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 September 30, 2009

Commission file number: 001-33787

QUEST ENERGY PARTNERS, L.P.

(Exact name of registrant specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)		26-0518546 (I.R.S. Employer Identification No.)

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

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

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

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

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


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

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

As of November 2, 2009, the issuer had 12,316,521 common units outstanding.

QUEST ENERGY PARTNERS, L.P.
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 September 30, 2009 and December 31, 2008			F-1
Condensed Consolidated Statements of Operations for the Three Months and Nine Months Ended September 30, 2009 and 2008			F-2
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2009 and 2008			F-3
Condensed Consolidated Statement of Partners’ Equity/(Deficit) for the Nine Months Ended September 30, 2009			F-4
Notes to Condensed Consolidated Financial Statements			F-5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			1
Item 3. Quantitative and Qualitative Disclosures About Market Risk			10
Item 4. Controls and Procedures			11

PART II — OTHER INFORMATION

Item 1. Legal Proceedings			15
Item 1A. Risk Factors			15
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			34
Item 3. Defaults Upon Senior Securities			34
Item 4. Submission of Matters to a Vote of Security Holders			34
Item 5. Other Information			34
Item 6. Exhibits			35
SIGNATURES			36
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I — FINANCIAL INFORMATION


Item 1.		Financial Statements

QUEST ENERGY PARTNERS, L.P AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS
($ in thousands, except unit data)


	September 30,			December 31,
	2009			2008
	(Unaudited)
ASSETS

Current assets:
Cash and cash equivalents	$	18,011		$	3,706
Restricted cash		301			112
Accounts receivable — trade, net		8,323			11,696
Other receivables		1,850			2,590
Due from affiliates		3,890			—
Other current assets		576			2,031
Inventory		8,329			8,782
Current derivative financial instrument assets		19,625			42,995

Total current assets		60,905			71,912

Property and equipment, net		15,684			17,367
Oil and gas properties under full cost method of accounting, net		36,064			151,120
Other assets, net		2,628			4,167
Long-term derivative financial instrument assets		4,653			30,836

Total assets	$	119,934		$	275,402


LIABILITIES AND EQUITY/(DEFICIT)

Current liabilities:
Accounts payable	$	4,867		$	7,380
Revenue payable		3,391			3,221
Accrued expenses		3,011			1,770
Due to affiliates		—			4,697
Current portion of notes payable		29,865			41,882
Current derivative financial instrument liabilities		1,413			12

Total current liabilities		42,547			58,962

Long-term derivative financial instrument liabilities		5,294			4,230
Asset retirement obligations		4,943			4,592
Notes payable		160,054			189,090

Commitments and contingencies

Partners’ equity/(deficit):
Common unitholders — Issued — 12,331,521 at September 30, 2009 and December 31, 2008 (9,100,000 — public; 3,231,521 — affiliate); outstanding — 12,316,521 at September 30, 2009 and December 31, 2008; respectively (9,100,000 — public; 3,216,521 — affiliate)		(17,697	)		45,832
Subordinated unitholder — affiliate; 8,857,981 units issued and outstanding at September 30, 2009 and December 31, 2008		(71,530	)		(25,857	)
General Partner — affiliate; 431,827 units issued and outstanding at September 30, 2009 and December 31, 2008		(3,677	)		(1,447	)

Total partners’ equity/(deficit)		(92,904	)		18,528

Total liabilities and partners’ equity	$	119,934		$	275,402

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

F-1

QUEST ENERGY PARTNERS, L.P AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in thousands, except per unit data)
(Unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
Oil and gas sales	$	18,151		$	49,454		$	56,260		$	136,908

Costs and expenses:
Oil and gas production		8,458			9,821			23,216			34,104
Transportation expense		10,879			8,583			31,272			25,921
General and administrative expenses		5,570			734			13,249			5,501
Depreciation, depletion and amortization		9,076			13,196			24,766			34,750
Impairment of oil and gas properties		—			—			95,169			—
Recovery of misappropriated funds, net of liabilities assumed		—			—			(31	)		—

