e10vq

Large accelerated filer o

Accelerated filer þ

Non-accelerated filer o

Smaller reporting company o

(Do not check if a smaller reporting company)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)


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

For the quarterly period ended September 30, 2008.


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

For the transition period from to .

Commission file number: 0-17371

QUEST RESOURCE CORPORATION

(Exact name of registrant as specified in its charter)


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

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):

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 July 24, 2009, the issuer had 32,025,976 shares of common stock outstanding.

EXPLANATORY NOTE

This Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 includes consolidated interim financial statements as of September 30, 2008 and for the three and nine month periods ended September 30, 2008, which have not previously been issued, and restated consolidated interim financial statements for the three and nine month periods ended September 30, 2007, which have not previously been restated in any other report for Quest Resource Corporation (“QRCP”). The consolidated balance sheet as of December 31, 2007 included herein was previously restated in our Annual Report on Form 10-K for the year ended December 31, 2008 filed on June 3, 2009, and amended on July 28, 2009 (the “2008 Form 10-K”).

Investigation — On August 22, 2008, in connection with an inquiry from the Oklahoma Department of Securities, the boards of directors of QRCP, Quest Energy GP, LLC (“Quest Energy GP”), the general partner of Quest Energy Partners, L.P. (NASDAQ: QELP) (“Quest Energy” or “QELP”), which is a publicly traded limited partnership controlled by QRCP, and Quest Midstream GP, LLC (“Quest Midstream GP”), the general partner of Quest Midstream Partners, L.P. (“Quest Midstream” or “QMLP”), a private limited partnership controlled by QRCP, held a joint working session to address certain unauthorized transfers, repayments and re-transfers of funds (the “Transfers”) to entities controlled by their former chief executive officer, Mr. Jerry D. Cash.

A joint special committee comprised of one member designated by each of the boards of directors of QRCP, Quest Energy GP, and Quest Midstream GP was immediately appointed to oversee an independent internal investigation of the Transfers. In connection with this investigation, other errors were identified in prior year financial statements and management and the board of directors concluded that QRCP had material weaknesses in its internal control over financial reporting. As of December 31, 2008, these material weaknesses continued to exist.

As reported on a Current Report on Form 8-K filed on January 2, 2009, on December 31, 2008, the board of directors of QRCP determined that the audited consolidated financial statements of QRCP as of and for the years ended December 31, 2007, 2006 and 2005 and QRCP’s unaudited consolidated financial statements as of and for the three months ended March 31, 2008 and as of and for the three and six months ended June 30, 2008 should no longer be relied upon. The investigation and determination that our previously issued financial statements should no longer be relied upon resulted in our inability to timely file this Quarterly Report on Form 10-Q for the quarter ended September 30, 2008.

Restatement and Reaudit — In October 2008, QRCP’s audit committee engaged a new independent registered public accounting firm to audit QRCP’s consolidated financial statements for 2008 and, in January 2009, engaged them to reaudit QRCP’s consolidated financial statements as of December 31, 2007 and 2006 and for the years ended December 31, 2007, 2006 and 2005.

It was determined that QRCP’s previously issued consolidated financial statements contained errors in a majority of the financial statement line items for all periods presented. Please refer to the restated consolidated financial statements included in our 2008 Form 10-K which corrected these errors and which includes a detailed explanation of the most significant errors and comparisons of previously reported amounts to restated amounts, including the balance sheet as of December 31, 2007, which is included in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2008. This Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 includes only comparisons of previously reported amounts to restated amounts for the three and nine month periods ended September 30, 2007, which have not previously been restated in any other report.

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Except as otherwise required by the context, references in this quarterly report to “we,” “our,” “us,” “Quest” or “the Company” refer to Quest Resource Corporation and its subsidiaries: Quest Energy Partners, L.P.; Quest Energy GP, LLC; Quest Cherokee, LLC; Quest Cherokee Oilfield Service, LLC; Quest Midstream Partners, L.P.; Quest Midstream GP, LLC; Bluestem Pipeline, LLC; Quest Transmission Company, LLC; Quest Kansas Pipeline, L.L.C; Quest Kansas General Partner, L.L.C.; Quest Pipelines (KPC); Quest Oil & Gas, LLC; Quest Energy Service, LLC; Quest Eastern Resource LLC and Quest MergerSub, Inc.. Our operations are primarily conducted through Quest Cherokee, LLC, Quest Cherokee Oilfield Service, LLC, Bluestem Pipeline, LLC, Quest Energy Service, LLC and, beginning July 11, 2008, Quest Eastern Resource LLC.

Our unaudited interim financial statements include consolidated balance sheets as of September 30, 2008 and December 31, 2007, consolidated statements of operations for the three month and nine month periods ended September 30, 2008, restated consolidated statements of operations for the three month and nine month periods ended September 30, 2007, a consolidated statement of cash flows for the nine month period ended September 30, 2008, a restated consolidated statement of cash flows for the nine month period ended September 30, 2007, and the notes thereto.

The financial statements included herein have been prepared internally, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been omitted. However, in our opinion, all adjustments (which include only normal recurring accruals) necessary to fairly present the financial position and results of operations have been made for the periods presented. The results of operations of any interim period are not necessarily indicative of the results of operations for the full year.

The financial statements included herein should be read in conjunction with the financial statements and notes thereto included in our 2008 Form 10-K.

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

($ in thousands, except share and per share data)


	September 30, 2008			December 31, 2007
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	17,909		$	6,680
Restricted cash		559			1,236
Accounts receivable — trade, net		8,932			15,557
Other receivables		4,301			1,480
Other current assets		8,382			3,962
Inventory		13,855			6,622
Current derivative financial instrument assets		16,958			8,008

Total current assets		70,896			43,545
Oil and gas properties under full cost method of accounting, net		487,367			300,953
Pipeline assets, net		307,418			294,526
Other property and equipment, net		24,141			21,505
Other assets, net		15,207			8,541
Long-term derivative financial instrument assets		11,956			3,467

Total assets	$	916,985		$	672,537


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	38,011		$	31,202
Revenue payable		1,202			7,725
Accrued expenses		5,274			8,387
Current portion of notes payable		46,525			666
Current derivative financial instrument liabilities		3,211			8,108

Total current liabilities		94,223			56,088
Non-current liabilities:
Long-term derivative financial instrument liabilities		15,334			6,311
Asset retirement obligations		5,760			2,938
Notes payable		343,152			233,046
Minority interests		290,327			297,385
Commitments and contingencies
Stockholders’ 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 — 32,309,040 and 23,553,230 at September 30, 2008 and December 31, 2007, respectively, outstanding — 31,685,600 and 22,471,355 at September 30, 2008 and December 31, 2007, respectively		34			24
Additional paid-in capital		298,392			211,852
Accumulated deficit		(130,237	)		(135,107	)

Total stockholders’ equity		168,189			76,769

Total liabilities and stockholders’ equity	$	916,985		$	672,537

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

F-1

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

($ in thousands, except share and per share data)

(Unaudited)


	Three months ended September 30,						Nine months ended September 30,
	2008			2007			2008			2007
				(Restated)						(Restated)
Revenue:
Oil and gas sales	$	49,531		$	23,852		$	136,989		$	76,396
Gas pipeline revenue		7,512			1,788			21,561			5,122

Total revenues		57,043			25,640			158,550			81,518
Costs and expenses:
Oil and gas production		9,963			9,206			33,000			29,095
Pipeline operating		7,737			4,966			22,859			14,157
General and administrative expenses		4,638			5,278			16,579			14,249
Depreciation, depletion and amortization		18,353			9,879			49,686			27,315
Misappropriation of funds		—			500			—			1,500

Total costs and expenses		40,691			29,829			122,124			86,316

Operating income (loss)		16,352			(4,189	)		36,426			(4,798	)
Other income (expense):
Gain (loss) from derivative financial instruments		145,132			13,388			(4,482	)		8,232
Gain (loss) on sale of assets		7			50			7			(141	)
Other income (expense), net		52			(5	)		174			(37	)
Interest expense		(7,273	)		(8,109	)		(17,451	)		(24,085	)
Interest income		86			102			207			382

Total other income (expense)		138,004			5,426			(21,545	)		(15,649	)

Income (loss) before income taxes and minority interests		154,356			1,237			14,881			(20,447	)
Income tax expense		—			—			—			—

Net income (loss) before minority interest		154,356			1,237			14,881			(20,447	)
Minority interest		(66,505	)		(745	)		(10,011	)		(2,501	)

Net income (loss)	$	87,851		$	492		$	4,870		$	(22,948	)

Net income (loss) per common share:
Basic	$	2.83		$	0.02		$	0.19		$	(1.03	)
Diluted	$	2.80		$	0.02		$	0.19		$	(1.03	)
Weighted average shares outstanding:
Basic		31,096,433			22,447,022			25,527,004			22,353,917

Diluted		31,397,737			22,787,198			25,627,438			22,353,917

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

F-2

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

($ in thousands)

(Unaudited)


	Nine Months Ended September 30,
	2008			2007
				(Restated)
Cash flows from operating activities:
Net income (loss)	$	4,870		$	(22,948	)
Adjustments to reconcile net income (loss) to cash provided by (used in) operations:
Depreciation, depletion and amortization		49,686			27,315
Stock-based compensation		1,748			4,557
Stock-based compensation — minority interests		359			758
Amortization of deferred loan costs		1,578			1,629
Change in fair value of derivative financial instruments		(13,313	)		(3,069	)
Bad debt expense		96			22
Minority interest		10,011			2,501
Loss (gain) on disposal of property and equipment		(7	)		141
Change in assets and liabilities:
Accounts receivable		6,529			(585	)
Other receivables		(2,821	)		(1,079	)
Other current assets		(1,351	)		(830	)
Other assets		1,453			(1,157	)
Accounts payable		6,792			20,643
Revenue payable		(6,523	)		1,486
Accrued expenses		(3,160	)		2,314
Other long-term liabilities		472			122
Other		(255	)		(68	)

Net cash provided by operating activities		56,164			31,752

Cash flows from investing activities:
Restricted cash		677			(86	)
Acquisition of business — PetroEdge		(141,777	)		—
Equipment, development, leasehold and pipeline		(120,813	)		(103,325	)

Net cash used in investing activities		(261,913	)		(103,411	)

Cash flows from financing activities:
Proceeds from bank borrowings		84,000			—
Repayments of note borrowings		(50,035	)		(393	)
Proceeds from revolver note		122,000			55,000
Distributions to unitholders		(20,770	)		(3,879	)
Refinancing costs		(3,018	)		(1,387	)
Proceeds from issuance of common stock		84,801			—

Net cash provided by financing activities		216,978			49,341

Net increase (decrease) in cash		11,229			(22,318	)
Cash and cash equivalents beginning of period		6,680			33,820

Cash and cash equivalents end of period	$	17,909		$	11,502

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

F-3

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2008

(Unaudited)

Note 1 — Basis of Presentation

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

We are an integrated independent energy company involved in the acquisition, development, gathering, transportation, exploration, and production of oil and natural gas. Our principal operations and producing properties are located in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma and the Appalachian Basin in West Virginia, Pennsylvania and New York. We conduct substantially all of our production operations through Quest Energy Partners, L.P. (Nasdaq: QELP) (“Quest Energy” or “QELP”) and our natural gas transportation and gathering operations through Quest Midstream Partners, L.P. (“Quest Midstream” or “QMLP”). Our Appalachian Basin operations are primarily focused on the development of the Marcellus Shale through Quest Eastern Resource LLC, a wholly-owned subsidiary of QRCP (“Quest Eastern”), and Quest Energy. Our Cherokee Basin operations are currently focused on developing coal bed methane or CBM gas production through Quest Energy, which is served by a gas gathering pipeline network owned by Quest Midstream. Quest Midstream also owns an interstate natural gas transmission pipeline.

We conduct our business through two reportable business segments. These segments and the activities performed to provide services to our customers and create value for our stockholders are as follows:

	•		Oil and gas production, and

	•		Natural gas pipelines, including transporting, gathering, treating and processing natural gas.

Our unaudited consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain information and disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) have been condensed or omitted. We believe that the presentations and disclosures herein are adequate to make the information not misleading. The unaudited consolidated financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2008 that was filed on June 3, 2009 and amended on July 28, 2009 (the “2008 Form 10-K”).

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.

Misappropriation, Reaudit and Restatement

Investigation — On August 22, 2008, in connection with an inquiry from the Oklahoma Department of Securities, the boards of directors of QRCP, Quest Energy GP, LLC (“Quest Energy GP”), the general partner of QELP, and Quest Midstream GP, LLC (“Quest Midstream GP”), the general partner of QMLP, held a joint working session to address certain unauthorized transfers, repayments and re-transfers of funds (the “Transfers”) to entities controlled by their former chief executive officer, Mr. Jerry D. Cash. These transfers totaled approximately $10 million between 2005 and 2008.

A joint special committee comprised of one member designated by each of the boards of directors of QRCP, Quest Energy GP, and Quest Midstream GP, was immediately appointed to oversee an independent internal

F-4

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

investigation of the Transfers. In connection with this investigation, other errors were identified in prior year financial statements and management and the board of directors concluded that QRCP had material weaknesses in its internal control over financial reporting. As of December 31, 2008, these material weaknesses continued to exist.

Reaudit and Restatement — As reported on a Current Report on Form 8-K filed on January 2, 2009, on December 31, 2008, the board of directors of QRCP determined that the audited consolidated financial statements of QRCP as of and for the years ended December 31, 2007, 2006 and 2005 and QRCP’s unaudited consolidated financial statements as of and for the three months ended March 31, 2008 and as of and for the three and six months ended June 30, 2008 should no longer be relied upon.

In October 2008, QRCP’s audit committee engaged a new independent registered public accounting firm to audit QRCP’s consolidated financial statements for 2008 and, in January 2009, engaged them to reaudit QRCP’s consolidated financial statements as of December 31, 2007 and 2006 and for the years ended December 31, 2007, 2006 and 2005.

The consolidated financial statements to which these notes apply include restated financial statements for QRCP for the three and nine month periods ended September 30, 2007 (see Note 11 - Restatement). The consolidated balance sheet as of December 31, 2007 was restated in our 2008 Form 10–K.

Going Concern

The accompanying consolidated financial statements have been prepared assuming that QRCP 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. QRCP has incurred significant losses from 2003 through 2008, 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 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 and Quest Midstream for revenue and cash flow. Quest Midstream did not pay any distributions on any of its units for the third or fourth quarters of 2008, and Quest Energy suspended its distributions on its subordinated units for 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 in 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, and drilling commitments and payments to landowners necessary to maintain its oil and gas leases.

Recombination — Given the liquidity challenges facing QRCP, Quest Midstream and Quest Energy, each entity has undertaken a strategic review of its assets and 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 the three companies would recombine. The recombination would be effected by forming a new, yet to be named, publicly-traded corporation (“New Quest”) that, through a series of mergers and entity conversions, would wholly-own all three entities (the “Recombination”). The Merger Agreement follows the execution of a non-binding letter of intent by the three Quest entities that was publicly announced on June 3, 2009.

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

F-5

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Cash and Capital Resources — As of September 30, 2008, QRCP, excluding QELP and QMLP, had cash and cash equivalents of $4.3 million and no ability to borrow under the terms of its existing credit agreement. QRCP currently estimates that it will not have enough cash to pay its expenses, including capital expenditures and debt service requirements, after August 31, 2009. This date could be extended if QRCP is able to restructure its debt obligations, issue equity securities and/or sell additional assets. The accompanying financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Recent Accounting Pronouncements

In February 2008, the Financial Accounting Standards Board (“the FASB”) issued Staff Position FAS 157-2, Effective Date of FASB Statement No. 157 (“FSP 157-2”). FSP 157-2 delays the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those recognized or disclosed at fair value in the financial statements on a recurring basis, at least annually (January 1, 2009 for QRCP). The adoption of FSP 157-2 is not expected to have a material impact on our financial condition, operations or cash flows.

Effective upon issuance, the FASB issued Staff Position FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active, (“FSP 157-3”) in October 2008. FSP 157-3 clarifies the application of SFAS No. 157 in determining the fair value of a financial asset when the market for that financial asset is not active. As of September 30, 2008, we had no financial assets with a market that was not active. Accordingly, FSP 157-3 is not expected to have an impact on our consolidated financial statements.

In April 2007, the FASB issued FSP FIN 39-1, Amendment of FASB Interpretation No. 39 (“FSP FIN 39-1”), which amends FIN 39, Offsetting of Amounts Related to Certain Contracts. FSP FIN 39-1 permits netting fair values of derivative assets and liabilities for financial reporting purposes, if such assets and liabilities are with the same counterparty and subject to a master netting arrangement. FSP FIN 39-1 also requires that the net presentation of derivative assets and liabilities include amounts attributable to the fair value of the right to reclaim collateral assets held by counterparties or the obligation to return cash collateral received from counterparties. We did not elect to adopt FSP FIN 39-1.

In June 2008, the FASB issued FSP EITF No. 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (“FSP EITF 03-6-1”). FSP EITF 03-6-1 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and are therefore required to be included in the earnings allocation in calculating earnings per share under the two-class method described in SFAS No. 128, Earnings per Share. FSP EITF 03-6-1 requires companies to treat unvested share-based payment awards that have non-forfeitable rights to dividend or dividend equivalents as a separate class of securities in calculating earnings per share. FSP EITF 03-6-1 is effective for fiscal years beginning after December 15, 2008 (January 1, 2009 for QRCP). We do not expect FSP EITF 03-6-1 to have an effect on the presentation of earnings per share.

In December 2007, FASB issued SFAS No. 141(R), Business Combinations (SFAS 141(R)) which replaces SFAS No. 141. SFAS No. 141(R) establishes principles and requirements for how the acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree. In addition, SFAS 141(R) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase. SFAS 141(R) also establishes disclosure requirements to enable users to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective as of the beginning of an entity’s fiscal year that begins after December 15, 2008 (January 1, 2009 for QRCP), with early adoption prohibited. The adoption of SFAS 141(R) did not have a material affect on our results of operations, cash flows or financial position as of January 1, 2009, the date of adoption.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assts and Financial Liabilities (“SFAS 159”), including an amendment to SFAS No. 115. Under SFAS 159, entities may elect to measure specified financial instruments and warranty and insurance contracts at fair value on a contract-contract basis, with changes in fair value recognized in earnings each reporting period. The election, called the fair value option, enables entities to achieve an offset accounting effect for changes in fair value of certain related assets and liabilities without having to apply complex hedge accounting provisions. SFAS 159 is expected to expand the use of fair value measurement consistent with the FASB’s long-term objectives for financial instruments. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We have assessed the provisions of SFAS 159 and we have elected not to apply fair value accounting to our existing eligible financial instruments. As a result, the adoption of SFAS 159 did not have an impact on our financial statements.

F-6

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

parent retains its controlling financial interest in its subsidiary. In addition, SFAS No. 160 establishes principles for valuation of retained non-controlling equity investments and measurement of gain or loss when a subsidiary is deconsolidated. SFAS No. 160 also establishes disclosure requirements to clearly identify and distinguish between interests of the parent and the interests of the non-controlling owners. SFAS No. 160 is effective for fiscal years and interim periods beginning after December 15, 2008 (January 1, 2009 for QRCP), with early adoption prohibited. Under SFAS No. 160, QRCP will be required to classify the minority interest liability reflected in the accompanying condensed consolidated balance sheet as a component of stockholders’ equity and will be required to present net income attributable to QRCP and the minority partners’ ownership interest separately on the consolidated statement of operations. We are currently assessing any other impact this standard will have on our results of operations, cash flows and financial position.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 133. This statement does not change the accounting for derivatives but will require enhanced disclosures about derivative strategies and accounting practices. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008, and we will comply with any necessary disclosure requirements beginning with the interim financial statements for the three months ended March 31, 2009.

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

Note 2 — Acquisitions and Divestitures

Acquisitions

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. The assets acquired were approximately 78,000 net acres of oil and natural gas producing properties in the Appalachian Basin with estimated net proved reserves of 99.6 Bcfe as of May 1, 2008 and net production of approximately 3.3 million cubic feet equivalent per day (“Mmcfe/d”). The transaction was recorded within QRCP’s oil and gas production segment and was funded using the proceeds from QRCP’s July 8, 2008 public offering of 8,800,000 shares of common stock and borrowings under QELP’s revolving credit facility and the proceeds of a $45 million, six-month term loan entered into by QELP.

