UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


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

For the quarterly period ended ~~June~~September 30, 2009.

Commission file number: 0-17371

QUEST RESOURCE CORPORATION

(Exact name of registrant as specified in its charter)

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


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

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

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

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

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

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

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

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

As of ~~August 12~~November 2, 2009, the issuer had 32,~~025~~042,~~976~~642 shares of common stock outstanding.

QUEST RESOURCE CORPORATION ~~FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2009~~

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2009

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008			F-1
Condensed Consolidated Balance Sheets as of September 30, 2009 and December 31, 2008			F-1
Condensed Consolidated Statements of Operations for the Three Months and Six Months Ended June 30, 2009 and 2008			F-2
Condensed Consolidated Statements of Operations for the Three Months and Nine Months Ended September 30, 2009 and 2008			F-2
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2009 and 2008			F-3
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2009 and 2008			F-3
Condensed Consolidated Statements of Stockholders’ Equity for the Six Months Ended June 30, 2009			F-4
Condensed Consolidated Statements of Equity for the Nine Months Ended September 30, 2009			F-4
Notes to Condensed Consolidated Financial Statements			F-5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			21
Item 3. Quantitative and Qualitative Disclosures About Market Risk			1615
Item 4. Controls and Procedures			16
PART II — OTHER INFORMATION
Item 1. Legal Proceedings			2019
Item 1A. Risk Factors			2019
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			2046
Item 3. Defaults Upon Senior Securities			2046
Item 4. Submission of Matters to a Vote of Security Holders			2046
Item 5. Other Information			2046
Item 6. Exhibits			2047
SIGNATURES			2148
EX-10.5
EX-31.1
EX-31.2
EX-32.1
EX-32.2

~~QUEST~~PART ~~RESOURCE~~I ~~CORPORATION~~— FINANCIAL INFORMATION

~~CONDENSED~~Item ~~CONSOLIDATED~~1. ~~BALANCE~~Financial ~~SHEETS (in thousands, except share and per share data)~~ Statements

	June 30,			December 31,
	2009			2008
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	42,413		$	13,785
Restricted cash		760			559
Accounts receivable — trade, net		15,392			16,715
Other receivables		7,932			9,434
Other current assets		2,473			2,858
Inventory		11,235			11,420
Current derivative financial instrument assets		35,123			42,995
Total current assets		115,328			97,766
Oil and gas properties under full cost method of accounting, net		49,413			172,537
Pipeline assets, net		305,299			310,439
Other property and equipment, net		21,514			23,863
Other assets, net		11,080			14,735
Long-term derivative financial instrument assets		1,876			30,836
Total assets	$	504,510		$	650,176
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	17,284		$	35,804
Revenue payable		8,901			8,309
Accrued expenses		8,955			7,138
Current portion of notes payable		54,970			45,013
Current derivative financial instrument liabilities		411			12
Total current liabilities		90,521			96,276
Non-current liabilities:
Long-term derivative financial instrument liabilities		8,153			4,230
Asset retirement obligations		6,211			5,922
Notes payable		307,722			343,094
Commitments and contingencies
Stockholders’ equity (deficit):
Preferred stock, $0.001 par value; authorized shares — 50,000,000; none issued and outstanding		—			—
Common stock, $0.001 par value; authorized shares — 200,000,000; issued — 32,193,531 and 32,224,643 at June 30, 2009 and December 31, 2008; outstanding — 31,869,279 and 31,720,312 at June 30, 2009 and December 31, 2008, respectively		33			33
Additional paid-in capital		299,031			298,583
Treasury stock, at cost		(7	)		(7	)
Accumulated deficit		(371,896	)		(302,491	)
Total stockholders’ deficit before non-controlling interests		(72,839	)		(3,882	)
Non-controlling interests		164,742			204,536
Total stockholders’ equity		91,903			200,654
Total liabilities and stockholders’ equity	$	504,510		$	650,176

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


	September 30, 2009			December 31, 2008
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	33,948		$	13,785
Restricted cash		702			559
Accounts receivable — trade, net		10,561			16,715
Other receivables		3,474			9,434
Other current assets		1,643			2,858
Inventory		10,800			11,420
Current derivative financial instrument assets		19,625			42,995

Total current assets		80,753			97,766
Oil and gas properties under full cost method of accounting, net		43,048			172,537
Pipeline assets, net		302,572			310,439
Other property and equipment, net		20,358			23,863
Other assets, net		8,188			14,735
Long-term derivative financial instrument assets		4,653			30,836

Total assets	$	459,572		$	650,176

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	15,747		$	35,804
Revenue payable		4,281			8,309
Accrued expenses		7,434			7,138
Current portion of notes payable		41,019			45,013
Current derivative financial instrument liabilities		1,413			12

Total current liabilities		69,894			96,276

Long-term derivative financial instrument liabilities		5,294			4,230
Asset retirement obligations		6,346			5,922
Notes payable		302,535			343,094

Commitments and contingencies
Equity:
Preferred stock, $0.001 par value; authorized shares — 50,000,000; none issued and outstanding		—			—
Common stock, $0.001 par value; authorized shares — 200,000,000; issued — 32,073,132 and 32,224,643 at September 30, 2009 and December 31, 2008, respectively, outstanding — 31,890,945 and 31,720,312 at September 30, 2009 and December 31, 2008, respectively		33			33
Additional paid-in capital		299,134			298,583
Treasury stock, at cost		(7	)		(7	)
Accumulated deficit		(383,423	)		(302,491	)

Total stockholders’ deficit before non-controlling interests		(84,263	)		(3,882	)
Non-controlling interests		159,766			204,536

Total equity		75,503			200,654

Total liabilities and equity	$	459,572		$	650,176

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

F-1

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

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


	For the Three months ended						For the Nine months ended
	September 30,						September 30,
	2009			2008			2009			2008
Revenue:
Oil and gas sales	$	18,329		$	49,531		$	56,711		$	136,989
Gas pipeline revenue		5,633			7,512			21,022			21,561

Total revenues		23,962			57,043			77,733			158,550
Costs and expenses:
Oil and gas production		8,739			9,963			23,699			33,000
Pipeline operating		8,243			7,737			22,264			22,859
General and administrative		11,337			4,638			29,705			16,579
Depreciation, depletion and amortization		14,068			18,353			39,274			49,686
Impairment of oil and gas properties		—			—			102,902			—
Recovery of misappropriated funds, net of liabilities assumed		(9	)		—			(3,406	)		—

Total costs and expenses		42,378			40,691			214,438			122,124

Operating income (loss)		(18,416	)		16,352			(136,705	)		36,426
Other income (expense):
Gain (loss) from derivative financial instruments		8,752			145,132			31,078			(4,482	)
Other income (expense), net		(140	)		59			(1	)		181
Interest expense, net		(6,920	)		(7,187	)		(20,666	)		(17,244	)

Total other income (expense)		1,692			138,004			10,411			(21,545	)

Income (loss) before income taxes and non-controlling interests		(16,724	)		154,356			(126,294	)		14,881
Income tax expense		—			—			—			—

Net income (loss)		(16,724	)		154,356			(126,294	)		14,881
Net (income) loss attributable to non-controlling interest		5,197			(66,505	)		45,362			(10,011	)

Net income (loss) attributable to controlling interest	$	(11,527	)	$	87,851		$	(80,932	)	$	4,870

Net income (loss) per common share:
Basic	$	(0.36	)	$	2.75		$	(2.54	)	$	0.18
Diluted	$	(0.36	)	$	2.75		$	(2.54	)	$	0.18
Weighted average shares outstanding:
Basic		31,885			31,920			31,828			26,481

Diluted		31,885			31,920			31,828			26,481

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Revenue:
Oil and gas sales	$	16,107		$	49,144		$	38,382		$	87,458
Gas pipeline revenue		7,586			7,148			15,389			14,049
Total revenues		23,693			56,292			53,771			101,507
Costs and expenses:
Oil and gas production		7,274			12,631			14,960			23,037
Pipeline operating		6,861			8,164			14,021			15,122
General and administrative		10,486			6,198			18,368			11,941
Depreciation, depletion and amortization		9,086			16,444			25,206			31,333
Impairment of oil and gas properties		—			—			102,902			—
Recovery of misappropriated funds, net of liabilities assumed		(3,397	)		—			(3,397	)		—
Total costs and expenses		30,310			43,437			172,060			81,433
Operating income (loss)		(6,617	)		12,855			(118,289	)		20,074
Other income (expense):
Gain (loss) from derivative financial instruments		(17,138	)		(105,375	)		22,326			(149,614	)
Loss on sale of assets		—			(30	)		—			—
Other income (expense)		83			72			139			122
Interest expense		(6,858	)		(5,174	)		(13,746	)		(10,057	)
Total other income (expense)		(23,913	)		(110,507	)		8,719			(159,549	)
Loss before income taxes		(30,530	)		(97,652	)		(109,570	)		(139,475	)
Income tax expense		—			—			—			—
Net loss	$	(30,530	)	$	(97,652	)	$	(109,570	)	$	(139,475	)
Net loss attributable to noncontrolling interests	$	12,511		$	39,766		$	40,165		$	56,494
Net loss attributable to common stockholders	$	(18,019	)	$	(57,886	)	$	(69,405	)	$	(82,981	)
Basic and diluted net loss attributable to common stockholders per common share	$	(0.57	)	$	(2.53	)	$	(2.18	)	$	(3.65	)
Basic and diluted weighted average shares outstanding		31,867,857			22,844,600			31,798,546			22,742,289

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

F-2

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

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


	For the Nine Months Ended
	September 30,
	2009			2008
Cash flows from operating activities:
Net income (loss)	$	(126,294	)	$	14,881
Adjustments to reconcile net income (loss) to cash provided by operations:
Depreciation, depletion and amortization		39,274			49,686
Stock-based compensation		1,143			2,107
Impairment of oil and gas properties		102,902			—
Amortization of deferred loan costs		4,109			1,578
Change in fair value of derivative financial instruments		52,018			(13,313	)
Bad debt expense		—			96
Recovery of misappropriated funds, net of liabilities assumed		(977	)		—
Loss (gain) on disposal of property and equipment		83			(7	)
Change in assets and liabilities:
Accounts receivable		6,154			6,529
Other receivables		5,960			(2,821	)
Other current assets		1,215			(1,351	)
Other assets		153			1,453
Accounts payable		(20,221	)		6,792
Revenue payable		(4,140	)		(6,523	)
Accrued expenses		3,211			(3,160	)
Other long-term liabilities		—			472
Other		(2	)		(255	)

Cash flows from operating activities		64,588			56,164

Cash flows from investing activities:
Restricted cash		(143	)		677
Proceeds from sale of oil and gas properties		8,846			—
Acquisition of business — PetroEdge		—			(141,777	)
Equipment, development, leasehold and pipeline		(6,363	)		(120,813	)

Cash flows from investing activities		2,340			(261,913	)

Cash flows from financing activities:
Proceeds from bank borrowings		1,430			84,000
Repayments of note borrowings		(13,854	)		(50,035	)
Proceeds from revolver note		1,500			122,000
Repayments of revolver note		(35,272	)		—
Distributions to unitholders		—			(20,770	)
Refinancing costs		(569	)		(3,018	)
Proceeds from issuance of common stock		—			84,801

Cash flows from financing activities		(46,765	)		216,978

Net increase in cash		20,163			11,229
Cash and cash equivalents beginning of period		13,785			6,680

Cash and cash equivalents end of period	$	33,948		$	17,909

	Six Months Ended
	June 30,
	2009			2008
Cash flows from operating activities:
Net loss	$	(109,570	)	$	(139,475	)
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation, depletion and amortization		25,206			31,333
Impairment of oil and gas properties		102,902			—
Stock-based compensation		448			3,045
Stock-based compensation — non-controlling interests		371			243
Amortization of deferred loan costs		2,097			1,052
Change in fair value of derivative financial instruments		41,154			139,344
Bad debt expense		—			73
Non-cash portion of gain on recovery of misappropriated funds		(977	)		—
Change in assets and liabilities:
Accounts receivable		1,322			(877	)
Other receivables		2,336			(1,986	)
Other current assets		386			(1,037	)
Other assets		116			(341	)
Accounts payable		(16,152	)		13,763
Revenue payable		480			227
Accrued expenses		1,817			4,884
Other long-term liabilities		(1	)		427
Other		(57	)		(427	)
Net cash flows from operating activities		51,878			50,248
Cash flows from investing activities:
Change in restricted cash		(201	)		783
Equipment, development, leasehold and pipeline additions		(5,256	)		(98,000	)
Proceeds from sale of oil and gas properties		8,730			—
Net cash flows from investing activities		3,273			(97,217	)
Cash flows from financing activities:
Proceeds from bank borrowings		1,430			4,000
Repayments of note borrowings		(9,662	)		(313	)
Proceeds from revolver		—			75,000
Repayment of revolver		(17,902	)		—
Distributions to unitholders		—			(16,845	)
Refinancing costs		(389	)		—
Net cash flows from financing activities		(26,523	)		61,842
Net increase in cash		28,628			14,873
Cash and cash equivalents, beginning of period		13,785			6,680
Cash and cash equivalents, end of period	$	42,413		$	21,553

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

F-3

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

CONDENSED CONSOLIDATED STATEMENT OF EQUITY FOR THE SIX MONTHS ENDED JUNE 30, 2009 (Amounts subsequent to December 31, 2008 are unaudited) (in thousands)


											Total
											Stockholders’
			Additional								Deficit Before
	Common		Paid-in		Treasury			Accumulated			Non-controlling			Non-controlling			Total
	Stock		Capital		Stock			Deficit			Interests			Interests			Equity
Balance, December 31, 2008	$	33	$	298,583	$	(7	)	$	(302,491	)	$	(3,882	)	$	204,536		$	200,654
Stock based compensation		—		551		—			—			551			592			1,143
Net loss		—		—		—			(80,932	)		(80,932	)		(45,362	)		(126,294	)

Balance, September 30, 2009	$	33	$	299,134	$	(7	)	$	(383,423	)	$	(84,263	)	$	159,766		$	75,503

											Total
											Stockholders’
			Additional								Deficit Before						Total
	Common		Paid-in		Treasury			Accumulated			Non-controlling			Non-controlling			Stockholders’
	Stock		Capital		Stock			Deficit			Interests			Interests			Equity
Balance, December 31, 2008	$	33	$	298,583	$	(7	)	$	(302,491	)	$	(3,882	)	$	204,536		$	200,654
Stock based compensation				448		—			—			448			371			819
Net loss		—		—		—			(69,405	)		(69,405	)		(40,165	)		(109,570	)
Balance, June 30, 2009	$	33	$	299,031	$	(7	)	$	(371,896	)	$	(72,839	)	$	164,742		$	91,903

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

F-4

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

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2009
(Unaudited)

Note 1 — Basis of Presentation

These condensed consolidated financial statements have been prepared by Quest Resource Corporation (“QRCP” or the “Company”) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), and reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for the interim periods, on a ~~basis~~ basis consistent with the annual audited consolidated financial statements. All such adjustments are of a ~~normal~~ normal recurring nature. In addition, the Company also recorded a $0.8 million write-off of unamortized debt issuance costs associated with the modification of its term loan (See Note 3 — Long Term Debt). Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and the summary of significant accounting policies and notes included in the Company’s Annual Report on Form 10-K/A for the year ended December 31, 2008 (the “2008 Form 10-K/A”).

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

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

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

In December 2007, the Financial Accounting Standards Board (the “FASB”) issued ~~Statement~~FASB ~~of Financial~~ Accounting ~~Standards~~ ~~(“SFAS”)~~Standards ~~No. 160,~~Codification ~~Non-controlling Interests in Consolidated Financial Statements — An Amendment of ARB No. 51~~ (“~~SFAS~~FASB ~~160~~ASC”). ~~SFAS~~810 NoConsolidation. ~~160~~ FASB ASC 810 establishes accounting ~~and~~ 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~~FASB ~~No. 160~~ASC 810 establishes principles for valuation of retained non-controlling equity investments and measurement of gain or loss when a subsidiary is deconsolidated. ~~SFAS~~FASB ~~No. 160~~ASC 810-10 also establishes disclosure requirements to clearly identify and distinguish between interests of the parent and the interests of the non-controlling owners. The Company adopted ~~SFAS~~FASB ~~No. 160~~ASC 810 effective January 1, 2009. Under ~~SFAS~~FASB ~~No.~~ASC ~~160~~810, QRCP is required to classify amounts previously presented as a minority interest liability as a component of equity in the condensed consolidated balance sheet and is required to present net income (loss) attributable to QRCP and the ~~minority~~noncontrolling partners’ ownership interest separately in the condensed consolidated statement of operations. All prior periods have been reclassified to comply ~~with~~ ~~SFAS~~with ~~No.~~FASB ~~160~~ASC 810.

Going Concern

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

QRCP is almost exclusively dependent upon distributions from its partnership interests in Quest Energy Partners, L.P. (“QELP” or “Quest Energy”) and Quest Midstream Partners, L.P. (“QMLP” or “Quest Midstream”) for cash flow. Quest Midstream has not paid any distributions on any of its units since the second quarter of 2008, and Quest Energy suspended its distributions on its subordinated units ~~since~~starting with the third quarter of 2008 and all units starting with the fourth quarter of 2008. QRCP does not expect to receive any distributions from Quest Energy or Quest Midstream for the remainder of 2009 and is unable to estimate at this time when such distributions may be resumed.

F-5

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

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

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

Recombination — Given the liquidity challenges facing the Company, Quest Midstream and Quest Energy, each entity has undertaken a strategic review of its assets and has evaluated and continues to evaluate transactions to dispose of assets in order to raise additional funds for operations and/or to repay indebtedness. On July 2, 2009, QRCP, Quest Midstream, ~~and~~ Quest Energy and other parties thereto entered into an Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which ~~would~~, ~~form~~following a ~~new~~series of mergers and an entity conversion, ~~yet~~QRCP, Quest Energy and the successor to beQuest ~~named~~Midstream will become wholly-owned subsidiaries of PostRock Energy Corporation (“PostRock”) a new, publicly-traded ~~holding~~ corporation (~~“New~~the ~~Quest~~“Recombination”) ~~that~~. On October 2, 2009, the ~~through~~Merger aAgreement ~~series~~was amended to, among other things, reflect certain technical changes as the result of ~~mergers~~an ~~and~~internal ~~entity~~restructuring. ~~conversion~~On October 6, ~~would~~2009, ~~wholly-own~~PostRock filed with the SEC a ~~all~~registration ~~three~~statement ~~entities~~on (“Form S-4, which included a joint proxy statement/prospectus, relating to the Recombination”).

~~Cash~~While ~~and~~we ~~Capital~~are ~~Resources~~working —toward ~~While~~the ~~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~~PostRock ~~Quest~~and its subsidiaries, the approval of the transaction by our stockholders and the unitholders of QELP and QMLP, and consents from each entity’s existing lenders. There can be no assurance that these conditions will be met or that the Recombination will occur.

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

~~As of~~Cash ~~June~~and Capital Resources — On September 3011, 2009, QRCP, ~~excluding~~amended ~~QELP~~ and ~~QMLP,~~restated ~~had~~its ~~cash and~~credit ~~cash~~agreement ~~equivalents~~to ofadd an additional $~~1.1~~8 million ~~and~~revolving nocredit ~~ability~~facility, which will be used to ~~borrow~~finance QRCP’s ~~under~~drilling program in the ~~terms~~Appalachian ofBasin, ~~its~~general ~~existing~~and ~~credit~~administrative ~~agreement~~expenses, working capital and other corporate expenses. ~~QRCP~~Management ~~currently estimates~~believes that itthe new revolving credit facility will ~~not~~provide ~~have~~QRCP ~~enough~~with ~~cash~~sufficient liquidity to ~~pay~~satisfy its ~~expenses~~obligations, including general and administrative expenses, capital expenditures and debt service requirements, ~~after~~through ~~September~~June 1530, ~~2009~~2010. As ~~This~~discussed ~~date~~in ~~could~~Note 3 — Long-Term Debt, the total amount due on July 11, 2010 , by QRCP under its credit agreement is estimated to be ~~extended~~approximately if$21 million. As a result, QRCP will need to raise a significant amount of equity capital during the first half of 2010 to pay this amount and further fund its drilling program. QRCP (or PostRock if the Recombination is completed) may not be able to raise a sufficient amount of equity capital for these purposes at the appropriate time due ~~restructure~~to market conditions or its ~~debt~~financial ~~obligations,~~condition and prospects or may have to issue ~~equity~~shares ~~securities~~at a significant discount to the market price. The Company, through its subsidiaries Quest Energy and/ Quest Cherokee LLC (“Quest Cherokee”), is party to a Second Lien Senior Term Loan Agreement originally due and maturing on September 30, 2009. We have obtained amendments to extend the maturity date of the loan through November 16, 2009.While we are currently negotiating further extensions to this loan, there can be no assurance that such negotiations will be successful or ~~sell~~that ~~additional~~we ~~assets~~will be able to repay amounts due under the Second Lien Senior Term Loan Agreement in accordance with the terms of the agreement. The accompanying financial statements do not include any adjustments that might result from the outcome of ~~this~~these ~~uncertainty~~uncertainties.

Recent Accounting Pronouncements and Recently Adopted Accounting Pronouncements

In ~~March~~June ~~2008~~2009, the FASB issued ~~SFAS~~FASB ~~No. 161,~~ASC ~~Disclosures~~105 ~~about~~Generally ~~Derivative~~Accepted ~~Instruments~~Accounting ~~and~~Principles, which ~~Hedging~~establishes ~~Activities-an amendment of~~ FASB ~~Statement~~ASC ~~No. 133~~as ~~(“SFAS~~the ~~No.~~sole ~~161”).~~source ~~This~~of ~~statement~~authoritative ~~does not~~GAAP. ~~change~~Pursuant to the ~~accounting~~provisions ~~for~~of ~~derivatives~~FASB ~~but~~ASC ~~will~~105, ~~require~~the ~~enhanced~~Company ~~disclosures~~has ~~about~~updated ~~derivative strategies~~references ~~and~~to ~~accounting~~GAAP ~~practices.~~in Weits financial ~~adopted~~statements ~~SFAS~~for ~~No.~~the ~~161~~period ~~effective~~ended ~~January~~September 130, 2009. ~~See~~The ~~Note~~adoption 4of ~~– Derivative~~this ~~Financial~~standard ~~Instruments~~did ~~for~~not have ~~the~~a material impact toon our ~~disclosures~~consolidated financial statements.

~~The~~In ~~Company~~March 2008, ~~adopted~~the FASB ~~Staff~~issued ~~Position~~FASB ~~(“FSP”)~~ASC ~~Emerging Issues Task Force No. 03~~815-~~6-1,~~10 ~~Determining~~Derivatives ~~Whether~~and ~~Instruments~~Hedging ~~Granted~~that indoes ~~Share-Based~~not ~~Payment Transactions Are Participating~~change Securities (“EITF No. 03-6-1”), effective January 1, 2009. EITF No. 03-6-1 addresses whether instruments granted in share-based payment transactions are considered participating securities prior to vesting and therefore included in the ~~allocation~~accounting ~~of earnings~~ for ~~purposes~~derivatives ofbut ~~calculating~~does ~~earnings~~require ~~per unit~~enhanced ~~(“EPU”)~~disclosures ~~under~~about ~~the~~derivative ~~two-class method as required by SFAS~~strategies ~~No. 128, Earnings per Share. EITF No. 03-6-1 provides that unvested unit-based awards that contain non-forfeitable rights to dividends are participating securities~~ and ~~should~~accounting ~~be included in the computation of EPU~~practices. ~~The~~ ~~Company’s~~We ~~restricted stock~~adopted ~~units contain non-forfeitable rights to dividends and thus require~~ these ~~awards~~provisions toeffective ~~be included~~January 1, ~~in the EPU computation~~2009. ~~All~~ ~~prior~~See ~~periods~~Note ~~have~~4 ~~been conformed to the current year presentation. During~~— ~~periods~~Derivative ofFinancial ~~losses,~~Instruments ~~EPU~~for ~~will not be impacted, as~~ the ~~Company’s~~impact ~~participating securities are not obligated~~ to ~~share~~our ~~in the losses of the Company and thus, are not included in the EPU share computation~~disclosures. ~~See Note 7 – Stockholders’ Equity and Earnings per Share.~~

InThe ~~December 2008,~~Company adopted the ~~SEC~~provisions ~~issued~~of ~~Release~~FASB ~~No. 33-8995,~~ASC ~~Modernization~~260 ofEarnings ~~Oil~~Per ~~and~~Share, ~~Gas~~effective ~~Reporting~~January 1, ~~which~~2009, ~~revises~~with ~~disclosure~~respect ~~requirements~~to ~~for~~whether ~~oil~~instruments ~~and~~granted ~~gas~~in ~~companies.~~share-based Inpayment ~~addition~~transactions ~~to changing the~~are ~~definition~~considered ~~and~~participating ~~disclosure~~securities ~~requirements~~prior ~~for~~to ~~oil~~vesting and ~~gas~~therefore ~~reserves,~~included in the ~~new~~allocation ~~rules change the~~of ~~requirements~~earnings for ~~determining~~purposes ~~oil and gas reserve quantities. These rules permit the use~~ of ~~new technologies~~calculating toearnings ~~determine~~per ~~proved~~share ~~reserves~~(“EPS”) under ~~certain~~the ~~criteria~~two-class ~~and~~method ~~allow companies to disclose~~as ~~their~~required ~~probable~~by ~~and~~FASB ~~possible~~ASC ~~reserves~~260. ~~The~~FASB ~~new~~ASC ~~rules~~260 ~~also~~provides ~~require~~that ~~companies~~unvested tounit-based ~~report~~awards ~~the independence~~that ~~and qualifications of their reserves preparer or auditor and file reports when a third~~contain ~~party~~non-forfeitable isrights ~~relied upon~~ to ~~prepare~~dividends ~~reserves~~are ~~estimates~~participating orsecurities ~~conducts a reserves audit. The new rules also require that oil~~ and ~~gas~~should ~~reserves~~ be ~~reported~~included ~~and~~in the ~~full cost ceiling limitation be calculated~~ ~~using~~computation ~~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 periodEPS. The ~~new~~Company’s ~~rules~~restricted ~~are~~stock ~~effective~~units ~~for~~contain ~~annual reports on Form 10~~non-Kforfeitable ~~for fiscal~~rights ~~years ending on or after December 31, 2009, pending the potential alignment of certain accounting standards by the FASB with the new rule. We plan~~ to ~~implement the new requirements in~~ ~~our Annual Report on Form 10-K for the year ended December 31, 2009. We are currently evaluating the impact of the new rules on our consolidated financial statements.~~

F-6

~~QUEST~~dividends and thus require these awards to be included in the EPS computation. All prior ~~RESOURCE~~periods ~~CORPORATION~~have ~~NOTES~~been TOconformed ~~CONDENSED~~to ~~CONSOLIDATED~~the ~~FINANCIAL~~current ~~STATEMENTS~~year presentation. During periods of losses, EPS will not be impacted, as the Company’s participating securities are not obligated to share in the losses of the Company and thus, are not included in the EPS share computation. See Note 7 — Stockholders’ ~~(Continued)(Unaudited)~~Equity and Earnings per Share.

