e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


		QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2009.

Commission file number: 0-17371

QUEST RESOURCE CORPORATION

(Exact name of registrant as specified in its charter)



Nevada (State or other jurisdiction of incorporation or organization)		90-0196936 (I.R.S. Employer Identification No.)

210 Park Avenue, Suite 2750, Oklahoma City, OK 73102
(Address of principal executive offices) (Zip Code)

405-600-7704
(Registrant’s telephone number, including area code)

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

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

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


Large accelerated filer o		Accelerated filer þ		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

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

As of August 12, 2009, the issuer had 32,025,976 shares of common stock outstanding.

QUEST RESOURCE CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)


	June 30,			December 31,
	2009			2008
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	42,413		$	13,785
Restricted cash		760			559
Accounts receivable — trade, net		15,392			16,715
Other receivables		7,932			9,434
Other current assets		2,473			2,858
Inventory		11,235			11,420
Current derivative financial instrument assets		35,123			42,995

Total current assets		115,328			97,766
Oil and gas properties under full cost method of accounting, net		49,413			172,537
Pipeline assets, net		305,299			310,439
Other property and equipment, net		21,514			23,863
Other assets, net		11,080			14,735
Long-term derivative financial instrument assets		1,876			30,836

Total assets	$	504,510		$	650,176


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	17,284		$	35,804
Revenue payable		8,901			8,309
Accrued expenses		8,955			7,138
Current portion of notes payable		54,970			45,013
Current derivative financial instrument liabilities		411			12

Total current liabilities		90,521			96,276
Non-current liabilities:
Long-term derivative financial instrument liabilities		8,153			4,230
Asset retirement obligations		6,211			5,922
Notes payable		307,722			343,094
Commitments and contingencies
Stockholders’ equity (deficit):
Preferred stock, $0.001 par value; authorized shares — 50,000,000; none issued and outstanding		—			—
Common stock, $0.001 par value; authorized shares — 200,000,000; issued — 32,193,531 and 32,224,643 at June 30, 2009 and December 31, 2008; outstanding — 31,869,279 and 31,720,312 at June 30, 2009 and December 31, 2008, respectively		33			33
Additional paid-in capital		299,031			298,583
Treasury stock, at cost		(7	)		(7	)
Accumulated deficit		(371,896	)		(302,491	)

Total stockholders’ deficit before non-controlling interests		(72,839	)		(3,882	)
Non-controlling interests		164,742			204,536

Total stockholders’ equity		91,903			200,654

Total liabilities and stockholders’ equity	$	504,510		$	650,176

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

F-1

QUEST RESOURCE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except share and per share data)
(Unaudited)


	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Revenue:
Oil and gas sales	$	16,107		$	49,144		$	38,382		$	87,458
Gas pipeline revenue		7,586			7,148			15,389			14,049

Total revenues		23,693			56,292			53,771			101,507

Costs and expenses:
Oil and gas production		7,274			12,631			14,960			23,037
Pipeline operating		6,861			8,164			14,021			15,122
General and administrative		10,486			6,198			18,368			11,941
Depreciation, depletion and amortization		9,086			16,444			25,206			31,333
Impairment of oil and gas properties		—			—			102,902			—
Recovery of misappropriated funds, net of liabilities assumed		(3,397	)		—			(3,397	)		—

Total costs and expenses		30,310			43,437			172,060			81,433

Operating income (loss)		(6,617	)		12,855			(118,289	)		20,074
Other income (expense):
Gain (loss) from derivative financial instruments		(17,138	)		(105,375	)		22,326			(149,614	)
Loss on sale of assets		—			(30	)		—			—
Other income (expense)		83			72			139			122
Interest expense		(6,858	)		(5,174	)		(13,746	)		(10,057	)

Total other income (expense)		(23,913	)		(110,507	)		8,719			(159,549	)

Loss before income taxes		(30,530	)		(97,652	)		(109,570	)		(139,475	)
Income tax expense		—			—			—			—

Net loss	$	(30,530	)	$	(97,652	)	$	(109,570	)	$	(139,475	)

Net loss attributable to noncontrolling interests	$	12,511		$	39,766		$	40,165		$	56,494

Net loss attributable to common stockholders	$	(18,019	)	$	(57,886	)	$	(69,405	)	$	(82,981	)

Basic and diluted net loss attributable to common stockholders per common share	$	(0.57	)	$	(2.53	)	$	(2.18	)	$	(3.65	)

Basic and diluted weighted average shares outstanding		31,867,857			22,844,600			31,798,546			22,742,289

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

F-2

QUEST RESOURCE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)


	Six Months Ended
	June 30,
	2009			2008
Cash flows from operating activities:
Net loss	$	(109,570	)	$	(139,475	)
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation, depletion and amortization		25,206			31,333
Impairment of oil and gas properties		102,902			—
Stock-based compensation		448			3,045
Stock-based compensation — non-controlling interests		371			243
Amortization of deferred loan costs		2,097			1,052
Change in fair value of derivative financial instruments		41,154			139,344
Bad debt expense		—			73
Non-cash portion of gain on recovery of misappropriated funds		(977	)		—
Change in assets and liabilities:
Accounts receivable		1,322			(877	)
Other receivables		2,336			(1,986	)
Other current assets		386			(1,037	)
Other assets		116			(341	)
Accounts payable		(16,152	)		13,763
Revenue payable		480			227
Accrued expenses		1,817			4,884
Other long-term liabilities		(1	)		427
Other		(57	)		(427	)

Net cash flows from operating activities		51,878			50,248

Cash flows from investing activities:
Change in restricted cash		(201	)		783
Equipment, development, leasehold and pipeline additions		(5,256	)		(98,000	)
Proceeds from sale of oil and gas properties		8,730			—

Net cash flows from investing activities		3,273			(97,217	)

Cash flows from financing activities:
Proceeds from bank borrowings		1,430			4,000
Repayments of note borrowings		(9,662	)		(313	)
Proceeds from revolver		—			75,000
Repayment of revolver		(17,902	)		—
Distributions to unitholders		—			(16,845	)
Refinancing costs		(389	)		—

Net cash flows from financing activities		(26,523	)		61,842

Net increase in cash		28,628			14,873
Cash and cash equivalents, beginning of period		13,785			6,680

Cash and cash equivalents, end of period	$	42,413		$	21,553

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

F-3

QUEST RESOURCE CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 1 — Basis of Presentation

These condensed consolidated financial statements have been prepared by Quest Resource Corporation (“QRCP” or the “Company”) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), and reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for the interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. These financial statements should be read in conjunction with the financial statements and the summary of significant accounting policies and notes included in the Company’s Annual Report on Form 10-K/A for the year ended December 31, 2008 (the “2008 Form 10-K/A”).

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The operating results for the interim periods are not necessarily indicative of the results to be expected for the full year.

Certain prior period amounts have been reclassified to conform to current year presentation. These reclassifications had no effect on previously reported net income.

Unless the context clearly requires otherwise, references to “us”, “we”, “our”, “QRCP”, or the “Company” are intended to mean Quest Resource Corporation and its consolidated subsidiaries.

In December 2007, the Financial Accounting Standards Board (the “FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 160, Non-controlling Interests in Consolidated Financial Statements — An Amendment of ARB No. 51 (“SFAS 160”). SFAS No. 160 establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the non-controlling interest, and changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary. In addition, SFAS No. 160 establishes principles for valuation of retained non-controlling equity investments and measurement of gain or loss when a subsidiary is deconsolidated. SFAS No. 160 also establishes disclosure requirements to clearly identify and distinguish between interests of the parent and the interests of the non-controlling owners. The Company adopted SFAS No. 160 effective January 1, 2009. Under SFAS No. 160, QRCP is required to classify amounts previously presented as a minority interest liability as a component of equity in the condensed consolidated balance sheet and is required to present net income attributable to QRCP and the minority partners’ ownership interest separately in the condensed consolidated statement of operations. All prior periods have been reclassified to comply with SFAS No. 160.

Going Concern

The accompanying condensed consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates the realization of assets and the liquidation of liabilities in the normal course of business, though such an assumption may not be true. The Company has incurred significant losses from 2003 through 2008 and into 2009, mainly attributable to operations, legal restructurings, financings, the current legal and operational structure and, to a lesser degree, the cash expenditures resulting from the investigation related to certain unauthorized transfers, repayments and re-transfers of funds to entities controlled by our former chief executive officer (“the Transfers”). We have determined that there is substantial doubt about our ability to continue as a going concern.

QRCP is almost exclusively dependent upon distributions from its partnership interests in Quest Energy Partners, L.P. (“QELP” or “Quest Energy”) and Quest Midstream Partners, L.P. (“QMLP” or “Quest Midstream”) for cash flow. Quest Midstream has not paid any distributions on any of its units since the second quarter of 2008, and Quest Energy suspended its distributions on its subordinated units since the third quarter of 2008 and all units starting with the fourth quarter of 2008. QRCP does not expect to receive any distributions from Quest

F-5

QUEST RESOURCE CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

Energy or Quest Midstream for the remainder of 2009 and is unable to estimate at this time when such distributions may be resumed.

Although QRCP is not currently receiving distributions from Quest Energy or Quest Midstream, it continues to require cash to fund general and administrative expenses, debt service requirements, capital expenditures to develop and maintain its undeveloped acreage, drilling commitments and payments to landowners necessary to maintain its oil and gas leases.

Recombination — Given the liquidity challenges facing the Company, Quest Midstream and Quest Energy, each entity has undertaken a strategic review of its assets and has evaluated and continues to evaluate transactions to dispose of assets in order to raise additional funds for operations and/or to repay indebtedness. On July 2, 2009, QRCP, Quest Midstream and Quest Energy entered into an Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which would form a new, yet to be named, publicly-traded holding corporation (“New Quest”) that, through a series of mergers and entity conversion, would wholly-own all three entities (“the Recombination”).

Cash and Capital Resources — While we anticipate completion of the Recombination before the end of 2009, it remains subject to the satisfaction of a number of conditions, including, among others, the arrangement of one or more satisfactory credit facilities for New Quest, the approval of the transaction by our stockholders and the unitholders of QELP and QMLP, and consents from each entity’s existing lenders. There can be no assurance that these conditions will be met or that the Recombination will occur.

Upon completion of the Recombination, the equity of New Quest would be owned approximately 44% by current QMLP common unit holders, approximately 33% by current QELP common unit holders (other than QRCP), and approximately 23% by current QRCP stockholders.

As of June 30, 2009, QRCP, excluding QELP and QMLP, had cash and cash equivalents of $1.1 million and no ability to borrow under the terms of its existing credit agreement. QRCP currently estimates that it will not have enough cash to pay its expenses, including capital expenditures and debt service requirements, after September 15, 2009. This date could be extended if QRCP is able to restructure its debt obligations, issue equity securities and/or sell additional assets. The accompanying financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Recent Accounting Pronouncements and Recently Adopted Accounting Pronouncements

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 133 (“SFAS No. 161”). This statement does not change the accounting for derivatives but will require enhanced disclosures about derivative strategies and accounting practices. We adopted SFAS No. 161 effective January 1, 2009. See Note 4 – Derivative Financial Instruments for the impact to our disclosures.

The Company adopted FASB Staff Position (“FSP”) Emerging Issues Task Force No. 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (“EITF No. 03-6-1”), effective January 1, 2009. EITF No. 03-6-1 addresses whether instruments granted in share-based payment transactions are considered participating securities prior to vesting and therefore included in the allocation of earnings for purposes of calculating earnings per unit (“EPU”) under the two-class method as required by SFAS No. 128, Earnings per Share. EITF No. 03-6-1 provides that unvested unit-based awards that contain non-forfeitable rights to dividends are participating securities and should be included in the computation of EPU. The Company’s restricted stock units contain non-forfeitable rights to dividends and thus require these awards to be included in the EPU computation. All prior periods have been conformed to the current year presentation. During periods of losses, EPU will not be impacted, as the Company’s participating securities are not obligated to share in the losses of the Company and thus, are not included in the EPU share computation. See Note 7 – Stockholders’ Equity and Earnings per Share.

In December 2008, the SEC issued Release No. 33-8995, Modernization of Oil and Gas Reporting, which revises disclosure requirements for oil and gas companies. In addition to changing the definition and disclosure requirements for oil and gas reserves, the new rules change the requirements for determining oil and gas reserve quantities. These rules permit the use of new technologies to determine proved reserves under certain criteria and allow companies to disclose their probable and possible reserves. The new rules also require companies to report the independence and qualifications of their reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit. The new rules also require that oil and gas reserves be reported and the full cost ceiling limitation be calculated using a twelve-month average price rather than period-end prices. The use of a twelve-month average price could have had an effect on our 2009 depletion rates for our natural gas and crude oil properties and the amount of the impairment recognized as of December 31, 2008 had the new rules been effective for the period. The new rules are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, pending the potential alignment of certain accounting standards by the FASB with the new rule. We plan to implement the new requirements in our Annual Report on Form 10-K for the year ended December 31, 2009. We are currently evaluating the impact of the new rules on our consolidated financial statements.

F-6

QUEST RESOURCE CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

In May 2009, the FASB issued SFAS No. 165, Subsequent Events, or (“SFAS No. 165”). SFAS No. 165 establishes general standards of accounting for and disclosure of transactions and events that occur after the balance sheet date but before financial statements are issued or are available to be issued. It also requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date. We adopted SFAS No. 165 for the period ending June 30, 2009. See Note 12 — Subsequent Events.

In June 2009, the FASB issued SFAS No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles — A Replacement of FASB Statement No. 162. The FASB Accounting Standards Codification (the “Codification”) will become the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date, the Codification will supersede all then-existing non-SEC accounting and reporting standards. This standard is effective for interim and annual periods ending after September 15, 2009. This standard will not have a material impact on our consolidated financial statements upon adoption.

Note 2 — Acquisition and Divestiture

Acquisition

PetroEdge — On July 11, 2008, QRCP completed the acquisition of privately held PetroEdge Resources (WV) LLC (“PetroEdge”) in an all cash purchase for approximately $142 million in cash including transaction costs, subject to certain adjustments for working capital and certain other activity between May 1, 2008 and the closing date. At the time of the acquisition, PetroEdge owned approximately 78,000 net acres of oil and natural gas producing properties in the Appalachian Basin with estimated net proved reserves of 99.6 Bcfe as of May 1, 2008 and net production of approximately 3.3 million cubic feet equivalent per day (“Mmcfe/d”). The transaction was recorded within QRCP’s oil and gas production segment and was funded using the proceeds from QRCP’s July 8, 2008 public offering of 8,800,000 shares of common stock, borrowings under QELP’s revolving credit facility and the proceeds of a $45 million, six-month term loan entered into by QELP.

Pro Forma Summary Data Related to Acquisition (Unaudited)

The following unaudited pro forma information summarizes the results of operations for the periods indicated, as if the PetroEdge acquisition had occurred at the beginning of the period (in thousands, except per share data):


	Three Months Ended			Six Months Ended
	June 30,			June 30,
	2008			2008
Pro forma revenue	$	59,492		$	108,057
Pro forma net income (loss)	$	(59,908	)	$	(87,108	)
Pro forma net income (loss) per share — basic and diluted	$	(1.84	)	$	(2.76	)

Divestiture

On February 13, 2009, we divested of approximately 23,000 net undeveloped acres and one well in Lycoming County, Pennsylvania to a private party for approximately $8.7 million. The proceeds were credited to the full cost pool.

