehensive income included $23.7 million and $84.8 million, respectively, of deferred gains related to discontinued cash flow hedges that will be recognized as a gain from oil and gas hedging activities when the hedged production is sold. No oil and gas derivatives were monetized during the first nine months of 2008.

The effects of hedging on our net revenues for the three and nine months ended September 30, 2008 and 2009 are as follows:


	Three months ended September 30,						Nine months ended September 30,
(dollars in thousands)	2008			2009			2008			2009
Gain (loss) from oil and gas hedging activities:
Receipts from (payments on) hedge settlements	$	(36,978	)	$	(458	)	$	(98,235	)	$	2,474
Hedge ineffectiveness and reclassification adjustments		34,663			1,601			6,565			20,360

Total	$	(2,315	)	$	1,143		$	(91,670	)	$	22,834

Primarily as a result of substantially lower oil prices in 2009 than in 2008, payments on hedge settlements were $0.5 million during the third quarter of 2009 compared to $37.0 million during the third quarter of 2008, and receipts from hedge settlements were $2.5 million during the first nine months of 2009 compared to payments on hedge settlements of $98.2 million during the first nine months of 2008. Gains of $1.6 million and $20.8 million associated with derivatives for which hedge accounting had previously been discontinued were reclassified into earnings during the three and nine months ended September 30, 2009, respectively, as the hedged production was sold. As a result of these transactions, as well as the discontinuance of hedge accounting for all gas swaps discussed above, our gain from oil and gas hedging activities was $1.1 million and $22.8 million during the three and nine months ended September 30, 2009 compared to a loss of $2.3 million and $91.7 million for the comparable periods in 2008.

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


	Three months ended September 30,						Nine months ended September 30,
	2008			2009			2008			2009
Oil (per Bbl):
Before derivative settlements	$	111.04		$	60.51		$	106.69		$	50.36
After derivative settlements	$	78.17		$	62.43		$	75.24		$	53.42
Post-settlement to pre-settlement price		70.4	%		103.2	%		70.5	%		106.1	%
Gas (per Mcf):
Before derivative settlements	$	8.85		$	3.16		$	8.93		$	3.16
After derivative settlements	$	7.42		$	5.25		$	7.79		$	4.81
Post-settlement to pre-settlement price		83.8	%		166.1	%		87.2	%		152.2	%

Costs and expenses. The following table presents information about our operating expenses for the three and nine months ended September 30, 2008 and 2009:


	Three months ended September 30,				Percent change		Nine months ended September 30,				Percent change
	2008		2009		Percent change		2008		2009		Percent change
Costs and expenses (dollars in thousands)
Lease operating expenses	$	32,290	$	21,980	(31.9	)%	$	86,202	$	72,945	(15.4	)%
Production taxes		9,822		5,367	(45.4	)%		28,338		14,168	(50.0	)%
Depreciation, depletion and amortization		25,129		24,700	(1.7	)%		73,774		80,100	8.6	%
General and administrative		4,879		5,854	20.0	%		18,960		18,128	(4.4	)%
Costs and expenses (per Boe)
Lease operating expenses	$	18.45	$	11.29	(38.8	)%	$	16.53	$	12.58	(23.9	)%
Production taxes		5.61		2.76	(50.8	)%		5.43		2.44	(55.1	)%
Depreciation, depletion and amortization		14.36		12.69	(11.6	)%		14.14		13.82	(2.3	)%
General and administrative		2.79		3.01	7.9	%		3.63		3.13	(13.8	)%

Lease operating expenses – Due to higher production mostly associated with the Bowdle 47 No. 2 well and our efforts to reduce production costs, lease operating expenses per Boe for the three and nine months ended September 30, 2009 declined $7.16 to $11.29 and $3.95 to $12.58, respectively, compared to the same periods in 2008. During the three and nine months ended September 30, 2009, electricity and fuel costs decreased by $1.6 million and $3.1 million, respectively, and workovers and other field service costs decreased by $8.7 million and $10.2 million, respectively, compared to the same periods in 2008. Oil prices have recently started to improve, and if this upward trend continues, we expect absolute and per Boe operating costs to increase as well.