Total costs and expenses		33,983			32,334			187,641			100,276

Operating income (loss)		(15,832	)		17,120			(131,381	)		36,632
Other income (expense):
Gain (loss) from derivative financial instruments		8,752			145,132			31,078			(4,482	)
Other income (expense)		(33	)		40			94			154
Interest expense, net		(3,370	)		(4,354	)		(11,274	)		(8,747	)

Total other income (expense)		5,349			140,818			19,898			(13,075	)

Net income (loss)	$	(10,483	)	$	157,938		$	(111,483	)	$	23,557

General partners’ interest in net income (loss)	$	(210	)	$	3,159		$	(2,230	)	$	471

Limited partners’ interest in net income (loss)	$	(10,273	)	$	154,779		$	(109,253	)	$	23,086

Net income (loss) per limited partner unit: (basic and diluted)	$	(0.49	)	$	7.30		$	(5.16	)	$	1.09

Weighted average limited partner units outstanding:
Common units (basic and diluted)		12,317			12,332			12,317			12,329

Subordinated units (basic and diluted)		8,858			8,858			8,858			8,858

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

F-2

QUEST ENERGY PARTNERS, L.P AND SUBSIDIARIES

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


	For the Nine Months Ended
	September 30,
	2009			2008
Cash flows from operating activities:
Net income (loss)	$	(111,483	)	$	23,557
Adjustments to reconcile net income (loss) to cash provided by (used in) operations:
Depreciation, depletion and amortization		24,766			34,750
Unit-based compensation		51			21
Change in fair value of derivative financial instruments		52,018			(13,312	)
Impairment of oil and gas properties		95,169			—
Amortization of deferred loan costs		1,781			847
Bad debt expense		—			97
Other non-cash items affecting net income		(55	)		—
Change in assets and liabilities:
Accounts receivable		3,373			(5,818	)
Other receivables		740			(513	)
Other current assets		1,455			120
Other assets		—			13,696
Due to/from affiliates		(9,468	)		734
Accounts payable		(2,727	)		(4,266	)
Revenue payable		58			(146	)
Accrued expenses		2,074			(1,222	)
Other long-term liabilities		—			(33	)
Other		(1	)		(1	)

Net cash from operating activities		57,751			48,511

Cash flows from investing activities:
Restricted cash		(189	)		1,093
Proceeds from sale of oil and gas properties		116			—
Acquisition of business — PetroEdge		—			(71,213	)
Equipment, development and leasehold		(1,384	)		(78,214	)

Net cash from investing activities		(1,457	)		(148,334	)

Cash flows from financing activities:
Proceeds from bank borrowings		102			45,000
Repayments of note borrowings		(12,849	)		(534	)
Proceeds from revolver note		—			89,000
Repayments of revolver note		(29,000	)		—
Contributions (distributions)		—			636
Distributions to unitholders		—			(22,573	)
Syndication costs		—			(265	)
Refinancing costs		(242	)		(1,893	)

Net cash from financing activities		(41,989	)		109,371

Net increase in cash and cash equivalents		14,305			9,548
Cash and cash equivalents, beginning of period		3,706			169

Cash and cash equivalents, end of period	$	18,011		$	9,717

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

F-3

QUEST ENERGY PARTNERS, L.P AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ EQUITY/(DEFICIT)
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2009
(Amounts subsequent to December 31, 2008 are unaudited)
(in thousands, except unit amounts)


	Common										General		General			Total
	Units		Common			Subordinated		Subordinated			Partner		Partner			Partners’
	Issued		Unitholders			Units		Unitholders			Units		Interest			Equity/(Deficit)
Balance, December 31, 2008		12,331,521	$	45,832			8,857,981	$	(25,857	)		431,827	$	(1,447	)	$	18,528
Net loss		—		(63,580	)		—		(45,673	)		—		(2,230	)		(111,483	)
Unit-based compensation				51			—		—			—		—			51

Balance, September 30, 2009		12,331,521	$	(17,697	)		8,857,981	$	(71,530	)		431,827	$	(3,677	)	$	(92,904	)

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

F-4

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1. Basis of Presentation

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

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

Unless the context clearly requires otherwise, references to “us”, “we”, “our” or the “Partnership” are intended to mean Quest Energy Partners, L.P. and its consolidated subsidiaries.