F-7

QUEST RESOURCE CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

Note 3 — Long-Term Debt

The following is a summary of QRCP’s long-term debt as of the periods indicated (in thousands):


	June 30,		December 31,
	2009		2008
Borrowings under bank senior credit facilities
QRCP	$	29,420	$	29,000
Quest Energy:
Quest Cherokee Credit Agreement		174,000		189,000
Second Lien Loan Agreement		33,600		41,200
Quest Midstream		125,098		128,000
Notes payable to banks and finance companies		574		907

Total debt		362,692		388,107
Less current maturities included in current liabilities		54,970		45,013

Total long-term debt	$	307,722	$	343,094

Credit Facilities

QRCP.

At June 30, 2009, $29.4 million was outstanding under the term loan. The weighted average interest rate for the quarter ended June 30, 2009 was 12.25%.

On January 30, 2009, QRCP entered into a Third Amendment to Amended and Restated Credit Agreement that restricted the use of proceeds from certain asset sales.

On May 29, 2009, QRCP entered into a Fourth Amendment to Amended and Restated Credit Agreement pursuant to the terms of which (i) the lender waived the financial covenant defaults for the quarters ended December 31, 2008 and March 31, 2009; (ii) the lender waived the mandatory prepayment for the Collateral Deficiency for the quarters ended December 31, 2008, March 31, 2009 and June 30, 2009; and (iii) the reporting deadline for certain financial statements was extended.

On June 30, 2009, QRCP entered into a Fifth Amendment to Amended and Restated Credit Agreement in order to, among other things, (i) waive the financial covenant defaults for the quarter ended June 30, 2009, (ii) waive the mandatory prepayment due to the Collateral Deficiency for the quarter ended June 30, 2009, and (iii) defer the reporting deadline for certain financial statements.

Quest Energy.

A. Quest Cherokee Credit Agreement.

Quest Cherokee LLC (“Quest Cherokee”) is a party to an Amended and Restated Credit Agreement, as amended (the “Quest Cherokee Credit Agreement”), with RBC, KeyBank National Association (“KeyBank’) and the lenders party thereto for a $250 million revolving credit

F-8

QUEST RESOURCE CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

facility, which is guaranteed by Quest Energy. Availability under the revolving credit facility is tied to a borrowing base that will be redetermined by the lenders every six months taking into account the value of Quest Cherokee’s proved reserves.

The borrowing base was $190.0 million as of June 30, 2009. The amount borrowed under the Quest Cherokee Credit Agreement as of June 30, 2009 was $174.0 million. At June 30, 2009, Quest Cherokee had $15.0 million available for borrowing, with the remaining $1.0 million supporting letters of credit issued under the Quest Cherokee Credit Agreement. The weighted average interest rate under the Quest Cherokee Credit Agreement for the quarter ended June 30, 2009 was 5.09%.

In July 2009, the borrowing base under the Quest Cherokee Credit Agreement was reduced from $190 million to $160 million, which, following the payment discussed below, resulted in the outstanding borrowings under the Quest Cherokee Credit Agreement exceeding the new borrowing base by $14 million (the “Borrowing Base Deficiency”). In anticipation of the reduction in the borrowing base, Quest Energy amended or exited certain of its above market natural gas price derivative contracts and, in return, received approximately $26 million. The strike prices on the derivative contracts that Quest Energy did not exit were set to market prices at the time. At the same time, Quest Energy entered into new natural gas price derivative contracts to increase the total amount of its future proved developed natural gas production hedged to approximately 85% through 2013. On June 30, 2009, using these proceeds, Quest Energy made a principal payment of $15 million on the Quest Cherokee Credit Agreement. On July 8, 2009, Quest Energy repaid the $14 million Borrowing Base Deficiency.

On June 18, 2009, Quest Energy and Quest Cherokee entered into a Third Amendment to Amended and Restated Credit Agreement that, among other things, permits Quest Cherokee’s obligations under oil and gas derivative contracts with BP Corporation North America, Inc. or any of its affiliates to be secured by the liens under the Quest Cherokee Credit Agreement on a pari passu basis with the obligations under the Quest Cherokee Credit Agreement. On June 30, 2009, Quest Energy and Quest Cherokee entered into a Fourth Amendment to Amended and Restated Credit Agreement that deferred Quest Energy’s obligation to deliver certain financial statements.

Quest Cherokee was in compliance with all of its covenants as of June 30, 2009.

B. Second Lien Loan Agreement.

Quest Energy and Quest Cherokee are parties to a Second Lien Senior Term Loan Agreement, as amended (the “Second Lien Loan Agreement”), dated as of July 11, 2008, with RBC, KeyBank, Société Générale and the parties thereto for a $45 million term loan due and maturing on September 30, 2009.

Quest Energy made quarterly principal payments of $3.8 million on February 17, 2009 and May 15, 2009 and August 17, 2009.

As of June 30, 2009, $33.6 million was outstanding under the Second Lien Loan Agreement. The weighted average interest rate under the Second Lien Loan Agreement for the quarter ended June 30, 2009 was 11.25%.

On June 30, 2009, Quest Energy and Quest Cherokee entered into a Second Amendment to the Second Lien Senior Term Loan Agreement that deferred Quest Energy’s obligation to deliver certain financial statements to the lenders.

Quest Cherokee was in compliance with all of its covenants as of June 30, 2009.

Quest Midstream.

Quest Midstream and its wholly-owned subsidiary, Bluestem Pipeline, LLC, have a separate $135 million syndicated revolving credit facility under an Amended and Restated Credit Agreement, as amended (“Quest Midstream Credit Agreement”), with RBC and the lenders party thereto.

As of June 30, 2009, the amount borrowed under the Quest Midstream Credit Agreement was $125.1 million. The weighted average interest rate for the quarter ended June 30, 2009 was 4.67%.

Quest Midstream was in compliance with all of its covenants as of June 30, 2009.

F-9

QUEST RESOURCE CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

Note 4 — Derivative Financial Instruments

Our objective in entering into derivative financial instruments is to manage exposure to commodity price and interest rate fluctuations, protect our returns on investments, and achieve a more predictable cash flow in connection with our acquisition activities and borrowings related to these activities. These transactions limit exposure to declines in prices or increases in interest rates, but also limit the benefits we would realize if prices increase or interest rates decrease. When prices for oil and natural gas or interest rates are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expense due to changes in the fair value of our derivative financial instrument contracts. Cash charges or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration. Specifically, we utilize futures, swaps and options. Futures contracts and commodity swap agreements are used to fix the price of expected future oil and gas sales at major industry trading locations, such as Henry Hub, Louisiana for gas and Cushing, Oklahoma for oil. Basis swaps are used to fix or float the price differential between the price of gas at Henry Hub and various other market locations. Options are used to fix a floor and a ceiling price (collar) for expected future oil and gas sales. Derivative financial instruments are also used to manage commodity price risk inherent in customer pricing requirements and to fix margins on the future sale of natural gas.

Settlements of any exchange-traded contracts are guaranteed by the New York Mercantile Exchange (NYMEX) or the Intercontinental Exchange and are subject to nominal credit risk. Over-the-counter traded swaps, options and physical delivery contracts expose us to credit risk to the extent the counterparty is unable to satisfy its settlement commitment. We monitor the creditworthiness of each counterparty and assess the impact, if any, on fair value. In addition, we routinely exercise our contractual right to net realized gains against realized losses when settling with our swap and option counterparties.

We account for our derivative financial instruments in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”). SFAS No. 133 requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met, or exemptions for normal purchases and normal sales (“NPNS”) as permitted by SFAS No. 133 exist. We do not designate our derivative financial instruments as hedging instruments for financial accounting purposes, and, as a result, we recognize the change in the respective instruments’ fair value currently in earnings. In accordance with SFAS No. 161, the table below outlines the classification of our derivative financial instruments on our condensed consolidated balance sheets and their financial impact in our condensed consolidated statement of operations as of and for the periods indicated (in thousands):

Fair Value of Derivative Financial Instruments


		June 30,			December 31,
Derivative Financial Instruments	Balance Sheet location	2009			2008
Commodity contracts	Derivative financial instruments — Current assets	$	35,123		$	42,995
Commodity contracts	Derivative financial instruments — Long-term assets		1,876			30,836
Commodity contracts	Derivative financial instruments — Current liabilities		(411	)		(12	)
Commodity contracts	Derivative financial instruments — Long-term liabilities		(8,153	)		(4,230	)

Net derivative assets		$	28,435		$	69,589

F-10

QUEST RESOURCE CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

The Effect of Derivative Financial Instruments


		Three months ended						Six months ended
		June 30,						June 30,
Derivative Financial Instruments	Statement of Operations location	2009			2008			2009		2008
Commodity contracts	Gain (loss) from derivative financial instruments	$	(17,138	)	$	(105,375	)	$	22,326	$	(149,614	)

Settlements in the normal course of maturities of our derivative financial instrument contracts result in cash receipts from or cash disbursement to our derivative contract counterparties and are, therefore, realized gains or losses. Changes in the fair value of our derivative financial instrument contracts are included in income currently with a corresponding increase or decrease in the balance sheet fair value amounts. Gains and losses associated with derivative financial instruments related to oil and gas production were as follows for the periods indicated (in thousands):


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Realized gains (losses)	$	46,646		$	(9,059	)	$	63,480		$	(10,270	)
Unrealized losses		(63,784	)		(96,316	)		(41,154	)		(139,344	)

Gain (loss) from derivative financial instruments	$	(17,138	)	$	(105,375	)	$	22,326		$	(149,614	)

F-11

QUEST RESOURCE CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

The following tables summarize the estimated volumes, fixed prices and fair values attributable to gas derivative contracts as of December 31, 2008:


	Year Ending December 31,
	2009		2010		2011		Thereafter		Total
	($ in thousands, except volumes and per unit data)
Natural Gas Swaps:
Contract volumes (Mmbtu)		14,629,200		12,499,060		2,000,004		2,000,004		31,128,268
Weighted-average fixed price per Mmbtu	$	7.78	$	7.42	$	8.00	$	8.11	$	7.67
Fair value, net	$	38,107	$	14,071	$	2,441	$	2,335	$	56,954
Natural Gas Collars:
Contract volumes (Mmbtu):
Floor		750,000		630,000		3,549,996		3,000,000		7,929,996
Ceiling		750,000		630,000		3,549,996		3,000,000		7,929,996
Weighted-average fixed price per Mmbtu:
Floor	$	11.00	$	10.00	$	7.39	$	7.03	$	7.79
Ceiling	$	15.00	$	13.11	$	9.88	$	7.39	$	9.52
Fair value, net	$	3,630	$	1,875	$	3,144	$	2,074	$	10,723
Total Natural Gas Contracts:
Contract volumes (Mmbtu)		15,379,200		13,129,060		5,550,000		5,000,004		39,058,264
Weighted-average fixed price per Mmbtu	$	7.94	$	7.55	$	7.61	$	7.44	$	7.70
Fair value, net	$	41,737	$	15,946	$	5,585	$	4,409	$	67,677
Crude Oil Swaps:
Contract volumes (Bbl)		36,000		30,000		—		—		66,000
Weighted-average fixed per Bbl	$	90.07	$	87.50	$	—	$	—	$	88.90
Fair value, net	$	1,246	$	666	$	—	$	—	$	1,912

Total fair value, net	$	42,983	$	16,612	$	5,585	$	4,409	$	69,589

Note 5 — Fair Value Measurements

Our financial instruments include commodity derivatives, debt, cash, receivables and payables. The carrying value of our debt approximates fair value due to the variable nature of the interest rates. The carrying amount of cash, receivables and accounts payable approximates fair value because of the short-term nature of those instruments.

Effective January 1, 2009, we adopted FSP 157-2, which applies to our nonfinancial assets and liabilities for which we disclose or recognize at fair value on a nonrecurring basis, such as asset retirement obligations and other assets and liabilities. Fair value is the exit price that we would receive to sell an asset or pay to transfer a liability in an orderly transaction between market participants at the measurement date.

F-13

QUEST RESOURCE CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

SFAS No. 157 also establishes a hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy are as follows:

•

Level 1 — Quoted prices available in active markets for identical assets or liabilities as of the reporting date.

•

Level 2 — Pricing inputs other than quoted prices in active markets included in Level 1 which are either directly or indirectly observable as of the reporting date. Level 2 consists primarily of non-exchange traded commodity derivatives.

•

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources.

We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. Certain of our derivatives are classified as Level 3 because observable market data is not available for all of the time periods for which we have derivative instruments. As observable market data becomes available for all of the time periods, these derivative positions will be reclassified as Level 2.

The following table sets forth, by level within the fair value hierarchy, our assets and liabilities that were measured at fair value on a recurring basis as of the periods indicated (in thousands):


									Netting and
	Level		Level			Level			Cash			Total Net Fair
June 30, 2009	1		2			3			Collateral*			Value
Derivative financial instruments — assets	$	—	$	4,952		$	32,047		$	—		$	36,999
Derivative financial instruments — liabilities		—		(368	)		(8,196	)	$	—			(8,564	)

Total	$	—	$	4,584		$	23,851		$	—		$	28,435


December 31, 2008
Derivative financial instruments — assets	$	—	$	8,866		$	64,883		$	(4,160	)	$	69,589
Derivative financial instruments — liabilities		—		(224	)		(3,936	)		4,160			—

Total	$	—	$	8,642		$	60,947		$	—		$	69,589


*		Amounts represent the effect of legally enforceable master netting agreements between the Company and its counterparties and the payable or receivable for cash collateral held or placed with the same counterparties.

Risk management assets and liabilities in the table above represent the current fair value of all open derivative positions, excluding those derivatives designated as NPNS. We classify all of these derivative instruments as “Derivative financial instrument assets” or “Derivative financial instrument liabilities” in our condensed consolidated balance sheets.

In order to determine the fair value of amounts presented above, we utilize various factors, including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and parental guarantees), but also the impact of our nonperformance risk on our liabilities. We utilize observable market data for credit default swaps to assess the impact of non-performance credit risk when evaluating our assets from counterparties.

F-14

QUEST RESOURCE CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

In certain instances, we may utilize internal models to measure the fair value of our derivative instruments. Generally, we use similar models to value similar instruments. Valuation models utilize various inputs which include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the assets or liabilities, and market-corroborated inputs, which are inputs derived principally from or corroborated by observable market data by correlation or other means.

