Form 10-Q

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Table=20 of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION =

Washington, D.C. 20549

Form 10-Q

x	QUARTERLY=20 REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE = ACT OF=20 1934

For the quarterly period ended June 30, = 2009=20

=A8

TRANSITION REPORT PURSUANT TO SECTION = 13 OR=20 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934=20

For the transition period from=20 &nb= sp; =20 to=20 &nb= sp; =20

Commission file number: 333-134748

Chaparral Energy, Inc.

(Exact name of registrant as specified in = its charter)=20


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=20 offices)		(Zip=20 code)

(405) 478-8770

(Registrant=92s telephone number, including = area code)=20

Indicate by check mark whether the registrant=20 (1) has filed all reports required to be filed by Section 13 = or 15(d)=20 of the Securities Exchange Act of 1934 during the preceding 12 months = (or for=20 such shorter period that the registrant was required to file such = reports), and=20 (2) has been subject to such filing requirements for the past 90=20 days. Yes x No =A8

Indicate by check mark whether the registrant = has=20 submitted electronically and posted on its corporate Web site, if any, = every=20 Interactive Data File required to be submitted and posted pursuant to = Rule 405=20 of Regulation S-T (=A7232.405 of this chapter) during the preceding 12 = months (or=20 for such shorter period that the registrant was required to submit and = post such=20 files). Yes =A8 No =A8

Indicate by check mark whether the registrant = is a large=20 accelerated filer, an accelerated filer, a non-accelerated filer or a = smaller=20 reporting company. See the definitions of =93large accelerated filer,=94 = =93accelerated filer=94 and =93smaller reporting company=94 in Rule = 12b-2 of the=20 Exchange Act.

Large Accelerated Filer =A8 &nbs= p;Accelerated Filer =A8 &nbs= p;Non-Accelerated Filer x = Smaller Reporting Company =A8

Indicate by check mark whether the registrant = is a shell=20 company (as defined in Rule 12b-2 of the Exchange=20 Act). Yes =A8 No x

877,000 shares of the registrant=92s common = stock were=20 outstanding as of August 13, 2009.

Table=20 of Contents

CHAPARRAL ENERGY, INC. =

Index to Form 10-Q


		Page
Part I. FINANCIAL = INFORMATION
Item 1. Financial = Statements
Consolidated=20 Balance Sheets as of December 31, 2008 and June 30, 2009 = (Unaudited)		5
Consolidated=20 Statements of Operations for the three and six months ended = June 30,=20 2008 and 2009 (Unaudited)		6
Consolidated=20 Statements of Cash Flows for the six months ended June 30, = 2008 and=20 2009 (Unaudited)		7
Notes=20 to Consolidated Financial Statements = (Unaudited)		9
Item 2.=20 Management=92s Discussion and Analysis of Financial Condition and = Results of=20 Operations		22
Overview		22
Liquidity=20 and Capital Resources		25
Results=20 of Operations		30
Critical=20 Accounting Policies and Estimates		34
Recent=20 Accounting Pronouncements		36
Item 3.=20 Quantitative and Qualitative Disclosures About Market=20 Risk		36
Item 4.=20 Controls and Procedures		39
Part=20 II. OTHER INFORMATION		39
Item 1.=20 Legal Proceedings		39
Item 1A.=20 Risk Factors		39
Item 6.=20 Exhibits		39
Signatures		41
EX-31.1 (Certification by CEO required by = rule=20 13a-14(a)/15d-14(a))
EX-31.2 (Certification by CFO required by = rule=20 13a-14(a)/15d-14(a))
EX-32.1 (Certification by CEO pursuant to = section=20 906)
EX-32.2 (Certification by CFO pursuant to = section=20 906)

Table=20 of Contents

CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS =

This report includes statements that constitute = forward-looking statements within the meaning of the federal securities = laws.=20 These statements are subject to risks and uncertainties. These = statements may=20 relate to, but are not limited to, information or assumptions about = Capital and=20 other expenditures, dividends, financing plans, Capital structure, cash = flow,=20 pending legal and regulatory proceedings and claims, including = environmental=20 matters, future economic performance, operating income, cost savings,=20 management=92s plans, strategies, goals and objectives for future = operations and=20 growth.

These forward-looking statements generally are=20 accompanied by words such as =93intend,=94 =93anticipate,=94 = =93believe,=94 =93estimate,=94=20 =93expect,=94 =93should,=94 =93seek,=94 =93project,=94 =93plan=94 or = similar expressions. It should=20 be understood that these forward-looking statements are necessarily = estimates=20 reflecting the best judgment of our senior management, not guarantees of = future=20 performance. They are subject to a number of assumptions, risks and=20 uncertainties that could cause actual results to differ materially from = those=20 expressed or implied in the forward-looking statements.

Forward-looking statements may relate to = various=20 financial and operational matters, including, among other things: =

=95

fluctuations in demand=20 or the prices received for our oil and gas;=20

=95

the = amount, nature and=20 timing of Capital expenditures; =

=95

drilling = of wells;=20

=95

competition and=20 government regulations;

=95

timing and = amount of=20 future production of oil and gas; =

=95

costs of = exploiting and=20 developing our properties and conducting other operations, in the=20 aggregate and on a per unit equivalent basis;=20

=95

increases = in proved=20 reserves;

=95

operating = costs and=20 other expenses;

=95

cash flow = and=20 anticipated liquidity;

=95

estimates = of proved=20 reserves;

=95

exploitation or property=20 acquisitions;

=95

marketing = of oil and=20 gas; and

=95

general = economic=20 conditions and the other risks and uncertainties discussed in this = report.=20

Undue reliance should not be placed on = forward-looking=20 statements, which speak only as of the date of this report. Unless = otherwise=20 required by law, we undertake no obligation to publicly update or revise = any=20 forward-looking statements, whether as a result of new information, = future=20 events or otherwise.

Table=20 of Contents

GLOSSARY OF OIL AND GAS TERMS =

The terms defined in this section are used = throughout=20 this Form 10-Q:

=95

Bbl. One stock=20 tank barrel, or 42 U.S. gallons liquid volume, used herein in = reference to=20 crude oil, condensate or natural gas liquids.=20

=95

BBtu. One billion=20 British thermal units.

=95

Bcf. One billion=20 cubic feet of natural gas.

=95

Bcfe. One billion=20 cubic feet of natural gas equivalent using the ratio of one barrel = of=20 crude oil, condensate or natural gas liquids to 6 Mcf of natural = gas.=20

=95

Btu. British=20 thermal unit, which is the heat required to raise the temperature = of a=20 one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.=20

=95

Enhanced oil recovery=20 (EOR). The use of any improved recovery method, including = injection of=20 CO2 or polymer, to remove additional oil after secondary recovery. =

=95

MBbl. One=20 thousand barrels of crude oil, condensate, or natural gas liquids. =

=95

Mcf. One thousand=20 cubic feet of natural gas.

=95

Mcfe. One=20 thousand cubic feet of natural gas equivalents.=20

=95

MMBbl. One=20 million barrels of crude oil, condensate, or natural gas liquids.=20

=95

MMcf. One million=20 cubic feet of natural gas.

=95

MMcfe. One=20 million cubic feet of natural gas equivalents.=20

=95

NYMEX. The New=20 York Mercantile Exchange.

=95

PDP. Proved=20 developed producing.

=95

Proved = reserves.=20 The estimated quantities of crude oil, natural gas and natural gas = liquids=20 which geological and engineering data demonstrate with reasonable=20 certainty to be recoverable in future years from known reservoirs = under=20 existing economic and operating conditions, i.e., prices and costs = as of=20 the date the estimate is made. Prices include consideration of = changes in=20 existing prices provided only by contractual arrangements, but not = on=20 escalations based upon future conditions. =

=95

Proved = undeveloped=20 reserves. Reserves that are expected to be recovered from new = wells on=20 undrilled acreage or from existing wells where a relatively major=20 expenditure is required for recompletion. =

Table=20 of Contents

PART I =97 FINANCIAL INFORMATION =

ITEM 1.

FINANCIAL = STATEMENTS=20

Chaparral Energy, = Inc. and=20 subsidiaries

Consolidated balance sheets


(Dollars in thousands, except per = share=20 data)	December 31, 2008			June 30, 2009 (unaudited)
Assets
Current assets:
Cash and cash equivalents	$	52,112			$	84,276
Accounts receivable, net		63,957				44,698
Production tax benefit		13,685				43
Inventories		13,552				10,863
Prepaid expenses		4,114				4,328
Derivative instruments		51,412				37,939
Assets held for sale		19,531				4,004

Total current assets		218,363				186,151
Property and equipment=97at cost, = net		65,759				62,606
Oil & gas properties, using the = full cost=20 method:
Proved		1,751,096				1,844,682
Unproved (excluded from the amortization=20 base)		16,865				16,797
Work in progress (excluded from the = amortization=20 base)		31,893				1,779
Accumulated depreciation, depletion, = amortization=20 and impairment		(573,233	)			(863,730	)

Total oil & gas = properties		1,226,621				999,528
Funds held in escrow		2,350				1,662
Derivative instruments		157,720				16,131
Deferred income taxes		=97				71,337
Assets held for sale		7,744				2,576
Other assets		34,279				18,569

	$	1,712,836			$	1,358,560

Liabilities and stockholders=92=20 equity
Current liabilities:
Accounts payable and accrued=20 liabilities	$	89,744			$	49,064
Accrued payroll and benefits = payable		9,215				10,415
Accrued interest payable		15,408				14,394
Revenue distribution = payable		19,827				17,391
Current maturities of long-term debt and = Capital=20 leases		5,536				5,041
Derivative instruments		=97				5,420
Deferred income taxes		19,696				12,388
Liabilities associated with discontinued=20 operations		3,697				1,033

Total current liabilities		163,123				115,146
Long-term debt and Capital leases, less = current=20 maturities		615,936				526,604
Senior notes, net		647,675				647,774
Derivative instruments		3,388				22,466
Deferred compensation		762				815
Asset retirement = obligations		33,075				34,712
Deferred income taxes		42,699				=97
Liabilities associated with discontinued=20 operations		1,778				185
Commitments and contingencies (note=20 8)
Stockholders=92 equity:
Preferred stock, 600,000 shares = authorized, none=20 issued and outstanding		=97				=97
Common stock, $.01 par value, 3,000,000 = shares=20 authorized; 877,000 shares issued and outstanding as of = December 31,=20 2008 and June 30, 2009, respectively		9				9
Additional paid in = Capital		100,918				100,918
Retained earnings (accumulated=20 deficit)		21,340				(121,208	)
Accumulated other comprehensive income, = net of=20 taxes		82,133				31,139

		204,400				10,858

	$	1,712,836			$	1,358,560

The accompanying notes are an integral part of = these=20 consolidated financial statements.

Table=20 of Contents

Chaparral Energy, = Inc. and=20 subsidiaries

Consolidated statements of operations =


	Three months ended June 30,			Six months = ended June 30,
(Dollars in thousands, except per = share=20 data)	2008 (unaudited)			2009 (unaudited)			2008 (unaudited)		2009 (unaudited)
Revenues:
Oil and gas sales	$	157,668			$	69,064		$	278,696		$	122,931
Gain (loss) from oil and gas hedging=20 activities		(58,230	)			6,188			(89,355	)		21,691

Total revenues		99,438				75,252			189,341			144,622
Costs and expenses:
Lease operating		26,367				23,557			53,912			50,965
Production tax		10,601				4,941			18,516			8,801
Depreciation, depletion and=20 amortization		24,934				25,230			48,645			55,400
Loss on impairment of oil & gas=20 properties		=97				=97			=97			240,790
Litigation settlement		=97				=97			=97			2,928
General and = administrative		7,829				5,906			14,081			12,274

Total costs and expenses		69,731				59,634			135,154			371,158
Operating income (loss)		29,707				15,618			54,187			(226,536	)
Non-operating income = (expense):
Interest expense		(21,101	)			(22,720	)		(42,621	)		(45,184	)
Non-hedge derivative gains = (losses)		(58,499	)			(33,019	)		(67,181	)		17,308
Other income		669				2,783			1,154			13,750

Net non-operating expense		(78,931	)			(52,956	)		(108,648	)		(14,126	)
Loss from continuing operations before = income=20 taxes		(49,224	)			(37,338	)		(54,461	)		(240,662	)
Income tax benefit		(18,903	)			(14,175	)		(20,931	)		(92,617	)

Loss from continuing = operations		(30,321	)			(23,163	)		(33,530	)		(148,045	)
Income from discontinued operations, net = of related=20 taxes		269				5,439			511			5,497

Net loss	$	(30,052	)		$	(17,724	)	$	(33,019	)	$	(142,548	)

Net income (loss) per share (basic and=20 diluted):
Continuing operations	$	(34.57	)		$	(26.41	)	$	(38.23	)	$	(168.81	)
Discontinued operations		0.30				6.20			0.58			6.27

Net income (loss) per share (basic and=20 diluted):	$	(34.27	)		$	(20.21	)	$	(37.65	)	$	(162.54	)

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=20 consolidated financial statements.

Table=20 of Contents

Chaparral Energy, = Inc. and=20 subsidiaries

Consolidated statements of cash flows =


	Six months = ended June 30,
(Dollars in = thousands)	2008 (unaudited)			2009 (unaudited)
Cash flows from operating = activities
Net loss	$	(33,019	)		$	(142,548	)
Adjustments to reconcile net loss to net = cash=20 provided by operating activities
Depreciation, depletion &=20 amortization		48,645				55,400
Depreciation, depletion & = amortization of=20 discontinued operations		522				499
Loss on impairment of oil and gas=20 properties		=97				240,790
Litigation settlement		=97				2,928
Deferred income taxes		(20,612	)			(89,178	)
(Gain) loss from hedge ineffectiveness = and=20 reclassification adjustments		28,098				(18,759	)
Change in fair value of non-hedge = derivative=20 instruments		67,181				(17,308	)
Gain on sale of ESP Division of GCS and = other=20 assets		(230	)			(9,005	)
Other		777				1,359
Change in assets and = liabilities
Accounts receivable		(14,410	)			39,649
Inventories		(276	)			3,310
Prepaid expenses and other = assets		3,614				9,946
Accounts payable and accrued=20 liabilities		23,560				(6,466	)
Revenue distribution = payable		8,231				(2,436	)
Deferred compensation		2,393				(149	)

Net cash provided by operating=20 activities		114,474				68,032
Cash flows from investing = activities
Purchase of property and equipment and = oil and gas=20 properties		(151,443	)			(99,605	)
Proceeds from sale of ESP Division of=20 GCS		=97				24,650
Proceeds from dispositions of property = and=20 equipment and oil and gas properties		1,610				437
Settlement of non-hedge derivative=20 instruments		(4,559	)			132,466
Cash in escrow		2,596				389

Net cash provided by (used in) investing=20 activities		(151,796	)			58,337
Cash flows from financing = activities
Proceeds from long-term = debt		47,541				=97
Repayment of long-term = debt		(2,272	)			(91,922	)
Principal payments under Capital lease=20 obligations		(100	)			(126	)
Settlement of derivative instruments=20 acquired		108				=97
Fees paid related to financing=20 activities		(647	)			(2,157	)

Net cash provided by (used in) financing=20 activities		44,630				(94,205	)

Net increase in cash and cash=20 equivalents		7,308				32,164
Cash and cash equivalents at beginning of = period		11,687				52,112

Cash and cash equivalents at end of=20 period	$	18,995			$	84,276

Supplemental cash flow = information
Cash paid during the period = for:
Interest, net of Capitalized = interest	$	37,471			$	44,276
Income taxes		=97				=97

The accompanying notes are an integral part of = these=20 consolidated financial statements.

Table=20 of Contents

Chaparral Energy, Inc. and subsidiaries=20

Consolidated statements of cash = flows=97(Continued)=20

Supplemental disclosure of investing and = financing=20 activities

During the six months ended June 30, 2008 = and 2009,=20 we entered into Capital lease obligations of $448 and $111, = respectively, for=20 the purchase of machinery and equipment.

During the six months ended June 30, 2008, = oil and=20 gas property additions of $3,701 were recorded as increases to accounts = payable=20 and accrued expenses, and were reflected in cash used in investing = activities in=20 the periods that the payables were settled. During the six months ended=20 June 30, 2009, oil and gas property additions of $35,089 previously = included in accounts payable and accrued expenses were settled and are = reflected=20 in cash used in investing activities.

We also recorded a non-cash reduction in oil = and gas=20 properties and a corresponding increase in accounts receivable of $4,845 = during=20 the six months ended June 30, 2008. This amount represents loss of = well=20 control insurance proceeds for costs incurred prior to June 30, = 2008 on the=20 Bowdle 47 No. 2 well. During the six months ended June 30, = 2009, we=20 received the final insurance settlement of $1,910, which was recorded as = a=20 reduction in cash paid for the purchase of property and equipment and = oil and=20 gas properties.

During the six months ended June 30, 2008 = and 2009,=20 we recorded an asset and related liability of $500 and $300, = respectively,=20 associated with the asset retirement obligation on the acquisition = and/or=20 development of oil and gas properties.

Interest of $681 and $410 was Capitalized = during the six=20 months ended June 30, 2008 and 2009, respectively, primarily = related to=20 unproved oil and gas leaseholds.

Table=20 of Contents

Chaparral Energy, = Inc. and=20 subsidiaries

Notes to consolidated financial statements=20

(dollars in thousands, unless otherwise = noted)=20

Note 1: Nature of operations and summary of=20 significant accounting policies

Chaparral Energy, Inc. and subsidiaries, = (collectively,=20 =93we=94, =93our=94, =93us=94, or the =93Company=94) is involved in the = acquisition,=20 exploration, development, production and operation of oil and gas = properties.=20 Properties are located primarily in Oklahoma, Texas, New Mexico, = Louisiana,=20 Arkansas, Montana, Kansas, and Wyoming.