Production taxes (which include ad valorem taxes) – The decrease for the third quarter of 2009 was primarily due to 53.0% lower average prices, partially offset by an 11.2% increase in production volumes. The decrease for the first nine months of 2009 was primarily due to 57.8% lower average prices, partially offset by an 11.2% increase in production volumes.

Depreciation, depletion and amortization (“DD&A”) – The decrease for the third quarter of 2009 was primarily due to a $0.7 million decrease in DD&A on oil and gas properties. Our DD&A rate on oil and gas properties per equivalent unit of production decreased $1.68 to $11.22 per Boe primarily due to the decrease in capitalized costs resulting from our ceiling test impairments recorded in the fourth quarter of 2008 and the first quarter of 2009, combined with lower estimated future development costs. This decrease in the DD&A rate per equivalent unit of production reduced DD&A for oil and gas properties by $2.9 million, which was offset by increased DD&A of $2.2 million due to higher production volumes.

The increase for the first nine months of 2009 was primarily due to an increase in DD&A on oil and gas properties of $4.2 million. Higher production volumes increased DD&A on oil and gas properties by $7.2 million, which was offset by a $3.0 million reduction in DD&A due to a lower rate per equivalent unit of production. Our DD&A rate on oil and gas properties per equivalent unit of production decreased $0.57 to $12.34 per Boe primarily due to the decrease in capitalized costs resulting from our ceiling test impairments recorded in the fourth quarter of 2008 and the first quarter of 2009, combined with lower estimated future development costs.

Impairment of oil and gas properties — In accordance with the full cost method of accounting, the net capitalized costs of oil and gas properties are not to exceed their related estimated future net revenues discounted at 10%, as adjusted for our cash flow hedge positions and net of tax considerations, plus the lower of cost or estimated fair value of unproved properties. During the first quarter of 2009, gas prices declined significantly as compared to the December 31, 2008 spot price of $5.62 per Mcf. Based on March 31, 2009 spot prices of $49.66 per Bbl of oil and $3.63 per Mcf of gas, the internally estimated PV-10 value of our reserves declined by 13.5% compared to our PV-10 value at December 31, 2008. As a result, we recorded a ceiling test impairment of oil and gas properties of $240.8 million during the first quarter of 2009. The effect of derivative contracts accounted for as cash flow hedges, based on the March 31, 2009 spot prices, increased the full cost ceiling by $169.0 million, thereby reducing the ceiling test write down by the same amount.

As of September 30, 2009, the cost center ceiling exceeded the net capitalized cost of our oil and gas properties, and no ceiling test impairment was recorded during the third quarter of 2009. The internally estimated PV-10 value of our reserves was estimated based on spot prices of $70.21 per Bbl of oil and $3.24 per Mcf of gas at September 30, 2009. The effect of derivative contracts accounted for as cash flow hedges, based on these September 30, 2009 spot prices, reduced the full cost ceiling by $10.7 million. The qualifying cash flow hedges as of September 30, 2009, which consisted of commodity price swaps, covered 3,954 MBbls of oil production for the period from October 2009 through December 2011.

Loss on impairment of ethanol plant. We owned a 66.67% interest in Oklahoma Ethanol LLC, a joint venture to construct and operate an ethanol production plant in Blackwell, Oklahoma. Oklahoma Ethanol LLC retained a financial advisor to arrange project financing to fund construction costs and for related start-up working capital. Because financing did not close by September 15, 2008, the minority owner, Oklahoma Sustainable Energy LLC, is no longer able to participate in the joint venture, and we now own 100% of Oklahoma Ethanol, LLC. The City of Blackwell has also been unable to obtain financing for the railroad upgrades and storage facilities that would be necessary to support ethanol production. During the third quarter of 2008, we determined that we will be unlikely to obtain equity capital or new project financing for an ethanol plant, and accordingly recorded an impairment charge of $2.9 million, which was the amount of our investment in the ethanol plant.