The following table sets forth a reconciliation of changes in the fair value of risk management assets and liabilities classified as Level 3 in the fair value hierarchy (in thousands):


	Six Months Ended
	June 30, 2009
Balance at beginning of period	$	60,947
Realized and unrealized gains included in earnings		19,695
Purchases, sales, issuances, and settlements		(56,791	)
Transfers into and out of Level 3		—

Balance as of June 30, 2009	$	23,851

Note 6 — Asset Retirement Obligations

The following table reflects the changes to our asset retirement liability for the period indicated (in thousands):


	Six Months Ended
	June 30, 2009
Asset retirement obligations at beginning of period	$	5,922
Liabilities incurred		—
Liabilities settled		—
Accretion		289
Revisions in estimated cash flows		—

Asset retirement obligations at end of period	$	6,211

Note 7 — Stockholders’ Equity and Earnings per Share

Share-Based Payments — The granting of stock awards and options to our employees under our 2005 Omnibus Stock Award Plan (the “Award Plan”), as amended, represent share-based payment transactions that are treated as compensation expense with a corresponding increase to additional paid-in capital. During the six months ended June 30, 2009, 300,000 shares were granted under the Award Plan, all of which were stock options. As of June 30, 2009, there were approximately 797,000 shares available under the Award Plan for future stock awards and options. For the three and six months ended June 30, 2009, total share-based compensation related to stock awards and options was $0.2 million and $0.5 million, compared to $1.1 million and $3.0 million for the comparable periods in 2008, respectively. Share-based compensation is included in general and administrative expense on our statement of operations. Total share-based compensation to be recognized on unvested stock awards and options as of June 30, 2009 is $0.8 million over a weighted average period of 1.21 years.

Noncontrolling interests — A rollforward of the noncontrolling interests related to QRCP’s investments in Quest Energy and Quest Midstream for the periods indicated is as follows (in thousands):


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Quest Energy
Beginning of period	$	29,378		$	126,071		$	58,666		$	145,364
Contributions, net		—			—			—			(265	)
Distributions		—			(3,744	)		—			(5,615	)
Net income (loss) attributable to non-controlling interest		(13,247	)		(39,456	)		(42,568	)		(56,625	)
Stock compensation expense related to QELP unit-based awards		—			8			33			20

End of period		16,131			82,879			16,131			82,879

Quest Midstream
Beginning of period		147,698			148,760		$	145,870		$	152,021
Contributions, net		—			—			—
Distributions		—			(3,815	)		—			(7,630	)
Net income (loss) attributable to non-controlling interest		736			(310	)		2,403			131
Stock compensation expense related to QMLP unit-based awards		177			113			338			226

End of period		148,611			144,748			148,611			144,748

Total non-controlling interest at end of period	$	164,742		$	227,627		$	164,742		$	227,627

F-15

QUEST RESOURCE CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

Loss per Share — A reconciliation of the numerator and denominator used in the basic and diluted per share calculations for the periods indicated, is as follows (dollars in thousands, except share and per share amounts):


	Three months ended						Six months ended
	June 30,						June 30,
	2009			2008			2009			2008
Basic and diluted earnings per share:
Net loss attributable to common stockholders	$	(18,019	)	$	(57,886	)	$	(69,405	)	$	(82,981	)
Basic and diluted weighted average number of shares:
Common shares		31,867,857			22,844,600			31,798,546			22,742,289
Unvested share-based awards participating		—			—			—			—

Basic and diluted weighted average number of shares:		31,867,857			22,844,600			31,798,546			22,742,289

Basic and diluted net loss attributable to common stockholders per common share	$	(0.57	)	$	(2.53	)	$	(2.18	)	$	(3.65	)

Effective January 1, 2009, the Company adopted FSP EITF No. 03-6-1, which requires participating securities to be included in the allocation of earnings when calculating EPS under the two-class method. All prior period EPS data presented above has been retrospectively adjusted to conform to the new requirements. During periods of losses, basic EPS will not be impacted, as the Company’s participating securities are not obligated to share in the losses of the Company and thus, are not included in the basic EPS share computation.

Because we reported a net loss for the three and six months ended June 30, 2009, participating securities covering 302,049 common shares were excluded from the computation of net loss per share because their effect would have been antidilutive.

Note 8— Impairment of Oil and Gas Properties

At the end of each quarterly period, the unamortized cost of oil and natural gas properties, net of related deferred income taxes, is limited to the full cost ceiling, computed as the sum of the estimated future net revenues from our proved reserves using current period-end prices discounted at 10%, and adjusted for related income tax effects (ceiling test). In the event our capitalized costs exceed the ceiling limitation at the end of the reporting date, we subsequently evaluate the limitation based on price changes that occur after the balance sheet date to assess impairment as currently permitted by Staff Accounting Bulletin Topic 12—Oil and Gas Producing Activities. Under full cost accounting rules, any ceiling test write-downs of oil and natural gas properties may not be reversed in subsequent periods. Since we do not designate our derivative financial instruments as hedges, we are not allowed to use the impacts of the derivative financial instruments in our ceiling test computation. As a result, decreases in commodity prices which contribute to ceiling test write-downs may be offset by mark-to-market gains which are not reflected in our ceiling test results.

Under the present full cost accounting rules, we are required to compute the after-tax present value of our proved oil and natural gas properties using spot market prices for oil and natural gas at our balance sheet date. The base for our spot prices for natural gas is Henry Hub and for oil is Cushing, Oklahoma. The computation resulted in the carrying costs of our unamortized proved oil and natural gas properties, net of deferred taxes, exceeding the March 31, 2009 present value of future net revenues by approximately $122.6 million. As a result of subsequent increases in spot prices, the amount of the ceiling test impairment was reduced to $102.9 million and is included in our condensed consolidated statement of operations. No further impairment was necessary at June 30, 2009. Natural gas, which is sold at other natural gas marketing hubs where we conduct operations, is subject to prices which reflect variables that can increase or decrease spot natural gas prices at these hubs such as market demand, transportation costs and quality of the natural gas being sold. Those differences are referred to as the basis differentials. Typically, basis differentials result in natural gas prices which are lower than Henry Hub, except in Appalachia, where we have typically received a premium to Henry Hub. We may face further ceiling test write-downs in future periods, depending on level of commodity prices, drilling results and well performance.

The calculation of the ceiling test is based upon estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, production and changes in economics related to the properties subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

F-16

QUEST RESOURCE CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

Note 9— Commitments and Contingencies

Litigation

We are subject, from time to time, to certain legal proceedings and claims in the ordinary course of conducting our business. Below is a brief description of any material legal proceedings that were initiated against us since December 31, 2008.

Federal Derivative Case

William Dean Enders, derivatively on behalf of nominal defendant Quest Energy Partners, L.P. v. Jerry D. Cash, David E. Grose, David C. Lawler, Gary Pittman, Mark Stansberry, J. Philip McCormick, Douglas Brent Mueller, Mid Continent Pipe & Equipment, LLC, Reliable Pipe & Equipment, LLC, RHB Global, LLC, RHB, Inc., Rodger H. Brooks, Murrell, Hall, McIntosh & Co. PLLP, and Eide Bailly LLP, Case No. CIV-09-752-F, U.S. District Court for the Western District of Oklahoma, filed July 17, 2009

On July 17, 2009, a complaint was filed in the United States District Court for the Western District of Oklahoma, purportedly on Quest Energy’s behalf, which names certain of its current and former officers and directors, external auditors and vendors. The factual allegations relate to, among other things, the transfers and lack of effective internal controls. The complaint asserts claims for breach of fiduciary duty, waste of corporate assets, unjust enrichment, conversion, disgorgement under the Sarbanes-Oxley Act of 2002, and aiding and abetting breaches of fiduciary duties against the individual defendants and vendors and professional negligence and breach of contract against the external auditors. The complaint seeks monetary damages, disgorgement, costs and expenses and equitable and/or injunctive relief. It also seeks Quest Energy to take all necessary actions to reform and improve its corporate governance and internal procedures. Quest Energy intends to defend vigorously against these claims.

Personal Injury Litigation

St. Paul Surplus Lines Insurance Company v. Quest Cherokee Oilfield Service, LLC, et al., CJ-2009-1078, District Court of Tulsa County, State of Oklahoma, filed February 11, 2009

QCOS has been named as a defendant in this declaratory action. This action arises out of the Trigoso matter discussed below. Plaintiff alleges that no coverage is owed QCOS under the excess insurance policy issued by plaintiff. The contentions of plaintiff primarily rest on their position that the allegations made in Trigoso are intentional in nature and that the excess insurance policy does not cover such claims. QCOS will vigorously defend the declaratory action.

Billy Bob Willis, et al. v. Quest Resource Corporation, et al., Case No. CJ-09-00063, District Court of Nowata County, State of Oklahoma, filed April 28, 2009

QRCP, et al. have been named in the above-referenced lawsuit. The lawsuit has not been served. At this time and due to the recent filing of the lawsuit, the Company is unable to provide further detail.

Jacob Dodd v. Arvilla Oilfield Services, LLC, et al., Case No. 08-C-47, Circuit Court of Ritchie County, State of West Virginia, filed May 8, 2008

Quest Eastern, et al. has been named in this personal injury lawsuit arising out of an automobile collision and was served on May 12, 2009. Limited discovery has taken place. Quest Eastern intends to vigorously defend against this claim.

Litigation Related to Oil and Gas Leases

Edward E. Birk, et ux., and Brian L. Birk, et ux., v. Quest Cherokee, LLC, Case No. 09-CV-27, District Court of Neosho County, State of Kansas, filed April 23, 2009

Quest Cherokee was named as a defendant in a lawsuit filed by Edward E. Birk, et ux., and Brian L. Birk, et ux., on April 23, 2009. In that case, the plaintiffs claim that they are entitled to an overriding royalty interest (1/16^th in some leases, and 1/32^nd in some leases) in 14 oil and gas leases owned and operated by Quest Cherokee. Plaintiffs contend that Quest Cherokee has produced oil and/or gas from wells located on or unitized with those leases, and that Quest Cherokee has failed to pay plaintiffs their overriding royalty interest in that production. We are investigating the factual and legal basis for these claims and intend to defend against them vigorously based upon the results of the investigation.

F-17

QUEST RESOURCE CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

Robert C. Aker, et al. v. Quest Cherokee, LLC, et al., Case No. 3-09CV101, U.S. District Court for the Western District of Pennsylvania, filed April 16, 2009

Quest Cherokee, et al. were named as defendants in this action where plaintiffs seek a ruling invalidating certain oil and gas leases. Quest Cherokee has filed a motion to dismiss for lack of jurisdiction, and no discovery has taken place. Quest Cherokee is investigating whether it is a proper party to this lawsuit and intends to vigorously defend against this claim.

Larry Reitz, et al. v. Quest Resource Corporation, et al., Case No. CJ-09-00076, District Court of Nowata County, State of Oklahoma, filed May 15, 2009

QRCP, et al. have been named in the above-referenced lawsuit. The lawsuit was served on May 22, 2009. Defendants have filed a motion to dismiss certain claims, and no discovery has taken place. Plaintiffs allege that defendants have wrongfully deducted costs from the royalties of plaintiffs and have engaged in self-dealing contracts and agreements resulting in a less than market price for production. Plaintiffs seek unspecified actual and punitive damages. Defendants intend to defend vigorously against this claim.

Kim E. Kuhn, Scott Tomlinson, Todd Tomlinson, Charles Willier, Brian Sefcik v. Quest Cherokee, LLC, Case No. 2009 CV 43, District Court of Wilson County, State of Kansas, filed July 27, 2009

Quest Cherokee has been named as a defendant by the landowners identified above for allegedly refusing to execute a Surface and Use Agreement. Plaintiffs seek monetary damages for breach of contract, damages to their property caused by Quest Cherokee, to terminate Quest Cherokee’s access to the property, and attorneys’ fees. Quest Cherokee denies plaintiffs’ allegations and will vigorously defend against the plaintiffs’ claims.

Below is a brief description of any material developments that have occurred in our ongoing material legal proceedings since December 31, 2008. Additional information with respect to our material legal proceedings can be found in our 2008 Form 10-K/A.

Personal Injury Litigation

Segundo Francisco Trigoso and Dana Jara De Trigoso v. Quest Cherokee Oilfield Service, LLC, CJ-2007-11079, in the District Court of Oklahoma County, State of Oklahoma, filed December 27, 2007

QCOS was named in this lawsuit filed by plaintiffs Segundo Francisco Trigoso and Dana Jara De Trigoso. Plaintiffs allege that Segundo Francisco Trigoso was seriously injured while working for QCOS on September 29, 2006 and that the conduct of QCOS was substantially certain to cause injury to Segundo Francisco Trigoso. Plaintiffs seek unspecified damages for physical injuries, emotional injuries, loss of consortium and pain and suffering. Plaintiffs also seek punitive damages. Various motions for summary judgment have been filed and denied by the court. It is expected that the court will set this matter for trial in Winter 2010. The parties are currently engaged in settlement negotiations and preparing for trial. QCOS intends to defend vigorously against plaintiffs’ claims.

Berenice Urias v. Quest Cherokee, LLC, et al., CV-2008-238C in the Fifth Judicial District, County of Lea, State of New Mexico (Second Amended Complaint filed September 24, 2008)

Quest Cherokee was named in this wrongful death lawsuit filed by Berenice Urias. Plaintiff was the surviving fiancée of the decedent Montano Moreno. The decedent was killed while working for United Drilling, Inc. United Drilling was transporting a drilling rig between locations when the decedent was electrocuted. All claims against Quest Cherokee have been dismissed with prejudice.