In ~~May~~ December ~~2009~~2008, the ~~FASB~~SEC issued ~~SFAS~~ Release No. ~~165~~33-8995, ~~Subsequent Events~~Modernization of Oil and Gas Reporting, which orrevises ~~(“SFAS~~disclosure Norequirements for oil and gas companies. ~~165”).~~ In addition to changing the definition and disclosure requirements for oil and gas reserves, the new rules change the ~~SFAS~~requirements Nofor determining oil and gas reserve quantities. ~~165~~These ~~establishes~~rules ~~general~~permit ~~standards~~the use of ~~accounting~~new technologies ~~for~~to determine proved reserves under certain criteria and ~~disclosure~~allow ofcompanies ~~transactions~~to disclose their probable and ~~events~~possible ~~that~~reserves. ~~occur~~The ~~after~~new ~~the~~rules ~~balance~~also ~~sheet~~require ~~date~~companies ~~but~~to ~~before~~report ~~financial~~the independence ~~statements~~and ~~are~~qualifications ~~issued~~of their reserves preparer or ~~are~~auditor ~~available~~and tofile reports when a third beparty ~~issued~~is relied upon to prepare reserves estimates or conducts a reserves audit. ItThe new rules also require ~~requires~~that oil and gas reserves be reported and the ~~disclosure~~full cost ceiling limitation be calculated using a twelve-month average price rather than period-end prices. The use of ~~the~~a ~~date~~twelve-month ~~through~~average price ~~which~~could have had an ~~entity~~effect ~~has~~on ~~evaluated~~our ~~subsequent~~2009 ~~events~~depletion rates for our crude oil and natural gas properties and the ~~basis~~amount ~~for~~of ~~that~~the ~~date.~~impairment Werecognized ~~adopted~~as ~~SFAS~~of ~~No.~~December 31, ~~165~~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 ~~June~~on 30or 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 ~~See~~our ~~Note~~Annual 12Report —on ~~Subsequent~~Form ~~Events~~10-K for the year ended December 31, 2009. We are currently evaluating the impact of the new rules on our consolidated financial statements.

In ~~June~~ May 2009, the FASB issued ~~SFAS~~FASB ~~No.~~ASC ~~168,~~855 ~~The~~Subsequent Events. FASB ~~Accounting Standards~~ASC ~~Codification~~855 ~~and~~establishes ~~the~~general standards ~~Hierarchy~~ of ~~Generally~~accounting ~~Accepted Accounting~~for ~~Principles~~and —disclosure ~~A Replacement~~ of ~~FASB~~transactions ~~Statement~~and ~~No. 162. The~~events ~~FASB~~that ~~Accounting~~occur ~~Standards~~after ~~Codification (~~the ~~“Codification”) will~~balance ~~become~~sheet ~~the~~date ~~source~~but ofbefore ~~authoritative~~financial ~~GAAP~~statements ~~recognized~~are byissued ~~the~~or ~~FASB~~are available to be ~~applied~~ ~~by nongovernmental entities~~issued. ~~Rules~~It ~~and interpretive releases~~also ofrequires the ~~SEC~~disclosure ~~under authority~~ of ~~federal~~the ~~securities~~date ~~laws~~through ~~are~~which ~~also sources~~an ofentity ~~authoritative~~has ~~GAAP~~evaluated ~~for~~subsequent ~~SEC~~events ~~registrants.~~and On the ~~effective~~ ~~date,~~basis ~~the Codification~~for ~~will~~that ~~supersede all then-existing non-SEC accounting and reporting standards~~date. ~~This~~We ~~standard~~adopted isFASB ~~effective~~ASC ~~for~~855 ~~interim~~beginning ~~and~~with ~~annual periods~~the ~~ending after~~period ~~September~~ended 15June 30, 2009. ~~This standard will not have a material impact on our consolidated~~ ~~financial statements upon adoption.~~

Note 2 — ~~Acquisition~~Acquisitions and ~~Divestiture~~Divestitures

Acquisition

PetroEdge — On July 11, 2008, QRCP completed the acquisition of privately held PetroEdge ~~Resources~~ Resources (WV) LLC (“PetroEdge”) in an all cash purchase for approximately $142 million in cash ~~including~~ including transaction costs, subject to certain adjustments for working capital and certain other ~~activity~~ activity between May 1, 2008 and the closing date. At the time of the acquisition, PetroEdge owned approximately 78,000 net acres of oil and natural gas producing properties in the Appalachian Basin with estimated net proved reserves of 99.6 Bcfe as of May 1, 2008 ~~and net production of approximately 3~~.~~3 million~~ ~~cubic feet equivalent per day (“Mmcfe/d”).~~ The transaction was recorded within QRCP’s oil and gas production segment and was funded using the proceeds from QRCP’s July 8, 2008 public offering of 8,800,000 shares of common stock, borrowings under QELP’s revolving credit facility and the proceeds of a $45 million, six-month term loan entered into by QELP.

Pro Forma Summary Data Related to Acquisition (Unaudited)

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

	Three Months Ended		~~Three~~Nine Months Ended			~~Six Months Ended~~
			June 30,			June 30,
	September 30,		September 30,
	2008		2008			~~2008~~
Pro forma revenue	$	57,043	$	59165,~~492~~100		$	~~108,057~~
Pro forma net income (loss)	$	87,851	$	(591,~~908~~971	)	$	~~(87,108~~	)
Pro forma net income (loss) per share — basic and diluted	$	2.70	$	(10.8406	)	$	~~(2.76~~	)

Divestiture

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

F-7

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

Note 3 — Long-Term Debt

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

	June 30,		December 31,
	September 30,		December 31,
	2009		2008
Borrowings under bank senior credit facilities
Borrowings under bank senior credit facilities:
QRCP	$	29,420	$	29,000
QRCP:
Credit Agreement Term Loan	$	30,345	$	29,000
Credit Agreement Revolving Line of Credit		1,500
Quest Energy:
Quest Cherokee Credit Agreement		~~174~~160,000		189,000
Second Lien Loan Agreement		3329,~~600~~800		41,200
Quest Midstream		125,098		128,000
Quest Midstream:		121,728		128,000
Notes payable to banks and finance companies		~~574~~181		907
Total debt		~~362~~343,~~692~~554		388,107
Less current maturities included in current liabilities		5441,~~970~~019		45,013
Total long-term debt	$	~~307~~302,~~722~~535	$	343,094

Credit Facilities

QRCP.

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

AtQRCP ~~June~~entered into a Second Amended and Restated Credit Agreement (the “Credit Agreement”) with RBC on September 3011, 2009,. The Credit Agreement contemplates the Recombination and provides that the closing of the Recombination will not be an event of default. No additional amendments to the Credit Agreement are contemplated prior to the closing of the Recombination or in connection therewith. The Credit Agreement includes a term loan with a current outstanding principal balance of $2928.43 million ~~was~~and ~~outstanding~~an $8 million revolving line of credit. In addition, there are also four promissory notes that have been issued under the Credit Agreement: an $862,786 interest deferral note dated June 30, 2009 (representing outstanding due and unpaid interest on the term loan.), ~~The~~a $924,332 ~~weighted~~interest ~~average~~deferral note dated September 30, 2009 (representing outstanding due and unpaid interest ~~rate~~on ~~for~~the term loan), a $282,500 payment-in-kind note dated May 29, 2009 (representing a 1% amendment fee payable by QRCP in connection with the ~~quarter~~fourth ~~ended~~amendment to the Original Credit Agreement), and a second $25,000 payment-in-kind note dated June 30, 2009 ~~was~~(representing 12an amendment fee payable by QRCP in connection with the fifth amendment to the Original Credit Agreement).~~25%.~~

OnModification ~~January 30,~~of ~~2009,~~Debt. As a result of the amendment and restatement of the Credit Agreement, QRCP ~~entered~~evaluated ~~into~~the aremaining ~~Third~~cash ~~Amendment~~flows toof ~~Amended~~this facility under FASB ASC 470-50-40 Debt — Modifications and ~~Restated~~Extinguishments ~~Credit~~— Derecognition to determine if the facility had been ~~Agreement~~substantially modified as defined by the guidance. Upon determining that ~~restricted~~a substantial modification had occurred, QRCP recorded an extinguishment of prior debt and the ~~use~~assumption of ~~proceeds~~new debt at fair value. Our analysis indicated that the fair value of the new debt facility was not materially different from ~~certain~~the ~~asset~~principal ~~sales~~amount of the previous debt facility. As a result, QRCP recorded a $0.8 million loss on extinguishment of debt which represents a write-off of unamortized debt issuance costs associated with the prior debt facility. The loss is reflected in interest expense, net, in QRCP’s condensed consolidated statements of operations.

~~Under~~Interest ~~the~~Rate ~~Credit~~and ~~Agreement,~~Other ~~QRCP~~Fees. isInterest ~~required~~accrues toon ~~maintain~~the asQRCP ofterm loan, the ~~end~~two ofinterest deferral ~~each~~notes ~~quarter,~~and ~~an interest~~the ~~coverage~~two ~~ratio~~payment-in-kind ofnotes ~~not~~at ~~less~~the ~~than~~base ~~2.5~~rate toplus 110.0%. The base rate varies daily and ais ~~leverage~~generally ~~ratio~~the higher of nothe ~~more~~federal ~~than~~funds 2.rate plus 0.50% toor RBC’s prime rate for such 1day.0 The revolving line of credit is non-interest bearing. Instead, QRCP ~~was~~is ~~not~~required into ~~compliance~~pay ~~with~~to ~~these~~the lenders ~~financial~~a ~~covenants~~facility asfee ofequal ~~March 31,~~to ~~2009~~$2.0 million Inon ~~addition~~July 11, ~~under~~ ~~the~~2010. ~~terms~~The offacility ~~the~~fee ~~Credit~~will ~~Agreement,~~be proportionately ~~the~~reduced ~~outstanding~~if ~~principal~~all ~~amount~~ of ~~borrowings~~the ~~may~~following ~~not exceed~~facility ~~the~~fee ~~sum~~reduction ofconditions are satisfied: (i) ~~the~~repayment ~~value~~and oftermination by QRCP’s ~~oil~~of ~~and~~the ~~gas~~revolving ~~properties~~line inof ~~the~~credit, ~~Appalachian Basin~~ (~~as determined~~ii) payment byof the ~~administrative~~deferred quarterly ~~agent~~principal payments under the ~~Credit~~term ~~Agreement~~loan inas ~~its~~discussed ~~reasonable~~below ~~discretion)~~under ~~and~~ “— Payments,” (iiiii) ~~50%~~ repayment of the ~~market~~interest ~~value~~deferral ofnotes ~~QRCP’s~~and ~~interests~~the two payment-in-kind ~~Quest~~notes ~~Energy~~ and ~~Quest Midstream~~ (~~such~~iv) payment ~~excess~~of any isdeferred ~~referred~~interest tounder asthe aterm ~~“Collateral~~loan, ~~Deficiency”).~~the ~~QRCP~~interest isdeferral ~~required~~note toand ~~make~~the atwo ~~mandatory~~payment-in-kind ~~prepayment~~notes ~~equal~~as todiscussed ~~any~~below ~~such~~under ~~Collateral~~“— ~~Deficiency~~Payments. ”

~~On May 29, 2009, QRCP entered into a Fourth Amendment to~~F-8 Amended and Restated Credit Agreement pursuant to the terms of which (i) the lender waived the financial covenant defaults for the quarters ended December 31, 2008 and March 31, 2009; (ii) the lender waived the mandatory prepayment for the Collateral Deficiency for the quarters ended December 31, 2008, March 31, 2009 and June 30, 2009; and (iii) the reporting deadline for certain financial statements was extended.

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

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

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

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

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

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

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

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

Quest Energy.

A. Quest Cherokee Credit Agreement.

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

~~F-8~~ The borrowing base was $160.0 million and the amount borrowed under the Quest Cherokee Credit Agreement was $160.0 million as of September 30, 2009. As a result, there was no additional borrowing availability. The weighted average interest rate under the Quest Cherokee Credit Agreement for the quarter ended September 30, 2009 was 4.36%.

F-9

~~QUEST~~ In July 2009, the borrowing base under the Quest Cherokee Credit Agreement was reduced from ~~RESOURCE~~$190 million ~~CORPORATION~~to ~~NOTES~~$160 million, TOwhich, ~~CONDENSED~~following ~~CONSOLIDATED~~the ~~FINANCIAL~~payment ~~STATEMENTS~~discussed —below, resulted in the ~~(Continued)(Unaudited)~~outstanding borrowings under the Quest Cherokee Credit Agreement exceeding the new borrowing base by $14 million. In anticipation of the reduction in the borrowing base, Quest Energy amended or exited certain of its above market natural gas price derivative contracts and, in return, received approximately $26 million. The strike prices on the derivative contracts that Quest Energy did not exit were set to market prices at the time. At the same time, Quest Energy entered into new natural gas price derivative contracts to increase the total amount of its future estimated proved developed producing natural gas production hedged to approximately 85% through 2013. On June 30, 2009, using these proceeds, Quest Energy made a principal payment of $15 million on the Quest Cherokee Credit Agreement. On July 8, 2009, Quest Energy repaid the $14 million Borrowing Base Deficiency. Quest Energy anticipates that in connection with the redetermination of its borrowing base in November 2009, its borrowing base will be further reduced from its current level of $160 million. In the event of a borrowing base reduction, Quest Energy expects to be able to make the required payments resulting from the borrowing base deficiency out of existing funds.

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

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

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

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

Quest Cherokee was in compliance with all of its covenants under the Quest Cherokee Credit Agreement as of ~~June~~September 30, 2009.

B. Second Lien Loan Agreement.

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

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

As of ~~June~~September 30, 2009, $3329.68 million was outstanding under the Second Lien Loan Agreement. ~~The~~ The weighted average interest rate under the Second Lien Loan Agreement for the quarter ended ~~June~~ September 30, 2009 was 11.25%.

On June 30, 2009, Quest Energy and Quest Cherokee entered into a Second Amendment to the Second Lien Senior Term Loan Agreement that deferred Quest Energy’s obligation to deliver certain financial statements to the lenders. On September 30, 2009, Quest Energy and Quest Cherokee entered into a Third Amendment to the Second Lien Senior Term Loan Agreement that extended the maturity date of the loan for an additional 31 days from September 30, 2009 to October 31, 2009. On October 30, 2009, Quest Energy and Quest Cherokee entered into a Fourth Amendment to the Second Lien Senior Term Loan Agreement that extended the maturity date of the loan for an additional 16 days to November 16, 2009. While Quest Energy and Quest Cherokee are currently negotiating further extensions to this loan, there can be no assurance that such negotiations will be successful or that Quest Energy and Quest Cherokee will be able to repay amounts due under the Second Lien Loan Agreement in accordance with the terms of the agreement.

Quest Cherokee was in compliance with all of its covenants under the Second Lien Loan Agreement as of ~~June~~September 30, 2009.

Quest Midstream.

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

As of ~~June~~September 30, 2009, the amount borrowed under the Quest Midstream Credit Agreement was $~~125~~121.1 7 million. The weighted average interest rate for the quarter ended ~~June~~September 30, 2009 was 4 3.6738%.

~~Quest~~On ~~Midstream~~August 19, ~~was~~2009, inRBC ~~compliance~~and ~~with~~QMLP ~~all~~entered into a letter agreement wherein QMLP agreed that during negotiations related to the Recombination, it would not submit a borrowing request or request a letter of ~~its~~credit ~~covenants~~until asthe earlier to occur of ~~June~~the Recombination or December 3031, 2009.

F-910

~~QUEST RESOURCE~~ QMLP ~~CORPORATION~~made ~~NOTES~~a TO$3.4 million ~~CONDENSED~~Excess ~~CONSOLIDATED~~Cash ~~FINANCIAL~~Flow ~~STATEMENTS~~payment — (~~Continued~~as defined in the Quest Midstream Credit Agreement)~~(Unaudited)~~ on August 17, 2009.

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

Note 4 — Derivative Financial Instruments

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

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

We account for our derivative financial instruments in accordance with ~~SFAS~~FASB ~~No. 133,~~ASC 815 ~~Accounting~~Derivatives ~~for Derivative Instruments~~ and Hedging. ~~Activities~~FASB ~~(“SFAS~~ASC ~~No. 133”).~~815 ~~SFAS No. 133~~ requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. ~~SFAS~~ASC ~~No. 133~~Topic 815 requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met, or exemptions for normal purchases and normal sales (“NPNS”) as permitted by ~~SFAS~~FASB ASC ~~No. 133~~815 exist. We do not designate our derivative financial instruments as hedging instruments for financial accounting purposes, and, as a result, we recognize the change in the respective instruments’ fair value currently in earnings. In accordance with ~~SFAS~~FASB ~~No. 161~~ASC 815, the table below outlines the classification of our derivative financial instruments on our condensed consolidated balance sheets and their financial impact in our condensed consolidated statement of operations as of and for the periods indicated (in thousands):

Fair Value of Derivative Financial Instruments

				June 30,				December 31,
		September 30,				December 31,
Derivative Financial Instruments	Balance Sheet location	2009		~~2009~~		2008		~~2008~~
Commodity contracts	~~Derivative~~Current derivative financial ~~instruments~~instrument ~~— Current assets~~asset	$	19,625	$	~~35,123~~	$	42,995	$	~~42,995~~
Commodity contracts	~~Derivative financial instruments —~~ Long-term ~~assets~~derivative financial instrument asset		4,653		~~1,876~~		30,836		~~30,836~~
Commodity contracts	~~Derivative~~Current derivative financial ~~instruments~~instrument ~~— Current liabilities~~liability		(1,413	)	~~(411~~	)	(12	)	~~(12~~	)
Commodity contracts	~~Derivative financial instruments —~~ Long-term ~~liabilities~~derivative financial instrument liability		(5,294	)	~~(8,153~~	)	(4,230	)	~~(4,230~~	)
Net derivative assets				$	28,435			$	69,589
		$	17,571			$	69,589

F-10

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

The Effect of Derivative Financial Instruments

		Three months ended						~~Six months ended~~	Nine months ended
		June 30,						June 30,
		September 30,							September 30,
Derivative Financial Instruments	Statement of Operations location	2009			2008			~~2009~~	2009		~~2008~~	2008
Commodity contracts	Gain (loss) from derivative financial instruments	$	~~(17~~8,~~138~~752	)	$	~~(105~~145,~~375~~132	)	$	~~22,326~~$	31,078	$	~~(149,614~~$	)(4,482	)

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Realized gains (losses)	$	46,646		$	(9,059	)	$	63,480		$	(10,270	)
Unrealized losses		(63,784	)		(96,316	)		(41,154	)		(139,344	)
Gain (loss) from derivative financial instruments	$	(17,138	)	$	(105,375	)	$	22,326		$	(149,614	)

F-11

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


	Three months ended						Nine months ended
	September 30,						September 30,
	2009			2008			2009			2008
Realized gains (losses)	$	19,616		$	(7,525	)	$	83,096		$	(17,795	)
Unrealized gains (losses)		(10,864	)		152,657			(52,018	)		13,313

Total	$	8,752		$	145,132		$	31,078		$	(4,482	)

~~The~~In ~~following~~June 2009, ~~tables~~we ~~summarize~~amended or exited certain of our above market natural gas price derivative contracts for periods beginning in the ~~estimated~~second ~~volumes~~quarter of 2010 through the fourth quarter of 2012. In return, ~~fixed~~we ~~prices~~received ~~and~~approximately ~~fair~~$26 million. ~~values~~Concurrent with this, the strike prices on the ~~attributable~~derivative contracts that we did not exit were set to ~~oil~~market prices at the time and we entered into new natural gas price derivative contracts asto increase the total amount of ~~June 30,~~our ~~2009:~~future estimated proved developed producing natural gas production hedged to approximately 85% through 2013.

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

The following table summarizes the estimated volumes, fixed prices and fair values attributable to oil and gas derivative contracts as of September 30, 2009:


	Remainder of		Year Ending December 31,
	2009		2010			2011			2012			Thereafter			Total
	($ in thousands, except volumes and per unit data)
Natural Gas Swaps:
Contract volumes (Mmbtu)		3,687,360		16,129,060			13,550,302			11,000,004			9,000,003			53,366,729
Weighted-average fixed price per Mmbtu	$	7.78	$	6.26		$	6.80		$	7.13		$	7.28		$	6.85
Fair value, net	$	11,939	$	5,020		$	1,048		$	1,676		$	1,178		$	20,861
Natural Gas Collars:
Contract volumes (Mmbtu)		187,500		—			—			—			—			187,500
Weighted-average fixed price per Mmbtu:
Floor	$	11.00	$	—		$	—		$	—		$	—		$	11.00
Ceiling	$	15.00	$	—		$	—		$	—		$	—		$	15.00
Fair value, net	$	1,154	$	—		$	—		$	—		$	—		$	1,154
Total Natural Gas Contracts:
Contract volumes (Mmbtu)		3,874,860		16,129,060			13,550,302			11,000,004			9,000,003			53,554,229
Weighted-average fixed price per Mmbtu	$	7.94	$	6.26		$	6.80		$	7.13		$	7.28		$	6.87
Fair value, net	$	13,093	$	5,020		$	1,048		$	1,676		$	1,178		$	22,015
Basis Swaps:
Contract volumes (Bbl)		—		3,630,000			8,549,998			9,000,000			9,000,003			30,180,001
Weighted-average fixed price per Bbl	$	—	$	0.63		$	0.67		$	0.70		$	0.71		$	0.69
Fair value, net	$	—	$	(957	)	$	(1,512	)	$	(1,393	)	$	(1,138	)	$	(5,000	)
Crude Oil Swaps:
Contract volumes (Bbl)		9,000		30,000			—			—			—			39,000
Weighted-average fixed price per Bbl	$	90.07	$	87.50		$	—		$	—		$	—		$	88.09
Fair value, net	$	170	$	386		$	—		$	—		$	—		$	556

Total fair value, net	$	13,263	$	4,449		$	(464	)	$	283		$	40		$	17,571

F-12

~~QUEST~~ The following table summarizes the estimated volumes, fixed prices and fair values ~~RESOURCE~~attributable ~~CORPORATION~~to ~~NOTES~~gas TOderivative ~~CONDENSED~~contracts ~~CONSOLIDATED~~as ~~FINANCIAL~~of ~~STATEMENTS~~December 31, —2008: ~~(Continued)(Unaudited)~~

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


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

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

	Year Ending December 31,
	2009		2010		2011		Thereafter		Total
	($ in thousands, except volumes and per unit data)
Natural Gas Swaps:
Contract volumes (Mmbtu)		14,629,200		12,499,060		2,000,004		2,000,004		31,128,268
Weighted-average fixed price per Mmbtu	$	7.78	$	7.42	$	8.00	$	8.11	$	7.67
Fair value, net	$	38,107	$	14,071	$	2,441	$	2,335	$	56,954
Natural Gas Collars:
Contract volumes (Mmbtu):
Floor		750,000		630,000		3,549,996		3,000,000		7,929,996
Ceiling		750,000		630,000		3,549,996		3,000,000		7,929,996
Weighted-average fixed price per Mmbtu:
Floor	$	11.00	$	10.00	$	7.39	$	7.03	$	7.79
Ceiling	$	15.00	$	13.11	$	9.88	$	7.39	$	9.52
Fair value, net	$	3,630	$	1,875	$	3,144	$	2,074	$	10,723
Total Natural Gas Contracts:
Contract volumes (Mmbtu)		15,379,200		13,129,060		5,550,000		5,000,004		39,058,264
Weighted-average fixed price per Mmbtu	$	7.94	$	7.55	$	7.61	$	7.44	$	7.70
Fair value, net	$	41,737	$	15,946	$	5,585	$	4,409	$	67,677
Crude Oil Swaps:
Contract volumes (Bbl)		36,000		30,000		—		—		66,000
Weighted-average fixed per Bbl	$	90.07	$	87.50	$	—	$	—	$	88.90
Fair value, net	$	1,246	$	666	$	—	$	—	$	1,912
Total fair value, net	$	42,983	$	16,612	$	5,585	$	4,409	$	69,589

Note 5 — Fair Value Measurements

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

Effective January 1, 2009, we adopted ~~FSP~~FASB ~~157-2,~~ASC 820 Fair Value Measurements and Disclosures which applies to our nonfinancial assets and liabilities for which we disclose or recognize at fair value on a nonrecurring basis, such as asset retirement obligations and other assets and liabilities. Fair value is the exit price that we would receive to sell an asset or pay to transfer a liability in an orderly transaction between market participants at the measurement date.

~~F-13~~ FASB ASC 820 also establishes a hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy are as follows:

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

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

•

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

•

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

•

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

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

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

									Netting and
	Level		Level			Level			Cash			Total Net Fair
June 30, 2009	1		2			3			Collateral*			Value
Derivative financial instruments — assets	$	—	$	4,952		$	32,047		$	—		$	36,999
Derivative financial instruments — liabilities		—		(368	)		(8,196	)	$	—			(8,564	)
Total	$	—	$	4,584		$	23,851		$	—		$	28,435
December 31, 2008
Derivative financial instruments — assets	$	—	$	8,866		$	64,883		$	(4,160	)	$	69,589
Derivative financial instruments — liabilities		—		(224	)		(3,936	)		4,160			—
Total	$	—	$	8,642		$	60,947		$	—		$	69,589

F-13


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

Total	$	—	$	5,530		$	12,041		$	—		$	17,571


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

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


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

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

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

F-14

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

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

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

	Six Months Ended
	Nine Months Ended
	June 30, 2009
	September 30, 2009
Balance at beginning of period	$	60,947
Realized and unrealized gains included in earnings		1925,~~695~~309
Purchases, sales, issuances, and settlements		(5674,~~791~~215	)
Transfers into and out of Level 3		—
Balance as of June 30, 2009	$	23,851
Balance as of September 30, 2009	$	12,041

Note 6 — Asset Retirement Obligations

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

	Six Months Ended
	Nine Months Ended
	June 30, 2009
	September 30, 2009
Asset retirement obligations at beginning of period	$	5,922
Liabilities incurred		—
Liabilities settled		—
Accretion		~~289~~424
Revisions in estimated cash flows		—
Asset retirement obligations at end of period	$	6,~~211~~346

~~Note~~F-14 ~~7 — Stockholders’ Equity and Earnings per Share~~

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

Note 7 — Equity and Earnings per Share

Share-Based Payments — The granting of stock awards and options to our employees under our 2005 Omnibus Stock Award Plan, as amended (the “Award Plan”), represent share-based payment transactions that are treated as compensation expense with a corresponding increase to additional paid-in capital. During the nine months ended September 30, 2009, 300,000 stock options were granted outside of the Award Plan. As of September 30, 2009, there were approximately 1.3 million shares available under the Award Plan for future stock awards and options. For the three and nine months ended September 30, 2009, total share-based compensation related to stock awards and options was $0.1 million and $0.6 million, compared to $(1.3) million and $1.7 million for the comparable periods in 2008, respectively. Share-based compensation is included in general and administrative expense on our statement of operations. Total share-based compensation to be recognized on unvested stock awards and options as of September 30, 2009 is $0.6 million over a weighted average period of 1.19 years.

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

	Three Months Ended						~~Six~~Nine Months Ended
	June 30,						June 30,
	September 30,						September 30,
	2009			2008			2009			2008
Quest Energy
Beginning of period	$	2916,~~378~~131		$	~~126~~82,~~071~~879		$	58,666		$	145,364
Contributions, net		—			—			—			(265	)
Distributions		—			(3,~~744~~925	)		—			(59,~~615~~540	)
Net income (loss) attributable to non-controlling interest		(134,~~247~~418	)		~~(39~~66,~~456~~565	)		(4246,~~568~~986	)		~~(56~~9,~~625~~940	)
Stock compensation expense related to QELP unit-based awards		—17			87			3350			2027
End of period	$	1611,~~131~~730		$	82145,~~879~~526		$	1611,~~131~~730		$	82145,~~879~~526
Quest Midstream
Beginning of period	$	~~147~~148,~~698~~611		$	~~148~~144,~~760~~748		$	145,870		$	152,021
Contributions, net		—			—			—			—
Distributions		—			~~(3,815~~—	)		—			(7,630	)
Net income (loss) attributable to non-controlling interest		~~736~~(779	)		(~~310~~60	)		21,~~403~~624			~~131~~71
Stock compensation expense related to QMLP unit-based awards		~~177~~204			113			~~338~~542			~~226~~339
End of period	$	148,~~611~~036		$	144,~~748~~801		$	148,~~611~~036		$	144,~~748~~801
Total non-controlling interest at end of period	$	~~164~~159,~~742~~766		$	~~227~~290,~~627~~327		$	~~164~~159,~~742~~766		$	~~227~~290,~~627~~327

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


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

Basic and diluted weighted average number of shares:		31,885,445			31,919,649		31,827,513			26,481,051

Basic and diluted net loss attributable to common stockholders per common share	$	(0.36	)	$	2.75	$	(2.54	)	$	0.18

Effective January 1, 2009, the Company adopted the provisions of FASB ASC 260 Earnings Per Share which requires participating securities to be included in the allocation of earnings when calculating earnings per share, or EPS, under the two-class method. All prior period EPS data presented above has been retrospectively adjusted to conform to the new requirements. During

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~~QUEST~~periods of losses, basic EPS will not be impacted, as the Company’s ~~RESOURCE~~participating ~~CORPORATION~~securities ~~NOTES~~are TOnot ~~CONDENSED~~obligated ~~CONSOLIDATED~~to ~~FINANCIAL~~share ~~STATEMENTS~~in —the losses of the Company and thus, are not ~~(Continued)(Unaudited)~~included in the basic EPS share computation.