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

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

As of December 31, 2008, the recorded receivable for the Working Capital Adjustment was $14.4 million, and was included in other assets on the consolidated balance sheet. As of December 31, 2008, the recorded payable related to the Tax Election was $4.4 million, and was included in accounts payable and accrued liabilities on the consolidated balance sheet. As a result of the settlement, as of September 30, 2009, the receivable related to the Working Capital Adjustment and the Tax Election payable were eliminated, the escrow cash account was reclassified to operating cash, and we recorded a charge to expense of $2.9 million.

General and administrative expenses (“G&A”) – The $1.0 million increase for the third quarter of 2009 was primarily due to higher deferred compensation costs. Due to a reduction in the fair value of our phantom stock during the third quarter of 2008, we recognized a deferred compensation gain which reduced G&A expense by $1.2 million for that quarter. The $0.8 million decrease for the first nine months of 2009 was primarily due to lower compensation costs. G&A expense is net of amounts capitalized as part of our exploration and development activities, as shown in the following table:


	Three months ended September 30,						Nine months ended September 30,
	2008			2009			2008			2009
General and administrative cost	$	7,438		$	8,530		$	28,777		$	26,359
Less: general and administrative cost capitalized		(2,559	)		(2,676	)		(9,817	)		(8,231	)

General and administrative expense	$	4,879		$	5,854		$	18,960		$	18,128

Interest expense – Interest expense for the three months ended September 30, 2009 increased by 3.7% compared to the same period in 2008 primarily as a result of higher interest rates paid. Interest expense for the nine months ended September 30, 2009 increased by 5.2% compared to the same period in 2008 primarily as a result of increased levels of borrowings. The following table presents interest expense for the three and nine months ended September 30, 2008 and 2009:


	Three months ended September 30,				Nine months ended September 30,
(dollars in thousands)	2008		2009		2008		2009
Revolver interest	$	5,836	$	6,583	$	17,405	$	20,355
8 ¹/ 2% Senior Notes, due 2015		7,089		7,105		21,255		21,304
8 ⁷/ 8% Senior Notes, due 2017		7,433		7,403		22,187		22,194
Bank fees and other interest		1,303		1,380		3,435		3,802

	$	21,661	$	22,471	$	64,282	$	67,655

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


	Three months ended September 30,						Nine months ended September 30,
(dollars in thousands)	2008			2009			2008			2009
Change in fair value of non-qualified commodity price swaps	$	42,525		$	(7,210	)	$	(16,355	)	$	(75,963	)
Change in fair value of non-designated costless collars		37,682			(7,377	)		29,125			(43,546	)
Change in fair value of natural gas basis differential contracts		(1,627	)		(4,845	)		3,188			(15,081	)
Receipts from (payments on) settlement of non-qualified commodity price swaps		(3,021	)		7,791			(8,227	)		107,020
Receipts from settlement of non-designated costless collars		125			9,013			125			41,358
Receipts from (payments on) settlement of natural gas basis differential contracts		1,502			(2,372	)		2,149			(1,480	)

	$	77,186		$	(5,000	)	$	10,005		$	12,308

The gain on non-qualified commodity price swaps for the third quarter of 2009 was $0.6 million and included gains of $0.9 million on oil swaps, partially offset by losses of $0.3 million on gas swaps. The gain on non-qualified commodity price swaps for the third quarter of 2008 was $39.5 million, and was comprised of gains on oil swaps that were entered into in anticipation of the Calumet acquisition and did not qualify as hedges. The gain on non-qualified commodity price swaps for the nine months ended September 30, 2009 was $31.1 million and included gains of $41.5 million on gas swaps, partially offset by losses of $10.4 million on oil swaps. The loss on non-qualified commodity price swaps for the third quarter of 2008 was $24.6 million, and was comprised of losses on oil swaps that were entered into in anticipation of the Calumet acquisition and did not qualify as hedges.