Litigation Related to Oil and Gas Leases

Quest Cherokee has been named as a defendant or counterclaim defendant in several lawsuits in which the plaintiff claims that oil and gas leases owned and operated by Quest Cherokee have either expired by their terms or, for various reasons, have been forfeited by Quest Cherokee. Those lawsuits were originally filed in the district courts of Labette, Montgomery, Wilson, and Neosho Counties, Kansas. Quest Cherokee has drilled wells on some of the oil and gas leases in issue and some of those oil and gas leases do not have a well located thereon but have been unitized with other oil and gas leases upon which a well has been drilled. As of August 10, 2009, the total amount of acreage covered by the leases at issue in these lawsuits was approximately 5,118 acres. Quest Cherokee intends to vigorously defend against those claims. Following is a list of those cases:

Housel v. Quest Cherokee, LLC, Case No. 06-CV-26-I, District Court of Montgomery County, State of Kansas, filed March 2, 2006

Roger Dean Daniels v. Quest Cherokee, LLC, Case No. 06-CV-61, District Court of Montgomery County, State of Kansas, filed May 5, 2006 (currently on appeal)

F-18

QUEST RESOURCE CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

Carol R. Knisely, et al. v. Quest Cherokee, LLC, Case No. 07-CV-58-I, District Court of Montgomery County, State of Kansas, filed April 16, 2007

Quest Cherokee, LLC v. David W. Hinkle, et al., Case No. 2006-CV-74, District Court of Labette County, State of Kansas, filed September 5, 2006

Scott Tomlinson, et al. v. Quest Cherokee, LLC, Case No. 2007-CV-45, District Court of Wilson County, State of Kansas, filed August 29, 2007

Ilene T. Bussman et al. v. Quest Cherokee, LLC, Case No. 07-CV-106-PA, District Court of Labette County, State of Kansas, filed November 26, 2007

Gary Dale Palmer, et al. v. Quest Cherokee, LLC, Case No. 07-CV-107-PA, District Court of Labette County, State of Kansas, filed November 26, 2007

Richard L. Bradford, et al. v. Quest Cherokee, LLC, Case No. 2008-CV-67, District Court of Wilson County, State of Kansas, filed September 18, 2008 (settled and dismissed)

Richard Winder v. Quest Cherokee, LLC, Case Nos. 07-CV-141 and 08-CV-20, District Court of Neosho County, State of Kansas, filed December 7, 2007, and February 27, 2008

Central Natural Resources, Inc. v. Quest Cherokee, LLC, et al., Case No. 04-C-100-PA, District Court of Labette County, State of Kansas, filed on September 1, 2004

Quest Cherokee and Bluestem were named as defendants in a lawsuit filed by Central Natural Resources, Inc. (“Central Natural Resources”) on September 1, 2004 in the District Court of Labette County, Kansas. Central Natural Resources owns the coal underlying numerous tracts of land in Labette County, Kansas. Quest Cherokee has obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying some of that land and has drilled wells that produce coal bed methane gas on that land. Bluestem purchases and gathers the gas produced by Quest Cherokee. Plaintiff alleges that it is entitled to the coal bed methane gas produced and revenues from these leases and that Quest Cherokee is a trespasser and has damaged its coal through its drilling and production operations. Plaintiff is seeking quiet title and an equitable accounting for the revenues from the coal bed methane gas produced. Plaintiff has alleged that Bluestem converted the gas and seeks an accounting for all gas purchased by Bluestem from the wells in issue. Quest Cherokee contends it has valid leases with the owners of the coal bed methane gas rights. The issue is whether the coal bed methane gas is owned by the owner of the coal rights or by the owners of the gas rights. If Quest Cherokee prevails on that issue, then the Plaintiff’s claims against Bluestem fail. All issues relating to ownership of the coal bed methane gas and damages have been bifurcated. Cross motions for summary judgment on the ownership of the coal bed methane gas were filed by Quest Cherokee and the plaintiff, with summary judgment being awarded in Quest Cherokee’s favor. Plaintiff appealed the summary judgment and the Kansas Supreme Court has issued an opinion affirming the District Court’s decision and has remanded the case to the District Court for further proceedings consistent with that decision. Central Natural Resources has filed a motion seeking to dismiss all of its remaining claims, without prejudice, and a journal entry of dismissal has been approved by the District Court.

Central Natural Resources, Inc. v. Quest Cherokee, LLC, et al., Case No. CJ-06-07, District Court of Craig County, State of Oklahoma, filed January 17, 2006

Quest Cherokee was named as a defendant in a lawsuit filed by Central Natural Resources, Inc. on January 17, 2006, in the District Court of Craig County, Oklahoma. Central Natural Resources owns the coal underlying approximately 2,250 acres of land in Craig County, Oklahoma. Quest Cherokee has obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying those lands, and has drilled and completed 20 wells that produce coal bed methane gas on those lands. Plaintiff alleged that it is entitled to the coal bed methane gas produced and revenues from these leases and that Quest Cherokee is a trespasser. Plaintiff sought to quiet its alleged title to the coal bed methane and an accounting of the revenues from the coal bed methane gas produced by Quest Cherokee. Quest Cherokee contended it has valid leases from the owners of the coal bed methane gas rights. The issue was whether the coal bed methane gas is owned by the owner of the coal rights or by the owners of the gas rights. All claims have been dismissed by agreement of all of the parties and a journal entry of dismissal has been approved by the District Court.

F-19

QUEST RESOURCE CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

Other

Well Refined Drilling Co. v. Quest Cherokee, LLC, Case No. 2007-CV-91, District Court of Neosho County, State of Kansas, filed July 19, 2007; and Well Refined Drilling Co. v. Quest Cherokee, LLC, Case No. 2007-CV-46, District Court of Wilson County, State of Kansas, filed September 4, 2007

Quest Cherokee was named as a defendant in two lawsuits filed by Well Refined Drilling Company in the District Court of Neosho County, Kansas (Case No. 2007 CV 91) and in the District Court of Wilson County, Kansas (Case No. 2007 CV 46). In both cases, plaintiff contended that Quest Cherokee owed certain sums for services provided by the plaintiff in connection with drilling wells for Quest Cherokee. Plaintiff had also filed mechanics liens against the oil and gas leases on which those wells are located and also sought foreclosure of those liens. Quest Cherokee had answered those petitions and had denied plaintiff’s claims. The claims in these lawsuits have been settled and dismissed by agreement of all of the parties.

Barbara Cox v. Quest Cherokee, LLC, Case No. CIV-08-0546, U.S. District Court for the District of New Mexico, filed April 18, 2008

Quest Cherokee was named in this lawsuit by Barbara Cox. Plaintiff is a landowner in Hobbs, New Mexico and owns the property where the Quest State 9-4 Well was drilled and plugged. Plaintiff alleged that Quest Cherokee violated the New Mexico Surface Owner Protection Act and has committed a trespass and nuisance in the drilling and maintenance of the well. The parties have settled this case and it will be dismissed.

Environmental Matters

As of June 30, 2009, there were no known environmental or regulatory matters related to our operations which are reasonably expected to result in a material liability to us. Like other oil and gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. Therefore it is extremely difficult to reasonably quantify future environmental related expenditures.

Financial Advisor Contracts

On June 26, 2009 Quest Midstream GP entered into an amendment to its original financial advisor agreement which provided that in consideration of a one time payment of $1.75 million, which was paid on July 7, 2009, no additional fees of any kind would be due under the terms of the original agreement other than a fee of $1.5 million if the KPC Pipeline is sold within two years of the date of the amendment. The settlement with the financial advisor was accrued at June 30, 2009 and included in general and administrative expenses for the period then ended.

In May 2009, QRCP terminated the engagement of its financial advisor; however, the financial advisor is entitled to fees, which are not currently estimable, if certain transactions occur. In June 2009, QRCP retained a different financial advisor to render a fairness opinion to QRCP in connection with the Recombination. The financial advisor received total compensation of $275,000 in connection with such engagement.

In January 2009, Quest Energy GP engaged a financial advisor to us in connection with the review of our strategic alternatives. Under the terms of the agreement, the financial advisor received a one-time advisory fee of $50,000 in January 2009 and was entitled to additional monthly advisory fees of $25,000 for a minimum period of six months payable on the last day of the month beginning January 31, 2009. In addition, the financial advisor was entitled to inestimable fees if certain transactions occur. On July 1, 2009, Quest Energy GP entered into an amendment to its original financial advisor agreement, which provided that the monthly advisory fee increased to $200,000 per month with a total of $800,000, representing the aggregate fees for each of April, May, June and July 2009, which amount was paid upon execution of the amendment. The additional financial advisor fees payable if certain transactions occurred were canceled; however, the financial advisor was still entitled to a fairness opinion fee of $650,000 in connection with any merger, sale or acquisition involving Quest Energy GP or Quest Energy, which amount was paid in connection with the delivery of a fairness opinion at the time of the execution of the Merger Agreement.

F-20

QUEST RESOURCE CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

Note 10 — Related Party Transactions

Settlement of lawsuit

While QRCP estimates the value of these assets to be less than the amount of the unauthorized transfers and cost of the internal investigation, Mr. Cash represented that they comprise all of Mr. Cash’s net worth and the majority of the value of the controlled-entity. We did not take Mr. Cash’s stock in QRCP, which he represented had been pledged to secure personal loans with a principal balance far in excess of the current market value of the stock.

STP owns interests in certain oil producing properties in Oklahoma, and other assets and liabilities. STP’s accounting and operation records provided to QELP, at the date of the settlement, were in poor condition and we are in the process of reconstructing the financial records in order to determine the estimated fair value of the assets acquired and liabilities assumed in connection with the settlement. Based on documents we received prior to the settlement, the estimated fair value of the net assets to be assumed was expected to provide QELP reimbursement for all of the costs of the internal investigation and the costs of the litigation against Mr. Cash that have been paid by QELP; however, the financial information we received prior to closing contained errors related to Mr. Cash’s ownership interests in the properties as well as amounts due vendors and royalty owners. Based on work performed to date we believe that the actual estimated fair value of net assets of STP that QELP received is less than previously expected. We expect to complete our analysis of STP’s financial information and our final valuation of the oil producing properties obtained from STP by December 31, 2009. We also are in the process of determining what further actions can be taken with regards to this and intend to pursue all remedies available under the law.

Based on the information available at this time, we have estimated the fair value of the assets and liabilities obtained in connection with the settlement. As additional information becomes available other assets and/or liabilities may be identified and recorded.

The estimated fair value of the assets and liabilities received is as follows (in thousands):


	QRCP		QELP			Total
Cash, net of legal expenses	$	2,420	$	—		$	2,420
Oil & gas properties		896		1,076			1,972
Other assets		50		—			50
Current liabilities		—		(326	)		(326	)
Long-term debt		—		(719	)		(719	)
					)
Net assets received	$	3,366	$	31		$	3,397
					)

Merger Agreement and Related Agreements

As discussed in Note 1 — Basis of Presentation, on July 2, 2009, we entered into the Merger Agreement with Quest Energy, Quest Midstream, and other parties thereto pursuant to which we would form a new, yet to be named, publicly-traded corporation that, through a series of mergers and entity conversions, would wholly-own all three entities.

On July 2, 2009, immediately prior to the execution of the Merger Agreement, we entered into Amendment No. 1 (the “Rights Amendment”) to the Rights Agreement with Computershare Trust Company, N.A., as successor rights agent to UMB Bank, n.a., amending the Rights Agreement, dated as of May 31, 2006 (the “Rights Agreement”), in order to render the Rights (as defined in the Rights Agreement) inapplicable to the Recombination and the other transactions contemplated by the Merger Agreement. The Rights Amendment also modified the Rights Agreement so that it would expire in connection with the Recombination if the Rights Agreement is not otherwise terminated.

Additionally, in connection with the Merger Agreement, on July 2, 2009, we entered into a Support Agreement with Quest Energy, Quest Midstream and certain Quest Midstream unitholders (the “Support Agreement”). Pursuant to the Support Agreement, we have, subject to certain conditions, agreed to vote the common and subordinated units of Quest Energy and Quest Midstream that we own in favor of the Recombination and the holders of approximately 43% of the common units of Quest Midstream have, subject to certain conditions, agreed to vote their common units in favor of the Recombination.

F-21

QUEST RESOURCE CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

Note 11 — Operating Segments

Operating segment data for the periods indicated is as follows (in thousands):


							Other and
	Oil and Gas			Natural Gas			Intersegment
	Production			Pipelines			Eliminations			Total
Three Months Ended June 30, 2009:
Total revenues	$	16,107		$	19,616		$	(12,030	)	$	23,693
Inter-segment revenues		—			(12,030	)		12,030			—

Third-party revenues	$	16,107		$	7,586		$	—		$	23,693


Segment operating profit (loss)	$	(8,233	)	$	8,705		$	—		$	472

Three Months Ended June 30, 2008:
Total revenues	$	49,144		$	15,823		$	(8,675	)	$	56,292
Inter-segment revenues		—			(8,675	)		8,675			—

Third-party revenues	$	49,144		$	7,148		$	—		$	56,292


Segment operating profit	$	15,615		$	3,438		$	—		$	19,053

Six Months Ended June 30, 2009:
Total revenues	$	38,382		$	39,926		$	(24,537	)	$	53,771
Inter-segment revenues		—			(24,537	)		24,537			—

Third-party revenues	$	38,382		$	15,389		$	—		$	53,771


Segment operating profit (loss)	$	(121,205	)	$	17,887		$	—		$	(103,318	)

Six Months Ended June 30, 2008:
Total revenues	$	87,458		$	31,387		$	(17,338	)	$	101,507
Inter-segment revenues		—			(17,338	)		17,338			—

Third-party revenues	$	87,458		$	14,049		$	—		$	101,507


Segment operating profit	$	24,233		$	7,782		$	—		$	32,015


Identifiable assets:
June 30, 2009	$	175,040		$	329,470		$	—		$	504,510
December 31, 2008	$	311,592		$	338,584		$	—		$	650,176

The following table reconciles segment operating profits reported above to loss before income taxes and noncontrolling interests (in thousands):


	Three months ended June 30,						Six months ended June 30,
	2009			2008			2009			2008
Segment operating profit (loss) ⁽¹⁾	$	472		$	19,053		$	(103,318	)	$	32,015
General and administrative expenses		(10,486	)		(6,198	)		(18,368	)		(11,941	)
Recovery of misappropriated funds net of liabilities assumed		3,397			—			3,397			—
Gain (loss) from derivative financial instruments		(17,138	)		(105,375	)		22,326			(149,614	)
Interest expense, net		(6,858	)		(5,174	)		(13,746	)		(10,057	)
Other income (expense) and gain on sale of assets		83			42			139			122

Loss before income taxes	$	(30,530	)	$	(97,652	)	$	(109,570	)	$	(139,475	)

⁽¹⁾ Segment operating profit represents total revenues less costs and expenses directly attributable thereto.

Note 12 - Subsequent Events

We evaluated our activity after June 30, 2009 until the date of issuance, August 17, 2009, for recognized and unrecognized subsequent events not discussed elsewhere in these footnotes and determined there were none.

F-22


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

Forward-looking statements

This quarterly report contains forward-looking statements, as defined in Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. These forward-looking statements relate to, among other things, the following:

	•		our future financial and operating performance and results;

	•		our business strategy;

	•		market prices;

	•		our future derivative financial instrument activities; and

	•		our plans and forecasts.

We have based these forward-looking statements on our current assumptions, expectations and projections about future events.

We use the words “may,” “expect,” “anticipate,” “estimate,” “believe,” “continue,” “intend,” “plan,” “budget” and other similar words to identify forward-looking statements. You should read statements that contain these words carefully because they discuss future expectations, contain projections of results of operations or of our financial condition and/or state other “forward-looking” information. We do not undertake any obligation to update or revise publicly any forward-looking statements, except as required by law. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this quarterly report, including, but not limited to:

	•		fluctuations in prices of oil and natural gas;

	•		Imports of foreign oil and natural gas, including liquefied natural gas;

	•		future capital requirements and availability of financing;

	•		continued disruption of credit and capital markets and the ability of financial institutions to honor their commitments;

	•		estimates of reserves and economic assumptions;

	•		geological concentration of our reserves;

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. The forward looking statements in this report only speak as of the date of this report; we disclaim any obligation to update these statements unless required by securities laws, and we caution you to not rely on them unduly. When considering our forward- looking statements, keep in mind the risk factors and other cautionary statements in this quarterly report, and the risk factors included in our Annual Report on Form 10-K/A for the year ended December 31, 2008 (our “2008 Form 10-K/A”).

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil and natural gas, the availability of capital from our revolving credit facilities and liquidity from capital markets. Declines in oil or natural gas prices may have a material adverse affect on our financial condition, liquidity, ability to obtain financing and operating results. Lower oil or natural gas prices also may reduce the amount of oil or natural gas that we can produce economically. A decline in oil or natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our oil and natural gas reserves, our ability to fund our operations and our financial condition, cash flow, results of operations and access to capital. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

Overview of QRCP

We are an integrated independent energy company involved in the acquisition, development, transportation, exploration, and production of natural gas, primarily from coal seams (coal bed methane, or “CBM”), and oil. We report our results of operations as two business segments, oil and gas production; and natural gas pipelines.