Going Concern

The accompanying condensed consolidated financial statements have been prepared assuming that the Partnership 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 Partnership and its predecessor have incurred significant losses from 2004 through 2008 and into 2009, mainly attributable to the operations, impairment of oil and gas properties, unrealized gains and losses from derivative financial instruments, 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.

While we were in compliance with the covenants in our credit agreements as of December 31, 2008 and September 30, 2009, there is no assurance that we will be in compliance as of December 31, 2009. If defaults exist in subsequent periods that are not waived by our lenders, our assets could be subject to foreclosure or other collection efforts. Our Amended and Restated Credit Agreement, as amended (“Quest Cherokee Credit Agreement”) limits the amount we can borrow to a borrowing base amount, determined by the lenders at their sole discretion. Outstanding borrowings in excess of the borrowing base will be required to be repaid in either four equal monthly installments following notice of the new borrowing base or immediately if the borrowing base is reduced in connection with a sale or disposition of certain properties in excess of 5% of the borrowing base. 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 we 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 was repaid on July 8, 2009. We anticipate that in connection with the redetermination of our borrowing base in November 2009, our borrowing base will be further reduced from its current level of $160 million. In the event of a borrowing base reduction, we expect to be able to make the required payments resulting from the borrowing base deficiency out of our existing funds.

Under the terms of our Second Lien Senior Term Loan Agreement, as amended (“Second Lien Loan Agreement”), we are required to make quarterly payments of $3.8 million. We have made payments through August 17, 2009. The balance remaining of $29.8 million which was previously due on September 30, 2009, is now due on November 16, 2009, as a result of the extension obtained under the Fourth Amendment to Second Lien Senior Term Loan Agreement entered into on October 30, 2009. While we are currently negotiating further extensions to this loan, there can be no assurance that such negotiations will be successful or that we will be able to repay amounts due under the Second Lien Loan Agreement in accordance with the terms of the agreement. Failure to make the remaining principal payment under the Second Lien Loan Agreement (absent any waiver granted or amendment to the agreement) would be a default under the terms of both credit agreements, resulting in payment acceleration of both loans.

F-5

Our parent, Quest Resource Corporation (“QRCP”) has pledged its ownership in our general partner to secure its term loan credit agreement and historically has been almost exclusively dependent upon distributions from its interest in Quest Midstream Partners, L.P. (“Quest Midstream” or “QMLP”) and us for revenue and cash flow. QRCP has not received any distributions from Quest Midstream in 2009; furthermore, we suspended distributions on our subordinated units starting with the third quarter of 2008 and all units starting with the fourth quarter of 2008, do not expect to have any available cash to pay distributions and are unable to estimate at this time when such distributions may, if ever, be resumed. If QRCP were to default under its credit agreement, the lenders of QRCP’s credit facility could obtain control of our general partner or sell control of our general partner to a third party. In the past, QRCP has not satisfied all of the financial covenants contained in its credit agreement. In QRCP’s Annual Report on Form 10-K/A for the year ended December 31, 2008, its independent registered public accounting firm expressed doubt about its ability to continue as a going concern if it is unable to restructure its debt obligations, issue equity securities and/or sell assets. On September 11, 2009, QRCP amended and restated its credit agreement to add an additional $8 million revolving credit facility to finance QRCP’s drilling program in the Appalachian Basin, general and administrative expenses and working capital and other corporate expenses. Under the terms of the amended and restated credit agreement, the total amount due on July 11, 2010 by QRCP under its credit agreement is estimated to be approximately $21 million. As a result, QRCP will need to raise a significant amount of equity capital during the first half of 2010 to pay this amount and further fund its drilling program. If QRCP is not successful in obtaining sufficient additional funds, there is a significant risk that QRCP will be forced to file for bankruptcy protection.