The gain on costless collars was $1.6 million and $37.8 million, respectively, for the third quarter of 2009 and 2008. The gain on costless collars for the third quarter of 2009 consisted of a gain of $1.2 million and $0.4 million, respectively, on oil and gas collars. The gain on costless collars for the third quarter of 2008 consisted of a gain of $18.8 million and $19.0 million on oil and gas collars, respectively. For the nine months ended September 30, 2009, the loss on costless collars was $2.2 million compared to a gain of $29.3 million for the comparable period of 2008. The loss on costless collars for the nine months ended September 30, 2009 consisted of a loss on oil collars of $11.8 million, which included a $7.3 million loss on monetization in the second quarter. The loss was partially offset by a gain on gas collars of $9.6 million. For the nine months ended September 30, 2008, the gain on costless collars consisted of a gain of $15.2 million and $14.1 million on oil and gas collars, respectively. These changes are due primarily to higher NYMEX forward strip oil and gas prices at September 30, 2009 compared to June 30, 2009 and December 31, 2008.

The loss on natural gas basis differential contracts was $7.2 million for the third quarter of 2009 compared to a loss of $0.1 million for the third quarter of 2008. The loss on natural gas basis differential contracts was $16.6 million for the nine months ended September 30, 2009 compared to a gain of $5.3 million for the comparable period of 2008. The increase in losses on natural gas basis differential swaps during the three and nine months ended September 30, 2009 compared to the three and nine months ended September 30, 2008 was primarily due to lower differentials indicated by the forward commodity price curves. We had basis swaps covering 34,030 BBtu at September 30, 2009 compared to 4,730 BBtu at September 30, 2008.

Primarily as a result of the above transactions, we had non-hedge derivative losses of $5.0 million for the first quarter of 2009 compared to non-hedge derivative gains of $77.2 million for the comparable period of 2008, and non-hedge derivative gains of $12.3 million and $10.0 million, respectively, for the nine months ended September 30, 2009 and 2008.

Production tax credits – During 2006, we purchased interests in two venture capital limited liability companies resulting in a total investment of $15.0 million. Our return on the investment was the receipt of $2 of Oklahoma tax credits for every $1 invested and was recouped from our Oklahoma production taxes. The investments are accounted for as a production tax benefit asset and are netted against tax credits realized in other income using the effective yield method over the expected recovery period. Other income for the three months ended September 30, 2008 and 2009 did not include any significant Oklahoma production tax credits. Other income for the nine months ended September 30, 2008 and 2009 includes Oklahoma production tax credits of $0.7 million and $13.5 million, respectively. This source of income will not be available in future periods.

Discontinued Operations – During the second quarter of 2009, we committed to a plan to sell the assets of GCS, a wholly owned subsidiary that provides oilfield supplies, oilfield chemicals, downhole electric submersible pumps, and related services to oil and gas operators primarily in Oklahoma, Texas, and Wyoming.

On May 14, 2009, we entered into an agreement to sell the assets of the ESP Division of GCS to Global for a cash price of $26.0 million, subject to working capital adjustments as provided in the agreement. On June 8, 2009, we received $24.7 million in conjunction with the closing of the ESP Division sale to Global. The amount received reflected a reduction of $1.3 million due to working capital changes as of March 31, 2009. We paid off notes payable attributed to certain assets sold to Global in the amount of $1.6 million. The purchase price is subject to a final working capital adjustment, which is expected to be settled before December 31, 2009. For the nine months ended September 30, 2009, we recorded a pre-tax gain associated with the sale of $9.0 million. All taxable income associated with such gain was offset by existing net operating losses.

The operating results of GCS for the three and nine months ended September 30, 2008 and 2009 have been reclassified as discontinued operations in the consolidated statements of operations. Income from discontinued operations, including the gain on the sale of the ESP Division and net of income taxes, was $0.4 million and $0.1 million, respectively, for the third quarter of 2008 and 2009, and $0.9 million and $5.6 million, respectively, for the nine months ended September 30, 2008 and 2009.