Our principal oil and gas production operations are located in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma; Seminole County, Oklahoma; and West Virginia, New York and Pennsylvania in the Appalachian Basin. Our Cherokee Basin operations are primarily focused on developing CBM gas production through Quest Energy Partners, L.P. (“Quest Energy” or “QELP”) and our Appalachian Basin operations are primarily focused on the development of natural gas production from the Marcellus Shale through QELP and Quest Eastern Resource LLC (“Quest Eastern”).

Our principal natural gas pipelines operations consist of a gas gathering pipeline network that primarily serves our Cherokee Basin producing properties and an interstate natural gas transmission pipeline. Both of these systems are owned through Quest Midstream Partners, L.P. (“Quest Midstream” or QMLP”). In addition, we own a small gathering line in the Appalachian Basin that serves Quest Eastern’s and Quest Energy’s producing properties.

Unless otherwise indicated, references to “us,” “we,” “our,” the “Company” or “QRCP” include our subsidiaries and controlled affiliates.

Since we control the general partner interests in Quest Energy and Quest Midstream, we reflect our ownership interest in these partnerships on a consolidated basis, which means that our financial results are combined with Quest Energy’s and Quest Midstream’s financial results and the results of our subsidiaries. The interest owned by non-controlling partners’ share of income is reflected as noncontrolling interests in our results of operations. Since the initial public offering of Quest Energy in November 2007, QRCP’s potential sources of revenue and cash flows consists almost exclusively of distributions on its partnership units in Quest Energy and Quest Midstream, because QRCP’s Appalachian assets largely consist of undeveloped acreage. Our consolidated results of operations are derived from the results Quest Energy’s and Quest Midstream’s operations as well the results of Quest Eastern’s operations related to the Appalachian Basin and our general and administrative expenses and our interest income (expense). Accordingly, the discussion of our financial position and results of operations in this Management’s Discussion and Analysis of Financial Condition and Results of Operations primarily reflects the operating activities and results of operations of Quest Energy and Quest Midstream.

Operating Highlights

The Company’s significant operational highlights by area during the second quarter of 2009 include:

	•		Increased natural gas production by approximately 297,000 Mcf from the prior year quarter.

	•		Increased oil production by approximately 2,000 Bbls from the prior year quarter.

	•		Increased total production by approximately 309,000 Mcfe from the prior year quarter.

	•		Reduced oil and gas production costs by $1.11 per Mcfe from the prior year quarter.

Financial Highlights

The Company’s significant financial highlights during the first half of 2009 include:

	•		Reduced total debt by $25.4 million from December 31, 2008.

	•		Increased cash and cash equivalents by $28.6 million from December 31, 2008.

	•		Repriced derivatives and received $26 million

Recent Developments

Global Financial Crisis and Impact on Capital Markets and Commodity Prices

During 2009 the global economy has continued to experience a significant downturn. There are two significant ramifications to the exploration and production industry as the economy continues to deteriorate. The first is that capital markets have essentially frozen. Equity, debt and credit markets shut down. Future growth opportunities have been and are expected to continue to be constrained by the lack of access to liquidity in the financial markets.

The second impact to the industry is that fear of global recession has resulted in a significant decline in oil and gas prices and the differential from NYMEX pricing to our sales point for our Cherokee Basin gas production has widened to unprecedented levels of volatility. While the differential has narrowed some, the volatility remains.

Our operations and financial condition are significantly impacted by these prices. On June 30, 2009, the spot market price for natural gas at Henry Hub was $ 3.89 per Mmbtu, a 70.3% decrease from June 30, 2008. The price of oil has shown similar volatility, with a $69.79 per Bbl spot market price for oil at Cushing, Oklahoma at June 30, 2009, a 50.1% decrease from June 30, 2008. In the second quarter of 2009, our average realized prices for oil and natural gas were $73.83 per Bbl and $2.72 per Mcf, respectively, compared with second quarter 2008 average realized prices of $111.25 per Bbl and $9.28 per Mcf, respectively. It is impossible to predict the duration or outcome of these price declines or the long-term impact on drilling and operating costs and the impacts, whether favorable or unfavorable, to our results of operations and liquidity. Natural gas prices came under pressure in the second half of 2008, and continued into 2009 as a result of lower domestic product demand that was caused by the weakening economy and concerns over excess supply of natural gas. In the Cherokee Basin, where we produce and sell most of our gas, there has been a widening of the historical discount of prices in the area to the NYMEX pricing point at Henry Hub as a result of elevated levels of natural gas drilling activity in the region and a lack of pipeline takeaway capacity. During the second quarter of 2009, this discount (or basis differential) in the Cherokee Basin ranged from $0.67 per Mmbtu to $1.06 per Mmbtu. Due to our relatively low level of oil production relative to gas and our existing commodity hedge positions, the volatility of oil prices had less of an effect on our operations.

Suspension of Distributions and Asset Sale

Distributions on all of Quest Energy’s and Quest Midstream’s units continue to be suspended. Since these distributions would have been substantially all of QRCP’s cash flows for 2009, the loss of these distributions was material to QRCP’s financial position. QRCP received cash distributions from Quest Energy and Quest Midstream of $7.9 million for the six months ended June 30, 2008 and did not receive any cash distributions from Quest Energy and Quest Midstream for the six months ended June 30. 2009.

On February 13, 2009, we divested of approximately 23,000 net undeveloped acres and one well in Lycoming County, Pennsylvania to a private party for approximately $8.7 million.

Settlement Agreements

      As discussed in our 2008 Form 10-K/A, we filed lawsuits, related to the Transfers, seeking, among other things, to recover the funds that were transferred. On May 19, 2009, we entered into settlement agreements with Mr. Cash, the controlled-entity and the other owners to settle this litigation. Under the terms of the settlement, and based on a settlement allocation agreed to by the board of directors of QRCP and QELP, QRCP received (1) approximately $2.4 million in cash and (2) 60% of the controlled-entity’s interest in a gas well located in Louisiana and a landfill gas development project located in Texas and QELP received Mr. Cash’s interest in STP Newco, Inc (“STP”) which consisted of 100% of the common stock of the company.

      While QRCP estimates the value of these assets to be less than the amount of the unauthorized transfers and cost of the internal investigation, Mr. Cash represented that they comprise all of Mr. Cash’s net worth and the majority of the value of the controlled-entity. We did not take Mr. Cash’s stock in QRCP, which he represented had been pledged to secure personal loans with a principal balance far in excess of the current market value of the stock.

      STP owns interests in certain oil producing properties in Oklahoma, and other assets and liabilities. STP’s accounting and operation records provided to QELP, at the date of the settlement, were in poor condition and we are in the process of reconstructing the financial records in order to determine the estimated fair value of the assets acquired and liabilities assumed in connection with the settlement. Based on documents we received prior to the settlement, the estimated fair value of the net assets to be assumed was expected to provide QELP reimbursement for all of the costs of the internal investigation and the costs of the litigation against Mr. Cash that have been paid by QELP; however, the financial information we received prior to closing contained errors related to Mr. Cash’s ownership interests in the properties as well as amounts due vendors and royalty owners. Based on work performed to date we believe that the actual estimated fair value of net assets of STP that QELP received is less than previously expected. We expect to complete our analysis of STP’s financial information and our final valuation of the oil producing properties obtained from STP by December 31, 2009. We also are in the process of determining what further actions can be taken with regards to this and intend to pursue all remedies available under the law.

      Based on the information available at this time, we have estimated the fair value of the assets and liabilities obtained in connection with the settlement. As additional information becomes available other assets and/or liabilities may be identified and recorded.

The estimated fair value of the assets and liabilities received is as follows (in thousands):


	QRCP		QELP			Total
Cash, net of legal expenses	$	2,420	$	—		$	2,420
Oil & gas properties		896		1,076			1,972
Other assets		50		—			50
Current liabilities		—		(326	)		(326	)
Long-term debt		—		(719	)		(719	)

Net assets received	$	3,366	$	31		$	3,397

Credit Agreement Amendments

QRCP

QRCP and Royal Bank of Canada (“RBC”) are parties to an Amended and Restated Credit Agreement, as amended (the “Credit Agreement”), dated as of July 11, 2008, for a $35 million term loan, due and maturing on July 11, 2010. In May 2009, QRCP entered into a Fourth Amendment to the Credit Agreement that, among other things, waived certain events of default related to the financial covenants and collateral requirements under the Credit Agreement, extended certain financial reporting deadlines and permitted the settlement agreements with Mr. Cash discussed elsewhere herein and in our 2008 Form 10-K/A.

In June 2009, QRCP entered into a Fifth Amendment to the Credit Agreement that, among other things, amended and/or waived certain of the representations and covenants contained in the Credit Agreement.

Quest Energy

Quest Energy is a party, as a guarantor, to an Amended and Restated Credit Agreement with Quest Cherokee, as the borrower, Royal Bank of Canada (“RBC”), as administrative agent and collateral agent, KeyBank National Association, as documentation agent and the lenders party thereto (together with all amendments, the “Quest Cherokee Credit Agreement”). Concurrent with the PetroEdge acquisition, Quest Energy and Quest Cherokee entered into a Second Lien Senior Term Loan Agreement (the “Second Lien Loan Agreement,” together with the Quest Cherokee Credit Agreement, the “Quest Cherokee Agreements”).

In June 2009, Quest Energy and Quest Cherokee entered into amendments to the Quest Cherokee Agreements that, among other things, permit Quest Cherokee’s obligations under oil and gas derivative contracts with BP Corporation North America, Inc. (“BP”) or any of its affiliates to be secured by the liens under the Quest Cherokee Credit Agreement on a pari passu basis with the obligations under the Quest Cherokee Credit Agreement and defer until August 15, 2009, Quest Energy’s obligation to deliver to RBC unaudited consolidated balance sheets and related statements of income and cash flows for the fiscal quarters ending September 30, 2008 and March 31, 2009.

In July 2009, the borrowing base under the Quest Cherokee Credit Agreement was reduced from $190 million to $160 million, which, following the principal payment of $15 million Quest Energy made on June 30, 2009, resulted in the outstanding borrowings under the Quest Cherokee Credit Agreement exceeding the new borrowing base by $14 million (the “Borrowing Base Deficiency”). In anticipation of the reduction in the borrowing base, Quest Energy amended or exited certain of its above market natural gas price derivative contracts and, in return, received approximately $26 million. At the same time, Quest Energy entered into new natural gas price derivative contracts to increase the total amount of its future proved developed natural gas production hedged to approximately 85% through 2013. On July 8, 2009, Quest Energy repaid the $14 million Borrowing Base Deficiency.

Results of Operations

The following discussion of financial condition and results of operations should be read in conjunction with the consolidated financial statements and the related notes, which are included elsewhere in this report.

Operating segment data for the periods indicated are as follows (in thousands):


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Revenues:
Oil and gas sales	$	16,107		$	49,144		$	38,382		$	87,458
Natural gas pipelines		19,616			15,823			39,926			31,387
Elimination of inter-segment revenue		(12,030	)		(8,675	)		(24,537	)		(17,338	)

Natural gas pipelines, net of inter-segment revenue		7,586			7,148			15,389			14,049

Total segment revenues	$	23,693		$	56,292		$	53,771		$	101,507

Operating profit (loss):
Oil and gas production	$	(8,233	)	$	15,615		$	(121,205	)	$	24,233
Natural gas pipelines		8,705			3,438			17,887			7,782

Total segment operating profit (loss)		472			19,053			(103,318	)		32,015
General and administrative expenses		(10,486	)		(6,198	)		(18,368	)		(11,941	)
Recovery of misappropriated funds, net of liabilities assumed		3,397			—			3,397			—

Total operating income (loss)	$	(6,617	)	$	12,855		$	(118,289	)	$	20,074

Three Months Ended June 30, 2009 Compared to the Three Months Ended June 30, 2008

Oil and Gas Production Segment

Oil and gas production segment data for the periods indicated are as follows (in thousands):


	Three Months Ended
	June 30,				Increase/
	2009		2008		(Decrease)
Oil and gas sales	$	16,107	$	49,144	$	(33,037	)	(67.2	)%
Oil and gas production costs	$	7,274	$	12,631	$	(5,357	)	(42.4	)%
Transportation expense (intercompany)	$	12,030	$	8,675	$	3,355		38.7	%
Depreciation, depletion and amortization	$	5,036	$	12,223	$	(7,187	)	(58.8	)%

Production Data:
Natural gas production (Mmcf)		5,392		5,095		297		5.8	%
Oil production (Mbbl)		19		17		2		11.8	%
Total production (Mmcfe)		5,506		5,197		309		5.9	%
Average daily production (Mmcfe/d)		60.5		57.1		3.4		6.0	%


	Three Months Ended
	June 30,				Increase/
	2009		2008		(Decrease)
Average Sales Price per Unit:
Natural gas (Mcf)	$	2.72	$	9.28	$	(6.56	)	(70.7	)%
Oil (Bbl)	$	73.83	$	111.25	$	(37.42	)	(33.6	)%
Natural gas equivalent (Mcfe)	$	2.93	$	9.46	$	(6.53	)	(69.0	)%
Average Unit Costs per Mcfe:
Production costs	$	1.32	$	2.43	$	(1.11	)	(45.7	)%
Transportation expense (intercompany)	$	2.18	$	1.67	$	0.51		30.5	%
Depreciation, depletion and amortization	$	0.91	$	2.35	$	1.44		(61.3	)%

Oil and Gas Sales. Oil and gas sales decreased $33.0 million, or 67.2%, to $16.1 million during the three months ended June 30, 2009. This decrease was the result of a decrease in average realized prices, offset by a small increase in volumes. The decrease in average realized prices resulted in decreased revenues of $36.0 million. Our average realized prices on an equivalent basis (Mcfe), decreased to $2.93 per Mcfe for the three months ended June 30, 2009 from $9.46 per Mcfe for the three months ended June 30, 2008. Offsetting this decrease were additional volumes of 297 Mmcfe, accounting for an increase in revenues by $3.0 million. The increased volumes primarily resulted from the PetroEdge acquisition.

Oil and Gas Operating Expenses. Oil and gas operating expenses consist of oil and gas production costs, which include lease operating expenses, severance taxes and ad valorem taxes, and transportation expense. Oil and gas operating expenses decreased $2.0 million, or 9.4%, to $19.3 million during the three months ended June 30, 2009, from $21.3 million during the three months ended June 30, 2008.

Oil and gas production costs decreased $5.4 million, or 42.4%, to $7.3 million during the three months ended June 30, 2009, from $12.6 million during the three months ended June 30, 2008. This decrease was primarily due cost-cutting measures implemented in the third quarter of 2008. Field headcount was reduced by 31.9% while simultaneously reducing overtime hours for the three months ended June 30, 2009 compared to the three months ended June 30, 2008. The reductions came at the same time we absorbed the operations of PetroEdge which increased our total production, further reducing our cost per Mcfe. Production costs including gross production taxes and ad valorem taxes were $1.32 per Mcfe for the three months ended June 30, 2009 as compared to $2.43 per Mcfe for the three months ended June 30, 2008. The decrease in per unit cost was due to the cost-cutting measure discussed above, as well as higher volumes over which to spread fixed costs.