Based on the foregoing, we have determined that there is substantial doubt about our ability to continue as a going concern, absent an amendment of our credit agreements.

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

While we are working toward the completion of the Recombination before year-end, it remains subject to the satisfaction of a number of conditions, including, among others, the arrangement of one or more satisfactory credit facilities for PostRock and its subsidiaries, the approval of the transaction by our unitholders, the unitholders of QMLP and the stockholders of QRCP, and consents from each entity’s existing lenders. There can be no assurance that these conditions will be met or that the Recombination will occur.

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

The accompanying financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Recent Accounting Pronouncements

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

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

The Partnership adopted the provisions of FASB ASC 260 Earnings Per Share, effective January 1, 2009, relating to whether instruments granted in share-based payment transactions are considered participating securities prior to vesting and therefore included in the allocation of earnings for purposes of calculating earnings per unit (“EPU”) under the two-class method as required by FASB ASC 260. FASB ASC 260 provides that unvested unit-based awards that contain non-forfeitable rights to dividends are participating securities and should be included in the computation of EPU. The Partnership’s bonus units contain non-forfeitable rights to dividends and thus require these awards to be included in the EPU computation. All prior periods have been conformed to the current year presentation. During periods of losses, EPU will not be impacted, as the Partnership’s participating securities are not obligated to share in the losses of the Partnership and thus, are not included in the EPU computation. See Note 8. Net Income Per Limited Partner Unit.

F-6

The Partnership also adopted the provisions of FASB ASC 260 Earnings Per Share, effective January 1, 2009, relating to the comparability of EPU calculation for master limited partnerships with incentive distribution rights (“IDR”). FASB ASC 260 requires retrospective restatement of prior periods. IDRs will be awarded as certain targeted distributions are met. At this time, the Company has not met any targeted distributions, thus adoption of the IDR provisions within FASB ASC 260 has had no impact to the Partnership’s basic EPU calculation.

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

In May 2009, the FASB issued FASB ASC 855 Subsequent Events. FASB ASC 855 establishes general standards of accounting for and disclosure of transactions and events that occur after the balance sheet date but before financial statements are issued or are available to be issued. It also requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date. We adopted FASB ASC 855 beginning with the period ended June 30, 2009.

2. Acquisition

PetroEdge — On July 11, 2008, QRCP completed the acquisition of privately held PetroEdge Resources LLC (WV) (“PetroEdge”) in an all cash purchase for approximately $142 million in cash including transaction costs, subject to certain adjustments for working capital and certain other activity between May 1, 2008 and the closing date. At the time of the acquisition, PetroEdge owned approximately 78,000 net acres of oil and natural gas producing properties in the Appalachian Basin with estimated net proved reserves of 99.6 Bcfe as of May 1, 2008 .

At closing, QRCP sold the producing well bores to our subsidiary, Quest Cherokee LLC (“Quest Cherokee”), for approximately $71.2 million. The proved undeveloped reserves, unproved and undrilled acreage related to the wellbores (generally all acreage other than established spacing related to the producing wellbores) and a gathering system were retained by PetroEdge and its name was changed to Quest Eastern Resource LLC. Quest Eastern is designated as operator of the wellbores purchased by Quest Cherokee and conducts drilling and other operations for our affiliates and third parties on the PetroEdge acreage. We funded our purchase of the PetroEdge wellbores with borrowings under our Quest Cherokee Credit Agreement and the proceeds of a $45 million, six-month term loan. See Note 3. Long-Term Debt.