The purchase price was allocated to assets acquired and liabilities assumed based on estimated fair values of the respective assets and liabilities at the time of closing. The following table summarizes the allocation of the purchase price (in thousands):

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Current assets	$	3,069
Oil and gas properties		142,618	(a)
Gathering facilities		1,820
Current liabilities		(3,537	)
Asset retirement obligations		(2,193	)(a)

Purchase price	$	141,777


(a)		Net assets acquired by Quest Cherokee consisted of $73.4 million of proved oil and gas properties and $2.2 million of asset retirement obligations.

KPC Pipeline — On November 1, 2007, Quest Midstream completed the purchase of an interstate pipeline running from Oklahoma to Missouri (the KPC Pipeline) for approximately $133.7 million, including transaction costs. The acquisition expanded Quest Midstream’s pipeline operations and was recorded in QRCP’s natural gas pipelines segment. The KPC Pipeline is a 1,120 mile interstate gas pipeline, which transports natural gas from Oklahoma and western Kansas to the metropolitan Wichita and Kansas City markets and is one of only three pipeline systems capable of delivering gas into the Kansas City metropolitan market. The KPC system includes three compressor stations with a total of 14,680 horsepower and has a capacity of approximately 160 Mmcf/d. The KPC Pipeline has supply interconnections with pipelines owned and/or operated by Enogex, Inc., Panhandle Eastern Pipeline Company and ANR Pipeline Company, allowing Quest Midstream to transport natural gas sourced from the Anadarko and Arkoma basins, as well as the western Kansas and Oklahoma panhandle producing regions. The acquisition was funded through the issuance of 3,750,000 common units of Quest Midstream for $20.00 per common unit and borrowings of $58 million under Quest Midstream’s credit facility.

The total cost of the acquisition was allocated to the assets acquired and liabilities assumed based on their estimated fair values on the acquisition date. The preliminary allocation was recorded during 2007 before valuation work was completed on contract-based intangibles. After completing valuation work on the acquired intangibles, a final purchase price allocation was recorded in 2008. The following table summarizes the allocation of the purchase price (in thousands):


Pipeline assets	$	124,936
Contract-related intangible assets		9,934
Liabilities assumed		(1,145	)

Purchase price	$	133,725

Pro Forma Summary Data related to acquisitions (unaudited)

The following unaudited pro forma information summarizes the results of operations for the three month and nine month periods ended September 30, 2008 and 2007, as if the PetroEdge and the KPC Pipeline acquisitions had occurred at the beginning of the period (in thousands):


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2008		2007			2008			2007
Pro forma revenue	$	57,043	$	28,677		$	165,100		$	90,629
Pro forma net income (loss)	$	87,851	$	(3,623	)	$	(1,971	)	$	(35,294	)
Pro forma net income (loss) per share — basic	$	2.78	$	(0.12	)	$	(0.06	)	$	(1.14	)
Pro forma net income (loss) per share — diluted	$	2.78	$	(0.12	)	$	(0.06	)	$	(1.14	)

The pro forma information does not reflect any cost savings or other synergies anticipated as a result of the acquisitions or any future acquisition-related expenses. The pro forma adjustments are based on estimates and assumptions. Management believes the estimates and assumptions are reasonable, and that the significant effects of the transactions are properly reflected.

The pro forma information is a result of combining the income statement of QRCP with the pre-acquisition results of KPC and PetroEdge adjusted for 1) recording pro forma interest expense on debt incurred to acquire KPC and PetroEdge; 2) DD&A expense calculated based on the adjusted basis of the properties and intangibles acquired using the purchase method of accounting; and 3) any related income tax effects of

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these adjustments based on the applicable statutory tax rates. The 11 day period, in which we did not own PetroEdge, for the three months ended September 30, 2008 was not deemed material for proforma disclosure and therefore proforma amounts equal actual amounts.

Searight — Quest Energy purchased certain oil producing properties in Seminole County, Oklahoma from a private company for $9.5 million in a transaction that closed in early February 2008. In addition, Quest Energy entered into crude oil swaps for approximately 80% of the estimated net production from the property’s proved developed producing reserves at WTI-NYMEX prices per barrel of oil of approximately $96.00 in 2008, $90.00 in 2009, and $87.50 for 2010. The acquisition was financed with borrowings under Quest Energy’s credit facility.

Divestitures

On June 4, 2008, we acquired the right to develop, and the option to purchase, certain drilling and other rights in and below the Marcellus Shale covering approximately 28,700 net acres in Potter County, Pennsylvania for $4.0 million. On November 26, 2008, we divested of these rights to a private party for approximately $3.2 million.

On October 30, 2008, we divested of approximately 22,600 net undeveloped acres and one well in Somerset County, Pennsylvania to a private party for approximately $6.8 million.

On November 5, 2008, we divested of 50% of our interest in approximately 4,500 net undeveloped acres in Wetzel County, West Virginia to a private party for $6.1 million. Included in the sale were three wells in various stages of completion and existing pipelines and facilities. QRCP will continue to operate the property included in this joint venture. All future development costs will be split equally between us and the private party.

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

The proceeds from these divestitures were credited to the full cost pool.

Note 3 — Long-Term Debt

The following is a summary of QRCP’s long-term debt at September 30, 2008 and December 31, 2007 (in thousands):


	September 30,		December 31,
	2008		2007
Borrowings under bank senior credit facilities
QRCP	$	33,500	$	44,000
Quest Energy:
Revolving credit facility		183,000		94,000
Term loan		45,000		—
Quest Midstream		128,000		95,000
Notes payable to banks and finance companies, secured by equipment and vehicles, due in installments through October 2013 with interest ranging from 1.9% to 8.9% per annum		177		712

Total debt		389,677		233,712
Less current maturities included in current liabilities		46,525		666

Total long-term debt	$	343,152	$	233,046

Credit Facilities

QRCP. On July 11, 2008, QRCP and Royal Bank of Canada (“RBC”) entered into an Amended and Restated Credit Agreement to convert QRCP’s then-existing $50 million revolving credit facility to a $35 million term loan, due and maturing on July 11, 2010 (the “Original Term Loan”). Thereafter, the parties entered into the following amendments to the credit agreement (collectively, with all amendments, the “Credit Agreement”):

	•		On October 24, 2008, QRCP and RBC entered into a First Amendment to Amended and Restated Credit Agreement, which, among other things, added a $6 million term loan (the “Additional Term Loan”) to the $35 million term loan under the Credit Agreement.

	•		On November 4, 2008, QRCP entered into a Second Amendment to Amended and Restated Credit Agreement (the “Second Amendment to Credit Agreement”) which clarified that the $6 million commitment under the Additional Term Loan would be reduced dollar for dollar to the extent QRCP retained net cash proceeds from dispositions in accordance with the terms of the Credit Agreement and

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			it also amended and/or waived certain of the representations and covenants contained in the Credit Agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result of (1) the Transfers and (2) not timely settling certain intercompany accounts among QRCP, Quest Energy and Quest Midstream.

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

	•		On May 29, 2009, QRCP entered into a Fourth Amendment to Amended and Restated Credit Agreement that, among other things, waived certain events of default related to the financial covenants and collateral requirements under the Credit Agreement, extended certain financial reporting deadlines and permitted the settlement agreements with Mr. Cash discussed elsewhere herein and in QRCP’s 2008 Form 10-K.

	•		On June 30, 2009, QRCP entered into a Fifth Amendment to Amended and Restated Credit Agreement (the “Fifth Amendment to Credit Agreement”) that, among other things, amended and/or waived certain of the representations and covenants contained in the Credit Agreement.

Interest Rate. Interest accrues on the Original Term Loan, and accrued on the Additional Term Loan, at either LIBOR plus 10% (with a LIBOR floor of 3.5%) or the base rate plus 9.0%. The base rate varies daily and is generally the higher of the federal funds rate plus 0.50%, RBC’s prime rate or LIBOR plus 2.5% (but without the LIBOR floor). The Original Term Loan may be prepaid without any premium or penalty, at any time.

Payments. The Original Term Loan is payable in quarterly installments of $1.5 million on the last business day of each March, June, September and December commencing on September 30, 2008, with the remaining principal amount being payable in full on July 11, 2010. As discussed in the next paragraph, QRCP prepaid all of the quarterly principal payment requirements through June 30, 2009 and therefore has no quarterly principal payments due until September 30, 2009. If the outstanding amount of the Original Term Loan is at any time more than 50% of the market value of QRCP’s partnership interests in Quest Midstream and Quest Energy pledged to secure the loan plus the value of QRCP’s oil and gas properties (as defined in the Credit Agreement) pledged to secure the loan, QRCP will be required to either repay the term loan by the amount of such excess or pledge additional assets to secure the term loan.

Restrictions on Use of Proceeds from Asset Sales. As part of the Second Amendment to Credit Agreement, QRCP agreed to apply any net cash proceeds from a sale of assets or a sale of equity interests in certain subsidiaries as follows: first, to repay any amounts borrowed under the Additional Term Loan (this was done on October 30, 2008); second, to prepay the next three quarterly principal payments due on the Original Term Loan on the last business day of December 2008, March 2009 and June 2009 (this was done in October and November 2008); third, subject to certain conditions being met and the net cash proceeds being received by January 31, 2009, up to $20 million for QRCP’s own use for working capital and to make capital expenditures for the development of its oil and gas properties; and fourth, any excess net cash proceeds to repay the Original Term Loan. The Third Amendment to Credit Agreement provided that in connection with the sale of QRCP’s Lycoming County, Pennsylvania acreage in February 2009, QRCP could retain all of the net proceeds from such sale in excess of $750,000. QRCP will be required to apply all of the net cash proceeds from the issuance of any debt and 50% of the net cash proceeds from the sale of any equity securities to first repay the Original Term Loan and then to QRCP.

Security Interest. The Credit Agreement is secured by a first priority lien on QRCP’s ownership interests in Quest Energy and Quest Midstream and their general partners 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 each of Quest Midstream GP, Quest Midstream and each of their subsidiaries and Quest Energy GP, Quest Energy and each of their subsidiaries (collectively the “Excluded MLP Entities”) are not pledged to secure the Credit Agreement.

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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, will be secured pari passu by the liens granted under the loan documents.

Debt Balance at September 30, 2008. At September 30, 2008, $33.5 million was outstanding under the Original Term Loan and $0 million was outstanding under the Additional Term Loan because the additional term loan was funded after that date. The Additional Term Loan was repaid on October 30, 2008.

Representations, Warranties and Covenants. QRCP and its subsidiaries (excluding the Excluded MLP Entities) are required to make certain representations and warranties that are customary for a credit agreement of this type. The agreement also contains affirmative and negative covenants that are customary for credit agreements of this type.

The Fifth Amendment to Credit Agreement, among other things, amended and/or waived certain of the representations and covenants contained in the Credit Agreement, in order to, among other things, (i) defer until August 15, 2009 our obligation to deliver to RBC unaudited stand alone balance sheets and related statements of income and cash flows for the fiscal quarters ending September 30, 2008 and March 31, 2009; (ii) waive financial covenant (namely the interest coverage ratio and leverage ratio) events of default for the fiscal quarter ended June 30, 2009; (iii) waive any mandatory prepayment due to any collateral deficiency during the fiscal quarter ended September 30, 2009; and (iv) defer until September 30, 2009 the interest payment due on June 30, 2009, which amount was represented by a promissory note bearing interest at the Base Rate (as defined in the Credit Agreement) with a maturity date of September 30, 2009.

The Credit Agreement’s financial covenants prohibit QRCP and any of its subsidiaries (excluding the Excluded MLP Entities) from:

•		permitting the interest coverage ratio (ratio of consolidated EBITDA (or consolidated annualized EBITDA for periods ending on or before December 31, 2008) to consolidated interest charges (or consolidated annualized interest charges for periods ending on or before December 31, 2008)) at any fiscal quarter-end, commencing with the quarter-ended September 30, 2008, to be less than 2.5 to 1.0 (calculated based on the most recently delivered compliance certificate); and

•		permitting the leverage ratio (ratio of consolidated funded debt to consolidated EBITDA (or consolidated annualized EBITDA for periods ending on or before December 31, 2008)) at any fiscal quarter-end, commencing with the quarter-ended September 30, 2008, to be greater than 2.0 to 1.0 (calculated based on the most recently delivered compliance certificate).

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Amendment to Credit Agreement) and the related restructuring which were capped at $1,500,000 for purposes of this definition and (viii) other non-cash charges and expenses deducted in the determination of such consolidated net income, including, without limitation, non-cash charges and expenses relating to swap contracts or resulting from accounting convention changes, of QRCP and its subsidiaries (excluding the Excluded MLP Entities) on a consolidated basis, all determined in accordance with GAAP.

Consolidated annualized EBITDA means, for QRCP and its subsidiaries (excluding the Excluded MLP Entities) on a consolidated basis, (i) for the fiscal quarter ended September 30, 2008, consolidated EBITDA for the nine month period ended September 30, 2008 multiplied by 1.33, and (ii) for the fiscal quarter ended December 31, 2008, consolidated EBITDA for the twelve month period ended December 31, 2008.

Consolidated interest charges are defined to mean for QRCP and its subsidiaries (excluding the Excluded MLP Entities) on a consolidated basis, the sum of (i) all interest, premium payments, fees, charges and related expenses of QRCP and its subsidiaries (excluding the Excluded MLP Entities) in connection with indebtedness (net of interest rate swap contract settlements) (including capitalized interest), in each case to the extent treated as interest in accordance with GAAP, and (ii) the portion of rent expense of QRCP and its subsidiaries (excluding the Excluded MLP Entities) with respect to any period under capital leases that is treated as interest in accordance with GAAP.

Consolidated annualized interest charges means, for QRCP and its subsidiaries (excluding the Excluded MLP Entities) on a consolidated basis, (i) for the fiscal quarter ended September 30, 2008, consolidated interest charges for the nine month period ended September 30, 2008 multiplied by 1.33, and (ii) for the fiscal quarter ended December 31, 2008, consolidated interest charges for the twelve month period ended December 31, 2008.

Consolidated funded debt means, for QRCP and its subsidiaries (excluding the Excluded MLP Entities) on a consolidated basis, the sum of (i) the outstanding principal amount of all obligations and liabilities, whether current or long-term, for borrowed money (including obligations under the Credit Agreement), (ii) all reimbursement obligations relating to letters of credit that have been drawn and remain unreimbursed, (iii) attributable indebtedness pertaining to capital leases, (iv) attributable indebtedness pertaining to synthetic lease obligations, and (v) without duplication, all guaranty obligations with respect to indebtedness of the type specified in subsections (i) through (iv) above.

Events of Default. Events of default under the Credit Agreement are customary for transactions of this type and include, without limitation, non-payment of principal when due, non-payment of interest, fees and other amounts for a period of three business days after the due date, failure to perform or observe covenants and agreements (subject to a 30-day cure period in certain cases), representations and warranties not being correct in any material respect when made, cross-defaults to other material indebtedness, certain acts of bankruptcy or insolvency, and change of control. Under the Credit Agreement, a change of control means the acquisition by any person, or two or more persons acting in concert, of beneficial ownership (within the meaning of Rule 13d-3 of the SEC under the Securities Exchange Act of 1934) of 50% or more of QRCP’s outstanding shares of voting stock; provided, however, that a merger of QRCP into another entity in which the other entity is the survivor will not be deemed a change of control if QRCP’s stockholders of record as constituted immediately prior to such acquisition hold more than 50% of the outstanding shares of voting stock of the surviving entity.

Waivers. QRCP was in compliance with all of its financial covenants as of September 30, 2008. However, QRCP was not in compliance with all of its financial covenants as of December 31, 2008, March 31, 2009 or June 30, 2009 and QRCP does not anticipate that it will be in compliance at any time in the foreseeable future. On May 29, 2009, QRCP obtained a waiver of these defaults from its lender for the quarters ended December 31, 2008 and March 31, 2009 and on June 30, 2009, QRCP obtained a waiver of these defaults from its lender for the fiscal quarter ended June 30, 2009.

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Quest Energy.

A. Quest Cherokee Credit Agreement.

On November 15, 2007, Quest Energy, as a guarantor, entered into an Amended and Restated Credit Agreement (the “Original Cherokee Credit Agreement”) with QRCP, as the initial co-borrower, Quest Cherokee, as the borrower, RBC, as administrative agent and collateral agent, KeyBank National Association, as documentation agent and the lenders party thereto. In connection with the closing of the initial public offering and the application of the net proceeds thereof, QRCP was released as a borrower under the Original Cherokee Credit Agreement. Thereafter, the parties entered into the following amendments to the Original Cherokee Credit Agreement (collectively, with all amendments, the “Quest Cherokee Credit Agreement”):

	•		On April 15, 2008, Quest Energy and Quest Cherokee entered into a First Amendment to Amended and Restated Credit Agreement that, among other things, amended the interest rate and maturity date pursuant to the “market flex” rights contained in the commitment papers related to the Quest Cherokee Credit Agreement.

	•		On October 28, 2008, Quest Energy and Quest Cherokee entered into a Second Amendment to Amended and Restated Credit Agreement to amend and/or waive certain of the representations and covenants contained in the Quest Cherokee Credit Agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result of (1) the Transfers and (2) not timely settling certain intercompany accounts among QRCP, Quest Energy and Quest Midstream.

	•		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. (“BP”) or any of its affiliates to be secured by the liens under the credit agreement on a pari passu basis with the obligations under the credit agreement.

	•		On June 30, 2009, Quest Energy and Quest Cherokee entered into a Fourth Amendment to Amended and Restated Credit Agreement that deferred until August 15, 2009, Quest Energy’s obligation to deliver to RBC unaudited consolidated balance sheets and related statements of income and cash flows for the fiscal quarters ending September 30, 2008 and March 31, 2009.

Borrowing Base. The credit facility under the Quest Cherokee Credit Agreement consists of a three-year $250 million revolving credit facility. Availability under the revolving credit facility is tied to a borrowing base that will be redetermined by the lenders every six months taking into account the value of Quest Cherokee’s proved reserves. In addition, Quest Cherokee and RBC each have the right to initiate a redetermination of the borrowing base between each six-month redetermination. As of September 30, 2008, the borrowing base was $190.0 million, and the amount borrowed under the Quest Cherokee Credit Agreement was $183.0 million. We had $6.0 million available for borrowing, with the remaining $1.0 million supporting letters of credit issued under the Quest Cherokee Credit Agreement.

In July 2009, the borrowing base under the Quest Cherokee Credit Agreement was reduced from $190 million to $160 million, which, following the payment discussed below, resulted in the outstanding borrowings under the Quest Cherokee Credit Agreement exceeding the new borrowing base by $14 million (the “Borrowing Base Deficiency”). In anticipation of the reduction in the borrowing base, Quest Energy amended or exited certain of its above market natural gas price derivative contracts and, in return, received approximately $26 million. The strike prices on the derivative contracts that Quest Energy did not exit were set to market prices at the time. At the same time,

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Quest Energy entered into new natural gas price derivative contracts to increase the total amount of its future proved developed natural gas production hedged to approximately 85% through 2013. On June 30, 2009, using these proceeds, Quest Energy made a principal payment of $15 million on the Quest Cherokee Credit Agreement. On July 8, 2009, Quest Energy repaid the Borrowing Base Deficiency.

Commitment Fee. Quest Cherokee will pay a quarterly revolving commitment fee equal to 0.30% to 0.50% (depending on the utilization percentage) of the actual daily amount by which the lesser of the aggregate revolving commitment and the borrowing base exceeds the sum of the outstanding balance of borrowings and letters of credit under the revolving credit facility.

Interest Rate. Until the Second Lien Loan Agreement is paid in full, interest will accrue at either LIBOR plus 4.0% or the base rate plus 3.0%. After the Second Lien Loan Agreement is paid in full, interest will accrue at either LIBOR plus a margin ranging from 2.75% to 3.375% (depending on the utilization percentage) or the base rate plus a margin ranging from 1.75% to 2.375% (depending on the utilization percentage). The base rate varies daily and is generally the higher of the federal funds rate plus 0.50%, RBC’s prime rate or LIBOR plus 1.25%.