Interim financial statements =

The accompanying unaudited consolidated interim = financial=20 statements of the Company have been prepared in accordance with = accounting=20 principles generally accepted in the United States of America = (=93GAAP=94) for=20 interim financial information and with the instructions to Form 10-Q and = Article=20 10 of Regulation S-X and do not include all of the financial information = and=20 disclosures required by GAAP. The financial information as of = June 30,=20 2009, and for the three months and six months ended June 30, 2008 = and 2009,=20 is unaudited. In the opinion of management, such information contains = all=20 adjustments, consisting only of normal recurring accruals, considered = necessary=20 for a fair presentation of the results of the interim periods. The = results of=20 operations for the three and six months ended June 30, 2009, are = not=20 necessarily indicative of the results of operations that will be = realized for=20 the year ended December 31, 2009.

The consolidated interim financial statements = should be=20 read in conjunction with the consolidated financial statements and notes = thereto, together with management=92s discussion and analysis of = financial=20 condition and results of operations contained in our Form 10-K filed = with the=20 Securities and Exchange Commission on March 31, 2009.

Principles of consolidation =

The unaudited consolidated financial statements = include=20 the accounts of Chaparral Energy, Inc. and its wholly and majority owned = subsidiaries. All significant intercompany balances and transactions = have been=20 eliminated.

Reclassifications

Certain reclassifications have been made to = prior period=20 financial statements to conform to current period presentation. =

Use of estimates

The preparation of financial statements in = conformity=20 with GAAP requires management to make estimates and assumptions that = affect the=20 reported amounts of assets and liabilities and disclosure of contingent = assets=20 and liabilities at the date of the financial statements and the reported = amounts=20 of revenues and expenses during the reporting period. Actual results = could=20 differ from these estimates. Significant estimates affecting these = financial=20 statements include estimates for quantities of proved oil and gas = reserves,=20 deferred income taxes, asset retirement obligations, fair value of = derivative=20 instruments, and others, and are subject to change.

Cash and cash equivalents =

We consider all highly liquid investments with = an=20 original maturity of three months or less to be cash equivalents. We = maintain=20 cash and cash equivalents in bank deposit accounts and money market = funds which=20 may not be federally insured. As of June 30, 2009, cash and funds = held in=20 escrow with a recorded balance totaling $81,494 was held at JP Morgan = Chase=20 Bank, N.A. We have not experienced any losses in such accounts and = believe we=20 are not exposed to any significant credit risk on such accounts. =

Table=20 of Contents

Fair value measurements =

In September 2006, the Financial Accounting = Standards=20 Board (=93FASB=94) issued SFAS No. 157, Fair Value = Measurements (=93SFAS=20 157=94), which defines fair value, establishes a framework for measuring = fair=20 value, and expands disclosures about fair value measurements. As defined = in SFAS=20 157, fair value is the price that would be received to sell an asset or = paid to=20 transfer a liability in an orderly transaction between market = participants at=20 the measurement date. Where available, fair value is based on observable = market=20 prices or parameters or derived from such prices or parameters. Where = observable=20 prices or inputs are not available, valuation models are applied. These=20 valuation techniques involve some level of management estimation and = judgment,=20 the degree of which is dependent on the price transparency for the = instruments=20 or market and the instruments=92 complexity. This statement is effective = for=20 fiscal years and interim periods beginning after November 15, 2007. =

We elected to implement this Statement with the = one-year=20 deferral permitted by FASB Staff Position (=93FSP=94) 157-2, = Effective Date of=20 FASB Statement No. 157 (=93FSP 157-2=94), for nonfinancial = assets and=20 nonfinancial liabilities measured at fair value, except those that are=20 recognized or disclosed on a recurring basis (at least annually). We = adopted the=20 provisions of SFAS 157 for our financial assets and financial = liabilities=20 measured at fair value on January 1, 2008. We adopted the = provisions of=20 SFAS 157 for our nonfinancial assets and nonfinancial liabilities = measured at=20 fair value on a non-recurring basis on January 1, 2009. The = implementation=20 of SFAS 157 did not cause a change in the method of calculating fair = value of=20 assets or liabilities, with the exception of incorporating the impact of = nonperformance risk on derivative instruments. The primary impact from = adoption=20 was additional disclosures.

Assets and liabilities recorded at fair value = in the=20 balance sheet are categorized according to the fair value hierarchy = defined in=20 SFAS 157. The hierarchical levels are based upon the level of judgment=20 associated with the inputs used to measure the fair value of the assets = and=20 liabilities. In certain cases, the inputs used to measure fair value may = fall=20 into different levels of the fair value hierarchy. In such cases, the = asset or=20 liability is categorized based on the lowest level input that is = significant to=20 the fair value measurement in its entirety. Our assessment of the = significance=20 of a particular input to the fair value measurement in its entirety = requires=20 judgment, and may affect the placement of assets and liabilities within = the=20 levels of the fair value hierarchy.

Level 1 inputs are unadjusted quoted prices in = active=20 markets for identical assets or liabilities at the measurement date.=20 Level 2 inputs include adjusted quoted prices for similar = instruments in=20 active markets, and inputs other than quoted prices that are observable = for the=20 asset or liability. Fair value assets and liabilities included in = this=20 category are derivatives with fair values based on published forward = commodity=20 price curves and other observable inputs. Level 3 inputs are = unobservable inputs=20 for the asset or liability, and include situations where there is = little, if=20 any, market activity for the asset or liability. Assets recognized at = fair value=20 and included in this category are certain financial derivatives and = additions to=20 our asset retirement obligations.

In April 2009, the FASB issued three FSPs to = provide=20 additional application guidance and enhance disclosures regarding fair = value=20 measurements and impairments of securities. FSP FAS 157-4, = Determining Fair=20 Value When the Volume and Level of Activity for the Asset or Liability = Have=20 Significantly Decreased and Identifying Transactions That Are Not = Orderly,=20 provides guidelines for making fair value measurements more consistent = with the=20 principles presented in SFAS No. 157. FSP FAS 107-1 and APB = 28-1,=20 Interim Disclosures about Fair Value of Financial Instruments, = enhances=20 consistency in financial reporting by increasing the frequency of fair = value=20 disclosures. FSP FAS 115-2 and FAS 124-2, Recognition and = Presentation of=20 Other-Than-Temporary Impairments, provides additional guidance in = accounting=20 for and presenting impairment losses on securities. These three = FSPs are=20 effective for interim and annual periods ending after June 15, = 2009, with=20 early adoption permitted for periods ending after March 15, = 2009. We=20 adopted the provisions of these FSPs for the period ending = March 31,=20 2009. The adoption of these FSPs resulted in additional = disclosures, but=20 did not have an impact on our financial position or results of = operations.=20

Net income (loss) per share =

Basic net income (loss) per share is computed = by dividing=20 net income (loss) attributable to all classes of common shareholders by = the=20 weighted average number of shares of all classes of common stock = outstanding=20 during the applicable period. Diluted net income (loss) per share is = determined=20 in the same manner as basic net income (loss) per share except that the = number=20 of shares is increased to assume exercise of potentially dilutive = securities=20 outstanding during the periods presented. There were no potentially = dilutive=20 securities outstanding during the periods presented.

Table=20 of Contents

Accounts receivable

Accounts receivable consisted of the following = at=20 December 31, 2008 and June 30, 2009:


	December 31, 2008			June 30, 2009
Joint interests	$	21,136			$	13,907
Accrued oil and gas sales		27,432				27,195
Hedge settlements		15,315				4,146
Other		654				125
Allowance for doubtful = accounts		(580	)			(675	)

	$	63,957			$	44,698

Inventories

Inventories are comprised of equipment used in = developing=20 oil and gas properties, oil and gas production inventories, and = equipment for=20 resale. Equipment inventory and inventory for resale are carried at the = lower of=20 cost or market using the average cost method. Oil and gas product = inventories=20 are stated at the lower of production cost or market. We regularly = review=20 inventory quantities on hand and records provisions for excess or = obsolete=20 inventory, if necessary. Inventories at December 31, 2008 and = June 30,=20 2009 consisted of the following:


	December 31, 2008			June 30, 2009
Equipment inventory	$	10,484			$	8,391
Oil and gas product		3,467				3,272
Inventory valuation = allowance		(399	)			(800	)

	$	13,552			$	10,863

Oil and gas properties =

We use the full cost method of accounting for = oil and gas=20 properties and activities. Accordingly, we Capitalize all costs incurred = in=20 connection with the exploration for and development of oil and gas = reserves.=20 Proceeds from the disposition of oil and gas properties are accounted = for as a=20 reduction in Capitalized costs, with no gain or loss generally = recognized unless=20 such dispositions involve a significant alteration in the depletion = rate. We=20 Capitalize internal costs that can be directly identified with = exploration and=20 development activities, but do not include any costs related to = production,=20 general corporate overhead or similar activities. Capitalized costs = include=20 geological and geophysical work, 3D seismic, delay rentals, drilling and = completing and equipping oil and gas wells, including salaries, benefits = and=20 other internal costs directly attributable to these activities. =

In accordance with the full cost method of = accounting,=20 the net Capitalized costs of oil and gas properties are not to exceed = their=20 related estimated future net revenues discounted at 10% (=93PV-10 = value=94), as=20 adjusted for our cash flow hedge positions and net of tax = considerations, plus=20 the lower of cost or estimated fair value of unproved properties. During = the=20 first quarter of 2009, gas prices declined significantly as compared to = the=20 December 31, 2008 spot price of $5.62 per Mcf. Based on = March 31,=20 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=20 the PV-10 value at December 31, 2008. As a result, we recorded a = ceiling=20 test impairment of oil and gas properties of $240,790 during the first = quarter=20 of 2009. The effect of derivative contracts accounted for as cash flow = hedges,=20 based on the March 31, 2009, spot prices, increased the full cost = ceiling=20 by $169,013, thereby reducing the ceiling test write down by the same = amount.=20

The internally estimated PV-10 value of our = reserves was=20 estimated based on spot prices of $69.89 per Bbl of oil and $3.89 per = Mcf of gas=20 at June 30, 2009. The effect of derivative contracts accounted for = as cash=20 flow hedges, based on these June 30, 2009, spot prices, reduced the = full=20 cost ceiling by $12,928. The qualifying cash flow hedges as of = June 30,=20 2009, which consisted of commodity price swaps, covered 4,265 MBbls of = oil=20 production for the period from July 2009 through December 2011. As of=20 June 30, 2009, the cost center ceiling exceeded the net Capitalized = cost of=20 our oil and gas properties, and no ceiling test impairment was recorded = during=20 the second quarter of 2009.

A decline in oil and gas prices subsequent to=20 June 30, 2009, could result in additional ceiling test write downs = in the=20 third quarter of 2009 or in subsequent periods. The amount of any future = impairment is difficult to predict, and will depend on the oil and gas = prices at=20 the end of or during each period, the incremental proved reserves added = during=20 each period, and additional Capital spent.

Table=20 of Contents

Production tax benefit asset =

During 2006, we purchased interests in two = venture=20 Capital limited liability companies resulting in a total investment of = $15,000.=20 Our return on the investment was the receipt of $2 of Oklahoma tax = credits for=20 every $1 invested and was recouped from our Oklahoma production taxes. = The=20 investments are accounted for as a production tax benefit asset and are = netted=20 against tax credits realized in other income using the effective yield = method=20 over the expected recovery period. As of December 31, 2008 and=20 June 30, 2009, the carrying value of the production tax benefit = asset was=20 $13,685 and $43, respectively. Oklahoma production tax credits of $323 = and=20 $2,684, respectively, for the three months ended June 30, 2008 and = 2009 and=20 $688 and $13,544, respectively, for the six months ended June 30, = 2008 and=20 2009 were included in other income in the consolidated statements of = operations.=20

Funds held in escrow

We have funds held in escrow that are = restricted as to=20 withdrawal or usage. The restricted amounts consisted of the following:=20


	December 31, 2008		June 30, 2009
Escrow from acquisitions	$	692		$	=97
Plugging and abandonment = escrow		1,658			1,662

	$	2,350		$	1,662

We are entitled to make quarterly withdrawals = from the=20 plugging escrow account equal to one-half of the interest earnings for = the=20 period and as reimbursement for actual plugging and abandonment expenses = incurred on the North Burbank Unit, provided that written documentation = has been=20 provided. The balance is not intended to reflect our total future = financial=20 obligation for the plugging and abandonment of these wells.

Impairment of long-lived assets =

Impairment losses are recorded on property and = equipment=20 used in operations and other long lived assets when indicators of = impairment are=20 present and the undiscounted cash flows estimated to be generated by = those=20 assets are less than the assets=92 carrying amount. Impairment is = measured based=20 on the excess of the carrying amount over the fair value of the asset.=20

Asset retirement obligations =

We account for asset retirement obligations in = accordance=20 with SFAS No. 143, Accounting for Asset Retirement = Obligations,=20 which requires entities to record the fair value of a liability for an = asset=20 retirement obligation in the period in which it is incurred and a = corresponding=20 increase in the carrying amount of oil and gas properties. The accretion = of the=20 asset retirement obligations is included in depreciation, depletion and=20 amortization on the consolidated statements of operations. Our asset = retirement=20 obligations consist of the estimated present value of future costs to = plug and=20 abandon or otherwise dispose of our oil and gas properties and related=20 facilities. Significant inputs used in determining such obligations = include=20 estimates of plugging and abandonment costs, inflation rates, and well = life, all=20 of which are Level 3 inputs according to the SFAS 157 fair value = hierarchy.=20 These estimates may change based upon future inflation rates and changes = in=20 statutory remediation rules.

Deferred income taxes

Deferred income taxes are provided for = significant=20 carryforwards and temporary differences between the tax basis of an = asset or=20 liability and its reported amount in the financial statements that will = result=20 in taxable or deductible amounts in future years. Deferred income tax = assets or=20 liabilities are determined by applying the presently enacted tax rates = and laws.=20 We record a valuation allowance for the amount of net deferred tax = assets when,=20 in management=92s opinion, it is more likely than not that such assets = will not be=20 realized.

We account for uncertain tax positions in = accordance with=20 FASB Interpretation No. 48, Accounting for Uncertainty in Income = Taxes=97An Interpretation of FASB Statement No. 109 (=93FIN = 48=94). If=20 applicable, we would report a liability for tax benefits resulting from=20 uncertain tax positions taken or expected to be taken in a tax return, = and would=20 recognize interest and penalties related to uncertain tax positions in = interest=20 expense. As of December 31, 2008 and June 30, 2009, we have = not=20 recorded a liability or accrued interest related to uncertain tax = positions.=20

The tax years 1998 through 2009 remain open to=20 examination for federal income tax purposes and by the other major = taxing=20 jurisdictions to which we are subject.

Table=20 of Contents

Recently issued accounting standards=20

In December 2007, the FASB issued SFAS = No. 141=20 (revised 2007), Business Combinations (=93SFAS 141(R)=94), which = replaces=20 FASB Statement No. 141. SFAS 141(R) establishes principles and = requirements=20 for how an acquirer recognizes and measures in its financial statements = the=20 identifiable assets acquired, the liabilities assumed, any = non-controlling=20 interest in the acquiree and the goodwill acquired. SFAS No. 141(R) = also=20 establishes disclosure requirements that will enable users to evaluate = the=20 nature and financial effects of the business combination. SFAS 141(R) is = effective for acquisitions that occur in an entity=92s fiscal year that = begins=20 after December 15, 2008. We adopted the provisions of SFAS 141(R) = effective=20 January 1, 2009. This statement will apply prospectively to future = business=20 combinations, and did not have an effect on our reported financial = position or=20 results of operations.

In March 2008, the FASB issued SFAS = No. 161,=20 Disclosures about Derivative Instruments and Hedging Activities =96 an = amendment=20 of FASB Statement No. 133 (=93SFAS 161=94). SFAS 161 addresses = concerns=20 that the existing disclosure requirements in SFAS 133 do not provide = adequate=20 information about how derivative and hedging activities affect an = entity=92s=20 financial position, financial performance, and cash flows. Accordingly, = this=20 statement requires enhanced disclosures about an entity=92s derivative = and hedging=20 activities and thereby improves the transparency of financial reporting. = This=20 statement is effective for financial statements issued for fiscal years = and=20 interim periods beginning after November 15, 2008. We adopted the=20 disclosure requirements of SFAS 161 beginning January 1, 2009. The = adoption=20 of this statement did not have an impact on our financial position or = results of=20 operations.

In December 2008, the SEC issued Release=20 No. 33-8995, Modernization of Oil and Gas Reporting, which = revises=20 disclosure requirements for oil and gas companies. The new disclosure=20 requirements permit the use of new technologies to determine proved = reserves if=20 those technologies have been demonstrated empirically to lead to = reliable=20 conclusions about reserve volumes. The new disclosure requirements also = require=20 companies to include nontraditional resources such as oil sands, shale, = coal=20 beds or other nonrenewable natural resources in reserves if they are = intended to=20 be upgraded to synthetic oil and gas. Currently the SEC requires that = reserve=20 volumes are determined using prices on the last day of the reporting = period;=20 however, the new disclosure requirements provide for reporting oil and = gas=20 reserves using an average price based upon the first day of each month = for the=20 prior twelve months rather than year-end prices. The new requirements = will also=20 allow companies to disclose their probable and possible reserves to = investors,=20 and will require them to report the independence and qualifications of = their=20 reserves preparer or auditor. The new rule is effective for annual = reports on=20 Form 10-K for fiscal years ending on or after December 31, 2009, = pending=20 the potential alignment of certain accounting standards by the FASB with = the new=20 rule. We will adopt the provisions of the new rule in connection with = our=20 December 31, 2009 Form 10-K filing. We are currently evaluating the = impact=20 of the rule on our financial statements.

In May 2009, the FASB issued SFAS No. 165, = Subsequent Events (=93SFAS 165=94). SFAS 165 establishes general = standards of=20 accounting for and disclosure of events that occur after the balance = sheet date=20 but before financial statements are issued or are available to be = issued.=20 Although there is new terminology, the standard is based on the same = principles=20 as those that currently exist. This statement, which includes a new = required=20 disclosure of the date through which an entity has evaluated subsequent = events,=20 is effective for interim or annual periods ending after June 15, = 2009. We=20 adopted the statement for the period ending June 30, 2009. The = adoption of=20 this statement did not have an impact on our financial position or = results of=20 operations.

Subsequent events

As of August 13, 2009, which is the date = these=20 financial statements were issued, there are no additional material = subsequent=20 events requiring additional disclosure in or amendment to these = financial=20 statements.