~~Loss~~Because ~~per~~we ~~Share~~reported —a Anet ~~reconciliation~~loss offor the ~~numerator~~three and ~~denominator~~nine ~~used~~months inended ~~the~~September 30, 2009, ~~basic~~participating ~~and~~securities ~~diluted~~covering 227,231 common shares were excluded from the computation of net loss per share ~~calculations~~because ~~for~~their ~~the~~effect ~~periods~~would ~~indicated~~have been antidilutive. Furthermore, is asapproximately ~~follows~~700,000 ~~(dollars~~stock inoptions ~~thousands~~outstanding at September 30, ~~except~~2009 ~~share~~were out-of-the-money and ~~per~~thus ~~share~~antidilutive. ~~amounts):~~Approximately 300,000 stock options outstanding at September 30, 2008 were out-of-the-money and thus antidilutive.

	Three months ended						Six months ended
	June 30,						June 30,
	2009			2008			2009			2008
Basic and diluted earnings per share:
Net loss attributable to common stockholders	$	(18,019	)	$	(57,886	)	$	(69,405	)	$	(82,981	)
Basic and diluted weighted average number of shares:
Common shares		31,867,857			22,844,600			31,798,546			22,742,289
Unvested share-based awards participating		—			—			—			—
Basic and diluted weighted average number of shares:		31,867,857			22,844,600			31,798,546			22,742,289
Basic and diluted net loss attributable to common stockholders per common share	$	(0.57	)	$	(2.53	)	$	(2.18	)	$	(3.65	)

Note 8 — Impairment of Oil and Gas Properties

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

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

Note 8— Impairment of Oil and Gas Properties

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

Under the present full cost accounting rules, we are required to compute the after-tax present value of our proved oil and natural gas properties using spot market prices for oil and natural gas at our balance sheet date. The base for our spot prices for natural gas is Henry Hub and for oil is Cushing, Oklahoma. The Company had previously recognized a ceiling test impairment of $102.9 million during the first quarter of 2009 while no impairment was necessary for the second quarter of 2009. As of September 30, 2009, the ceiling test computation utilizing spot prices on that day resulted in the carrying costs of our unamortized proved oil and natural gas properties, net of deferred taxes, exceeding the ~~March~~September 3130, 2009 present value of future net revenues by approximately $~~122~~11.6 1 million. As a result of subsequent increases in spot prices, the ~~amount~~need ofto ~~the~~recognize ~~ceiling~~an ~~test~~ impairment ~~was~~for ~~reduced~~the toquarter ~~$102.9 million~~ended ~~and~~September ~~is included in our condensed consolidated statement of operations. No further impairment was necessary at June~~ 30, 2009, was eliminated. Natural gas, which is sold at other natural gas marketing hubs where we conduct operations, is subject to prices which reflect variables that can increase or decrease spot natural gas prices at these hubs such as market demand, transportation costs and quality of the natural gas being sold. Those differences are referred to as the basis differentials. Typically, basis differentials result in natural gas prices which are lower than Henry Hub, except in Appalachia, where we have typically received a premium to Henry Hub. We may face further ceiling test write-downs in future periods, depending on the level of commodity prices, drilling results and well performance.

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

Note 9 — Commitments and Contingencies

Litigation

We are subject, from time to time, to certain legal proceedings and claims in the ordinary course of conducting our business. Below is a brief description of the material legal proceedings that have been initiated against us since December 31, 2008 and any material developments in existing material legal proceedings that have occurred since December 31, 2008. For additional information regarding our legal proceedings, please see Note 12 to our consolidated financial statements included in our 2008 Form 10-K/A and Note 9 to our condensed consolidated financial statements included in our Quarterly Reports on Form 10-Q for the three months ended March 31, 2009 and June 30, 2009.

Federal Individual Securities Litigation

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

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

~~Note~~ J. 9—Steven ~~Commitments~~Emerson, Emerson Partners, J. Steven Emerson Roth IRA, J. Steven Emerson IRA RO II, and ~~Contingencies~~Emerson Family Foundation v. Quest Resource Corporation, Inc., Quest Energy Partners L.P., Jerry Cash, David E. Grose, and John Garrison, Case No. 5:09-cv-1226-M, U.S. District Court for the Western District of Oklahoma, filed November 3, 2009

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

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

Federal Derivative Case

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

On July 17, 2009, a complaint was filed in the United States District Court for the Western District of Oklahoma, purportedly on Quest Energy’s behalf, which names certain of its current and former officers and directors, external auditors and vendors. The factual allegations relate to, among other things, the transfers and lack of effective internal controls. The complaint asserts claims for breach of fiduciary duty, waste of corporate assets, unjust enrichment, conversion, disgorgement under the Sarbanes-Oxley Act of 2002, and aiding and abetting breaches of fiduciary duties against the individual defendants and vendors and professional negligence and breach of contract against the external auditors. The complaint seeks monetary damages, disgorgement, costs and expenses and equitable and/or injunctive relief. It also seeks Quest Energy to take all necessary actions to reform and improve its corporate governance and internal procedures. ~~Quest~~On September 8, ~~Energy~~2009, ~~intends~~the case was transferred to ~~defend~~Judge ~~vigorously~~Miles-LaGrange ~~against~~who ~~these~~is ~~claims~~presiding over the other federal cases discussed below, and the case number was changed to CIV-09-752-M. All proceedings in this matter are currently stayed under Judge Miles-LaGrange’s order of October 16, 2009.

Personal Injury Litigation

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

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

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

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

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

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

Litigation Related to Oil and Gas Leases

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

Quest Cherokee was named as a defendant in a lawsuit filed by Edward E. Birk, et ux., and Brian L. Birk, et ux., on April 23, 2009. In that case, the plaintiffs claim that they are entitled to an overriding royalty interest (1/16th in some leases, and 1/32nd in some leases) in 14 oil and gas leases owned and operated by Quest Cherokee. Plaintiffs contend that Quest Cherokee has produced oil and/or gas from wells located on or unitized with those leases, and that Quest Cherokee has failed to pay plaintiffs their overriding royalty interest in that production. 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.

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~~QUEST~~Quest Cherokee was named as a defendant in a lawsuit filed by Edward E. Birk, et ux., and Brian L. ~~RESOURCE~~Birk, ~~CORPORATION~~et ~~NOTES~~ux., TOon ~~CONDENSED~~April 23, ~~CONSOLIDATED~~2009. ~~FINANCIAL~~In ~~STATEMENTS~~that —case, the plaintiffs claim that they are entitled to an overriding royalty interest (~~Continued~~1/16th in some leases, and 1/32nd in some leases)~~(Unaudited)~~ in 14 oil and gas leases owned and operated by Quest Cherokee. Plaintiffs contend that Quest Cherokee has produced oil and/or gas from wells located on or unitized with those leases, and that Quest Cherokee has failed to pay plaintiffs their overriding royalty interest in that production. Quest Cherokee has filed an answer defending its position. Quest Cherokee intends to defend vigorously against these claims.

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

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

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

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

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

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

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

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

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

		Federal Securities Class Actions

**Michael Friedman, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David E. Grose, Case No. 08-cv-936-M, U.S. District Court for the Western District of Oklahoma, filed September 5, 2008**

*James Jents, individually and on behalf of all others similarly situated v. Quest Resource Corporation, Jerry Cash, David E. Grose, and John Garrison,* Case No. 08-cv-968-M, U.S. District Court for the Western District of Oklahoma, filed September 12, 2008

*J. Braxton Kyzer and Bapui Rao, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation and David E. Grose,* Case No. 08-cv-1066-M, U.S. District Court for the Western District of Oklahoma, filed October 6, 2008

*Paul Rosen, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David E. Grose,* Case No. 08-cv-978-M, U.S. District Court for the Western District of Oklahoma, filed September 17, 2008

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

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

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

Royalty Owner Class Action

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

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

Personal Injury Litigation

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

QCOS was named in this lawsuit filed by plaintiffs Segundo Francisco Trigoso and Dana Jara De Trigoso. Plaintiffs allege that Segundo Francisco Trigoso was seriously injured while working for ~~QCOS~~ 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~~ Various motions for summary judgment have been filed and denied by the court. It is expected that the court will set this matter for trial in Winter 2010. ~~The~~ ~~parties are currently engaged in settlement negotiations and preparing for trial.~~ QCOS intends to defend vigorously against plaintiffs’ claims.

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

Quest Cherokee was named in this wrongful death lawsuit filed by Berenice Urias. Plaintiff was the surviving fiancée of the decedent Montano Moreno. The decedent was killed while working for ~~United~~ 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.~~

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drilling rig between locations when the decedent was electrocuted. All claims against Quest Cherokee have been dismissed with prejudice.

Litigation Related to Oil and Gas Leases

Quest Cherokee has been named as a defendant or counterclaim defendant in several lawsuits in which the plaintiff claims that oil and gas leases owned and operated by Quest Cherokee have either expired by their terms or, for various reasons, have been forfeited by Quest Cherokee. Those lawsuits were originally filed in the district courts of Labette, Montgomery, Wilson, and Neosho Counties, Kansas. Quest Cherokee has drilled wells on some of the oil and gas leases in issue and some of those oil and gas leases do not have a well located thereon but have been unitized with other oil and gas leases upon which a well has been drilled. As of ~~August~~ 10November 4, 2009, the total amount of acreage covered by the leases at issue in these lawsuits was approximately 5,~~118~~100 acres. Quest Cherokee intends to vigorously defend against those claims. Following is a list of those cases:

Housel v. Quest Cherokee, LLC, Case No. 06-CV-26-I, District Court of Montgomery County, State of Kansas, filed March 2, 2006 Roger Dean Daniels v. Quest Cherokee, LLC, Case No. 06-CV-61, District Court of Montgomery County, State of Kansas, filed May 5, 2006 (currently on appeal with the Kansas Court of Appeals, Case No. 08-100576-A; oral argument scheduled for November 18, 2009) Carol R. Knisely, et al. v. Quest Cherokee, LLC, Case No. 07-CV-58-I, District Court of Montgomery County, State of Kansas, filed April 16, 2007 Scott Tomlinson, et al. v. Quest Cherokee, LLC, Case No. 2007-CV-45, District Court of Wilson County, State of Kansas, filed August 29, 2007 (trial set for December 2009) Ilene T. Bussman et al. v. Quest Cherokee, LLC, Case No. 07-CV-106-PA, District Court of Labette County, State of Kansas, filed November 26, 2007 Gary Dale Palmer, et al. v. Quest Cherokee, LLC, Case No. 07-CV-107-PA, District Court of Labette County, State of Kansas, filed November 26, 2007 Richard L. Bradford, et al. v. Quest Cherokee, LLC, Case No. 2008-CV-67, District Court of Wilson County, State of Kansas, filed September 18, 2008 (settled and dismissed on August 3, 2009) Richard Winder v. Quest Cherokee, LLC, Case Nos. 07-CV-141 and 08-CV-20, District Court of Neosho County, State of Kansas, filed December 7, 2007, and February 27, 2008 Quest Cherokee v. Hinkle, et. al. & Admiral Bay, Case No. 2006-CV-74, District Court of Labette County, State of Kansas, filed September 15, 2006 (trial set for February 2010) Central Natural Resources, Inc. v. Quest Cherokee, LLC, et al., Case No. 04-C-100-PA, District Court of Labette County, State of Kansas, filed on September 1, 2004

~~Roger~~Quest ~~Dean~~Cherokee ~~Daniels~~and v.Bluestem ~~Quest~~were ~~Cherokee,~~named ~~LLC,~~as ~~Case~~defendants Noin a lawsuit filed by Central Natural Resources, Inc. (“Central Natural Resources”) on September ~~06-CV-61~~1, 2004 in the District Court of ~~Montgomery~~ Labette County, ~~State~~Kansas. Central Natural Resources owns the coal underlying numerous tracts of ~~Kansas,~~land ~~filed~~in Labette ~~May 5~~County, ~~2006~~Kansas. ~~(currently~~Quest onCherokee ~~appeal)~~has obtained oil and gas leases from the owners of the

F-1820

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

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

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

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

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

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

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

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

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

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

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

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

F-19

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

Other

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

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

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

Quest Cherokee was named in this lawsuit by Barbara Cox. Plaintiff is a landowner in Hobbs, New Mexico and owns the property where the Quest State 9-4 Well was drilled and plugged. ~~Plaintiff~~ Plaintiff alleged that Quest Cherokee violated the New Mexico Surface Owner Protection Act and has ~~committed~~ committed a trespass and nuisance in the drilling and maintenance of the well. The parties have settled this case and itdismissal ~~will~~is beexpected ~~dismissed~~before the end of November 2009.

Environmental Matters

As of ~~June~~September 30, 2009, there were no known environmental or regulatory matters related to ~~our~~ our operations which are reasonably expected to result in a material liability to us. Like other ~~oil~~ 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.

F-21

Financial Advisor Contracts

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

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

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

F-20

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

Note 10 — Related Party Transactions

Settlement ~~of lawsuit~~Agreements

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

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

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

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

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

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

F-22


	QRCP		QELP			Total
Cash, net of legal expenses	$	2,429	$	—		$	2,429
Oil & gas properties		896		1,076			1,972
Other assets		50		—			50
Current liabilities		—		(326	)		(326	)
Long-term debt		—		(719	)		(719	)

Net assets received	$	3,375	$	31		$	3,406

Merger Agreement and Related Agreements

As discussed in Note 1 — Basis of Presentation, on July 2, 2009, we entered into the Merger Agreement with Quest Energy, Quest Midstream, and other parties thereto pursuant to which, following wea ~~would~~series of mergers and an entity conversion, QRCP, Quest Energy and the successor to ~~form~~Quest aMidstream ~~new~~will become wholly-owned subsidiaries of PostRock. On October 2, ~~yet~~2009, the Merger Agreement was amended to, beamong ~~named~~other things, ~~publicly-traded~~reflect ~~corporation~~certain ~~that~~technical changes as the result of an internal restructuring. Additionally, ~~through~~since shortly before execution of the Merger Agreement one of the Quest Midstream investors had abandoned its Quest Midstream common units, which were inadvertently included in calculating the Quest Midstream exchange ratio contained in the Merger Agreement, the amendment also permitted Quest Midstream to make a ~~series~~distribution of ~~mergers~~additional ~~and~~common ~~entity~~units ~~conversions~~to its common unitholders in order to increase the number of outstanding common units to match, ~~would~~as ~~wholly-own~~closely ~~all~~as ~~three~~practicable, ~~entities~~the number set forth in the Merger Agreement. The effect of the distribution was to preserve the relative ownership percentages of PostRock agreed to by the parties without the need to amend the Quest Midstream exchange ratio.

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

Additionally, in connection with the Merger Agreement, on July 2, 2009, we entered into a Support Agreement with Quest Energy, Quest Midstream and certain Quest Midstream unitholders (the “Support Agreement”), which was amended on October 2, 2009 to, among other things, add an additional Quest Midstream common unitholder as a party. Pursuant to the Support Agreement, as amended, we have, subject to certain conditions, agreed to vote the common and subordinated units of Quest Energy and Quest Midstream that we own in favor of the Recombination and the holders of approximately 4373% of the common units of Quest Midstream have, subject to certain conditions, agreed to vote their common units in favor of the Recombination.

F-2123

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

Note 11 — Operating Segments

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

							Other and
	Oil and Gas			Natural Gas			Intersegment
	Production			Pipelines			Eliminations			Total
Three Months Ended June 30, 2009:
Three Months Ended September 30, 2009:
Total revenues	$	1618,~~107~~329		$	1916,~~616~~635		$	(1211,~~030~~002	)	$	23,~~693~~962
Inter-segment revenues		—			(1211,~~030~~002	)		1211,~~030~~002			—
Third-party revenues	$	1618,~~107~~329		$	75,~~586~~633		$	—		$	23,~~693~~962
Segment operating profit (loss)	$	(811,~~233~~342	)	$	84,~~705~~254		$	—		$	~~472~~(7,088	)
Three Months Ended June 30, 2008:
Three Months Ended September 30, 2008:
Total revenues	$	49,~~144~~531		$	1516,~~823~~095		$	(8,~~675~~583	)	$	5657,~~292~~043
Inter-segment revenues		—			(8,~~675~~583	)		8,~~675~~583			—
Third-party revenues	$	49,~~144~~531		$	7,~~148~~512		$	—		$	5657,~~292~~043
Segment operating profit	$	1518,~~615~~005		$	32,~~438~~985		$	—		$	1920,~~053~~990
Six Months Ended June 30, 2009:
Nine months ended September 30, 2009:
Total revenues	$	3856,~~382~~711		$	3952,~~926~~260		$	(2431,~~537~~238	)	$	5377,~~771~~733
Inter-segment revenues		—			(2431,~~537~~238	)		2431,~~537~~238			—
Third-party revenues	$	3856,~~382~~711		$	1521,~~389~~022		$	—		$	5377,~~771~~733
Segment operating profit (loss)	$	(~~121~~128,~~205~~246	)	$	17,~~887~~840		$	—		$	(~~103~~110,~~318~~406	)
Six Months Ended June 30, 2008:
Nine months ended September 30, 2008:
Total revenues	$	87136,~~458~~989		$	3147,~~387~~482		$	(1725,~~338~~921	)	$	~~101~~158,~~507~~550
Inter-segment revenues		—			(1725,~~338~~921	)		1725,~~338~~921			—
Third-party revenues	$	87136,~~458~~989		$	1421,~~049~~561		$	—		$	~~101~~158,~~507~~550
Segment operating profit	$	2442,~~233~~237		$	710,~~782~~768		$	—		$	3253,~~015~~005
Identifiable assets:
June 30, 2009	$	175,040		$	329,470		$	—		$	504,510
September 30, 2009	$	132,298		$	327,274		$	—		$	459,572
December 31, 2008	$	311,592		$	338,584		$	—		$	650,176

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

	Three months ended June 30,						Six months ended June 30,
	Three months ended						Nine months ended
	September 30,						September 30,
	2009			2008			2009			2008
Segment operating profit (loss) (1)	$	~~472~~(7,088	)	$	1920,~~053~~990		$	(~~103~~110,~~318~~406	)	$	3253,~~015~~005
General and administrative expenses		(1011,~~486~~337	)		(64,~~198~~638	)		(1829,~~368~~705	)		(1116,~~941~~579	)
Recovery of misappropriated funds net of liabilities assumed		~~3,397~~9			—			3,~~397~~406			—
Gain (loss) from derivative financial instruments		~~(17~~8,~~138~~752	)		~~(105~~145,~~375~~132	)		2231,~~326~~078			(~~149~~4,~~614~~482	)
Interest expense, net		(6,~~858~~920	)		(57,~~174~~187	)		(1320,~~746~~666	)		(1017,~~057~~244	)
Other income (expense) and gain on sale of assets		83			42			139			122
Other income (expense), net		(140	)		59			(1	)		181
Loss before income taxes	$	(3016,~~530~~724	)	$	~~(97~~154,~~652~~356	)	$	(~~109~~126,~~570~~294	)	$	~~(139~~14,~~475~~881	)


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

Note 12 -— Subsequent Events

We evaluated our activity after ~~June~~ September 30, 2009 until the date of issuance, ~~August~~ 17November 5, 2009, for recognized and unrecognized subsequent events not discussed elsewhere in these footnotes and determined there were none.

F-2224

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

Forward-looking statements

This quarterly report contains forward-looking statements, asthat ~~defined~~do innot ~~Section 27A~~directly ofor ~~the~~exclusively ~~Securities~~relate ~~Act~~to historical facts. You can typically identify forward-looking statements by the use of forward-looking ~~1933~~words, such as ~~amended~~“may,” or“will,” ~~the~~“could,” ~~Securities~~“project,” ~~Act~~“believe,” “intend,” “anticipate,” “expect,” “estimate,” “continue,” “potential,” “plan,” “forecast” and ~~Section 21E~~other words of similar ~~the~~import. ~~Securities~~Forward-looking statements include information concerning possible or assumed ~~Exchange~~future ~~Act~~results of ~~1934~~our operations, asincluding ~~amended~~statements about the Recombination, orprojected financial information, valuation information, possible outcomes from strategic alternatives other than the Recombination, ~~Exchange~~the ~~Act.~~expected ~~These~~amounts, ~~forward-looking~~timing ~~statements~~and ~~relate~~availability toof financing, availability under ~~among~~credit ~~other~~facilities, ~~things~~levels of capital expenditures, ~~the~~sources ~~following:~~of funds, and funding requirements, among others.

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

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

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

• fluctuations in prices of oil and natural gas; • Imports of foreign oil and natural gas, including liquefied natural gas; • future capital requirements and availability of financing; • continued disruption of credit and capital markets and the ability of financial institutions to honor their commitments; • estimates of reserves and economic assumptions; • geological concentration of our reserves;

• risks associated with drilling and operating wells; • risks associated with the operation of natural gas pipelines and gathering systems; • discovery, acquisition, development and replacement of oil and natural gas reserves; • cash flow and liquidity; • timing and amount of future production of oil and natural gas; • availability of drilling and production equipment; • marketing of oil and natural gas; • developments in oil-producing and natural gas-producing countries; • title to our properties; • litigation; • competition; • general economic conditions, including costs associated with drilling and operations of our properties; • environmental or other governmental regulations, including legislation to reduce emissions of greenhouse gases; • receipt and collectability of amounts owed to us by purchasers of our production and counterparties to our derivative financial instruments; • decisions whether or not to enter into derivative financial instruments; • events similar to those of September 11, 2001; • actions of third party co-owners of interests in properties in which we also own an interest; and • fluctuations in interest rates.

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

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

Overview of QRCP

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

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

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

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

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

Operating Highlights

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

• Increased natural gas production by approximately 297,000 Mcf from the prior year quarter. • Increased oil production by approximately 2,000 Bbls from the prior year quarter. • Increased total production by approximately 309,000 Mcfe from the prior year quarter. • Reduced oil and gas production costs by $1.11 per Mcfe from the prior year quarter.

	•		Reduced oil and gas production costs in the current quarter by $0.13 per Mcfe from the prior year quarter.

	•		Sustained natural gas production levels similar to the prior year despite minimal current period capital expenditures on acquisition and development.

Financial Highlights

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

• Reduced total debt by $2544.46 million from December 31, 2008. • Increased cash and cash equivalents by $2820.62 million from December 31, 2008. • Repriced derivatives during the second quarter of 2009 and received $26 million. • Obtained a new $8 million revolving credit facility during the third quarter of 2009 to finance the Company’s drilling program in the Appalachian Basin, general and administrative expenses, working capital and other corporate expenses.

Recent Developments

Global Financial Crisis and Impact on Capital Markets and Commodity Prices

~~During~~Currently, ~~2009~~there ~~the~~is ~~global~~unprecedented ~~economy~~uncertainty ~~has~~in ~~continued~~the tofinancial ~~experience a significant downturn~~markets. ~~There~~This ~~are~~uncertainty ~~two~~presents ~~significant~~additional ~~ramifications~~potential risks to ~~the~~us ~~exploration~~ and ~~production~~our ~~industry~~subsidiaries asand ~~the economy continues to deteriorate~~affiliates. ~~The~~These ~~first~~risks isinclude the ~~that~~availability ~~capital markets have essentially frozen. Equity, debt~~ and ~~credit markets~~costs ~~shut~~associated ~~down.~~with ~~Future~~our ~~growth~~borrowing ~~opportunities~~capabilities ~~have been~~ and ~~are~~raising ~~expected~~additional ~~to continue to be~~debt ~~constrained~~and byequity ~~the lack of access to liquidity in the financial markets~~capital.

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

~~Our~~For ~~operations~~oil, ~~and~~worldwide ~~financial~~demand ~~condition~~has ~~are~~decreased ~~significantly impacted~~ by ~~these~~over ~~prices.~~5% Onfrom ~~June 30, 2009,~~2007 ~~the~~levels ~~spot~~creating ~~market~~an ~~price~~oversupply environment ~~for~~similar to natural gas ~~at Henry Hub was $ 3~~.~~89 per~~ ~~Mmbtu, a 70.3% decrease from June 30, 2008.~~ The ~~price~~recent recovery of oil ~~has~~prices ~~shown~~into ~~similar~~the ~~volatility, with a~~ $~~69.79~~70 per ~~Bbl~~barrel ~~spot~~range ~~market~~has ~~price~~had ~~for~~a ~~oil~~small atpositive ~~Cushing,~~impact ~~Oklahoma~~on atrevenues ~~June 30,~~during ~~2009, a 50.1% decrease from June 30, 2008. In~~ the second ~~quarter~~half of 2009,. ~~our~~Our ~~average~~management ~~realized~~believes that ~~prices~~managing ~~for~~price ~~oil~~volatility ~~and~~will ~~natural~~continue ~~gas~~to ~~were $73.83~~be ~~per~~a ~~Bbl and $2~~challenge.72 ~~per~~The ~~Mcf,~~spot ~~respectively,~~market ~~compared~~price ~~with~~for ~~second~~oil ~~quarter~~at Cushing, ~~2008~~Oklahoma ~~average~~at ~~realized prices~~September 30, of2009 was $~~111~~70.2546 per ~~Bbl~~barrel, ~~and~~a $930.280% ~~per~~decrease ~~Mcf~~from the price at September 30, ~~respectively~~2008. It is impossible to predict the duration or outcome of these price declines or the long-term impact on drilling and operating costs and the impacts, whether favorable or unfavorable, to our results of operations and liquidity. Natural gas prices came under pressure in the second half of 2008, and continued into 2009 as a result of lower domestic product demand that was caused by the weakening economy and concerns over excess supply of natural gas. In the Cherokee Basin, where we produce and sell most of our gas, there has been a widening of the historical discount of prices in the area to the NYMEX pricing point at Henry Hub as a result of elevated levels of natural gas drilling activity in the region and a lack of pipeline takeaway capacity. During the second quarter of 2009, this discount (or basis differential) in the Cherokee Basin ranged from $0.67 per Mmbtu to $1.06 per Mmbtu. Due to our relatively low level of oil production relative to gas and our existing commodity hedge positions, the volatility of oil prices had less of an effect on our operations.

impacts, whether favorable or unfavorable, to our results of operations, liquidity and capital resources. Due to our relatively low level of oil production relative to gas and our existing commodity hedge positions, the volatility of oil prices had less of an effect on our operations.

Suspension of Distributions and Asset Sale

~~Distributions~~Quest Midstream has not paid any distributions on any of its units since the second quarter of 2008, and Quest Energy suspended its distributions on its subordinated units starting with the third quarter of 2008 and on all units starting with the fourth quarter of 2008. Distributions on all of Quest Energy’s and Quest Midstream’s units continue to be suspended., and we are unable to estimate when such distributions may, if ever, be resumed. Since these distributions would have been substantially all of QRCP’s cash flows for 2009, the loss of these distributions was material to QRCP’s financial position. QRCP received cash distributions from Quest Energy and Quest Midstream of $712.9 million for the ~~six~~ nine months ended ~~June~~September 30, 2008 and did not receive any cash distributions from Quest Energy and Quest Midstream for the ~~six~~nine months ended ~~June~~September 30. , 2009.