Non-GAAP financial measures and reconciliations

We define adjusted EBITDA as net income (loss), adjusted to exclude (1) interest and other financing costs, net of capitalized interest, (2) income taxes, (3) depreciation, depletion and amortization, (4) unrealized (gain) loss on ineffective portion of hedges and reclassification adjustments, (5) non-cash change in fair value of non-hedge derivative instruments, (6) interest income, (7) non-cash deferred compensation (gain) expense, (8) gain or loss on disposed assets, and (9) impairment charges and other significant, unusual, non-cash charges. Any cash proceeds received from the monetization of derivatives with a scheduled maturity date more than 12 months following the date of such monetization are excluded from the calculation of adjusted EBITDA.

Management uses adjusted EBITDA as a supplemental financial measurement to evaluate our operational trends. Items excluded generally represent non-cash adjustments, the timing and amount of which cannot be reasonably estimated and are not considered by management when measuring our overall operating performance. In addition, adjusted EBITDA mirrors the Consolidated EBITDAX ratio that is used in the covenant calculation required under our Credit Agreement described in the Liquidity and Capital Resources section above. We consider compliance with this covenant to be material. Adjusted EBITDA is used as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to net income, as an indicator of our operating performance, as an alternative to cash flows from operating activities, or as a measure of liquidity. Adjusted EBITDA is not defined under GAAP and, accordingly, it may not be a comparable measurement to those used by other companies. The following table provides a reconciliation of net loss to adjusted EBITDA for the specified periods:


	Three months ended September 30,						Nine months ended September 30,
(Dollars in thousands)	2008			2009			2008			2009
Net income (loss)	$	78,504		$	(4,386	)	$	45,485		$	(146,934	)
Interest expense		21,661			22,471			64,282			67,655
Income tax provision (benefit)		49,522			(1,565	)		28,910			(90,743	)
Depreciation, depletion, and amortization		25,577			24,827			74,744			80,726
Unrealized gain on ineffective portion of hedges and reclassification adjustments		(34,663	)		(1,601	)		(6,565	)		(20,360	)
Non-cash change in fair value of non-hedge derivative instruments		(78,580	)		19,432			(15,958	)		32,238
Interest income		(92	)		(65	)		(298	)		(237	)
Non-cash deferred compensation (gain) expense		(1,362	)		196			1,031			827
Gain on disposed assets		(51	)		(5	)		(281	)		(9,010	)
Loss on impairment of oil and gas properties		—			—			—			240,790
Loss on impairment of ethanol plant		2,900			—			2,900			—
Loss on litigation settlement		—			—			—			2,928

Adjusted EBITDA	$	63,416		$	59,304		$	194,250		$	157,880

Critical accounting policies and estimates

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

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

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

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

Oil and 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%, adjusted for derivatives accounted for as cash flow hedges, plus the lower of cost or fair market value of unproved properties. The ceiling calculation requires that prices and costs used to determine the estimated future net revenues 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 judgments are subject to future revisions from changing technology and regulatory requirements. We review our assumptions and estimates of future development and future abandonment costs on a quarterly basis.

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

We use the present value of estimated cash flows related to our asset retirement obligation to determine the fair value. 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 deferred income taxes based on 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 (“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 production for the nine months ended September 30, 2009, our gross revenues from oil and gas sales would change approximately $1.7 million for each $0.10 change in gas prices and $2.9 million for each $1.00 change in oil prices.

To mitigate a portion of our exposure to fluctuations in commodity prices, we enter into commodity price swaps, costless collars, and basis protection swaps. For commodity price swaps, we receive a fixed price for the hedged commodity and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

In anticipation of the Calumet acquisition, we entered into additional commodity swaps to provide protection against a decline in the price of oil. We do not believe that these instruments qualify as hedges. Therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative gains (losses). Also, as a result of the acquisition, Chaparral assumed the existing Calumet swaps on October 31, 2006, and designated these as cash flow hedges. As of December 31, 2008, the hedges assumed as part of the Calumet acquisition have been settled.

