UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q/A

(Amendment No. 1)

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

Commission file number: 0-17371

QUEST RESOURCE CORPORATION

Nevada		90-0196936
(State or other jurisdiction of incorporation or organization)		(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		Smaller reporting company o
				(Do not check if a smaller reporting company)

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

     As of November 2, 2009, the issuer had 32,042,642 shares of common stock outstanding.

 

 

EXPLANATORY NOTE

Each item of the quarterly report on Form 10-Q as originally filed on November 5, 2009 has been included in this Form 10-Q/A in its entirety. No attempt has been made in this Form 10-Q/A to modify or update the disclosures as presented in the original Form 10-Q to reflect events occurring after the original filing date. Additional disclosure has been made to reflect the cancellation of the Missouri Gas Energy (“MGE”) contract, which occurred on October 31, 2009. In particular, and without limitation, we have provided certain forward-looking information in this Form 10-Q/A. This information has not been revised from the information provided in the originally filed quarterly report on Form 10-Q because it did not relate to the cancellation of such contract.

QUEST RESOURCE CORPORATION

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of September 30, 2009 and December 31, 2008			F-1
Condensed Consolidated Statements of Operations for the Three Months and Nine Months Ended September 30, 2009 and 2008			F-2
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2009 and 2008			F-3
Condensed Consolidated Statements of Equity for the Nine Months Ended September 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			1
Item 3. Quantitative and Qualitative Disclosures About Market Risk			15
Item 4. Controls and Procedures			16
PART II — OTHER INFORMATION
Item 1. Legal Proceedings			19
Item 1A. Risk Factors			19
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			46
Item 3. Defaults Upon Senior Securities			46
Item 4. Submission of Matters to a Vote of Security Holders			46
Item 5. Other Information			46
Item 6. Exhibits			47
SIGNATURES			48
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I — FINANCIAL INFORMATION

Item 1.		Financial Statements

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
($ in thousands, except share data)

		September 30, 2009				December 31, 2008
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	33,948			$	13,785
Restricted cash			702				559
Accounts receivable — trade, net			10,561				16,715
Other receivables			3,474				9,434
Other current assets			1,643				2,858
Inventory			10,800				11,420
Current derivative financial instrument assets			19,625				42,995
Total current assets			80,753				97,766
Oil and gas properties under full cost method of accounting, net			43,048				172,537
Pipeline assets, net			302,572				310,439
Other property and equipment, net			20,358				23,863
Other assets, net			8,188				14,735
Long-term derivative financial instrument assets			4,653				30,836
Total assets		$	459,572			$	650,176
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable		$	15,747			$	35,804
Revenue payable			4,281				8,309
Accrued expenses			7,434				7,138
Current portion of notes payable			41,019				45,013
Current derivative financial instrument liabilities			1,413				12
Total current liabilities			69,894				96,276
Long-term derivative financial instrument liabilities			5,294				4,230
Asset retirement obligations			6,346				5,922
Notes payable			302,535				343,094
Commitments and contingencies
Equity:
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 — 32,073,132 and 32,224,643 at September 30, 2009 and December 31, 2008, respectively, outstanding — 31,890,945 and 31,720,312 at September 30, 2009 and December 31, 2008, respectively			33				33
Additional paid-in capital			299,134				298,583
Treasury stock, at cost			(7	)			(7	)
Accumulated deficit			(383,423	)			(302,491	)
Total stockholders’ deficit before non-controlling interests			(84,263	)			(3,882	)
Non-controlling interests			159,766				204,536
Total equity			75,503				200,654
Total liabilities and equity		$	459,572			$	650,176

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

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in thousands, except per share data)
(Unaudited)

		For the Three months ended								For the Nine months ended
		September 30,								September 30,
		2009				2008				2009				2008
Revenue:
Oil and gas sales		$	18,329			$	49,531			$	56,711			$	136,989
Gas pipeline revenue			5,633				7,512				21,022				21,561
Total revenues			23,962				57,043				77,733				158,550
Costs and expenses:
Oil and gas production			8,739				9,963				23,699				33,000
Pipeline operating			8,243				7,737				22,264				22,859
General and administrative			11,337				4,638				29,705				16,579
Depreciation, depletion and amortization			14,068				18,353				39,274				49,686
Impairment of oil and gas properties			—				—				102,902				—
Recovery of misappropriated funds, net of liabilities assumed			(9	)			—				(3,406	)			—
Total costs and expenses			42,378				40,691				214,438				122,124
Operating income (loss)			(18,416	)			16,352				(136,705	)			36,426
Other income (expense):
Gain (loss) from derivative financial instruments			8,752				145,132				31,078				(4,482	)
Other income (expense), net			(140	)			59				(1	)			181
Interest expense, net			(6,920	)			(7,187	)			(20,666	)			(17,244	)
Total other income (expense)			1,692				138,004				10,411				(21,545	)
Income (loss) before income taxes and non-controlling interests			(16,724	)			154,356				(126,294	)			14,881
Income tax expense			—				—				—				—
Net income (loss)			(16,724	)			154,356				(126,294	)			14,881
Net (income) loss attributable to non-controlling interest			5,197				(66,505	)			45,362				(10,011	)
Net income (loss) attributable to controlling interest		$	(11,527	)		$	87,851			$	(80,932	)		$	4,870
Net income (loss) per common share:
Basic		$	(0.36	)		$	2.75			$	(2.54	)		$	0.18
Diluted		$	(0.36	)		$	2.75			$	(2.54	)		$	0.18
Weighted average shares outstanding:
Basic			31,885				31,920				31,828				26,481
Diluted			31,885				31,920				31,828				26,481

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

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
($ in thousands)
(Unaudited)