Note 2: Discontinued operations =

During the second quarter of 2009, we committed = to a plan=20 to sell the assets of Green Country Supply, Inc. (=93GCS=94), a wholly = owned=20 subsidiary that provides oilfield supplies, oilfield chemicals, downhole = electric submersible pumps, and related services to oil and gas = operators=20 primarily in Oklahoma, Texas, and Wyoming.

On May 14, 2009, we entered into an = agreement to=20 sell the assets of the Electric Submersible Pumps Division of GCS (the = =93ESP=20 Division=94) to Global Oilfield Services, Inc. (=93Global=94) for a cash = price of=20 $26,000, subject to working Capital adjustments as provided in the = agreement. On=20 June 8, 2009, we received $24,650 in conjunction with the closing = of the=20 ESP Division sale to Global. The amount received reflected a reduction = of $1,350=20 due to working Capital changes as of March 31, 2009. We paid off = notes=20 payable attributed to certain assets sold to Global in the amount of = $1,605. The=20 purchase price is subject to a final working Capital adjustment on or = before=20 August 27, 2009. As of June 30, 2009, we recorded a pre-tax = gain=20 associated with the sale of $9,004. All taxable income associated with = such gain=20 was offset by existing net operating losses.


	Three = months=20 ended June 30,			Six months = ended June 30,
	2008			2009			2008		2009
Revenues	$	8,331			$	3,314		$	16,070		$	8,113
Operating expenses		(7,896	)			(3,476	)		(15,240	)		(8,181	)
Gain on sale		=97				9,004			=97			9,004

Income before income = taxes		435				8,842			830			8,936
Income tax provision		(166	)			(3,403	)		(319	)		(3,439	)

Income from discontinued = operations	$	269			$	5,439		$	511		$	5,497

At December 31, 2008 and June 30, = 2009, the=20 assets and liabilities of GCS are classified as assets held for sale and = liabilities associated with discontinued operations, respectively, on = our=20 consolidated balance sheets.

Table=20 of Contents

Note 3: Derivative activities and financial=20 instruments

Derivative activities

Our results of operations, financial condition = and=20 Capital resources are highly dependent upon the prevailing market prices = of, and=20 demand for, oil and gas. These commodity prices are subject to wide = fluctuations=20 and market uncertainties. To mitigate a portion of this exposure, we = enter into=20 commodity price swaps, costless collars, and basis protection swaps. For = commodity price swaps, we receive a fixed price for the hedged commodity = and pay=20 a floating market price to the counterparty. The fixed-price payment and = the=20 floating-price payment are offset, resulting in a net amount due to or = from the=20 counterparty.

Collars contain a fixed floor price (put) and = ceiling=20 price (call). If the market price exceeds the call strike price or falls = below=20 the put strike price, we receive the fixed price and pay the market = price. If=20 the market price is between the call and the put strike price, no = payments are=20 due from either party. Our collars have not been designated as hedges = pursuant=20 to SFAS 133. Therefore, the changes in fair value and settlement of = these=20 derivative contracts are recognized as non-hedge derivative gains = (losses). This=20 can have a significant impact on our results of operations due to the = volatility=20 of the underlying commodity prices.

We use basis protection swaps to reduce basis = risk. Basis=20 is the difference between the physical commodity being hedged and the = price of=20 the futures contract used for hedging. Basis risk is the risk that an = adverse=20 change in the futures market will not be completely offset by an equal = and=20 opposite change in the cash price of the commodity being hedged. Basis = risk=20 exists in natural gas primarily due to the geographic price = differentials=20 between cash market locations and futures contract delivery locations. = Natural=20 gas basis protection swaps are arrangements that guarantee a price = differential=20 for gas from a specified pricing point. We receive a payment from the=20 counterparty if the price differential is greater than the stated terms = of the=20 contract and pay the counterparty if the price differential is less than = the=20 stated terms of the contract. We do not believe that these instruments = qualify=20 as hedges pursuant to SFAS 133; therefore, the changes in fair value and = settlement of these derivative contracts are recognized as non-hedge = derivative=20 gains (losses).

As part of the Calumet acquisition, we assumed = the=20 existing Calumet swaps on October 31, 2006 and designated these as = cash=20 flow hedges. In accordance with SFAS No. 141, Business = Combinations, these=20 derivative positions were recorded at fair value in the purchase price=20 allocation as a liability of $838. Because of this accounting treatment, = only=20 cash settlements for changes in fair value subsequent to the acquisition = date=20 for the derivative positions assumed result in adjustments to our oil = and gas=20 revenues upon settlement. For example, if the fair value of the = derivative=20 positions assumed does not change, then upon the sale of the underlying=20 production and corresponding settlement of the derivative positions, = cash would=20 be paid to the counterparties and there would be no adjustment to oil = and gas=20 revenues related to the derivative positions. If, however, the actual = sales=20 price is different from the price assumed in the original fair value=20 calculation, the difference would be reflected as either a decrease or = increase=20 in oil and gas revenues, depending upon whether the sales price was = higher or=20 lower, respectively, than the price assumed in the original fair value=20 calculation.

Pursuant to SFAS 133, the change in fair value = of the=20 acquired cash flow hedges from the date of acquisition is recorded as a=20 component of accumulated other comprehensive income. In addition, the = hedge=20 instruments are deemed to contain a significant financing element, and = all cash=20 flows associated with these positions are reported as a financing = activity in=20 the consolidated statement of cash flows for the periods in which = settlement=20 occurs. All of these positions were settled as of December 31, = 2008.=20

Table=20 of Contents

Our outstanding oil and gas derivative = instruments as of=20 June 30, 2009, are summarized below:


	Oil=20 derivatives
	Swaps	Collars
	Volume MBbl	Weighted average fixed price to=20 be received		Volume MBbl		Weighted average range=20 to be received
2009	1,304	$	67.32		120		$	110.00 - $164.28
2010	2,277		67.07		240			110.00 - = 168.55
2011	1,605		63.86		204			110.00 - = 152.71

	5,186				564


	Gas=20 derivatives	Natural gas=20 basis protection=20 swaps
	Swaps	Collars
	Volume BBtu	Weighted average fixed price = to=20 be received		Volume BBtu		Weighted average range to=20 be received		Volume BBtu	Weighted average fixed price = to=20 be paid
2009	4,490	$	8.09		1,980		$	10.00 - $13.85	9,060	$	0.92
2010	12,600		7.43		3,360			10.00 - 11.53	15,050		0.84
2011	9,600		7.42		=97				11,250		0.77

	26,690				5,340				35,360

All derivative financial instruments are = recorded on the=20 balance sheet at fair value. The fair value of swaps is generally = determined=20 based on the difference between the fixed contract price and the = underlying=20 published forward market price. The fair value of collars is determined = using an=20 option pricing model which takes into account market volatility, market = prices,=20 and contract parameters. Derivative instruments are discounted using a = rate that=20 incorporates our nonperformance risk for derivative liabilities, and our = counterparties=92 credit risk for derivative assets. Our derivative = contracts have=20 been executed with the institutions that are parties to our revolving = credit=20 facility. We believe the credit risks associated with all of these=20 institutions are acceptable. None of our derivative contracts have = margin=20 requirements, collateral provisions, or other credit-risk-related = contingent=20 features that would require funding prior to the scheduled cash = settlement date.=20

The estimated fair values of derivative = instruments are=20 provided below. The carrying amounts of these instruments are equal to = the=20 estimated fair values.


	As of=20 December 31, 2008		As of = June 30,=20 2009
	Assets		Liabilities			Net=20 Value	Assets		Liabilities			Net=20 Value
Derivatives designated as cash flow=20 hedges:
Oil swaps	$	116,311		$	(5,631	)	$	110,680		$	1,104		$	(36,759	)	$	(35,655	)
Derivatives not designated as hedging=20 instruments:
Gas swaps		14,043			(731	)		13,312			36,786			=97			36,786
Oil swaps		2,424			(1,688	)		736			=97			(9,558	)		(9,558	)
Gas collars		21,682			=97			21,682			23,990			=97			23,990
Oil collars		57,716			=97			57,716			19,239			=97			19,239
Natural gas basis differential = swaps		2,093			(475	)		1,618			=97			(8,618	)		(8,618	)

Total non-hedge = instruments		97,958			(2,894	)		95,064			80,015			(18,176	)		61,839

Total derivative = instruments		214,269			(8,525	)		205,744			81,119			(54,935	)		26,184
Less:
Netting adjustments (1)		5,137			(5,137	)		=97			27,049			(27,049	)		=97
Current portion asset = (liability)		51,412			=97			51,412			37,939			(5,420	)		32,519

	$	157,720		$	(3,388	)	$	154,332		$	16,131		$	(22,466	)	$	(6,335	)

(1)	Amounts=20 represent the impact of legally enforceable master netting = agreements that=20 allow us to net settle positive and negative positions with the = same=20 counterparties.

Table=20 of Contents

Changes in the fair value of effective cash = flow hedges=20 are recorded as a component of accumulated other comprehensive income = (=93AOCI=94),=20 which is later transferred to earnings when the hedged transaction = occurs. The=20 ineffective portion is calculated as the difference between the change = in fair=20 value of the derivative and the estimated change in cash flows from the = item=20 hedged, and is included in gain (loss) from oil and gas hedging = activities in=20 the consolidated statements of operations. If it is probable the oil or = gas=20 sales which are hedged will not occur, hedge accounting is discontinued = and the=20 gain or loss reported in AOCI is immediately reclassified into income. = If a=20 derivative which qualified for cash flow hedge accounting ceases to be = highly=20 effective, or is liquidated or sold prior to maturity, hedge accounting = is=20 discontinued. The gain or loss associated with the discontinued hedges = remains=20 in AOCI and is reclassified into income as the hedged transactions = occur.=20

Gains and losses associated with cash flow = hedges are=20 summarized below.


	Three months ended June 30,			Six months ended June 30,
	2008			2009			2008		2009
Amount of gain (loss) recognized in AOCI = (effective=20 portion)
Oil swaps	$	(256,728	)		$	(57,944	)	$	(303,752	)	$	(59,444	)
Gas swaps		(24,866	)			=97			(44,729	)		=97
Income taxes		108,926				22,402			134,802			22,993

	$	(172,668	)		$	(35,542	)	$	(213,679	)	$	(36,451	)

Amount of gain (loss) reclassified from = AOCI in=20 income (effective portion)(1)
Oil swaps	$	(25,647	)		$	6,761		$	(41,297	)	$	19,072
Gas swaps		(7,065	)			1,758			(6,215	)		4,645
Income taxes		12,653				(3,190	)		18,379			(9,174	)

	$	(20,059	)		$	5,329		$	(29,133	)	$	14,543

Amount of loss recognized in income = (ineffective=20 portion)(1)
Oil swaps	$	(11,747	)		$	(2,331	)	$	(14,399	)	$	(2,026	)
Gas swaps		(13,771	)			=97			(27,444	)		=97

	$	(25,518	)		$	(2,331	)	$	(41,843	)	$	(2,026	)

(1)	Included in=20 gain (loss) from oil and gas hedging activities in the = consolidated=20 statements of operations.

During the fourth quarter of 2008, we = determined that our=20 gas swaps are no longer expected to be highly effective, primarily due = to the=20 increased volatility in the basis differentials between the contract = price and=20 the indexed price at the point of sale. As a result, we discontinued = hedge=20 accounting and applied mark-to-market accounting treatment to all = outstanding=20 gas swaps. The change in fair value related to these instruments, after = hedge=20 accounting was discontinued, is recorded immediately in non-hedge = derivative=20 gains (losses) in the consolidated statements of operations. In the = past, a=20 portion of the change in fair value would have been deferred through = other=20 comprehensive income and the ineffective portion would have been = included in=20 gain (loss) from oil and gas hedging activities.

In addition, during the fourth quarter of 2008, = we early=20 settled oil and gas swaps and collars with original settlement dates = from=20 January through June of 2009 for proceeds of $32,589. During the first = quarter=20 of 2009, we early settled additional gas swaps with original settlement = dates=20 from May through October of 2009 for proceeds of $9,522. During the = second=20 quarter of 2009, we early settled additional oil swaps and collars with = original=20 settlement dates from January 2012 through December 2013 for proceeds of = $102,352. Certain swaps that were early settled had previously been = accounted=20 for as cash flow hedges. As of December 31, 2008, and June 30, = 2009,=20 accumulated other comprehensive income included $23,662 and $86,436,=20 respectively, of deferred gains related to discontinued cash flow hedges = that=20 will be recognized as a gain from oil and gas hedging activities when = the hedged=20 production is sold. No oil and gas derivatives were early settled during = the=20 first six months of 2008.

Gains of $7,887 and $19,159 associated with = derivatives=20 for which hedge accounting had previously been discontinued, were = reclassified=20 into earnings during the three and six months ended June 30, 2009, = respectively,=20 as the hedged production was sold. There were no gains or losses = associated with=20 the discontinuance of hedge accounting treatment during the three and = six months=20 ended June 30, 2008. Gain (loss) from oil and gas hedging = activities, which=20 is a component of total revenues in the consolidated statements of = operations,=20 is comprised of the following:


	Three = months=20 ended June 30,			Six months = ended June 30,
	2008			2009			2008		2009
Oil derivatives
Reclassification adjustment for hedge = gains=20 (losses) included in net loss	$	(25,647	)		$	6,761		$	(41,297	)	$	19,072
Loss on ineffective portion of = derivatives=20 qualifying for hedge accounting		(11,747	)			(2,331	)		(14,399	)		(2,026	)
Gas derivatives
Reclassification adjustment for hedge = gains=20 (losses) included in net loss		(7,065	)			1,758			(6,215	)		4,645
Loss on ineffective portion of = derivatives=20 qualifying for hedge accounting		(13,771	)			=97			(27,444	)		=97

Total	$	(58,230	)		$	6,188		$	(89,355	)	$	21,691

Table=20 of Contents

Based upon market prices at June 30, 2009, = and=20 assuming no future change in the market, we expect to reclassify $4,641 = of the=20 balance in accumulated other comprehensive income to income during the = next 12=20 months when the forecasted transactions actually occur. All forecasted=20 transactions hedged as of June 30, 2009, are expected to be settled = by=20 December 2011.

The changes in fair value and settlement of = derivative=20 contracts that do not qualify or have not been designated as hedges in=20 accordance with SFAS 133 are recognized as non-hedge derivative gains = (losses).=20 All non-hedge derivative contracts outstanding at June 30, 2009, = are=20 expected to be settled by December 2011. Non-hedge derivative gains = (losses) in=20 the consolidated statements of operations are comprised of the = following:=20


	Three = months=20 ended June 30,			Six months = ended June 30,
	2008			2009			2008		2009
Change in fair value of non-qualified = commodity=20 price swaps	$	(51,058	)		$	(98,665	)	$	(58,880	)	$	(68,753	)
Change in fair value of non-designated = costless=20 collars		(8,557	)			(39,331	)		(8,557	)		(36,169	)
Change in fair value of natural gas basis = differential contracts		3,119				(5,910	)		4,815			(10,236	)
Receipts from (payments on) settlement of = non-qualified commodity price swaps		(3,380	)			84,499			(5,206	)		99,229
Receipts from settlement of = non-designated costless=20 collars		=97				27,267			=97			32,345
Receipts from (payments on) settlement of = natural=20 gas basis differential contracts		1,377				(879	)		647			892

	$	(58,499	)		$	(33,019	)	$	(67,181	)	$	17,308

Derivative settlements receivable of $15,315 = and $4,146=20 were included in accounts receivable at December 31, 2008 and = June 30,=20 2009, respectively. Derivative settlements payable of $0 and $3,617 were = included in accounts payable and accrued liabilities at = December 31, 2008=20 and June 30, 2009, respectively.

We have no Level 1 assets or liabilities as of=20 June 30, 2009. Our derivative contracts classified as Level 2 are = valued=20 using quotations provided by price index developers such as Platts and = Oil Price=20 Information Service. In certain less liquid markets, forward prices are = not as=20 readily available. In these circumstances, commodity swaps are valued = using=20 internally developed methodologies that consider historical = relationships among=20 various commodities that result in management=92s best estimate of fair = value.=20 These contracts are classified as Level 3. Due to unavailability of = observable=20 volatility data input, the fair value measurement of all our collars has = been=20 categorized as Level 3.

The fair value hierarchy for our financial = assets and=20 liabilities as of December 31, 2008 and June 30, 2009, = accounted for=20 at fair value on a recurring basis is shown by the following tables. =


	As of=20 December 31, 2008		As of = June 30,=20 2009
	Derivative assets			Derivative liabilities			Net=20 assets (liabilities)	Derivative assets		Derivative liabilities			Net=20 assets (liabilities)
Significant other observable inputs = (Level=20 2)	$	134,666			$	(8,525	)	$	126,141	$	37,890			$	(54,935	)	$	(17,045	)
Significant unobservable inputs (Level=20 3)		79,603				=97			79,603		43,229				=97			43,229
Netting adjustments (1)		(5,137	)			5,137			=97		(27,049	)			27,049			=97

	$	209,132			$	(3,388	)	$	205,744	$	54,070			$	(27,886	)	$	26,184

(1)	Amounts=20 represent the impact of legally enforceable master netting = agreements that=20 allow us to net settle positive and negative positions with the = same=20 counterparties.

Table=20 of Contents

Changes in the fair value of net commodity = derivatives=20 classified as Level 3 in the fair value hierarchy at June 30, 2009, = were:=20


Six months ended June 30, = 2009	Net derivative assets
Beginning balance	$	79,603
Total realized and unrealized gains = included in=20 non-hedge derivative gains (losses)		(3,739	)
Purchases, issuances, and = settlements		(32,635	)

Ending balance	$	43,229

The amount of total gains for the period = included=20 in non-hedge derivative gains (losses) attributable to the change = in=20 unrealized gains relating to assets still held at the reporting=20 date	$	1,632

Fair value of financial instruments=20

The carrying values of items = comprising current=20 assets and current liabilities, other than derivatives, approximate fair = values=20 due to the short-term maturities of these instruments. The carrying = value for=20 long-term debt at December 31, 2008, and June 30, 2009, = approximates=20 fair value because substantially all debt carries variable market rates. = Based=20 on market prices, at December 31, 2008, the fair value of the = 8 1/2 %=20 Senior Notes and 8 7/8 %=20 Senior Notes were $73,125 and $73,125, respectively. Based on market = prices, at=20 June 30, 2009, the fair value of the 8 1/2 %=20 Senior Notes and 8 7/8 %=20 Senior Notes were $201,500 and $201,500, respectively.=20

Fair value amounts have been estimated using = available=20 market information. The use of different market assumptions or valuation = methodologies may have a material effect on the estimated fair value = amounts.=20

Note 4: Asset retirement obligations =

The following table provides a summary of our = asset=20 retirement obligations for June 30, 2009.