B. Second Lien Loan Agreement.

On July 11, 2008, concurrent with the PetroEdge acquisition, Quest Energy and Quest Cherokee entered into a Second Lien Senior Term Loan Agreement (the “Second Lien Loan Agreement,” together with the Quest Cherokee Credit Agreement, the “Quest Cherokee Agreements”) for a six-month, $45 million term loan. Thereafter, the parties entered into the following amendments to the Second Lien Loan Agreement:

•		On October 28, 2008, Quest Energy and Quest Cherokee entered into a First Amendment to Second Lien Senior Term Loan Agreement (the “First Amendment to Second Lien Loan Agreement”) to, among other things, extend the maturity date to September 30, 2009 and to amend and/or waive certain of the representations and covenants contained in the Second Lien Loan Agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result or (1) the Transfers and (2) not timely settling certain intercompany accounts among QRCP, Quest Energy and Quest Midstream.

•		On June 30, 2009, Quest Energy and Quest Cherokee entered into a Second Amendment to Second Lien Senior Term Loan Agreement that amended a covenant in order to defer until August 15, 2009, Quest Energy’s obligation to deliver to RBC unaudited consolidated balance sheets and related statements of income and cash flows for the fiscal quarters ending September 30, 2008 and March 31, 2009.

Payments. The First Amendment to Second Lien Loan Agreement requires Quest Cherokee to make repayments of principal in quarterly installments of $3.8 million while amounts borrowed under the Second Lien Loan Agreement are outstanding. As of September 30, 2008, $45.0 million was outstanding under the Second Lien Loan Agreement. Quest Energy has made the quarterly principal payments subsequent to that date and management believes that Quest Energy has sufficient capital resources to repay the $3.8 million principal payment due under the Second Lien Loan Agreement on August 15, 2009. Management is currently pursuing various options to restructure or refinance the Second Lien Loan Agreement. There can be no assurance that such efforts will be successful or that the terms of any new or restructured indebtedness will be favorable to Quest Energy and Quest Cherokee.

Interest Rate. Interest accrues on the term loan at either LIBOR plus 9.0% (with a LIBOR floor of 3.5%) or the base rate plus 8.0%. The base rate varies daily and is generally the higher of the federal funds rate plus 0.5%, RBC’s prime rate or LIBOR plus 1.25%. Amounts due under the Second Lien Loan Agreement may be prepaid without any premium or penalty, at any time.

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Restrictions on Proceeds from Asset Sales. Subject to certain restrictions, Quest Cherokee and its subsidiaries are required to apply all net cash proceeds from sales of assets that yield gross proceeds of over $5 million to repay the amounts outstanding under the Second Lien Loan Agreement.

Covenants. Under the terms of the Second Lien Loan Agreement, Quest Energy is required by June 30, 2009 to (i) complete a private placement of its equity securities or debt, (ii) engage one or more investment banks reasonably satisfactory to RBC Capital Markets to publicly sell or privately place common equity securities or debt of Quest Energy, which offering must close prior to August 14, 2009 (the deadline for closing and funding the securities offering may be extended up until September 30, 2009) or (iii) engage RBC Capital Markets to arrange financing to refinance the term loan under the Second Lien Loan Agreement on the prevailing terms in the credit market. Prior to the June 30, 2009 deadline, Quest Energy engaged an investment bank reasonably satisfactory to RBC Capital Markets.

Further, so long as any amounts remain outstanding under the Second Lien Loan Agreement, Quest Energy and Quest Cherokee must be in compliance with a financial covenant that prohibits each of Quest Cherokee, Quest Energy or any of their respective subsidiaries from permitting Available Liquidity (as defined in the Quest Cherokee Agreements) to be less than $14 million at March 31, 2009 and to be less than $20 million at June 30, 2009.

C. General Provisions Applicable to Quest Cherokee Agreements.

Restrictions on Distributions and Capital Expenditures. The Quest Cherokee Agreements restrict the amount of quarterly distributions Quest Energy may declare and pay to its unitholders to not exceed $0.40 per common unit per quarter as long as any amounts remain outstanding under the Second Lien Loan Agreement. The $3.8 million quarterly principal payments discussed above must also be paid before any distributions may be paid and Quest Cherokee’s capital expenditures are limited to $30 million for 2009.

Security Interest. The Quest Cherokee Credit Agreement is secured by a first priority lien on substantially all of the assets of Quest Energy, Quest Cherokee and Quest Cherokee Oilfield Service, LLC (“QCOS”). The Second Lien Loan Agreement is secured by a second priority lien on substantially all of the assets of Quest Energy, Quest Cherokee and QCOS.

The Quest Cherokee Agreements provide that all obligations arising under the loan documents, including obligations under any hedging agreement entered into with lenders or their affiliates or BP, will be secured pari passu by the liens granted under the loan documents.

Representations, Warranties and Covenants. Quest Energy, Quest Cherokee, Quest Energy GP and their subsidiaries are required to make certain representations and warranties that are customary for credit agreements of these types. The Quest Cherokee Agreements also contain affirmative and negative covenants that are customary for credit agreements of these types.

The Quest Cherokee Agreements’ financial covenants prohibit Quest Energy, Quest Cherokee and any of their subsidiaries from:

•

permitting the ratio (calculated based on the most recently delivered compliance certificate) of Quest Energy’s consolidated current assets (including the unused availability under the revolving credit facility, but excluding non-cash assets under FAS No. 133) to consolidated current liabilities (excluding non-cash obligations under

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		FAS No. 133, asset and asset retirement obligations and current maturities of indebtedness under the Quest Cherokee Credit Agreement) at any fiscal quarter-end to be less than 1.0 to 1.0; provided, however, that current assets and current liabilities will exclude mark-to-market values of swap contracts, to the extent such values are included in current assets and current liabilities;

•		permitting the interest coverage ratio (calculated on the most recently delivered compliance certificate) of adjusted consolidated EBITDA to consolidated interest charges at any fiscal quarter-end to be less than 2.5 to 1.0 measured on a rolling four quarter basis; and

•		permitting the leverage ratio (calculated based on the most recently delivered compliance certificate) of consolidated funded debt to adjusted consolidated EBITDA at any fiscal quarter-end to be greater than 3.5 to 1.0 measured on a rolling four quarter basis.

The Second Lien Loan Agreement contains an additional financial covenant that prohibits Quest Energy, Quest Cherokee, and any of their subsidiaries from permitting the total reserve leverage ratio (ratio of total proved reserves to consolidated funded debt) at any fiscal quarter-end (calculated based on the most recently delivered compliance certificate) to be less than 1.5 to 1.0.

Adjusted consolidated EBITDA is defined in the Quest Cherokee Agreements to mean the sum of (i) consolidated EBITDA plus (ii) the distribution equivalent amount (for each fiscal quarter of Quest Energy, the amount of cash paid to the members of Quest Energy GP’s management group and non-management directors with respect to restricted common units, bonus units and/or phantom units of Quest Energy that are required under GAAP to be treated as compensation expense prior to vesting (and which, upon vesting, are treated as limited partner distributions under GAAP)).

Consolidated EBITDA is defined in the Quest Cherokee Agreements to mean for Quest Energy and its subsidiaries on a consolidated basis, an amount equal to the sum of (i) consolidated net income, (ii) consolidated interest charges, (iii) the amount of taxes, based on or measured by income, used or included in the determination of such consolidated net income, (iv) the amount of depreciation, depletion and amortization expense deducted in determining such consolidated net income, (v) acquisition costs required to be expensed under FAS No. 141(R), (vi) fees and expenses of the internal investigation relating to the Misappropriation Transaction (as defined in the First Amendment to Second Lien Loan Agreement) and the related restructuring (which shall be capped at $1,500,000 for purposes of this definition), and (vii) other non-cash charges and expenses, including, without limitation, non-cash charges and expenses relating to swap contracts or resulting from accounting convention changes, of Quest Energy and its subsidiaries on a consolidated basis, all determined in accordance with GAAP.

Consolidated interests charges is defined to mean for Quest Energy and its subsidiaries on a consolidated basis, the excess of (i) the sum of (a) all interest, premium payments, fees, charges and related expenses of Quest Energy and its subsidiaries in connection with indebtedness (net of interest rate swap contract settlements) (including capitalized interest), in each case to the extent treated as interest in accordance with GAAP, and (b) the portion of rent expense of Quest Energy and its subsidiaries with respect to such period under capital leases that is treated as interest in accordance with GAAP over (ii) all interest income for such period.

Consolidated funded debt is defined to mean for Quest Energy and its subsidiaries on a consolidated basis, the sum of (i) the outstanding principal amount of all obligations and liabilities, whether current or long-term, for borrowed money (including obligations under the Quest Cherokee Agreements, but excluding all reimbursement obligations relating to outstanding but undrawn letters of credit), (ii) attributable indebtedness pertaining to capital leases, (iii) attributable indebtedness pertaining to synthetic lease obligations, and (iv) without duplication, all guaranty obligations with respect to indebtedness of the type specified in subsections (i) through (iii) above.

Quest Energy was in compliance with all of its covenants as of September 30, 2008.

F-16

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

any material respect when made, certain acts of bankruptcy or insolvency, cross defaults to other material indebtedness, borrowing base deficiencies, and change of control. Under the Quest Cherokee Agreements, a change of control means (i) QRCP fails to own or to have voting control over at least 51% of the equity interest of Quest Energy GP, (ii) any person acquires beneficial ownership of 51% or more of the equity interest in Quest Energy; (iii) Quest Energy fails to own 100% of the equity interests in Quest Cherokee, or (iv) QRCP undergoes a change in control (the acquisition by a person, or two or more persons acting in concert, of beneficial ownership of 50% or more of QRCP’s outstanding shares of voting stock, except for a merger with and into another entity where the other entity is the survivor if QRCP’s stockholders of record immediately preceding the merger hold more than 50% of the outstanding shares of the surviving entity).

Quest Midstream. Quest Midstream and its wholly-owned subsidiary, Bluestem Pipeline, LLC (“Bluestem”), have a separate $135 million syndicated revolving credit facility. On November 1, 2007, Quest Midstream and Bluestem entered into an Amended and Restated Credit Agreement and First Amendment to Amended and Restated Credit Agreement (together, the “Quest Midstream Credit Agreement”) with RBC, as administrative agent and collateral agent, and the lenders party thereto. On October 28, 2008, Quest Midstream and Bluestem entered into a Second Amendment to the Quest Midstream Credit Agreement (the “Quest Midstream Second Amendment”). The Quest Midstream Credit Agreement together with the Quest Midstream Second Amendment are referred to collectively as the “Amended Quest Midstream Credit Agreement.” As of September 30, 2008, the amount borrowed under the Amended Quest Midstream Credit Agreement was $128.0 million.

The Quest Midstream Second Amendment, among other things, amended and/or waived certain of the representations and covenants contained in the Quest Midstream Credit Agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result of (1) the Transfers and (2) not timely settling certain intercompany accounts among QRCP, Quest Energy and Quest Midstream.

Quest Midstream and Bluestem may, from time to time, request an increase in the $135 million commitment by an amount in the aggregate not exceeding $75 million. However, the lenders are under no obligation to increase the revolving credit facility upon such request.

Commitment Fee. Quest Midstream and Bluestem will pay a quarterly revolving commitment fee equal to 0.375% to 0.50% (depending on the total leverage ratio) on the difference between $135 million and the outstanding balance of borrowings and letters of credit under the revolving credit facility.

Interest Rate. During the Transition Period (as defined in the Amended Quest Midstream Credit Agreement), interest accrued on the revolving credit facility at either LIBOR plus 4% or the base rate plus 3.0%. After the Transition Period ends, interest accrues at either LIBOR plus a margin ranging from 2.0% to 3.50% (depending on the total leverage ratio) or the base rate plus a margin ranging from 1.0% to 2.5% (depending on the total leverage ratio), at our option. The base rate is generally the higher of the federal funds rate plus 0.50%, RBC’s prime rate or LIBOR plus 1.25%. The Transition Period ended on March 31, 2009 when Quest Midstream’s audited financial statements for 2008 were delivered to RBC.

Required Prepayment. If the total leverage ratio is greater than 4.5 to 1.0 for any fiscal quarter ending on or after December 31, 2008, Quest Midstream and Bluestem must prepay the revolving loans in an amount equal to 75% of Excess Cash Flow (as defined in the Amended Quest Midstream Credit Agreement) for such fiscal quarter. Additionally, the lenders’ revolving commitment will be temporarily reduced dollar for dollar by the amount of any such prepayment. Once the total leverage ratio is less than 4.0 to 1.0 at the end of any fiscal quarter, any reductions in the revolving commitments will be reinstated and no further prepayments will be required.

Restrictions on Capital Expenditures and Distributions. The Amended Quest Midstream Credit Agreement places limitations on capital expenditures for each of Quest Midstream and Bluestem as follows: (i) $5 million for the fourth fiscal quarter of 2008; (ii) $7 million for the first fiscal quarter of 2009; (iii) $7 million for the second fiscal quarter of 2009; (iv) $3 million for the third fiscal quarter of 2009; and (v) $3 million for the fourth fiscal quarter of 2009.

F-17

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Amended Quest Midstream Credit Agreement restricts Quest Midstream’s ability to make distributions on its units unless the total leverage ratio is not greater than 4.0 to 1.0 after giving effect to the quarterly distribution.

Security Interest. The Amended Quest Midstream Credit Agreement is secured by a first priority lien on substantially all of the assets of Quest Midstream and Bluestem and their subsidiaries (including the KPC Pipeline).

The Amended Quest Midstream Credit Agreement provides that all obligations arising under the loan documents, including obligations under any hedging agreement entered into with lenders or their affiliates, will be secured pari passu by the liens granted under the loan documents.

Representations, Warranties and Covenants. Bluestem, Quest Midstream and their subsidiaries are required to make certain representations and warranties that are customary for credit agreements of this type. The Amended Quest Midstream Credit Agreement also contains affirmative and negative covenants that are customary for credit agreements of this type.

The Amended Quest Midstream Credit Agreement’s financial covenants prohibit Bluestem, Quest Midstream and any of their subsidiaries from:

•		permitting the interest coverage ratio (ratio of adjusted consolidated EBITDA to consolidated interest charges) on a rolling four quarter basis (calculated based on the most recently delivered compliance certificate), commencing with the fiscal quarter ending December 31, 2007, to be less than 2.50 to 1.00 for any fiscal quarter ending on or prior to December 31, 2008, increasing to 2.75 to 1.00 for each fiscal quarter end thereafter; and

•		permitting the total leverage ratio (ratio of adjusted consolidated funded debt to adjusted consolidated EBITDA) on a rolling four quarter basis (calculated based on the most recently delivered compliance certificate), commencing with the fiscal quarter ending December 31, 2007 and ending December 31, 2008, to be greater than 5.00 to 1.00, decreasing to 4.50 to 1.00 for each fiscal quarter end thereafter.

Adjusted consolidated EBITDA is defined in the Amended Quest Midstream Credit Agreement to mean the sum of (i) consolidated EBITDA plus (ii) the distribution equivalent amount (for each fiscal quarter of Quest Midstream, the amount of cash paid to the members of Quest Midstream GP’s management group and non-management directors with respect to restricted common units, bonus units and/or phantom units of Quest Midstream that are required under GAAP to be treated as compensation expense prior to vesting (and which, upon vesting, are treated as limited partner distributions under GAAP)).

Consolidated EBITDA is defined in the Amended Quest Midstream Credit Agreement for Quest Midstream and its subsidiaries on a consolidated basis, an amount equal to the sum of (i) consolidated net income, (ii) consolidated interest charges, (iii) the amount of taxes, based on or measured by income, used or included in the determination of consolidated net income, (iv) the amount of depreciation, depletion and amortization expense deducted in determining consolidated net income, (v) merger and acquisition costs required to be expensed under FAS No. 141(R), (vi) fees and expenses of the internal investigation relating to the Misappropriation Transaction (as defined in the Quest Midstream Second Amendment) and the related restructuring which are capped at $1,500,000 for purposes of the definition of Consolidated EBITDA and (vii) other non-cash charges and expenses, including, without limitation, non-cash charges and expenses related to swap contracts or resulting from accounting convention changes, of Quest Midstream and its subsidiaries on a consolidated basis, all determined in accordance with GAAP.

F-18

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Consolidated interest charges is defined to mean for Quest Midstream and its subsidiaries on a consolidated basis, the sum of (i) all interest, premium payments, fees, charges and related expenses of Quest Midstream and its subsidiaries in connection with indebtedness (net of interest rate swap contract settlements) (including capitalized interest and net of any write-off of debt issuance costs), in each case to the extent treated as interest in accordance with GAAP, and (ii) the portion of rent expense of Quest Midstream and its subsidiaries with respect to such period under capital leases that is treated as interest in accordance with GAAP.

Consolidated net income is defined to mean for Quest Midstream and its subsidiaries on a consolidated basis, the net income or net loss of Quest Midstream and its subsidiaries from continuing operations, excluding: (i) the income (or loss) of any entity other than a subsidiary, except to the extent that any such income has been actually received by Quest Midstream or such subsidiary in the form of cash dividends or similar cash distributions; (ii) extraordinary gains and losses; (iii) any gains or losses attributable to non-cash write-ups or write-downs of assets; (iv) proceeds of any insurance on property, plant or equipment other than business interruption insurance; (v) any gain or loss, net of taxes, on the sale, retirement or other disposition of assets; and (vi) the cumulative effect of a change in accounting principles.

Bluestem and Quest Midstream are required during each calendar year to have at least 15 consecutive days during which there are no revolving loans outstanding for the purpose of financing working capital or funding quarterly distributions of Quest Midstream.

Events of Default. Events of default under the Amended Quest Midstream Credit Agreement are customary for transactions of this type and include, without limitation, non-payment of principal when due, non-payment of interest, fees and other amounts for a period of three business days after the due date, failure to perform or observe covenants and agreements (subject to a 30-day cure period in certain cases), representations and warranties not being correct in any material respect when made, certain acts of bankruptcy or insolvency, cross defaults to other material indebtedness, and change of control. Under the Quest Midstream Credit Agreement a change of control means (i) QRCP fails to own or to have voting control over, at least 51% of the equity interest of Quest Midstream GP; (ii) any person acquires beneficial ownership of 51% or more of the equity interest in Quest Midstream; (iii) Quest Midstream fails to own 100% of the equity interests in Bluestem or (iv) QRCP undergoes a change in control (the acquisition by a person, or two or more persons acting in concert, of beneficial ownership of 50% or more of QRCP’s outstanding shares of voting stock, except for a merger with and into another entity where the other entity is the survivor if QRCP’s stockholders of record immediately preceding the merger hold more than 50% of the outstanding shares of the surviving entity).

Quest Midstream was in compliance with all of its covenants as of September 30, 2008.

Note 4 — Derivative Financial Instruments

We are exposed to commodity price and interest rate risk, and management believes it prudent to periodically reduce our exposure to cash-flow variability resulting from this volatility. Accordingly, we enter into certain derivative financial instruments in order to manage exposure to commodity price risk inherent in QELP’s oil and gas production operations. 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.

F-19

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

At September 30, 2008 and December 31, 2007, QELP was a party to derivative financial instruments in order to manage commodity price risk associated with a portion of our expected future sales of our oil and gas production. None of these derivative instruments have been designated as hedges. Accordingly, we record all derivative instruments in the consolidated balance sheet at fair value with realized and unrealized gains and losses recognized in other income (expense) as they occur.