		For the Nine Months Ended
		September 30,
		2009				2008
Cash flows from operating activities:
Net income (loss)		$	(126,294	)		$	14,881
Adjustments to reconcile net income (loss) to cash provided by operations:
Depreciation, depletion and amortization			39,274				49,686
Stock-based compensation			1,143				2,107
Impairment of oil and gas properties			102,902				—
Amortization of deferred loan costs			4,109				1,578
Change in fair value of derivative financial instruments			52,018				(13,313	)
Bad debt expense			—				96
Recovery of misappropriated funds, net of liabilities assumed			(977	)			—
Loss (gain) on disposal of property and equipment			83				(7	)
Change in assets and liabilities:
Accounts receivable			6,154				6,529
Other receivables			5,960				(2,821	)
Other current assets			1,215				(1,351	)
Other assets			153				1,453
Accounts payable			(20,221	)			6,792
Revenue payable			(4,140	)			(6,523	)
Accrued expenses			3,211				(3,160	)
Other long-term liabilities			—				472
Other			(2	)			(255	)
Cash flows from operating activities			64,588				56,164
Cash flows from investing activities:
Restricted cash			(143	)			677
Proceeds from sale of oil and gas properties			8,846				—
Acquisition of business — PetroEdge			—				(141,777	)
Equipment, development, leasehold and pipeline			(6,363	)			(120,813	)
Cash flows from investing activities			2,340				(261,913	)
Cash flows from financing activities:
Proceeds from bank borrowings			1,430				84,000
Repayments of note borrowings			(13,854	)			(50,035	)
Proceeds from revolver note			1,500				122,000
Repayments of revolver note			(35,272	)			—
Distributions to unitholders			—				(20,770	)
Refinancing costs			(569	)			(3,018	)
Proceeds from issuance of common stock			—				84,801
Cash flows from financing activities			(46,765	)			216,978
Net increase in cash			20,163				11,229
Cash and cash equivalents beginning of period			13,785				6,680
Cash and cash equivalents end of period		$	33,948			$	17,909

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

QUEST RESOURCE CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2009
(Amounts subsequent to December 31, 2008 are unaudited)
(in thousands)

																		Total
																		Stockholders’
						Additional												Deficit Before
		Common				Paid-in				Treasury				Accumulated				Non-controlling				Non-controlling				Total
		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			—				551				—				—				551				592				1,143
Net loss			—				—				—				(80,932	)			(80,932	)			(45,362	)			(126,294	)
Balance, September 30, 2009		$	33			$	299,134			$	(7	)		$	(383,423	)		$	(84,263	)		$	159,766			$	75,503

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

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2009
(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 consolidated financial statements. All such adjustments are of a normal recurring nature. In addition, the Company also recorded a $0.8 million write-off of unamortized debt issuance costs associated with the modification of its term loan (See Note 3 — Long Term Debt). 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 condensed consolidated financial statements should be read in conjunction with the consolidated 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.

     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 FASB Accounting Standards Codification (“FASB ASC”) 810 Consolidation. FASB ASC 810 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, FASB ASC 810 establishes principles for valuation of retained non-controlling equity investments and measurement of gain or loss when a subsidiary is deconsolidated. FASB ASC 810-10 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 FASB ASC 810 effective January 1, 2009. Under FASB ASC 810, 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 (loss) attributable to QRCP and the noncontrolling partners’ ownership interest separately in the condensed consolidated statement of operations. All prior periods have been reclassified to comply with FASB ASC 810.

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 starting with 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.

     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, Quest Energy and other parties thereto entered into an Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which, following a series of mergers and an entity conversion, QRCP, Quest Energy and the successor to Quest Midstream will become wholly-owned subsidiaries of PostRock Energy Corporation (“PostRock”) a new, publicly-traded corporation (the “Recombination”). On October 2, 2009, the Merger Agreement was amended to, among other things, reflect certain technical changes as the result of an internal restructuring. On October 6, 2009, PostRock filed with the SEC a registration statement on Form S-4, which included a joint proxy statement/prospectus, relating to the Recombination.

     While we are working toward the 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 PostRock and its subsidiaries, 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 PostRock 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.

     Cash and Capital Resources — On September 11, 2009, QRCP amended and restated its credit agreement to add an additional $8 million revolving credit facility, which will be used to finance QRCP’s drilling program in the Appalachian Basin, general and administrative expenses, working capital and other corporate expenses. Management believes that the new revolving credit facility will provide QRCP with sufficient liquidity to satisfy its obligations, including general and administrative expenses, capital expenditures and debt service requirements through June 30, 2010. As discussed in Note 3 — Long-Term Debt, the total amount due on July 11, 2010 , by QRCP under its credit agreement is estimated to be approximately $21 million. As a result, QRCP will need to raise a significant amount of equity capital during the first half of 2010 to pay this amount and further fund its drilling program. QRCP (or PostRock if the Recombination is completed) may not be able to raise a sufficient amount of equity capital for these purposes at the appropriate time due to market conditions or its financial condition and prospects or may have to issue shares at a significant discount to the market price. The Company, through its subsidiaries Quest Energy and Quest Cherokee LLC (“Quest Cherokee”), is party to a Second Lien Senior Term Loan Agreement originally due and maturing on September 30, 2009. We have obtained amendments to extend the maturity date of the loan through November 16, 2009.While we are currently negotiating further extensions to this loan, there can be no assurance that such negotiations will be successful or that we will be able to repay amounts due under the Second Lien Senior Term Loan Agreement in accordance with the terms of the agreement. The accompanying financial statements do not include any adjustments that might result from the outcome of these uncertainties.

Recent Accounting Pronouncements and Recently Adopted Accounting Pronouncements

     In June 2009, the FASB issued FASB ASC 105 Generally Accepted Accounting Principles, which establishes FASB ASC as the sole source of authoritative GAAP. Pursuant to the provisions of FASB ASC 105, the Company has updated references to GAAP in its financial statements for the period ended September 30, 2009. The adoption of this standard did not have a material impact on our consolidated financial statements.

     In March 2008, the FASB issued FASB ASC 815-10 Derivatives and Hedging that does not change the accounting for derivatives but does require enhanced disclosures about derivative strategies and accounting practices. We adopted these provisions effective January 1, 2009. See Note 4 — Derivative Financial Instruments for the impact to our disclosures.

     The Company adopted the provisions of FASB ASC 260 Earnings Per Share, effective January 1, 2009, with respect to 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 share (“EPS”) under the two-class method as required by FASB ASC 260. FASB ASC 260 provides that unvested unit-based awards that contain non-forfeitable rights to dividends are participating securities and should be included in the computation of EPS. The Company’s restricted stock units contain non-forfeitable rights to

dividends and thus require these awards to be included in the EPS computation. All prior periods have been conformed to the current year presentation. During periods of losses, 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 EPS 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 crude oil and natural gas 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.