	Six months ended June 30, 2009
Beginning balance	$	33,375
Liabilities incurred in current=20 period		300
Liabilities settled in current = period		(89	)
Accretion expense		1,426

	$	35,012
Less current portion		300

	$	34,712

Table=20 of Contents

Note 5: Long-term debt

Long-term debt at December 31, 2008, and=20 June 30, 2009, consisted of the following:


	December 31, 2008		June 30, 2009
Revolving credit line with = banks	$	594,000		$	507,001
Real estate mortgage notes, principal and = interest=20 payable monthly, bearing interest at rates ranging from 5.50% to = 7.283%,=20 due February 2011 through January 2029; collateralized by real=20 property		13,806			13,676
Installment notes payable, principal and = interest=20 payable monthly, bearing interest at rates ranging from 4.594% to = 9.658%,=20 due July 2009 through November 2013; collateralized by = automobiles,=20 machinery and equipment		13,140			10,457

		620,946			531,134
Less current maturities		5,301			4,770

	$	615,645		$	526,364

In October 2006, we entered into a Seventh = Restated=20 Credit Agreement, which is scheduled to mature on October 31, 2010, = and is=20 collateralized by our oil and gas properties. Availability under our = credit=20 agreement is subject to a borrowing base which is set by the banks = semi-annually=20 on May 1 and November 1 of each year. In addition, the lenders = may=20 request a borrowing base redetermination once every six months. As a = result of=20 our early settlement of derivatives in the second quarter of 2009, the = borrowing=20 base was reduced from $600,000 to $513,001 effective June 8, 2009.=20

Interest was paid at least every three months = during 2008=20 and 2009. The effective rate of interest on the entire outstanding = balance was=20 5.299% and 5.937% as of December 31, 2008 and June 30, 2009,=20 respectively, and was based upon LIBOR.

The Credit Agreement has certain negative and = affirmative=20 covenants that require, among other things, maintaining financial = covenants for=20 current and debt service ratios and financial reporting. The Credit = Agreement,=20 as amended effective May 21, 2009, requires us to maintain a = Consolidated=20 Senior Total Debt to Consolidated EBITDAX ratio, as defined in our = Credit=20 Agreement, of not greater than:

=95

2.50 to = 1.0 for the four=20 consecutive fiscal quarters ending on March 31, 2009;=20

=95

3.00 to = 1.0 for the four=20 consecutive fiscal quarters ending on June 30,=20 2009, September 30, 2009, December 31, 2009, = and=20 March 31, 2010; and

=95

2.75 to = 1.0 for the four=20 consecutive fiscal quarters ending on June 30,=20 2010, September 30, 2010, and December 31, 2010.=20

For purposes of the amended ratio, Consolidated = Senior=20 Total Debt consists of all outstanding loans under the Credit Agreement, = letters=20 of credit and all obligations under Capital leases, minus cash on hand = in excess=20 of accounts payable and accrued liabilities that are more than 90 days = past the=20 invoice date, as defined in the Fifth Amendment to our Credit Agreement. =

The Credit Agreement, as amended, also requires = us to=20 limit the aggregate amount of our Capital expenditures incurred during = the=20 period beginning April 1, 2009 and ending December 31, 2009 to = our=20 discretionary cash flows for the period. Discretionary cash flows = consist of=20 Consolidated EBITDAX minus interest expense and taxes paid during the = period, as=20 defined in the Fifth Amendment to our Credit Agreement.

We believe we were in compliance with all = covenants under=20 the Credit Agreement as of June 30, 2009.

The Credit Agreement also specifies events of = default,=20 including non-payment, breach of warranty, non-performance of financial=20 covenants, default on other indebtedness, certain adverse judgments, and = change=20 of control, among others. In addition, bankruptcy and insolvency events = with=20 respect to us or certain of our subsidiaries will result in an automatic = acceleration of the indebtedness under the Credit Agreement. An = acceleration of=20 our indebtedness under the Credit Agreement could in turn result in an = event of=20 default under the indentures for our Senior Notes, which in turn could = result in=20 the acceleration of the Senior Notes.

Our Credit Agreement is scheduled to mature on=20 October 31, 2010. If we are not able to extend the maturity of our = Credit=20 Agreement before October 31, 2009, the entire balance then = outstanding=20 would be classified as a current liability. Borrowings under our Credit=20 Agreement are excluded from the Credit Agreement definition of current=20 liabilities. We do not expect current classification of the borrowings = to impact=20 our current ratio as calculated for loan compliance.

If our borrowing base amount is reduced by the = banks, or=20 if we expect to be unable to meet our required Current Ratio, or our = required=20 Consolidated Senior Total Debt to Consolidated EBITDAX ratio, we could = reduce=20 our debt amount by early settling additional derivative contracts, = selling oil=20 and gas assets, selling non-oil and gas assets, or raising equity. There = is no=20 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=20 adequately reduce the borrowing base, or that we will be able to meet = our future=20 obligations to the banks.

Table=20 of Contents

Note 6: Related party transactions =

In September 2006, Chesapeake Energy = Corporation, now CHK=20 Holdings, L.L.C., (=93Chesapeake=94) acquired a 31.9% beneficial = interest in the=20 Company through the sale of common stock. We participate in ownership of = properties operated by Chesapeake and received revenues and incurred = joint=20 interest billings on these properties of: $2,296 and $512, respectively, = for the=20 three months ended June 30, 2008; $972 and $750, respectively, for = the=20 three months ended June 30, 2009; $4,468 and $1,330, respectively, = for the=20 six months ended June 30, 2008; and $2,636 and $2,136 respectively, = for the=20 six months ended June 30, 2009. In addition, Chesapeake = participates in=20 ownership of properties operated by us. We paid revenues and recorded = joint=20 interest billings to Chesapeake of: $489 and $397, respectively, during = the=20 three months ended June 30, 2008; $236 and $642, respectively, = during the=20 three months ended June 30, 2009; $1,113 and $1,475, respectively, = during=20 the six months ended June 30, 2008, and $620 and $1,830, = respectively,=20 during the six months ended June 30, 2009. Amounts receivable from = and=20 payable to Chesapeake were $1,914 and $1,188, respectively, as of=20 December 31, 2008. Amounts receivable from and payable to = Chesapeake were=20 $2,014 and $1,486, respectively, as of June 30, 2009.

Note 7: Deferred compensation =

Effective January 1, 2004, we implemented = a Phantom=20 Unit Plan, which was revised on January 1, 2007, as the First = Amended and=20 Restated Phantom Stock Plan (the =93Plan=94) to provide deferred = compensation to=20 certain key employees (the =93Participants=94). Phantom stock may be = awarded to=20 participants in total up to 2% of the fair market value of the Company. = No=20 participant may be granted, in the aggregate, more than 5% of the = maximum number=20 of phantom shares available for award. Under the current plan, awards = vest on=20 the fifth anniversary of the award date, but may also vest on a pro-rata = basis=20 following a participant=92s termination of employment with us due to = death,=20 disability, retirement or termination by us without cause. Also, phantom = stock=20 will vest if a change of control event occurs. Upon vesting, = participants are=20 entitled to redeem their phantom stock for cash within 120 days of the = vesting=20 date.

Since the phantom stock is a liability award, = fair value=20 of the stock is remeasured at the end of each reporting period until = settlement=20 in accordance with the provisions of SFAS No. 123(R), Share = Based=20 Payments (=93SFAS 123(R)=94). As prescribed by the Plan, fair market = value is=20 calculated based on the Company=92s total asset value less total = liabilities, with=20 both assets and liabilities being adjusted to fair value. The primary = adjustment=20 required is the adjustment of oil and gas properties from net book value = to the=20 discounted and risk adjusted reserve value based on internal reserve = reports=20 priced on NYMEX forward strips.

Compensation expense is recognized over the = vesting=20 period of the phantom stock and is reflected in lease operating and = general and=20 administrative expenses in the consolidated statements of operations. = Such=20 expense is calculated net of forfeitures estimated based on our = historical and=20 expected turnover rates. We recognized deferred compensation expense as = follows:=20


	Three months ending			Six months = ending
	June 30, 2008			June 30, 2009			June 30, 2008		June 30, 2009
Deferred compensation = cost	$	3,135			$	706		$	3,566		$	940
Less: deferred compensation cost=20 Capitalized		(1,029	)			(232	)		(1,173	)		(309	)

Deferred compensation = expense	$	2,106				474		$	2,393			631

A summary of our phantom unit activity as of=20 December 31, 2008, and changes during the first six months of = fiscal year=20 2009 is 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,=20 2008	$	10.22		219,658
Granted	$	10.08		31,965
Vested	$	10.08		(77,224	)
Forfeited	$	10.22		(1,640	)

Unvested and total outstanding at June = 30,=20 2009	$	19.05		172,759			2.29		$	3,291

As of June 30, 2009, there was = approximately $1,579=20 of total unrecognized compensation cost related to unvested phantom = units that=20 is expected to be recognized over a weighted-average period of 2.29 = years. As of=20 December 31, 2008 and June 30, 2009, accrued payroll and = benefits=20 payable included $789 and $897, respectively, for deferred compensation = costs=20 vesting within the next twelve months.

Table=20 of Contents

Note 8: Commitments and contingencies =

Standby letters of credit (=93Letters=94) = available under the=20 revolving credit line are used in lieu of surety bonds with various = city, state=20 and federal agencies for liabilities relating to the operation of oil = and gas=20 properties. We had various Letters outstanding totaling $2,730 and = $2,880 as of=20 December 31, 2008, and June 30, 2009, respectively. Interest = on each=20 Letter accrues at the lender=92s prime rate (effective rate of 5.299% at = December 31, 2008, and 5.937% at June 30, 2009) for all = amounts paid=20 by the lenders under the Letters. We paid no interest on the Letters = during the=20 three and six months ended June 30, 2008 and 2009.

Various claims and lawsuits, incidental to the = ordinary=20 course of business, are pending both for and against us. In the opinion = of=20 management, all matters are not expected to have a material effect on = our=20 consolidated financial position or results of operations.

Effective April 15, 2009, we settled our = pending=20 lawsuit against John Milton Graves Trust u/t/a 6/11/2004, et al. This = case was=20 filed in the District Court of Tulsa County, State of Oklahoma, and = related to=20 (i) a post-closing adjustment of the price we paid for Calumet Oil = Company=20 (=93Calumet=94) in 2006 (the =93Working Capital Adjustment=94) and = (ii) a=20 contractual payment related to an election to be made by the sellers of = Calumet=20 (collectively, the =93Sellers=94) under the federal tax code (the =93Tax = Election=94).=20 Pursuant to the settlement agreement, which was based upon net = calculations of=20 the receivable and payable, the Sellers paid us $7,100, which amount is = intended=20 to settle all claims related to both the Working Capital Adjustment and = the Tax=20 Election claims, and we retained $387 contained in an escrow account = covering=20 any losses incurred by us for title defects related to our purchase of = Calumet.=20 In addition, the parties issued mutual releases, dismissed with = prejudice the=20 pending litigation and the claims made therein, and the Sellers will = take action=20 to clear the title to certain properties purchased by us in the Calumet=20 acquisition.

As of December 31, 2008, the recorded = receivable for=20 the Working Capital Adjustment was $14,406, and was included in other = assets on=20 the consolidated balance sheet. As of December 31, 2008, the = recorded=20 payable related to the Tax Election was $4,378, and was included in = accounts=20 payable and accrued liabilities on the consolidated balance sheet. As a = result=20 of the settlement, as of June 30, 2009, the receivable related to = the=20 Working Capital Adjustment and the Tax Election payable were eliminated, = the=20 escrow cash account was reclassified to operating cash, and we recorded = a charge=20 to expense of $2,928.

In February 2008, loss of well control occurred = at the=20 Bowdle 47 No. 2 well in Loving County, Texas. Total costs = attributable to=20 the loss of well control were approximately $10,648. Our insurance = policy has=20 covered 100% of these costs, with the $627 insurance retention and = deductible=20 being payable by us. As of June 30, 2009, we have received = insurance=20 proceeds of $10,021, and no further receipts are expected. Insurance = proceeds=20 received are recorded as a reduction of oil and gas properties on the = balance=20 sheet and in the statement of cash flows.

Note 9: Comprehensive loss

Components of comprehensive loss, net of = related tax, are=20 as follows for the three and six months ended June 30, 2008, and = 2009:=20


	Three months ended June 30,			Six months = ended June 30,
	2008			2009			2008		2009
Net loss	$	(30,052	)		$	(17,724	)	$	(33,019	)	$	(142,548	)
Unrealized loss on hedges		(172,668	)			(35,542	)		(213,679	)		(36,451	)
Reclassification adjustment for hedge = (gains)=20 losses included in net loss		20,059				(5,329	)		29,133			(14,543	)

Comprehensive loss	$	(182,661	)		$	(58,595	)	$	(217,565	)	$	(193,542	)

Table=20 of Contents

ITEM 2.

MANAGEMENT=92S DISCUSSION = AND ANALYSIS=20 OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS=20

The following discussion is intended to assist = you in=20 understanding our business and results of operations together with our = present=20 financial condition. This section should be read in conjunction with our = consolidated financial statements and the accompanying notes included = elsewhere=20 in this report.

Statements in our discussion may be = forward-looking=20 statements. These forward-looking statements involve risks and = uncertainties. We=20 caution that a number of factors could cause future production, revenues = and=20 expenses to differ materially from our expectations.

Overview =

We are an independent oil and gas company = engaged in the=20 production, acquisition, and exploitation of oil and gas properties. Our = areas=20 of operation include the Mid-Continent, Permian Basin, Gulf Coast, = Ark-La-Tex,=20 North Texas, and the Rocky Mountains. We maintain a portfolio of proved = and=20 unproved reserves, development and exploratory drilling opportunities, = and EOR=20 projects.

Our revenues, profitability and future growth = depend=20 substantially on prevailing prices for oil and gas and on our ability to = find,=20 develop and acquire oil and gas reserves that are economically = recoverable. The=20 preparation of our financial statements in conformity with generally = accepted=20 accounting principles (=93GAAP=94) requires us to make estimates and = assumptions=20 that affect our reported results of operations and the amount of our = reported=20 assets, liabilities and proved oil and gas reserves. We use the full = cost method=20 of accounting for our oil and gas activities.

Generally our producing properties have = declining=20 production rates. Our reserve estimates as of December 31, 2008, = reflect=20 that our production rate on current proved developed producing reserve=20 properties will decline at annual rates of approximately 17.0%, 11.4%, = and 10.8%=20 for the next three years. To grow our production and cash flow we must = find,=20 develop, and acquire new oil and gas reserves to replace those being = depleted by=20 production. Substantial Capital expenditures are required to find, = develop, and=20 acquire oil and gas reserves.

Oil and gas prices fluctuate widely. We = generally hedge a=20 substantial portion of our expected future oil and gas production to = reduce our=20 exposure to commodity price decreases. The prices we receive for our oil = and gas=20 production affect our:

=95

cash flow = available for=20 Capital expenditures;

=95

ability to = borrow and=20 raise additional Capital;

=95

ability to = service debt;=20

=95

quantity = of oil and gas=20 we can produce;

=95

quantity = of oil and gas=20 reserves; and

=95

operating = results for=20 oil and gas activities.

We believe the most significant, subjective or = complex=20 estimates we make in preparation of our financial statements are: =

=95

the amount = of estimated=20 future net revenues from oil and gas sales;=20

=95

the = quantity of our=20 proved oil and gas reserves;

=95

the timing = and amount of=20 future drilling, development and abandonment activities;=20

=95

the value = of our=20 derivative positions;

=95

the = realization of=20 deferred tax assets; and

=95

the full = cost ceiling=20 limitation.

We base our estimates on historical experience = and=20 various assumptions that we believe are reasonable under the = circumstances.=20 Actual results may differ from these estimates.

Table=20 of Contents

During the second quarter of 2009, quarterly = production=20 was 11,696 MMcfe, a 9.3% increase over production levels in the second = quarter=20 of 2008, primarily due to our Capital expenditures in the Permian and = Mid=20 Continent areas during 2008. However, a 59.9% decline in our average = sales price=20 before hedging resulted in a 56.2% decrease in revenue from oil and gas = sales in=20 the second quarter of 2009 compared to the same period in 2008. Despite = this=20 decrease in revenue, the $25.5 million decline in our non-hedge = derivative=20 losses, combined with the $9.0 million gain on the sale of the Electric=20 Submersible Pumps division (the =93ESP Division=94) of Green Country = Supply, Inc.=20 (=93GCS=94), resulted in a reduction of our net loss from $30.1 million = during the=20 second quarter of 2008 to $17.7 million during the second quarter of = 2009.=20

All of our operating expenses, with the = exception of=20 depreciation, depletion and amortization, decreased on both an absolute = and per=20 Mcfe basis during the second quarter of 2009 compared to the same period = in 2008=20 due to a reduction in activity and lower overall industry costs. Oil = prices have=20 recently started to improve, and if this upward trend continues, we = expect=20 operating costs to increase as well.

Our development, exploration, and acquisition = activities=20 require substantial Capital expenditures. Historically, we have funded = our=20 Capital expenditures through a combination of cash flows from operations = and=20 debt. Due to the recent turmoil in the market and the sharp decline in = oil and=20 gas prices, which began during the fourth quarter of 2008, we plan to = keep our=20 Capital expenditures within our discretionary cash flow for the period = from=20 April 1, 2009 to December 31, 2009, as required by our amended = Credit=20 Agreement.