Our outstanding oil and gas derivative instruments as of September 30, 2009, are summarized below:


	Crude oil swaps						Crude oil collars			Percent of PDP production(1)
	Hedge			Non-hedge			Non-hedge
	Volume MBbl	Weighted average fixed price to be received		Volume MBbl	Weighted average fixed price to be received		Volume MBbl	Weighted average range
4Q 2009	553	$	67.47	90	$	66.18	60	$	110.00 -$164.28	84.2	%
1Q 2010	520		68.13	102		65.80	60		110.00 - 168.55	83.9	%
2Q 2010	516		68.06	90		65.47	60		110.00 - 168.55	84.1	%
3Q 2010	499		68.24	90		65.10	60		110.00 - 168.55	84.0	%
4Q 2010	450		66.89	90		64.75	60		110.00 - 168.55	79.5	%
1Q 2011	354		66.44	99		64.24	51		110.00 - 152.71	68.2	%
2Q 2011	354		66.21	90		63.93	51		110.00 - 152.71	70.1	%
3Q 2011	354		65.96	90		63.61	51		110.00 - 152.71	72.3	%
4Q 2011	354		65.68	90		63.30	51		110.00 - 152.71	73.6	%

	3,954			831			504

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


	Natural gas swaps non-hedge			Natural gas collars non-hedge			Percent of PDP production (1)
	Volume BBtu	Weighted average fixed price to be received		Volume BBtu	Weighted average range		Percent of PDP production (1)
4Q 2009	2,900	$	7.91	990	$	10.00 -$13.85	69.76	%
1Q 2010	3,150		7.73	840		10.00 - 11.53	76.35	%
2Q 2010	3,150		7.05	840		10.00 - 11.53	81.01	%
3Q 2010	3,150		7.27	840		10.00 - 11.53	85.23	%
4Q 2010	3,150		7.69	840		10.00 - 11.53	89.20	%
1Q 2011	2,550		7.86	—		—	59.44	%
2Q 2011	2,550		6.99	—		—	63.43	%
3Q 2011	2,550		7.16	—		—	66.55	%
4Q 2011	2,550		7.51	—		—	68.67	%

	25,700			4,350


	Natural gas basis protection swaps non-hedge
	Volume BBtu	Weighted average fixed price to be paid
4Q 2009	4,440	$	0.94
1Q 2010	4,950		0.94
2Q 2010	4,120		0.73
3Q 2010	3,930		0.74
4Q 2010	3,600		0.79
1Q 2011	3,600		0.80
2Q 2011	3,260		0.71
3Q 2011	3,120		0.71
4Q 2011	3,010		0.72

	34,030

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

Subsequent to September 30, 2009, we entered into additional oil swaps for 290 MBbls for the periods of October 2010 through December 2011 with a weighted average price of $84.13.

Interest rates. All of the outstanding borrowings under our Credit Agreement as of September 30, 2009, are subject to market rates of interest as determined from time to time by the banks. We may designate borrowings under our Credit Agreement as either ABR loans or Eurodollar loans. ABR loans bear interest at a fluctuating rate that is linked to the greater of (1) the Prime Rate, as defined in our Credit Agreement, (2) the Federal Funds Effective Rate, as defined in our Credit Agreement, plus ¹/2 of 1%, or (3) the Adjusted LIBO rate, as defined in our Credit Agreement. Eurodollar loans bear interest at a fluctuating rate that is linked to the Adjusted LIBO Rate, defined as the greater of 2% or the rate applicable to dollar deposits in the London interbank market. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $513.0 million, equal to our borrowing base, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $5.1 million.

ITEM 4.