Gains and losses associated with derivative financial instruments related to oil and gas production were as follows for the three month and nine month periods ended September 30, 2008 and 2007 (in thousands):


	Three months ended September 30,					Nine months ended September 30,
	2008			2007		2008			2007
				(Restated)					(Restated)
Realized gains (losses)	$	(7,525	)	$	3,742	$	(17,795	)	$	5,163
Unrealized gains (losses)		152,657			9,646		13,313			3,069

Total	$	145,132		$	13,388	$	(4,482	)	$	8,232

The following tables summarize the estimated volumes, fixed prices and fair value attributable to oil and gas derivative contracts as of September 30, 2008:


	Remainder of			Year Ending December 31,
	2008			2009			2010			2011		Thereafter		Total
	($ in thousands, except volumes and per unit data)
Natural Gas Swaps:
Contract volumes (Mmbtu)		2,829,828			14,629,200			12,499,060			2,000,004		2,000,004		33,958,096
Weighted-average fixed price per Mmbtu	$	6.98		$	7.78		$	7.42		$	8.00	$	8.11	$	7.62
Fair value, net	$	4,011		$	6,421		$	(5,056	)	$	202	$	479	$	6,057
Natural Gas Collars:
Contract volumes (Mmbtu):
Floor		1,766,492			750,000			630,000			3,549,996		3,000,000		9,696,488
Ceiling		1,766,492			750,000			630,000			3,549,996		3,000,000		9,696,488
Weighted-average fixed price per Mmbtu:
Floor	$	6.54		$	11.00		$	10.00		$	7.39	$	7.00	$	7.56
Ceiling	$	7.53		$	15.00		$	13.11		$	9.88	$	9.60	$	9.97
Fair value, net	$	963		$	2,280		$	1,162		$	635	$	238	$	5,278
Total Natural Gas Contracts:
Contract volumes (Mmbtu)		4,596,320			15,379,200			13,129,060			5,550,000		5,000,004		43,654,584
Weighted-average fixed price per Mmbtu	$	6.81		$	7.94		$	6.59		$	7.61	$	7.44	$	7.31
Fair value, net	$	4,974		$	8,701		$	(3,894	)	$	837	$	717	$	11,335
Crude Oil Swaps:
Contract volumes (Bbl)		9,000			36,000			30,000			—		—		75,000
Weighted-average fixed per Bbl	$	95.92		$	90.07		$	87.50		$	—	$	—	$	89.74
Fair value, net	$	(41	)	$	(432	)	$	(493	)	$	—	$	—	$	(966	)

F-20

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following tables summarize the estimated volumes, fixed prices and fair value attributable to gas derivative contracts as of December 31, 2007:


	Year Ending
	December 31,
	2008			2009		2010			Thereafter		Total
	($ in thousands, except volumes and per unit data)
Natural Gas Swaps:
Contract volumes (Mmbtu)		8,595,876			12,629,365		10,499,225			—		31,724,466
Weighted-average fixed price per Mmbtu	$	6.39		$	7.70	$	7.31		$	—	$	7.22
Fair value, net	$	1,517		$	1,721	$	(4,565	)	$	—	$	(1,327	)
Natural Gas Collars:
Contract volumes (Mmbtu):
Floor		7,027,566			—		—			—		7,027,566
Ceiling		7,027,566			—		—			—		7,027,566
Weighted-average fixed price per Mmbtu:
Floor	$	6.54		$	—	$	—		$	—	$	6.54
Ceiling	$	7.53		$	—	$	—		$	—	$	7.53
Fair value, net	$	(1,617	)	$	—	$	—		$	—	$	(1,617	)
Total Natural Gas Contracts:
Contract volumes (Mmbtu)		15,623,442			12,629,365		10,499,225			—		38,752,032
Weighted-average fixed price per Mmbtu	$	6.46		$	7.70	$	7.31		$	—	$	7.09
Fair value, net	$	(100	)	$	1,721	$	(4,565	)	$	—	$	(2,944	)

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, 2008, we adopted SFAS No. 157, Fair Value Measurements (“SFAS 157”), for financial assets and liabilities measured on a recurring basis. SFAS 157 defines fair value, establishes a framework for measuring fair value and requires certain disclosures about fair value measurements for assets and liabilities measured on a recurring basis. In February 2008, the FASB issued FSP 157-2, which delayed the effective date of SFAS 157 by one year for non-financial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). We have elected to utilize this deferral and have only partially applied SFAS 157 (to financial assets and liabilities measured at fair value on a recurring basis, as described above). Accordingly, we will apply SFAS 157 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 in the first quarter of 2009. 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.

SFAS 157 also establishes a hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy are as follows:

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

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

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QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

•

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 September 30, 2008 (in thousands):


								Netting and
	Level	Level			Level			Cash			Total Net Fair
At September 30, 2008	1	2			3			Collateral*			Value
Derivative financial instruments — assets	$ —	$	4,972		$	21,219		$	(15,822	)	$	10,369
Derivative financial instruments — liabilities	$ —	$	(2,869	)	$	(12,953	)	$	15,822		$	—

Total	$ —	$	2,103		$	8,266		$	—		$	10,369


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

Risk management assets and liabilities in the table above represent the current fair value of all open derivative positions, excluding those derivatives designated as “normal purchases, normal sales.” We classify all of these derivative instruments as “Derivative financial instrument assets” or “Derivative financial instrument liabilities” in our 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,
	2008
Balance at beginning of period	$	3,444
Realized and unrealized gains included in earnings		5,677
Purchases, sales, issuances, and settlements		(855	)
Transfers into and out of Level 3		—

Balance as of September 30, 2008	$	8,266

F-22

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 6 — Asset Retirement Obligations

The following table reflects the changes to QRCP’s asset retirement liability for the nine month periods ended September 30, 2008 (in thousands):


	Nine Months Ended
	September 30, 2008
Asset retirement obligations at beginning of period	$	2,938
Liabilities incurred		93
Liabilities settled		(18	)
Acquisition of PetroEdge		2,193
Accretion		263
Revisions in estimated cash flows		291

Asset retirement obligations at end of period	$	5,760

Note 7 — Stockholders’ Equity and Earnings per Share

We account for stock awards and stock options in accordance with SFAS No. 123(R), Share-Based Compensation, or SFAS No. 123(R). As required by SFAS No. 123(R), the granting of options to our employees under our 2005 Long-Term Incentive Plan, or the 2005 Incentive Plan, are share-based payment transactions and are to be treated as compensation expense by us with a corresponding increase to additional paid-in capital. For the three and nine months ended September 30, 2008, total share-based compensation related to stock awards and options was $(1.3) million and $1.7 million, respectively. For the three and nine months ended September 30, 2007, total share-based compensation related to stock awards and options was $1.6 million and $4.6 million, 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, 2008 is $2.4 million over a weighted average period of 1.34 years.

During the nine months ended September 30, 2008, we converted 140,000 stock options held by certain directors into 70,000 bonus shares. As a result, we recognized additional compensation expense of $0.1 million for the period.

Earnings (Loss) per Share — A reconciliation of the numerator and denominator used in the basic and diluted per share calculations for the three month and nine month periods ended September 30, 2008 and 2007, is as follows (in thousands, except share and per share amounts):

F-23

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
Basic earnings per share:
Net income (loss)	$	87,851	$	492	$	4,870	$	(22,948	)
Weighted average shares outstanding		31,096		22,447		25,527		22,354

Basic earnings (loss) per share	$	2.83	$	0.02	$	0.19	$	(1.03	)

Diluted earnings per share:
Net income (loss)	$	87,851	$	492	$	4,870	$	(22,948	)
Weighted average shares outstanding		31,096		22,447		25,527		22,354
Dilutive shares:
Restricted stock		301		340		100		—
Stock options		—		—		—		—

Diluted shares outstanding		31,397		22,787		25,627		22,354

Diluted earnings (loss) per share:
Total diluted earnings (loss) per share	$	2.80	$	0.02	$	0.19	$	(1.03	)

Because we reported a net loss in the nine months ended September 30, 2007, restricted stock awards covering 113,392 common shares were excluded from the computation of net loss per share because their effect would have been antidilutive.

Note 8— 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. We record a liability related to our legal proceedings and claims when we have determined that it is probable that we will be obligated to pay and the related amount can be reasonably estimated.

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

F-24

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Four putative class action complaints were filed in the United States District Court for the Western District of Oklahoma against QRCP, Quest Energy Partners, L.P., and Quest Energy GP, LLC and certain of our current and former officers and directors. The complaints were filed by certain stockholders on behalf of themselves and other stockholders who purchased our common stock between May 2, 2005 and August 25, 2008 and Quest Energy 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, our stock price and the unit price of Quest Energy 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. Various individual plaintiffs have filed multiple rounds of motions seeking appointment as lead plaintiff, however the court has not yet ruled on these motions and appointed a lead plaintiff. Once a lead plaintiff is appointed, the lead plaintiff must file a consolidated amended complaint within 60 days after being appointed. No further activity is expected in the purported class action until a lead plaintiff is appointed and an amended consolidated complaint is filed. QRCP, Quest Energy and Quest Energy GP intend to defend vigorously against plaintiffs’ claims.

Federal Derivative Case

James Stephens, derivatively on behalf of nominal defendant Quest Resource Corporation. v. William H. Damon III, Jerry Cash, David Lawler, David E. Grose, James B. Kite Jr., John C. Garrison and Jon H. Rateau, Case No. 08-cv-1025-M, U.S. District Court for the Western District of Oklahoma, filed September 25, 2008

On September 25, 2008 a complaint was filed in the United States District Court for the Western District of Oklahoma, purportedly on our behalf, entitled James Stephens, derivatively on behalf on nominal defendant Quest Resource Corporation v. William H. Damon III, Jerry Cash, David Lawler, David E. Grose, James B. Kite Jr., John C. Garrison and Jon H. Rateau, Case No. 08-cv-1025-M. The complaint names certain of our current and former officers and directors as defendants. The factual allegations mirror those in the purported class actions described above, and the complaint asserts claims for breach of fiduciary duty, abuse of control, gross mismanagement, waste of corporate assets, and unjust enrichment. The complaint seeks disgorgement, costs, expenses, and equitable and/or injunctive relief. On October 16, 2008, the court stayed this case pending the court’s ruling on any motions to dismiss the class action claims. QRCP intends to defend vigorously against these claims.

State Court Derivative Cases

Tim Bodeker, derivatively on behalf of nominal defendant Quest Resource Corporation v. Jerry Cash, David E. Grose, Bob G. Alexander, David C. Lawler, James B. Kite, John C. Garrison, Jon H. Rateau and William H. Damon III, Case No. CJ-2008-9042, in the District Court of Oklahoma County, State of Oklahoma, filed October 8, 2008

William H. Jacobson, derivatively on behalf of nominal defendant Quest Resource Corporation v. Jerry Cash, David E. Grose, David C. Lawler, James B. Kite, Jon H. Rateau, Bob G. Alexander, William H. Damon III, John C. Garrison, Murrell, Hall, McIntosh & Co., LLP, and Eide Bailly, LLP, Case No. CJ-2008-9657, in the District Court of Oklahoma County, State of Oklahoma, filed October 27, 2008

Amy Wulfert, derivatively on behalf of nominal defendant Quest Resource Corporation, v. Jerry D. Cash, David C. Lawler, Jon C. Garrison, John H. Rateau, James B. Kite Jr., William H. Damon III, David E. Grose, N. Malone Mitchell III, and Bryan Simmons, Case No. CJ-2008-9042 — consolidated December 30, 2008, in the District Court of Oklahoma County, State of Oklahoma (Original Case No. CJ-2008-9624, filed October 24, 2008)

F-25

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The factual allegations in these petitions mirror those in the purported class actions discussed above. All three petitions assert claims for breach of fiduciary duty, abuse of control, gross mismanagement, and unjust enrichment. The Jacobson petition also asserts claims against the two auditing firms named in that suit for professional negligence and aiding and abetting the director defendants’ breaches of fiduciary duties. The Wulfert petition also asserts a claim against Mr. Bryan Simmons for aiding and abetting Messrs. Cash’s and Grose’s breaches of fiduciary duties. The petitions seek damages, costs, expenses, and equitable relief. On November 12, 2008, the parties to these lawsuits filed a motion to consolidate the actions and appoint lead counsel. The court has not yet ruled on this motion. Under the proposed order, the defendants need not respond to the individual petitions. Once the actions are consolidated, the proposed order provides that counsel for the parties shall meet and confer, within thirty days from the date of the entry of the order, regarding the scheduling of the filing of a consolidated derivative petition and the defendants’ responses to that petition. QRCP intends to defend vigorously against plaintiffs’ claims.

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 has answered the complaint and denied plaintiffs’ claims. Discovery in that case is ongoing. Quest Cherokee intends to defend vigorously against these claims.

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 Fall 2009. QCOS intends to defend vigorously against plaintiffs’ claims.

St. Paul Surplus Lines Insurance Company v. Quest Cherokee Oilfield Service, LLC, et al. CJ-2009-1078, in the 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. Plaintiff alleges that no coverage is owed QCOS under the excess insurance policy issued by plaintiff. The contentions of plaintiff primarily rest on their position that the allegations made in Trigoso are intentional in nature and that the excess insurance policy does not cover such claims. QCOS will vigorously defend the declaratory action.

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

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

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 is 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.

F-26

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Juana Huerter v. Quest Cherokee Oilfield Services, LLC, et al., Case No. 2008 CV-50, District Court of Neosho County, State of Kansas, filed May 5, 2008

QCOS, et al. was named in this personal injury lawsuit arising out of an automobile collision. Initial written discovery is being conducted. There is no pending trial date. QCOS intends to defend vigorously against this claim.

Bradley Haviland, Jr., v. Quest Cherokee Oilfield Services, LLC, et al., Case No. 2008 CV-78, District Court of Neosho County, State of Kansas, filed July 25, 2008

QCOS, et al. were named in this personal injury lawsuit arising out of an automobile collision. There is no pending trial date. QCOS intends to defend vigorously against this claim.

Litigation Related to Oil and Gas Leases

Quest Cherokee was 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 March 1, 2009, the total amount of acreage covered by the leases at issue in these lawsuits was approximately 4,808 acres. Quest Cherokee intends to vigorously defend against those claims. Following is a list of those cases:

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

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

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

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

Ilene T. Bussman et al. v. Quest Cherokee, LLC, Case No. 07-CV-106-PA, in the 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, in the 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, in the District Court of Wilson County, Kansas, filed September 18, 2008 (Quest Cherokee has resolved these claims as part of a settlement.)

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

Housel v. Quest Cherokee, LLC, 06-CV-26-I, in the District Court of Montgomery County, State of Kansas, filed March 2, 2006

Quest Cherokee was named as a defendant in a lawsuit filed by Charles Housel and Meredith Housel on March 2, 2006. Plaintiffs allege that the primary term of the lease at issue has expired and that based upon non-production, plaintiffs are entitled to cancellation of said lease. A judgment was entered against Quest Cherokee on May 15, 2006. Quest Cherokee, however, was never properly served with this lawsuit and did not learn of this lawsuit until on or about April 23, 2007. Quest Cherokee filed a Motion to Set Aside Default Judgment and the parties have since agreed to set aside the default judgment that was entered. Quest Cherokee has answered the complaint. On April 1, 2008, Quest Cherokee sought leave from the court to bring a third party claim against Layne Energy Operating, LLC (“Layne”) on the basis that it, among other things, has committed a trespass and has converted the well and gas and/or proceeds at issue. Quest Cherokee was granted leave to file its claim against Layne. Layne has moved to dismiss the Third Party Petition and Quest Cherokee has objected. Quest Cherokee intends to defend vigorously against plaintiffs’ claims and pursue vigorously its claims against Layne.

F-27

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Quest Cherokee and Bluestem were named as defendants in a lawsuit filed by Central Natural Resources, Inc. (“Central Natural Resources”) on September 1, 2004 in the District Court of Labette County, Kansas. Central Natural Resources owns the coal underlying numerous tracts of land in Labette County, Kansas. Quest Cherokee has obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying some of that land and has drilled wells that produce coal bed methane gas on that land. Bluestem purchases and gathers the gas produced by Quest Cherokee. Plaintiff alleges that it is entitled to the coal bed methane gas produced and revenues from these leases and that Quest Cherokee is a trespasser and has damaged its coal through its drilling and production operations. Plaintiff is seeking quiet title and an equitable accounting for the revenues from the coal bed methane gas produced. Plaintiff has alleged that Bluestem converted the gas and seeks an accounting for all gas purchased by Bluestem from the wells in issue. Quest Cherokee contends it has valid leases with the owners of the coal bed methane gas rights. The issue is whether the coal bed methane gas is owned by the owner of the coal rights or by the owners of the gas rights. If Quest Cherokee prevails on that issue, then the Plaintiff’s claims against Bluestem fail. All issues relating to ownership of the coal bed methane gas and damages have been bifurcated. Cross motions for summary judgment on the ownership of the coal bed methane gas were filed by Quest Cherokee and the plaintiff, with summary judgment being awarded in Quest Cherokee’s favor. Plaintiff appealed the summary judgment and the Kansas Supreme Court has issued an opinion affirming the District Court’s decision and has remanded the case to the District Court for further proceedings consistent with that decision. Quest Cherokee and Bluestem intend to defend vigorously against these claims.

Central Natural Resources, Inc. v. Quest Cherokee, LLC, et al., Case No. CJ-06-07 in the 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 alleges that it is entitled to the coal bed methane gas produced and revenues from these leases and that Quest Cherokee is a trespasser. Plaintiff seeks 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 contends it has valid leases from 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. Quest Cherokee has answered the petition and discovery has been stayed by agreement of the parties. Quest Cherokee intends to defend vigorously against these claims.

Edward E. Birk, et ux., and Brian L. Birk, et ux., v. Quest Cherokee, LLC, Case No. 09-CV-27, in the 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 has failed to pay plaintiffs their overriding royalty interest in that production. Quest’s answer date is June 15, 2009. We are investigating the factual and legal basis for these claims and intend to defend against them vigorously based upon the results of the investigation.

Robert C. Aker, et al. v. Quest Cherokee, LLC, et al., U.S. District Court for the Western District of Pennsylvania, Case No. 3-09CV101, 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 not answered 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.

Other

Well Refined Drilling Co. v. Quest Cherokee, LLC, Case No. 2007-CV-91, in the 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, in the 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 contends that Quest Cherokee owes certain sums for services provided by the plaintiff in connection with drilling wells for Quest Cherokee. Plaintiff has also filed mechanics liens against the oil and gas leases on which those wells are located and also seeks foreclosure of those liens. Quest Cherokee has answered those petitions and has denied plaintiff’s claims. Discovery in those cases is ongoing. Quest Cherokee intends to defend vigorously against these claims.

F-28

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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. were named in the above-referenced lawsuit. The lawsuit was served on May 22, 2009. Defendants have not answered 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.

Barbara Cox v. Quest Cherokee, LLC, U.S. District Court for the District of New Mexico, Case No. CIV-08-0546, 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 alleges 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. Quest Cherokee denies the allegations of plaintiff. Plaintiff has not articulated any firm damage numbers. Quest Cherokee intends to defend vigorously against plaintiff’s claims.

Environmental Matters — As of September 30, 2008, 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.

Note 9 — Related Party Transactions

During the three month and nine month periods ended September 30, 2007, our former chief executive officer, Mr. Jerry D. Cash made certain unauthorized transfers, repayments and re-transfers of funds totaling $0.5 million and $1.5 million, respectively, to entities that he controlled.

The Oklahoma Department of Securities has filed a lawsuit alleging that our former chief financial officer, Mr. David Grose, and our former purchasing manager, Mr. Brent Mueller, stole approximately $1.0 million. In addition to this theft, the Oklahoma Department of Securities has also filed a lawsuit alleging that our former chief financial officer and former purchasing manager received kickbacks totaling approximately $1.8 million ($0.9 million each) from several related suppliers beginning in 2005.

Note 10 — Operating Segments

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Revenues:
Oil and gas production	$	49,531		$	23,852		$	136,989		$	76,396
Natural gas pipelines		16,095			9,236			47,482			25,851
Elimination of inter-segment revenue		(8,583	)		(7,448	)		(25,921	)		(20,729	)

Natural gas pipelines, net of inter-segment revenue		7,512			1,788			21,561			5,122

Total segment revenues	$	57,043		$	25,640		$	158,550		$	81,518

Segment operating profit (loss):
Oil and gas production	$	18,005		$	(1,360	)	$	42,237		$	2,867
Natural gas pipelines		2,985			2,949			10,768			8,084

F-29

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Total segment operating profit		20,990			1,589			53,005			10,951
General and administrative expenses		(4,638	)		(5,278	)		(16,579	)		(14,249	)
Loss on misappropriation of funds		—			(500	)		—			(1,500	)

Total operating income (loss)	$	16,352		$	(4,189	)	$	36,426		$	(4,798	)
Interest expense, net		(7,187	)		(8,007	)		(17,244	)		(23,703	)
Gain (loss) from derivative financial instruments		145,132			13,388			(4,482	)		8,232
Other income (expense) and sale of assets		59			45			181			(178	)

Income (loss) before income taxes and minority interests	$	154,356		$	1,237		$	14,881		$	(20,447	)


	September 30,		December 31,
	2008		2007
Identifiable assets:
Oil and gas production	$	508,950	$	320,880
Natural gas pipelines		309,976		296,104

Total identifiable assets	$	818,926	$	616,984

Segment operating profit represents total revenues less costs and expenses attributable thereto, excluding interest and general corporate expenses.