Pro Forma Summary Data Related to Acquisition

The following unaudited pro forma information summarizes the results of operations for the three and nine month periods ended September 30, 2008, as if our acquisition of the PetroEdge assets had occurred at the beginning of the period (in thousands, except per unit data):


	Three Months		Nine Months
	Ended		Ended
	September 30,		September 30,
	2008		2008
Pro forma revenue	$	49,454	$	143,458
Pro forma net income	$	157,938	$	19,020
Pro forma net income per limited partner unit — basic and diluted	$	7.31	$	0.88

F-7

3. Long-Term Debt

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


	September 30,		December 31,
	2009		2008
Borrowings under bank senior credit facilities
Quest Cherokee Credit Agreement	$	160,000	$	189,000
Second Lien Loan Agreement		29,800		41,200
Notes payable to banks and finance companies, secured by equipment and vehicles		119		772

Total debt		189,919		230,972
Less current maturities included in current liabilities		29,865		41,882

Total long-term debt	$	160,054	$	189,090

Credit Facilities

A. Quest Cherokee Credit Agreement.

Quest Cherokee, LLC (“Quest Cherokee”) is a party to the Quest Cherokee Credit Agreement with Royal Bank of Canada (“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 $160 million and the amount borrowed under the Quest Cherokee Credit Agreement was $160 million as of September 30, 2009. As a result, there was no additional borrowing availability. The weighted average interest rate under the Quest Cherokee Credit Agreement for the quarter ended September 30, 2009 was 4.36%.

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

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

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

B. Second Lien Loan Agreement.

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

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

F-8

As of September 30, 2009 and December 31, 2008, $29.8 million and $41.2 million was outstanding under the Second Lien Loan Agreement, respectively. The weighted average interest rate under the Second Lien Loan Agreement for the quarter ended September 30, 2009 was 11.25%.

On June 30, 2009, Quest Energy and Quest Cherokee entered into a Second Amendment to the Second Lien 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 Loan Agreement that extended the maturity date of the loan 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 Loan Agreement that extended the maturity of the loan to November 16, 2009. While we are currently negotiating further extensions to this loan, there can be no assurance that such negotiations will be successful or that we will be able to repay amounts due under the Second Lien 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.

4. Derivative Financial Instruments

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

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

We account for our derivative financial instruments in accordance with FASB ASC 815 Derivatives and Hedging. FASB ASC 815 requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. FASB ASC 815 requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met, or exemptions for normal purchases and normal sales (“NPNS”) as permitted by FASB ASC 815 exist. We do not designate our derivative financial instruments as hedging instruments for financial accounting purposes, and, as a result, we recognize the change in the respective instruments’ fair value currently in earnings. In accordance with FASB ASC 815, the table below outlines the classification of our derivative financial instruments on our condensed consolidated balance sheets and their financial impact in our condensed consolidated statement of operations (in thousands):

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Fair Value of Derivative Financial Instruments


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

		$	17,571		$	69,589

The Effect of Derivative Financial Instruments


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

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


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

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

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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

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


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

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

5. Fair Value Measurements

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

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

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

•

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

•

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

•

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

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

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

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									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 us and our 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.

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

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


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

Balance as of September 30, 2009	$	12,041

6. Asset Retirement Obligations

The following table reflects the changes to the Partnership’s asset retirement liability for the nine months ended September 30, 2009 (in thousands):


	Nine months ended
	September 30, 2009
Asset retirement obligations at beginning of period	$	4,592
Liabilities incurred		—
Liabilities settled		—
Accretion		351
Revisions in estimated cash flows		—

Asset retirement obligations at end of period	$	4,943

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7. Equity Compensation Plans

We have an equity compensation plan for our employees, consultants and non-employee directors pursuant to which unit awards may be granted. During 2008, 30,000 bonus common units were awarded under our long-term incentive plan, of which, 15,000 vested in 2008 and the remaining 15,000 vests ratably over two years. As of September 30, 2009, there were approximately 2.1 million units available for future awards. Unit-based compensation expense was less than $0.1 million for the three and nine months ended September 30, 2009 and 2008.