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

Settlement Agreements

As discussed in our 2008 Form 10-K/A, we filed lawsuits, related to certain unauthorized transfers, repayments and re-transfers of funds (the “Transfers”) to entities controlled by Jerry D. Cash, our former chief executive officer, seeking, among other things, to recover the funds that were transferred. On May 19, 2009, we entered into settlement agreements with Mr. Cash, the controlled-entity and the other owners to settle this litigation. Under the terms of the settlement, and based on a settlement allocation agreed to by the board of directors of QRCP ~~and~~ and QELP, QRCP received (1) approximately $2.4 million in cash and (2) 60% of the controlled-entity’s interest in a gas well located in Louisiana and a landfill gas development project located in Texas ~~and~~ and QELP received Mr. Cash’s interest in STP Newco, Inc (“STP”) which consisted of 100% of the common stock of the company. While QRCP estimates the value of these assets to be less than the amount of the unauthorized transfers and cost of the internal investigation, Mr. Cash represented that they comprise all of Mr. Cash’s net worth and the majority of the value of the controlled-entity. We did not take Mr. Cash’s stock in QRCP, which he represented had been pledged to secure personal loans with a principal balance far in excess of the current market value of the stock. STP owns interests in certain oil producing properties in Oklahoma, and other assets and liabilities. STP’s accounting and operation records provided to QELP, at the date of the settlement, were in poor condition and we are in the process of reconstructing the financial records in order to determine the estimated fair value of the assets acquired and liabilities assumed in connection with the settlement. Based on documents we received prior to the settlement, the estimated fair value of the net assets to be assumed was expected to provide QELP reimbursement for all of the costs of the internal investigation and the costs of the litigation against Mr. Cash that have been paid by QELP; however, the financial information we received prior to closing contained errors related to Mr. Cash’s ownership interests in the properties as well as amounts due vendors and royalty owners. Based on work performed to date we believe that the actual estimated fair value of net assets of STP that QELP received is less than previously expected. We expect to complete our analysis of STP’s financial information and our final valuation of the oil producing properties obtained from STP by December 31, 2009. We also are in the process of determining what further actions can be taken with regards to this and intend to pursue all remedies available under the law. Based on the information available at this time, we have estimated the fair value of the assets and liabilities obtained in connection with the settlement. As additional information becomes available other assets and/or liabilities may be identified and recorded. The estimated fair value of the assets and liabilities received is as follows (in thousands):

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

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

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

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


	QRCP		QELP			Total
Cash, net of legal expenses	$	2,429	$	—		$	2,429
Oil and gas properties		896		1,076			1,972
Other assets		50		—			50
Current liabilities		—		(326	)		(326	)
Long-term debt		—		(719	)		(719	)

Net assets received	$	3,375	$	31		$	3,406

Recombination

On July 2, 2009, weQRCP, Quest Midstream, Quest Energy and other parties thereto entered into an Agreement and Plan of Merger (~~“The~~the “Merger Agreement”) ~~with~~pursuant ~~Quest~~to ~~Energy~~which, ~~Quest~~following ~~Midstream,~~a ~~and~~series of ~~other~~mergers ~~parties~~and ~~thereto~~an ~~pursuant~~entity conversion, QRCP, Quest Energy and the successor to ~~which~~Quest weMidstream ~~would~~will become ~~form~~wholly-owned asubsidiaries ~~new,~~of ~~yet~~PostRock toEnergy beCorporation ~~named~~(“PostRock”) a new, publicly-traded corporation ~~that~~(the “Recombination”). On October 2, ~~through~~2009, athe ~~series~~Merger Agreement was amended to, among other things, reflect certain technical changes as the result of ~~mergers~~an ~~and~~internal ~~entity~~restructuring. ~~conversions~~On October 6, ~~would~~2009, ~~wholly~~PostRock filed with the SEC a registration statement on Form S-~~own~~4, ~~all~~which ~~three~~included a ~~entities~~joint (proxy statement/prospectus, relating to the “Recombination”).

While we ~~anticipate~~are working toward the completion of the Recombination before ~~year-~~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~~PostRock ~~Quest~~and its subsidiaries, the approval of the transaction by ~~the~~ ~~unitholders~~our ofstockholders ~~Quest~~and ~~Energy,~~ the unitholders of ~~Quest~~QELP ~~Midstream~~ and ~~our stockholders~~QMLP, and consents from each entity’s existing lenders. There can be no assurance that these conditions will be met or that the Recombination will occur.

Upon completion of the Recombination, the equity of ~~New~~PostRock ~~Quest~~ would be owned approximately 44% by current ~~Quest~~QMLP ~~Midstream~~ common unitholders, approximately 33% by ~~QELP’s~~ current QELP common unitholders (other than QRCP), and approximately 23% by ~~our~~ current QRCP stockholders.

Credit Agreement Amendments

QRCP

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

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

Quest Energy

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

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

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

Results of Operations

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

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

Three Months Ended

~~Six~~Nine Months Ended

June 30,

September 30,

2009

2008

2009

2008

Revenues:

Oil and gas sales

1618,~~107~~329

49,~~144~~531

3856,~~382~~711

87136,~~458~~989

Natural gas pipelines

1916,~~616~~635

1516,~~823~~095

3952,~~926~~260

3147,~~387~~482

Elimination of inter-segment revenue

(1211,~~030~~002

)

(8,~~675~~583

)

(2431,~~537~~238

)

(1725,~~338~~921

)

Natural gas pipelines, net of inter-segment revenue

75,~~586~~633

7,~~148~~512

1521,~~389~~022

1421,~~049~~561

Total segment revenues

23,~~693~~962

5657,~~292~~043

5377,~~771~~733

~~101~~158,~~507~~550

Operating profit (loss):

Oil and gas production

(811,~~233~~342

)

1518,~~615~~005

(~~121~~128,~~205~~246

)

2442,~~233~~237

Natural gas pipelines

84,~~705~~254

32,~~438~~985

17,~~887~~840

710,~~782~~768

Total segment operating profit (loss)

~~472~~(7,088

)

1920,~~053~~990

(~~103~~110,~~318~~406

)

3253,~~015~~005

General and administrative expenses

(1011,~~486~~337

)

(64,~~198~~638

)

(1829,~~368~~705

)

(1116,~~941~~579

)

Recovery of misappropriated funds, net of liabilities assumed

~~3,397~~9

—

3,~~397~~406

—

Total operating income (loss)

(618,~~617~~416

)

1216,~~855~~352

(~~118~~136,~~289~~705

)

2036,~~074~~426

~~Three Months Ended June 30, 2009 Compared to the Three Months Ended June 30, 2008~~4

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

Oil and Gas Production Segment

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

	Three Months Ended
	June 30,				Increase/
	September 30,				Increase/
	2009		2008		(Decrease)
Oil and gas sales	$	1618,~~107~~329	$	49,~~144~~531	$	(3331,~~037~~202	)	(6763.20	)%
Oil and gas production costs	$	78,~~274~~739	$	129,~~631~~963	$	(51,~~357~~224	)	(4212.43	)%
Transportation expense (intercompany)	$	1211,~~030~~002	$	8,~~675~~583	$	32,~~355~~419		3828.72	%
Depreciation, depletion and amortization	$	59,~~036~~930	$	12,~~223~~980	$	(73,~~187~~050	)	(5823.85	)%
Production Data:
Natural gas production (Mmcf)		5,~~392~~389		5,~~095~~694		~~297~~(305	)	(5.84	)%
Oil production (Mbbl)		1920		1719		21		115.83	%
Total production (Mmcfe)		5,~~506~~512		5,~~197~~808		~~309~~(296	)	(5.91	)%
Average daily production (Mmcfe/d)		6059.59		5763.1		(3.42	)	6(5.01	)%


	Three Months Ended
	September 30,				Increase/
	2009		2008		(Decrease)
Average Sales Price per Unit:
Natural gas (Mcf)	$	3.15	$	8.31	$	(5.16	)	(62.1	)%
Oil (Bbl)	$	64.08	$	116.89	$	(52.81	)	(45.2	)%
Natural gas equivalent (Mcfe)	$	3.33	$	8.53	$	(5.20	)	(61.0	)%
Average Unit Costs per Mcfe:
Production costs	$	1.59	$	1.72	$	(0.13	)	(7.6	)%
Transportation expense (intercompany)	$	2.00	$	1.48	$	0.52		35.1	%
Depreciation, depletion and amortization	$	1.80	$	2.23	$	(0.43	)	(19.3	)%

Oil and Gas Sales. Oil and gas sales decreased $31.2 million, or 63.0%, to $18.3 million during the three months ended September 30, 2009. This decrease was primarily due to a decrease in average realized prices which resulted in decreased revenues of $30.2 million. Lower production volumes decreased revenue by an additional $1.0 million. Our average realized prices on an equivalent basis (Mcfe) decreased to $3.33 per Mcfe for the three months ended September 30, 2009, from $8.53 per Mcfe for the three months ended September 30, 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 $1.2 million, or 6.4%, to $19.7 million for the three months ended September 30, 2009, from $18.5 million for the three months ended September 30, 2008.

Oil and gas production costs decreased $1.2 million, or 12.3%, to $8.7 million during the three months ended September 30, 2009, from $10.0 million during the three months ended September 30, 2008. This decrease was primarily due to cost-cutting measures that began in the third quarter of 2008 continuing into the current year. Field headcount was reduced by approximately half while overtime hours were simultaneously reduced for the three months ended September 30, 2009 compared to the three months ended September 30, 2008. Well service improvement measures resulted in fewer wells going offline, reduced loss of production due to offline wells, and fewer well repairs in the current quarter compared to the prior year quarter. Production costs including gross production taxes and ad valorem taxes were $1.59 per Mcfe for the three months ended September 30, 2009 as compared to $1.72 per Mcfe for the three months ended September 30, 2008. The decrease in per unit cost was due to the cost-cutting and well service improvement measures discussed above.

Transportation expense increased $2.4 million, or 28.2%, to $11.0 million during the three months ended September 30, 2009, from $8.6 million during the three months ended September 30, 2008. The increase was primarily due to an increase in the contracted transportation fee. Transportation expense was $2.00 per Mcfe for the three months ended September 30, 2009 as compared to $1.48 per Mcfe for the three months ended September 30, 2008.

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

Depreciation, Depletion and Amortization. We are subject to variances in our depletion rates from period to period due to changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties. Our depreciation, depletion and amortization decreased approximately $3.1 million, or 23.5%, during the three months ended September 30, 2009 to $9.9 million from $13.0 million during the three months ended September 30, 2008. On a per unit basis, we had an decrease of $0.43 per Mcfe to $1.80 per Mcfe during the three months ended September 30, 2009 from $2.23 per Mcfe during the three months ended September 30, 2008. This decrease was primarily due to the impairment of our oil and gas properties in the fourth quarter of 2008 and the first quarter of 2009, which decreased our rate per unit, as well as the resulting decrease in the depletable pool.

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

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

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

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

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

Natural Gas Pipelines Segment

Natural gas pipelines segment data for the periods indicated are as follows (in thousands, except unit and per unit data):


	Three Months Ended
	September 30,
	2009		2008		Increase/ (Decrease)
Natural Gas Pipeline Revenue:
Gas pipeline revenue — Third Party	$	5,633	$	7,512	$	(1,879	)	(25.0	)%
Gas pipeline revenue — Intercompany		11,002		8,583		2,419		28.2	%

Total natural gas pipeline revenue	$	16,635	$	16,095	$	540		3.4	%
Pipeline operating expense	$	8,243	$	7,737	$	506		6.5	%
Depreciation and amortization expense	$	4,138	$	5,373	$	(1,235	)	(23.0	)%
Throughput Data (Mmcf):
Throughput — Third Party		1,761		1,509		252		16.7	%
Throughput — Intercompany		6,062		6,578		(516	)	(7.8	)%

Total throughput (Mmcf)		7,823		8,087		(264	)	(3.3	)%
Average Pipeline Operating Costs per Mcf:
Pipeline operating expense	$	1.05	$	0.96	$	0.09		9.4	%
Depreciation and amortization	$	0.53	$	0.66	$	(0.13	)	(19.7	)%

~~Table~~ Pipeline ofRevenue. ~~Contents~~Total natural gas pipeline revenue increased $0.5 million to $16.6 million for the three months ended September 30, 2009 from $16.1 million for the three months ended September 30, 2008.

	Three Months Ended
	June 30,
	2009		2008		Increase/ (Decrease)
Natural Gas Pipeline Revenue:
Gas pipeline revenue — Third Party	$	7,586	$	7,148	$	438		6.1	%
Gas pipeline revenue — Intercompany		12,030		8,675		3,355		38.7	%
Total natural gas pipeline revenue	$	19,616	$	15,823	$	3,793		24.0	%
Pipeline operating expense	$	6,861	$	8,164	$	(1,303	)	(16.0	)%
Depreciation and amortization expense	$	4,050	$	4,221	$	(171	)	(4.1	)%
Throughput Data (Mmcf):
Throughput — Third Party		2,651		1,455		1,196		82.2	%
Throughput — Intercompany		6,224		6,201		23		0.4	%
Total throughput (Mmcf)		8,875		7,656		1,219		15.9	%
Average Pipeline Operating Costs per Mmcf:
Pipeline operating expense	$	0.77	$	1.07	$	(0.30	)	(28.0	)%
Depreciation and amortization	$	0.46	$	0.55	$	(0.09	)	(16.4	)%

Third party natural gas pipeline revenue decreased $1.9 million, or 25.0%, to $5.6 million during the three months ended September 30, 2009, from $7.5 million during the three months ended September 30, 2008.

~~Pipeline~~Intercompany ~~Revenue. Total~~ natural gas pipeline revenue increased $32.84 million, or 2428.02%, to $1911.60 million during the three months ended ~~June~~September 30, 2009, from $~~15.~~8.6 million during the three months ended ~~June~~ September 30, 2008. The increase was primarily due to a higher contracted rate in 2009.

~~Third~~Pipeline ~~party~~Operating ~~natural~~Expense. ~~gas~~Pipeline ~~pipeline~~operating ~~revenue~~expense increased $0.45 million, or 6.15%, to $78.62 million during the three months ended ~~June~~September 30, 2009, from $7.17 million during the three months ended ~~June~~ September 30, 2008. ~~The~~Pipeline ~~increase~~operating ~~was~~costs ~~primarily~~per ~~due~~unit toincreased a$0.09 ~~higher~~per ~~contract~~Mcf ~~rate~~during the inthree months ended September 30, 2009, asfrom ~~well~~$0.96 asper ~~higher throughput~~Mcf ~~volumes~~to ~~during~~$1.05 ~~the~~per ~~three~~Mcf. ~~months~~The ~~ended~~increase ~~June 30,~~in ~~2009~~per unit ~~compared~~cost towas the ~~three~~result ~~months~~of ~~ended June 30,~~lower ~~2008~~volumes over which to spread fixed costs.

~~Intercompany~~Depreciation ~~natural~~and ~~gas~~Amortization. ~~pipeline~~Depreciation ~~revenue~~and ~~increased~~amortization expense decreased $31.42 million, or 3823.70%, to $124.01 million during the three months ended ~~June~~September 30, 2009, from $85.74 million during the three months ended ~~June~~ September 30, 2008. ~~The~~Depreciation ~~increase~~and ~~was~~amortization ~~primarily~~per ~~due~~unit decreased $0.13, or 19.7%, to a$0.53 ~~higher~~per ~~contracted~~Mcf ~~rate~~for inthe ~~2009,~~three asmonths ~~well~~ended asSeptember 30, a2009 from $0.~~4% increase~~66 inper ~~throughput~~Mcf for ~~volumes~~the ~~from~~three ~~our~~months ~~Cherokee~~ended ~~Basin~~September 30, ~~properties~~2008.

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

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

Unallocated Items

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

General and Administrative Expenses. General and administrative expenses increased $46.37 million, or 69144.24%, to $1011.53 million during the three months ended ~~June~~September 30, 2009, from $64.~~2 million~~6 million during the three months ended ~~June~~September 30, 2008. The increase is primarily due to increased ~~legal,~~accounting ~~investment~~and ~~banker,~~ audit ~~and~~ ~~other professional~~ fees inrelated ~~connection~~to ~~with~~our ~~the restatement and~~ reaudits ~~of our financial statements~~ and ~~recombination~~restatements ~~activities~~as ~~partially~~well ~~offset~~as ~~by reduced stock compensation expense.~~legal, investment

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

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

~~Six~~banker, ~~Months~~audit ~~Ended~~and ~~June 30,~~other ~~2009~~professional ~~Compared~~fees toin connection with the ~~Six~~Recombination ~~Months~~activities partially ~~Ended~~offset ~~June 30,~~by ~~2008~~reduced stock compensation expense.

Gain from Derivative Financial Instruments. Gain from derivative financial instruments decreased $136.4 million to $8.8 million for the three months ended September 30, 2009, from $145.1 million for the three months ended September 30, 2008. We recorded a $10.9 million unrealized loss and $19.6 million realized gain on our derivative contracts for the three months ended September 30, 2009 compared to a $152.7 million unrealized gain and $7.5 million realized loss for the three months ended September 30, 2008. Unrealized gains and losses are attributable to changes in oil and natural gas prices and volumes hedged from one period end to another.

Interest expense, net. Interest expense, net, decreased $0.3 million, or 4.2%, to $6.9 million during the three months ended September 30, 2009, from $7.2 million during the three months ended September 30, 2008. The decrease is primarily due to lower interest rates on QELP’s and QMLP’s revolving credit facilities offset by a $0.8 million write-off of unamortized debt issuance cost associated with the modification of QRCP’s Credit Agreement (See “—Liquidity and Capital Resources—Sources of Liquidity in 2009 and Capital Requirements—Credit Agreements—QRCP—Modification of debt” below)

Nine Months Ended September 30, 2009 Compared to the Nine Months Ended September 30, 2008

Oil and Gas Production Segment

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

	Six Months Ended
	Nine Months Ended
	June 30,				Increase/
	September 30,				Increase/
	2009		2008		(Decrease)
Oil and gas sales	$	3856,~~382~~711	$	87136,~~458~~989	$	(4980,~~076~~278	)	(5658.16	)%
Oil and gas production costs	$	1423,~~960~~699	$	2333,~~037~~000	$	(89,~~077~~301	)	(3528.12	)%
Transportation expense (intercompany)	$	2431,~~537~~238	$	1725,~~338~~921	$	75,~~199~~317		4120.5	%
Depreciation, depletion and amortization	$	1727,~~188~~118	$	2235,~~851~~831	$	(58,~~663~~713	)	(24.83	)%
Impairment of oil and gas properties	$	102,902		—	$	102,902		*
Production Data:
Natural gas production (Mmcf)		1016,~~809~~198		1015,~~061~~755		~~748~~443		72.48	%
Oil production (BBbl)		40		28		12		42.9	%
Oil production (Mbbl)		60		47		13		27.7	%
Total production (Mmcfe)		1116,~~049~~558		1016,~~228~~037		~~821~~521		83.02	%
Average daily production (Mmcfe/d)		6160.07		5658.25		42.82		83.58	%
Average Sales Price per Unit:
Natural gas (Mcf)	$	3.28	$	8.40	$	(5.12	)	61.0	%
Oil (Bbl)	$	73.47	$	105.96	$	(32.49	)	(30.7	)%
Natural gas equivalent (Mcfe)	$	3.47	$	8.55	$	(5.08	)	(59.4	)%
Average Unit Costs per Mcfe:
Production costs	$	1.35	$	2.25	$	(0.90	)	(40.0	)%
Transportation expense (intercompany)	$	2.22	$	1.70	$	0.52		30.6	%
Depreciation, depletion and amortization	$	1.56	$	2.23	$	(0.67	)	(30.0	)%

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


	Nine Months Ended
	September 30,				Increase/
	2009		2008		(Decrease)
Average Sales Price per Unit:
Natural gas (Mcf)	$	3.31	$	8.37	$	(5.06	)	(60.5	)%
Oil (Bbl)	$	52.38	$	110.40	$	(58.02	)	(52.6	)%
Natural gas equivalent (Mcfe)	$	3.42	$	8.54	$	(5.12	)	(60.0	)%
Average Unit Costs per Mcfe:
Production costs	$	1.43	$	2.06	$	(0.63	)	(30.6	)%
Transportation expense (intercompany)	$	1.89	$	1.62	$	0.27		16.7	%
Depreciation, depletion and amortization	$	1.64	$	2.23	$	(0.59	)	(26.5	)%

~~Oil~~* ~~and~~not Gas Operating Expenses. Oil and gas operating expenses consist of oil and gas production costs, which include lease operating expenses, severance taxes and ad valorem taxes, and transportation expense. Oil and gas operating expenses decreased $0.9 million, or 2.2%, to $39.5 million during the six months ended June 30, 2009, from $40.4 million during the six months ended June 30, 2008.meaningful

Oil and ~~gas~~Gas ~~production~~Sales. ~~costs~~Oil and gas sales decreased $880.13 million, or 3558.16%, to $1556.07 million ~~during~~ for the ~~six~~ nine months ended ~~June~~September 30, 2009, from $23137.0 million ~~during~~for the ~~six~~nine months ended ~~June~~ September 30, 2008. This decrease was primarily ~~due cost-cutting measures implemented in~~ the ~~third~~result ~~quarter~~ of ~~2008.~~a ~~Field headcount~~decrease ~~was~~in ~~reduced~~average byrealized ~~29.7%~~sales ~~while~~prices, offset, ~~simultaneously reducing overtime hours for the six months ended June 30~~minimally, ~~2009~~by ~~compared~~an toincrease ~~the~~in ~~six months ended June 30, 2008~~volumes. The ~~reductions~~decrease ~~came~~in ataverage ~~the~~realized ~~same~~sales ~~time we absorbed the operations of PetroEdge which increased our~~prices ~~total~~resulted ~~production,~~in ~~further~~a ~~reducing~~decrease ~~our~~in ~~cost~~revenues ~~per~~of ~~Mcfe~~$82.1 million. ~~Production~~Our ~~costs~~average ~~including~~realized ~~gross~~prices ~~production~~on ~~taxes~~an ~~and~~equivalent basis ad(Mcfe) ~~valorem~~decreased ~~taxes were~~to $13.3542 per Mcfe for the ~~six~~nine months ended ~~June~~September 30, 2009 asfrom ~~compared to~~ $28.25 54 per Mcfe for the ~~six~~ nine months ended ~~June~~September 30, 2008. ~~The~~Offsetting this decrease inwere ~~per~~additional volumes ~~unit~~of ~~cost~~521 ~~was~~Mmcfe, ~~due~~accounting tofor ~~the~~an ~~cost-cutting~~increase ~~measure discussed~~in ~~above,~~revenues asof ~~well~~$1.8 million. asThe ~~higher~~increased volumes primarily ~~over~~resulted ~~which~~from toour ~~spread~~acquisition ~~fixed~~of ~~costs~~oil and gas producing properties from PetroEdge Resources (WV) LLC (“PetroEdge”) on July 11, 2008.

107

~~Transportation~~Oil ~~expense~~and ~~increased~~Gas ~~$7.2 million,~~Operating ~~or 41~~Expenses.~~5%,~~ toOil ~~$24.5 million~~and ~~during~~gas ~~the~~operating ~~six months~~expenses ~~ended~~consist ~~June 30,~~of ~~2009,~~oil ~~from~~and ~~$17.3 million~~gas production ~~during~~costs, ~~the~~which ~~six~~include ~~months~~lease ~~ended~~operating ~~June 30~~expenses, ~~2008.~~severance ~~The increase~~taxes ~~was~~and ~~primarily~~ad ~~due~~valorem ~~to the increase in the contracted rate in 2009 compared to 2008~~taxes, ~~as well~~and astransportation ~~increased volumes of 821 Mmcfe~~expense. ~~The~~Oil ~~per~~and ~~unit~~gas ~~cost~~operating ~~increased~~expenses decreased $04.520 million, ~~per~~or ~~Mcfe~~6.8%, to $254.229 million ~~per~~during ~~Mcfe for~~ the ~~six~~nine months ended ~~June~~September 30, 2009, asfrom ~~compared to~~ $158.709 million ~~per~~during ~~Mcfe for~~ the ~~six~~nine months ended ~~June~~September 30, 2008.

~~Depreciation,~~Oil ~~Depletion~~ and ~~Amortization.~~gas Weproduction ~~are~~costs ~~subject~~decreased to$9.3 million, ~~variances~~or in28.2%, ~~our~~to ~~depletion~~$23.7 million ~~rates~~during the ~~from~~nine ~~period~~months toended ~~period~~September 30, ~~due~~2009, tofrom ~~changes~~$33.0 million induring ~~our~~the ~~oil~~nine ~~and~~months ~~gas~~ended ~~reserve quantities~~September 30, 2008. ~~production~~This ~~levels, product~~decrease ~~prices~~was ~~and~~primarily ~~changes~~due to cost-cutting measures that began in the ~~depletable~~third ~~cost~~quarter ~~basis~~ of 2008 ~~our~~continuing ~~oil~~into ~~and~~the ~~gas~~current ~~properties~~year. ~~Our depreciation,~~Field ~~depletion~~headcount ~~and~~was ~~amortization~~reduced ~~decreased~~by approximately ~~$5.7 million,~~one-third orwhile ~~24.8%,~~overtime inhours were simultaneously reduced for the nine months ended September 30, 2009 ~~period~~compared to ~~$17.2 million~~the ~~from~~nine months ~~$22.9~~ended September ~~million~~30, in 2008. OnThe areductions ~~per~~came ~~unit~~at ~~basis,~~the same time we ~~had~~absorbed anthe ~~decrease~~operations of ~~$0.67~~PetroEdge ~~per~~which ~~Mcfe~~increased toour ~~$1.56~~total ~~per~~production, ~~Mcfe~~further inreducing ~~2009~~our ~~from~~cost ~~$2.23~~ per Mcfe. Well service improvement measures resulted in ~~2008.~~fewer ~~This~~wells ~~decrease~~going ~~was~~offline, ~~primarily~~ reduced loss of production due to offline ~~the~~wells, ~~impairment~~and offewer ~~our~~well ~~oil~~repairs ~~and~~for ~~gas~~the ~~properties~~current inperiod compared to the ~~fourth~~prior ~~quarter~~year ofperiod. Production ~~2008~~costs including gross production taxes and ~~the~~ad ~~first~~valorem taxes were $1.43 per Mcfe for the ~~quarter~~nine ofmonths ended September 30, 2009 as compared to $2.06 per Mcfe for the nine months ended September 30, ~~which~~2008. ~~decreased~~The ~~our~~decrease ~~rate~~in per unit cost was due to the cost-cutting and well service improvement measures discussed above, as well as ~~the~~slightly ~~resulting~~higher ~~decrease~~volumes inover ~~the depletable~~which ~~pool~~to spread fixed costs.

~~Natural~~ Transportation ~~Gas~~expense ~~Pipelines~~increased ~~Segment~~$5.3 million, or 20.5%, to $31.2 million during the nine months ended September 30, 2009, from $25.9 million during the nine months ended September 30, 2008. The increase was primarily due to the increase in the contracted rate in 2009 compared to 2008, as well as increased volumes of 521 Mmcfe. The per unit cost increased $0.27 per Mcfe to $1.89 per Mcfe for the nine months ended September 30, 2009 as compared to $1.62 per Mcfe for the nine months ended September 30, 2008.

~~Natural~~ 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 ~~pipelines~~reserve ~~segment~~quantities, ~~data~~production ~~for~~levels, product prices and changes in the ~~periods~~depletable ~~indicated~~cost ~~are~~basis of our oil and gas properties. Our depreciation, depletion and amortization decreased approximately $8.7 million, or 24.3%, during the nine months ended September 30, 2009 to $27.1 million from $35.8 million during the nine months ended September 30, 2008. On a per unit basis, we had a decrease of $0.59 per Mcfe to $1.64 per Mcfe during the nine months ended September 30, 2009 from $2.23 per Mcfe during the nine months ended September 30, 2008. This decrease was primarily due to the impairments of our oil and gas properties in the fourth quarter of 2008 and the first quarter of 2009, which decreased our rate per unit, as ~~follows~~well (as the resulting decrease in ~~thousands):~~the depletable pool.