Transportation expense increased $3.4 million, or 38.7%, to $12.0 million during the three months ended June 30, 2009, from $8.7 million during the three months ended June 30, 2008. The increase was due to an increase in the contracted transportation fee and increased volumes. Transportation expense was $2.18 per Mcfe for the three months ended June 30, 2009 as compared to $1.67 per Mcfe for the three months ended June 30, 2008. Transportation expense per Mcfe is greater than our contracted rate due to third-party volumes being transported at our contracted rates for which we do not get reimbursed the full contracted rate.

Depreciation, Depletion and Amortization. We are subject to variances in our depletion rates from period to period due to changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties. Our depreciation, depletion and amortization decreased approximately $7.2 million, or 58.8%, in the 2009 period to $5.0 million from $12.2 million during the three months ended June 30, 2008. On a per unit basis, we had an decrease of $1.44 per Mcfe to $0.91 per Mcfe in 2009 from $2.35 per Mcfe in 2008. This decrease was primarily due to the impairment of our oil and gas properties in the fourth quarter of 2008 and the first quarter of 2009, which decreased our rate per unit, as well as the resulting decrease in the depletable pool.

Natural Gas Pipelines Segment

Natural gas pipelines segment data for the periods indicated are as follows (in thousands):


	Three Months Ended
	June 30,
	2009		2008		Increase/ (Decrease)
Natural Gas Pipeline Revenue:
Gas pipeline revenue — Third Party	$	7,586	$	7,148	$	438		6.1	%
Gas pipeline revenue — Intercompany		12,030		8,675		3,355		38.7	%

Total natural gas pipeline revenue	$	19,616	$	15,823	$	3,793		24.0	%
Pipeline operating expense	$	6,861	$	8,164	$	(1,303	)	(16.0	)%
Depreciation and amortization expense	$	4,050	$	4,221	$	(171	)	(4.1	)%
Throughput Data (Mmcf):
Throughput — Third Party		2,651		1,455		1,196		82.2	%
Throughput — Intercompany		6,224		6,201		23		0.4	%

Total throughput (Mmcf)		8,875		7,656		1,219		15.9	%
Average Pipeline Operating Costs per Mmcf:
Pipeline operating expense	$	0.77	$	1.07	$	(0.30	)	(28.0	)%
Depreciation and amortization	$	0.46	$	0.55	$	(0.09	)	(16.4	)%

Pipeline Revenue. Total natural gas pipeline revenue increased $3.8 million, or 24.0%, to $19.6 million during the three months ended June 30, 2009, from $15.8 million during the three months ended June 30, 2008.

Third party natural gas pipeline revenue increased $0.4 million, or 6.1%, to $7.6 million during the three months ended June 30, 2009, from $7.1 million during the three months ended June 30, 2008. The increase was primarily due to a higher contract rate in 2009, as well as higher throughput volumes during the three months ended June 30, 2009 compared to the three months ended June 30, 2008.

Intercompany natural gas pipeline revenue increased $3.4 million, or 38.7%, to $12.0 million during the three months ended June 30, 2009, from $8.7 million during the three months ended June 30, 2008. The increase was primarily due to a higher contracted rate in 2009, as well as a 0.4% increase in throughput volumes from our Cherokee Basin properties

Pipeline Operating Expense. Pipeline operating expense decreased $1.3 million, or 16.0%, to $6.9 million during the three months ended June 30, 2009, from $8.2 million during the three months ended June 30, 2008. Pipeline operating costs per unit decreased $0.30 per Mmcf during the three months ended June 30, 2009, from $1.07 per Mmcf to $0.77 per Mmcf. The decrease in per unit cost was the result of higher volumes, over which to spread fixed costs, as well as our cost-cutting efforts implemented in the third quarter of 2008.

Depreciation and Amortization. Depreciation and amortization expense decreased $0.2 million, or 4.1%, to $4.1 million during the three months ended June 30, 2009, from $4.2 million during the three months ended June 30, 2008. Depreciation and amortization per unit decreased $0.09, or 16.4%, to $0.46 per Mmcfe for the three months ended June 30, 2009 from $0.55 per Mmcf for the three months ended June 30, 2008. The decrease in per unit cost is due to an increase in throughput volumes.

Unallocated Items

The following is a discussion of items not allocated to either of our segments.

General and Administrative Expenses. General and administrative expenses increased $4.3 million, or 69.2%, to $10.5 million during the three months ended June 30, 2009, from $6.2 million during the three months ended June 30, 2008. The increase is primarily due to increased legal, investment banker, audit and other professional fees in connection with the restatement and reaudits of our financial statements and recombination activities partially offset by reduced stock compensation expense.

Loss from Derivative Financial Instruments. Loss from derivative financial instruments decreased $88.3 million to $17.1 million for the three months ended June 30, 2009, from $105.4 million for the three months ended June 30, 2008. We recorded a $63.8 million unrealized loss and $46.6 million realized gain on our derivative contracts for the three months ended June 30, 2009 compared to a $96.3 million unrealized loss and $9.1 million realized loss for the three months ended June 30, 2008. Unrealized gains and losses are attributable to changes in oil natural gas prices and volumes hedged from one period end to another. In June 2009, we amended or exited certain of our above market natural gas price derivative contracts for periods beginning in the second quarter of 2010 through the fourth quarter of 2012. In return, we received approximately $26 million. Concurrent with this, the strike prices on the derivative contracts that we did not exit were set to market prices at the time and we entered into new natural gas price derivative contracts to increase the total amount of our future proved developed natural gas production hedged to approximately 85% through 2013.

Interest expense, net. Interest expense, net, increased $1.7 million, or 32.5%, to $6.9 million during the three months ended June 30, 2009, from $5.2 million during the three months ended June 30, 2008. The increase is primarily due to a higher average outstanding debt balance for the three months ended June 30. 2009 compared to the three months ended June 30, 2008.

Six Months Ended June 30, 2009 Compared to the Six Months Ended June 30, 2008

Oil and Gas Production Segment

Oil and gas production segment data for the periods indicated are as follows (in thousands):


	Six Months Ended
	June 30,				Increase/
	2009		2008		(Decrease)
Oil and gas sales	$	38,382	$	87,458	$	(49,076	)	(56.1	)%
Oil and gas production costs	$	14,960	$	23,037	$	(8,077	)	(35.1	)%
Transportation expense (intercompany)	$	24,537	$	17,338	$	7,199		41.5	%
Depreciation, depletion and amortization	$	17,188	$	22,851	$	(5,663	)	(24.8	)%

Production Data:
Natural gas production (Mmcf)		10,809		10,061		748		7.4	%
Oil production (BBbl)		40		28		12		42.9	%
Total production (Mmcfe)		11,049		10,228		821		8.0	%
Average daily production (Mmcfe/d)		61.0		56.2		4.8		8.5	%
Average Sales Price per Unit:
Natural gas (Mcf)	$	3.28	$	8.40	$	(5.12	)	61.0	%

Oil (Bbl)	$	73.47	$	105.96	$	(32.49	)	(30.7	)%
Natural gas equivalent (Mcfe)	$	3.47	$	8.55	$	(5.08	)	(59.4	)%
Average Unit Costs per Mcfe:
Production costs	$	1.35	$	2.25	$	(0.90	)	(40.0	)%
Transportation expense (intercompany)	$	2.22	$	1.70	$	0.52		30.6	%
Depreciation, depletion and amortization	$	1.56	$	2.23	$	(0.67	)	(30.0	)%

Oil and Gas Sales. Oil and gas sales decreased $49.1 million, or 56.1%, to $38.4 million for the six months ended June 30, 2009 from $87.5 million for the six months ended June 30, 2008. This decrease was, primarily, the result of a decrease in average realized sales prices, offset, partially, by an increase in volumes. The decrease in average realized sales prices resulted in a decrease in revenues of $56.1 million. Our average realized prices on an equivalent basis (Mcfe), decreased to $3.47 per Mcfe for the six months ended June 30, 2009 period from $8.55 per Mcfe for the six months ended June 30, 2008. Offsetting this decrease were additional volumes of 821 Mmcfe, accounting for an increase in revenues of $7.0 million. The increased volumes primarily resulted from the PetroEdge acquisition.

Oil and Gas Operating Expenses. Oil and gas operating expenses consist of oil and gas production costs, which include lease operating expenses, severance taxes and ad valorem taxes, and transportation expense. Oil and gas operating expenses decreased $0.9 million, or 2.2%, to $39.5 million during the six months ended June 30, 2009, from $40.4 million during the six months ended June 30, 2008.

Oil and gas production costs decreased $8.1 million, or 35.1%, to $15.0 million during the six months ended June 30, 2009, from $23.0 million during the six months ended June 30, 2008. This decrease was primarily due cost-cutting measures implemented in the third quarter of 2008. Field headcount was reduced by 29.7% while simultaneously reducing overtime hours for the six months ended June 30, 2009 compared to the six months ended June 30, 2008. The reductions came at the same time we absorbed the operations of PetroEdge which increased our total production, further reducing our cost per Mcfe. Production costs including gross production taxes and ad valorem taxes were $1.35 per Mcfe for the six months ended June 30, 2009 as compared to $2.25 per Mcfe for the six months ended June 30, 2008. The decrease in per unit cost was due to the cost-cutting measure discussed above, as well as higher volumes over which to spread fixed costs.

Transportation expense increased $7.2 million, or 41.5%, to $24.5 million during the six months ended June 30, 2009, from $17.3 million during the six months ended June 30, 2008. The increase was primarily due to the increase in the contracted rate in 2009 compared to 2008, as well as increased volumes of 821 Mmcfe. The per unit cost increased $0.52 per Mcfe to $2.22 per Mcfe for the six months ended June 30, 2009 as compared to $1.70 per Mcfe for the six months ended June 30, 2008.

Depreciation, Depletion and Amortization. We are subject to variances in our depletion rates from period to period due to changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties. Our depreciation, depletion and amortization decreased approximately $5.7 million, or 24.8%, in the 2009 period to $17.2 million from $22.9 million in 2008. On a per unit basis, we had an decrease of $0.67 per Mcfe to $1.56 per Mcfe in 2009 from $2.23 per Mcfe in 2008. This decrease was primarily due to the impairment of our oil and gas properties in the fourth quarter of 2008 and the first quarter of 2009, which decreased our rate per unit, as well as the resulting decrease in the depletable pool.

Natural Gas Pipelines Segment

Natural gas pipelines segment data for the periods indicated are as follows (in thousands):


	Six Months Ended
	June 30,
	2009		2008		Increase/ (Decrease)
			(Restated)
			($ in thousands)
Natural Gas Pipeline Revenue:
Gas pipeline revenue — Third Party	$	15,389	$	14,049	$	1,340		9.5	%
Gas pipeline revenue — Intercompany		24,537		17,338		7,199		41.5	%

Total natural gas pipeline revenue	$	39,926	$	31,387	$	8,539		27.2	%
Pipeline operating expense	$	14,021	$	15,122	$	(1,101	)	(7.3	)%
Depreciation and amortization expense	$	8,018	$	8,482	$	(464	)	(5.5	)%
Throughput Data (Mmcf):
Throughput — Third Party		7,040		5,962		1,078		18.1	%
Throughput — Intercompany		12,644		12,284		360		2.9	%

Total throughput (Mmcf)		19,684		18,246		1,438		7.9	%
Average Pipeline Operating Costs per Mmcf:
Pipeline operating expense	$	0.71	$	0.83	$	(0.12	)	(14.5	)%
Depreciation and amortization	$	0.41	$	0.46	$	(0.05	)	(10.9	)%

Pipeline Revenue. Total natural gas pipeline revenue increased $8.5 million, or 27.2%, to $39.9 million during the six months ended June 30, 2009, from $31.4 million during the six months ended June 30, 2008.

Third party natural gas pipeline revenue increased $1.3 million, or 9.5%, to $15.4 million during the six months ended June 30, 2009, from $14.0 million during the six months ended June 30, 2008. The increase was primarily due to increased volumes of 1,078 Mmcf.

Intercompany natural gas pipeline revenue increased $7.2 million, or 41.5%, to $24.5 million during the six months ended June 30, 2009, from $17.3 million during the six months ended June 30, 2008. The increase is primarily due to the increase in contracted rate for 2009, as well as a 2.9% increase in throughput volumes from our Cherokee Basin properties.

Pipeline Operating Expense. Pipeline operating expense decreased $1.1 million, or 7.3%, to $14.0 million during the six months ended June 30, 2009, from $15.1 million during the six months ended June 30, 2008. This decrease is primarily due to our cost-cutting initiatives that began in the third quarter of 2008. Pipeline operating costs per unit decreased $0.12 per Mmcf during 2008, from $0.83 per Mmcf to $0.71 per Mmcf. The decrease in per unit cost was the result of the cost-cutting efforts, as well as higher volumes over which to spread fixed costs.

Depreciation and Amortization. Depreciation and amortization expense decreased $0.5 million, or 5.5%, to $8.0 million during the six months ended June 30, 2009, from $8.5 million during the six months ended June 30, 2008.

Unallocated Items

The following is a discussion of items not allocated to either of our segments.

General and Administrative Expenses. General and administrative expenses increased $6.5 million, or 53.8%, to $18.4 million during the six months ended June 30, 2009, from $11.9 million during the six months ended June 30, 2008. The increase is primarily due to the internal investigation and restatements and reaudits, increased legal and consulting expense due to the reaudits and restatements partially offset by reduced stock compensation expense.

Gain (loss) from derivative financial instruments. Gain from derivative financial instruments increased $171.9 million to $22.3 million during the six months ended June 30, 2009, from a loss of $149.6 million during the six months ended June 30, 2008. We recorded a $41.2 million unrealized loss and $63.5 million realized gain on our derivative contracts for the six months ended June 30, 2009 compared to a $139.3 million unrealized loss and $10.3 million realized loss for the six months ended June 30, 2008. The increase in realized gain was due to the $26 million cash received as a result of exiting certain of our above market derivative financial instruments.

Interest expense. Interest expense increased $3.7 million, or 36.7%, to $13.7 million during the six months ended June 30, 2009, from $10.1 million during the six months ended June 30, 2008. The increase is primarily due to a higher average outstanding debt balance for the six months ended June 30, 2009 compared to the six months ended June 30, 2008.

Liquidity and Capital Resources

Overview. Our operating cash flows are driven by the quantities of our production of oil and natural gas and the prices received from the sale of this production and revenue generated from our pipeline operating activities. Prices of oil and natural gas have historically been very volatile and can significantly impact the cash from the sale our oil and natural gas production. Use of derivative financial instruments help mitigate this price volatility. Cash expenses also impact our operating cash flow and consist primarily of oil and natural gas property operating costs, severance and ad valorem taxes, interest on our indebtedness, general and administrative expenses and taxes on income.

Our primary sources of liquidity are cash generated from our operations, amounts, if any, available under our revolving credit facilities, and funds from future private and public equity and debt offerings.