     In May 2009, the FASB issued FASB ASC 855 Subsequent Events. FASB ASC 855 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 FASB ASC 855 beginning with the period ended June 30, 2009.

Note 2 — Acquisitions and Divestitures

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. 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				Nine Months Ended
		September 30,				September 30,
		2008				2008
Pro forma revenue		$	57,043			$	165,100
Pro forma net income (loss)		$	87,851			$	(1,971	)
Pro forma net income (loss) per share — basic and diluted		$	2.70			$	(0.06	)

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.

Note 3 — Long-Term Debt

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

		September 30,				December 31,
		2009				2008
Borrowings under bank senior credit facilities:
QRCP:
Credit Agreement Term Loan		$	30,345			$	29,000
Credit Agreement Revolving Line of Credit			1,500
Quest Energy:
Quest Cherokee Credit Agreement			160,000				189,000
Second Lien Loan Agreement			29,800				41,200
Quest Midstream:			121,728				128,000
Notes payable to banks and finance companies			181				907
Total debt			343,554				388,107
Less current maturities included in current liabilities			41,019				45,013
Total long-term debt		$	302,535			$	343,094

Credit Facilities

     QRCP.

     QRCP and Royal Bank of Canada (“RBC”) were parties to an Amended and Restated Credit Agreement, as amended (the “Original Credit Agreement”), dated as of July 11, 2008, for a $35 million term loan, due and maturing on July 11, 2010.

     QRCP entered into a Second Amended and Restated Credit Agreement (the “Credit Agreement”) with RBC on September 11, 2009. The Credit Agreement contemplates the Recombination and provides that the closing of the Recombination will not be an event of default. No additional amendments to the Credit Agreement are contemplated prior to the closing of the Recombination or in connection therewith. The Credit Agreement includes a term loan with a current outstanding principal balance of $28.3 million and an $8 million revolving line of credit. In addition, there are also four promissory notes that have been issued under the Credit Agreement: an $862,786 interest deferral note dated June 30, 2009 (representing outstanding due and unpaid interest on the term loan), a $924,332 interest deferral note dated September 30, 2009 (representing outstanding due and unpaid interest on the term loan), a $282,500 payment-in-kind note dated May 29, 2009 (representing a 1% amendment fee payable by QRCP in connection with the fourth amendment to the Original Credit Agreement), and a second $25,000 payment-in-kind note dated June 30, 2009 (representing an amendment fee payable by QRCP in connection with the fifth amendment to the Original Credit Agreement).

     Modification of Debt. As a result of the amendment and restatement of the Credit Agreement, QRCP evaluated the remaining cash flows of this facility under FASB ASC 470-50-40 Debt — Modifications and Extinguishments — Derecognition to determine if the facility had been substantially modified as defined by the guidance. Upon determining that a substantial modification had occurred, QRCP recorded an extinguishment of prior debt and the assumption of new debt at fair value. Our analysis indicated that the fair value of the new debt facility was not materially different from the principal amount of the previous debt facility. As a result, QRCP recorded a $0.8 million loss on extinguishment of debt which represents a write-off of unamortized debt issuance costs associated with the prior debt facility. The loss is reflected in interest expense, net, in QRCP’s condensed consolidated statements of operations.

     Interest Rate and Other Fees. Interest accrues on the QRCP term loan, the two interest deferral notes and the two payment-in-kind notes at the base rate plus 10.0%. The base rate varies daily and is generally the higher of the federal funds rate plus 0.50% or RBC’s prime rate for such day. The revolving line of credit is non-interest bearing. Instead, QRCP is required to pay to the lenders a facility fee equal to $2.0 million on July 11, 2010. The facility fee will be proportionately reduced if all of the following facility fee reduction conditions are satisfied: (i) repayment and termination by QRCP of the revolving line of credit, (ii) payment of the deferred quarterly principal payments under the term loan as discussed below under “— Payments,” (iii) repayment of the interest deferral notes and the two payment-in-kind notes and (iv) payment of any deferred interest under the term loan, the interest deferral note and the two payment-in-kind notes as discussed below under “— Payments.”

     Additionally, QRCP through its subsidiaries assigned to the lenders an overriding royalty interest in the oil and gas properties owned by them in the aggregate equal to 2% of its respective working interest (plus royalty interest, if any), proportionately reduced, in its respective oil and gas properties. Each lender agreed to reconvey the overriding royalty interest (and any accrued payments owing to such lender) if on or before July 11, 2010 the facility fee reduction conditions discussed above are satisfied and the term loan (together with accrued and unpaid interest) is paid in full. Each lender also agreed to reconvey the overriding royalty interest (but not any accrued payments owing to such lender) if on or before July 11, 2010 the facility fee reduction conditions discussed above are satisfied.

     Payments. Quarterly principal payments of $1.5 million on the term loan due September 30, 2009, December 31, 2009, March 31, 2010 and June 30, 2010 will be deferred until July 11, 2010, at which time all $6 million will be due. Thereafter, QRCP will be required to make a principal repayment of $1.5 million at the end of each calendar quarter until maturity.

     Maturity Dates. The maturity date of the term loan is January 11, 2012. The maturity date of the revolving line of credit, the interest deferral notes and the two payment-in-kind notes is July 11, 2010. The revolving line of credit, term loan, the two interest deferral notes and the two payment-in-kind notes may be prepaid at any time without any premium or penalty. On July 11, 2010, the total amount due by QRCP under the Credit Agreement (assuming the facility fee reduction conditions are all satisfied on that date) would be approximately $21 million.

     Security Interest. The Credit Agreement is secured by a first priority lien on QRCP’s ownership interests in QELP and QMLP and the oil and gas properties owned by Quest Eastern in the Appalachian Basin, which are substantially all of QRCP’s assets. The assets of QMLP, QELP and their subsidiaries are not pledged to secure the QRCP term loan. The Credit Agreement provides that all obligations arising under the loan documents, including obligations under any hedging agreement entered into with lenders or their affiliates (or BP Corporation North America, Inc. or its affiliates), will be secured pari passu by the liens granted under the loan documents.