	Six Months Ended
	June 30,
	2009		2008		Increase/ (Decrease)
			(Restated)
			($ in thousands)
Natural Gas Pipeline Revenue:
Gas pipeline revenue — Third Party	$	15,389	$	14,049	$	1,340		9.5	%
Gas pipeline revenue — Intercompany		24,537		17,338		7,199		41.5	%
Total natural gas pipeline revenue	$	39,926	$	31,387	$	8,539		27.2	%
Pipeline operating expense	$	14,021	$	15,122	$	(1,101	)	(7.3	)%
Depreciation and amortization expense	$	8,018	$	8,482	$	(464	)	(5.5	)%
Throughput Data (Mmcf):
Throughput — Third Party		7,040		5,962		1,078		18.1	%
Throughput — Intercompany		12,644		12,284		360		2.9	%
Total throughput (Mmcf)		19,684		18,246		1,438		7.9	%
Average Pipeline Operating Costs per Mmcf:
Pipeline operating expense	$	0.71	$	0.83	$	(0.12	)	(14.5	)%
Depreciation and amortization	$	0.41	$	0.46	$	(0.05	)	(10.9	)%

Impairment of Oil and Gas Properties. Under the present full cost accounting rules, we are required to compute the after-tax present value of our proved oil and natural gas properties using spot market prices for oil and natural gas at our balance sheet date. The Company had previously recognized a ceiling test impairment of $102.9 million during the first quarter of 2009. No impairment was necessary for the second quarter of 2009. As of September 30, 2009, the ceiling test computation utilizing spot prices on that day resulted in the carrying costs of our unamortized proved oil and natural gas properties, net of deferred taxes, exceeding the September 30, 2009 present value of future net revenues by approximately $11.1 million. As a result of subsequent increases in spot prices, the need to recognize an impairment for the quarter ended September 30, 2009, was eliminated. No impairment was necessary for the three month and nine month periods ending September 30, 2008, due to the level of oil and natural gas prices during those periods.

~~Pipeline Revenue. Total natural gas pipeline revenue increased $~~8~~.5 million, or 27.2%, to~~ ~~$39.9 million during the six months ended June 30, 2009, from $31.4 million during the six months ended June 30, 2008.~~

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

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

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

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

Natural gas pipelines segment data for the periods indicated are as follows (in thousands, except unit and per unit data):


	Nine Months Ended
	September 30,
	2009		2008		Increase/ (Decrease)
	($ in thousands)
Natural Gas Pipeline Revenue:
Gas pipeline revenue — Third Party	$	21,022	$	21,561	$	(539	)	(2.5	)%
Gas pipeline revenue — Intercompany		31,238		25,921		5,317		20.5	%

Total natural gas pipeline revenue	$	52,260	$	47,482	$	4,778		10.1	%
Pipeline operating expense	$	22,264	$	22,859	$	(595	)	(2.6	)%
Depreciation and amortization expense	$	12,156	$	13,855	$	(1,699	)	(12.3	)%
Throughput Data (Mmcf):
Throughput — Third Party		8,801		7,471		1,330		17.8	%
Throughput — Intercompany		18,706		18,862		(156	)	(0.8	)%

Total throughput (Mmcf)		27,507		26,333		1,174		4.5	%
Average Pipeline Operating Costs per Mcf:
Pipeline operating expense	$	0.81	$	0.87	$	(0.06	)	(6.9	)%
Depreciation and amortization	$	0.44	$	0.53	$	(0.09	)	(17.0	)%

Pipeline Revenue. Total natural gas pipeline revenue increased $4.8 million, or 10.1%, to $52.3 million during the nine months ended September 30, 2009, from $47.5 million during the nine months ended September 30, 2008.

Third party natural gas pipeline revenue was generally flat, decreasing $0.5 million, or 2.5%, to $21.0 million during the nine months ended September 30, 2009, from $21.6 million during the nine months ended September 30, 2008.

Intercompany natural gas pipeline revenue increased $5.3 million, or 20.5%, to $31.2 million during the nine months ended September 30, 2009, from $25.9 million during the nine months ended September 30, 2008. The increase is primarily due to the increase in the contracted rate for 2009.

Pipeline Operating Expense. Pipeline operating expense was generally flat, decreasing $0.6 million, or 2.6%, to $22.3 million during the nine months ended September 30, 2009 from $22.9 million during the nine months ended September 30, 2008. Pipeline operating costs per unit decreased $0.06 per Mcf, from $0.87 per Mcf for the nine months ended September 30, 2008 to $0.81 per Mcf for the nine months ended September 30, 2009. The decrease in per unit cost was the result of the cost-cutting efforts, as well as higher volumes over which to spread fixed costs.

Depreciation and Amortization. Depreciation and amortization expense decreased $1.7 million, or 12.3%, to $12.2 million during the nine months ended September 30, 2009, from $13.9 million during the nine months ended September 30, 2008.

Unallocated Items

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

General and Administrative Expenses. General and administrative expenses increased $613.51 million, or 5379.82%, to $1829.47 million during the ~~six~~nine months ended ~~June~~September 30, 2009, from $1116.~~9 million~~6 million during the ~~six~~nine months ended ~~June~~September 30, 2008. The increase is primarily due to the ~~internal~~ ~~investigation and restatements and reaudits,~~ increased legal, consulting and ~~consulting~~audit ~~expense~~fees due to the reaudits and restatements ~~partially~~of ~~offset~~our byfinancial statement ~~reduced~~as ~~stock~~well ~~compensation~~as ~~expense~~increased legal, investment banker, and other professional fees in connection with our Recombination activities.

Gain (loss) from derivative financial instruments. Gain from derivative financial instruments increased $~~171~~35.96 million to $2231.31 million during the ~~six~~nine months ended ~~June~~September 30, 2009, from a loss of $~~149~~4.65 million during the ~~six~~nine months ended ~~June~~September 30, 2008. We recorded a $4152.20 million ~~unrealized~~ unrealized loss and $6383.5 1 million realized gain on our derivative contracts for the ~~six~~nine months ended ~~June~~September 30, 2009 compared to a $~~139~~13.3 million unrealized ~~loss~~gain and $1017.38 million realized loss for the ~~six~~ nine months ended ~~June 30, 2008. The increase in realized~~ ~~gain was due to the $26 million cash received as a result of exiting certain of our above market derivative financial instruments.~~

~~Interest~~9 expense. Interest expense increased $3.7 million, or 36.7%, to $13.7 million during the six months ended June 30, 2009, from $10.1 million during the six months ended June 30, 2008. The increase is primarily due to a higher average outstanding debt balance for the six months ended June 30, 2009 compared to the six months ended June 30, 2008.

September 30, 2008. The increase in realized gain included the $26 million cash received as a result of amending or exiting certain of our above market derivative financial instruments.

Interest expense, net. Interest expense, net, increased $3.4 million, or 19.8% to $20.7 million during the nine months ended September 30, 2009, from $17.2 million during the nine months ended September 30, 2008. The increase is primarily due to a higher average outstanding debt balance for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008 as well as a $0.8 million write-off of unamortized debt issuance cost associated with the modification of QRCP’s Credit Agreement in the third quarter of 2009 (See “—Liquidity and Capital Resources—Sources of Liquidity in 2009 and Capital Requirements—Credit Agreements—QRCP—Modification of Debt” below).

Liquidity and Capital Resources

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

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

At ~~June~~ September 30, 2009, Quest Energy had $1160.0 million ofoutstanding and no additional availability under its revolving credit facility. In ~~July~~ July 2009, the borrowing base under ~~its~~Quest Energy’s credit agreement was reduced from $190 million to $160 million, which, following the principal payment of $15.0 million Quest Energy made on June 30, 2009, resulted in the outstanding borrowings under the credit facility exceeding the new borrowing base by $14 million. In anticipation of the reduction in the borrowing base, Quest Energy amended or exited certain of its above market natural gas price derivative contracts and, in return, received approximately $26 million. At the same time, Quest Energy entered into new natural gas price derivative contracts to increase the total amount of its future estimated proved developed producing natural gas production hedged to approximately 85% through 2013. On July 8, 2009, Quest Energy repaid the $14 million borrowing base deficiency. Quest Energy anticipates that in connection with the redetermination of its borrowing base in November 2009, its borrowing base will be further reduced from its current level of $160 million. ~~Borrowing~~In ~~Base~~the ~~Deficiency~~event of a borrowing base reduction, Quest Energy expects to be able to make the required payments resulting from the borrowing base deficiency out of existing funds.

At ~~June~~ September 30, 2009, Quest Midstream had $~~125~~121.1 7 million outstanding ~~and~~under $9its revolving credit facility.9 ~~million~~On ofAugust 19, ~~availability~~2009, ~~under~~RBC and QMLP entered into a letter agreement wherein QMLP agreed ~~its~~that ~~revolving~~during negotiations related to the Recombination, it would not submit a borrowing request or request a letter of credit ~~facility~~until the earlier to occur of the Recombination or December 31, 2009.

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

As On ~~of June 30~~September 11, 2009, QRCP, ~~excluding~~amended ~~QELP~~ and ~~QMLP,~~restated ~~had~~its ~~cash~~credit ~~and~~agreement ~~cash~~to ~~equivalents~~add ofan ~~$1.1~~additional $8 million ~~and~~ revolving nocredit ~~ability~~facility to ~~borrow~~finance ~~under~~QRCP’s drilling program in the ~~terms~~Appalachian ofBasin, general ~~its~~and ~~existing~~administrative ~~credit~~expenses, ~~agreement.~~working ~~QRCP~~capital ~~currently~~and ~~estimates~~other ~~that~~corporate expenses. Management believes itthat the new revolving credit facility will ~~not~~provide ~~have~~QRCP ~~enough~~with ~~cash~~sufficient liquidity to satisfy ~~pay~~ its ~~expenses~~obligations, including general and administrative expenses, capital expenditures and debt service requirements through June 30, ~~after~~2010. ~~September~~As 15discussed under “—Credit Agreements—QRCP” below, ~~2009.~~the ~~This~~total ~~date~~amount ~~could~~due by QRCP under its Credit Agreement on July 11, 2010 is estimated to be approximately ~~extended~~$21 million. ifAs a result, QRCP iswill ~~able~~need to ~~restructure~~raise a significant amount of equity capital during the first half of 2010 to pay this amount and further fund its ~~debt~~drilling ~~obligations,~~program. QRCP ~~issue~~(or PostRock if the Recombination is completed) may not be able to raise a sufficient amount of equity ~~securities~~capital for these purposes at the appropriate time due to market conditions or its financial condition and/ prospects or ~~sell~~ ~~additional~~may ~~assets~~have to issue shares at a significant discount to the market price. See Part II,

~~Cash~~10 Flows from Operating Activities. Cash flows from operating activities totaled $51.9 million for the six months ended June 30, 2009 compared to cash flows from operations of $50.2 million for the six months ended June 30, 2008. Cash from operating activities increased due to the $26 million of cash received as a result of exiting certain of our above market derivative financial instruments in June 2009. This increase was offset by lower revenues as a result of lower realized sales prices for the six months ended June 30, 2009, compared to the six months ended June 30, 2008.

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

	Six Months Ended
	June 30, 2009
	(In thousands)
Capital expenditures:
Leasehold acquisition	$	3,662
Development		787
Pipelines		578
Other items		229
Total capital expenditures	$	5,256

Item 1A. “Risk Factors—Risks Related to the Business of QRCP—The current financial crisis and economic conditions have had, and may continue to have, a material adverse impact on QRCP’s business and financial condition.”

Cash Flows from ~~Financing~~Operating Activities. ~~Net~~Cash ~~cash~~ flows ~~from~~provided ~~financing~~by operating activities totaled $~~(26~~64.5) 6 million for the ~~six~~nine months ended ~~June~~September 30, 2009 as compared to cash flows ~~from~~provided ~~financing~~by operations ~~activities~~ of $6156.8 2 million for the ~~six~~ nine months ended ~~June~~September 30, 2008. ~~The~~Cash ~~cash provided~~ from ~~financing activities~~operating ~~during~~activities ~~2008~~increased ~~was~~ primarily due to ~~the~~ ~~borrowings~~realized gains on derivative financial instruments of $7983.0 1 million for the nine months ended September 30, ~~while~~2009, compared to the ~~cash~~realized ~~used~~losses of $17.8 million for the ~~six~~ nine months ended ~~June~~ September 30, ~~2009,~~2008. ~~was~~Realized ~~primarily~~gains ~~due~~in to the ~~repayment~~current ofperiod included $2726 million of cash received as a result of exiting or amending certain of our above market derivative financial instruments in June 2009.6 ~~million~~The increased cash flows from derivative gains was offset by lower revenues from oil and gas sales as a result of ~~revolver~~declining prices and ~~note~~by ~~borrowings~~higher selling, general and administrative expenses in the current period.

~~Working~~Cash ~~Capital~~Flows ~~Deficit~~from Investing Activities. AtNet ~~June 30,~~cash ~~2009,~~flows weprovided ~~had~~by ~~current assets~~investing ofactivities totaled $~~115~~2.3 million~~. Our working~~ ~~capital~~for ~~(current~~the ~~assets~~nine ~~minus~~months ~~current~~ended ~~liabilities~~September 30, ~~excluding~~2009 ~~the~~as ~~short-term~~compared ~~derivative asset~~to ~~and~~cash ~~liability~~flows ofused ~~$35.1 million~~in investing ~~and~~activities of $0261.49 million~~, respectively)~~ ~~was~~for athe ~~deficit~~nine ofmonths ~~$9.9 million at~~ended ~~June~~September 30, 2008. In 2009, ~~compared~~we significantly tocurbed aour ~~working~~acquisition ~~capital~~and ~~deficit~~development ~~(excluding~~activity due to the ~~short-term~~decline ~~derivative~~in ~~asset~~oil and gas ~~liability~~prices ofas well as liquidity constraints. In addition, we received $438.0 8 million ~~and~~from ~~$12,000,~~the ~~respectively)~~sale of certain oil and gas properties. Cash flows used in investing activities in 2008 included $41141.58 million atrelated ~~December~~to the PetroEdge acquisition. The following table sets forth our capital expenditures by major categories for the nine months ended September 3130, ~~2008~~2009.


	Nine months ended
	September 30, 2009
	(In thousands)
Capital expenditures:
Leasehold acquisition	$	1,710
Development		3,543
Pipelines		684
Other items		426

Total capital expenditures	$	6,363

Cash Flows from Financing Activities. Net cash flows used in financing activities totaled $46.8 million for the nine months ended September 30, 2009 as compared to cash flows provided by financing activities of $217.0 million for the nine months ended September 30, 2008. The cash provided by financing activities during 2008 was primarily due to the borrowings of $206.0 million, while the cash used for the nine months ended September 30, 2009 was primarily due to the repayment of $49.1 million of revolver and note borrowings.

Working Capital. At September 30, 2009, we had current assets of $80.8 million. Our working capital (current assets minus current liabilities, excluding the short-term derivative asset and liability of $19.6 million and $1.4 million, respectively) was a deficit of $7.4 million at September 30, 2009, compared to a working capital deficit (excluding the short-term derivative asset and liability of $43.0 million and $12,000, respectively) of $41.5 million at December 31, 2008.

Sources of Liquidity in 2009 and Capital Requirements

Credit ~~Agreements~~Facilities

QRCP.

AtQRCP ~~June~~entered into a Second Amended and Restated Credit Agreement (the “Credit Agreement”) with RBC on September 3011, 2009,. The Credit Agreement contemplates the Recombination and provides that the closing of the Recombination will not be an event of default. No additional amendments to the Credit Agreement are contemplated prior to the closing of the Recombination or in connection therewith. The Credit Agreement includes a term loan with a current outstanding principal balance of $2928.425 million ~~was~~and ~~outstanding~~an $8 million revolving line of credit. In addition, there are also four promissory notes that have been issued under the Credit Agreement: an $862,786 interest deferral note dated June 30, 2009 (representing outstanding due and unpaid interest on the term loan.), ~~The~~a $924,332 ~~weighted~~interest ~~average~~deferral note dated September 30, 2009 (representing outstanding due and unpaid interest ~~rate~~on ~~for~~the term loan), a $282,500 payment-in-kind note dated May 29, 2009 (representing a 1% amendment fee payable by QRCP in connection with the ~~quarter~~fourth ~~ended~~amendment to the Original Credit Agreement), and a second $25,000 payment-in-kind note dated June 30, 2009 ~~was~~(representing 12an amendment fee payable by QRCP in connection with the fifth amendment to the Original Credit Agreement).~~25%.~~

~~On January 30, 2009, QRCP entered into a Third Amendment to Amended and Restated Credit~~11 ~~Agreement that restricted the use of proceeds from certain asset sales.~~

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

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

Modification of debt. As a result of the amendment and restatement of the Credit Agreement, QRCP evaluated the remaining cash flows of this facility under FASB ASC 470-50-40 Debt — Modifications and Extinguishments — Derecognition to determine if the facility had been substantially modified as defined by the guidance. Upon determining that a substantial modification had occurred, QRCP recorded an extinguishment of prior debt and the assumption of new debt at fair value. Our analysis indicated that the fair value of the new debt facility was not materially different from the principal amount of the previous debt facility. As a result, QRCP recorded a $0.8 million loss on extinguishment of debt which represents a write-off of unamortized debt issuance costs associated with the prior debt facility. The loss is reflected in interest expense, net, in QRCP’s condensed consolidated statements of operations included in this Quarterly Report on Form 10-Q.

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

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

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

Debt Balance at September 30, 2009. At September 30, 2009, $30.3 million was outstanding under the term loan, interest deferral notes and payment-in-kind notes. The weighted average interest rate for the quarter ended September 30, 2009 was 12.42%. In addition, $1.5 million was outstanding under the $8.0 million revolving line of credit.

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

Quest Energy.

A. Quest Cherokee Credit Agreement.

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

The borrowing base was $~~190~~160.0 million asand ofthe ~~June 30, 2009. The~~ amount borrowed under the Quest Cherokee Credit Agreement ~~as of June 30, 2009~~ was $~~174~~160.0 million. Atas ~~June~~of September 30, 2009. As a result, ~~Quest~~there was no additional ~~Cherokee~~borrowing ~~had~~ability ~~$16.0 million~~as ~~available~~of ~~for~~September 30, ~~borrowing~~2009. The weighted average interest rate under the Quest Cherokee Credit Agreement for the quarter ended ~~June~~September 30, 2009 was 54.0936%.

In July 2009, the borrowing base under the Quest Cherokee Credit Agreement was reduced from $190 million to $160 million, which, following the payment discussed below, resulted in the outstanding borrowings under the Quest Cherokee Credit Agreement exceeding the new borrowing base by $14 million. In anticipation of the reduction in the borrowing base, Quest Energy amended or exited certain of its above market natural gas price derivative contracts and, in return, received approximately $26 million. The strike prices on the derivative contracts that Quest Energy did not exit were set to market prices at the time. At the same time, Quest Energy entered into new ~~natural~~ natural gas price derivative contracts to increase the total amount of its future estimated proved developed producing natural gas production hedged to approximately 85% through 2013. On ~~June~~September 30, 2009, using these proceeds, Quest Energy made a principal payment of $15 million on the Quest Cherokee ~~Credit~~ Credit Agreement. On July 8, 2009, Quest Energy repaid the $14 million Borrowing Base Deficiency. Quest Energy anticipates that in connection with the redetermination of its borrowing base in November 2009, its borrowing base will be further reduced from its current level of $160 million. In the event of a borrowing base reduction, Quest Energy expects to be able to make the required payments resulting from the borrowing base deficiency out of existing funds.

Quest Cherokee was in compliance with all of its covenants under the Quest Cherokee Credit Agreement as of ~~June~~September 30, 2009.

B. Second Lien Loan Agreement.

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

~~Quest Cherokee was in compliance with all of its covenants as of June 30, 2009.~~13

this loan, there can be no assurance that such negotiations will be successful or that Quest Energy and Quest Cherokee will be able to repay amounts due under the Second Lien Loan Agreement in accordance with the terms of the Second Lien Loan Agreement.

Quest Cherokee was in compliance with all of its covenants under the Second Lien Loan Agreement as of September 30, 2009.

Quest Midstream.

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

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

Contractual Obligations

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

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

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

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

~~Off-balance~~ As ~~Sheet~~discussed ~~Arrangements~~above under “—Liquidity and Capital Resources—Sources of Liquidity in 2009 and Capital Requirements—Credit Agreements—QRCP”, on September 11, 2009, QRCP amended and restated its credit agreement to, among other things, add a new revolving line of credit that permits borrowings of up to an initial maximum amount of $5.6 million until November 30, 2009 and thereafter, provided no event of default exists, up to a maximum of $8.0 million.

~~At June 30, 2009, we did not have any relationships with unconsolidated entities or financial~~14 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.

Off-balance Sheet Arrangements

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Commodity Price Risk

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

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

	Remainder of		Year Ending December 31,
	2009		2010			2011			2012			Thereafter			Total
	($ in thousands, except volumes and per unit data)		~~($ in thousands, except volumes and per unit data)~~
Natural Gas Swaps:
Contract volumes (Mmbtu)		73,~~734~~687,~~720~~360		16,129,060			13,550,302			11,000,004			9,000,003			5753,~~054~~366,~~089~~729
Weighted-average fixed price per Mmbtu	$	7.78	$	6.26		$	6.80		$	7.13		$	7.28		$	6.9185
Fair value, net	$	2511,~~150~~939	$	5,~~563~~020		$	~~(316~~1,048	)	$	331,676		$	~~(32~~1,178	)	$	3020,~~398~~861
Natural Gas Collars:
Contract volumes (Mmbtu)		~~375~~187,~~000~~500		—			—			—			—			~~375~~187,~~000~~500
Weighted-average fixed price per Mmbtu:
Floor	$	11.00	$	—		$	—		$	—		$	—		$	11.00
Ceiling	$	15.00	$	—		$	—		$	—		$	—		$	15.00
Fair value, net	$	21,~~464~~154	$	—		$	—		$	—		$	—		$	21,~~464~~154
Total Natural Gas Contracts:
Contract volumes (Mmbtu)		73,~~749~~874,~~720~~860		16,129,060			13,550,302			11,000,004			9,000,003			5753,~~429~~554,~~089~~229
Weighted-average fixed price per Mmbtu	$	7.94	$	6.26		$	6.80		$	7.13		$	7.28		$	6.9487
Fair value, net	$	2713,~~614~~093	$	5,~~563~~020		$	~~(316~~1,048	)	$	331,676		$	~~(32~~1,178	)	$	3222,~~862~~015
Basis Swaps:
Contract volumes (Bbl)		—		3,630,000			8,549,998			9,000,000			9,000,003			30,180,001
Weighted-average fixed price per Bbl	$	—	$	0.63		$	0.67		$	0.70		$	0.71		$	0.69
Fair value, net	$	—	$	(~~812~~957	)	$	(1,~~725~~512	)	$	(1,~~436~~393	)	$	(1,~~124~~138	)	$	$(5,~~097~~000	)
Crude Oil Swaps:
Contract volumes (Bbl)		189,000		30,000			—			—			—			4839,000
Weighted-average fixed price per Bbl	$	90.07	$	87.50		$	—		$	—		$	—		$	88.4609
Fair value, net	$	~~323~~170	$	~~347~~386		$	—		$	—		$	—		$	~~670~~556
Total fair value, net	$	2713,~~937~~263	$	54,~~098~~449		$	(~~2,041~~464	)	$	~~(1,403~~283	)	$	~~(1,156~~40	)	$	2817,~~435~~571

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

market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2008, in Item 7A of our 2008 Form 10-K/A.

ITEM 4. CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

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

In connection with the preparation of 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, 2009. Based on that evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective as of September 30, 2009. Notwithstanding this determination, our management believes that the condensed 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.

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

Management identified the following control deficiencies that constituted material weaknesses as of December 31, 2008:

(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 to QRCP’s policies and procedures.

	(b)		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.

~~limitations~~reporting, toaccounting ~~the~~for ~~effectiveness~~derivative ofinstruments, ~~any~~stock ~~system~~compensation ofcosts, ~~disclosure~~depreciation, ~~controls~~depletion and ~~procedures,~~ ~~including~~amortization, ~~the~~impairment ~~possibility~~ of ~~human~~oil ~~error~~ and ~~the~~gas ~~circumvention~~properties ~~or overriding of the controls~~ and ~~procedures.~~ ~~Accordingly,~~cash ~~even~~management ~~effective~~described ~~disclosure~~in ~~controls~~items ~~and procedures can only provide~~(2) to ~~reasonable assurance of the achieving their control objectives~~(8) below.

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

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

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

(a) We did not maintain a tone and control consciousness that consistently emphasized adherence to accurate financial reporting and enforcement of Company policies and procedures. This control deficiency fostered a lack of sufficient appreciation for internal controls over financial reporting, allowed for management override of internal controls in certain circumstances and resulted in an ineffective process for monitoring the adherence of QRCP’s policies and procedures. (b) In addition, we did not maintain a sufficient complement of personnel with an appropriate level of accounting knowledge, experience, and training in the application of GAAP commensurate with our financial reporting requirements and business environment. (c) We did not maintain an effective anti-fraud program designed to detect and prevent fraud relating to (i) an effective whistle-blower program, (ii) consistent background checks of personnel in positions of responsibility, and (iii) an ongoing program to manage identified fraud risks.

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

(2)

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

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

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

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

(3)

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

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

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

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

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

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

	(4)		Derivative instruments — We did not establish and maintain effective controls to ensure the correct application of GAAP related to derivative instruments. Specifically, we did not adequately document the criteria for measuring hedge effectiveness at the inception of certain derivative transactions and did not subsequently value those derivatives appropriately.
	(5)		Stock compensation cost — We did not establish and maintain effective controls to ensure completeness and accuracy of stock compensation costs. Specifically, effective controls were not designed and in place to ensure that documentation of the terms of the awards were reviewed in order to be recorded accurately.
	(6)		Depreciation, depletion and amortization — We did not establish and maintain effective controls to ensure completeness and accuracy of depreciation, depletion and amortization expense. Specifically, effective controls were not designed and in place to calculate and review the depletion of oil and gas properties.
	(7)		Impairment of oil and gas properties — We did not establish and maintain effective controls to ensure the accuracy and application of GAAP related to the capitalization of costs related to oil and gas properties and the required evaluation of impairment of such costs. Specifically, effective controls were not designed and in place to determine, review and record the nature of items recorded to oil and gas properties and the calculation of oil and gas property impairments.
	(8)		Cash management — We did not establish and maintain effective controls to adequately segregate the duties over cash management. Specifically, effective controls were not designed to prevent the misappropriation of cash.

~~Additionally, each of the control deficiencies described in items (1) through (8) above could~~17 result in a misstatement of the aforementioned account balances or disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected.

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

~~Remediation~~impairment ~~Plan~~ 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.

~~Our~~Each ~~management,~~of ~~under~~the ~~new~~control ~~leadership~~deficiencies as described ~~below,~~in ~~has~~items ~~been~~(1) through ~~actively~~(8) above ~~engaged~~could result in ~~the~~a ~~planning~~misstatement ~~for, and implementation~~ of, ~~remediation efforts to address~~ the ~~material~~aforementioned ~~weaknesses,~~account ~~as well~~balances asor ~~other~~disclosures ~~identified~~that ~~areas~~would ofresult ~~risk.~~in ~~These~~a ~~remediation efforts, outlined below, are intended~~material ~~both~~misstatement to ~~address~~ the ~~identified~~annual ~~material~~or ~~weaknesses~~interim ~~and~~consolidated ~~to enhance our overall~~ financial ~~control environment.~~statements Inthat ~~May 2009,~~would ~~Mr. David~~not ~~Lawler~~be ~~was appointed~~prevented ~~Chief~~or ~~Executive Officer (our principal executive officer)~~detected. ~~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.

InChanges ~~addition,~~in ~~Mr. Rateau,~~Internal ~~one~~Control ofOver ~~our~~Financial ~~independent directors, was elected as Chairman of the~~Reporting ~~Board, and Mr. McMichael, who has significant prior public company audit committee experience, was added to our Board of Directors and Audit Committee.~~

InAs ~~connection~~discussed ~~with our entry into the Merger Agreement~~above, ~~Mr.~~as ~~McMichael and another director, James B. Kite, Jr., resigned from our Board~~ of ~~Directors~~December 31, ~~each effective July 2~~2008, ~~2009.~~we ~~Messrs.~~had ~~McMichael and~~material ~~Kite~~weaknesses ~~resigned~~ in ~~order to reduce~~ our ~~expenses during the period between the signing of the Merger~~internal ~~Agreement~~control ~~and~~over ~~the~~financial ~~closing of the Recombination and not because of any disagreement with management on any matter relating to our operations, policies or practices~~reporting.