8. Net Income Per Limited Partner Unit

Subject to applicability of FASB ASC 260 Earnings Per Share, Partnership income is allocated 98% to the limited partners, including the holders of subordinated units, and 2% to the general partner. Income allocable to the limited partners is first allocated to the common unitholders up to the quarterly minimum distribution of $0.40 per unit, with remaining income allocated to the subordinated unitholders up to the minimum distribution amount. Basic and diluted net income per common and subordinated partner unit is determined by dividing net income attributable to common and subordinated partners by the weighted average number of outstanding common and subordinated partner units during the period.

FASB ASC 260 addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock (or partnership distributions to unitholders). Under FASB ASC 260, in accounting periods where the Partnership’s aggregate net income exceeds aggregate dividends declared in the period, the Partnership is required to present earnings per unit as if all of the earnings for the periods were distributed.

Earnings per limited partner unit are presented for the three and nine month periods ended September 30, 2009. The following table sets forth the computation of basic and diluted net loss per limited partner unit (in thousands, except unit and per unit data):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
Net income (loss)	$	(10,483	)	$	157,398		$	(111,483	)	$	23,557
Less: General Partner 2.0% ownership		(210	)		(3,159	)		(2,230	)		(471	)

Net income (loss) available to limited partners	$	(10,273	)	$	154,779		$	(109,253	)	$	(23,086	)

Basic and diluted weighted average number of units:
Common units		12,316,521			12,309,021			12,316,521			12,308,282
Subordinated units		8,857,981			8,857,981			8,857,981			8,857,981
Unvested unit-based awards participating		—			22,500			—			20,283

Basic and diluted weighted average number of units		21,174,502			21,189,502			21,174,502			21,186,546

Basic and diluted net income (loss) per limited partner unit:	$	(0.49	)	$	7.30		$	(5.16	)	$	1.09

Effective January 1, 2009, the Partnership adopted the provisions of FASB ASC 260 requiring participating securities to be included in the allocation of earnings when calculating EPU under the two-class method. All prior period EPU data presented above has been retrospectively adjusted to conform to the new requirements of this Staff Position. During periods of losses, basic EPU will not be impacted by the two-class method, as the Partnership’s participating securities are not obligated to share in the losses of the Partnership and thus, are not included in the EPU share computation.

The Partnership also adopted the provisions of FASB ASC 260 on January 1, 2009, relating to the comparability of EPU calculations for master limited partnerships with IDRs. Through September 30, 2009, the Partnership has not met any targeted distributions and thus, the provisions on IDR’s has had no impact to the Partnership’s EPU calculation.

Because we reported a net loss for the three and nine months ended September 30, 2009, participating securities covering 15,000 common shares were excluded from the computation of net loss per share because their effect would have been antidilutive.

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9. 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 Partnership had previously recognized a ceiling test impairment of $95.2 million during the first quarter of 2009 while no impairment was necessary for the second quarter of 2009. As of September 30, 2009, the ceiling test computation utilizing spot prices on that day resulted in the carrying costs of our unamortized proved oil and natural gas properties, net of deferred taxes, exceeding the September 30, 2009 present value of future net revenues by approximately $6.9 million. As a result of subsequent increases in spot prices, the need to recognize an impairment for the quarter ended September 30, 2009, was eliminated. Natural gas, which is sold at other natural gas marketing hubs where we conduct operations, is subject to prices which reflect variables that can increase or decrease spot natural gas prices at these hubs such as market demand, transportation costs and quality of the natural gas being sold. Those differences are referred to as the basis differentials. Typically, basis differentials result in natural gas prices which are lower than Henry Hub, except in Appalachia, where we have typically received a premium to Henry Hub. We may face further ceiling test write-downs in future periods, depending on the level of commodity prices, drilling results and well performance.

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

10. Commitments and Contingencies

Litigation

We are subject, from time to time, to certain legal proceedings and claims in the ordinary course of conducting our business. Below is a brief description of any material legal proceedings that were initiated against us since December 31, 2008 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 11 to our consolidated financial statements included in our 2008 Form 10-K/A and Note 10 to our consolidated financial statements included in our Forms 10-Q for the three months ended March 31, 2009 and June 30, 2009.