     Events of Default. In addition to customary events of default, it is an event of default under the Credit Agreement if by November 30, 2009, QRCP has not (i) delivered to RBC evidence that the Recombination has been agreed to by the lenders under QELP’s and QMLP’s credit agreements and (ii) delivered to RBC evidence that the board of directors of each of QRCP, QELP, QMLP and certain of their subsidiaries have approved the terms of any amendments, restatements or new credit facilities to renew, rearrange or replace the existing credit agreements of each of QELP and QMLP. The financial covenants have been removed from the Credit Agreement, but QRCP and RBC agreed that if the facility fee reduction conditions discussed above under “—Interest Rates and Other Fees” were satisfied on or before July 11, 2010, they would negotiate in good faith to amend the Credit Agreement to add financial covenants customary for similar credit agreements of this type.

     Debt Balance at September 30, 2009. At September 30, 2009, $30.3 million was outstanding under the term loan, the interest deferral notes and the payment-in-kind notes while $1.5 million was outstanding under the revolving line of credit. The weighted average interest rate for the quarter ended September 30, 2009 was 12.42%.

     Compliance. As discussed above under “—Events of Default,” the financial covenants were removed from the Credit Agreement as of September 30, 2009. QRCP was in compliance of with all of its remaining covenants under the Credit Agreement as of September 30, 2009.

     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 Royal Bank of Canada (“RBC”), KeyBank National Association (“KeyBank’) and the lenders party thereto for a three-year $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 $160.0 million and the amount borrowed under the Quest Cherokee Credit Agreement was $160.0 million as of September 30, 2009. As a result, there was no additional borrowing availability. The weighted average interest rate under the Quest Cherokee Credit Agreement for the quarter ended September 30, 2009 was 4.36%.

     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 estimated proved developed producing 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 Energy anticipates that in connection with the redetermination of its borrowing base in November 2009, its borrowing base will be further reduced from its current level of $160 million. In the event of a borrowing base reduction, Quest Energy expects to be able to make the required payments resulting from the borrowing base deficiency out of existing funds.

     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 under the Quest Cherokee Credit Agreement as of September 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 originally due and maturing on September 30, 2009.

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

     As of September 30, 2009, $29.8 million was outstanding under the Second Lien Loan Agreement. The weighted average interest rate under the Second Lien Loan Agreement for the quarter ended September 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. On September 30, 2009, Quest Energy and Quest Cherokee entered into a Third Amendment to the Second Lien Senior Term Loan Agreement that extended the maturity date of the loan for an additional 31 days from September 30, 2009 to October 31, 2009. On October 30, 2009, Quest Energy and Quest Cherokee entered into a Fourth Amendment to the Second Lien Senior Term Loan Agreement that extended the maturity date of the loan for an additional 16 days to November 16, 2009. While Quest Energy and Quest Cherokee are currently negotiating further extensions to this loan, there can be no assurance that such negotiations will be successful or that Quest Energy and Quest Cherokee will be able to repay amounts due under the Second Lien Loan Agreement in accordance with the terms of the agreement.

     Quest Cherokee was in compliance with all of its covenants under the Second Lien Loan Agreement as of September 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 (the “Quest Midstream Credit Agreement”), with RBC and the lenders party thereto.

     As of September 30, 2009, the amount borrowed under the Quest Midstream Credit Agreement was $121.7 million. The weighted average interest rate for the quarter ended September 30, 2009 was 3.38%.

     On August 19, 2009, RBC and QMLP entered into a letter agreement wherein QMLP agreed that during negotiations related to the Recombination, it would not submit a borrowing request or request a letter of credit until the earlier to occur of the Recombination or December 31, 2009.

     QMLP made a $3.4 million Excess Cash Flow payment (as defined in the Quest Midstream Credit Agreement) on August 17, 2009.

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

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 realized 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 FASB ASC 815 Derivatives and Hedging. FASB ASC 815 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. ASC Topic 815 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 FASB ASC 815 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 FASB ASC 815, 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

				September 30,				December 31,
Derivative Financial Instruments		Balance Sheet location		2009				2008
Commodity contracts		Current derivative financial instrument asset		$	19,625			$	42,995
Commodity contracts		Long-term derivative financial instrument asset			4,653				30,836
Commodity contracts		Current derivative financial instrument liability			(1,413	)			(12	)
Commodity contracts		Long-term derivative financial instrument liability			(5,294	)			(4,230	)
				$	17,571			$	69,589

The Effect of Derivative Financial Instruments

						Three months ended								Nine months ended
						September 30,								September 30,
Derivative Financial Instruments		Statement of Operations location				2009				2008				2009				2008
Commodity contracts		Gain (loss) from derivative financial instruments				$	8,752			$	145,132			$	31,078			$	(4,482	)

     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								Nine months ended
		September 30,								September 30,
		2009				2008				2009				2008
Realized gains (losses)		$	19,616			$	(7,525	)		$	83,096			$	(17,795	)
Unrealized gains (losses)			(10,864	)			152,657				(52,018	)			13,313
Total		$	8,752			$	145,132			$	31,078			$	(4,482	)

     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 estimated proved developed producing natural gas production hedged to approximately 85% through 2013.

     The following table summarizes the estimated volumes, fixed prices and fair values attributable to oil and gas derivative contracts as of September 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)			3,687,360				16,129,060				13,550,302				11,000,004				9,000,003				53,366,729
Weighted-average fixed price per Mmbtu		$	7.78			$	6.26			$	6.80			$	7.13			$	7.28			$	6.85
Fair value, net		$	11,939			$	5,020			$	1,048			$	1,676			$	1,178			$	20,861
Natural Gas Collars:
Contract volumes (Mmbtu)			187,500				—				—				—				—				187,500
Weighted-average fixed price per Mmbtu:
Floor		$	11.00			$	—			$	—			$	—			$	—			$	11.00
Ceiling		$	15.00			$	—			$	—			$	—			$	—			$	15.00
Fair value, net		$	1,154			$	—			$	—			$	—			$	—			$	1,154
Total Natural Gas Contracts:
Contract volumes (Mmbtu)			3,874,860				16,129,060				13,550,302				11,000,004				9,000,003				53,554,229
Weighted-average fixed price per Mmbtu		$	7.94			$	6.26			$	6.80			$	7.13			$	7.28			$	6.87
Fair value, net		$	13,093			$	5,020			$	1,048			$	1,676			$	1,178			$	22,015
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		$	—			$	(957	)		$	(1,512	)		$	(1,393	)		$	(1,138	)		$	(5,000	)
Crude Oil Swaps:
Contract volumes (Bbl)			9,000				30,000				—				—				—				39,000
Weighted-average fixed price per Bbl		$	90.07			$	87.50			$	—			$	—			$	—			$	88.09
Fair value, net		$	170			$	386			$	—			$	—			$	—			$	556
Total fair value, net		$	13,263			$	4,449			$	(464	)		$	283			$	40			$	17,571

     The following table summarizes 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):			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 FASB ASC 820 Fair Value Measurements and Disclosures 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.