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 are intended both to address the identified material weaknesses and to enhance our overall financial control environment. In January 2009, Mr. Eddie LeBlanc was appointed Chief Financial Officer (our principal financial and accounting officer). In May 2009, Mr. David Lawler was appointed Chief Executive Officer (our principal executive officer). The design and implementation of these and other remediation efforts are the commitment and responsibility of this new leadership team.

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 and our disclosure controls and procedures.

WeDuring ~~believe~~2009, the ~~measures~~Company ~~described~~has ~~above~~made ~~will~~the ~~enhance~~following ~~the~~changes ~~remediation~~to ofaddress the ~~control~~previously reported ~~deficiencies~~material weweaknesses ~~have~~in ~~identified and strengthen our~~ internal control over financial reporting. ~~We are committed to continuing to improve our internal control processes~~ and ~~will~~disclosure ~~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~~a) The Company hired additional experienced accounting personnel with specific experience in ~~Internal~~(1) ~~Control~~financial ~~Over~~reporting ~~Financial~~for ~~Reporting~~ public companies; (2) preparing consolidated financial statements; (3) oil and gas property and pipeline asset accounting; (4) inter-company accounts and investments in subsidiaries; and (5) GAAP revenue accounting. b) The Company implemented a closing calendar and consolidation process that includes accrual based financial statements being reviewed by qualified personnel in a timely manner. c) The Company reviews consolidating financial statements with senior management, the audit committee of the board of directors and the full board of directors. d) The Company completes disclosure checklists for both GAAP and SEC required disclosures to ensure disclosures are complete. e) The Company has created a disclosure committee as part of its SEC filing process.

~~Except~~In ~~as described above~~addition, ~~there were no other changes in our internal control over financial reporting~~ during the third quarter ~~ended~~of ~~June 30,~~ 2009 ~~that have materially affected~~, orthe ~~are~~Company ~~reasonably~~has: ~~likely to materially affect, our internal control over financial reporting.~~

19 a) Communicated internally to employees regarding ethics and the availability of its internal fraud hotline;

~~PART~~b) IIEvaluated –and ~~OTHER~~prioritized ~~INFORMATION~~ the material weaknesses noted above and developed specific actions necessary in order to remediate them; c) Performed a preliminary assessment of accounting and disclosure policies and procedures and begun the process of updating and revising them; and d) Begun regular meetings of the disclosure committee.

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 and disclosure controls and procedures. We are committed to continuing to improve our internal control processes and will continue to diligently and vigorously review our internal control over financial reporting and our disclosure controls and procedures. As we continue to evaluate and work to improve our internal control over financial reporting and our disclosure controls and procedures, 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.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

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

We are subject, from time to time, to certain legal proceedings and claims in the ordinary course of conducting our business. We record a liability related to our legal proceedings and claims when we have determined that it is probable that we will be obligated to pay and the related amount can be reasonably estimated. Except for those legal proceedings listed in Part I, Item 1, Note 10 to our ~~2008~~condensed consolidated financial statements included in this Form 10-Q or in our 2008 Form 10-K/A, we believe there are no pending legal proceedings in which we are currently involved which, if adversely determined, could have a material adverse effect on our financial position, results of operations or cash flow. While we intend to defend vigorously against these claims, we are unable to predict the outcome of these proceedings or reasonably estimate a range of possible loss that may result.

ITEM 1A. RISK FACTORS.

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

While the Recombination is pending, we will be subject to business uncertainties and contractual restrictions that could adversely affect our business.

Uncertainty about our financial condition and the effect of the Recombination on employees, customers and suppliers may have an adverse effect on us pending consummation of the Recombination and, consequently, on the combined company. These uncertainties may impair our ability to attract, retain and motivate key personnel until the Recombination is consummated and for a period of time thereafter, and could cause customers, suppliers and others who deal with us to seek to change existing business relationships with us. Employee retention may be particularly challenging during the pendency of the Recombination because employees may experience uncertainty about their future roles with the combined company, and we have experienced resignations of officers and other key personnel since the date of the Merger Agreement. If, despite our retention efforts, key employees depart because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, the combined company’s business could be seriously harmed.

The Merger Agreement restricts us, without QELP’s and QMLP’s consent and subject to certain exceptions, from taking certain specified actions until the Recombination occurs or the Merger Agreement terminates. These restrictions may prevent us from pursuing otherwise attractive business opportunities and making other changes to our business that may arise prior to completion of the Recombination or termination of the Merger Agreement.

Even absent these restrictions, we may not have the liquidity or resources available or the ability under our credit agreements to pursue alternatives to the Recombination, even if we determine that another opportunity would be more beneficial. In addition, management is devoting substantial time and other human resources to the proposed transaction and related matters, which could limit their ability to pursue other attractive business opportunities, including potential joint ventures, stand-alone projects and other transactions. If we are unable to pursue such other attractive business opportunities, then our growth prospects and the long-term strategic position of our business and the combined business could be adversely affected.

The Merger Agreement is subject to closing conditions that could result in the completion of the Recombination being delayed or not consummated, and the Recombination may not be consummated even if our stockholders and the QELP and QMLP unitholders approve the Merger Agreement and the Recombination.

Under the Merger Agreement, completion of the Recombination is conditioned upon the satisfaction of closing conditions, including, among others, the arrangement of one or more credit facilities for PostRock and its subsidiaries on terms reasonably acceptable to our board of directors and the conflicts committee of each of QEGP and QMGP, the approval of the transaction by our stockholders, the QELP unitholders and the QMLP unitholders, and consents from each entity’s existing lenders. The required conditions to closing may not be satisfied or, if permissible, waived, in a timely manner, if at all, and the Recombination may not occur. Given the distressed nature of the parties, PostRock may not be able to obtain one or more credit facilities on terms that our board of directors and the conflicts committee of each of QEGP and QMGP find reasonably acceptable. In addition, we, QELP and QMLP can agree not to consummate the Recombination even if our stockholders, QELP unitholders and QMLP unitholders approve the Merger Agreement and the Recombination and any of QRCP, QELP or QMLP may terminate the Merger Agreement if the Recombination has not been consummated by March 31, 2010.

Failure to complete the Recombination could negatively impact the value of our common stock and our future business and financial results because of, among other things, the disruption that would occur as a result of uncertainties relating to a failure to complete the Recombination.

If the Recombination is not completed for any reason, we could be subject to several risks including the following:

	•		there may be events of default under our indebtedness and such indebtedness may be accelerated and become immediately due and payable, which may result in the bankruptcy of QRCP or QELP (please read “— Risks Related to Our Financial Condition— If the Recombination is delayed or not consummated or if the Merger Agreement is terminated, there may be events of default under our indebtedness enabling the lenders to accelerate such indebtedness, which could lead to the foreclosure of collateral and our bankruptcy”);

	•		the market price of our common stock may decline to the extent that the current market price reflects market assumptions that the Recombination will be completed and that the combined company will experience a potentially enhanced financial position;

	•		our common stock may be delisted from the Nasdaq Global Market if the Recombination has not closed or we have not otherwise satisfied the $1 per share minimum bid listing requirement by March 15, 2010;

	•		there will be substantial transaction costs related to the Recombination, such as investment banking, legal and accounting fees, printing expenses and other related charges, that must be paid even if the Recombination is not completed;

	•		there may be an adverse impact on relationships with customers, suppliers and others to the extent they believe that we cannot compete in the marketplace or continue as a solvent entity without the Recombination or otherwise remain uncertain about our future prospects in the absence of the Recombination; and

	•		we may experience difficulty in retaining and recruiting current and prospective employees.

We will incur significant transaction and merger-related integration costs in connection with the Recombination.

As of September 30, 2009, we have already incurred approximately $7.3 million in aggregate transaction costs in connection with the Recombination and expect to pay approximately $6.7 million in additional aggregate transaction costs subsequent to September 30, 2009. These transaction costs include investment banking, legal and accounting fees and expenses, SEC filing fees, printing expenses, mailing expenses, proxy solicitation expenses and other related charges. These amounts are preliminary estimates that are subject to change. A portion of the transaction costs will be incurred regardless of whether the Recombination is consummated. We will pay 10% of the combined transaction costs and QELP and QMLP will each pay 45% of the combined transaction costs, except that we and QELP will share equally the costs of printing and mailing the definitive joint proxy statement/prospectus to, and soliciting proxies (including fees of proxy solicitors) from, our stockholders and QELP’s unitholders and QMLP will pay the cost of mailing the definitive joint proxy statement to, and soliciting proxies from, its unitholders. These costs will reduce the cash available to the combined company following completion of the Recombination and will adversely impact its liquidity and ability to make capital expenditures.

Risks Related to Our Financial Condition

Former senior management were terminated in 2008 following the discovery of various misappropriations of funds of QRCP and QELP.

In August of 2008, Jerry Cash, our former chairman, president and chief executive officer, resigned and David E. Grose, our former chief financial officer, was terminated, following the discovery of the misappropriation of $10 million principally from us by Mr. Cash with the assistance of Mr. Grose from 2005 through mid-2008. Additionally, the Oklahoma Department of Securities has filed a lawsuit alleging that Mr. Grose and Brent Mueller, 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. In March 2009, Mr. Mueller pled guilty to one felony count of misprision of justice. We have filed lawsuits against all three of these individuals seeking an asset freeze and damages related to the transfers, kickbacks and thefts. Pursuant to a settlement agreement with Mr. Cash, QRCP, QELP and QMLP recovered assets valued at $3.4 million from him and released all further claims against him. As a result of these activities, we recorded an aggregate

consolidated loss of $6.6 million. We have incurred costs totaling approximately $8.0 million in connection with the investigation of these misappropriations, legal fees, accountants’ fees and other related expenses. There can be no assurance that we will be successful in recovering any additional amounts. Any additional recoveries may consist of assets other than cash and accurately valuing such assets in the current economic climate may be difficult. Any amounts recovered will be recognized by us for financial accounting purposes only in the period in which the recovery occurs. For more detail concerning these unauthorized transfers, please read “Items 1. and 2. — Business and Properties — Recent Developments” in our 2008 Form 10-K/A.

QRCP and QELP are involved in securities lawsuits that may result in judgments, settlements, and/or indemnity obligations that are not covered by insurance and that may have a material adverse effect on us.

Between September 2008 and August 2009, four federal securities class action lawsuits, one federal individual securities lawsuit, two federal derivative lawsuits and three state court derivative lawsuits have been filed naming QRCP, QELP and certain current and former officers and directors as defendants. The securities lawsuits allege the defendants violated the federal securities laws by issuing false and misleading statements and/or concealing material facts concerning the unauthorized transfers of funds by former management described above and seek class certification, money damages, interest, attorneys’ fees, costs and expenses. The complaints allege that, as a result of these actions, QRCP’s stock price and QELP’s unit price were artificially inflated. The derivative lawsuits assert claims for breach of fiduciary duty, abuse of control, gross mismanagement, waste of corporate assets and unjust enrichment and seek disgorgement, money damages, costs, expenses and equitable or injunctive relief. Additional lawsuits may be filed. For more information, please read Note 9 to our consolidated financial statements in this quarterly report and Note 12 to our consolidated financial statements in our 2008 Form 10-K/A.

QRCP and QELP have incurred and will continue to incur substantial costs, legal fees and other expenses in connection with their defense against these claims. In addition, the final settlements or the courts’ final decisions in the securities cases could result in judgments against QRCP and QELP that are not covered by insurance or which exceed the policy limits. QRCP and QELP may also be obligated to indemnify certain of the individual defendants in the securities cases, which indemnity obligations may not be covered by insurance. QRCP and QELP have received letters from their directors and officers’ insurance carriers reserving their rights to limit or preclude coverage under various provisions and exclusions in the policies, including for the committing of a deliberate criminal or fraudulent act by a past, present, or future chief executive officer or chief financial officer. QELP has received a letter from its directors’ and officers’ insurance carrier that the carrier will not provide insurance coverage based on Mr. Cash’s alleged written admission that he engaged in acts for which coverage is excluded. QELP is reviewing the letter and evaluating its options. If these lawsuits have not been settled, tried or dismissed prior to the closing of the Recombination, PostRock will become subject to some or all of these lawsuits and would face the same risks with respect to these lawsuits as QRCP and QELP. QRCP and QELP might not have sufficient cash on hand to fund any such payment of expenses, judgments and indemnity obligations and might be forced to file for bankruptcy or take other actions that could have a material adverse effect on their financial condition and the price of their common stock or common units. Furthermore, certain officers and directors of PostRock may continue to be subject to these actions after the closing of the Recombination, which could adversely affect the ability of management and the board of directors of PostRock to implement its business strategy.

U.S. government investigations could affect our results of operations.

Numerous government entities are currently conducting investigations of QRCP and some of our former officers and directors. The Oklahoma Department of Securities has filed lawsuits against Mr. Cash, Mr. Grose and Mr. Mueller. In addition, the Oklahoma Department of Securities, the Federal Bureau of Investigation, the Department of Justice, the Securities and Exchange Commission, the Internal Revenue Service and other government agencies are currently conducting investigations related to QRCP and the misappropriations by these individuals.

We cannot anticipate the timing, outcome or possible financial or other impact of these investigations. The governmental agencies involved in these investigations have a broad range of civil and criminal penalties they may seek to impose against corporations and individuals for violations of securities laws, and other federal and state statutes, including, but not limited to, injunctive relief, disgorgement, fines, penalties and modifications to business practices and compliance programs. In recent years, these agencies and authorities have entered into agreements with, and obtained a broad range of penalties against, several public corporations and individuals in similar investigations, under which civil and criminal penalties were imposed, including in some cases multi-million dollar fines and other penalties and sanctions. Any injunctive relief, disgorgement, fines, penalties, sanctions or imposed modifications to business practices resulting from these investigations could adversely affect our and PostRock’s results of operations and financial condition and our and PostRock’s ability to continue as a going concern.

Our independent registered public accounting firm has expressed substantial doubt about our ability to continue as a going concern.

The independent auditor’s report accompanying our audited consolidated financial statements for the year ended December 31, 2008 contained a statement expressing substantial doubt as to our ability to continue as a going concern. The factors contributing to this concern include our recurring losses from operations, stockholders’ (deficit) equity, and inability to generate sufficient cash flow to meet its obligations and sustain its operations. If the Recombination is not consummated and we are unable to sell additional assets, restructure our indebtedness, issue equity securities and/or complete some other strategic transaction, then we may be forced to make a bankruptcy filing or take other actions that could have a material adverse effect on our business, the price of our common stock and our results of operations.

We have identified significant and pervasive material weaknesses in our internal control over financial reporting.

Following the discovery of the unauthorized transfers by certain members of senior management discussed above and in connection with our management’s review of our internal control over financial reporting as of December 31, 2008, control deficiencies that constituted material weaknesses related to the following items were identified:

	•		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.

	•		We did not maintain effective monitoring controls to determine the adequacy of our internal control over financial reporting and related policies and procedures.

	•		We did not establish and maintain effective controls over certain of our period-end financial close and reporting processes, including the preparation and review of financial statements and schedules and journal entries.

	•		We did not establish and maintain effective controls to ensure the correct application of GAAP related to derivative instruments.

	•		We did not establish and maintain effective controls to ensure completeness and accuracy of stock compensation costs.

	•		We did not establish and maintain effective controls to ensure completeness and accuracy of depreciation, depletion and amortization expense.

	•		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.

	•		We did not establish and maintain effective controls to adequately segregate the duties over cash management.

	•		We did not establish and maintain effective controls to ensure personnel in the accounting department were competent and capable of performing the functions required.

These material weaknesses resulted in the misstatement of certain of our annual and interim consolidated financial statements during the last three years. Based on management’s evaluation, because of the material weaknesses described above, management concluded that our internal control over financial reporting was not effective as of December 31, 2008 and continued not to be effective as of September 30, 2009.

While we have taken certain actions to address the deficiencies identified, it is unlikely that the remediation plan and timeline for implementation will eliminate all deficiencies for the year ended December 31, 2009. Additional measures may be necessary and these measures, along with other measures we expect to take to improve our internal control over financial reporting, may not be sufficient to address the deficiencies identified or ensure that our internal control over financial reporting is effective. If we are unable to provide

reliable and timely financial external reports, our business and prospects could suffer material adverse effects. In addition, we may in the future identify further material weaknesses or significant deficiencies in our internal control over financial reporting.

We have restated certain of our historical financial statements.

As discussed above, as a result of the misappropriation of funds by prior senior management and other significant and material errors identified in prior year financial statements and the material weaknesses in internal control over financial reporting, our board of directors determined on December 31, 2008 that our audited consolidated financial statements as of and for the years ended December 31, 2007, 2006 and 2005 and 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 and that it would be necessary to restate these financial statements.

The restated consolidated financial statements correct errors in a majority of the financial statement line items in the previously issued consolidated financial statements for all periods presented. The most significant errors (by dollar amount) consist of the following:

	•		The transfers described above, which were not approved expenditures, were not properly accounted for as losses.

	•		Hedge accounting was inappropriately applied for commodity derivative instruments and the valuation of commodity derivative instruments was incorrectly computed.

	•		Errors were identified in the accounting for the formation of Quest Cherokee in December 2003 in which: (i) no value was ascribed to the Quest Cherokee Class A units that were issued to ArcLight Energy Partners Fund I, L.P. 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 from ArcLight. Due to the errors that existed in the previous accounting, additional errors resulted in 2005 including: (i) a loss on extinguishment of debt was not recorded, and (ii) oil and gas properties, pipeline assets and retained earnings were overstated. Subsequent to the 2005 transaction, depreciation, depletion and amortization expense was also overstated due to these errors.

	•		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.

	•		Invoices were not properly accrued resulting in the understatement of accounts payable and numerous other balance sheet and income statement accounts.

	•		Capitalized interest was not recorded on pipeline construction.

	•		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 previously discussed errors and an additional error related to the methods used in calculating depreciation, depletion and amortization, errors existed in depreciation, depletion and amortization expense and accumulated depreciation, depletion and amortization.

	•		As a result of previously discussed errors relating to oil and gas properties and hedge accounting and errors relating to the treatment of deferred taxes, errors existed in ceiling test calculations.

Although the items listed above comprise the most significant errors (by dollar amount), numerous other errors were identified and restatement adjustments made. In addition, errors were identified in the calculation of outstanding shares in all periods as we

inappropriately included restricted share grants in our calculation of issued shares when the restrictions lapsed, rather than the date at which the restricted shares were granted.

As a result of the need to completely restate and reaudit all of the financial statements for the periods discussed above, management was unable to prepare and file our annual report for 2008 and our quarterly reports for the third quarter of 2008 and the first and second quarters of 2009 on a timely basis. Moreover, we were required to file amendments to certain of our periodic reports to correct an error identified in July 2009 related to the incorrect classification of realized gains on commodity derivative instruments during the year ended December 31, 2008, which affected the financial statements for the quarters ended March 31, June 30, and September 30, 2008 and the year ended December 31, 2008.

If the Recombination is delayed or not consummated or if the Merger Agreement is terminated, there may be events of default under our indebtedness enabling the lenders to accelerate such indebtedness, which could lead to our foreclosure of collateral and bankruptcy.

We have been in default under our Credit Agreement. In May 2009, we entered into an amendment to the Credit Agreement to, among other things, waive certain events of default related to our financial covenants and collateral requirements and to extend certain financial reporting deadlines.

In June 2009, we entered into an amendment to the Credit Agreement that, among other things, deferred until August 15, 2009 the obligation to deliver to RBC certain financial information. The amendment also waived financial covenant (namely the interest coverage ratio and leverage ratio) events of default for the fiscal quarter ended June 30, 2009, waived any mandatory prepayment due to any collateral deficiency during the fiscal quarter ended September 30, 2009, and deferred 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. On September 11, 2009, we further amended the Credit Agreement to extend the maturity date of the interest deferral note to July 11, 2010. The quarterly principal payments of $1.5 million due September 30, 2009, December 31, 2009, March 31, 2010 and June 30, 2010 were also effectively deferred until July 11, 2010, at which time all $6 million will be due. Thereafter, we will be required to make a principal repayment of $1.5 million at the end of each calendar quarter until maturity.

Furthermore, the current balance of $29.8 million of indebtedness under QELP’s Second Lien Loan Agreement has been extended to November 16, 2009. QELP does not expect to be able to pay such amount on that date and there can be no assurance that it will be able to obtain a further extension of the maturity date.

In July 2009, QELP’s borrowing base under its revolving credit agreement was reduced from $190 million to $160 million, which, following the principal payment discussed below, resulted in the outstanding borrowings under the revolving credit agreement exceeding the new borrowing base by $14 million. In anticipation of the reduction in the borrowing base, Quest Cherokee amended or exited certain of its above the market natural gas price derivative contracts and, in return, received approximately $26 million. On June 30, 2009, using these proceeds, Quest Cherokee made a principal payment of $15 million on the Quest Cherokee Credit Agreement. On July 8, 2009, Quest Cherokee repaid the $14 million borrowing base deficiency. Quest Energy anticipates that in connection with the redetermination of its borrowing base in November 2009, its borrowing base will be further reduced from its current level of $160 million. In the event of a borrowing base reduction, Quest Energy expects to be able to make the required payments resulting from the borrowing base deficiency out of existing funds.

An event of default under either of QELP’s credit agreements would cause an event of default under QELP’s other credit agreement.

If there is an event of default under any of our credit agreements, the lenders thereunder could accelerate the indebtedness and foreclose on the collateral. As of September 30, 2009, there was $31.8 million outstanding under the Credit Agreement, $160.0 million outstanding under the Quest Cherokee Credit Agreement and $29.8 million outstanding under the QELP Second Lien Loan Agreement.

If QELP or QRCP is required to make these prepayments or pay the full amounts of the indebtedness upon acceleration, it may be able to raise the funds only by selling assets or it may be unable to raise the funds at all, in which event it may be forced to file for bankruptcy protection or liquidation.

If defaults occur and the Recombination is delayed or the Merger Agreement is terminated and QRCP or QELP are unable to obtain waivers from its lenders or to obtain alternative financing to repay the credit facilities, QRCP or QELP may be required to

obtain additional waivers or its lender may foreclose on its assets, issue additional equity securities or refinance the credit agreements at unfavorable prices.

Risks Related to Our Business

The current financial crisis and economic conditions have had, and may continue to have, a material adverse impact on our business and financial condition.

Since the second half of 2008, global financial markets have been experiencing a period of unprecedented turmoil and upheaval characterized by extreme volatility and declines in prices of securities, diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse or sale of financial institutions and an unprecedented level of intervention from the U.S. federal government and other governments. In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets and the solvency of counterparties, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on more onerous terms and, in some cases, ceased to provide any new funding.

A continuation of the economic crisis could result in further reduced demand for oil and natural gas and keep downward pressure on the prices for oil and natural gas, which have fallen dramatically since reaching historic highs in July 2008. These price declines have negatively impacted our revenues and cash flows. Although we cannot predict the impact of difficult economic conditions, they could materially adversely affect our business and financial condition. For example:

	•		our ability to obtain credit and access the capital markets to fund the exploration or development of reserves, the construction of additional assets or the acquisition of assets or businesses from third parties may continue to be restricted;

	•		our hedging arrangements could become ineffective if our counterparties are unable to perform their obligations or seek bankruptcy;

	•		the values we are able to realize in asset sales or other transactions we engage in to raise capital may be reduced, thus making these transactions more difficult to consummate and less economic; and

	•		the demand for oil and natural gas could further decline due to deteriorating economic conditions, which could adversely affect our business, financial condition or results of operations.

No later than the first half of 2010, we will need to raise a significant amount of equity capital to fund our drilling program and pay down outstanding indebtedness, including principal, interest and fees of approximately $21 million due under the Credit Agreement on July 11, 2010. We may not be able to raise a sufficient amount of equity capital for these purposes at the appropriate time due to market conditions or our financial condition and prospects or may have to issue shares at a significant discount to the market price. If we are not able to raise this equity capital, it would have a material adverse impact on our ability to meet indebtedness repayment obligations and fund our operations and capital expenditures and we may be forced to file for bankruptcy. In addition, if we issue and sell additional shares in an equity offering, our stockholders’ ownership will be diluted and our stock price may decrease due to the additional shares available in the market.

Due to these factors, we cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or if funding is available only on unfavorable terms, we may be unable to meet our obligations as they come due or be required to post collateral to support our obligations, or we may be unable to implement our development plans, enhance our business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues, results of operations, or financial condition or cause us to file for bankruptcy.

Energy prices are very volatile, and if commodity prices remain low or continue to decline, our revenues, profitability and cash flows will be adversely affected. A sustained or further decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to fund our capital expenditures and meet our financial commitments.

The current global credit and economic environment has resulted in reduced demand for natural gas and significantly lower natural gas prices. Gas prices have seen a greater percentage decline over the past twelve months than oil prices due in part to a substantial supply of natural gas on the market and in storage. The prices we receive for our oil and natural gas production will heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities, and therefore their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile and will likely continue to be volatile in the future. For example, during the nine months ended September 30, 2009, the near month NYMEX natural gas futures price ranged from a high of $6.07 per Mmbtu to a low of $2.51 per Mmbtu. Approximately 98% of our production is natural gas. The prices that we receive for our production, and the levels of our production, depend on a variety of factors that are beyond our control, such as:

	•		the domestic and foreign supply of and demand for oil and natural gas;

	•		the price and level of foreign imports of oil and natural gas;

	•		the level of consumer product demand;

	•		weather conditions;

	•		overall domestic and global economic conditions;

	•		political and economic conditions in oil and gas producing countries, including embargoes and continued hostilities in the Middle East and other sustained military campaigns, acts of terrorism or sabotage;

	•		actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;

	•		the impact of the U.S. dollar exchange rates on oil and gas prices;

	•		technological advances affecting energy consumption;

	•		domestic and foreign governmental regulations and taxation;

	•		the impact of energy conservation efforts;

	•		the costs, proximity and capacity of gas pipelines and other transportation facilities; and

	•		the price and availability of alternative fuels.

Our revenues, profitability and cash flow depend upon the prices and demand for oil and gas, and a drop in prices will significantly affect our financial results and impede our growth. In particular, declines in commodity prices will:

	•		reduce the amount of cash flow available for capital expenditures, including for the drilling of wells and the construction of infrastructure to transport the natural gas we produce;

	•		negatively impact the value of our reserves because declines in oil and natural gas prices would reduce the amount of oil and natural gas we can produce economically;

	•		reduce the drilling and production activity of our third party customers and increase the rate at which our customers shut in wells; and

	•		limit our ability to borrow money or raise additional capital.

Future price declines may result in a write-down of our asset carrying values.

Lower gas prices may not only decrease our revenues, profitability and cash flows, but also reduce the amount of oil and gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. Substantial decreases in oil and gas prices have had and may continue to render a significant number of our planned exploration and development projects uneconomic. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil or gas properties for impairments. We will be required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and may, therefore, require a write-down of such carrying value.

For example, due to the low price of natural gas as of December 31, 2008, revisions resulting from further technical analysis and production during the year, our 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. The December 31, 2008 reserves 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) compared to $6.43 at December 31, 2007. Primarily as a result of this decrease, we recognized a non-cash impairment of $298.9 million for the year ended December 31, 2008. Due to a further decline in the spot price for natural gas during 2009, we incurred an additional impairment charge of approximately $102.9 million for the nine months ended September 30, 2009. We may incur further impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred which could result in a reduction in our credit facility borrowing base.

As a result of our financial condition, we have had to significantly reduce our capital expenditures, which will ultimately reduce cash flow and result in the loss of some leases.