Note 11 — Restatement

As reported on a Current Report on Form 8-K filed on January 2, 2009, on December 31, 2008, the board of directors of QRCP determined that the consolidated financial statements of QRCP as of and for the years ended December 31, 2007, 2006 and 2005 and its unaudited consolidated financial statements as of and for the three months ended March 31, 2008 and as of and for the three and six months ended June 30, 2008 should no longer be relied upon as the result of the discovery of the Transfers to entities controlled by QRCP’s former chief executive officer, Mr. Jerry D. Cash. Management identified other errors in these financial statements, as described below, and the board of directors concluded that QRCP had, and as of December 31, 2008 continued to have, material weaknesses in its internal control over financial reporting.

The Form 10-Q for the quarterly period ended September 30, 2008, to which these consolidated financial statements form a part, includes restated consolidated interim financial statements for QRCP for the three and nine month periods ended September 30, 2007.

Although the items listed below comprise the most significant errors (by dollar amount), numerous other errors were identified and restatement adjustments made.

The following table presents previously reported net income (loss), major restatement adjustments and restated net income (loss) for the three and nine months ended September 30, 2007 (in thousands):


	Three months ended			Nine months ended
	September 30, 2007			September 30, 2007
Net income (loss) as previously reported	$	1,973		$	(5,824	)
A — Effect of the Transfers		(500	)		(1,500	)
B — Reversal of hedge accounting		4,108			(2,286	)
C — Accounting for formation of Quest Cherokee		26			78
D — Capitalization of costs in full cost pool		(2,325	)		(7,695	)
E — Recognition of costs in proper periods		(544	)		(1,247	)
F — Capitalized interest		86			259
G — Stock-based compensation		(505	)		(746	)
H — Depreciation, depletion and amortization		(105	)		(881	)
I — Other errors*		(1,722	)		(3,106	)

Net income (loss) as restated	$	492		$	(22,948	)

* Includes minority interests impact.

F-30

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The most significant errors (by dollar amount) consist of the following:

(A) The Transfers, which were not approved expenditures of QRCP, were not properly accounted for as losses. As a result of these losses not being recorded, loss from misappropriation of funds was understated for the three and nine month periods ended September 30, 2007.

(B) Hedge accounting was inappropriately applied for QELP’s commodity derivative instruments and the valuation of commodity derivative instruments was incorrectly computed. We incorrectly presented realized gains and losses related to commodity derivative instruments within oil and gas sales. As a result of these errors, oil and gas sales and gain (loss) from derivative financial instruments were misstated for the three and nine month periods ended September 30, 2007.

(C) Errors were identified in the accounting for the formation of Quest Cherokee in December 2003 in which: (i) no value was ascribed to the subsidiary Class A units that were issued to ArcLight in connection with the transaction, (ii) a debt discount (and related accretion) and minority interest were not recorded, (iii) transaction costs were inappropriately capitalized to oil and gas properties, and (iv) subsequent to December 2003, interest expense was improperly stated as a result of these errors. In 2005, the debt relating to this transaction was repaid and the Class A units were repurchased. Subsequent to the 2005 transaction, depreciation, depletion and amortization expense was also overstated due to these errors.

(D) Certain general and administrative expenses unrelated to oil and gas production were inappropriately capitalized to oil and gas properties, and certain operating expenses were inappropriately capitalized to oil and gas properties being amortized. These items resulted in errors in valuation of the full cost pool, oil and gas production expenses and general and administrative expenses. As a result of these errors, oil and gas production expenses and general and administrative expenses were misstated for the three and nine month periods ended September 30, 2007.

(E) Invoices were not properly accrued resulting in the understatement of accounts payable and numerous other balance sheet and income statement accounts. As a result of these errors, oil and gas production expenses, pipeline operating expenses and general and administrative expenses were misstated for the three and nine month periods ended September 30, 2007.

(F) Capitalized interest was not recorded on pipeline construction. As a result of this error, interest expense was overstated for the three and nine month periods ended September 30, 2007.

(G) Errors were identified in stock-based compensation expense, including the use of incorrect grant dates, valuation errors, and incorrect vesting periods. As a result of these errors, general and administrative expenses were misstated for the three and nine month periods ended September 30, 2007.

(H) As a result of previously discussed errors and an additional error related to the method used in calculating depreciation, depletion and amortization, errors existed in our depreciation, depletion and amortization expense and our accumulated depreciation, depletion and amortization. As a result of these errors, depreciation, depletion and amortization expense was misstated for the three and nine month periods ended September 30, 2007.

(I) We identified other errors during the reaudit and restatement process where the impact on net income was not deemed significant enough to warrant separate disclosure of individual errors. Included in this amount is the minority interest effect of the errors discussed above.

The consolidated balance sheet as of December 31, 2007 was restated in the 2008 Form 10-K.

F-31

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table outlines the effects of the restatement adjustments on our Consolidated Statement of Operations for the period indicated (in thousands, except share and per share data):


	Three Months Ended September 30, 2007
	As Previously			Restatement			As
	Reported			Adjustments			Restated
Revenues:
Oil and gas sales	$	28,494		$	(4,642	)	$	23,852
Gas pipeline revenue		1,788			—			1,788
Other revenue (expense)		(5	)		5			—

Total revenues		30,277			(4,637	)		25,640
Costs and expenses:
Oil and gas production		7,280			1,926			9,206
Pipeline operating		5,004			(38	)		4,966
General and administrative expenses		3,653			1,625			5,278
Depreciation, depletion and amortization		9,276			603			9,879
Loss from misappropriation of funds		—			500			500

Total costs and expenses		25,213			4,616			29,829

Operating income (loss)		5,064			(9,253	)		(4,189	)
Other income (expense):
Gain from derivative financial instruments		5,539			7,849			13,388
Gain on sale of assets		50			—			50
Other income (expense)		—			(5	)		(5	)
Interest expense		(8,206	)		97			(8,109	)
Interest income		102			—			102

Total other income (expense)		(2,515	)		7,941			5,426

Income (loss) before income taxes and minority interests		2,549			(1,312	)		1,237
Income tax benefit (expense)		—			—			—

Net income (loss) before minority interests		2,549			(1,312	)		1,237
Minority interests		(576	)		(169	)		(745	)

Net income (loss)	$	1,973		$	(1,481	)	$	492

Income (loss) per common share:
Basic	$	0.09		$	(0.07	)	$	0.02
Diluted	$	0.09		$	(0.07	)	$	0.02
Weighted average shares outstanding:
Basic		22,296,179			150,843			22,447,022

Diluted		22,308,139			479,059			22,787,198

F-32

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table outlines the effects of the restatement adjustments on our Consolidated Statement of Operations for the period indicated (in thousands, except share and per share data):


	Nine Months Ended September 30, 2007
	As Previously			Restatement			As
	Reported			Adjustments			Restated
Revenue:
Oil and gas sales	$	81,910		$	(5,514	)	$	76,396
Gas pipeline revenue		5,122			—			5,122
Other revenue (expense)		(37	)		37			—

Total revenues		86,995			(5,477	)		81,518
Costs and expenses:
Oil and gas production		22,247			6,848			29,095
Pipeline operating		14,271			(114	)		14,157
General and administrative expenses		11,698			2,551			14,249
Depreciation, depletion and amortization		25,610			1,705			27,315
Loss from misappropriation of funds		—			1,500			1,500

Total costs and expenses		73,826			12,490			86,316

Operating income (loss)		13,169			(17,967	)		(4,798	)
Other income (expense):
Gain from derivative financial instruments		5,354			2,878			8,232
Loss on sale of assets		(141	)		—			(141	)
Other income (expense)		—			(37	)		(37	)
Interest expense		(22,928	)		(1,157	)		(24,085	)
Interest income		382			—			382

Total other income (expense)		(17,333	)		1,684			(15,649	)

Loss before income taxes and minority interests		(4,164	)		(16,283	)		(20,447	)
Income tax benefit (expense)		—			—			—

Net loss before minority interests		(4,164	)		(16,283	)		(20,447	)
Minority interests		(1,660	)		(841	)		(2,501	)

Net loss	$	(5,824	)	$	(17,124	)	$	(22,948	)

Loss per common share:
Basic	$	(0.26	)	$	(0.77	)	$	(1.03	)
Diluted	$	(0.26	)	$	(0.77	)	$	(1.03	)
Weighted average shares outstanding:
Basic		22,240,077			113,840			22,353,917

Diluted		22,240,077			113,840			22,353,917

F-33

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table outlines the effects of the restatement adjustments on our Consolidated Statement of Cash Flows for the period indicated (in thousands):


	Nine Months Ended September 30, 2007
	As Previously			Restatement			As
	Reported			Adjustments			Restated
Cash flows from operating activities:
Net loss	$	(5,824	)	$	(17,124	)	$	(22,948	)
Adjustments to reconcile net loss to cash provided by operations:
Depreciation, depletion and amortization		27,616			(301	)		27,315
Stock-based compensation		3,850			707			4,557
Stock-based compensation — minority interest		—			758			758
Stock issued for services and retirement plan		264			(264	)		—
Amortization of deferred loan costs		1,757			(128	)		1,629
Change in fair value of derivative financial instruments		(5,354	)		2,285			(3,069	)
Amortization of gas swap fees		187			(187	)		—
Bad debt expense		—			22			22
Minority interest		1,660			841			2,501
(Gain) loss on sale of assets		142			(1	)		141
Change in assets and liabilities:
Restricted cash		(86	)		86			—
Accounts receivable		(585	)		—			(585	)
Other receivables		(1,095	)		16			(1,079	)
Other current assets		(1,060	)		230			(830	)
Inventory		(160	)		160			—
Other assets		—			(1,157	)		(1,157	)
Accounts payable		20,468			175			20,643
Revenue payable		1,137			349			1,486
Accrued expenses		788			1,525			2,314
Other long-term liabilities		—			122			122
Other		—			(68	)		(68	)

Net cash provided by operating activities		43,706			(11,954	)		31,752

Cash flows from investing activities:
Restricted cash		—			(86	)		(86	)
Equipment, development, leasehold and pipeline		(112,420	)		9,095			(103,325	)

Net cash used in investing activities		(112,420	)		9,009			(103,411	)

Cash flows from financing activities:
Proceeds from bank borrowings		55,000			(55,000	)		—
Repayments of note borrowings		(393	)		—			(393	)
Proceeds from revolver note		—			55,000			55,000
Syndication costs paid		(48	)		48			—
Distributions to unit holders		(3,879	)		—			(3,879	)
Refinancing costs		(2,907	)		1,520			(1,387	)
Change in other long-term liabilities		123			(123	)		—

Net cash provided by financing activities		47,896			1,445			49,341

Net decrease in cash		(20,818	)		(1,500	)		(22,318	)
Cash and cash equivalents, beginning of period		41,820			(8,000	)		33,820

Cash and cash equivalents, end of period	$	21,002		$	(9,500	)	$	11,502

F-34

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 12 — Subsequent Events

Settlement Agreements

We filed lawsuits, related to the Transfers, against Mr. Cash, the entity controlled by Mr. Cash that was used in connection with the Transfers and two former officers, who are the other owners of the controlled-entity, 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 agreements, 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. While QRCP estimates the value of these assets to be less than the amount of the Transfers and cost of the internal investigation, they represent 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 had pledged to secure personal loans with a principal balance far in excess of the current market value of the stock. QELP received all of Mr. Cash’s equity interest in STP Newco, Inc., which owns certain oil producing properties in Oklahoma, and other assets as reimbursement for the costs of the internal investigation and the costs of the litigation against Mr. Cash that have been paid by QELP.

Financial Advisor Contracts

In October 2008, Quest Midstream GP engaged a financial advisor in connection with the review of Quest Midstream’s strategic alternatives. Under the terms of the agreement, the financial advisor received an advisory fee of $250,000 in October 2008 and was entitled to additional monthly advisory fees of $75,000 from December 2008 through September 2009, that was due ($750 thousand in arrearages) on October 1, 2009. In addition, the financial advisor was entitled to fees ranging from $2.0 million to $4.0 million, reduced by 50% of the advisory fees previously paid by Quest Midstream, depending on whether or not certain transactions occur. On June 26, 2009 Quest Midstream GP entered into an amendment to the original agreement which provided that in consideration of a one time payment of $1.75 million, which was paid on July 7, 2009, no additional fees of any kind would be due under the terms of the original agreement other than a fee of $1.5 million if the KPC Pipeline was sold within two years of the date of the amendment.

In October 2008, QRCP engaged a financial advisor with respect to a review of it’s strategic alternatives. Under the terms of the agreement, the financial advisor receives a monthly retention fee of $150,000 per month. In May 2009, QRCP terminated the engagement of the 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 QELP’s strategic alternatives. Under the terms of the agreement, the financial advisor received a one-time advisory fee of $50,000 in January 2009 and is 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 the original 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, being paid upon execution of the amendment. The additional financial advisor fees payable if certain transactions occurred were canceled; however, the financial advisor is 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.

Impairment of oil and gas properties

As of December 31, 2008, our net book value of oil and gas properties exceeded the full cost ceiling. Accordingly, an impairment charge was recognized in the fourth quarter of 2008 of $245.6 million. The impairment was attributable to declines in the prevailing market prices of oil and gas at the measurement date and revisions of reserves due to further technical analysis and production of gas during 2008. See our 2008 Form 10-K. Due to a further decline in natural gas prices subsequent to December 31, 2008, we expect to incur an additional impairment charge on our oil and gas properties of approximately $95.0 million to $115.0 million as of March 31, 2009.

Federal Derivative Case

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

Credit Agreement Amendments

In May and June 2009, QRCP, Quest Cherokee and Quest Energy entered into amendments to their respective credit agreements. See Note 3 — Long-Term Debt — Credit Facilities for descriptions of the amendments.

Merger Agreement and Related Agreements

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

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

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

F-35

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

Restatement

As discussed in the Explanatory Note to this Quarterly Report on Form 10-Q and in Note 11 — Restatement to our consolidated financial statements, we restated the consolidated financial statements included in this Quarterly Report on Form 10-Q as of December 31, 2007 in our 2008 Form 10-K and we are restating herein the interim consolidated financial statements for the three and nine month periods ended September 30, 2007. This Management’s Discussion and Analysis of Financial Condition and Results of Operations for the three and nine month periods ended September 30, 2007 reflects the restatements.

The following discussion should be read together with the consolidated financial statements and the notes to consolidated financial statements, which are included in Item 1 of this Form 10-Q, and the Risk Factors, which are set forth in Item 1A of the 2008 Form 10-K.

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. Our principal operations and producing properties 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. We conduct substantially all of our production operations through Quest Energy and our natural gas transportation, gathering, treating and processing operations through Quest Midstream. Our Cherokee Basin operations are currently focused on developing CBM gas production through Quest Energy, which is served by a gas gathering pipeline network owned through Quest Midstream. Quest Midstream also owns an interstate natural gas transmission pipeline. Our Appalachian Basin operations are primarily focused on the development of the Marcellus Shale through Quest Energy and Quest Eastern. Unless otherwise indicated, references to “us”, “we”, “our” or “QRCP” include our subsidiaries and controlled affiliates.

Since QRCP controls the general partner interests in Quest Energy and Quest Midstream, QRCP reflects its 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 other subsidiaries. The interest owned by non-controlling partners’ share of income is reflected as a minority interest expense 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 consist almost exclusively of distributions on its partnership interests 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 of operations of Quest Energy and Quest Midstream and also include interest of non- controlling partners in Quest Energy’s and Quest Midstream’s net income, interest income (expense) and general and administrative expenses not reflected in Quest Energy’s and Quest Midstream’s results of operations. 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.

Recent Developments

PetroEdge Acquisition

On July 11, 2008, QRCP acquired PetroEdge Resources (WV) LLC (“PetroEdge”) and simultaneously transferred PetroEdge’s natural gas producing wells to Quest Energy. Quest Energy funded the purchase of the PetroEdge wellbores with borrowings under its revolving credit facility, which was increased from $160 million to $190 million as part of the acquisition and the proceeds from its Second Lien Senior Term Loan Agreement (the “Second Lien Loan Agreement”). QRCP funded the balance of the PetroEdge acquisition with proceeds from a public offering of 8,800,000 shares of QRCP common stock at a price of $10.25 per share that closed on July 8, 2008. QRCP received net proceeds from this offering of approximately $84.7 million. Simultaneously with the closing of the PetroEdge acquisition, QRCP converted its then existing $50 million revolving credit facility to a $35 million term loan with a maturity date of July 11, 2010. RBC required QRCP to use $13 million of the proceeds

from the equity offering to reduce the outstanding indebtedness under its credit agreement from $48 million to $35 million. The purpose of the PetroEdge acquisition was to expand our operations to another geologic basin with less basis differential that had significant resource potential. The acquisition closed during the peak month of natural gas pricing in 2008.

Internal Investigation; Restatements and Reaudits

On August 23, 2008, only six weeks after the PetroEdge transaction closed, our then chief executive officer resigned following the discovery of the Transfers. The Transfers were brought to the attention of the boards of directors of each of QRCP, Quest Energy GP and Quest Midstream GP as a result of an inquiry and investigation that had been initiated by the Oklahoma Department of Securities. QRCP’s board of directors, jointly with the boards of directors of Quest Energy GP and Quest Midstream GP, formed a joint special committee to investigate the matter and to consider the effect on our consolidated financial statements. We also retained a new independent registered public accounting firm to reaudit our financial statements.

The investigation revealed that the Transfers resulted in a loss of funds totaling approximately $10 million by QRCP. Further, it was determined that our former chief financial officer directly participated and/or materially aided our former chief executive officer in connection with the unauthorized Transfers. In addition, the Oklahoma Department of Securities has filed a lawsuit alleging that our former chief financial officer and our former purchasing manager each received kickbacks of approximately $0.9 million from several related suppliers over a two-year period and that during the third quarter of 2008, they also engaged in the direct theft of $1 million for their personal benefit and use.

We experienced significant increased costs in the second half of 2008 and continue to experience such increased costs in 2009 due to, among other things:

	•		We had costs associated with the internal investigation and our responding to inquiries from the Oklahoma Department of Securities, the Federal Bureau of Investigation, the Department of Justice, the Securities and Exchange Commission and the Internal Revenue Service.

	•		As a result of the termination of the former chief executive officer and chief financial officer, we immediately retained consultants to perform the accounting and finance functions and to assist in the determination of the intercompany debt.

	•		We retained law firms to respond to the class action and derivative suits that have been filed against QRCP and Quest Energy GP and QELP and to pursue the claims against the former employees.

	•		We had costs associated with amending the credit agreements of QRCP, QELP and QMLP and obtaining the necessary waivers from our lenders thereunder as well as incremental increased interest expense related thereto. See “— Liquidity and Capital Resources.”

	•		We retained external auditors to reaudit the consolidated financial statements for the years ended December 31, 2007, 2006 and 2005.

	•		Each of QRCP, QELP and QMLP retained financial advisors to consider strategic options and each retained outside legal counsel or increased the amount of work being performed by its previously engaged outside legal counsel.

We estimate that the increased costs related to the foregoing will be approximately $7.0 million to $8.0 million in total.

Global Financial Crisis and Impact on Capital Markets and Commodity Prices

At about the same time as the Transfers were discovered, the global economy experienced a significant downturn. The crisis began over concerns related to the U.S. financial system and quickly grew to impact a wide range of industries. There were two significant ramifications to the exploration and production industry as the economy continued to deteriorate. The first was that capital markets essentially froze. Equity, debt and credit markets shut down. Future growth opportunities have been and are expected to continue to be constrained by the lack of access to liquidity in the financial markets.

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

Our operations and financial condition are significantly impacted by these prices. During the year ended December 31, 2008, the NYMEX monthly gas index price (last day) ranged from a high of $13.58 per Mmbtu to a low of $5.29 per Mmbtu. Natural gas prices came under pressure in the second half of the year as a result of lower domestic product demand that was caused by the weakening economy and concerns over excess supply of natural gas. In the Cherokee Basin, where we produce and sell most of our gas, there has been a widening of the historical discount of prices in the area to the NYMEX pricing point at Henry Hub as a result of elevated levels of natural gas drilling activity in the region and a lack of pipeline takeaway capacity. During 2008, this discount (or basis differential) in the Cherokee Basin ranged from $0.67 per Mmbtu to $3.62 per Mmbtu.