At June 30, 2009, Quest Energy had $1.0 million of availability under its revolving credit facility. In July 2009, the borrowing base under its credit agreement was reduced from $190 million to $160 million, which, following the principal payment of $15.0 million Quest Energy made on June 30, 2009, resulted in the outstanding borrowings under the credit facility exceeding the new borrowing base by $14 million. In anticipation of the reduction in the borrowing base, Quest Energy amended or exited certain of its above market natural gas price derivative contracts and, in return, received approximately $26 million. At the same time, Quest Energy entered into new natural gas price derivative contracts to increase the total amount of its future proved developed natural gas production hedged to approximately 85% through 2013. On July 8, 2009, Quest Energy repaid the $14 million Borrowing Base Deficiency.

At June 30, 2009, Quest Midstream had $125.1 million outstanding and $9.9 million of availability under its revolving credit facility.

QRCP is almost exclusively dependent upon distributions from its partnership interests in Quest Energy and Quest Midstream for revenue and cash flow. However, Quest Midstream has not paid any distributions on any of its units since the second quarter of 2008, and Quest Energy suspended its distributions on its subordinated units from the third quarter of 2008 and all units starting with the fourth quarter of 2008. QRCP does not expect to receive any distributions from Quest Energy or Quest Midstream for the remainder of 2009 and is unable to estimate at this time when such distributions may be resumed. Although QRCP is not currently receiving distributions from Quest Energy or Quest Midstream, it continues to require cash to fund general and administrative expenses, debt service requirements, capital expenditures to develop and maintain its undeveloped acreage, drilling commitments and payments to landowners necessary to maintain its oil and gas leases.

Cash Flows from Operating Activities. Cash flows from operating activities totaled $51.9 million for the six months ended June 30, 2009 compared to cash flows from operations of $50.2 million for the six months ended June 30, 2008. Cash from operating activities increased due to the $26 million of cash received as a result of exiting certain of our above market derivative financial instruments in June 2009. This increase was offset by lower revenues as a result of lower realized sales prices for the six months ended June 30, 2009, compared to the six months ended June 30, 2008.

Cash Flows from Investing Activities. Net cash flows from investing activities totaled $3.3 million for the six months ended June 30, 2009 as compared to cash flows from investing activities of $(97.2) million for the six months ended June 30, 2008. The following table sets forth our capital expenditures by major categories for the six months ended June 30, 2009. This increase in cash provided is primarily the result of reduced capital expenditures and proceeds from sale of oil and gas properties during the six months ended June 30, 2009 compared to the same period in 2008.


	Six Months Ended
	June 30, 2009
	(In thousands)
Capital expenditures:
Leasehold acquisition	$	3,662
Development		787
Pipelines		578
Other items		229

Total capital expenditures	$	5,256

Cash Flows from Financing Activities. Net cash flows from financing activities totaled $(26.5) million for the six months ended June 30, 2009 as compared to cash flows from financing activities of $61.8 million for the six months ended June 30, 2008. The cash provided from financing activities during 2008 was primarily due to the borrowings of $79.0 million, while the cash used for the six months ended June 30, 2009, was primarily due to the repayment of $27.6 million of revolver and note borrowings.

Working Capital Deficit. At June 30, 2009, we had current assets of $115.3 million. Our working capital (current assets minus current liabilities, excluding the short-term derivative asset and liability of $35.1 million and $0.4 million, respectively) was a deficit of $9.9 million at June 30, 2009, compared to a working capital deficit (excluding the short-term derivative asset and liability of $43.0 million and $12,000, respectively) of $41.5 million at December 31, 2008.

Sources of Liquidity in 2009 and Capital Requirements

Credit Agreements

QRCP.

At June 30, 2009, $29.4 million was outstanding under the term loan. The weighted average interest rate for the quarter ended June 30, 2009 was 12.25%.

On January 30, 2009, QRCP entered into a Third Amendment to Amended and Restated Credit Agreement that restricted the use of proceeds from certain asset sales.

Under the Credit Agreement, QRCP is required to maintain as of the end of each quarter, an interest coverage ratio of not less than 2.5 to 1.0 and a leverage ratio of no more than 2.0 to 1.0. QRCP was not in compliance with these financial covenants as of March 31, 2009. In addition, under the terms of the Credit Agreement, the outstanding principal amount of borrowings may not exceed the sum of (i) the value of QRCP’s oil and gas properties in the Appalachian Basin (as determined by the administrative agent under the Credit Agreement in its reasonable discretion) and (ii) 50% of the market value of QRCP’s interests in Quest Energy and Quest Midstream (such excess is referred to as a “Collateral Deficiency”). QRCP is required to make a mandatory prepayment equal to any such Collateral Deficiency. On May 29, 2009, QRCP entered into a Fourth Amendment to Amended and Restated Credit Agreement pursuant to the terms of which (i) the lender waived the financial covenant defaults for the quarters ended December 31, 2008 and March 31, 2009; (ii) the lender waived the mandatory prepayment for the Collateral Deficiency for the quarters ended December 31, 2008, March 31, 2009 and June 30, 2009; and (iii) the reporting deadline for certain financial statements was extended.

Quest Energy.

A. Quest Cherokee Credit Agreement.

Quest Cherokee is a party to an Amended and Restated Credit Agreement, as amended (the “Quest Cherokee Credit Agreement”), with RBC, KeyBank National Association (“KeyBank”) and the lenders party thereto for a $250 million revolving credit facility, which is guaranteed by Quest Energy. Availability under the revolving credit facility is tied to a borrowing base that is redetermined by the lenders every six months taking into account the value of Quest Cherokee’s proved reserves.

The borrowing base was $190.0 million as of June 30, 2009. The amount borrowed under the Quest Cherokee Credit Agreement as of June 30, 2009 was $174.0 million. At June 30, 2009, Quest Cherokee had $16.0 million available for borrowing. The weighted average interest rate under the Quest Cherokee Credit Agreement for the quarter ended June 30, 2009 was 5.09%.

In July 2009, the borrowing base under the Quest Cherokee Credit Agreement was reduced from $190 million to $160 million, which, following the payment discussed below, resulted in the outstanding borrowings under the Quest Cherokee Credit Agreement exceeding the new borrowing base by $14 million. In anticipation of the reduction in the borrowing base, Quest Energy amended or exited certain of its above market natural gas price derivative contracts and, in return, received approximately $26 million. The strike prices on the derivative contracts that Quest Energy did not exit were set to market prices at the time. At the same time, Quest Energy entered into new natural gas price derivative contracts to increase the total amount of its future proved developed natural gas production hedged to approximately 85% through 2013. On June 30, 2009, using these proceeds, Quest Energy made a principal payment of $15 million on the Quest Cherokee Credit Agreement. On July 8, 2009, Quest Energy repaid the $14 million Borrowing Base Deficiency.

Quest Cherokee was in compliance with all of its covenants as of June 30, 2009.

B. Second Lien Loan Agreement.

Quest Energy made quarterly principal payments of $3.8 million on February 17, 2009, May 15, 2009 and August 17, 2009.

Quest Cherokee was in compliance with all of its covenants as of June 30, 2009.

Quest Midstream.

As of June 30, 2009, the amount borrowed under the Quest Midstream Credit Agreement was $125.1 million. The weighted average interest rate for the quarter ended June 30, 2009 was 4.67%.

Quest Midstream was in compliance with all of its covenants as of June 30, 2009.

Contractual Obligations

We have numerous contractual commitments in the ordinary course of business, debt service requirements and operating lease commitments. Other than those discussed below, these commitments have not materially changed since December 31, 2008.

On June 26, 2009, Quest Midstream GP, LLC entered into an amendment to its original agreement with its financial advisor, which provided that in consideration of a one-time payment of $1.75 million, which was paid in July 2009, no additional fees of any kind would be due under the terms of the original agreement other than a fee of $1.5 million if the KPC Pipeline was sold within two years of the date of the amendment.

In May 2009, QRCP terminated the engagement of the financial advisor that had been retained to review QRCP’s strategic alternatives. In June 2009, QRCP retained a different financial advisor to render a fairness opinion to QRCP in connection with the Recombination. The financial advisor received total compensation of $275,000 in connection with such engagement.

On July 1, 2009, Quest Energy GP, LLC entered into an amendment to its original agreement with its financial advisor, which provided that the monthly advisory fee increased to $200,000 per month with a total of $800,000, representing the aggregate fees for each of April, May, June and July 2009, which amount was paid upon execution of the amendment. Fees through June 2009, have been expensed and properly accrued as of June 30, 2009. The additional financial advisor fees payable if certain transactions occurred were canceled; however, the financial advisor was still entitled to a fairness opinion fee of $650,000 in connection with any merger, sale or acquisition involving Quest Energy GP or Quest Energy, which amount was paid in connection with the delivery of a fairness opinion at the time of the execution of the Merger Agreement.

Off-balance Sheet Arrangements

At June 30, 2009, we did not have any relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. In addition, we do not engage in trading activities involving non-exchange traded contracts. As such, we are not exposed to any financing, liquidity, market, or credit risk that could arise if we had engaged in such activities.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Commodity Price Risk

Our most significant market risk relates to the prices we receive for our oil and natural gas production. In light of the historical volatility of these commodities, we periodically have entered into, and expect in the future to enter into, derivative arrangements aimed at reducing the variability of oil and natural gas prices we receive for our production.

The following table summarize the estimated volumes, fixed prices and fair value attributable to oil and gas derivative contracts as of June 30, 2009:


	Remainder of		Year Ending December 31,
	2009		2010			2011			2012			Thereafter			Total
			($ in thousands, except volumes and per unit data)
Natural Gas Swaps:
Contract volumes (Mmbtu)		7,734,720		16,129,060			13,550,302			11,000,004			9,000,003			57,054,089
Weighted-average fixed price per Mmbtu	$	7.78	$	6.26		$	6.80		$	7.13		$	7.28		$	6.91
Fair value, net	$	25,150	$	5,563		$	(316	)	$	33		$	(32	)	$	30,398
Natural Gas Collars:
Contract volumes (Mmbtu)		375,000		—			—			—			—			375,000
Weighted-average fixed price per Mmbtu:
Floor	$	11.00	$	—		$	—		$	—		$	—		$	11.00
Ceiling	$	15.00	$	—		$	—		$	—		$	—		$	15.00
Fair value, net	$	2,464	$	—		$	—		$	—		$	—		$	2,464
Total Natural Gas Contracts:
Contract volumes (Mmbtu)		7,749,720		16,129,060			13,550,302			11,000,004			9,000,003			57,429,089
Weighted-average fixed price per Mmbtu	$	7.94	$	6.26		$	6.80		$	7.13		$	7.28		$	6.94
Fair value, net	$	27,614	$	5,563		$	(316	)	$	33		$	(32	)	$	32,862
Basis Swaps:
Contract volumes (Bbl)		—		3,630,000			8,549,998			9,000,000			9,000,003			30,180,001
Weighted-average fixed price per Bbl	$	—	$	0.63		$	0.67		$	0.70		$	0.71		$	0.69
Fair value, net	$	—	$	(812	)	$	(1,725	)	$	(1,436	)	$	(1,124	)	$	(5,097	)
Crude Oil Swaps:
Contract volumes (Bbl)		18,000		30,000			—			—			—			48,000
Weighted-average fixed price per Bbl	$	90.07	$	87.50		$	—		$	—		$	—		$	88.46
Fair value, net	$	323	$	347		$			$			$			$	670
Total fair value, net	$	27,937	$	5,098		$	(2,041	)	$	(1,403	)	$	(1,156	)	$	28,435

In June 2009, we amended or exited certain of our above market natural gas price derivative contracts for periods beginning in the second quarter of 2010 through the fourth quarter of 2012. In return, we received approximately $26 million. Concurrent with this, the strike prices on the derivative contracts that we did not exit were set to market prices at the time and we entered into new natural gas price derivative contracts to increase the total amount of our future proved developed natural gas production hedged to approximately 85% through 2013. Except for the commodity derivative contracts noted above, there have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2008, in Item 7A of our 2008 Form 10-K/A.

ITEM 4. CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms and that such information is accumulated and communicated to management, including the principal executive officer and the principal financial officer, to allow timely decisions regarding required disclosures. There are inherent

limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of the achieving their control objectives.

In connection with the preparation of our 2008 Form 10-K/A, our management, under the supervision and with the participation of the current principal executive officer and current principal financial officer, conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2008 based on the framework and criteria established in Internal Control – Integrated Framework issued be the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). As a result of that evaluation, management identified numerous control deficiencies that constituted material weaknesses as of December 31, 2008. A material weakness is a deficiency, or a combination of deficiencies in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

Management identified the following control deficiencies that constituted material weaknesses as of December 31, 2008, which continue to exist at June 30, 2009:

(1)

Control environment — We did not maintain an effective control environment. The control environment, which is the responsibility of senior management, sets the tone of the organization, influences the control consciousness of its people, and is the foundation for all other components of internal control over financial reporting. Each of these control environment material weaknesses contributed to the material weaknesses discussed in items (2) through (8) below. We did not maintain an effective control environment because of the following material weaknesses:

	(a)		We did not maintain a tone and control consciousness that consistently emphasized adherence to accurate financial reporting and enforcement of Company policies and procedures. This control deficiency fostered a lack of sufficient appreciation for internal controls over financial reporting, allowed for management override of internal controls in certain circumstances and resulted in an ineffective process for monitoring the adherence of QRCP’s policies and procedures.

	(b)		In addition, we did not maintain a sufficient complement of personnel with an appropriate level of accounting knowledge, experience, and training in the application of GAAP commensurate with our financial reporting requirements and business environment.

	(c)		We did not maintain an effective anti-fraud program designed to detect and prevent fraud relating to (i) an effective whistle-blower program, (ii) consistent background checks of personnel in positions of responsibility, and (iii) an ongoing program to manage identified fraud risks.

The control environment material weaknesses described above contributed to the material weaknesses related to the transfers that were the subject of the internal investigation and to our internal control over financial reporting, period end financial close and reporting, accounting for derivative instruments, stock compensation costs, depreciation, depletion and amortization, impairment of oil and gas properties and cash management described in items (2) to (8) below.

(2)

Internal control over financial reporting — We did not maintain effective monitoring controls to determine the adequacy of our internal control over financial reporting and related policies and procedures because of the following material weaknesses:

	(a)		Our policies and procedures with respect to the review, supervision and monitoring of our accounting operations throughout the organization were either not designed and in place or not operating effectively.

	(b)		We did not maintain an effective internal control monitoring function. Specifically, there were insufficient policies and procedures to effectively determine the adequacy of our internal control over financial reporting and monitoring the ongoing effectiveness thereof.

Each of these material weaknesses relating to the monitoring of our internal control over financial reporting contributed to the material weaknesses described in items (3) through (8) below.

(3)

Period end financial close and reporting — We did not establish and maintain effective controls over certain of our period-end financial close and reporting processes because of the following material weaknesses:

	(a)		We did not maintain effective controls over the preparation and review of the interim and annual consolidated financial statements and to ensure that we identified and accumulated all required supporting information to ensure the completeness and accuracy of the consolidated financial statements and that balances and disclosures reported in the consolidated financial statements reconciled to the underlying supporting schedules and accounting records.