The following are material events that have = impacted our=20 results of operations or liquidity discussed below, or are expected to = impact=20 these items in future periods:

=95

Current = market=20 conditions. The credit markets are undergoing significant = volatility.=20 Many financial institutions have liquidity concerns, prompting = government=20 intervention to mitigate pressure on the credit markets. Our = exposure to=20 the current credit market crisis includes our revolving credit = facility,=20 counterparty risks related to our trade credit and derivative = instruments,=20 and risks related to our cash investments. =

Our cash accounts and deposits with any = financial=20 institution that exceed the amount insured by the Federal Deposit = Insurance=20 Corporation are at risk in the event one of these financial institutions = should=20 fail. As of June 30, 2009, cash with a recorded balance totaling = $81.5=20 million was held at JP Morgan Chase Bank, N.A.

We sell our crude oil, natural gas and natural = gas=20 liquids to a variety of purchasers. Some of these parties may experience = liquidity problems. Nonperformance by a trade creditor could result in = losses.=20 We also have significant net derivative assets that are held by = affiliates of=20 our lenders. As of June 30, 2009, net derivative assets totaling = $48.5=20 million were held by JP Morgan Chase Bank, N.A., Calyon Credit Agricole = CIB, The=20 Royal Bank of Scotland plc, and Bank of Oklahoma.

Our oil and gas sales revenues are derived from = the sale=20 of oil, gas and natural gas liquids. We recognize revenues when our = production=20 is sold and title is transferred. Our revenues are highly dependent upon = the=20 prices of, and the demand for, oil and gas. Historically, the markets = for oil=20 and gas have been volatile and are likely to continue to be volatile in = the=20 future. The prices we receive for our oil and gas and our levels of = production=20 are subject to wide fluctuations and depend on numerous factors beyond = our=20 control, including supply and demand, economic conditions, foreign = imports, the=20 actions of OPEC, political conditions in other oil producing countries, = and=20 governmental regulation, legislation and policies.

Oil and gas prices declined significantly = during the=20 second quarter of 2009 compared to the second quarter of 2008, which = will reduce=20 our cash flows from operations in future periods in which prices remain = at or=20 below the current levels. The commodity price swaps and costless collars = that=20 cover approximately 77% of our expected PDP oil production through = December 2011=20 and approximately 70% of our expected PDP gas production through = December 2011=20 will, however, become more valuable if prices continue to decline. =

Table=20 of Contents

=95

Credit = Agreement.=20 Our current Credit Agreement is a revolving credit facility in the = amount=20 of $513.0 million. At June 30, 2009, we had $507.0 million=20 outstanding under the Credit Agreement and $2.9 million was = utilized by=20 outstanding letters of credit. =

The Credit Agreement is scheduled to mature on=20 October 31, 2010. Should current credit market volatility be = prolonged,=20 future extensions of our Credit Agreement may contain terms that are = less=20 favorable than those of our current Credit Agreement. If we are not able = to=20 extend the maturity of our Credit Agreement before October 31, = 2009, the=20 entire balance then outstanding would be classified as a current = liability.=20 Borrowings under our Credit Agreement are excluded from the Credit = Agreement=20 definition of current liabilities. We do not expect current = classification of=20 the borrowings to impact our current ratio as calculated for loan = compliance.=20

Covenants set forth in the indentures = for our=20 8 1/2% Senior=20 Notes and the 8 7/8% Senior=20 Notes, including the Adjusted Consolidated Net Tangible Asset debt = incurrence=20 test (the =93ACNTA test=94), limit the amount of secured debt we can = incur. Certain=20 thresholds set forth in the ACNTA test are principally reliant upon the = levels=20 of commodity prices for oil and gas at specified dates. Based on the = commodity=20 prices for oil and gas at December 31, 2008, we will be unable to = borrow=20 additional amounts under our Credit Agreement during 2009, regardless of = the=20 availability under our Credit Agreement, unless our secured debt is = reduced=20 below approximately $330.0 million.

=95

Impairment of oil and=20 gas properties. In accordance with the full cost method of = accounting,=20 the net Capitalized costs of oil and gas properties are not to = exceed=20 their related estimated future net revenues discounted at 10% = (=93PV-10=20 value=94), as adjusted for our cash flow hedge positions and net = of tax=20 considerations, plus the lower of cost or estimated fair value of = unproved=20 properties. During the first quarter of 2009, gas prices declined=20 significantly as compared to the December 31, 2008 spot price = of=20 $5.62 per Mcf. Based on March 31, 2009 spot prices of $49.66 = per Bbl=20 of oil and $3.63 per Mcf of gas, the internally estimated PV-10 = value of=20 our reserves declined by 13.5% compared to the PV-10 value at=20 December 31, 2008. As a result, we recorded a ceiling test = impairment=20 of oil and gas properties of $240.8 million during the first = quarter of=20 2009. The effect of derivative contracts accounted for as cash = flow=20 hedges, based on the March 31, 2009 spot prices, increased = the full=20 cost ceiling by $169.0 million, thereby reducing the ceiling test = write=20 down by the same amount.

The internally estimated PV-10 value of our = reserves was=20 estimated based on spot prices of $69.89 per Bbl of oil and $3.89 per = Mcf of gas=20 at June 30, 2009. The effect of derivative contracts accounted for = as cash=20 flow hedges, based on these June 30, 2009, spot prices, reduced the = full=20 cost ceiling by $12.9 million. The qualifying cash flow hedges as of=20 June 30, 2009, which consisted of commodity price swaps, covered = 4,265=20 MBbls of oil production for the period from July 2009 through December = 2011. As=20 of June 30, 2009, the cost center ceiling exceeded the net = Capitalized cost=20 of our oil and gas properties, and no ceiling test impairment was = recorded=20 during the second quarter of 2009.

A decline in oil and gas prices subsequent to=20 June 30, 2009 could result in additional ceiling test write downs = in the=20 third quarter of 2009 or in subsequent periods. The amount of any future = impairment is difficult to predict, and will depend on the oil and gas = prices at=20 the end of or during each period, the incremental proved reserves added = during=20 each period, and additional Capital spent.

=95

Production tax=20 credit. During 2006, we purchased interests in two venture = Capital=20 limited liability companies resulting in a total investment of = $15.0=20 million. Our return on the investment was the receipt of $2 of = Oklahoma=20 tax credits for every $1 invested and was recouped from our = Oklahoma=20 production taxes. The investments are accounted for as a = production tax=20 benefit asset and are netted against tax credits realized in other = income=20 using the effective yield method over the expected recovery = period. As of=20 June 30, 2009, we had received $30.0 million of proceeds from = the=20 Oklahoma tax credits.

During the three and six months ended = June 30, 2009,=20 we received cash of $5.3 million and $27.2 million, respectively, from=20 application of these tax credits. This source of cash received will not = be=20 available in future periods.

=95

Discontinued=20 Operations =96 During the second quarter of 2009, we committed = to a plan=20 to sell the assets of GCS, a wholly owned subsidiary that provides = oilfield supplies, oilfield chemicals, downhole electric = submersible=20 pumps, and related services to oil and gas operators primarily in=20 Oklahoma, Texas, and Wyoming. =

On May 14, 2009, we entered into an = agreement to=20 sell the assets of the ESP Division of GCS to Global Oilfield Services, = Inc.=20 (=93Global=94) for a cash price of $26.0 million, subject to working = Capital=20 adjustments as provided in the agreement. On June 8, 2009, we = received=20 $24.7 million in conjunction with the closing of the ESP Division sale = to=20 Global. The amount received reflected a reduction of $1.3 million due to = working=20 Capital changes as of March 31, 2009. We paid off notes payable = attributed=20 to certain assets sold to Global in the amount of $1.6 million. The = purchase=20 price is subject to a final working Capital adjustment on or before=20 August 27, 2009. As of June 30, 2009, we recorded a pre-tax = gain=20 associated with the sale of $9.0 million. All taxable income associated = with=20 such gain was offset by existing net operating losses.

=95

Monetization of=20 derivative assets. During the first quarter of 2009, we = monetized=20 certain derivative instruments with original settlement dates from = May=20 through October of 2009. Net proceeds received from this = monetization were=20 $9.5 million. None of the monetized derivatives were incorporated = into the=20 determination of the borrowing base under our Credit Agreement. = During the=20 second quarter of 2009, we monetized additional derivative = instruments=20 with original settlement dates from January 2012 through December = 2013 for=20 proceeds of $102.4 million. As a result of this monetization, = effective=20 June 8, 2009, the borrowing base was reduced from $600.0 = million to=20 $513.0 million, resulting in a payment to the banks of $87.0 = million. The=20 remaining proceeds of $15.4 million increased our cash balance. As = of=20 June 30, 2009, we have a net derivative asset of $26.2 = million.=20

Table=20 of Contents

=95

Capital = expenditure=20 budget. We have expanded our oil and gas property Capital = expenditure=20 budget for 2009 reflecting an increased amount of cash available = primarily=20 from higher oil prices, the receipt of proceeds from derivative=20 monetizations, the sale of the ESP Division of GCS, and production = tax=20 credits. Our Capital expenditures for oil and gas properties were = $40.3=20 million and $23.9 million, respectively, during the first and = second=20 quarters of 2009. The majority of the costs incurred during the = first six=20 months of 2009 were incurred during the first quarter of 2009 as = we=20 completed projects begun during the fourth quarter of 2008. Our = projected=20 Capital expenditures for the rest of 2009 are between = $55 million and=20 $65 million, which, combined with our actual Capital = expenditures for=20 the second quarter of 2009, are within our projected discretionary = cash=20 flows for the period beginning April 1, 2009 and ending=20 December 31, 2009, as required by our Credit Agreement. = Discretionary=20 cash flows consist of Consolidated EBITDAX minus interest expense = and=20 taxes paid during the period, as defined in the Fifth Amendment to = our=20 Credit Agreement. For the period from April 1, 2009 to = June 30,=20 2009, our Capital expenditures exceeded our discretionary cash = flow by=20 $2.8 million. We expect to be in compliance with the covenant as = of=20 December 31, 2009.

The expanded 2009 Capital budget represents a = reduction=20 in Capital expenditures of approximately 60% from our 2008 levels. = Despite this=20 reduction, we expect production for 2009 to be slightly higher than 2008 = production as a result of Capital investments made in 2008 and the first = quarter=20 of 2009. We plan to drill several high impact wells in the second half = of 2009,=20 which, if successful, could maintain our production levels throughout = 2010.=20 However, we cannot accurately predict the timing or level of future = production.=20

=95

Insurance=20 proceeds. In February 2008, loss of well control occurred at = the=20 Bowdle 47 No. 2 well in Loving County, Texas. Total costs=20 attributable to the loss of well control were approximately $10.6 = million.=20 Our insurance policy has covered 100% of these costs, with the = $0.6=20 million insurance retention and deductible being payable by us. As = of=20 June 30, 2009, we have received insurance proceeds of $10.0 = million,=20 and no further receipts are expected. Insurance proceeds received = are=20 recorded as a reduction of oil and gas properties on the balance = sheet and=20 in the statement of cash flows. =

Liquidity and = Capital resources=20

Crude oil and natural gas prices have fallen=20 significantly from their peak levels during the second and third = quarters of=20 2008. Lower oil and gas prices decrease our revenues. An extended = decline in oil=20 or gas prices may materially and adversely affect our future business, = liquidity=20 or ability to finance planned Capital expenditures. Lower oil and gas = prices may=20 also reduce the amount of our borrowing base under our Credit Agreement, = which=20 is determined at the discretion of the lenders based on the collateral = value of=20 our proved reserves that have been mortgaged to the lenders.

Historically, our primary sources of liquidity = have been=20 cash generated from our operations and debt. At June 30, 2009, we = had=20 approximately $84.3 million of cash and cash equivalents and $3.1 = million of=20 availability under our revolving credit line with a borrowing base of = $513.0=20 million.

Covenants set forth in the indentures = for our=20 8 1/2% Senior=20 Notes and the 8 7/8% Senior=20 Notes, including the ACNTA test, limit the amount of secured debt we can = incur.=20 Certain thresholds set forth in the ACNTA test are principally reliant = upon the=20 levels of commodity prices for oil and gas at specified dates. Based on = the=20 commodity prices for oil and gas at December 31, 2008, we will be = unable to=20 borrow additional amounts under our Credit Agreement during 2009, = regardless of=20 the availability under our revolver, unless our secured debt is reduced = below=20 approximately $330.0 million.

We believe that we will have sufficient funds = available=20 through our cash from operations to meet our normal recurring operating = needs,=20 debt service obligations, Capital requirements and contingencies for the = next 12=20 months. We may adjust our planned Capital expenditures depending on the = timing=20 and amount of any equity funding received and the availability of = acquisition=20 opportunities that meet our investment criteria.

We generally have had a working Capital deficit = as our=20 Capital expenditures have historically exceeded our cash flow, and we = rely on=20 our borrowing base for additional Capital. Because of the ACNTA test = limitation=20 under our indentures, and its impact on our ability to utilize our = revolving=20 credit in 2009, we drew down substantially all our remaining = availability under=20 our Credit Agreement prior to December 31, 2008. During the fourth = quarter=20 of 2008, we also monetized certain derivative instruments with original=20 settlement dates from January through June of 2009, which generated net = proceeds=20 of $32.6 million. During the first quarter of 2009, we monetized certain = derivative instruments with original settlement dates from May through = October=20 of 2009, which generated net proceeds of $9.5 million. During the second = quarter=20 of 2009, we monetized additional derivative instruments with original = settlement=20 dates from January 2012 through December 2013 for proceeds of $102.4 = million. As=20 a result of this monetization, effective June 8, 2009, the = borrowing base=20 was reduced from $600.0 million to $513.0 million, resulting in a = payment to the=20 banks of $87.0 million. The remaining proceeds of $15.4 million = increased our=20 cash balance. We have changed our cash management activities to target a = minimum=20 balance of cash on hand, which we maintain in highly liquid investments. =

We pledge our producing oil and gas properties = to secure=20 our Credit Agreement. The banks establish a borrowing base by making an = estimate=20 of the collateral value of our oil and gas properties. We utilize the = available=20 funds as needed to supplement our operating cash flows as a financing = source for=20 our Capital expenditures. Our ability to fund our Capital expenditures = is=20 dependent on the level of product prices and the success of our = acquisition and=20 development program in adding to our available borrowing base. If oil = and gas=20 prices decrease from the amounts used in estimating the collateral value = of our=20 oil and gas properties, the borrowing base may be reduced, thus reducing = funds=20 available for our Capital expenditures. We mitigate a potential = reduction in our=20 borrowing base caused by a decrease in oil and gas prices through the = use of=20 commodity derivatives.

Table=20 of Contents

Sources and uses of cash. The net = increase in cash=20 is summarized as follows:


	Six months = ended June 30,
(dollars in = thousands)	2008			2009
Cash flows provided by operating=20 activities	$	114,474			$	68,032
Cash flows provided by (used in) = investing=20 activities		(151,796	)			58,337
Cash flows provided by (used in) = financing=20 activities		44,630				(94,205	)

Net increase in cash during the=20 period	$	7,308			$	32,164

Substantially all of our cash flow from = operating=20 activities is from the production and sale of oil and gas, reduced or = increased=20 by associated hedging activities. For the six months ended June 30, = 2009,=20 net cash provided from operations decreased 40.6% from the same period = in the=20 prior year primarily due to the decrease in revenue from oil and gas = sales.=20

We use the net cash provided by operations to = partially=20 fund our acquisition, exploration and development activities. Cash flows = provided by investing activities for the six months ended June 30, = 2009=20 included proceeds of $111.9 million from the monetization of derivatives = and=20 proceeds of $24.7 million from the sale of the ESP Division of GCS. A = portion of=20 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)	Six months ended June 30, 2009		Percent of total
Development activities:
Developmental drilling	$	32,231		50.2	%
Enhancements		16,945		26.4	%
Tertiary recovery		7,367		11.5	%
Acquisitions:
Proved properties		494		0.7	%
Unproved properties		2,387		3.7	%
Exploration activities		4,826		7.5	%

Total	$	64,250		100.0	%

In addition to the Capital expenditures for oil = and gas=20 properties, we spent approximately $1.5 million for the acquisition and=20 construction of new office and administrative facilities and equipment = during=20 the first six months of 2009.

As of June 30, 2009, we had cash and cash=20 equivalents of $84.3 million and long-term debt obligations of $1.2 = billion.=20

Our Credit Agreement. In October = 2006, we=20 entered into a Seventh Restated Credit Agreement, which is scheduled to = mature=20 on October 31, 2010, and is collateralized by our oil and gas = properties.=20 Availability under our Credit Agreement is subject to a borrowing base = which is=20 set by the banks semi-annually on May 1 and November 1 of each = year.=20 In addition, the lenders may request a borrowing base redetermination = once every=20 six months. As a result of our derivative monetization during the second = quarter=20 of 2009, the borrowing base was reduced from $600.0 million to $513.0 = million=20 effective June 8, 2009. We had $507.0 million outstanding under our = Credit=20 Agreement at June 30, 2009.

The agreement has certain negative and = affirmative=20 covenants that require, among other things, maintaining financial = covenants for=20 current and debt service ratios and financial reporting. We believe we = were in=20 compliance with all covenants under the Credit Agreement as of = June 30,=20 2009.

Borrowings under our Credit Agreement are made, = at our=20 option, as either Eurodollar loans or Alternate Base Rate (=93ABR=94) = loans. At=20 June 30, 2009, all of our borrowings were Eurodollar loans. =

Interest on Eurodollar loans is computed at the = Adjusted=20 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=20 interest period (one, two, three or six months, selected by us) times a=20 Statutory Reserve Rate multiplier, as defined in the Credit Agreement, = plus a=20 margin where the margin varies from 2.500% to 4.250% depending on the=20 utilization percentage of the conforming borrowing base. At = June 30, 2009,=20 the Adjusted LIBO rate, as defined, was 2.000%, the Statutory Reserve = Rate=20 multiplier was 100%, and the applicable margin and commitment fee = together were=20 3.937% resulting in an effective interest rate of 5.937% for Eurodollar=20 borrowings. Interest payments on Eurodollar borrowings are due the last = day of=20 the interest period, if shorter than three months or every three months. =

Table=20 of Contents

Interest on ABR loans is computed as the = greater of=20 (1) the Prime Rate, as defined in our Credit Agreement, = (2) the=20 Federal Funds Effective Rate plus 1/2 of 1%, or (3) the Adjusted = LIBO Rate,=20 as defined in our Credit Agreement, plus 1%; plus a margin where the = margin=20 varies from 1.625% to 3.375%, depending on the utilization percentage of = the=20 borrowing base.