The spot price for NYMEX crude oil in 2008 ranged from a high of $145.29 per barrel in early July to a low of $33.87 per barrel in late December. The volatility in oil prices during the year was a result of the worldwide recession, geopolitical activities, worldwide supply disruptions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets as well as domestic concerns about refinery utilization and petroleum product inventories pushing prices up during the first half of the year. 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.

Overall, as a result, our operating profitability was seriously adversely affected during the third quarter of 2008 and is expected to continue to be impaired during 2009. While our existing commodity hedge position mitigates the impact of commodity price declines, it does not eliminate the potential effects of changing commodity prices.

Credit Agreements

QRCP. On July 11, 2008, in connection with the PetroEdge acquisition, QRCP and Royal Bank of Canada (“RBC”) entered into an Amended and Restated Credit Agreement to convert QRCP’s then-existing $50 million revolving credit facility to a $35 million term loan, due and maturing on July 11, 2010 (the “Original Term Loan”). Thereafter, the parties entered into the following amendments to the credit agreement (collectively, with all amendments, the “Credit Agreement”):

	•		On October 24, 2008, QRCP and RBC entered into a First Amendment to Amended and Restated Credit Agreement, which, among other things, added a $6 million term loan (the “Additional Term Loan”) to the $35 million term loan under the Credit Agreement.

	•		On November 4, 2008, QRCP entered into a Second Amendment to Amended and Restated Credit Agreement (the “Second Amendment to Credit Agreement”) which clarified that the $6 million commitment under the Additional Term Loan would be reduced dollar for dollar to the extent QRCP retained net cash proceeds from dispositions in accordance with the terms of the Credit Agreement and it also amended and/or waived certain of the representations and covenants contained in the Credit Agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result of (1) the Transfers and (2) not timely settling certain intercompany accounts among QRCP, Quest Energy and Quest Midstream.

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

	•		On May 29, 2009, QRCP entered into a Fourth Amendment to Amended and Restated Credit Agreement (the “Fourth Amendment to Credit Agreement”) that, among other things, waived certain events of default related to the financial covenants and collateral requirements under the Credit Agreement, extended certain financial reporting deadlines and permitted the settlement agreements with Mr. Cash discussed elsewhere herein and in QRCP’s 2008 Form 10-K.

•

On June 30, 2009, QRCP entered into a Fifth Amendment to Amended and Restated Credit Agreement (the “Fifth Amendment to Credit Agreement”) that, among other things, amended and/or waived certain of the representations and covenants contained in the Credit Agreement.

Quest Energy

Quest Energy, entered into the following amendments to its Amended and Restated Credit Agreement dated November 15, 2007 with Quest Cherokee, as the borrower, RBC, as administrative agent and collateral agent, KeyBank National Association, as documentation agent and the lenders party thereto (collectively with all amendments, the “Quest Cherokee Credit Agreement”):

	•		On October 28, 2008, Quest Energy entered into a Second Amendment to Amended and Restated Credit Agreement to amend and/or waive certain of the representations and covenants contained in the Quest Cherokee Credit Agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result of (1) the Transfers and (2) not timely settling certain intercompany accounts among QRCP, Quest Energy and Quest Midstream.

	•		On June 18, 2009, Quest Energy 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 credit agreement on a pari passu basis with the obligations under the credit agreement.

	•		On June 30, 2009, Quest Energy entered into a Fourth Amendment to Amended and Restated Agreement that deferred until August 15, 2009, Quest Energy’s obligation to deliver to the lenders unaudited consolidated balance sheets and related statements of income and cash flows for the fiscal quarters ending September 30, 2008 and March 31, 2009.

On July 11, 2008, concurrent with the PetroEdge acquisition, Quest Energy and Quest Cherokee entered into a Second Lien Senior Term Loan Agreement (the “Second Lien Loan Agreement,” together with the Quest Cherokee Credit Agreement, the “Quest Cherokee Agreements”) for a six-month, $45 million term loan. See “Liquidity and Capital Resources — Credit Agreements — Quest Energy” for additional information regarding the Second Lien Loan Agreement. Thereafter the parties entered into the following amendments to the Second Lien Loan Agreement:

	•		On October 28, 2008, Quest Energy entered into a First Amendment to Second Lien Senior Term Loan Agreement (the “First Amendment to Second Lien Loan Agreement”) to, among other things, extend the maturity date to September 30, 2009 and to amend and/or waive certain of the representations and covenants contained in the Second Lien Loan Agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result or (1) the Transfers and (2) not timely settling certain intercompany accounts among QRCP, Quest Energy and Quest Midstream.

	•		On June 30, 2009, Quest Energy entered into a Second Amendment to Second Lien Senior Term Loan Agreement that amended a covenant in order to defer until August 15, 2009, Quest Energy’s obligation to deliver to the lenders unaudited consolidated balance sheets and related statements of income and cash flows for the fiscal quarters ending September 30, 2008 and March 31, 2009.

Quest Midstream

On October 28, 2008, Quest Midstream entered into a Second Amendment (the “Quest Midstream Second Amendment”) to their $135 million syndicated revolving credit facility

(the “Quest Midstream Credit Agreement”). The Quest Midstream Credit Agreement together with the Quest Midstream Second Amendment are referred to collectively as the “Amended Quest Midstream Credit Agreement.” The Quest Midstream Second Amendment, among other things, amended and/or waived certain of the representations and covenants contained in the Quest Midstream Credit Agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result of (1) the Transfers and (2) not timely settling certain intercompany accounts among QRCP, Quest Energy and Quest Midstream.

Suspension of Distributions and Asset Sales

Distributions were suspended on Quest Energy’s subordinated units beginning with the third quarter of 2008 and distributions were suspended on all of Quest Energy’s units, including its common units, beginning with the fourth quarter of 2008. Since these distributions would have been substantially all of QRCP’s cash flows for 2009 and the third and fourth quarter of 2008, the loss of the Quest Energy distributions was material to QRCP’s financial position.

In October 2008, we negotiated an additional $6 million term loan under the Credit Agreement with a maturity date of November 30, 2008. We agreed with our lenders that the additional term loan would be repaid with the net proceeds from asset sales by QRCP and that the first $4.5 million of net proceeds in excess of any additional term loans that were borrowed would be used to repay QRCP’s $35 million term loan.

On October 30, 2008, QRCP sold its interest in approximately 22,600 net undeveloped acres and one well in Somerset County, Pennsylvania to a private party for approximately $6.8 million. On November 26, 2008, QRCP sold its interest in the development rights and related purchase option, which it had purchased on June 4, 2008 covering approximately 28,700 acres in Potter County, Pennsylvania, to an undisclosed party for approximately $3.2 million. On February 13, 2009, QRCP sold its interest in approximately 23,076 net undeveloped acres in the Marcellus Shale and one well in Lycoming County, Pennsylvania to a third party for approximately $8.7 million.

Management decided that these undeveloped acres were good candidates for disposition in the current environment given the lack of gathering and transportation infrastructure in the immediate area and the cost and time that would be involved in establishing significant flow of natural gas.

In addition to these sales, on November 5, 2008, QRCP sold a 50% interest in approximately 4,500 net undeveloped acres, three wells in various stages of completion and existing pipelines and facilities in Wetzel County, West Virginia to another party for $6.1 million. QRCP will continue to operate the Wetzel County property. All future development costs will be split equally between QRCP and the other party. This joint venture arrangement allows QRCP to retain a significant interest in the Wetzel County property, which we believe is a desirable asset due to established infrastructure, pipeline taps and proved offset production in the area.

QRCP borrowed $2 million of the additional $6 million term loan under its Credit Agreement in October 2008. QRCP’s portion of the proceeds from the asset sales were used to repay the $2 million additional term loan and to reduce QRCP’s $35 million term loan to $28.3 million as of May 15, 2009.

Decrease in Year-End Reserves; Impairment

Due to the low price for natural gas as of December 31, 2008 as described above, revisions resulting from further technical analysis and production during the year, proved reserves decreased 17.2% to 174.8 Bcfe at December 31, 2008 from 211.1 Bcfe at December 31, 2007, and the standardized measure of our proved reserves decreased 42.7% to $164.1 million as of December 31, 2008 from $286.2 million as of December 31, 2007. Proved reserves also decreased as a result of our production during the year. Our proved reserves at December 31, 2008 were calculated using a spot price of $5.71 per Mmbtu (adjusted for basis differential, prices were $5.93 per Mmbtu in the Appalachian Basin and $4.84 per Mmbtu in the Cherokee Basin). As a result of this decrease, we will recognize a non-cash impairment of $298.9 million in fourth quarter of 2008.

This resulted in the lenders under the Quest Cherokee Credit Agreement reducing the borrowing base from $190 million to $160 million. See “— Liquidity and Capital Resources — Credit Agreements — Quest Energy.”

Seminole County Acreage Acquisition

In early February 2008, QELP purchased certain oil producing properties in Seminole County, Oklahoma from a private company for $9.5 million. In connection with the acquisition, QELP entered into crude oil swaps for approximately 80% of the estimated production from the property’s proved developed producing reserves at WTI-NYMEX prices per barrel of oil of approximately $96.00 in 2008, $90.00 in 2009, and $87.50 for 2010. The acquisition was financed with borrowings under Quest Energy’s credit facility. As of December 31, 2008, the properties had estimated net proved reserves of 588,800 Bbls, all of which were proved developed producing.

Settlement Agreements

We filed lawsuits against Mr. Cash, the entity controlled by Mr. Cash that was used in connection with the Transfers and two former officers, who are the other owners of the controlled-entity, seeking, among other things, to recover the funds that were transferred. On May 19, 2009, QRCP, QELP and QMLP entered into settlement agreements with Mr. Cash, the controlled-entity and the other owners to settle this litigation. Under the terms of the settlement agreements, 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. While QRCP estimates the value of these assets to be less than the amount of the Transfers and cost of the internal investigation, they represent 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. QELP received all of Mr. Cash’s equity interest in STP Newco, Inc., which owns certain oil producing properties in Oklahoma, and other assets as 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.

Recombination

Given the liquidity challenges facing QRCP, Quest Midstream and Quest Energy, each entity has undertaken a strategic review of its assets and 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 the three companies would recombine. The recombination would be effected by forming a new, yet to be named, publicly-traded corporation (“New Quest”) that, through a series of mergers and entity conversions, would wholly-own all three entities (the “Recombination”). The Merger Agreement follows the execution of a non-binding letter of intent by the three Quest entities that was publicly announced on June 3, 2009.

Segment Overview

We report our results of operations as two business segments. These segments and the activities performed to provide services to our customers and create value for our stockholders are as follows:

	•		Oil and gas production; and

	•		Natural gas pipelines, including transporting, gathering, treating and processing natural gas.

Operating segment data for the three and nine month periods ended September 30, 2008 and 2007 follows (in thousands):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
				(Restated)						(Restated)
Revenues:
Oil and gas production	$	49,531		$	23,852		$	136,989		$	76,396
Natural gas pipelines		16,095			9,236			47,482			25,851
Elimination of inter-segment revenue		(8,583	)		(7,448	)		(25,921	)		(20,729	)

Natural gas pipelines, net of inter-segment revenue		7,512			1,788			21,561			5,122

Total segment revenues	$	57,043		$	25,640		$	158,550		$	81,518

Operating profit (loss):
Oil and gas production	$	18,005		$	(1,360	)	$	42,237		$	2,867
Natural gas pipelines		2,985			2,949			10,768			8,084

Total segment operating profit		20,990			1,589			53,005			10,951
General and administrative expenses		(4,638	)		(5,278	)		(16,579	)		(14,249	)
Misappropriation of funds		—			(500	)		—			(1,500	)

Total operating income (loss)	$	16,352		$	(4,189	)	$	36,426		$	(4,798	)

Results of Operations

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

Oil and Gas Production Segment

Three Months Ended September 30, 2008 Compared to the Three Months Ended September 30, 2007

Overview. The following discussion of results of operations compares amounts for the three months ended September 30, 2008 to the amounts for the three months ended September 30, 2007, as follows:


	Three Months Ended
	September 30,				Increase/
	2008		2007		(Decrease)
			(Restated)
	($ in thousands)
Oil and gas sales	$	49,531	$	23,852	$	25,679	107.7	%
Oil and gas production costs	$	9,963	$	9,206	$	757	8.2	%
Transportation expense (intercompany)	$	8,583	$	7,448	$	1,135	15.2	%
Depreciation, depletion and amortization	$	12,980	$	8,558	$	4,422	51.7	%

Production. The following table presents the primary components of revenues of our Oil and Gas Production Segment (oil and gas production and average oil and gas prices), as well as the average costs per Mcfe, for the three month periods ended September 30, 2008 and 2007.


	Three Months Ended
	September 30,				Increase/
	2008		2007		(Decrease)
			(Restated)
Production Data:
Natural gas production (Mmcf)		5,694		4,375		1,319		30.1	%
Oil production (BBbl)		19		2		17		850.0	%
Total production (Mmcfe)		5,808		4,387		1,421		32.4	%
Average daily production (Mmcfe/d)		63.1		47.7		15.4		32.3	%
Average Sales Price per Unit:
Natural gas (Mcf)	$	8.31	$	5.42	$	2.89		53.3	%
Oil (Bbl)	$	116.89	$	65.64	$	51.25		78.1	%
Natural gas equivalent (Mcfe)	$	8.53	$	5.44	$	3.09		56.8	%
Average Unit Costs per Mcfe:
Production costs	$	1.72	$	2.10	$	(0.38	)	(18.1	)%
Transportation expense (intercompany)	$	1.48	$	1.70	$	(0.22	)	(12.9	)%
Depreciation, depletion and amortization	$	2.23	$	1.95	$	0.28		14.4	%

Oil and Gas Sales. Oil and gas sales increased $25.7 million, or 107.7%, from $23.8 million during the three months ended September 30, 2007 to $49.5 million during the three months ended September 30, 2008. This increase was the result of increased sales volumes and an increase in average realized prices. Of this increase, $18.0 million was attributable to an increase in the average sales price in 2008. Our average sales prices, on an equivalent basis (Mcfe), increased to $8.53 per Mcfe for the three months ended September 30, 2008 from $5.44 per Mcfe for the three months ended September 30, 2007. Additional volumes of 1,421 Mmcfe accounted for $7.7 million of the increase. The increased volumes resulted from the 2008 acquisitions, as well as additional wells completed in 2008.

Oil and Gas Operating Expenses. Oil and gas operating expenses consist of oil and gas production costs, which include lease operating expenses, severance taxes and ad valorem taxes, and transportation expense. Oil and gas operating expenses increased $1.9 million, or 11.4%, to $18.5 million during the three months ended September 30, 2008, from $16.7 million during the three months ended September 30, 2007.

Oil and gas production costs increased $0.8 million, or 8.2%, to $10.0 million during the three months ended September 30, 2008, from $9.2 million during the three months ended September 30, 2007. This increase was primarily due to increased volumes in 2008. Production costs including gross production taxes and ad valorem taxes were $1.72 per Mcfe for the three months ended September 30, 2008 as compared to $2.10 per Mcfe for the three months ended September 30, 2007. This decrease in per unit cost was due to increased volumes, over which to spread fixed costs.

Transportation expense increased $1.1 million, or 15.2 %, to $8.5 million during the three months ended September 30, 2008, from $7.4 million during the three months ended September 30, 2007. The increase was primarily due to increased volumes, which resulted in additional expense of approximately $2.4 million. This increase was offset by a decrease in per unit cost of $0.22 per Mcfe. Transportation expense was $1.48 per Mcfe for the three months ended September 30, 2008 as compared to $1.70 per Mcfe for the three months ended September 30, 2007.

ended September 30, 2007. This increase was primarily due to the PetroEdge acquisition, resulting in an increase in the per unit rate. Depletion of oil and gas properties accounted for $4.0 million of the total increase. The remaining $0.4 million was due to depreciation and amortization for additional vehicles, equipment and facilities acquired in 2008.

Nine Months Ended September 30, 2008 Compared to the Nine Months Ended September 30, 2007

Overview. The following discussion of results of operations compares amounts for the nine months ended September 30, 2008 to the amounts for the nine months ended September 30, 2007, as follows:


	Nine Months Ended
	September 30,				Increase/
	2008		2007		(Decrease)
			(Restated)
	($ in thousands)
Oil and gas sales	$	136,989	$	76,396	$	60,593	79.3	%
Oil and gas production costs	$	33,000	$	29,095	$	3,905	13.4	%
Transportation expense (intercompany)	$	25,921	$	20,729	$	5,192	25.0	%
Depreciation, depletion and amortization	$	35,831	$	23,705	$	12,126	51.2	%

Production. The following table presents the primary components of revenues of our oil and gas production segment (oil and gas production and average oil and gas prices), as well as the average costs per Mcfe, for the nine month periods ended September 30, 2008 and 2007.


	Nine Months Ended
	September 30,				Increase/
	2008		2007		(Decrease)
			(Restated)
Production Data:
Natural gas (Mmcf)		15,755		12,211		3,544		29.0	%
Oil (BBbl)		47		6		41		683.3	%
Total production (Mmcfe)		16,037		12,247		3,790		30.9	%
Average daily production (Mmcfe/d)		58.5		44.9		13.6		30.3	%
Average Sales Price per Unit:
Natural gas (Mcf)	$	8.37	$	6.23	$	2.14		34.3	%
Oil (Bbl)	$	110.40	$	57.06	$	53.34		93.5	%
Natural gas equivalent (Mcfe)	$	8.54	$	6.24	$	2.30		36.9	%
Average Unit Costs per Mcfe:
Production costs	$	2.06	$	2.38	$	(0.32	)	(13.4	)%
Transportation expense (intercompany)	$	1.62	$	1.69	$	(0.07	)	(4.1	)%
Depreciation, depletion and amortization	$	2.23	$	1.94	$	0.29		14.9	%

Oil and Gas Sales. Oil and gas sales increased $60.6 million, or 79.3%, from $76.4 million during the nine months ended September 30, 2007 to $137.0 million during the nine months ended September 30, 2008. This increase was the result of increased sales volumes and an increase in average realized prices. Of the increase, $36.9 million was attributable to an increase in the average sales price in 2008. Our average sales prices on an equivalent basis (Mcfe), increased to $8.54 per Mcfe for the nine months ended September 30, 2008 from $6.24 per Mcfe for the nine months ended September 30, 2007. Additional volumes of 3,790 Mmcfe accounted for $23.7 million. The increased volumes resulted from our 2008 acquisitions, as well as additional wells completed in 2008.

Oil and Gas Operating Expenses. Oil and gas operating expenses consist of oil and gas production costs, which include lease operating expenses, severance taxes and ad valorem taxes, and transportation expense. Oil and gas operating expenses increased $9.1 million, or 18.3 %, to $58.9 million during the nine months ended September 30, 2008, from $49.8 million during the nine months ended September 30, 2007.

Oil and gas production costs increased $3.9 million, or 13.4%, to $33.0 million during the nine months ended September 30, 2008, from $29.1 million during the nine months ended September 30, 2007. This increase was primarily due to increased volumes in 2008. Production costs including gross production taxes and ad valorem taxes were $2.06 per Mcfe for the nine months ended September 30, 2008 as compared to $2.38 per Mcfe for the nine months ended September 30, 2007. The decrease in per unit cost was due to higher volumes over which to spread fixed costs.

Transportation expense increased $5.2 million, or 25.0 %, to $25.9 million during the nine months ended September 30, 2008, from $20.7 million during the nine months ended September 30, 2007. The increase was primarily due to increased volumes, which resulted in additional expense of approximately $6.4 million. This increase was offset by a decrease in per unit cost of $0.07 per Mcfe. Transportation expense was $1.62 per Mcfe for the nine months ended September 30, 2008 as compared to $1.69 per Mcfe for the nine months ended September 30, 2007.

Depreciation, Depletion and Amortization. We are subject to variances in our depletion rates from period to period due to changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties. Our depreciation, depletion and amortization increased approximately $12.1 million, or 51.2 %, for the nine months ended September 30, 2008 to $35.8 million from $23.7 million for the nine months ended September 30, 2007. On a per unit basis, we had an increase of $0.29 per Mcfe to $2.23 per Mcfe for the nine months ended September 30, 2008 from $1.94 per Mcfe for the nine months ended September 30, 2007. This increase was primarily due to downward revisions in our proved reserves, resulting in an increase in the per unit rate. Depletion of oil and gas properties accounted for $11.0 million of the increase, while depreciation and amortization increased approximately $1.1 million primarily due to additional vehicles, equipment and facilities acquired in 2008.