	(b)		We did not maintain effective controls to ensure that we identified and accumulated all required supporting information to ensure the completeness and accuracy of the accounting records.

	(c)		We did not maintain effective controls over the preparation, review and approval of account reconciliations. Specifically, we did not have effective controls over the completeness and accuracy of supporting schedules for substantially all financial statement account reconciliations.

	(d)		We did not maintain effective controls over the complete and accurate recording and monitoring of intercompany accounts. Specifically, effective controls were not designed and in place to ensure that intercompany balances were completely and accurately classified and reported in our underlying accounting records and to ensure proper elimination as part of the consolidation process.

	(e)		We did not maintain effective controls over the recording of journal entries, both recurring and non-recurring. Specifically, effective controls were not designed and in place to ensure that journal entries were properly prepared with sufficient support or documentation or were reviewed and approved to ensure the accuracy and completeness of the journal entries recorded.

	(4)		Derivative instruments — We did not establish and maintain effective controls to ensure the correct application of GAAP related to derivative instruments. Specifically, we did not adequately document the criteria for measuring hedge effectiveness at the inception of certain derivative transactions and did not subsequently value those derivatives appropriately.

	(5)		Stock compensation cost — We did not establish and maintain effective controls to ensure completeness and accuracy of stock compensation costs. Specifically, effective controls were not designed and in place to ensure that documentation of the terms of the awards were reviewed in order to be recorded accurately.

	(6)		Depreciation, depletion and amortization — We did not establish and maintain effective controls to ensure completeness and accuracy of depreciation, depletion and amortization expense. Specifically, effective controls were not designed and in place to calculate and review the depletion of oil and gas properties.

	(7)		Impairment of oil and gas properties — We did not establish and maintain effective controls to ensure the accuracy and application of GAAP related to the capitalization of costs related to oil and gas properties and the required evaluation of impairment of such costs. Specifically, effective controls were not designed and in place to determine, review and record the nature of items recorded to oil and gas properties and the calculation of oil and gas property impairments.

	(8)		Cash management — We did not establish and maintain effective controls to adequately segregate the duties over cash management. Specifically, effective controls were not designed to prevent the misappropriation of cash.

Additionally, each of the control deficiencies described in items (1) through (8) above could result in a misstatement of the aforementioned account balances or disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected.

In connection with the preparation of this Quarterly Report on Form 10-Q, our management, under the supervision and with the participation of the current principal executive officer and current principal financial officer, conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of June 30, 2009. Based on that evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective as of June 30, 2009. Notwithstanding this determination, our management believes that the consolidated financial statements in this Quarterly Report on Form 10-Q fairly present, in all material respects, our financial position and results of operations and cash flows as of the dates and for the periods presented, in conformity with GAAP.

Remediation Plan

Our management, under new leadership as described below, has been actively engaged in the planning for, and implementation of, remediation efforts to address the material weaknesses, as well as other identified areas of risk. These remediation efforts, outlined below, are intended both to address the identified material weaknesses and to enhance our overall financial control environment. In May 2009, Mr. David Lawler was appointed Chief Executive Officer (our principal executive officer). In January 2009, Mr. Eddie LeBlanc was appointed Chief Financial Officer (our principal financial and accounting officer). The design and implementation of these and other remediation efforts are the commitment and responsibility of this new leadership team.

In addition, Mr. Rateau, one of our independent directors, was elected as Chairman of the Board, and Mr. McMichael, who has significant prior public company audit committee experience, was added to our Board of Directors and Audit Committee.

In connection with our entry into the Merger Agreement, Mr. McMichael and another director, James B. Kite, Jr., resigned from our Board of Directors, each effective July 2, 2009. Messrs. McMichael and Kite resigned in order to reduce our expenses during the period between the signing of the Merger Agreement and the closing of the Recombination and not because of any disagreement with management on any matter relating to our operations, policies or practices.

Our new leadership team, together with other senior executives, is committed to achieving and maintaining a strong control environment, high ethical standards, and financial reporting integrity. This commitment will be communicated to and reinforced with every employee and to external stakeholders. This commitment is accompanied by a renewed management focus on processes that are intended to achieve accurate and reliable financial reporting.

As a result of the initiatives already underway to address the control deficiencies described above, we have effected personnel changes in our accounting and financial reporting functions. We have taken remedial actions, which included termination, with respect to all employees who were identified as being involved with the inappropriate transfers of funds. In addition, we have implemented additional training and/or increased supervision and established segregation of duties regarding the initiation, approval and reconciliation of cash transactions, including wire transfers.

The Board of Directors has directed management to develop a detailed plan and timetable for the implementation of the foregoing remedial measures (to the extent not already completed) and will monitor their implementation. In addition, under the direction of the Board of Directors, management will continue to review and make necessary changes to the overall design of our internal control environment, as well as policies and procedures to improve the overall effectiveness of internal control over financial reporting.

We believe the measures described above will enhance the remediation of the control deficiencies we have identified and strengthen our internal control over financial reporting. We are committed to continuing to improve our internal control processes and will continue to diligently and vigorously review our financial reporting controls and procedures. As we continue to evaluate and work to improve our internal control over financial reporting, we may determine to take additional measures to address control deficiencies or determine to modify, or in appropriate circumstances not to complete, certain of the remediation measures described above.

Changes in Internal Control Over Financial Reporting

Except as described above, there were no other changes in our internal control over financial reporting during the quarter ended June 30, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

See Part I, Item I, Note 9 to our condensed consolidated financial statements entitled “Commitments and Contingencies,” which is incorporated herein by reference.

We are subject, from time to time, to certain legal proceedings and claims in the ordinary course of conducting our business. We record a liability related to our legal proceedings and claims when we have determined that it is probable that we will be obligated to pay and the related amount can be reasonably estimated. Except for those legal proceedings listed in our 2008 Form 10-K/A, we believe there are no pending legal proceedings in which we are currently involved which, if adversely determined, could have a material adverse effect on our financial position, results of operations or cash flow. While we intend to defend vigorously against these claims, we are unable to predict the outcome of these proceedings or reasonably estimate a range of possible loss that may result.

ITEM 1A. RISK FACTORS.

There have been no material changes to the information included in Item 1A. “Risk Factors” in our 2008 Form 10-K/A.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

None.

ITEM 5. OTHER INFORMATION.

None.

ITEM 6. EXHIBITS



2.1*		Agreement and Plan of Merger, dated as of July 2, 2009, by and among Quest Holdings Corp., Quest Resource Corporation, Quest Midstream Partners, L.P., Quest Energy Partners, L.P., Quest Midstream GP, LLC, Quest Energy GP, LLC, Quest Resource Acquisition Corp., Quest Energy Acquisition, LLC, Quest Midstream Holdings Corp. and Quest Midstream Acquisition, LLC (incorporated herein by reference to Exhibit 2.1 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 7, 2009).

4.1*		Amendment No. 1 to the Rights Agreement, dated as of July 2, 2009, between Quest Resource Corporation and Computershare Trust Company, N.A., as successor rights agent to UMB Bank, N.A. (incorporated herein by reference to Exhibit 4.1 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 7, 2009).

10.1*		Settlement Agreement by and among Quest Resource Corporation, Quest Energy Partners, L.P., Quest Midstream Partners, L.P. and Jerry D. Cash, dated May 19, 2009 (incorporated herein by reference to Exhibit 10.31 to Quest Energy Partners, L.P.’s Annual Report on Form 10-K filed on June 16, 2009).

10.2*		Full and Final Settlement Agreement and Mutual Release, by and among Quest Resource Corporation, Quest Energy Partners, L.P. Midstream Partners, L.P., Rockport Energy, LLC, Rockport Georgetown Partners, LLC, Rockport Georgetown Holdings, LP, Jerry D. Cash, Bryan T. Simmons and Steven Hochstein, dated May 19, 2009 (incorporated herein by reference to Exhibit 10.32 to Quest Energy Partners, L.P.’s Annual Report on Form 10-K filed on June 16, 2009).

10.3*		Third Amendment to Amended and Restated Credit Agreement, dated as of May 29, 2009, by and among Quest Cherokee, LLC, Quest Energy Partners, L.P., Quest Cherokee Oilfield Service, LLC, Royal Bank of Canada, KeyBank National Association and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 to Quest Resource Corporation’s Current Report on Form 8-K filed on June 23, 2009).

10.4*		Amended and Restated Intercreditor Agreement and Collateral Agency Agreement, dated as of June 18, 2009, by and among Royal Bank of Canada, BP Corporation North America, Inc. and Quest Cherokee, LLC (incorporated herein by reference to Exhibit 10.2 to Quest Resource Corporation’s Current Report on Form 8-K filed on June 23, 2009).

10.5*		Fourth Amendment to Amended and Restated Credit Agreement, dated as of May 29, 2009, by and among the Company, Royal Bank of Canada and the Guarantors party thereto (incorporated herein by reference to Exhibit 10.62 to Quest Resource Corporation’s Annual Report on Form 10-K filed on June 2, 2009).

10.6*		Fifth Amendment to Amended and Restated Credit Agreement, dated as of June 30, 2009, by and among Quest Resource Corporation, Royal Bank of Canada and the Guarantors party thereto (incorporated herein by reference to Exhibit 10.4 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 7, 2009).

10.7*		First Amendment to Pledge and Security Agreement for Amended and Restated Credit Agreement by Quest Oil & Gas, LLC for the benefit of Royal Bank of Canada, dated May 29, 2009 (incorporated herein by reference to Exhibit 10.67 to Quest Resource Corporation’s Annual Report on Form 10-K filed on June 2, 2009).

10.8*		Fourth Amendment to Amended and Restated Credit Agreement, dated as of June 30, 2009, among Quest Cherokee, LLC, Quest Energy Partners, L.P., Quest Cherokee Oilfield Service, LLC, Royal Bank of Canada, KeyBank National Association and the Required Lenders party thereto (incorporated herein by reference to Exhibit 10.5 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 7, 2009).

10.9*		Second Amendment to Second Lien Senior Term Loan Agreement, dated as of June 30, 2009, among Quest Cherokee, LLC, Quest Energy Partners, L.P., Quest Cherokee Oilfield Service, LLC, Royal Bank of Canada, KeyBank National Association, Société Générale and the Required Lenders party thereto (incorporated herein by reference to Exhibit 10.6 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 7, 2009).

10.10*		Support Agreement, dated as of July 2, 2009, among Quest Resource Corporation, Quest Midstream Partners, L.P., Quest Energy Partners, L.P. and each of the unitholders of Quest Midstream Partners, L.P. party thereto (incorporated herein by reference to Exhibit 10.1 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 7, 2009).

10.11*		Amendment No. 1 to Amended and Restated Investors’ Rights Agreement, effective as of July 1, 2009, by and among Quest Midstream Partners, L.P., Quest Midstream GP, LLC, Quest Resource Corporation and the Investors party thereto (incorporated herein by reference to Exhibit 10.2 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 7, 2009).

10.12*		Amendment No. 2 to the Second Amended and Restated Agreement of Limited Partnership of Quest Midstream Partners, L.P., dated July 1, 2009, by and among Quest Midstream GP, LLC, Quest Resource Corporation and the Limited Partners party thereto (incorporated herein by reference to Exhibit 10.3 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 7, 2009).

31.1		Certification by principal executive officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification by principal financial officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification by principal executive officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification by principal financial officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		Incorporated by reference.

PLEASE NOTE: Pursuant to the rules and regulations of the Securities and Exchange Commission, we have filed or incorporated by reference the agreement referenced above as exhibit to this Quarterly Report on Form 10-Q. The agreements have been filed to provide investors with information regarding their respective terms. The agreements are not intended to provide any other factual information about the Company or its business or operations. In particular, the assertions embodied in any representations, warranties and covenants contained in the agreements may be subject to qualifications with respect to knowledge and materiality different from those applicable to investors and may be qualified by information in confidential disclosure schedules not included with the exhibit. These disclosure schedules may contain information that modifies, qualifies and creates exceptions to the representations, warranties and covenants set forth in the agreements. Moreover, certain representations, warranties and covenants in the agreements may have been used for the purpose of allocating risk between the parties, rather than establishing matters as facts. In addition, information concerning the subject matter of the representations, warranties and covenants may have changed after the date of the respective agreement, which subsequent information may or may not be fully reflected in the Company’s public disclosures. Accordingly, investors should not rely on the representations, warranties and covenants in the agreements as characterizations of the actual state of facts about the Company or its business or operations on the date hereof.


PART I — FINANCIAL INFORMATION

Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008			F-1
Condensed Consolidated Statements of Operations for the Three Months and Six Months Ended June 30, 2009 and 2008			F-2
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2009 and 2008			F-3
Condensed Consolidated Statements of Stockholders’ Equity for the Six Months Ended June 30, 2009			F-4
Notes to Condensed Consolidated Financial Statements			F-5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			2
Item 3. Quantitative and Qualitative Disclosures About Market Risk			16
Item 4. Controls and Procedures			16

PART II — OTHER INFORMATION

Item 1. Legal Proceedings			20
Item 1A. Risk Factors			20
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			20
Item 3. Defaults Upon Senior Securities			20
Item 4. Submission of Matters to a Vote of Security Holders			20
Item 5. Other Information			20
Item 6. Exhibits			20
SIGNATURES			21
EX-31.1
EX-31.2
EX-32.1
EX-32.2


	Quest Resource Corporation
	By:	/s/ David C. Lawler
		David C. Lawler
		Chief Executive Officer and President


	By:	/s/ Eddie M. LeBlanc, III
		Eddie M. LeBlanc, III
		Chief Financial Officer


											Total
											Stockholders’
			Additional								Deficit Before						Total
	Common		Paid-in		Treasury			Accumulated			Non-controlling			Non-controlling			Stockholders’
	Stock		Capital		Stock			Deficit			Interests			Interests			Equity
Balance, December 31, 2008	$	33	$	298,583	$	(7	)	$	(302,491	)	$	(3,882	)	$	204,536		$	200,654
Stock based compensation				448		—			—			448			371			819
Net loss		—		—		—			(69,405	)		(69,405	)		(40,165	)		(109,570	)

Balance, June 30, 2009	$	33	$	299,031	$	(7	)	$	(371,896	)	$	(72,839	)	$	164,742		$	91,903

	•		risks associated with drilling and operating wells;

	•		risks associated with the operation of natural gas pipelines and gathering systems;

	•		discovery, acquisition, development and replacement of oil and natural gas reserves;

	•		cash flow and liquidity;

	•		timing and amount of future production of oil and natural gas;

	•		availability of drilling and production equipment;

	•		marketing of oil and natural gas;

	•		developments in oil-producing and natural gas-producing countries;

	•		title to our properties;

	•		litigation;

	•		competition;

	•		general economic conditions, including costs associated with drilling and operations of our properties;

	•		environmental or other governmental regulations, including legislation to reduce emissions of greenhouse gases;

	•		receipt and collectability of amounts owed to us by purchasers of our production and counterparties to our derivative financial instruments;

	•		decisions whether or not to enter into derivative financial instruments;

	•		events similar to those of September 11, 2001;

	•		actions of third party co-owners of interests in properties in which we also own an interest; and

	•		fluctuations in interest rates.