Commitment fees of 0.50% accrue on the unused = portion of=20 the borrowing base amount, depending on the utilization percentage, and = are=20 included as a component of interest expense. We have the right to make=20 prepayments of the borrowings at any time without penalty or premium.=20

Interest was paid at least every three months = during 2008=20 and 2009. The effective rate of interest on the entire outstanding = balance was=20 5.299% and 5.937% as of December 31, 2008, and June 30, 2009,=20 respectively, and was based upon LIBOR.

Our Credit Agreement contains restrictive = covenants that=20 may limit our ability, among other things, to:

=95

incur = additional=20 indebtedness;

=95

create or = incur=20 additional liens on our oil and gas properties;=20

=95

pay = dividends in cash or=20 other property, redeem our Capital stock or prepay certain = indebtedness;=20

=95

make = investments in or=20 loans to others;

=95

change our = line of=20 business;

=95

enter into = operating=20 leases;

=95

merge or = consolidate=20 with another person, or lease or sell all or substantially all of = our=20 assets;

=95

sell, = farm-out or=20 otherwise transfer property containing proved reserves;=20

=95

enter into = transactions=20 with affiliates;

=95

issue = preferred stock;=20

=95

enter into = negative=20 pledge agreements or agreements restricting the ability of our=20 subsidiaries to pay dividends; =

=95

enter into = certain swap=20 agreements; and

=95

amend, = modify or waive=20 under our permitted bond documents (i) any covenants that = would make=20 the terms materially more onerous to us or (ii) certain other = provisions.

Our Credit Agreement requires us to maintain a = current=20 ratio, as defined in our Credit Agreement, of not less than 1.0 to 1.0. = The=20 definition of current assets and current liabilities used for = determination of=20 the current ratio computed for loan compliance purposes differs from = current=20 assets and current liabilities determined in compliance with GAAP. Since = compliance with financial covenants is a material requirement under our = Credit=20 Agreement, we consider the current ratio calculated under our Credit = Agreement=20 to be a useful measure of our liquidity because it includes the funds = available=20 to us under our Credit Agreement and is not affected by the volatility = in=20 working Capital caused by changes in the fair value of derivatives. At=20 December 31, 2008 and June 30, 2009, our current ratio as = computed=20 using GAAP was 1.34 and 1.62, respectively. After giving effect to the=20 adjustments, our current ratio computed for loan compliance purposes was = 1.19=20 and 1.56, respectively. The following table reconciles our current = assets and=20 current liabilities using GAAP to the same items for purposes of = calculating the=20 current ratio for our loan compliance:


(dollars in = thousands)	December 31, 2008			June 30, 2009
Current assets per GAAP	$	218,363			$	186,151
Plus=97Availability under credit=20 agreement		3,270				3,120
Less=97Short-term derivative=20 instruments		(51,412	)			(37,939	)

Current assets as = adjusted	$	170,221			$	151,332


Current liabilities per = GAAP	$	163,123			$	115,146
Less=97Deferred tax liability on = derivative=20 instruments and asset retirement obligations		(19,755	)			(12,447	)
Less=97Short-term asset retirement=20 obligations		(300	)			(300	)
Less=97Short-term derivative=20 instruments		=97				(5,420	)

Current liabilities as = adjusted	$	143,068			$	96,979

Current ratio for loan = compliance		1.19				1.56

Table=20 of Contents

The monetization of derivatives in December = 2008 and the=20 first and second quarters of 2009 allowed us to exceed our required = current=20 ratio by a higher margin.

Our Credit Agreement is scheduled to mature on=20 October 31, 2010. If we are not able to extend the maturity of our = Credit=20 Agreement before October 31, 2009, the entire balance then = outstanding=20 would be classified as a current liability for GAAP accounting purposes. = Borrowings under our Credit Agreement are excluded from the Credit = Agreement=20 definition of current liabilities. We do not expect current = classification of=20 the borrowings to impact our current ratio as calculated for loan = compliance.=20

The Credit Agreement, as amended effective = May 21,=20 2009, requires us to maintain a Consolidated Senior Total Debt to = Consolidated=20 EBITDAX ratio, as defined in our Credit Agreement, of not greater than:=20

=95

2.50 to = 1.0 for the four=20 consecutive fiscal quarters ending on March 31, 2009;=20

=95

3.00 to = 1.0 for the four=20 consecutive fiscal quarters ending on June 30,=20 2009, September 30, 2009, December 31, 2009, = and=20 March 31, 2010; and

=95

2.75 to = 1.0 for the four=20 consecutive fiscal quarters ending on June 30,=20 2010, September 30, 2010, and December 31, 2010.=20

The Credit Agreement also specifies events of = default,=20 including:

=95

our = failure to pay=20 principal or interest under the Credit Agreement when due and = payable;=20

=95

our = representations or=20 warranties proving to be incorrect, in any material respect, when = made or=20 deemed made;

=95

our = failure to observe=20 or perform certain covenants, conditions or agreements under the = Credit=20 Agreement;

=95

our = failure to make=20 payments on certain other material indebtedness when due and = payable;=20

=95

the = occurrence of any=20 event or condition that requires the redemption or repayment of, = or an=20 offer to redeem or repay, certain other material indebtedness = prior to its=20 scheduled maturity;

=95

the = commencement of an=20 involuntary proceeding seeking liquidation, reorganization or = other=20 relief, or the appointment of a receiver, trustee, custodian or = other=20 similar official for us or our subsidiaries, and the proceeding or = petition continues undismissed for 60 days or an order approving = the=20 foregoing is entered;

=95

our = inability, admission=20 or failure generally to pay our debts as they become due;=20

=95

the entry = of a final,=20 non-appealable judgment for the payment of money in excess of $5.0 = million=20 that remains undischarged for a period of 60 consecutive days;=20

=95

a Change = of Control (as=20 defined in the Credit Agreement); and =

=95

the = occurrence of a=20 default under any permitted bond document, which such default = continues=20 unremedied or is not waived prior to the expiration of any = applicable=20 grace or cure under any permitted bond document.=20

If our borrowing base amount is reduced by the = banks, or=20 if we expect to be unable to meet our required Current Ratio, or our = required=20 Consolidated Senior Total Debt to Consolidated EBITDAX ratio, we could = reduce=20 our debt amount by monetizing additional derivative contracts, selling = oil and=20 gas assets, selling non-oil and gas assets, or raising equity. There is = no=20 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=20 adequately reduce the borrowing base, or that we will be able to meet = our future=20 obligations to the banks.

If the outstanding borrowings under our Credit = Agreement=20 were to exceed the borrowing base as a result of a redetermination, we = would be=20 required to eliminate this excess. Within 10 days after receiving notice = of the=20 new borrowing base, we would be required to make an election: = (1) to repay=20 a portion of our bank borrowings in the amount of the excess either in a = lump=20 sum within 30 days or in equal monthly installments over a six-month = period;=20 (2) to submit within 90 days additional oil and gas properties we = own for=20 consideration in connection with the determination of the borrowing base = sufficient to eliminate the excess or (3) to eliminate the excess = through a=20 combination of repayments and the submission of additional oil and gas=20 properties within 90 days.

Table=20 of Contents

Alternative Capital resources. We = have=20 historically used cash flow from operations, debt financing, and = derivative=20 monetizations as our primary sources of Capital. In the future we may = use=20 additional sources such as asset sales, public or private issuances of = common or=20 preferred stock, or project financing. While we believe we would be able = to=20 obtain funds through one or more of these alternative sources, if = needed, we=20 cannot provide assurance that these resources would be available on = terms=20 acceptable to us.

Table=20 of Contents

Results of = operations=20

Comparison of three and six months ended=20 June 30, 2009 to three and six months ended June 30, 2008.=20

Revenues and production. The following = table=20 presents information about our oil and gas sales before the effects of = commodity=20 derivative settlements:


	Three = months=20 ended June 30,					Six months = ended June 30,
	2008		2009		change			2008	2009		change
Oil and gas sales (dollars in=20 thousands)
Oil	$	107,314		$	50,783		(52.7	)%	$	190,327		$	85,896	(54.9	)%
Gas		50,354			18,281		(63.7	)%		88,369			37,035	(58.1	)%

Total	$	157,668		$	69,064		(56.2	)%	$	278,696		$	122,931	(55.9	)%
Production
Oil (MBbls)		931			941		1.1	%		1,823			1,904	4.4	%
Gas (MMcf)		5,117			6,050		18.2	%		9,853			11,687	18.6	%
MMcfe		10,703			11,696		9.3	%		20,791			23,111	11.2	%
Average sales prices (excluding = derivative=20 settlements)
Oil per Bbl	$	115.27		$	53.97		(53.2	)%	$	104.40		$	45.11	(56.8	)%
Gas per Mcf		9.84			3.02		(69.3	)%		8.97			3.17	(64.7	)%
Mcfe		14.73			5.90		(59.9	)%		13.40			5.32	(60.3	)%

Oil and gas revenues decreased by approximately = 56%=20 during the three and six months ended June 30, 2009, due to a = decrease in=20 average price per Mcfe. Oil and gas prices declined significantly during = the=20 first and second quarters of 2009 as compared to the same periods of = 2008. Based=20 on our forecasted production, if oil and gas prices remain at current = levels or=20 decline further, our revenues in 2009 will be significantly lower than = the=20 amounts reported in 2008.

Oil sales decreased 52.7% from $107.3 million = during the=20 second quarter of 2008 to $50.8 million during the same period in 2009. = This=20 decrease was due to a 53.2% decrease in average oil prices from $115.27 = to=20 $53.97 per barrel, partially offset by a 1.1% increase in production = volumes to=20 941 MBbls. Gas sales decreased 63.7% from $50.4 million during the = second=20 quarter of June 30, 2008 to $18.3 million during the same period in = 2009.=20 This decrease was due to a 69.3% decrease in average gas prices, = partially=20 offset by an 18.2% increase in gas production volumes to 6,050 MMcf. =

Oil sales decreased 54.9% from $190.3 million = during the=20 six months ended June 30, 2008 to $85.9 million during the same = period in=20 2009. This decrease was due to a 56.8% decrease in average oil prices = from=20 $104.40 to $45.11 per barrel, partially offset by a 4.4% increase in = production=20 volumes to 1,904 MBbls. Gas sales decreased 58.1% from $88.4 million = during the=20 six months ended June 30, 2008 to $37.0 million during the same = period in=20 2009. This decrease was due to a 64.7% decrease in average gas prices, = partially=20 offset by an 18.6% increase in gas production volumes to 11,687 MMcf.=20

Production volumes by area were as follows = (MMcfe):=20


	Three months ended June 30,	Percentage		Six months ended June 30,	Percentage
	2008	2009	change		2008	2009	change
Mid Continent	7,050	7,450	5.7	%	13,828	14,784	6.9	%
Permian	2,011	2,691	33.8	%	3,275	5,272	61.0	%
Ark-La-Tex	412	419	1.7	%	900	769	(14.6	)%
North Texas	267	243	(9.0	)%	580	496	(14.5	)%
Rockies	253	198	(21.7	)%	474	389	(17.9	)%
Gulf Coast	710	695	(2.1	)%	1,734	1,401	(19.2	)%

Totals	10,703	11,696	9.3	%	20,791	23,111	11.2	%

Oil and gas production for the three and six = months ended=20 June 30, 2009 increased primarily due to our drilling program and=20 enhancements of our existing properties, much of which was accomplished = in 2008=20 and the first quarter of 2009. We have focused our Capital expenditures = on the=20 Mid Continent and Permian areas. As a result, production in our growth = areas has=20 declined and is expected to continue to decline, since our planned = Capital=20 expenditures for the remainder of 2009 are also focused in our core = areas of the=20 Mid Continent and Permian Basin.

The=20 increase in production in the Permian area is primarily due to the = Bowdle 47=20 No. 2, which began selling gas in late November 2008 and accounted = for=20 approximately 11% and 10%, respectively, of total production for the = three and=20 six months ended June 30, 2009. We expect production from this well to = begin to=20 decline during the third quarter of 2009. Production from the = Bowdle 47=20 No. 2 for the last six months of 2009 is expected to be = approximately 75%=20 of its production for the first six months of 2009, and its production = in 2010=20 is expected to be approximately 48% of its total production in 2009. We = plan to=20 drill an offset, the Bowdle 47 No. 4, as well as several other = high=20 impact wells in the second half of 2009, which, if successful, could = maintain=20 our production levels throughout 2010. However, we cannot accurately = predict the=20 timing or the level of future production.

Our results of operations, financial condition, = and=20 Capital resources are highly dependent upon the prevailing market prices = of, and=20 demand for, oil and gas. These commodity prices are subject to wide = fluctuations=20 and market uncertainties. To mitigate a portion of this exposure, we = enter into=20 commodity price swaps, costless collars, and basis protection swaps. = Certain=20 commodity price swaps qualified and were designated as cash flow hedges. =

Table=20 of Contents

In addition, during the fourth quarter of 2008, = we=20 monetized oil and gas swaps and collars with original settlement dates = from=20 January through June of 2009 for proceeds of $32.6 million. During the = first=20 quarter of 2009, we monetized additional gas swaps with original = settlement=20 dates from May through October of 2009 for proceeds of $9.5 million. = During the=20 second quarter of 2009, we monetized additional oil swaps and collars = with=20 original settlement dates from January 2012 through December 2013 for = proceeds=20 of $102.4 million. Certain swaps that were monetized had previously been = accounted for as cash flow hedges. As of December 31, 2008 and=20 June 30, 2009, accumulated other comprehensive income included = $23.7=20 million and $86.4 million, respectively, of deferred gains related to=20 discontinued cash flow hedges that will be recognized as a gain from oil = and gas=20 hedging activities when the hedged production is sold. No oil and gas=20 derivatives were monetized during the first six months of 2008. =

The effects of hedging on our net revenues for = the three=20 and six months ended June 30, 2008 and 2009 are as follows: =


	Three = months=20 ended June 30,			Six months = ended June 30,
(dollars in thousands)	2008			2009			2008		2009
Gain (loss) from oil and gas hedging=20 activities:
Receipts from (payments on) hedge=20 settlements	$	(44,994	)		$	(1,699	)	$	(61,257	)	$	2,932
Hedge ineffectiveness and = reclassification=20 adjustments		(13,236	)			7,887			(28,098	)		18,759

Total	$	(58,230	)		$	6,188		$	(89,355	)	$	21,691

Primarily as a result of substantially lower = oil prices=20 in 2009 than in 2008, payments on hedge settlements were $1.7 million = during the=20 second quarter of 2009 compared to $45.0 million during the second = quarter of=20 2008, and receipts from hedge settlements were $2.9 million during the = first six=20 months of 2009 compared to payments on hedge settlements of $61.3 = million during=20 the first six months of 2008. Gains of $7.9 million and $19.2 million = associated=20 with derivatives for which hedge accounting had previously been = discontinued,=20 were reclassified into earnings during the three and six months ended = June 30,=20 2009, respectively, as the hedged production was sold. As a result of = these=20 transactions, as well as the discontinuance of hedge accounting for all = gas=20 swaps discussed above, our gain from oil and gas hedging activities was = $6.2=20 million and $21.7 million during the three and six months ended = June 30,=20 2009 compared to a loss of $58.2 million and $89.4 million for the = comparable=20 periods in 2008.

Our realized prices are impacted by realized = gains and=20 losses resulting from commodity derivatives contracts. The following = table=20 presents information about the effects of derivative settlements, = excluding=20 early settlements, on realized prices:


	Three months ended June 30,			Six months = ended June 30,
	2008			2009			2008		2009
Oil (per Bbl):
Before derivative = settlements	$	115.27			$	53.97		$	104.40		$	45.11
After derivative = settlements	$	76.06			$	53.77		$	73.69		$	48.76
Post-settlement to pre-settlement=20 price		66.0	%			99.6	%		70.6=20	%		108.1	%
Gas (per Mcf):
Before derivative = settlements	$	9.84			$	3.02		$	8.97		$	3.17
After derivative = settlements	$	7.79			$	4.18		$	7.97		$	4.59
Post-settlement to pre-settlement=20 price		79.2	%			138.4	%		88.9	%		144.8	%

Table=20 of Contents

Costs and expenses. The following table = presents=20 information about our operating expenses for the second quarter of 2008 = and=20 2009:


	Three months ended June 30,		Percent			Six months ended June 30,		Percent
	2008		2009		change			2008	2009		change
Costs and expenses (dollars in=20 thousands)
Lease operating expenses	$	26,367		$	23,557		(10.7	)%	$	53,912		$	50,965	(5.5	)%
Production taxes		10,601			4,941		(53.4	)%		18,516			8,801	(52.5	)%
Depreciation, depletion and=20 amortization		24,934			25,230		1.2	%		48,645			55,400	13.9	%
General and = administrative		7,829			5,906		(24.6	)%		14,081			12,274	(12.8	)%
Costs and expenses (per = Mcfe)
Lease operating expenses	$	2.46		$	2.01		(18.3	)%	$	2.59		$	2.21	(14.7	)%
Production taxes		0.99			0.42		(57.6	)%		0.89			0.38	(57.3	)%
Depreciation, depletion and=20 amortization		2.33			2.16		(7.3	)%		2.34			2.40	2.6	%
General and = administrative		0.73			0.50		(31.5	)%		0.68			0.53	(22.1	)%

Lease operating expenses =96 Due to = higher=20 production mostly associated with the Bowdle 47 No. 2 well and our = efforts=20 to reduce production costs, lease operating expenses per Mcfe for the = three and=20 six months ended June 30, 2009 declined $0.45 to $2.01 and $0.38 to = $2.21,=20 respectively, compared to the same periods in 2008. During the three and = six=20 months ended June 30, 2009, electricity and fuel costs decreased by = $1.3=20 million and $1.5 million, respectively, and workovers and other field = service=20 costs decreased by $1.4 million and $1.5 million, respectively, compared = to the=20 same periods in 2008. Oil prices have recently started to improve, and = if this=20 upward trend continues, we expect absolute and per Mcfe operating costs = to=20 increase as well.