Natural Gas Pipelines Segment

Three Months Ended September 30, 2008 Compared to the Three Months Ended September 30, 2007


	Three Months Ended
	September 30,
	2008		2007		Increase/ (Decrease)
			(Restated)

Natural Gas Pipeline Revenue ($ in thousands):
Gas pipeline revenue — Third Party	$	7,512	$	1,788	$	5,724	320.1	%
Gas pipeline revenue — Intercompany		8,583		7,448		1,135	15.2	%

Total natural gas pipeline revenue	$	16,095	$	9,236	$	6,859	74.3	%
Pipeline operating expense	$	7,737	$	4,966	$	2,771	55.8	%
Depreciation and amortization expense	$	5,373	$	1,321	$	4,052	306.7	%
Throughput Data (Mmcf):
Throughput — Third Party		1,453		426		1,027	241.1	%
Throughput — Intercompany		6,578		5,420		1,158	21.4	%

Total throughput (Mmcf)		8,031		5,846		2,185	37.4	%
Average Pipeline Operating Costs per Mcf:
Pipeline operating expense	$	0.96	$	0.85	$	0.11	12.9	%
Depreciation and amortization	$	0.67	$	0.23	$	0.44	191.3	%

Pipeline Revenue. Total natural gas pipeline revenue increased $6.9 million, or 74.3%, to $16.1 million during the three months ended September 30, 2008, from $9.2 million during the three months ended September 30, 2007.

Third party natural gas pipeline revenue increased $5.7 million, or 320.1%, to $7.5 million during the three months ended September 30, 2008, from $1.8 million during the three months ended September 30, 2007. The increase was primarily related to Quest Pipelines (KPC), which we refer to as KPC, which was acquired November 1, 2007. During the three months ended

September 30, 2008, KPC had revenues of $4.8 million. The remaining increase of $0.9 million was due to additional third party volumes on our gathering system.

Intercompany natural gas pipeline revenue increased $1.1 million, or 15.2 %, to $8.5 million during the three months ended September 30, 2008, from $7.4 million during the three months ended September 30, 2007. The increase is due to the 21.4% increase in throughput volumes from our Cherokee Basin properties and the higher gathering and compression fees that became effective January 1, 2008 under the midstream services agreement.

Pipeline Operating Expense. Pipeline operating expense increased $2.7 million, or 55.8%, to $7.7 million during the three months ended September 30, 2008, from $5.0 million during the three months ended September 30, 2007. This increase is primarily the result of our KPC acquisition in November 2007. During the three months ended September 30, 2008, KPC had pipeline operating costs of $2.0 million. The remaining increase of $0.7 million is due to increased throughput volumes in 2008. Pipeline operating costs per unit increased $0.11 per Mcf during 2008, from $0.85 per Mcf to $0.96 per Mcf.

Depreciation and Amortization. Depreciation and amortization expense increased $4.1 million, or 306.7 %, to $5.4 million during the three months ended September 30, 2008, from $1.3 million during the three months ended September 30, 2007. The increase is primarily due to the amortization of our intangibles of $1.1 million acquired in the KPC acquisition, as well as an increase in depreciation on our pipelines of $1.7 million.

Nine Months Ended September 30, 2008 Compared to the Nine Months Ended September 30, 2007


	Nine Months Ended
	September 30,
	2008		2007		Increase/ (Decrease)
			(Restated)
	($ in thousands)
Natural Gas Pipeline Revenue:
Gas pipeline revenue — Third Party	$	21,561	$	5,122	$	16,439	320.9	%
Gas pipeline revenue — Intercompany		25,921		20,729		5,192	25.0	%

Total natural gas pipeline revenue	$	47,482	$	25,851	$	21,631	83.7	%
Pipeline operating expense	$	22,859	$	14,157	$	8,702	61.5	%
Depreciation and amortization expense	$	13,855	$	3,610	$	10,245	283.8	%
Throughput Data (Mmcf):
Throughput — Third Party		7,301		1,272		6,029	474.0	%
Throughput — Intercompany		18,862		14,990		3,872	25.8	%

Total throughput (Mmcf)		26,193		16,262		9,931	66.3	%
Average Pipeline Operating Costs per Mcf:
Pipeline operating expense	$	0.87	$	0.87	$	—	—	%
Depreciation and amortization	$	0.53	$	0.22	$	0.31	140.9	%

Pipeline Revenue. Total natural gas pipeline revenue increased $21.6 million, or 83.7 %, to $47.5 million during the nine months ended September 30, 2008, from $25.9 million during the nine months ended September 30, 2007.

Third party natural gas pipeline revenue increased $16.4 million, or 320.9%, to $21.6 million during the nine months ended September 30, 2008, from $5.1 million during the nine months ended September 30, 2007. The increase was primarily related to the November 2007 KPC acquisition. During the nine months ended September 30, 2008, KPC had revenues of $14.7 million. The remaining increase of $1.7 million was due to additional third party volumes on our gathering system.

Intercompany natural gas pipeline revenue increased $5.2 million, or 25.0%, to $25.9 million during the nine months ended September 30, 2008, from $20.7 million during the nine months ended September 30, 2007. The increase is due to the 25.8 % increase in throughput volumes from our Cherokee Basin properties and the higher

gathering and compression fees that became effective January 1, 2008 under the midstream services agreement.

Pipeline Operating Expense. Pipeline operating expense increased $8.7 million, or 61.5%, to $22.9 million during the nine months ended September 30, 2008, from $14.2 million during the nine months ended September 30, 2007. This increase is primarily the result of the November 2007 KPC acquisition. During the nine months ended September 30, 2008, KPC had pipeline operating costs of $5.8 million. Pipeline operating costs per unit remained constant at $0.87 per Mcf for the nine months ended September 30, 2008.

Depreciation and Amortization. Depreciation and amortization expense increased $10.2 million, or 283.8 %, to $13.8 million during the nine months ended September 30, 2008, from $3.6 million during the nine months ended September 30, 2007. The increase is primarily due to the amortization of our intangibles of $3.3 million acquired in the KPC acquisition, as well as an increase in depreciation on our pipelines of $5.4 million.

Unallocated Items

The following discussion of results of operations will discuss the amounts for the three and nine months ended September 30, 2008.

General and Administrative Expenses

General and administrative expenses decreased $0.6 million, or 12.1%, to $4.6 million during the three months ended September 30, 2008, from $5.2 million during the three months ended September 30, 2007. The decrease is due to lower stock compensation expense of $2.8 million, primarily in connection with the departure of our former chief executive and financial officers. This decrease was offset by an increase in expenses related to the internal investigation of the Transfers of $0.8 million, an increase in salaries of $0.6 million and an increase in rent in connection with establishing a Houston Office and new corporate headquarters of $0.2 million. The remaining increase was the result of the costs associated with Quest Energy being a separate publicly traded company.

General and administrative expenses increased $2.3 million, or 16.4%, to $16.5 million during the nine months ended September 30, 2008, from $14.2 million during the nine months ended September 30, 2007. The increase was primarily due to an increase in salaries of $2.4 million. In addition, we had increases of $0.8 million due to the internal investigation of the Transfers, an increase in rent of $0.5 million and an increase in accounting fees of $0.3 million. These increases were offset by a decrease in stock compensation of $2.8 million. The remaining increase was the result of the costs associated with Quest Energy being a separate publicly traded company.

Loss from Misappropriation of Funds

As disclosed previously, in connection with the Transfers, we have recorded a loss from misappropriation of funds of $0.5 million and $1.5 million for the three and nine month periods ended September 30, 2007, respectively.

Other Income (Expense)

Gain (loss) from derivative financial instruments. Gain from derivative financial instruments increased $131.7 million to $145.1 million during the three months ended September 30, 2008, from $13.4 million during the three months ended September 30, 2007. Due to the increase in average crude oil and natural gas prices during the third quarter of 2008, we recorded a $152.6 million unrealized gain and $7.5 million realized loss on our derivative contracts for the three months ended September 30, 2008 compared to a $9.7 million unrealized gain and $3.7 million realized gain for the three months ended September 30, 2007.

Gain from derivative financial instruments decreased $12.7 million to a loss of $4.5 million during the nine months ended September 30, 2008, from $8.2 million during the nine months ended September 30, 2007. Due to the increase in average crude oil and natural gas prices during the third quarter of 2008, we recorded a $13.3 million unrealized gain and $17.8 million realized loss on our derivative contracts for the nine months ended September 30,

2008 compared to a $3.1 million unrealized gain and $5.1 million realized gain for the nine months ended September 30, 2007.

Interest expense, net. Interest expense, net decreased $0.8 million, or 10.2%, to $7.2 million during the three months ended September 30, 2008, from $8.0 million during the three months ended September 30, 2007. The decrease was due to the refinancing of our credit facilities in 2007, lower outstanding borrowings, as well as lower interest rates during 2008.

Interest expense, net decreased $6.5 million, or 27.2%, to $17.2 for the nine months ended September 30, 2008 from $23.7 for the nine months ended September 30, 2007. The decrease was due to the refinancing of our credit facilities in 2007, lower outstanding borrowings, as well as lower interest rates in 2008.

Liquidity and Capital Resources

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

Cash flows from operations totaled $56.2 million for the nine months ended September 30, 2008, as compared to cash flows from operations of $31.8 million for the nine months ended September 30, 2007. The increase is attributable primarily to net cash from increased production and from higher average oil and natural gas prices in 2008 (although 2008 prices began to decline significantly in the third quarter of 2008) compared with average prices during 2007.

Cash Flows Used in Investing Activities. Net cash used in investing activities totaled $261.9 million for the nine months ended September 30, 2008 as compared to $103.4 million for the nine months ended September 30, 2007. The following table sets forth our capital expenditures by major categories for the nine months ended September 30, 2008.


	Nine Months Ended
	September 30, 2008
	(In thousands)
Capital expenditures:
Leasehold acquisition and development	$	78,344
Acquisition of PetroEdge		141,777
Acquisition of Seminole County, Oklahoma property		9,500
Pipelines		21,740
Other items		11,229

Total capital expenditures	$	262,590

Cash Flows from Financing Activities. Net cash provided by financing activities totaled $217.0 million for the nine months ended September 30, 2008 as compared to $49.3 million for the nine months ended September 30, 2007. The cash provided from financing activities was primarily due to net borrowings of $156.0 million and proceeds from issuance of common stock of $84.8 million, partially offset by $20.8 million of distributions to unitholders.

Working Capital Deficit. At September 30, 2008, we had current assets of $70.9 million. Our working capital (current assets minus current liabilities, excluding the short-term derivative asset and liability of $17.0 million and $3.2 million, respectively) was a deficit of $37.0 million at September 30, 2008, compared to a working capital (excluding the short-term derivative asset and liability of $8.0 million and $8.1 million, respectively) deficit of $12.4 million at December 31, 2007. This change is mostly due to the second lien term loan incurred by QELP in connection with the PetroEdge acquisition, which is reflected as current in the consolidated balance sheet as of September 30, 2008.

Credit Agreements

QRCP. On July 11, 2008, in connection with the PetroEdge acquisition, QRCP and Royal Bank of Canada (“RBC”) entered into an Amended and Restated Credit Agreement to convert QRCP’s then-existing $50 million revolving credit facility to a $35 million term loan, due and maturing on July 11, 2010 (the “Original Term Loan”). Thereafter, the parties entered into the following amendments to the credit agreement (collectively, with all amendments, the “Credit Agreement”):

	•		On October 24, 2008, QRCP and RBC entered into a First Amendment to Amended and Restated Credit Agreement, which, among other things, added a $6 million term loan (the “Additional Term Loan”) to the $35 million term loan under the Credit Agreement.

	•		On November 4, 2008, QRCP entered into a Second Amendment to the Credit Agreement (the “Second Amendment to Credit Agreement”) which clarified that the $6 million commitment under the Additional Term Loan would be reduced dollar for dollar to the extent QRCP retained net cash proceeds from dispositions in accordance with the terms of the Credit Agreement and it also amended and/or waived certain of the representations and covenants contained in the Credit Agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result of (1) the Transfers and (2) not timely settling certain intercompany accounts among QRCP, Quest Energy and Quest Midstream.

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

	•		On May 29, 2009, QRCP entered into a Fourth Amendment to Amended and Restated Credit Agreement that, among other things, waived certain events of default related to the financial covenants and collateral requirements under the Credit Agreement, extended certain financial reporting deadlines and permitted the settlement agreements with Mr. Cash discussed elsewhere herein and in QRCP’s 2008 Form 10-K.

	•		On June 30, 2009, QRCP entered into a Fifth Amendment to Amended and Restated Credit Agreement (the “Fifth Amendment to Credit Agreement”) that, among other things, amended and/or waived certain of the representations and covenants contained in the Credit Agreement.

Payments. The Original Term Loan is payable in quarterly installments of $1.5 million on the last business day of each March, June, September and December commencing on September 30, 2008, with the remaining principal amount being payable in full on July 11, 2010. As discussed in the next paragraph, QRCP has prepaid all of the quarterly principal payment requirements through June 30, 2009 and therefore has no quarterly principal payments due until September 30, 2009. If the outstanding amount of the Original Term Loan is at any time more than 50% of the market value of QRCP’s partnership interests in Quest Midstream and Quest Energy pledged to secure the loan plus the value of QRCP’s oil and gas properties (as defined in the Credit Agreement) pledged to secure the loan, QRCP will be required to either repay the term loan by the amount of such excess or pledge additional assets to secure the term loan.

on the last business day of December 2008, March 2009 and June 2009 (this was done in October and November 2008); third, subject to certain conditions being met and the net cash proceeds being received by January 31, 2009, up to $20 million for QRCP’s own use for working capital and to make capital expenditures for the development of its oil and gas properties; and fourth, any excess net cash proceeds to repay the Original Term Loan. The Third Amendment to Credit Agreement provided that in connection with the sale of QRCP’s Lycoming County, Pennsylvania acreage in February 2009, QRCP could retain all of the net proceeds from such sale in excess of $750,000. QRCP will be required to apply all of the net cash proceeds from the issuance of any debt and 50% of the net cash proceeds from the sale of any equity securities to first repay the Original Term Loan and then to QRCP.

Debt Balance at September 30, 2008. At September 30, 2008, $33.5 million was outstanding under the Original Term Loan and $0 million was outstanding under the Additional Term Loan because the Additional Term Loan was funded after that date. The Additional Term Loan was repaid on October 30, 2008.

The Credit Agreement’s financial covenants prohibit QRCP and any of its subsidiaries (excluding the Excluded MLP Entities) from:

•

permitting the interest coverage ratio (ratio of consolidated EBITDA (or consolidated annualized EBITDA for periods ending on or before December 31, 2008) to consolidated interest charges (or consolidated annualized

		interest charges for periods ending on or before December 31, 2008)) at any fiscal quarter-end, commencing with the quarter-ended September 30, 2008, to be less than 2.5 to 1.0 (calculated based on the most recently delivered compliance certificate); and

•		permitting the leverage ratio (ratio of consolidated funded debt to consolidated EBITDA (or consolidated annualized EBITDA for periods ending on or before December 31, 2008)) at any fiscal quarter-end, commencing with the quarter-ended September 30, 2008, to be greater than 2.0 to 1.0 (calculated based on the most recently delivered compliance certificate).

Consolidated EBITDA is defined in the Credit Agreement to mean for QRCP and its subsidiaries (excluding the Excluded MLP Entities) on a consolidated basis, an amount equal to the sum of (i) consolidated net income, (ii) consolidated interest charges, (iii) the amount of taxes, based on or measured by income, used or included in the determination of such consolidated net income, (iv) the amount of depreciation, depletion and amortization expense deducted in determining such consolidated net income, (v) merger and acquisition costs incurred by QRCP that are required to be expensed as a result of the termination of the merger agreement with Pinnacle Gas Resources, Inc., (vi) merger and acquisition costs required to be expensed under FAS 141(R), (vii) fees and expenses of the internal investigation relating to the Misappropriation Transaction (as defined in the First Amendment to Credit Agreement) and the related restructuring which were capped at $1,500,000 for purposes of this definition and (viii) other non-cash charges and expenses deducted in the determination of such consolidated net income, including, without limitation, non-cash charges and expenses relating to swap contracts or resulting from accounting convention changes, of QRCP and its subsidiaries (excluding the Excluded MLP Entities) on a consolidated basis, all determined in accordance with GAAP.

the SEC under the Securities Exchange Act of 1934) of 50% or more of QRCP’s outstanding shares of voting stock; provided, however, that a merger of QRCP into another entity in which the other entity is the survivor will not be deemed a change of control if QRCP’s stockholders of record as constituted immediately prior to such acquisition hold more than 50% of the outstanding shares of voting stock of the surviving entity.

Waivers. QRCP was in compliance with all of its financial covenants as of September 30, 2008. However, QRCP was not in compliance with all of its covenants as of December 31, 2008, March 31, 2009 or June 30, 2009, and QRCP does not anticipate that it will be in compliance at any time in the foreseeable future. On May 29, 2009, QRCP obtained a waiver of these defaults from its lender for the quarters ended December 31, 2008 and March 31, 2009 and on June 30, 2009, QRCP obtained a waiver of these defaults from its lender for the fiscal quarter ended June 30, 2009.

Quest Energy.

A. Quest Cherokee Credit Agreement.

	•		On April 15, 2008, Quest Energy and Quest Cherokee entered into a First Amendment to Amended and Restated Credit Agreement that, among other things, amended the interest rate and maturity date pursuant to the “market flex” rights contained in the commitment papers related to the Quest Cherokee Credit Agreement.

	•		On October 28, 2008, Quest Energy and Quest Cherokee entered into a Second Amendment to Amended and Restated Credit Agreement to amend and/or waive certain of the representations and covenants contained in the Quest Cherokee Credit Agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result of (1) the Transfers and (2) not timely settling certain intercompany accounts among QRCP, Quest Energy and Quest Midstream.

	•		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. (“BP”) or any of its affiliates to be secured by the liens under the credit agreement on a pari passu basis with the obligations under the credit agreement.

	•		On June 30, 2009, Quest Energy and Quest Cherokee entered into a Fourth Amendment to Amended and Restated Credit Agreement that deferred until August 15, 2009, Quest Energy’s obligation to deliver to RBC unaudited consolidated balance sheets and related statements of income and cash flows for the fiscal quarters ending September 30, 2008 and March 31, 2009.

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

B. Second Lien Loan Agreement.

•		On October 28, 2008, Quest Energy and Quest Cherokee entered into a First Amendment to Second Lien Senior Term Loan Agreement (the “First Amendment to Second Lien Loan Agreement”) to, among other things, extend the maturity date to September 30, 2009 and to amend and/or waive certain of the representations and covenants contained in the Second Lien Loan Agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result or (1) the Transfers and (2) not timely settling certain intercompany accounts among QRCP, Quest Energy and Quest Midstream.

•		On June 30, 2009, Quest Energy and Quest Cherokee entered into a Second Amendment to Second Lien Senior Term Loan Agreement that amended a covenant in order to defer until August 15, 2009, Quest Energy’s obligation to deliver to RBC unaudited consolidated balance sheets and related statements of income and cash flows for the fiscal quarters ending September 30, 2008 and March 31, 2009.

no assurance that such efforts will be successful or that the terms of any new or restructured indebtedness will be favorable to Quest Energy and Quest Cherokee.

C. General Provisions Applicable to Quest Cherokee Agreements.

The Quest Cherokee Agreements provide that all obligations arising under the loan documents, including obligations under any hedging agreement entered into with lenders or their affiliates or BP will be secured pari passu by the liens granted under the loan documents.