     FASB ASC 820 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 dates indicated (in thousands):

														Netting and
		Level				Level				Level				Cash				Total Net Fair
September 30, 2009		1				2				3				Collateral*				Value
Derivative financial instruments — assets		$	—			$	5,663			$	18,615			$	—			$	24,278
Derivative financial instruments — liabilities		$	—			$	(133	)		$	(6,574	)		$	—			$	(6,707	)
Total		$	—			$	5,530			$	12,041			$	—			$	17,571
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

     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.

     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):

		Nine Months Ended
		September 30, 2009
Balance at beginning of period		$	60,947
Realized and unrealized gains included in earnings			25,309
Purchases, sales, issuances, and settlements			(74,215	)
Transfers into and out of Level 3			—
Balance as of September 30, 2009		$	12,041

Note 6 — Asset Retirement Obligations

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

		Nine Months Ended
		September 30, 2009
Asset retirement obligations at beginning of period		$	5,922
Liabilities incurred			—
Liabilities settled			—
Accretion			424
Revisions in estimated cash flows			—
Asset retirement obligations at end of period		$	6,346

Note 7 — 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, as amended (the “Award Plan”), represent share-based payment transactions that are treated as compensation expense with a corresponding increase to additional paid-in capital. During the nine months ended September 30, 2009, 300,000 stock options were granted outside of the Award Plan. As of September 30, 2009, there were approximately 1.3 million shares available under the Award Plan for future stock awards and options. For the three and nine months ended September 30, 2009, total share-based compensation related to stock awards and options was $0.1 million and $0.6 million, compared to $(1.3) million and $1.7 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 September 30, 2009 is $0.6 million over a weighted average period of 1.19 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								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Quest Energy
Beginning of period		$	16,131			$	82,879			$	58,666			$	145,364
Contributions, net			—				—				—				(265	)
Distributions			—				(3,925	)			—				(9,540	)
Net income (loss) attributable to non-controlling interest			(4,418	)			66,565				(46,986	)			9,940
Stock compensation expense related to QELP unit-based awards			17				7				50				27
End of period		$	11,730			$	145,526			$	11,730			$	145,526
Quest Midstream
Beginning of period		$	148,611			$	144,748			$	145,870			$	152,021
Contributions, net			—				—				—				—
Distributions			—				—				—				(7,630	)
Net income (loss) attributable to non-controlling interest			(779	)			(60	)			1,624				71
Stock compensation expense related to QMLP unit-based awards			204				113				542				339
End of period		$	148,036			$	144,801			$	148,036			$	144,801
Total non-controlling interest at end of period		$	159,766			$	290,327			$	159,766			$	290,327

     Income/(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								Nine months ended
		September 30,								September 30,
		2009				2008				2009				2008
Basic and diluted earnings per share:
Net income (loss) attributable to common stockholders		$	(11,527	)		$	87,851			$	(80,932	)		$	4,870
Basic and diluted weighted average number of shares:
Common shares			31,885,445				31,096,433				31,827,513				25,527,004
Unvested share-based awards participating			—				823,216				—				954,047
Basic and diluted weighted average number of shares:			31,885,445				31,919,649				31,827,513				26,481,051
Basic and diluted net loss attributable to common stockholders per common share		$	(0.36	)		$	2.75			$	(2.54	)		$	0.18

     Effective January 1, 2009, the Company adopted the provisions of FASB ASC 260 Earnings Per Share which requires participating securities to be included in the allocation of earnings when calculating earnings per share, or 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 nine months ended September 30, 2009, participating securities covering 227,231 common shares were excluded from the computation of net loss per share because their effect would have been antidilutive. Furthermore, approximately 700,000 stock options outstanding at September 30, 2009 were out-of-the-money and thus antidilutive. Approximately 300,000 stock options outstanding at September 30, 2008 were out-of-the-money and thus 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 Company had previously recognized a ceiling test impairment of $102.9 million during the first quarter of 2009 while no impairment was necessary for the second quarter of 2009. As of September 30, 2009, the ceiling test computation utilizing spot prices on that day resulted in the carrying costs of our unamortized proved oil and natural gas properties, net of deferred taxes, exceeding the September 30, 2009 present value of future net revenues by approximately $11.1 million. As a result of subsequent increases in spot prices, the need to recognize an impairment for the quarter ended September 30, 2009, was eliminated. 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 the 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.

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 the material legal proceedings that have been initiated against us since December 31, 2008 and any material developments in existing material legal proceedings that have occurred since December 31, 2008. For additional information regarding our legal proceedings, please see Note 12 to our consolidated financial statements included in our 2008 Form 10-K/A and Note 9 to our condensed consolidated financial statements included in our Quarterly Reports on Form 10-Q for the three months ended March 31, 2009 and June 30, 2009.

Federal Individual Securities Litigation

Bristol Capital Advisors v. Quest Resource Corporation, Inc., Jerry Cash, David E. Grose, and John Garrison, Case No. CIV-09-932, U.S. District Court for the Western District of Oklahoma, filed August 24, 2009

     On August 24, 2009 a complaint was filed in the United States District Court for the Western District of Oklahoma naming the Company and certain current and former officers and directors as defendants. The complaint was filed by an individual shareholder of the Company’s stock. The complaint asserts claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934. The complaint alleges that the defendants violated the federal securities laws by issuing false and misleading statements and/or concealing material information concerning unauthorized transfers from subsidiaries of the Company to entities controlled by the Company’s former chief executive officer, Mr. Jerry D. Cash. The complaint also alleges that the Company issued false and misleading statements and or/concealed material information concerning a misappropriation by its former chief financial officer, Mr. David E. Grose, of $1 million in Company funds and receipt of unauthorized kickbacks of approximately $850,000 from a Company vendor. The complaint also alleges that, as a result of these actions, the Company’s stock price was artificially inflated when the plaintiff purchased the Company’s stock. The Company intends to defend vigorously against the plaintiff’s claims.