Production taxes (which include ad valorem = taxes)=20 =96 The decrease for the second quarter of 2009 was primarily due to = 59.9%=20 lower average prices, partially offset by a 9.3% increase in production = volumes.=20 The decrease for the first six months of 2009 was primarily due to 60.3% = lower=20 average prices, partially offset by an 11.2% increase in production = volumes.=20

Depreciation, depletion and amortization = (=93DD&A=94)=20 =96 The increase for the second quarter of 2009 was primarily due to = a $0.8=20 million increase in depreciation on equipment placed in service during = the third=20 quarter of 2008, which was partially offset by a decrease in DD&A on = oil and=20 gas properties of $0.5 million. Our DD&A rate on oil and gas = properties per=20 equivalent unit of production decreased $0.23 to $1.91 per Mcfe = primarily due to=20 the decrease in Capitalized costs resulting from our ceiling test = impairments=20 recorded in the fourth quarter of 2008 and the first quarter of 2009, = combined=20 with lower estimated future development costs. This decrease in the = DD&A=20 rate per equivalent unit of production reduced DD&A for oil and gas=20 properties by $2.4 million, which was offset by increased DD&A of = $1.9=20 million due to higher production volumes.

The increase for the first six months of 2009 = was=20 primarily due to an increase in DD&A on oil and gas properties of = $4.9=20 million as a result of higher production volumes. Our DD&A rate on = oil and=20 gas properties per equivalent unit of production was $2.15 for the first = six=20 months of 2009 and 2008.

Impairment of oil and gas properties =97 = In=20 accordance with the full cost method of accounting, the net Capitalized = costs of=20 oil and gas properties are not to exceed their related estimated future = net=20 revenues discounted at 10%, as adjusted for our cash flow hedge = positions and=20 net of tax considerations, plus the lower of cost or estimated fair = value of=20 unproved properties. During the first quarter of 2009, gas prices = declined=20 significantly as compared to the December 31, 2008 spot price of = $5.62 per=20 Mcf. Based on March 31, 2009 spot prices of $49.66 per Bbl of oil = and $3.63=20 per Mcf of gas, the internally estimated PV-10 value of our reserves = declined by=20 13.5% compared to our PV-10 value at December 31, 2008. As a = result, we=20 recorded a ceiling test impairment of oil and gas properties of $240.8 = million=20 during the first quarter of 2009. The effect of derivative contracts = accounted=20 for as cash flow hedges, based on the March 31, 2009 spot prices, = increased=20 the full cost ceiling by $169.0 million, thereby reducing the ceiling = test write=20 down by the same amount.

The internally estimated PV-10 value of our = reserves was=20 estimated based on spot prices of $69.89 per Bbl of oil and $3.89 per = Mcf of gas=20 at June 30, 2009. The effect of derivative contracts accounted for = as cash=20 flow hedges, based on these June 30, 2009, spot prices, reduced the = full=20 cost ceiling by $12.9 million. The qualifying cash flow hedges as of=20 June 30, 2009, which consisted of commodity price swaps, covered = 4,265=20 MBbls of oil production for the period from July 2009 through December = 2011. As=20 of June 30, 2009, the cost center ceiling exceeded the net = Capitalized cost=20 of our oil and gas properties, and no ceiling test impairment was = recorded=20 during the second quarter of 2009.

Litigation settlement =97 Effective = April 15,=20 2009, we settled our pending lawsuit against John Milton Graves Trust = u/t/a=20 6/11/2004,
et al. This case was related to (i) a post-closing = adjustment=20 of the price we paid for Calumet Oil Company (=93Calumet=94) in 2006 = (the =93Working=20 Capital Adjustment=94) and (ii) a contractual payment related to an = election=20 to be made by the sellers of Calumet (collectively, the =93Sellers=94) = under the=20 federal tax code (the =93Tax Election=94).

Pursuant to the settlement agreement, which was = based=20 upon net calculations of the receivable and payable, the Sellers paid us = $7.1=20 million, which amount is intended to settle all claims related to both = the=20 Working Capital Adjustment and the Tax Election claims, and we retained = $0.4=20 million contained in an escrow account covering any losses incurred by = us for=20 title defects related to our purchase of Calumet. In addition, the = parties=20 issued mutual releases, dismissed with prejudice the pending litigation = and the=20 claims made therein, and the Sellers will take action to clear the title = to=20 certain properties purchased by us in the Calumet acquisition. =

As of December 31, 2008, the recorded = receivable for=20 the Working Capital Adjustment was $14.4 million, and was included in = other=20 assets on the consolidated balance sheet. As of December 31, 2008, = the=20 recorded payable related to the Tax Election was $4.4 million, and was = included=20 in accounts payable and accrued liabilities on the consolidated balance = sheet.=20 As a result of the settlement, as of June 30, 2009, the receivable = related=20 to the Working Capital Adjustment and the Tax Election payable were = eliminated,=20 the escrow cash account was reclassified to operating cash, and we = recorded a=20 charge to expense of $2.9 million.

Table=20 of Contents

General and administrative expenses =96 = The decrease=20 was primarily due to lower deferred compensation costs. The value of = each unit=20 in our Phantom Stock Plan decreased due to lower commodity prices. As a = result,=20 deferred compensation expense decreased by $1.5 million and $1.7 = million,=20 respectively, during the three and six months ended June 30, 2009 = as=20 compared to the same period of 2008. G&A expense is net of amounts=20 Capitalized as part of our exploration and development activities, as = shown in=20 the following table:


	Three = months=20 ended June 30,			Six months = ended June 30,
	2008			2009			2008		2009
General and administrative = cost	$	11,950			$	8,601		$	21,339		$	17,829
Less: general and administrative cost=20 Capitalized		(4,121	)			(2,695	)		(7,258	)		(5,555	)

General and administrative = expense	$	7,829			$	5,906		$	14,081		$	12,274

Interest expense =96 Interest expense = for the three=20 and six months ended June 30, 2009 increased by 7.7% and 6.0%,=20 respectively, compared to the same periods in 2008 primarily as a result = of=20 increased levels of borrowings. The following table presents interest = expense=20 for the three and six months ended June 30, 2008 and 2009: =


	Three months ended June 30,		Six months ended June 30,
(dollars in = thousands)	2008		2009		2008	2009
Revolver interest	$	5,498		$	6,920	$	11,569	$	13,772
8 1/2%=20 Senior Notes, due 2015		7,085			7,102		14,166		14,199
8 7/8%=20 Senior Notes, due 2017		7,379			7,397		14,754		14,791
Other interest		1,139			1,301		2,132		2,422

	$	21,101		$	22,720	$	42,621	$	45,184

Non-hedge derivative gains (losses). = Non-hedge=20 derivative gains (losses) in the consolidated statements of operations = are=20 comprised of the following:


	Three = months=20 ended June 30,			Six months = ended June 30,
(dollars in = thousands)	2008			2009			2008		2009
Change in fair value of non-qualified = commodity=20 price swaps	$	(51,058	)		$	(98,665	)	$	(58,880	)	$	(68,753	)
Change in fair value of non-designated = costless=20 collars		(8,557	)			(39,331	)		(8,557	)		(36,169	)
Change in fair value of natural gas basis = differential contracts		3,119				(5,910	)		4,815			(10,236	)
Receipts from (payments on) settlement of = non-qualified commodity price swaps		(3,380	)			84,499			(5,206	)		99,229
Receipts from settlement of = non-designated costless=20 collars		=97				27,267			=97			32,345
Receipts from (payments on) settlement of = natural=20 gas basis differential contracts		1,377				(879	)		647			892

	$	(58,499	)		$	(33,019	)	$	(67,181	)	$	17,308

The loss on non-qualified commodity price swaps = for the=20 second quarter of 2009 was $14.2 million, and included losses of $12.4 = million=20 and $1.8 million on oil and gas swaps, respectively. The gain on = non-qualified=20 commodity price swaps for the first six months of 2009 was $30.4 million = and=20 included gains of $41.7 million on gas swaps, partially offset by losses = of=20 $11.3 million on oil swaps. The loss on non-qualified commodity price = swaps for=20 the three and six months ended June 30, 2008 was $54.4 million and = $64.1=20 million respectively, and was comprised of losses on oil swaps that were = entered=20 into in anticipation of the Calumet acquisition and did not qualify as = hedges.=20

For the three and six months ended = June 30, 2009,=20 the loss on costless collars was $12.0 million and $3.8 million, = respectively.=20 Due primarily to higher NYMEX forward strip oil prices at June 30, = 2009=20 compared to March 31, 2009 and December 31, 2008, the loss on = oil=20 collars was $12.5 million and $13.0 million, respectively, for the three = and six=20 months ended June 30, 2009. This was partially offset by a gain on = gas=20 collars of $0.5 million and $9.2 million, respectively, for the three = and six=20 months ended June 30, 2009. For the three and six months ended=20 June 30, 2008, the loss on costless collars was $8.6 million and = consisted=20 of a loss on oil collars of $3.7 million and a loss on gas collars of = $4.9=20 million.

For the three and six months ended = June 30, 2009,=20 the loss on natural gas basis differential contracts was $6.8 million = and $9.3=20 million, respectively, compared to gains of $4.5 million and $5.5 = million,=20 respectively, for the comparable periods of 2008, primarily due to lower = differentials indicated by the forward commodity price curves. We had = basis=20 swaps covering 35,360 BBtu at June 30, 2009 compared to 6,950 BBtu = at=20 June 30, 2008.

Primarily as a result of the above = transactions, we had=20 non-hedge derivative losses of $33.0 million and $58.5 million, = respectively,=20 for the quarters ended June 30, 2009 and 2008, and non-hedge = derivative=20 gains of $17.3 million for the first six months of 2009 compared to = non-hedge=20 derivative losses of $67.2 million for the comparable period in 2008.=20

Table=20 of Contents

Production tax credits =96 During 2006, = we purchased=20 interests in two venture Capital limited liability companies resulting = in a=20 total investment of $15.0 million. Our return on the investment was the = receipt=20 of $2 of Oklahoma tax credits for every $1 invested and was = recouped from=20 our Oklahoma production taxes. The investments are accounted for as a = production=20 tax benefit asset and are netted against tax credits realized in other = income=20 using the effective yield method over the expected recovery period. = Other income=20 for the three months ended June 30, 2008 and 2009 includes Oklahoma = production tax credits of $0.3 million and $2.6 million, respectively. = Other=20 income for the six months ended June 30, 2008 and 2009 includes = Oklahoma=20 production tax credits of $0.7 million and $13.5 million, respectively. = This=20 source of income will not be available in future periods.

Discontinued Operations =96 During the = second=20 quarter of 2009, we committed to a plan to sell the assets of GCS, a = wholly=20 owned subsidiary that provides oilfield supplies, oilfield chemicals, = downhole=20 electric submersible pumps, and related services to oil and gas = operators=20 primarily in Oklahoma, Texas, and Wyoming.

On May 14, 2009, we entered into an = agreement to=20 sell the assets of the ESP Division of GCS to Global for a cash price of = $26.0=20 million, subject to working Capital adjustments as provided in the = agreement. On=20 June 8, 2009, we received $24.7 million in conjunction with the = closing of=20 the ESP Division sale to Global. The amount received reflected a = reduction of=20 $1.3 million due to working Capital changes as of March 31, 2009. = We paid=20 off notes payable attributed to certain assets sold to Global in the = amount of=20 $1.6 million. The purchase price is subject to a final working Capital=20 adjustment on or before August 27, 2009. As of June 30, 2009, = we=20 recorded a pre-tax gain associated with the sale of $9.0 million. All = taxable=20 income associated with such gain was offset by existing net operating = losses.=20

The operating results of GCS for the three and = six months=20 ended June 30, 2008 and 2009 have been reclassified as discontinued = operations in the consolidated statements of operations. Income from=20 discontinued operations, including the gain on the sale of the ESP = Division and=20 net of income taxes, was $0.3 million and $5.4 million, respectively, = for the=20 second quarter of 2008 and 2009, and $0.5 million and $5.5 million,=20 respectively, for the six months ended June 30, 2008 and 2009. =

Non-GAAP financial measures and = reconciliations=20

We define adjusted EBITDA as net income (loss), = adjusted=20 to exclude (1) interest and other financing costs, net of = Capitalized=20 interest, (2) income taxes, (3) depreciation, depletion and=20 amortization, (4) unrealized (gain) loss on ineffective portion of = hedges=20 and reclassification adjustments, (5) non-cash change in fair value = of=20 non-hedge derivative instruments, (6) interest income, = (7) non-cash=20 deferred compensation expense, (8) gain or loss on disposed assets, = and=20 (9) impairment charges and other significant, unusual, non-cash = charges.=20 Any cash proceeds received from the monetization of derivatives with a = scheduled=20 maturity date more than 12 months following the date of such = monetization are=20 excluded from the calculation of adjusted EBITDA.

Management uses adjusted EBITDA as a = supplemental=20 financial measurement to evaluate our operational trends. Items excluded = generally represent non-cash adjustments, the timing and amount of which = cannot=20 be reasonably estimated and are not considered by management when = measuring our=20 overall operating performance. In addition, adjusted EBITDA mirrors the=20 Consolidated EBITDAX ratio that is used in the covenant calculation = required=20 under our Credit Agreement described in the Liquidity and Capital = Resources=20 section above. We consider compliance with this covenant to be material. = Adjusted EBITDA is used as a supplemental financial measurement in the=20 evaluation of our business and should not be considered as an = alternative to net=20 income, as an indicator of our operating performance, as an alternative = to cash=20 flows from operating activities, or as a measure of liquidity. Adjusted = EBITDA=20 is not defined under GAAP and, accordingly, it may not be a comparable=20 measurement to those used by other companies. The following table = provides a=20 reconciliation of net loss to adjusted EBITDA for the specified periods: =


	Three = months=20 ended June 30,			Six months = ended June 30,
(Dollars in = thousands)	2008			2009			2008		2009
Net loss	$	(30,052	)		$	(17,724	)	$	(33,019	)	$	(142,548	)
Interest expense		21,101				22,720			42,621			45,184
Income tax benefit		(18,737	)			(10,772	)		(20,612	)		(89,178	)
Depreciation, depletion, and=20 amortization		25,275				25,456			49,167			55,899
Unrealized (gain) loss on ineffective = portion of=20 hedges and reclassification adjustments		13,236				(7,887	)		28,098			(18,759	)
Non-cash change in fair value of = non-hedge=20 derivative instruments		56,496				41,554			62,622			12,806
Interest income		(85	)			(71	)		(206	)		(172	)
Non-cash deferred compensation=20 expense		2,106				474			2,393			631
Gain on disposed assets		(235	)			(9,004	)		(230	)		(9,005	)
Loss on impairment of oil and gas=20 properties		=97				=97			=97			240,790
Loss on litigation = settlement		=97				=97			=97			2,928

Adjusted EBITDA	$	69,105			$	44,746		$	130,834		$	98,576

Critical accounting = policies and=20 estimates

The discussion and analysis of our financial = condition=20 and results of operations are based upon our consolidated financial = statements.=20 The preparation of these statements requires us to make assumptions and=20 estimates that affect the reported amounts of assets, liabilities, = revenues and=20 expenses. We base our estimates on historical experience and other = sources that=20 we believe are reasonable at the time. Actual results may differ from = the=20 estimates and assumptions we used in preparation of our financial = statements. We=20 evaluate our estimates and assumptions on a regular basis. Described = below are=20 the most significant policies and the related estimates and assumptions = we apply=20 in the preparation of our financial statements. See Note 1 to our = consolidated=20 financial statements for a discussion of additional accounting policies = and=20 estimates made by management.

Revenue recognition. We derive almost = all of our=20 revenue from the sale of crude oil and natural gas produced from our oil = and gas=20 properties. Revenue is recorded in the month the product is delivered to = the=20 purchaser. We receive payment on substantially all of these sales from = one to=20 three months after delivery. At the end of each month, we estimate the = amount of=20 production delivered to purchasers that month and the price we will = receive.=20 Variances between our estimated revenue and actual payment received for = all=20 prior months are recorded in the month payment is received.

Table=20 of Contents

Derivative instruments. Certain of our = oil and gas=20 derivative contracts are designed to be treated as cash flow hedges = under=20 Statement of Financial Accounting Standards No. 133, Accounting = for=20 Derivative Instruments and Hedging Activity, as amended (=93SFAS = 133=94). This=20 policy significantly impacts the timing of revenue or expense recognized = from=20 this activity, as our contracts are adjusted to their fair value at the = end of=20 each month. Pursuant to SFAS 133, the effective portion of the hedge = gain or=20 loss, meaning the portion of the change in the fair value of the = contract that=20 offsets the change in the expected future cash flows from our forecasted = sales=20 of production, is recognized in income when the hedged production is = reported as=20 revenue. We reflect this as an adjustment to our revenue in the =93Gain = (loss)=20 from oil and gas hedging activities=94 line in our consolidated = statements of=20 operations. Until hedged production is reported in earnings and the = contract=20 settles, the effective portion of the change in the fair value of the = contract=20 is reported in the =93Accumulated other comprehensive income=94 line = item in=20 stockholders=92 equity. The ineffective portion of the hedge gain or = loss is=20 reported in the =93Gain (loss) from oil and gas hedging activities=94 = line item each=20 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=20 period-end market values and the change in the fair value of the = contracts is=20 included in the =93Non-hedge derivative gains (losses)=94 line in our = consolidated=20 statements of operations. As a result, our reported earnings could = include large=20 non-cash fluctuations, particularly in volatile pricing environments.=20

We determine the fair value of our crude oil, = natural=20 gas, and basis swaps by reference to forward pricing curves for oil and = gas=20 futures contracts. The difference between the forward price curve and = the=20 contractual fixed price is discounted to the measurement date using a = credit=20 risk adjusted discount rate. In certain less liquid markets, forward = prices are=20 not as readily available. In these circumstances, swaps are valued using = internally developed methodologies that consider historical = relationships among=20 various commodities that result in management=92s best estimate of fair = value.=20 These contracts are classified as Level 3 in accordance with SFAS=20 No. 157, Fair Value Measurements (=93SFAS 157=94). We have = determined=20 that the fair value methodology described above for the remainder of our = swaps=20 is consistent with observable market inputs and have categorized them as = Level 2=20 in accordance with SFAS 157. We determine fair value for our oil and gas = collars=20 using an option pricing model which takes into account market = volatility, market=20 prices, contract parameters, and credit risk. Due to unavailability of=20 observable volatility data input for our collars, we have determined = that all of=20 our collars=92 fair value measurements are categorized as Level 3 in = accordance=20 with SFAS 157. Derivative instruments are discounted using a rate = that=20 incorporates our nonperformance risk for derivative liabilities, and our = counterparties=92 credit risk for derivative assets. Our derivative = contracts have=20 been executed with the institutions that are parties to our revolving = credit=20 facility. We believe the credit risks associated with all of these=20 institutions are acceptable.