Due to the global economic and financial crisis, the decline in commodity prices, the unauthorized transfers of funds by prior senior management and restrictions in the Credit Agreement, as described in more detail in other risk factors, we have not been able to raise the capital necessary to implement our drilling plans for 2009 and 2010. We reduced our capital expenditure budgets from $84.1 million in 2008 to $3.3 million in 2009, and QELP reduced its capital expenditure budgets from $155.4 million in 2008 to $9.7 million in 2009. In addition, QELP plans to drill only seven new wells in 2009, after drilling 328 new wells in 2008. QELP does not expect to drill a substantial number of wells if the Recombination is not completed. The effect of this reduced capital expenditures and drilling program is that QELP may not be able to maintain its reserves levels and that QRCP and QELP may lose leases that require a certain level of drilling activity. Please read “— Certain of our undeveloped leasehold acreage is subject to leases that may expire in the near future.” The failure of QELP to maintain its reserve levels could adversely affect the borrowing base under its revolving credit facility.

We face the risks of leverage.

As of September 30, 2009, QRCP had borrowed $31.8 million, QELP had borrowed $189.8 million and QMLP had borrowed $121.7 million under their respective credit agreements. We anticipate that we may in the future incur additional debt for financing our growth. Our ability to borrow funds will depend upon a number of factors, including the condition of the financial markets. Under certain circumstances, the use of leverage may create a greater risk of loss to stockholders than if we did not borrow. The risk of loss in such circumstances is increased because we would be obligated to meet fixed payment obligations on specified dates regardless of our cash flow. If we do not make our debt service payments when due, our lenders may foreclose on assets securing such debt.

Our future level of debt could have important consequences, including the following:

	•		our ability to obtain additional debt or equity financing, if necessary, for drilling, expansion, working capital and other business needs may be impaired or such financing may not be available on favorable terms;

	•		a substantial decrease in our revenues as a result of lower oil and natural gas prices, decreased production or other factors could make it difficult for us to pay our liabilities. Any failure by us to meet these obligations could result in litigation, non-performance by contract counterparties or bankruptcy;

	•		our funds available for operations and future business opportunities will be reduced by that portion of our cash flow required to make principal or interest payments on our debt;

	•		we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

	•		our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our indebtedness, we will be forced to take actions such as reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness or seeking additional equity capital or bankruptcy protection. We may not be able to affect any of these remedies on satisfactory terms or at all.

Our credit agreements have substantial restrictions and financial covenants that restrict our business and financing activities.

The operating and financial restrictions and covenants in our credit agreements and the terms of any future financing agreements may restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities. Our credit agreements and any future financings agreements may restrict our ability to:

	•		incur indebtedness;

	•		grant liens;

	•		pay dividends;

	•		redeem or repurchase equity interests;

	•		make certain acquisitions and investments, loans or advances;

	•		lease equipment;

	•		enter into a merger, consolidation or sale of assets;

	•		dispose of property;

	•		enter into hedging arrangements with certain counterparties;

	•		limit the use of loan proceeds;

	•		make capital expenditures above specified amounts; and

	•		enter into transactions with affiliates.

In the past, we have been required to comply with certain financial covenants and ratios. Future financing agreements may require us to comply with financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by our results of operations and financial conditions and events or circumstances beyond our control. If market or other economic conditions do not improve, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit agreements, our indebtedness may become immediately due and payable, the interest rates on our credit agreements may increase and the lenders’ commitment, if any, to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments in which event we may be forced to file for bankruptcy.

For a description of our credit facilities, please read Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Agreements.”

An increase in interest rates will cause our debt service obligations to increase.

Borrowings under our credit agreements bear interest at floating rates. The rates are subject to adjustment based on fluctuations in market interest rates. An increase in the interest rates associated with our floating-rate debt would increase our debt service costs and affect our results of operations and cash flow. In addition, an increase in our interest expense could adversely affect our future ability to obtain financing or materially increase the cost of any additional financing.

We may be unable to pass through all of our costs and expenses for gathering and compression to royalty owners under our gas leases, which would reduce our net income and cash flows.

We incur costs and expenses for gathering, dehydration, treating and compression of the natural gas that we produce. The terms of some of our existing gas leases may not, and the terms of some of the gas leases that we may acquire in the future may not, allow us to charge the full amount of these costs and expenses to the royalty owners under the leases. We currently recover approximately 75% of the total gathering fees incurred to transport natural gas for our royalty interest owners. On August 6, 2007, certain mineral interest owners filed a putative class action lawsuit against Quest Cherokee, that, among other things, alleges Quest Cherokee improperly charged certain expenses to the mineral and/or overriding royalty interest owners under leases covering the acres leased by Quest Cherokee in Kansas. We will be responsible for any judgments or settlements with respect to this litigation. Please see Note 8 to our consolidated financial statements in this quarterly report for a discussion of this litigation. To the extent that we are unable to charge the full amount of these costs and expenses to our royalty owners, our net income and cash flows will be reduced.

We depend on one customer for sales of our Cherokee Basin natural gas. A reduction by this customer in the volumes of gas it purchases from us could result in a substantial decline in our revenues and net income.

During the year ended December 31, 2008, QELP sold substantially all of its natural gas produced in the Cherokee Basin at market-based prices to ONEOK Energy Marketing and Trading Company (“ONEOK”) under a sale and purchase contract, which has an indefinite term but may be terminated by either party on 30 days’ notice, other than with respect to pending transactions, or less following an event of default. Sales under this contract accounted for approximately 80% and 60% of our consolidated revenue for the year ended December 31, 2008 and for the nine months ended September 30, 2009, respectively. If ONEOK were to reduce the volume of gas it purchases under this agreement, our revenue and cash flow would decline and our results of operations and financial condition could be materially adversely affected.

We are exposed to trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our customers and by counterparties to our derivative contracts. Some of our customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in its dealings with other parties. Any increase in the nonpayment or nonperformance by our customers and/or counterparties could adversely affect our results of operations and financial condition.

Unless we replace the reserves that we produce, our existing reserves and production will decline, which would adversely affect our revenues, profitability and cash flows.

Producing oil and gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and gas reserves, production and cash flow depend on our success in developing and exploiting our reserves efficiently and finding or acquiring additional recoverable reserves economically. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations. Factors that may hinder our ability to acquire additional reserves include competition, access to capital, prevailing gas prices and attractiveness of properties for sale. Because of our financial condition, we will not be able to replace in 2009 the reserves we expect to produce in 2009. Similarly, we may not be able to replace in 2010 the reserves we expect to produce in 2010. The failure of QELP to maintain its reserve levels could adversely affect the borrowing base under its revolving credit facility.

As of December 31, 2008, our proved reserve-to-production ratio was 7.8 years. Because this ratio includes proved undeveloped reserves, we expect that this ratio will not increase even if those proved undeveloped reserves are developed and the wells produce as expected. The proved reserve-to-production ratio reflected in our reserve report as of December 31, 2008 will change if production from our existing wells declines in a different manner than they have estimated and can change when we drill additional wells, make acquisitions and under other circumstances.

Our future success depends on QMLP’s ability to continually obtain new sources of natural gas supply for QMLP’s gas gathering system, which depends in part on certain factors beyond its control. Any decrease in supplies of natural gas could adversely affect our revenues and operating income.

QMLP’s gathering pipeline system is connected to natural gas fields and wells, from which the production will naturally decline over time, which means that the cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on QMLP’s gas gathering system, it must continually obtain new natural gas supplies. Substantially all of the natural gas on QMLP’s gas gathering system is produced by QELP in the Cherokee Basin. QMLP may not be able to obtain additional contracts for natural gas to connect to its gas gathering system. The primary factors affecting its ability to connect new supplies of natural gas and attract new customers to the gathering system include the level of successful drilling activity near the gathering system and QMLP’s ability to compete for the attachment of such additional volumes to the system. Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas reserves. Drilling activity generally decreases as natural gas prices decrease. The current pricing environment, particularly in combination with the constrained capital and credit markets and overall economic downturn, has resulted in a decline in our drilling activity. Lower drilling levels over a sustained period have had and could have a negative effect on the volumes of natural gas QMLP gathers and processes, which would materially adversely affect our business and financial results or our ability to achieve a growth strategy.

There is a significant delay between the time we drill and complete a CBM well and when the well reaches peak production. As a result, there will be a significant lag time between when we make capital expenditures and when we will begin to recognize significant cash flow from those expenditures.

Our general production profile for a CBM well averages an initial 5-10 Mcf/d (net), steadily rising for the first twelve months while water is pumped off and the formation pressure is lowered until the wells reach peak production (an average of 50-55 Mcf/d (net)). In addition, there could be significant delays between the time a well is drilled and completed and when the well is connected to a gas gathering system. This delay between the time when we expend capital expenditures to drill and complete a well and when we will begin to recognize significant cash flow from those expenditures may adversely affect our cash flow from operations. Our average cost to drill and complete a CBM well is between $110,000 to $120,000.

Our estimated proved reserves are based on assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

It is not possible to measure underground accumulations of oil and gas in an exact way. Oil and gas reserve engineering requires subjective estimates of underground accumulations of oil and gas and assumptions concerning future oil and gas prices, production levels and operating and development costs. In estimating our level of oil and gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to:

	•		a constant level of future oil and gas prices;

	•		geological conditions;

	•		production levels;

	•		capital expenditures;

	•		operating and development costs;

	•		the effects of governmental regulations and taxation; and

	•		availability of funds.

If these assumptions prove to be incorrect, our estimates of proved reserves, the economically recoverable quantities of oil and gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly.

As of December 31, 2008, in connection with an evaluation by our independent reservoir engineering firm, we (on a consolidated basis) had a downward revision of our estimated proved reserves of approximately 123.2 Bcfe (substantially all of which related to QELP’s proved reserves). A decrease in natural gas prices between January 1, 2008 and December 31, 2008 had an estimated impact

of 31.1 Bcfe. A decrease in natural gas prices between the date of the PetroEdge acquisition and December 31, 2008 had an estimated impact of approximately 35.5 Bcfe of the reduction. The estimated remaining 61.6 Bcfe reduction was attributable to (a) the elimination of 43.2 Bcfe in proved reserves as a result of further technical analysis of the reserves acquired from PetroEdge, and (b) a decrease of approximately 13.4 Bcfe due to the adverse impact on estimated reserves of an expected increase in gathering and compression costs.

Our standardized measure is calculated using unhedged oil and gas prices and is determined in accordance with the rules and regulations of the SEC. The present value of future net cash flows from our estimated proved reserves is not necessarily the same as the market value of our estimated proved reserves. The estimated discounted future net cash flows from our estimated proved reserves is based on prices and costs in effect on the day of estimate. However, actual future net cash flows from our oil and gas properties also will be affected by factors such as:

	•		the actual prices we receive for oil and gas;

	•		our actual operating costs in producing oil and gas;

	•		the amount and timing of actual production;

	•		the amount and timing of our capital expenditures;

	•		supply of and demand for oil and gas; and

	•		changes in governmental regulations or taxation.

The timing of both production and incurrence of expenses in connection with the development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with the FASB ASC 932 Extractive Activities, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.

Drilling for and producing oil and gas is a costly and high-risk activity with many uncertainties that could adversely affect our financial condition or results of operations.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. The cost of drilling, completing and operating a well is often uncertain, and cost factors, as well as the market price of oil and natural gas, can adversely affect the economics of a well. Furthermore, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

	•		high costs, shortages or delivery delays of drilling rigs, equipment, labor or other services;

	•		adverse weather conditions;

	•		difficulty disposing of water produced as part of the coal bed methane production process;

	•		equipment failures or accidents;

	•		title problems;

	•		pipe or cement failures or casing collapses;

	•		compliance with environmental and other governmental requirements;

	•		environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;

	•		lost or damaged oilfield drilling and service tools;

	•		loss of drilling fluid circulation;

	•		unexpected operational events and drilling conditions;

	•		increased risk of wellbore instability due to horizontal drilling;

	•		unusual or unexpected geological formations;

	•		natural disasters, such as fires;

	•		blowouts, surface craterings and explosions; and

	•		uncontrollable flows of oil, gas or well fluids.

A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of oil or gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances. We may drill wells that are unproductive or, although productive, do not produce oil or gas in economic quantities. Unsuccessful drilling activities could result in higher costs without any corresponding revenues. Furthermore, a successful completion of a well does not ensure a profitable return on the investment.

Our management has limited experience in drilling wells to the Marcellus Shale and less information regarding reserves and decline rates in the Marcellus Shale than in the Cherokee Basin. Wells drilled to the Marcellus Shale are deeper, more expensive and more susceptible to mechanical problems in drilling and completing than wells in the Cherokee Basin.

Our management has limited experience in drilling wells in the Marcellus Shale reservoir. As of September 30, 2009, we had drilled four vertical and two horizontal gross wells in the Marcellus Shale. Other operators in the Appalachian Basin also have limited experience in the drilling of Marcellus Shale wells. As a result, we have much less information with respect to the ultimate recoverable reserves and the production decline rate in the Marcellus Shale than we have in the Cherokee Basin. The wells to be drilled in the Marcellus Shale will be drilled deeper than in the Cherokee Basin and some may be horizontal wells, which makes the Marcellus Shale wells more expensive to drill and complete. The wells, especially any horizontal wells, will also be more susceptible than those in the Cherokee Basin to mechanical problems associated with the drilling and completion of the wells, such as casing collapse and lost equipment in the wellbore. The fracturing of the Marcellus Shale will be more extensive and complicated than fracturing the geological formations in the Cherokee Basin and will require greater volumes of water than conventional gas wells. The management of water and treatment of produced water from Marcellus Shale wells may be more costly than the management of produced water from other geologic formations.

The revenues of QMLP’s interstate pipeline business are generated under contracts that must be renegotiated periodically.

Substantially all of the revenues from the KPC Pipeline are generated under two firm capacity contracts with Kansas Gas Service, or KGS, and one firm capacity contract with Missouri Gas Energy, or MGE. The contracts with KGS generated 58% and 57% of total revenues from the KPC Pipeline for the year ended December 31, 2008 and the nine months ended September 30, 2009, respectively, and the contract with MGE generated 36% and 35% of total revenues from the KPC Pipeline for the year ended December 31, 2008 and the nine months ended September 30, 2009, respectively. The MGE firm contract was for 46,000 Dth/d which expired on October 31, 2009 and has not been renegotiated. KGS has several contracts for firm capacity on the KPC Pipeline, including contracts for the following capacities and terms (i) 12,000 Dth/d extending through October 31, 2013, (ii) 62,568 Dth/d extending through October 14, 2014, (iii) 6,857 Dth/d extending through March 31, 2017 and (iv) 6,900 Dth/d extending through September 30, 2017. QMLP has executed a Letter Agreement with KGS to terminate the contract for 62,568 Dth/d and replace it with two new contracts covering 27,568 Dth/d and 30,000 Dth/d both of which would extend through October 31, 2017. The contract for 30,000 Dth/d has provisions for volume decreases after the third year on a sliding basis each year. These contracts will go into effect upon final execution by both QMLP and KGS pending regulatory approval.

If QMLP is unable to extend or replace its firm contracts when they expire or renegotiate them on terms as favorable as the existing contracts, we could suffer a material reduction in revenues, earnings and cash flows. In particular, QMLP’s ability to extend and replace contracts could be adversely affected by factors it cannot control, including:

•

competition by other pipelines, including the change in rates or upstream supply of existing pipeline competitors, as well as the proposed construction by other companies of additional pipeline capacity in markets served by QMLP’s interstate pipelines;

	•		changes in state regulation of local distribution companies, which may cause them to negotiate short-term contracts or turn back their capacity when their contracts expire;

	•		reduced demand and market conditions in the areas QMLP serves;

	•		the availability of alternative energy sources or natural gas supply points; and

	•		regulatory actions.

Our hedging activities could result in financial losses or reduce our income.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we have entered into, and may in the future enter into, derivative arrangements for a significant portion of our oil and natural gas production that could result in both realized and unrealized hedging losses. The extent of our commodity price exposure is related largely to the effectiveness and scope of our hedging activities.

The prices at which we enter into derivative financial instruments covering our production in the future is dependent upon commodity prices at the time we enter into these transactions, which may be substantially lower than current oil and natural gas prices. Accordingly, our commodity price risk management strategy will not protect us from significant and sustained declines in oil and natural gas prices received for our future production. Conversely, our commodity price risk management strategy may limit our ability to realize cash flow from commodity price increases. Furthermore, we have adopted a policy that requires, and our credit facilities mandate, that we enter into derivative transactions related to only a portion of our expected production volumes and, as a result, we have direct commodity price exposure on the portion of our production volumes that is not covered by a derivative financial instrument.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into hedging transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our hedging activities are subject to the following risks:

	•		a counterparty may not perform its obligation under the applicable derivative instrument;

	•		there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and

	•		the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures.

Because of our lack of asset and geographic diversification, adverse developments in our operating areas would adversely affect our results of operations.

Substantially all of our assets are located in the Cherokee Basin and Appalachian Basin. As a result, our business is disproportionately exposed to adverse developments affecting these regions. These potential adverse developments could result from, among other things, changes in governmental regulation, capacity constraints with respect to the pipelines connected to our wells, curtailment of production, natural disasters or adverse weather conditions in or affecting these regions. Due to our lack of diversification in asset type and location, an adverse development in our business or these operating areas would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.

The oil and gas industry is highly competitive and we may be unable to compete effectively with larger companies, which may adversely affect our results of operations.

The oil and gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and gas and securing equipment and trained personnel, and we compete with other companies that have greater resources. Many of our competitors are major and large independent oil and gas companies, and they not only drill for and produce oil and gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. Our larger competitors also possess and employ financial, technical and personnel resources substantially greater than ours. These companies may be able to pay more for oil and gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, there is substantial competition for investment capital in the oil and gas industry. These larger companies may have a greater ability to continue drilling activities during periods of low oil and gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with larger companies could have a material impact on our business activities, results of operations and financial condition.

With respect to its natural gas gathering system, QMLP may face competition in its efforts to obtain additional natural gas volumes. QMLP competes principally against other producers in the Cherokee Basin with natural gas gathering services. Its competitors may expand or construct gathering systems in the Cherokee Basin that would create additional competition for the services QMLP provides to its customers.

With respect to the KPC Pipeline, QMLP competes with other interstate and intrastate pipelines in the transportation of natural gas for transportation customers primarily on the basis of transportation rates, access to competitively priced supplies of natural gas, markets served by the pipeline, and the quality and reliability of transportation services. Major competitors include Southern Star Central Gas Pipeline, Inc., Kinder Morgan Interstate Gas Transmission’s Pony Express Pipeline and Panhandle Eastern PipeLine Company in the Kansas City market and Southern Star Central Gas Pipeline, Inc., Peoples Natural Gas and Mid-Continent Market Center in the Wichita market.

Natural gas also competes with other forms of energy available to our customers, including electricity, coal, hydroelectric power, nuclear power and fuel oil. The impact of competition could be significantly increased as a result of factors that have the effect of significantly decreasing demand for natural gas in the markets served by QMLP’s pipelines, such as competing or alternative forms of energy, adverse economic conditions, weather, higher fuel costs, and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs that is not fully insured, our operations and financial results could be adversely affected.

There are a variety of risks inherent in our operations that may generate liabilities, including contingent liabilities, and financial losses to us, such as:

	•		damage to wells, pipelines, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;

	•		inadvertent damage from construction, farm and utility equipment;

	•		leaks of gas or oil spills as a result of the malfunction of equipment or facilities;

	•		fires and explosions; and

	•		other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial revenue losses.

In accordance with typical industry practice, we possess property, business interruption and general liability insurance at levels we believe are appropriate; however, insurance against all operational risk is not available to us. We are not fully insured against all risks, including drilling and completion risks that are generally not recoverable from third parties or insurance. We do not have property insurance on any of QMLP’s underground pipeline systems or wellheads that would cover damage to the pipelines. Pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the cost

of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets subsequent to the terrorist attacks on September 11, 2001 and the hurricanes in 2005, 2006 and 2008 have made it more difficult for us to obtain certain types of coverage. There can be no assurance that we will be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition and results of operations.

Shortages of crews could delay our operations, adversely affect our ability to increase our reserves and production and adversely affect our results of operations.

Wage increases and shortages in personnel in the future could increase our costs and/or restrict or delay our ability to drill wells and conduct our operations. Any delay in the drilling of new wells or significant increase in labor costs could adversely affect our ability to increase our reserves and production and reduce our revenues and cash available for distribution. Additionally, higher labor costs could cause certain of our projects to become uneconomic and therefore not be implemented or for existing wells to become shut-in, reducing our production and adversely affecting our results of operations.

Certain of our undeveloped leasehold acreage is subject to leases that may expire in the near future.

In the Cherokee Basin, as of September 30, 2009, QELP held oil and gas leases on approximately 535,817 net acres, of which 135,691 net acres (or 25.3%) are undeveloped and not currently held by production. Unless we establish commercial production on the properties subject to these leases during their term, these leases will expire. Leases covering approximately 20,037 net acres are scheduled to expire before December 31, 2009 and an additional 77,892 net acres are scheduled to expire before December 31, 2010. If these leases expire and are not renewed, we will lose the right to develop the related properties.

Subsequent to our divestiture of the Lycoming County, Pennsylvania properties on February 13, 2009, we held oil and gas leases and development rights, by virtue of farm-out agreements or similar mechanisms, on 30,467 net acres in the Appalachian Basin that are still within their original lease or agreement term and are not earned or are not held by production. Unless we establish commercial production on the properties or fulfill the requirements specified by the various agreements, during the prescribed time periods, these leases or agreements will expire. Leases or agreements covering approximately 1,605 net acres are scheduled to expire before December 31, 2009 and an additional approximately 6,000 net acres are scheduled to expire before December 31, 2010. Of this acreage, approximately 8,200 net acres can be maintained and held beyond December 31, 2010 by drilling four gross wells before December 31, 2009 and an additional six gross wells before December 31, 2010. Because of our financial condition, we do not expect to be able to meet the drilling and payment obligations to earn or maintain all of this leasehold acreage.

Our identified drilling location inventories will be developed over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, resulting in temporarily lower cash from operations, which may impact our results of operations.

Our management has specifically identified drilling locations for our future multi-year drilling activities on our existing acreage. We have identified, based on reserves as of December 31, 2008, approximately 292 gross proved undeveloped drilling locations and approximately 2,034 additional gross potential drilling locations in the Cherokee Basin and approximately 22 gross proved undeveloped drilling locations and approximately 435 additional gross potential drilling locations in the Appalachian Basin. These identified drilling locations represent a significant part of our future long-term development drilling program. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, gas prices, costs and drilling results. The assignment of proved reserves to these locations is based on the assumptions regarding gas prices in our December 31, 2008 reserve report, which prices have declined since the date of the report. In addition, no proved reserves are assigned to any of the approximately 2,034 Cherokee Basin and 435 Appalachian Basin potential drilling locations we have identified and therefore, there exists greater uncertainty with respect to the likelihood of drilling and completing successful commercial wells at these potential drilling locations. Our final determination of whether to drill any of these drilling locations will be dependent upon the factors described above, our financial condition, our ability to obtain additional capital as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, it is unlikely that all of the numerous drilling locations identified will be drilled within the timeframe specified in our reserve report or will ever be drilled, and we do not know if we will be able to produce gas from these or any other potential drilling locations. As such, our actual drilling

activities may materially differ from those presently identified, which could have a significant adverse effect on our financial condition and results of operations.

We may incur losses as a result of title deficiencies in the properties in which we invest.

If an examination of the title history of a property reveals that an oil or gas lease has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would substantially decline in value. In such an instance, the amount paid for such oil or gas lease or leases would be lost. It is management’s practice, in acquiring oil and gas leases, or undivided interests in oil and gas leases, not to incur the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.

Prior to drilling an oil or gas well, however, it is the normal practice in the oil and gas industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil or gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such curative work entails expense. The work might include obtaining affidavits of heirship or causing an estate to be administered. Our failure to obtain these rights may adversely impact its ability in the future to increase production and reserves.

A change in the jurisdictional characterization of some of QMLP’s gathering assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of its gathering assets, which may indirectly cause our revenues to decline and operating expenses to increase.

Section 1(b) of the Natural Gas Act of 1938, or NGA, exempts natural gas gathering facilities from Federal Energy Regulatory Commission, or FERC, jurisdiction. We believe that the facilities comprising QMLP’s gathering system meet the traditional tests used by FERC to distinguish nonjurisdictional gathering facilities from jurisdictional transportation facilities, and that, as a result, the gathering system is not subject to FERC’s jurisdiction. However, FERC regulation will still affect QMLP’s gathering business and the markets for its natural gas. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, ratemaking, capacity release and market center promotion, could indirectly affect QMLP’s gathering business. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of regular litigation. The classification and regulation of some of QMLP’s gathering facilities may be subject to change based on future determinations by FERC, the courts or Congress.

Although natural gas gathering facilities are exempt from FERC jurisdiction under the NGA, such facilities are subject to rate regulation when owned by an interstate pipeline and other forms of regulation by the state in which such facilities are located. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, open access requirements and rate regulation. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that a number of interstate pipeline companies have transferred gathering facilities to unregulated affiliates. QMLP’s gathering operations are limited to the States of Kansas, Oklahoma and West Virginia. QMLP will be licensed as an operator of a natural gas gathering system with the Kansas Corporation Commission, or KCC, and is required to file periodic information reports with the KCC. QMLP is not required to be licensed as an operator or to file reports in Oklahoma or West Virginia.

Third party producers on QMLP’s Cherokee Basin gathering system have the ability to file complaints challenging the rates that QMLP charges. The rates must be just, reasonable, not unjustly discriminatory and not unduly preferential. If the KCC or the Oklahoma Corporation Commission, or OCC, as applicable, were to determine that the rates charged to a complainant did not meet this standard, the KCC or the OCC, as applicable, would have the ability to adjust the rates with respect to the wells that were the subject of the complaint. QMLP’s gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on QMLP’s operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

The KPC Pipeline is subject to regulation by FERC, which could have an adverse impact on QMLP’s ability to establish transportation rates that would allow it to recover the full cost of operating the KPC pipeline, plus a reasonable return, which may affect our business and results of operations.

As an interstate natural gas pipeline, the KPC Pipeline is subject to regulation by FERC under the NGA. FERC’s regulation of interstate natural gas pipelines extends to such matters as:

	•		transportation of natural gas;

	•		rates, operating terms and conditions of service;

	•		the types of services KPC may offer to its customers;

	•		construction of new facilities;

	•		acquisition, extension or abandonment of services or facilities;

	•		accounting and recordkeeping;

	•		commercial relationships and communications with affiliated companies involved in certain aspects of the natural gas business; and

	•		the initiation and discontinuation of services.

KPC may only charge transportation rates that it has been authorized to charge by FERC. In addition, FERC prohibits natural gas companies from engaging in any undue preference or discrimination with respect to rates or terms and conditions of service. The maximum recourse rates that it may charge for transportation services are established through FERC’s ratemaking process, and those recourse rates, as well as the terms and conditions of service, are set forth in KPC’s FERC-approved tariff. Pipelines may also negotiate rates that are higher than the maximum recourse rates stated in their tariffs, provided such rates are filed with, and approved by, FERC. Under the NGA, existing rates may be challenged by complaint, proposed rate increases may be challenged by protest, and either may be challenged by FERC on its own initiative. Any successful challenge against KPC’s current rates or any future proposed rates could adversely affect our revenues.

Generally and absent settlement, the maximum filed recourse rates for interstate pipelines are based on the cost of service plus an approved return on investment, the equity component of which may be determined through the use of a proxy group of similarly-situated companies. Specifically, FERC uses a discounted cash flow model that incorporates the use of proxy groups to develop a range of reasonable returns earned on equity interests in companies with corresponding risks. FERC then assigns a rate of return on equity within that range to reflect specific risks of that pipeline when compared to the proxy group companies. Other key determinants in the ratemaking process are debt costs, depreciation expense, operating costs of providing service, including an income tax allowance, and volume throughput and contractual capacity commitment assumptions.

We cannot give any assurance regarding the likely future regulations under which KPC will operate the KPC Pipeline or the effect such regulation could have on its business, financial condition, and results of operations. FERC periodically revises and refines its ratemaking and other policies in the context of rulemakings, pipeline-specific adjudications, or other regulatory proceedings. FERC’s policies may also be modified when FERC decisions are subjected to judicial review. Changes to ratemaking policies may in turn affect the rates KPC can charge for transportation service.

We lack experience with and could be subject to penalties and fines if QMLP fails to comply with FERC regulations.