     J. Steven Emerson, Emerson Partners, J. Steven Emerson Roth IRA, J. Steven Emerson IRA RO II, and Emerson Family Foundation v. Quest Resource Corporation, Inc., Quest Energy Partners L.P., Jerry Cash, David E. Grose, and John Garrison, Case No. 5:09-cv-1226-M, U.S. District Court for the Western District of Oklahoma, filed November 3, 2009

     On November 3, 2009 a complaint was filed in the United States District Court for the Western District of Oklahoma naming QRCP, QELP, and certain current and former officers and directors as defendants. The complaint was filed by individual shareholders of QRCP stock and individual purchasers of QELP common units. The complaint asserts claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934. The complaint alleges that the defendants violated the federal securities laws by issuing false and misleading statements and/or concealing material information concerning unauthorized transfers from subsidiaries of QRCP to entities controlled by QRCP’s former chief executive officer, Mr. Jerry D. Cash. The complaint also alleges that QRCP and QELP issued false and misleading statements and or/concealed material information concerning a misappropriation by its former chief financial officer, Mr. David E. Grose, of $1 million in company funds and receipt of unauthorized kickbacks of approximately $850,000 from a company vendor. The complaint also alleges that, as a result of these actions, the price of QRCP stock and QELP common units was artificially inflated when the plaintiff purchased QRCP stock and QELP common units. The plaintiffs seek $10 million in damages. QRCP and QELP intend to defend vigorously against the plaintiffs’ claims.

     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. On September 8, 2009, the case was transferred to Judge Miles-LaGrange who is presiding over the other federal cases discussed below, and the case number was changed to CIV-09-752-M. All proceedings in this matter are currently stayed under Judge Miles-LaGrange’s order of October 16, 2009.

     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.

     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 (1/16th in some leases, and 1/32nd 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. Quest Cherokee has filed an answer defending its position. Quest Cherokee intends to defend vigorously against these claims.

     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.

      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. Plaintiffs are royalty owners who allege underpayment of royalties owed to them. Plaintiffs also allege, among other things, that defendants engaged in self-dealing and breached fiduciary duties owed to plaintiffs, and that defendants acted fraudulently toward the plaintiffs. Plaintiffs also allege that the gathering fees and related charges should not have been deducted in paying royalties. QRCP intends to defend this action vigorously.

     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.

		Federal Securities Class Actions
Michael Friedman, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David E. Grose, Case No. 08-cv-936-M, U.S. District Court for the Western District of Oklahoma, filed September 5, 2008
James Jents, individually and on behalf of all others similarly situated v. Quest Resource Corporation, Jerry Cash, David E. Grose, and John Garrison, Case No. 08-cv-968-M, U.S. District Court for the Western District of Oklahoma, filed September 12, 2008
J. Braxton Kyzer and Bapui Rao, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation and David E. Grose, Case No. 08-cv-1066-M, U.S. District Court for the Western District of Oklahoma, filed October 6, 2008
Paul Rosen, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David E. Grose, Case No. 08-cv-978-M, U.S. District Court for the Western District of Oklahoma, filed September 17, 2008

     Four putative class action complaints were filed in the United States District Court for the Western District of Oklahoma naming QRCP, QELP and Quest Energy GP, LLC (“Quest Energy GP”) and certain of their current and former officers and directors as defendants. The complaints were filed by certain stockholders on behalf of themselves and other stockholders who purchased QRCP common stock between May 2, 2005 and August 25, 2008 and QELP common units between November 7, 2007 and August 25, 2008.

The complaints assert claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and Sections 11 and 15 of the Securities Act of 1933. The complaints allege that the defendants violated the federal securities laws by issuing false and misleading statements and/or concealing material facts concerning certain unauthorized transfers of funds from subsidiaries of QRCP to entities controlled by QRCP’s former chief executive officer, Mr. Jerry D. Cash. The complaints also allege that, as a result of these actions, QRCP’s stock price and the unit price of QELP was artificially inflated during the class period. On December 29, 2008 the court consolidated these complaints as Michael Friedman, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David E. Grose, Case No. 08-cv-936-M, in the Western District of Oklahoma. On September 24, 2009, the court appointed lead plaintiffs for each of the QRCP class and the QELP class. The lead plaintiffs must file a consolidated amended complaint within 60 days after being appointed. No further activity is expected in the purported class action until an amended consolidated complaint is filed. On October 13, 2009, the lead plaintiffs filed a motion for partial modification of the automatic discovery stay provided by the Private Securities Litigation Reform Act of 1995. QRCP, QELP and Quest Energy GP intend to defend vigorously against plaintiffs’ claims.

     QRCP and QELP have received letters from their directors and officers’ insurance carriers reserving their rights to limit or preclude coverage under various provisions and exclusions in the policies, including for the committing of a deliberate criminal or fraudulent act by a past, present, or future chief executive officer or chief financial officer. QELP recently received a letter from its directors’ and officers’ liability insurance carrier that it will not provide insurance coverage based on Mr. Cash’s alleged written admission that he engaged in acts for which coverage is excluded. QELP is reviewing this letter and evaluating its options.

     Royalty Owner Class Action

     Hugo Spieker, et al. v. Quest Cherokee, LLC, Case No. 07-1225-MLB, in the U.S. District Court, District of Kansas, filed August 6, 2007

     Quest Cherokee was named as a defendant in a class action lawsuit filed by several royalty owners in the U.S. District Court for the District of Kansas. The case was filed by the named plaintiffs on behalf of a putative class consisting of all Quest Cherokee’s royalty and overriding royalty owners in the Kansas portion of the Cherokee Basin. Plaintiffs contend that Quest Cherokee failed to properly make royalty payments to them and the putative class by, among other things, paying royalties based on reduced volumes instead of volumes measured at the wellheads, by allocating expenses in excess of the actual costs of the services represented, by allocating production costs to the royalty owners, by improperly allocating marketing costs to the royalty owners, and by making the royalty payments after the statutorily proscribed time for doing so without providing the required interest. Quest Cherokee answered the complaint and denied plaintiffs’ claims. On July 21, 2009, the court had granted plaintiffs’ motion to compel production of Quest Cherokee’s electronically stored information, or ESI, and directed the parties to decide upon a timeframe for producing Quest Cherokee’s ESI. Discovery has been stayed until December 5, 2009 to allow the parties to discuss settlement terms. Quest Cherokee has received an initial settlement offer from plaintiffs’ counsel and is in the process of evaluating that offer and its response to the same.