Oil and gas properties.

=95

Full = cost=20 accounting. We use the full cost method of accounting for our = oil and=20 gas properties. Under this method, all costs incurred in the = exploration=20 and development of oil and gas properties are Capitalized into a = cost=20 center. These costs include drilling and equipping productive = wells, dry=20 hole costs, seismic costs and delay rentals. Capitalized costs = also=20 include salaries, employee benefits, consulting services and other = expenses that directly relate to our exploration and development=20 activities.

=95

Proved = oil and gas=20 reserves quantities. Proved oil and gas reserves are the = estimated=20 quantities of crude oil and natural gas which geologic and = engineering=20 data demonstrate with reasonable certainty to be recoverable in = future=20 periods from known reservoirs under existing economic and = operating=20 conditions. The estimates of proven reserves for a given reservoir = may=20 change significantly over time as a result of changing prices, = operating=20 cost, additional development activity and the actual operating=20 performance. We continually make revisions to reserve estimates = throughout=20 the year as additional information becomes available.=20

=95

Depreciation,=20 depletion and amortization. The quantities of proved oil and = gas=20 reserves are a significant component of our calculation of = depreciation,=20 depletion and amortization expense, and revisions in such = estimates may=20 alter the rate of future expense. The depreciation, depletion and=20 amortization rate is determined using the units-of-production = method based=20 on estimates of proved oil and gas reserves and production, which = are=20 converted to a common unit of measure based on the relative energy = content.

=95

Full = cost ceiling=20 limitation. Under the full cost method, the net Capitalized = costs of=20 oil and gas properties recorded on our balance sheet cannot exceed = the=20 estimated future net revenues discounted at 10%, adjusted for = derivatives=20 accounted for as cash flow hedges, plus the lower of cost or fair = market=20 value of unproved properties. The ceiling calculation requires = that prices=20 and costs used to determine the estimated future net revenues are = those in=20 effect as of the last day of the quarter. If oil and gas prices = decline or=20 if we have downward revisions to our estimated reserve quantities, = it is=20 possible that write downs of our oil and gas properties could = occur in the=20 future.

=95

Costs = not subject to=20 amortization. Costs of unevaluated properties are excluded = from our=20 amortization base until we have evaluated the properties. The = costs=20 associated with unevaluated leasehold acreage and seismic data,=20 exploratory wells currently drilling and Capitalized interest are=20 initially excluded from our amortization base. Leasehold costs are = either=20 transferred to the amortization base with the costs of drilling a = well or=20 are assessed quarterly for possible impairment. Our future = depreciation,=20 depletion and amortization rate would increase if costs are = transferred to=20 the amortization base without any associated reserves.=20

Table=20 of Contents

=95

Future = development=20 and abandonment costs. Our future development cost include = costs to be=20 incurred to obtain access to proved reserves such as drilling = costs and=20 the installation of production equipment. Future abandonment costs = include=20 costs to plug and abandon our oil and gas properties and related=20 facilities. We develop estimates of these costs for each of our = properties=20 based on their location, type of facility, market demand for = equipment and=20 currently available procedures. Because these costs typically = extend many=20 years into the future, estimating these future costs is difficult = and=20 requires management to make numerous judgments. These judgments = are=20 subject to future revisions from changing technology and = regulatory=20 requirements. We review our assumptions and estimates of future=20 development and future abandonment costs on a quarterly basis.=20

In accordance with Statement of Accounting = Standards=20 No. 143, Accounting for Asset Retirement Obligations, we = record a=20 liability for the discounted fair value of an asset retirement = obligation in the=20 period in which it is incurred and the corresponding cost is Capitalized = by=20 increasing the carrying value of the related asset. The liability is = accreted to=20 its present value each period and the Capitalized cost is depreciated = over the=20 useful life of the related asset.

We use the present value of estimated cash = flows related=20 to our asset retirement obligation to determine the fair value. The = present=20 value calculation requires us to make numerous assumptions and = judgments,=20 including the ultimate costs of dismantling and site restoration, = inflation=20 factors, credit adjusted discount rates, timing of settlement and = changes in the=20 legal, regulatory, environmental and political environments. To the = extent=20 future revisions to these assumptions impact the present value of the = existing=20 asset retirement obligation liability, a corresponding adjustment will = be=20 required for the related asset. We believe the estimates and judgments = reflected=20 in our financial statements are reasonable but are necessarily subject = to the=20 uncertainties we have just described. Accordingly, any significant = variance in=20 any of the above assumptions or factors could materially affect our = estimated=20 future cash flows.

Income taxes. We provide for income = taxes in=20 accordance with Statement on Financial Accounting Standards = No. 109,=20 Accounting for Income Taxes. Deferred income taxes are provided for = the=20 difference between the tax basis of assets and liabilities and the = carrying=20 amount in our financial statements. This difference will result in = taxable=20 income or deductions in future years when the reported amount of the = asset or=20 liability is settled. Since our tax returns are filed after the = financial=20 statements are prepared, estimates are required in valuing tax assets = and=20 liabilities. We record adjustments to actual in the period we file our = tax=20 returns.

Valuation allowance for NOL = carryforwards. In=20 computing our income tax expense, we assess the need for a valuation = allowance=20 on deferred tax assets, which consist primarily of net operating loss, = or NOL,=20 carryforwards. For federal income tax purposes these NOL carryforwards = expire 15=20 to 20 years from the year of origination. Generally we assess our = ability to=20 fully utilize these carryforwards by estimating expected future taxable = income=20 based on the assumption that we will produce our existing reserves, as = scheduled=20 for production in our reserve report and by analyzing the expected = reversal of=20 existing deferred tax liabilities. These computations are imprecise due = to the=20 extensive use of estimates and assumptions. Each quarter we assess our = ability=20 to utilize NOL carryforwards. We will record a valuation allowance for = the=20 amount of net deferred tax assets when, in management=92s opinion, it is = more=20 likely than not that such asset will not be realized.

Also see the footnote disclosures included in = Part 1,=20 Item 1 of this report.

Recent accounting=20 pronouncements

See recently adopted and issued accounting = standards in=20 Part I, Item 1. Financial Statements, Note 1: Nature of operations = and=20 summary of significant accounting policies.

ITEM 3.

QUANTITATIVE AND QUALITATIVE = DISCLOSURES ABOUT MARKET RISK =

Oil and gas prices. Our financial = condition,=20 results of operations and Capital resources are highly dependent upon = the=20 prevailing market prices of, and demand for, oil and gas. These = commodity prices=20 are subject to wide fluctuations and market uncertainties due to a = variety of=20 factors that are beyond our control. We cannot predict future oil and = gas prices=20 with any degree of certainty. Sustained declines in oil and gas prices = may=20 adversely affect our financial condition and results of operations, and = may also=20 reduce the amount of net oil and gas reserves that we can produce = economically.=20 Any reduction in reserves, including reductions due to price = fluctuations, can=20 reduce our borrowing base under our Credit Agreement and adversely = affect our=20 liquidity and our ability to obtain Capital for our acquisition, = exploration and=20 development activities.

Based on our production for the six months = ended=20 June 30, 2009, our gross revenues from oil and gas sales would = change=20 approximately $1.2 million for each $0.10 change in gas prices and $1.9 = million=20 for each $1.00 change in oil prices.

Table=20 of Contents

To mitigate a portion of our exposure to = fluctuations in=20 commodity prices, we enter into commodity price swaps, costless collars, = and=20 basis protection swaps. For commodity price swaps, we receive a fixed = price for=20 the hedged commodity and pay a floating market price to the = counterparty. The=20 fixed-price payment and the floating-price payment are netted, resulting = in a=20 net amount due to or from the counterparty.

In anticipation of the Calumet acquisition, we = entered=20 into additional commodity swaps to provide protection against a decline = in the=20 price of oil. We do not believe that these instruments qualify as hedges = pursuant to SFAS 133. Therefore, the changes in fair value and = settlement of=20 these derivative contracts are recognized as non-hedge derivative = losses. Also,=20 as a result of the acquisition, Chaparral assumed the existing Calumet = swaps on=20 October 31, 2006, and designated these as cash flow hedges. As of=20 December 31, 2008, the hedges assumed as part of the Calumet = acquisition=20 have been settled.

Our outstanding oil and gas derivative = instruments as of=20 June 30, 2009, are summarized below:


	Crude oil=20 swaps	Crude oil=20 collars		Percent=20 of PDP production(1)
	Hedge	Non-hedge		Non-hedge
	Volume MBbl	Weighted average fixed price to=20 be received		Volume MBbl		Weighted average fixed price to be receiv= ed		Volume MBbl	Weighted average range to be received
3Q 2009	571	$	67.47		90		$	66.57	60	$	110.00 - $164.28	84.1	%
4Q 2009	553		67.47		90			66.18	60		110.00 - = 164.28	84.8	%
1Q 2010	495		67.69		102			65.80	60		110.00 - = 168.55	81.6	%
2Q 2010	495		67.62		90			65.47	60		110.00 - = 168.55	82.3	%
3Q 2010	468		67.51		90			65.10	60		110.00 - = 168.55	80.7	%
4Q 2010	447		66.81		90			64.75	60		110.00 - = 168.55	84.5	%
1Q 2011	309		64.40		99			64.24	51		110.00 - = 152.71	66.4	%
2Q 2011	309		64.06		90			63.93	51		110.00 - = 152.71	66.4	%
3Q 2011	309		63.71		90			63.61	51		110.00 - = 152.71	67.8	%
4Q 2011	309		63.33		90			63.30	51		110.00 - = 152.71	69.1	%

	4,265				921				564

(1)	Based on our=20 most recent internally estimated PDP production for such periods.=20

Table=20 of Contents


	Natural = gas=20 swaps non-hedge	Natural = gas=20 collars non-hedge		Percent=20 of PDP production (1)
	Volume BBtu	Weighted average fixed price to be receiv= ed		Volume BBtu		Weighted=20 average range to be received
3Q 2009	1,590	$	8.41		990		$	10.00 - $13.85	43.4	%
4Q 2009	2,900		7.91		990			10.00 - = 13.85	70.4	%
1Q 2010	3,150		7.73		840			10.00 - = 11.53	76.9	%
2Q 2010	3,150		7.05		840			10.00 - = 11.53	81.3	%
3Q 2010	3,150		7.27		840			10.00 - = 11.53	85.5	%
4Q 2010	3,150		7.69		840			10.00 - = 11.53	94.5	%
1Q 2011	2,400		7.91		=97			=97	59.4	%
2Q 2011	2,400		7.03		=97			=97	61.8	%
3Q 2011	2,400		7.20		=97			=97	64.4	%
4Q 2011	2,400		7.55		=97			=97	66.6	%

	26,690				5,340


	Natural = gas=20 basis protection swaps non-hedge
	Volume BBtu	Weighted average fixed price to be=20 paid
3Q 2009	4,620	$	0.91
4Q 2009	4,440		0.94
1Q 2010	4,950		0.94
2Q 2010	3,300		0.80
3Q 2010	3,300		0.80
4Q 2010	3,500		0.80
1Q 2011	3,600		0.80
2Q 2011	2,550		0.75
3Q 2011	2,550		0.75
4Q 2011	2,550		0.75

	35,360

(1)	Based on our=20 most recent internally estimated PDP production for such periods.=20

Subsequent to June 30, 2009, we entered = into=20 additional oil swaps for 260 MBbls for the periods of January 2010 = through=20 December 2011 with a weighted average price of $80.26. We also entered = into=20 additional gas swaps for 600 BBtu for the periods of January through = December=20 2011 with a weighted average price of $6.76.

Interest rates. All of the = outstanding=20 borrowings under our Credit Agreement as of June 30, 2009, are = subject to=20 market rates of interest as determined from time to time by the banks. = We may=20 designate borrowings under our Credit Agreement as either ABR loans or=20 Eurodollar loans. ABR loans bear interest at a fluctuating rate that is = linked=20 to the greater of (1) the Prime Rate, as defined in our Credit = Agreement,=20 (2) the Federal Funds Effective Rate plus 1 / 2 of 1%, or (3) the Adjusted = LIBO rate, as=20 defined in our Credit Agreement. Eurodollar loans bear interest at a = fluctuating=20 rate that is linked to the Adjusted LIBO Rate, defined as the greater of = 2% or=20 the rate applicable to dollar deposits in the London interbank market. = Any=20 increases in these rates can have an adverse impact on our results of = operations=20 and cash flow. Assuming a constant debt level of $513.0 million, equal = to our=20 borrowing base, the cash flow impact for a 12-month period resulting = from a 100=20 basis point change in interest rates would be $5.1 million.

Table=20 of Contents

ITEM 4.

CONTROLS AND=20 PROCEDURES

Disclosure controls and procedures =

We have established disclosure controls and = procedures to=20 ensure that material information relating to the Company, including its=20 consolidated subsidiaries, is made known to the officers who certify our = financial reports and to other members of senior management and the = Board of=20 Directors. Based on their evaluation as of the end of the period covered = by this=20 quarterly report, our Chairman, President and Chief Executive Officer = and our=20 Executive Vice President and Chief Financial Officer have concluded that = our=20 disclosure controls and procedures (as defined in Rules 13a-15(e) = and=20 15d-15(e) under the Securities Exchange Act of 1934) are effective to = ensure=20 that the information required to be disclosed by us in the reports that = we file=20 or submit under the Securities Exchange Act of 1934 is recorded, = processed,=20 summarized and reported within the time periods specified in SEC rules = and forms=20 and are effective to ensure that information required to be disclosed in = such=20 reports is accumulated and communicated to our management, including our = principal executive officer and principal financial officer, to allow = timely=20 decisions regarding required disclosure.

Internal control over financial reporting=20

There were no changes in our internal control = over=20 financial reporting that occurred during the most recent fiscal quarter = that=20 have materially affected, or are reasonably likely to materially affect, = our=20 internal control over financial reporting.

PART = II=97OTHER=20 INFORMATION

ITEM 1.

LEGAL PROCEEDINGS =

In the opinion of management, there are no = other material=20 pending legal proceedings to which we or any of our subsidiaries are a = party or=20 of which any of our property is the subject. However, due to the nature = of our=20 business, certain legal or administrative proceedings may arise from = time to=20 time in the ordinary course of business.

ITEM 1A.

RISK FACTORS =

Information with respect to risk factors is = included=20 under Item 1A. of our Annual Report on Form 10-K for the year ended = December 31, 2008. There have been no material changes to the risk = factors=20 since the filing of such Form 10-K.

ITEM 6.

EXHIBITS =


Exhibit No.		Description

10.20*		Fifth = Amendment to=20 Seventh Restated Credit Agreement dated as of May 21, 2009.=20 (Incorporated by reference to Exhibit 10.1 of the Company=92s = Current Report=20 on Form 8-K (SEC File No. 333-134748), filed on May 26,=20 2009)

Table=20 of Contents


Exhibit No.		Description

31.1		Certification by Chief=20 Executive Officer required by Rule 13a-14(a) and 15d-14(a) under = the=20 Exchange Act

31.2		Certification by Chief=20 Financial Officer required by Rule 13a-14(a) and 15d-14(a) under = the=20 Exchange Act

32.1		Certification by Chief=20 Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted = pursuant=20 to Section 906 of the Sarbanes-Oxley Act of 2002

32.2		Certification of Chief=20 Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted = pursuant=20 to Section 906 of the Sarbanes-Oxley Act of=20 2002

*	Incorporated=20 by reference

Table=20 of Contents

SIGNATURES =

Pursuant to the requirements of the Securities = Exchange=20 Act of 1934, the registrant has duly caused this report to be signed on = its=20 behalf by the undersigned thereunto duly authorized.


CHAPARRAL=20 ENERGY, INC.

By:		/s/ Mark A. = Fischer
Name:		Mark A.=20 Fischer
Title:		President and Chief Executive=20 Officer
		(Principal Executive = Officer)

By:		/s/ Joseph O. = Evans
Name:		Joseph=20 O. Evans
Title:		Chief Financial Officer = and
		Executive Vice = President
		(Principal Financial Officer = and
		Principal Accounting=20 Officer)

Date: August 13, 2009

Table=20 of Contents

EXHIBIT INDEX


Exhibit No.		Description

10.20*		Fifth = Amendment to=20 Seventh Restated Credit Agreement dated as of May 21, 2009.=20 (Incorporated by reference to Exhibit 10.1 of the Company=92s = Current Report=20 on Form 8-K (SEC File No. 333-134748), filed on May 26,=20 2009)

Table=20 of Contents


Exhibit No.		Description

31.1		Certification by Chief=20 Executive Officer required by Rule 13a-14(a) and 15d-14(a) under = the=20 Exchange Act

31.2		Certification by Chief=20 Financial Officer required by Rule 13a-14(a) and 15d-14(a) under = the=20 Exchange Act

32.1		Certification by Chief=20 Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted = pursuant=20 to Section 906 of the Sarbanes-Oxley Act of 2002

32.2		Certification of Chief=20 Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted = pursuant=20 to Section 906 of the Sarbanes-Oxley Act of=20 2002

*	Incorporated=20 by reference