QMLP acquired the KPC Pipeline, which is its only FERC regulated asset, in November 2007. Given QMLP’s limited experience with FERC-regulated pipeline operations, and the complex and evolving nature of FERC regulation, it may incur significant costs related to compliance with FERC regulations. Should QMLP fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1,000,000 per day for each violation, and to order disgorgement of profits associated with any violation. FERC’s enforcement authority also includes the options of revoking or modifying existing certificate authority and referring matters to the United States Department of Justice for criminal prosecution. Since enactment of the Energy Policy Act of 2005, FERC has initiated a number of enforcement proceedings and imposed penalties on various regulated entities, including other interstate natural gas pipelines.

We may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental and operational safety regulations or an accidental release of hazardous substances into the environment.

We may incur significant costs and liabilities as a result of environmental, health and safety requirements applicable to our oil and gas exploration, development and production activities. These costs and liabilities could arise under a wide range of federal, state and local environmental, health and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, liability for natural resource damages or damages to third parties, and to a lesser extent, issuance of injunctions to limit or cease operations.

Our operations are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example, (1) the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions, (2) the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state laws that impose requirements for the handling, storage, treatment or discharge of waste from our facilities, (3) the federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as “Superfund,” and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties owned or operated by us or our predecessors or locations to which we or our predecessors has sent waste for disposal and (4) the federal Clean Water Act and analogous state laws and regulations that impose detailed permit requirements and strict controls regarding the discharge of pollutants into waters of the United States and state waters. Failure to comply with these laws and regulations or newly adopted laws or regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders limiting or enjoining future operations or imposing additional compliance requirements or operational limitation on such operations. Certain environmental laws, including CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of oil and natural gas, air emissions related to our operations, and historical industry operations and waste disposal practices. For example, an accidental release from one of QMLP’s pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover these costs from insurance.

We may face unanticipated water and other waste disposal costs.

We may be subject to regulation that restricts our ability to discharge water produced as part of our gas production operations. Productive zones frequently contain water that must be removed in order for the gas to produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce gas in commercial quantities. The produced water must be transported from the lease and injected into disposal wells. The availability of disposal wells with sufficient capacity to receive all of the water produced from our wells may affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability.

Where water produced from our projects fails to meet the quality requirements of applicable regulatory agencies, our wells produce water in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of all applicable regulatory agencies, or we are unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur:

	•		we cannot obtain future permits from applicable regulatory agencies;

	•		water of lesser quality or requiring additional treatment is produced;

	•		our wells produce excess water;

	•		new laws and regulations require water to be disposed in a different manner; or

	•		costs to transport the produced water to the disposal wells increase.

RCRA and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous solid wastes. Under the auspices of the U.S. Environmental Protection Agency (“EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. In the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, and waste oils, which may be regulated as hazardous wastes. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements. However, drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, production and transportation of oil and gas are currently excluded from regulation as hazardous wastes under RCRA. These wastes may be regulated by EPA or state agencies as non-hazardous solid wastes. Moreover, it is possible that certain oil and gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

Pipeline integrity programs and repairs may impose significant costs and liabilities.

Pursuant to the Pipeline Safety Improvement Act of 2002, the DOT has adopted regulations requiring pipeline operators to develop integrity management programs for intrastate and interstate natural gas and natural gas liquids pipelines located near high consequence areas, where a leak or rupture could do the most harm. The regulations require operators to:

	•		perform ongoing assessments of pipeline integrity;

	•		identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

	•		improve data collection, integration and analysis;

	•		repair and remediate the pipeline as necessary; and

	•		implement preventive and mitigating actions.

We estimate that we will incur costs of approximately $1.0 million through 2009 to complete the last year of the initial high consequence area integrity testing of which we have incurred approximately $0.25 million to date. We estimate we will incur approximately $1.5 million in 2012 to implement pipeline integrity management program testing along certain segments of natural gas pipelines. We also estimate that we will incur costs of approximately $0.5 million through 2009 and an additional $0.25 million to $0.3 million in 2010 to complete the last year of a Stray Current Survey resulting from a 2005 U.S. Department of Transportation (“DOT”) audit. These costs may be significantly higher due to the following factors:

	•		our estimate does not include the costs of repairs, remediation or preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial;

	•		additional regulatory requirements that are enacted could significantly increase the amount of these expenditures;

	•		the actual implementation costs may be materially higher than we estimate because of increased industry-wide demand for contractors and service providers and the related increase in costs; or

	•		failure to comply with DOT regulations and any corresponding deadlines, which could subject us to penalties and fines.

Recent and future environmental laws and regulations may significantly limit, and increase the cost of, our exploration and production operations.

Recent and future environmental laws and regulations, including additional federal and state restrictions on greenhouse gas emissions that may be passed in response to climate change concerns, may increase our operating costs and also reduce the demand for the oil and natural gas we produce. The oil and gas industry is a direct source of certain greenhouse gas (“GHG”) emissions, such as carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. Specifically, on April 17, 2009, the EPA issued a notice of its proposed finding and determination that emission of carbon dioxide, methane, and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to EPA, contributing to warming of the earth’s atmosphere. EPA’s proposed finding and determination, and any final action in the future, will allow it to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. Although it may take EPA several years to adopt and impose regulations limiting emissions of GHGs, any such regulation could require us to incur costs to reduce emissions of GHGs associated with our operations. Similarly, on June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or ACESA. ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs and could have an adverse effect on demand for the oil and natural gas we produce. At the state level, more than one-third of the states, including California, have begun taking actions to control and/or reduce emissions of GHGs. The California Global Warming Solutions Act of 2006, also known as “AB 32,” caps California’s greenhouse gas emissions at 1990 levels by 2020, and the California Air Resources Board is currently developing mandatory reporting regulations and early action measures to reduce GHG emissions prior to January 1, 2012. Although most of the regulatory initiatives developed or being developed by the various states have to date been focused on large sources of GHG emissions, such as coal-fired electric power plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations in the future.

In addition, the U.S. Congress is currently considering certain other legislation which, if adopted in its current proposed form, could subject companies involved in oil and natural gas exploration and production activities to substantial additional regulation. If such legislation is adopted, federal tax incentives could be curtailed, and hedging activities as well as certain other business activities of exploration and production companies could be limited, resulting in increased operating costs. Any such limitations or increased operating costs could have a material adverse effect on our business.

Growing our business by constructing new assets is subject to regulatory, political, legal and economic risks.

One of the ways QMLP intends to grow its business in the long-term is through the construction of new midstream assets.

The construction of additions or modifications to QMLP’s gas gathering system and/or the KPC Pipeline, and the construction of new midstream assets, involves numerous operational, regulatory, environmental, political and legal risks beyond our control and may require the expenditure of significant amounts of capital. These potential risks include, among other things:

	•		inability to complete construction of these projects on schedule or at the budgeted cost due to the unavailability of required construction personnel or materials;

	•		failure to receive any material increases in revenues until the project is completed, even though we may have expended considerable funds during the construction phase, which may be prolonged;

	•		facilities may be constructed to capture anticipated future growth in production in a region in which such growth does not materialize;

	•		reliance on third party estimates of reserves in making a decision to construct facilities, which estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating reserves;

	•		inability to obtain rights-of-way to construct additional pipelines or the cost to do so may be uneconomical;

	•		the construction of additions or modifications to the KPC Pipeline may require the issuance of certificates of public convenience and necessity from FERC, which may result in delays or increased costs; and

	•		additions to or modifications of the gas gathering system could result in a change in its NGA-exempt status.

If we do not make acquisitions on economically acceptable terms, our future growth and profitability will be limited.

Our ability to grow and to increase our profitability depends in part on our ability to make acquisitions that result in an increase in our net income per share and cash flows. We may be unable to make such acquisitions because we are: (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms or (3) outbid by competitors. If we are unable to acquire properties containing proved reserves, our total level of proved reserves will decline as a result of our production, which will adversely affect our results of operations.

Even if we do make acquisitions that we believe will increase our net income per share and cash flows, these acquisitions may nevertheless result in a decrease in net income and/or cash flows. Any acquisition involves potential risks, including, among other things:

	•		mistaken assumptions about reserves, future production, volumes, revenues and costs, including synergies;

	•		an inability to integrate successfully the businesses we acquire;

	•		a decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the acquisition;

	•		a significant increase in our interest expense or financial leverage if we incur additional debt to finance the acquisition;

	•		the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;

	•		an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;

	•		limitations on rights to indemnity from the seller;

	•		mistaken assumptions about the overall costs of equity or debt;

	•		the diversion of management’s and employees’ attention from other business concerns;

	•		the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges;

	•		unforeseen difficulties operating in new product areas or new geographic areas; and

	•		customer or key employee losses at the acquired businesses.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and investors will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

In addition, we may pursue acquisitions outside the Cherokee and Appalachian Basins. Because we operate substantially in the Cherokee and Appalachian Basins, we do not have the same level of experience in other basins. Consequently, acquisitions in areas outside the Cherokee and Appalachian Basins may not allow us the same operational efficiencies we currently benefit from in those basins. In addition, acquisitions outside the Cherokee and Appalachian Basins will expose us to different operational risks due to potential differences, among others, in:

	•		geology;

	•		well economics;

	•		availability of third party services;

	•		transportation charges;

	•		content, quantity and quality of oil and gas produced;

	•		volume of waste water produced;

	•		state and local regulations and permit requirements; and

	•		production, severance, ad valorem and other taxes.

Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume environmental and other risks and liabilities in connection with acquired properties.

If third party pipelines and other facilities interconnected to QMLP’s natural gas pipelines become unavailable to transport or produce natural gas, its revenues and cash available for distribution could be adversely affected.

QMLP depends upon third party pipelines and other facilities that provide delivery options to and from its pipelines and facilities for the benefit of its customers. Since QMLP does not own or operate any of these pipelines or other facilities, their continuing operation is not within its control. If any of these third party pipelines and other facilities become unavailable to transport or produce natural gas, our revenues and cash available for distribution could be adversely affected.

Failure of the natural gas that QMLP gathers on its gas gathering system to meet the specifications of interconnecting interstate pipelines could result in curtailments by the interstate pipelines.

Natural gas gathered on QMLP’s gas gathering system is delivered into interstate pipelines. These interstate pipelines establish specifications for the natural gas that they are willing to accept, which include requirements such as hydrocarbon dewpoint, temperature, and foreign content including water, sulfur, carbon dioxide and hydrogen sulfide. These specifications vary by interstate pipeline. If the natural gas delivered from the gas gathering system fails to meet the specifications of a particular interstate pipeline that pipeline may refuse to accept all or a part of the natural gas scheduled for delivery to it. In those circumstances, QMLP may be required to find alternative markets for that natural gas or to shut-in the producers of the non-conforming natural gas, potentially reducing its throughput volumes or revenues.

QMLP’s interstate natural gas pipeline has recorded certain assets that may not be recoverable from its customers.

FERC rate-making and accounting policies permit pipeline companies to record certain types of expenses that relate to regulated activities to be recorded on our balance sheet as regulatory assets for possible future recovery in jurisdictional rates. QMLP considers a number of factors to determine the probability of future recovery of these assets. If QMLP determines future recovery is no longer probable or if FERC denies recovery, it would be required to write off the regulatory assets at that time, potentially reducing our revenues.

Operational limitations of the KPC Pipeline could cause a significant decrease in our revenues and operating results.

During peak demand periods, failures of compression equipment or pipelines could limit the KPC Pipeline’s ability to meet firm commitments, which may limit its ability to collect reservation charges from its customers and, if so, could negatively impact our revenues and results of operations.

QMLP does not own all of the land on which its pipelines are located or on which it may seek to locate pipelines in the future, which could disrupt its operations and growth.

QMLP does not own the land on which its pipelines have been constructed, but does have right-of-way and easement agreements from landowners and governmental agencies, some of which require annual payments to maintain the agreements and most of which have a perpetual term. New pipeline infrastructure construction may subject QMLP to more onerous terms or to increased costs if the design of a pipeline requires redirecting. Such costs could have a material adverse effect on our business, results of operations and financial condition.

In addition, the construction of additions to the pipelines may require QMLP to obtain new rights-of-way prior to constructing new pipelines. QMLP may be unable to obtain such rights-of-way to expand pipelines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive to obtain new rights-of-way. If the cost of obtaining new rights-of-way increases, then our business and results of operations could be adversely affected.

Our success depends on key management personnel, the loss of any of whom could disrupt our business.

The success of our operations and activities is dependent to a significant extent on the efforts and abilities of our management. We have not obtained, and we do not anticipate obtaining, “key man” insurance for any of our management. The loss of services of any of our key management personnel could have a material adverse effect on our business. If the key personnel do not devote significant time and effort to the management and operation of the business, our financial results may suffer.

Risks Related to the Ownership of Our Common Stock

We currently are not in compliance with NASDAQ’s continued listing requirements, and if our common stock is delisted, it could negatively impact the price of our common stock, our ability to access the capital markets and the liquidity of our common stock.

Our common stock is currently listed on the NASDAQ Global Market. To maintain our listing, we are required to maintain a minimum closing bid price of at least $1.00 per share for our common stock for 30 consecutive business days. On September 15, 2009, we received a notice from the staff of The NASDAQ Stock Market, indicating that, because our stock has not maintained a minimum bid price of $1.00 per share for the last 30 consecutive business days, a deficiency exists under NASDAQ Listing Rule 5450(a)(1). However, NASDAQ Listing Rule 5810(c)(3)(A) provides us a 180 calendar day grace period to regain compliance. Our grace period will expire on March 15, 2010. We will automatically regain compliance with NASDAQ rules if, at any time during this grace period the bid price for its shares closes at $1.00 or more per share for a minimum of ten consecutive business days. If we have not regained compliance by the end of this grace period we will receive a written notification that our securities are subject to delisting, a determination we can choose to appeal to NASDAQ Hearing’s Panel.

Any potential delisting of our common stock from the NASDAQ Global Market would make it more difficult for our stockholders to sell our stock in the public market. Additionally, the delisting of our common stock could materially adversely affect our ability to raise capital that may be needed for future operations. Delisting could also have other negative results, including the potential loss of confidence by customers and employees, the loss of institutional investor interest, and fewer business development opportunities and would likely result in decreased liquidity and increased volatility for our common stock.

Our stock price may be volatile.

The following factors could affect our stock price:

	•		the Recombination and the uncertainty whether it will be consummated or successful;

	•		our operating and financial performance and prospects;

	•		quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;

	•		changes in revenue or earnings estimates or publication of research reports by analysts about us or the exploration and production industry;

	•		changes in revenue or earnings estimates or publication of research reports by analysts about us or the exploration and production industry;

	•		material weaknesses in the control environment;

	•		actual or anticipated variations in our reserve estimates and quarterly operating results;

	•		changes in oil and natural gas prices;

	•		speculation in the press or investment community;

	•		sales of our common stock by significant stockholders;

	•		short-selling of our common stock by investors;

	•		pending litigation, including securities class action and derivative lawsuits;

	•		issuance of a significant number of shares to raise additional capital to fund our operations;

	•		increases in our cost of capital;

	•		changes in applicable laws or regulations, court rulings and enforcement and legal actions;

	•		changes in market valuations of similar companies;

	•		adverse market reaction to any increased indebtedness we incur in the future;

	•		additions or departures of key management personnel;

	•		actions by our stockholders;

	•		general market conditions, including fluctuations in and the occurrence of events or trends affecting the price of oil and natural gas; and

	•		domestic and international economic, legal and regulatory factors unrelated to our performance.

It is unlikely that we will be able to pay dividends on our common stock.

We have never paid dividends on our common stock. We cannot predict with certainty that our operations will result in sufficient revenues to enable us to operate profitably and with sufficient positive cash flow so as to enable us to pay dividends to the holders of common stock. In addition, the Credit Agreement prohibits us from paying any dividend to the holders of our common stock without the consent of the lenders under the Credit Agreement, other than dividends payable solely in equity interests of QRCP.

The percentage ownership evidenced by the common stock is subject to dilution.

We are authorized to issue up to 200,000,000 shares of common stock and are not prohibited from issuing additional shares of such common stock. Moreover, to the extent that we issue any additional common stock, a holder of the common stock is not necessarily entitled to purchase any part of such issuance of stock. The holders of the common stock do not have statutory “preemptive rights” and therefore are not entitled to maintain a proportionate share of ownership by buying additional shares of any new issuance of common stock before others are given the opportunity to purchase the same. Accordingly, your percentage ownership, as a holder of the common stock, is subject to change as a result of the sale of any additional common stock or other equity interests in QRCP.

Our common stock is an unsecured equity interest.

Just like any equity interest, our common stock is not secured by any of our assets. Therefore, in the event of our liquidation, the holders of our common stock will receive distributions only after all of our secured and unsecured creditors have been paid in full. There can be no assurance that we will have sufficient assets after paying its secured and unsecured creditors to make any distribution to the holders of our common stock.

Provisions in Nevada law could delay or prevent a change in control, even if that change would be beneficial to our stockholders.

Certain provisions of Nevada law may delay, discourage, prevent or render more difficult an attempt to obtain control of us, whether through a tender offer, business combination, proxy contest or otherwise. The provisions of Nevada law are designed to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with our board of directors.

Specifically, the Nevada Revised Statutes contain a provision prohibiting certain “combinations” (generally defined to include certain mergers, disposition of assets transactions, and share issuance or transfer transactions) between a resident domestic corporation and an “interested stockholder” (generally defined to be the beneficial owner of 10% or more of the voting power of the outstanding

shares of the corporation), except those combinations which are approved by the board of directors before the interested stockholder first obtained a 10% interest in the corporation’s stock. There are additional exceptions to the prohibition, which apply to combinations if they occur more than three years after the interested stockholder’s date of acquiring shares. This provision applies unless the corporation elects against its application in its original articles of incorporation or an amendment thereto. Our restated articles of incorporation, as amended, do not currently contain a provision rendering this provision inapplicable.

We have various mechanisms in place to discourage takeover attempts, which may reduce or eliminate our stockholders’ ability to sell their shares for a premium in a change of control transaction.

Various provisions of our articles of incorporation and bylaws may discourage, delay or prevent a change in control or takeover attempt of our company by a third party that is opposed to by our management and board of directors. Public stockholders who might desire to participate in such a transaction may not have the opportunity to do so. These anti-takeover provisions could substantially impede the ability of public stockholders to benefit from a change of control or change in our management and board of directors. These provisions include:

	•		the right of our board of directors to issue and determine the rights and preferences of preferred stock to make it more difficult for a third party to acquire, or to discourage a third party from acquiring, a majority of our outstanding voting stock;

	•		at certain times, classification of our directors into three classes with respect to the time for which they hold office;

	•		non-cumulative voting for directors;

	•		control by our board of directors of the size of our board of directors;

	•		limitations on the ability of stockholders to call special meetings of stockholders; and

	•		advance notice requirements for nominations by stockholders of candidates for election to our board of directors or for proposing matters that can be acted upon by our stockholders at stockholder meetings.

We have also approved a stockholders’ rights agreement, as amended (the “Rights Agreement”), between us and UMB Bank, N.A., (subsequently acquired by Computershare Limited) as Rights Agent. Pursuant to the Rights Agreement, holders of our common stock are entitled to purchase one one-thousandth (1/1,000) of a share (a “Unit”) of Series B Junior Participating Preferred Stock at a price of $75.00 per Unit upon certain events. The purchase price is subject to appropriate adjustment upon the happening of certain events. Generally, in the event a person or entity acquires, or initiates a tender offer to acquire, at least 15% of our then outstanding common stock, the Rights will become exercisable for shares of common stock equal to (i) the number of Units held by a stockholder multiplied by the then-current purchase price, and (ii) divided by one-half of our then-current stock price. The existence of the Rights Agreement may discourage, delay or prevent a change of control or takeover attempt of us by a third party that is opposed to by our management and board of directors.


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

None.


ITEM 3.		*DEFAULTS UPON SENIOR SECURITIES.*

None.


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

~~None~~No matters were submitted to a vote of security holders during the third quarter of 2009.


ITEM 5.		*OTHER INFORMATION.*

None.


ITEM 6.		*EXHIBITS*

2.1*		Agreement and Plan of Merger, dated as of July 2, 2009, by and among Quest Holdings Corp., Quest Resource Corporation, Quest Midstream Partners, L.P., Quest Energy Partners, L.P., Quest Midstream GP, LLC, Quest Energy GP, LLC, Quest Resource Acquisition Corp., Quest Energy Acquisition, LLC, Quest Midstream Holdings Corp. and Quest Midstream Acquisition, LLC (incorporated herein by reference to Exhibit 2.1 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 7, 2009).
*2.1		First Amendment dated as of October 2, 2009 to the Agreement and Plan of Merger, dated as of July 2, 2009, by and among New Quest Holdings Corp. (n/k/a PostRock Energy Corporation), Quest Resource Corporation, Quest Midstream Partners, L.P., Quest Energy Partners, L.P., Quest Midstream GP, LLC, Quest Energy GP, LLC, Quest Resource Acquisition Corp., Quest Energy Acquisition, LLC, Quest Midstream Holdings Corp. and Quest Midstream Acquisition, LLC (incorporated herein by reference to Exhibit 2.2 to PostRock Energy Corporation’s Registration Statement on Form S-4 filed on October 6, 2009).
4.1*		Amendment No. 1 to the Rights Agreement, dated as of July 2, 2009, between Quest Resource Corporation and Computershare Trust Company, N.A., as successor rights agent to UMB Bank, N.A. (incorporated herein by reference to Exhibit 4.1 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 7, 2009).
*10.1		Second Amended and Restated Credit Agreement dated as of September 11, 2009 by and among Quest Resource Corporation, Royal Bank of Canada, the lenders party thereto and RBC Capital Markets (incorporated herein by reference to Exhibit 10.1 to Quest Resource Corporation’s Current Report on Form 8-K filed on September 17, 2009).
10.1*		Settlement Agreement by and among Quest Resource Corporation, Quest Energy Partners, L.P., Quest Midstream Partners, L.P. and Jerry D. Cash, dated May 19, 2009 (incorporated herein by reference to Exhibit 10.31 to Quest Energy Partners, L.P.’s Annual Report on Form 10-K filed on June 16, 2009).
*10.2		Third Amendment to Second Lien Senior Term Loan Agreement, dated as of September 30, 2009, by and among Quest Cherokee, LLC, Quest Energy Partners, L.P., Quest Cherokee Oilfield Service, LLC, Royal Bank of Canada, KeyBank National Association, Société Générale and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 to Quest Resource Corporation’s Current Report on Form 8-K filed on October 1, 2009).
10.2*		Full and Final Settlement Agreement and Mutual Release, by and among Quest Resource Corporation, Quest Energy Partners, L.P. Midstream Partners, L.P., Rockport Energy, LLC, Rockport Georgetown Partners, LLC, Rockport Georgetown Holdings, LP, Jerry D. Cash, Bryan T. Simmons and Steven Hochstein, dated May 19, 2009 (incorporated herein by reference to Exhibit 10.32 to Quest Energy Partners, L.P.’s Annual Report on Form 10-K filed on June 16, 2009).
*10.3		Fourth Amendment to Second Lien Senior Term Loan Agreement, dated as of October 31, 2009, by and among Quest Cherokee, LLC, Quest Energy Partners, L.P., Quest Cherokee Oilfield Service, LLC, Royal Bank of Canada, KeyBank National Association, Société Générale and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 to Quest Resource Corporation’s Current Report on Form 8-K filed on November 2, 2009).
10.3*		Third Amendment to Amended and Restated Credit Agreement, dated as of May 29, 2009, by and among Quest Cherokee, LLC, Quest Energy Partners, L.P., Quest Cherokee Oilfield Service, LLC, Royal Bank of Canada, KeyBank National Association and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 to Quest Resource Corporation’s Current Report on Form 8-K filed on June 23, 2009).
*10.4		First Amendment dated as of October 2, 2009 to the Support Agreement, dated as of July 2, 2009, by and among Quest Resource Corporation, Quest Energy Partners, L.P., Quest Midstream Partners, L.P., Alerian Opportunity Partners IV, LP, Alerian Opportunity Partners IX, LP and certain other unitholders of Quest Midstream Partners, L.P. party thereto (incorporated herein by reference to Exhibit 10.61 to PostRock Energy Corporation’s Registration Statement on Form S-4 filed on October 6, 2009).
10.4*		Amended and Restated Intercreditor Agreement and Collateral Agency Agreement, dated as of June 18, 2009, by and among Royal Bank of Canada, BP Corporation North America, Inc. and Quest Cherokee, LLC (incorporated herein by reference to Exhibit 10.2 to Quest Resource Corporation’s Current Report on Form 8-K filed on June 23, 2009).
10.5		Second Amendment to Employment Agreement, dated as of August 28, 2009, by and between Quest Resource Corporation and Jack T. Collins.
10.5*		Fourth Amendment to Amended and Restated Credit Agreement, dated as of May 29, 2009, by and among the Company, Royal Bank of Canada and the Guarantors party thereto (incorporated herein by reference to Exhibit 10.62 to Quest Resource Corporation’s Annual Report on Form 10-K filed on June 2, 2009).
10.6*		Fifth Amendment to Amended and Restated Credit Agreement, dated as of June 30, 2009, by and among Quest Resource Corporation, Royal Bank of Canada and the Guarantors party thereto (incorporated herein by reference to Exhibit 10.4 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 7, 2009).
10.7*		First Amendment to Pledge and Security Agreement for Amended and Restated Credit Agreement by Quest Oil & Gas, LLC for the benefit of Royal Bank of Canada, dated May 29, 2009 (incorporated herein by reference to Exhibit 10.67 to Quest Resource Corporation’s Annual Report on Form 10-K filed on June 2, 2009).
10.8*		Fourth Amendment to Amended and Restated Credit Agreement, dated as of June 30, 2009, among Quest Cherokee, LLC, Quest Energy Partners, L.P., Quest Cherokee Oilfield Service, LLC, Royal Bank of Canada, KeyBank National Association and the Required Lenders party thereto (incorporated herein by reference to Exhibit 10.5 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 7, 2009).
10.9*		Second Amendment to Second Lien Senior Term Loan Agreement, dated as of June 30, 2009, among Quest Cherokee, LLC, Quest Energy Partners, L.P., Quest Cherokee Oilfield Service, LLC, Royal Bank of Canada, KeyBank National Association, Société Générale and the Required Lenders party thereto (incorporated herein by reference to Exhibit 10.6 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 7, 2009).
10.10*		Support Agreement, dated as of July 2, 2009, among Quest Resource Corporation, Quest Midstream Partners, L.P., Quest Energy Partners, L.P. and each of the unitholders of Quest Midstream Partners, L.P. party thereto (incorporated herein by reference to Exhibit 10.1 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 7, 2009).
10.11*		Amendment No. 1 to Amended and Restated Investors’ Rights Agreement, effective as of July 1, 2009, by and among Quest Midstream Partners, L.P., Quest Midstream GP, LLC, Quest Resource Corporation and the Investors party thereto (incorporated herein by reference to Exhibit 10.2 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 7, 2009).
10.12*		Amendment No. 2 to the Second Amended and Restated Agreement of Limited Partnership of Quest Midstream Partners, L.P., dated July 1, 2009, by and among Quest Midstream GP, LLC, Quest Resource Corporation and the Limited Partners party thereto (incorporated herein by reference to Exhibit 10.3 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 7, 2009).
31.1		Certification by principal executive officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification by principal financial officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification by principal executive officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification by principal financial officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		Incorporated by reference.

PLEASE NOTE: Pursuant to the rules and regulations of the Securities and Exchange Commission, we we have filed or incorporated by reference the ~~agreement~~agreements referenced above as ~~exhibit~~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 ~~not~~ no included with the ~~exhibit~~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~~ 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.

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SIGNATURES

Pursuant to the requirements of ~~Section 13 or 15(d) of~~ the Securities Exchange Act of 1934, the registrant has duly caused this ~~Quarterly~~ Report ~~on Form 10-Q~~ to be signed on its behalf by the undersigned, thereunto duly authorized this 5th ~~17th~~ day of ~~August~~November, 2009.


	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

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