     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. 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 November 4, 2009, the total amount of acreage covered by the leases at issue in these lawsuits was approximately 5,100 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 with the Kansas Court of Appeals, Case No. 08-100576-A; oral argument scheduled for November 18, 2009)

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

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 (trial set for December 2009)

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 on August 3, 2009)

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

Quest Cherokee v. Hinkle, et. al. & Admiral Bay, Case No. 2006-CV-74, District Court of Labette County, State of Kansas, filed September 15, 2006 (trial set for February 2010)

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 issued an opinion affirming the District Court’s decision and remanded the case to the District Court for further proceedings consistent with that decision. Central Natural Resources 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.

     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 dismissal is expected before the end of November 2009.

Environmental Matters

     As of September 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, LLC 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 interstate natural gas pipeline owned by a QMLP subsidiary 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 QELP in connection with the review of its 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.

Note 10 — Related Party Transactions

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 comprised substantially 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 matter 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		$	2,429			$	—			$	2,429
Oil & gas properties			896				1,076				1,972
Other assets			50				—				50
Current liabilities			—				(326	)			(326	)
Long-term debt			—				(719	)			(719	)
Net assets received		$	3,375			$	31			$	3,406

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, following a series of mergers and an entity conversion, QRCP, Quest Energy and the successor to Quest Midstream will become wholly-owned subsidiaries of PostRock. On October 2, 2009, the Merger Agreement was amended to, among other things, reflect certain technical changes as the result of an internal restructuring. Additionally, since shortly before execution of the Merger Agreement one of the Quest Midstream investors had abandoned its Quest Midstream common units, which were inadvertently included in calculating the Quest Midstream exchange ratio contained in the Merger Agreement, the amendment also permitted Quest Midstream to make a distribution of additional common units to its common unitholders in order to increase the number of outstanding common units to match, as closely as practicable, the number set forth in the Merger Agreement. The effect of the distribution was to preserve the relative ownership percentages of PostRock agreed to by the parties without the need to amend the Quest Midstream exchange ratio.

     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”), which was amended on October 2, 2009 to, among other things, add an additional Quest Midstream common unitholder as a party. Pursuant to the Support Agreement, as amended, 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 73% of the common units of Quest Midstream have, subject to certain conditions, agreed to vote their common units in favor of the Recombination.

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 September 30, 2009:
Total revenues		$	18,329			$	16,635			$	(11,002	)		$	23,962
Inter-segment revenues			—				(11,002	)			11,002				—
Third-party revenues		$	18,329			$	5,633			$	—			$	23,962
Segment operating profit (loss)		$	(11,342	)		$	4,254			$	—			$	(7,088	)
Three Months Ended September 30, 2008:
Total revenues		$	49,531			$	16,095			$	(8,583	)		$	57,043
Inter-segment revenues			—				(8,583	)			8,583				—
Third-party revenues		$	49,531			$	7,512			$	—			$	57,043
Segment operating profit		$	18,005			$	2,985			$	—			$	20,990
Nine months ended September 30, 2009:
Total revenues		$	56,711			$	52,260			$	(31,238	)		$	77,733
Inter-segment revenues			—				(31,238	)			31,238				—
Third-party revenues		$	56,711			$	21,022			$	—			$	77,733
Segment operating profit (loss)		$	(128,246	)		$	17,840			$	—			$	(110,406	)
Nine months ended September 30, 2008:
Total revenues		$	136,989			$	47,482			$	(25,921	)		$	158,550
Inter-segment revenues			—				(25,921	)			25,921				—
Third-party revenues		$	136,989			$	21,561			$	—			$	158,550
Segment operating profit		$	42,237			$	10,768			$	—			$	53,005
Identifiable assets:
September 30, 2009		$	132,298			$	327,274			$	—			$	459,572
December 31, 2008		$	311,592			$	338,584			$	—			$	650,176

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

		Three months ended								Nine months ended
		September 30,								September 30,
		2009				2008				2009				2008
Segment operating profit (loss) (1)		$	(7,088	)		$	20,990			$	(110,406	)		$	53,005
General and administrative expenses			(11,337	)			(4,638	)			(29,705	)			(16,579	)
Recovery of misappropriated funds net of liabilities assumed			9				—				3,406				—
Gain (loss) from derivative financial instruments			8,752				145,132				31,078				(4,482	)
Interest expense, net			(6,920	)			(7,187	)			(20,666	)			(17,244	)
Other income (expense), net			(140	)			59				(1	)			181
Loss before income taxes		$	(16,724	)		$	154,356			$	(126,294	)		$	14,881

Note 12 — Subsequent Events

     On October 31, 2009, QMLP’s gas transportation contract with MGE was terminated and has not been renegotiated or renewed. This customer was a significant customer to QMLP. The loss of this customer could result in an impairment of the KPC pipeline assets and customer-related intangible assets. As of November 5, 2009, the range of impairment can not be estimated. The carrying value of these assets was $119.7 million as of September 30, 2009.

     We evaluated our activity after September 30, 2009 until the date of issuance, November 5, 2009, for recognized and unrecognized subsequent events not discussed elsewhere in these footnotes and determined there were none.

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

Forward-looking statements

     This quarterly report contains forward-looking statements that do not directly or exclusively relate to historical facts. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “will,” “could,” “project,” “believe,” “intend,” “anticipate,” “expect,” “estimate,” “continue,” “potential,” “plan,” “forecast” and other words of similar import. Forward-looking statements include information concerning possible or assumed future results of our operations, including statements about the Recombination, projected financial information, valuation information, possible outcomes from strategic alternatives other than the Recombination, the expected amounts, timing and availability of financing, availability under credit facilities, levels of capital expenditures, sources of funds, and funding requirements, among others.