CONTROLS AND PROCEDURES

Disclosure controls and procedures

We have established disclosure controls and procedures to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to the officers who certify our financial reports and to other members of senior management and the Board of Directors. Based on their evaluation as of the end of the period covered by this quarterly report, our Chairman, President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and are effective to ensure that information required to be disclosed in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Internal control over financial reporting

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

PART II—OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

No material legal proceedings were filed against us or any of our subsidiaries in the third quarter of 2009 and no material change to previously reported litigation occurred in the third quarter of 2009. However, due to the nature of our business, certain legal or administrative proceedings may arise from time to time in the ordinary course of business.

ITEM 1A.

RISK FACTORS

We cannot control the activities on properties we do not operate and we are unable to ensure the proper operation and profitability of these non-operated properties.

We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operation of these properties. The success and timing of drilling and development activities on our partially owned properties operated by others therefore will depend upon a number of factors outside of our control, including the operator’s:

•

timing and amount of capital expenditures;

•

expertise and diligence in adequately performing operations and complying with applicable agreements;

•

financial resources;

•

inclusion of other participants in drilling wells; and

•

use of technology.

As a result of any of the above or an operator’s failure to act in ways that are in our best interest, our allocated production revenues and results of operations could be adversely affected.

If the third parties we rely on for gathering and distributing our oil and gas are unable to meet our needs for such services and facilities, our future exploration and production activities could be adversely affected.

The marketability of our production depends upon the proximity of our reserves to, and the capacity of, third-party facilities and third-party services, including oil and gas gathering systems, pipelines, trucking or terminal facilities, and refineries or processing facilities. Such third parties are subject to federal and state regulation of the production and transportation of oil and gas. If such third parties are unable to comply with such regulations and we are unable to replace such service and facilities providers, we may be required to shut-in producing wells or delay or discontinue development plans for our properties. A shut-in, delay or discontinuance could adversely affect our financial condition.

If we are not able to generate sufficient cash to service all of our long-term indebtedness and are unable to reduce expenditures sufficiently, restructure, refinance or take other actions to satisfy our obligations under our Credit Facility, our operations and business would be adversely affected.

Our ability to make scheduled payments on or to refinance our long-term indebtedness obligations depends on our financial and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We cannot provide any assurances that we will maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our long-term indebtedness.

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets or operations, seek additional borrowings or restructure or refinance our long-term indebtedness, including our senior notes. We cannot provide assurance that we would be able to take any of these actions, that these actions would be successful and permit us to meet our scheduled debt service or that these actions would be permitted under the terms of existing or future agreements, including our Credit Facility and the indentures governing our senior notes. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our Credit Facility and the indentures governing our senior notes restrict our ability to dispose of assets and use the proceeds from the disposition. We may not be able to consummate those dispositions or to obtain the proceeds which we could realize from them, and these proceeds may not be adequate to meet any debt service obligations then due.

If we cannot make scheduled payments on our long-term indebtedness, we will be in default and, as a result:

•

debt holders could declare all outstanding principal and interest to be due and payable;

•

we may be in default under our master (ISDA) derivative contracts and counter-parties could demand early termination; and

•

the lenders under the Credit Facility could terminate their commitments to loan us money and foreclose against the assets securing their borrowings; and

•

we could be forced into bankruptcy or liquidation.

Possible regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and gas.