The Quest Cherokee Agreements’ financial covenants prohibit Quest Energy, Quest Cherokee and any of their subsidiaries from:

•		permitting the ratio (calculated based on the most recently delivered compliance certificate) of Quest Energy’s consolidated current assets (including the unused availability under the revolving credit facility, but excluding non-cash assets under FAS No. 133) to consolidated current liabilities (excluding non-cash obligations under FAS No. 133, asset and asset retirement obligations and current maturities of indebtedness under the Quest Cherokee Credit Agreement) at any fiscal quarter-end to be less than 1.0 to 1.0; provided, however, that current assets and current liabilities will exclude mark-to-market values of swap contracts, to the extent such values are included in current assets and current liabilities;

•		permitting the interest coverage ratio (calculated on the most recently delivered compliance certificate) of adjusted consolidated EBITDA to consolidated interest charges at any fiscal quarter-end to be less than 2.5 to 1.0 measured on a rolling four quarter basis; and

•		permitting the leverage ratio (calculated based on the most recently delivered compliance certificate) of consolidated funded debt to adjusted consolidated EBITDA at any fiscal quarter-end to be greater than 3.5 to 1.0 measured on a rolling four quarter basis.

capital leases, (iii) attributable indebtedness pertaining to synthetic lease obligations, and (iv) without duplication, all guaranty obligations with respect to indebtedness of the type specified in subsections (i) through (iii) above.

Quest Energy was in compliance with all of its covenants as of September 30, 2008.

Events of Default. Events of default under the Quest Cherokee Agreements are customary for transactions of this type and include, without limitation, non-payment of principal when due, non-payment of interest, fees and other amounts for a period of three business days after the due date, failure to perform or observe covenants and agreements (subject to a 30-day cure period in certain cases), representations and warranties not being correct in any material respect when made, certain acts of bankruptcy or insolvency, cross defaults to other material indebtedness, borrowing base deficiencies, and change of control. Under the Quest Cherokee Agreements, a change of control means (i) QRCP fails to own or to have voting control over at least 51% of the equity interest of Quest Energy GP, (ii) any person acquires beneficial ownership of 51% or more of the equity interest in Quest Energy; (iii) Quest Energy fails to own 100% of the equity interests in Quest Cherokee, or (iv) QRCP undergoes a change in control (the acquisition by a person, or two or more persons acting in concert, of beneficial ownership of 50% or more of QRCP’s outstanding shares of voting stock, except for a merger with and into another entity where the other entity is the survivor if QRCP’s stockholders of record immediately preceding the merger hold more than 50% of the outstanding shares of the surviving entity).

Quest Midstream. Quest Midstream and its wholly-owned subsidiary, Bluestem Pipeline, LLC (“Bluestem”) have a separate $135 million syndicated revolving credit facility. On November 1, 2007, Quest Midstream and Bluestem entered into an Amended and Restated Credit Agreement and First Amendment to Amended and Restated Credit Agreement (together, the “Quest Midstream Credit Agreement”) with RBC, as administrative agent and collateral agent, and the lenders party thereto. On October 28, 2008, Quest Midstream and Bluestem entered into a Second Amendment to the Quest Midstream Credit Agreement (the “Quest Midstream Second Amendment”). The Quest Midstream Credit Agreement together with the Quest Midstream Second Amendment are referred to collectively as the “Amended Quest Midstream Credit Agreement.” As of September 30, 2008, the amount borrowed under the Amended Quest Midstream Credit Agreement was $128.0 million.

quarter, any reductions in the revolving commitments will be reinstated and no further prepayments will be required.

The Amended Quest Midstream Credit Agreement’s financial covenants prohibit Bluestem, Quest Midstream and any of their subsidiaries from:

•		permitting the interest coverage ratio (ratio of adjusted consolidated EBITDA to consolidated interest charges) on a rolling four quarter basis (calculated based on the most recently delivered compliance certificate), commencing with the fiscal quarter ending December 31, 2007, to be less than 2.50 to 1.00 for any fiscal quarter ending on or prior to December 31, 2008, increasing to 2.75 to 1.00 for each fiscal quarter end thereafter; and

•		permitting the total leverage ratio (ratio of adjusted consolidated funded debt to adjusted consolidated EBITDA) on a rolling four quarter basis (calculated based on the most recently delivered compliance certificate), commencing with the fiscal quarter ending December 31, 2007 and ending December 31, 2008, to be greater than 5.00 to 1.00, decreasing to 4.50 to 1.00 for each fiscal quarter end thereafter.

(ii) consolidated interest charges, (iii) the amount of taxes, based on or measured by income, used or included in the determination of consolidated net income, (iv) the amount of depreciation, depletion and amortization expense deducted in determining consolidated net income, (v) merger and acquisition costs required to be expensed under FAS No. 141(R), (vi) fees and expenses of the internal investigation relating to the Misappropriation Transaction (as defined in Quest Midstream Second Amendment) and the related restructuring which are capped at $1,500,000 for purposes of the definition of Consolidated EBITDA and (vii) other non-cash charges and expenses, including, without limitation, non-cash charges and expenses related to swap contracts or resulting from accounting convention changes, of Quest Midstream and its subsidiaries on a consolidated basis, all determined in accordance with GAAP.

Quest Midstream was in compliance with all of its covenants as of September 30, 2008.

Contractual Obligations

We have numerous contractual commitments in the ordinary course of business, debt service requirements and operating lease commitments. The following table summarizes these commitments at September 30, 2008:


	Payments Due by Period
			Less Than		1-3		4-5		More Than
	Total		1 Year		Years		Years		5 Years
	(In thousands)
Term Loan — QRCP		33,500		1,500		—		32,000		—
Revolving Credit Facility — Quest Energy		183,000		—		183,000		—		—
Term Loan — Quest Energy		45,000		45,000		—		—		—
Revolving Credit Facility — Quest Midstream		128,000		—		—		128,000		—
Other Note obligations		177		25		111		33		8
Interest expense on bank credit facilities(1)		68,294		24,071		33,462		10,761		—
Operating lease obligations		13,243		4,934		2,995		2,413		2,901

Total commitments	$	468,539	$	74,855	$	217,568	$	173,207	$	2,909


(1)		The interest payment obligation was computed using the LIBOR interest rate as of September 30, 2008. Assumes no reduction in the outstanding principal amount borrowed under the revolving credit facilities prior to maturity.

Off-balance Sheet Arrangements

At September 30, 2008, we did not have any relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. In addition, we do not engage in trading activities involving non-exchange traded contracts. As such, we are not exposed to any financing, liquidity, market, or credit risk that could arise if we had engaged in such activities.

Critical Accounting Policies

The preparation of our consolidated financial statements requires us to make assumptions and estimates that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. We base our estimates on historical experiences and various other assumptions that we believe are reasonable; however, actual results may differ. Our significant accounting policies are described in Note 2 — Summary of Significant Accounting Policies to our consolidated financial statements included in the 2008 Form 10-K. See also Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies” in our 2008 Form 10-K.

Recent Accounting Pronouncements

In February 2008, the FASB issued Staff Position FAS 157-2, Effective Date of FASB Statement No. 157 (“FSP 157-2”). FSP 157-2 delays the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those recognized or disclosed at fair value in the financial statements on a recurring basis, at least annually. The adoption of FSP 157-2 is not expected to have a material impact on our financial condition, operations or cash flows.

In December 2007, FASB issued SFAS No. 141(R), Business Combinations, which replaces SFAS No. 141. SFAS No. 141(R) establishes principles and requirements for how the acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree. In addition, SFAS No. 141(R) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase. SFAS No. 141(R) also establishes disclosure requirements to enable users to evaluate the nature and financial effects of the business combination. SFAS No. 141(R) is effective as of the beginning of an entity’s fiscal year that begins after December 15, 2008 (January 1, 2009 for QRCP), with early adoption prohibited. The adoption of SFAS No. 141R did not have a material affect on our results of operations, cash flows or financial position as of January 1, 2009.

In December 2007, the FASB issued SFAS No. 160, Non-controlling Interests in Consolidated Financial Statements — An Amendment of ARB No. 51. SFAS No. 160 establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the non-controlling interest, and changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary. In addition, SFAS No. 160 establishes principles for valuation of retained non-controlling equity investments and measurement of gain or loss when a subsidiary is deconsolidated. SFAS No. 160 also establishes disclosure requirements to clearly identify and distinguish between interests of the parent and the interests of the non-controlling owners. SFAS No. 160 is effective for fiscal years and interim periods beginning after December 15, 2008, with early adoption prohibited. Under SFAS No. 160, QRCP will be required to classify the minority interest liability reflected in the accompanying consolidated balance sheet as a component of stockholders’ equity and will be required to present net income attributable to QRCP and the minority partners’ ownership interest separately on the consolidated statement of operations. We are currently assessing any other impact this standard will have on our results of operations, cash flows and financial position.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 133 (“SFAS 161”). This statement does not change the accounting for derivatives but will require enhanced disclosures about derivative strategies and accounting practices. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008, and we will comply with any necessary disclosure requirements beginning with the interim financial statements for the three months ended March 31, 2009.

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.

Forward-Looking Statements

Various statements in this report, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These include such matters as projections and estimates concerning the timing and success of specific projects; financial position; business strategy; budgets; amount, nature and timing of capital expenditures; drilling of wells and construction of pipeline infrastructure; acquisition and development of oil and natural gas properties and related pipeline infrastructure; timing and amount of future production of oil and gas; operating costs and other expenses; estimated future net revenues from oil and natural gas reserves and the present value thereof; cash flow and anticipated liquidity; and other plans and objectives for future operations.

When we use the words “believe,” “intend,” “expect,” “may,” “will,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The factors impacting these risks and uncertainties include, but are not limited to:

	•		current financial instability and deteriorating economic conditions;

	•		our current financial instability;

	•		volatility of oil and gas prices;

	•		completion of the Recombination;

	•		increases in the cost of drilling, completion and gas gathering or other costs of developing and producing our reserves;

	•		our restrictive debt covenants;

	•		results of our hedging activities;

	•		drilling, operational and environmental risks; and

	•		regulatory changes and litigation risks.

You should consider carefully the statements in Item 1A. “Risk Factors” in our 2008 Form 10-K and other sections of this report, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements.

We have based these forward-looking statements on our current expectations and assumptions about future events. The forward-looking statements in this report speak only as of the date of this report; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. Readers are urged to carefully review and consider the various disclosures made by us in our reports filed with the SEC, which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operation and cash flows. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those expected or projected.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Commodity Price Risk

Our most significant market risk is commodity risk. We seek to mitigate this risk through the use of fixed price contracts.

The following tables summarize the estimated volumes, fixed prices and fair value attributable to oil and gas derivative contracts as of September 30, 2008:


	Remainder of			Years Ending December 31,
	2008			2009			2010			2011		2012		Total
	(in thousands, except volumes and per unit data)
Natural Gas Swaps:
Contract volumes (Mmbtu)		2,829,828			14,629,200			12,499,060			2,000,004		2,000,004		33,958,096
Weighted-average fixed price per Mmbtu	$	6.98		$	7.78		$	7.42		$	8.00	$	8.11	$	7.62

Fair value, net	$	4,011		$	6,421		$	(5,056	)	$	202	$	479	$	6,057
Natural Gas Collars:
Contract volumes (Mmbtu):
Floor		1,766,492			750,000			630,000			3,549,996		3,000,000		9,696,488
Ceiling		1,766,492			750,000			630,000			3,549,996		3,000,000		9,696,488
Weighted-average fixed price per Mmbtu:
Floor	$	6.54		$	11.00		$	10.00		$	7.39	$	7.00	$	7.56
Ceiling	$	7.53		$	15.00		$	13.11		$	9.88	$	9.60	$	9.97
Fair value, net	$	963		$	2,280		$	1,162		$	635	$	238	$	5,278
Total Natural Gas Contracts:
Contract volumes (Mmbtu)		4,596,320			15,379,200			13,129,060			5,550,000		5,000,004		43,654,584
Weighted-average fixed price per Mmbtu	$	6.81		$	7.94		$	6.59		$	7.61	$	7.44	$	7.31

Fair value, net	$	4,974		$	8,701		$	(3,894	)	$	837	$	717	$	11,335
Crude Oil Swaps:
Contract volumes (Bbl)		9,000			36,000			30,000			—		—		75,000
Weighted-average fixed price per Bbl	$	95.92		$	90.07		$	87.50		$	—	$	—	$	89.74
Fair value, net	$	(41	)	$	(432	)	$	(493	)	$	—	$	—	$	(966	)

Interest Rate Risk

As of September 30, 2008, we had outstanding $389.7 million of variable-rate debt. A 1% increase in our interest rates would increase gross interest expense approximately $3.9 million per year. As of September 30, 2008, we did not have any interest rate hedging activities.

ITEM 4. CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms and that such information is accumulated and communicated to management, including the principal executive officer and the principal financial officer, to allow timely decisions regarding required disclosures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of the achieving their control objectives.

In connection with the preparation of our 2008 Form 10-K and this Quarterly Report on Form 10-Q, our management, under the supervision and with the participation of the current principal executive officer and current principal financial officer, conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of September 30, 2008. Based on that evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective as of September 30, 2008. Notwithstanding this determination, our management believes that the consolidated financial statements in this Quarterly Report on Form 10-Q fairly present, in all material respects, our financial position and results of operations and cash flows as of the dates and for the periods presented, in conformity with GAAP.

Management identified the following control deficiencies that constituted material weaknesses as of September 30, 2008:

(1)

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

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

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

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

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

(2)

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

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

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

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

(3)

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

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

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

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

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

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

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

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

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

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

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

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

Remediation Plan

Our management, under new leadership as described below, has been actively engaged in the planning for, and implementation of, remediation efforts to address the material weaknesses, as well as other identified areas of risk. These remediation efforts, outlined below, are intended both to address the identified material weaknesses and to enhance our overall financial control environment. In August 2008, Mr. David Lawler was appointed President (and in May 2009 was appointed as our Chief Executive Officer) (our principal executive officer) and in September 2008, Mr. Jack Collins was appointed Chief Compliance Officer. In January 2009, Mr. Eddie LeBlanc was appointed Chief Financial Officer (our principal financial and accounting officer). The design and implementation of these and other remediation efforts are the commitment and responsibility of this new leadership team.

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

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

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

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

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

Changes in Internal Control Over Financial Reporting

Except as described above, there were no other changes in internal control over financial reporting during the quarter ended September 30, 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

We are subject, from time to time, to certain legal proceedings and claims in the ordinary course of conducting our business. As of September 30, 2008, as a result of the Transfers and the restatements of our financial statements, we are involved in litigation outside the ordinary course of our business. Except for those legal proceedings listed in Part I, Item I, Note 8 to our consolidated financial statements, entitled “Commitments and Contingencies,” which is incorporated herein by reference, we believe there are no pending legal proceedings in which we are currently involved which, if adversely determined, could have a material adverse effect on our financial position, results of operations or cash flow. Like other oil and natural 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.

ITEM 1A. RISK FACTORS.

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

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

None

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None

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

No matters were submitted to a vote of security holders during the third quarter of 2008.

ITEM 5. OTHER INFORMATION.

None.

ITEM 6. EXHIBITS


2.1*		Agreement for Purchase and Sale, dated July 11, 2008, by and among QRCP, Quest Eastern Resource LLC and Quest Cherokee LLC (incorporated herein by reference to Exhibit 2.1 to QRCP’s Current Report on Form 8-K filed on July 16, 2008).

10.1*		Employment Agreement dated July 14, 2008 between QRCP and Tom Lopus (incorporated herein by reference to Exhibit 10.15 to QRCP’s Quarterly Report on Form 10-Q filed on August 11, 2008).

10.2*		Amended and Restated Credit Agreement, dated as of July 11, 2008, by and among QRCP, as the Borrower, Royal Bank of Canada, as Administrative Agent and Collateral Agent, and the lenders from time to time party thereto (incorporated herein by reference to Exhibit 10.1 to QRCP’s Current Report on Form 8-K filed on July 16, 2008).


10.3*		First Amendment to Pledge and Security Agreement for Amended and Restated Credit Agreement by QRCP for the benefit of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.4 to QRCP’s Current Report on Form 8-K filed on July 16, 2008).

10.4*		Pledge and Security Agreement for Amended and Restated Credit Agreement by Quest Eastern Resource LLC for the benefit of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.2 to QRCP’s Current Report on Form 8-K filed on July 16, 2008).

10.5*		Pledge and Security Agreement for Amended and Restated Credit Agreement, dated as of July 11, 2008, by Quest Mergersub, Inc., for the benefit of Royal Bank of Canada (incorporated herein by reference to Exhibit 10.3 to QRCP’s Current Report on Form 8-K filed on July 16, 2008).

10.6*		Guaranty for Amended and Restated Credit Agreement by Quest Eastern Resource LLC in favor of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.5 to QRCP’s Current Report on Form 8-K filed on July 16, 2008).

10.7*		Guaranty for Amended and Restated Credit Agreement by Quest MergerSub, Inc. in favor of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.6 to QRCP’s Current Report on Form 8-K filed on July 16, 2008).

10.8*		Second Lien Senior Term Loan Agreement, dated as of July 11, 2008, by and among Quest Cherokee, LLC, Quest Energy Partners, L.P., Royal Bank of Canada, KeyBank National Association, Société Générale, the lenders party thereto and RBC Capital Markets (incorporated herein by reference to Exhibit 10.7 to QRCP’s Current Report on Form 8-K filed on July 16, 2008).

10.9*		Guaranty for Second Lien Term Loan Agreement by Quest Cherokee Oilfield Service, LLC in favor of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.8 to QRCP’s Current Report on Form 8-K filed on July 16, 2008).

10.10*		Guaranty for Second Lien Term Loan Agreement by Quest Energy Partners, L.P. in favor of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.9 to QRCP’s Current Report on Form 8-K filed on July 16, 2008).

10.11*		Pledge and Security Agreement for Second Lien Term Loan Agreement by Quest Cherokee Oilfield Service, LLC for the benefit of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.10 to QRCP’s Current Report on Form 8-K filed on July 16, 2008).

10.12*		Pledge and Security Agreement for Second Lien Term Loan Agreement by Quest Energy Partners, L.P. for the benefit of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.11 to QRCP’s Current Report on Form 8-K filed on July 16, 2008).

10.13*		Pledge and Security Agreement for Second Lien Term Loan Agreement by Quest Cherokee, LLC for the benefit of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.12 to QRCP’s Current Report on Form 8-K filed on July 16, 2008).

10.14*		Intercreditor Agreement, dated as of July 11, 2008, by and between Royal Bank of Canada and Quest Cherokee, LLC (incorporated herein by reference to Exhibit 10.13 to QRCP’s Current Report on Form 8-K filed on July 16, 2008).

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

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

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

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


*		Incorporated by reference.

PLEASE NOTE: Pursuant to the rules and regulations of the Securities and Exchange Commission, we have filed or incorporated by reference the agreements referenced above as exhibits to this Quarterly Report on Form 10-Q. The agreements have been filed to provide investors with information regarding their respective terms. The agreements are not intended to provide any other factual information about the Company or its business or operations. In particular, the assertions embodied in any representations, warranties and covenants contained in the agreements may be subject to qualifications with respect to knowledge and materiality different from those applicable to investors and may be qualified by information in confidential disclosure schedules no included with the exhibits. These disclosure schedules may contain information that modifies, qualifies and creates exceptions to the representations, warranties and covenants set forth in the agreements. Moreover, certain representations, warranties and covenants in the agreements may have been used for the purpose of allocating risk between the parties, rather than establishing matters as facts. In addition, information concerning the subject matter of the representations, warranties and covenants may have changed after the date of the respective agreement, which subsequent information may or may not be fully reflected in the Company’s public disclosures. Accordingly, investors should not rely on the representations, warranties and covenants in the agreements as characterizations of the actual state of facts about the Company or its business or operations on the date hereof.


PART I — FINANCIAL INFORMATION
Item 1. Financial Statements			2
Consolidated Balance Sheets:			F-1
September 30, 2008 and December 31, 2007
Consolidated Statements of Operations:			F-2
Three Months and Nine Months Ended September 30, 2008 and 2007
Consolidated Statements of Cash Flows:			F-3
Nine Months Ended September 30, 2008 and 2007
Condensed Notes to Consolidated Financial Statements			F-4
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			3
Item 3. Quantitative and Qualitative Disclosures About Market Risk			29
Item 4. Controls and Procedures			30

PART II — OTHER INFORMATION
Item 1. Legal Proceedings			33
Item 1A. Risk Factors			33
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			33
Item 3. Defaults Upon Senior Securities			33
Item 4. Submission of Matters to a Vote of Security Holders			33
Item 5. Other Information			33
Item 6. Exhibits			33
SIGNATURES			35
EX-31.1
EX-31.2
EX-32.1
EX-32.2


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


	By:	/s/ Eddie M. LeBlanc, III
		Eddie M. LeBlanc, III
		Chief Financial Officer (principal financial and accounting officer)