     These forward-looking statements represent our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside of our control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. Those factors include, among others, the risk factors described in Part II, Item IA. “Risk Factors,” as well as the risk factors described in Item 1A. “Risk Factors” in our 2008 Form 10-K/A.

     In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than as described. You should consider the areas of risk and uncertainty described above and discussed in Part II, Item IA. “Risk Factors,” as well as the risk factors described in Item 1A. “Risk Factors” in our 2008 Form 10-K/A in connection with any written or oral forward-looking statements that may be made after the date of this report by us. Except as may be required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

     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 (the “KPC 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 include:

	•		Reduced oil and gas production costs in the current quarter by $0.13 per Mcfe from the prior year quarter.
	•		Sustained natural gas production levels similar to the prior year despite minimal current period capital expenditures on acquisition and development.

Financial Highlights

     The Company’s significant financial highlights include:

	•		Reduced total debt by $44.6 million from December 31, 2008.
	•		Increased cash and cash equivalents by $20.2 million from December 31, 2008.
	•		Repriced derivatives during the second quarter of 2009 and received $26 million.
	•		Obtained a new $8 million revolving credit facility during the third quarter of 2009 to finance the Company’s drilling program in the Appalachian Basin, general and administrative expenses, working capital and other corporate expenses.

Recent Developments

Global Financial Crisis and Impact on Capital Markets and Commodity Prices

     Currently, there is unprecedented uncertainty in the financial markets. This uncertainty presents additional potential risks to us and our subsidiaries and affiliates. These risks include the availability and costs associated with our borrowing capabilities and raising additional debt and equity capital.

     Additionally, the current global economic outlook coupled with exceptional unconventional resource development success in the U.S. has resulted in a significant decline in natural gas prices across the United States. Gas price declines impact us in two different ways. First, the basis differential from NYMEX pricing to sales point pricing for our Cherokee Basin gas production has narrowed significantly. Our Cherokee Basin basis differential averaged $0.49 per Mmbtu in the third quarter of 2009 and was $0.23 per Mmbtu in October 2009 which is down from an average of $1.79 per Mmbtu in the third quarter of 2008 and $3.38 per Mmbtu in October 2008. The second impact has been the absolute value erosion of natural gas. Our operations and financial condition are significantly impacted by absolute natural gas prices. On September 30, 2009, the spot market price for natural gas at Henry Hub was $3.30 per Mmbtu, a 53.7% decrease from September 30, 2008.

     For oil, worldwide demand has decreased by over 5% from 2007 levels creating an oversupply environment similar to natural gas. The recent recovery of oil prices into the $70 per barrel range has had a small positive impact on revenues during the second half of 2009. Our management believes that managing price volatility will continue to be a challenge. The spot market price for oil at Cushing, Oklahoma at September 30, 2009 was $70.46 per barrel, a 30.0% decrease from the price at September 30, 2008. 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, liquidity and capital resources. 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.

   Loss of major customer

     On October 31, 2009, QMLP’s gas transportation contract with Missouri Gas Energy was terminated and has not been renegotiated or renewed. This customer was a significant customer to QMLP. The loss of this customer could result in an impairment of the KPC Pipeline assets and customer-related intangible assets. As of November 5, 2009, the range of impairment can not be estimated. The carrying value of these assets was $119.7 million as of September 30, 2009.

   Suspension of Distributions and Asset Sale

     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 starting with the third quarter of 2008 and on all units starting with the fourth quarter of 2008. Distributions on all of Quest Energy’s and Quest Midstream’s units continue to be suspended, and we are unable to estimate when such distributions may, if ever, be resumed. 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 $12.9 million for the nine months ended September 30, 2008 and did not receive any cash distributions from Quest Energy and Quest Midstream for the nine months ended September 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 certain unauthorized transfers, repayments and re-transfers of funds (the “Transfers”) to entities controlled by Jerry D. Cash, our former chief executive officer, 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 comprised substantially 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 matter 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		$	2,429			$	—			$	2,429
Oil and gas properties			896				1,076				1,972
Other assets			50				—				50
Current liabilities			—				(326	)			(326	)
Long-term debt			—				(719	)			(719	)
Net assets received		$	3,375			$	31			$	3,406

   Recombination

     On July 2, 2009, QRCP, Quest Midstream, Quest Energy and other parties thereto entered into an Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which, following a series of mergers and an entity conversion, QRCP, Quest Energy and the successor to Quest Midstream will become wholly-owned subsidiaries of PostRock Energy Corporation (“PostRock”) a new, publicly-traded corporation (the “Recombination”). On October 2, 2009, the Merger Agreement was amended to, among other things, reflect certain technical changes as the result of an internal restructuring. On October 6, 2009, PostRock filed with the SEC a registration statement on Form S-4, which included a joint proxy statement/prospectus, relating to the Recombination.

     While we are working toward the 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 PostRock and its subsidiaries, 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 PostRock would be owned approximately 44% by current QMLP common unitholders, approximately 33% by current QELP common unitholders (other than QRCP), and approximately 23% by current QRCP stockholders.

     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”), which was amended on October 2, 2009 to, among other things, add an additional Quest Midstream common unitholder as a party. Pursuant to the Support Agreement, as amended, 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 73% of the common units of Quest Midstream have, subject to certain conditions, agreed to vote their common units in favor of the Recombination.

Results of Operations

     The following discussion of financial condition and results of operations should be read in conjunction with the condensed 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								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Revenues:
Oil and gas sales		$	18,329			$	49,531			$	56,711			$	136,989
Natural gas pipelines			16,635				16,095				52,260				47,482
Elimination of inter-segment revenue			(11,002	)			(8,583	)			(31,238	)			(25,921	)
Natural gas pipelines, net of inter-segment revenue			5,633				7,512				21,022				21,561
Total segment revenues		$	23,962			$	57,043			$	77,733			$	158,550
Operating profit (loss):
Oil and gas production		$	(11,342	)		$	18,005			$	(128,246	)		$	42,237
Natural gas pipelines			4,254				2,985				17,840				10,768
Total segment operating profit (loss)			(7,088	)			20,990				(110,406	)			53,005
General and administrative expenses			(11,337	)			(4,638	)			(29,705	)			(16,579	)
Recovery of misappropriated funds, net of liabilities assumed			9				—				3,406				—
Total operating income (loss)		$	(18,416	)		$	16,352			$	(136,705	)		$	36,426