Recent scientific studies have suggested that emissions of gases, commonly referred to as “greenhouse gases” including carbon dioxide, methane and nitrous oxide among others, may be contributing to warming of the earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, several states have already taken legal measures to reduce emissions of greenhouse gases. As a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, 549 U.S. 497 (2007), finding that greenhouse gases fall within the Clean Air Act (CAA) definition of “air pollutant,” the Environmental Protection Agency (“EPA”) was required to determine whether emissions of greenhouse gases “endanger” public health or welfare. In April 2009, the EPA proposed a finding of such endangerment and has announced plans to soon finalize its proposed endangerment finding. Consistent with its endangerment finding, in September 2009, the EPA proposed regulations to control greenhouse gas emissions from light duty vehicles. The EPA also announced that its action to control greenhouse gas emissions from light duty vehicles automatically triggers application of the CAA prevention of significant deterioration and Title V operating permit program to major stationary sources of greenhouse gas emissions. Thus, in September 2009, the EPA issued a proposed “tailoring” rule explaining how it would implement the CAA permitting programs to major stationary source greenhouse gas emission sources. In September 2009, the EPA also adopted a mandatory greenhouse gas reporting rule which will assist the EPA in implementing the major stationary source permitting programs triggered by the mobile source rules. The EPA’s rules may become final and effective even if Congress adopts new legislation addressing emissions of greenhouse gases. Finally, in September 2009, the United States Court of Appeals for the Second Circuit issued its decision in Connecticut v. AEP allowing plaintiffs’ claims that public utilities greenhouse gas emissions created a “public nuisance” to go to trial over defendants’ objections based upon political question, preemption and lack of standing. This case exposes other significant emission sources of greenhouse gases to similar litigation risk. This effect of this recent caselaw may be mitigated by Congress’s adoption of greenhouse gas legislation and, or, the EPA’s final adoption of greenhouse gas emission standards.

Other nations have already agreed to regulate emissions of greenhouse gases, pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) have agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. International negotiations are currently underway to develop a new agreement, with the participation of the United States. International developments, passage of state or federal climate control legislation or other regulatory initiatives, the adoption of regulations by the EPA and analogous state agencies that restrict emissions of greenhouse gases in areas in which we conduct business, or further development of caselaw allowing claims based upon greenhouse gas emissions, could have an adverse effect on our operations and demand for oil and gas.

Potential legislative and regulatory actions could increase our costs, reduce our revenue and cash flow from oil and gas sales, reduce our liquidity or otherwise alter the way we conducts our business.

Pending federal budget proposals would potentially increase and accelerate the payment of federal income taxes of independent producers of oil and gas. Proposals that would significantly affect us would repeal the expensing of intangible drilling costs, repeal the percentage depletion allowance, repeal the manufacturing tax deduction for oil and gas companies and increase the amortization period of geological and geophysical expenses. These changes, if enacted, will make it more costly for us to explore for and develop our oil and gas resources.

The U.S. Congress is considering measures aimed at increasing the transparency and stability of the over-the-counter (OTC) derivative markets and preventing excessive speculation. We maintain an active price and basis protection hedging program related to the oil and gas we produce. Additionally, we have used the OTC market exclusively for our oil and gas derivative contracts and rely on our hedging activities to manage the risk of low commodity prices and to predict with greater certainty the cash flow from our hedged production. Proposals being considered would impose clearing and standardization requirements for all OTC derivatives and restrict trading positions in the energy futures markets. Such changes would likely materially reduce our hedging opportunities and could negatively affect our revenues and cash flow during periods of low commodity prices.

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. of our Annual Report on Form 10-K for the year ended December 31, 2008, which could materially affect our business, financial condition, or future results.

ITEM 6.

EXHIBITS


Exhibit No.		Description

2.1*		Agreement and Plan of Reorganization By and Among United Refining Energy Corp., Chaparral Subsidiary, Inc. and Chaparral Energy, Inc. dated as of October 9, 2009. (Incorporated by reference to Exhibit 2.1of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on October 13, 2009.)

10.22		Second Amended & Restated Phantom Stock Plan dated as of December 31, 2008.


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 10, 2009

EXHIBIT INDEX


Exhibit No.		Description

2.1*		Agreement and Plan of Reorganization By and Among United Refining Energy Corp., Chaparral Subsidiary, Inc. and Chaparral Energy, Inc. dated as of October 9, 2009. (Incorporated by reference to Exhibit 2.1of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on October 13, 2009.)

10.22		Second Amended & Restated Phantom Stock Plan dated as of December 31, 2008.


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

Chaparral Energy, Inc. - FORM 10-Q - November 10, 2009

Attached files

Chaparral Energy, Inc. Reports

Also read