Federal Individual Securities Litigation

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

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

Federal Derivative Case

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

On July 17, 2009, a complaint was filed in the United States District Court for the Western District of Oklahoma, purportedly on Quest Energy’s behalf, which names certain of its current and former officers and directors, external auditors and vendors. The factual allegations relate to, among other things, the transfers and lack of effective internal controls. The complaint asserts claims for breach of fiduciary duty, waste of corporate assets, unjust enrichment, conversion, disgorgement under the Sarbanes-Oxley Act of 2002, and aiding and abetting breaches of fiduciary duties against the individual defendants and vendors and professional negligence and breach

F-15

of contract against the external auditors. The complaint seeks monetary damages, disgorgement, costs and expenses and equitable and/or injunctive relief. It also seeks Quest Energy to take all necessary actions to reform and improve its corporate governance and internal procedures. On September 8, 2009, the case was transferred to Judge Miles-LaGrange who is presiding over the other federal cases discussed below, and the case number was changed to CIV-09-752-M. All proceedings in this matter are currently stayed under Judge Miles-Lagrange’s order of October 16, 2009.

Personal Injury Litigation

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

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

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

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

Litigation Related to Oil and Gas Leases

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

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

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

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

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

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

F-16

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

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

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

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

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

Federal Securities Class Actions

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

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

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

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

Four putative class action complaints were filed in the United States District Court for the Western District of Oklahoma naming QRCP, QELP and Quest Energy GP, LLC (“Quest Energy GP”) and certain of their current and former officers and directors as defendants. The complaints were filed by certain stockholders on behalf of themselves and other stockholders who purchased QRCP common stock between May 2, 2005 and August 25, 2008 and QELP common units between November 7, 2007 and August 25, 2008. The complaints assert claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and Sections 11 and 15 of the Securities Act of 1933. The complaints allege that the defendants violated the federal securities laws by issuing false and misleading statements and/or concealing material facts concerning certain unauthorized transfers of funds from subsidiaries of QRCP to entities controlled by QRCP’s former chief executive officer, Mr. Jerry D. Cash. The complaints also allege that, as a result of these actions, QRCP’s stock price and the unit price of QELP was artificially inflated during the class period. On December 29, 2008 the court consolidated these complaints as Michael Friedman, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David E. Grose, Case No. 08-cv-936-M, in the Western District of Oklahoma. On September 24, 2009, the court appointed lead plaintiffs for each of the QRCP class and the QELP class. The lead plaintiffs must file a consolidated amended complaint within 60 days after being appointed. No further activity is expected in the purported class action until an amended consolidated complaint is filed. On October 13, 2009, the lead plaintiffs filed a motion for partial modification of the automatic discovery stay provided by the Private Securities Litigation Reform Act of 1995. QRCP, QELP and Quest Energy GP intend to defend vigorously against plaintiffs’ claims.

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

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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 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 the offer and its response to the same.

Personal Injury Litigation

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

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

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

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

Litigation Related to Oil and Gas Leases

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

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

Roger Dean Daniels v. Quest Cherokee, LLC, Case No. 06-CV-61, District Court of Montgomery County, State of Kansas, filed May 5, 2006 (currently on appeal with the Kansas Court of Appeals, Case No. 08-100576-A; oral argument scheduled for November 18, 2009)

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

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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 in August 2009)

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

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

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

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

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

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

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whether the coal bed methane gas is owned by the owner of the coal rights or by the owners of the gas rights. All claims have been dismissed by agreement of all of the parties and a journal entry of dismissal has been approved by the District Court.

Other

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

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

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

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

Environmental Matters

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

Financial Advisor Contract

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

11. Related Party Transactions

Settlement Agreements

As discussed in our 2008 Form 10-K/A, we and QRCP filed lawsuits, related to the Transfers, seeking, among other things, to recover the funds that were transferred. On May 19, 2009, we, QRCP, and Quest Midstream 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 our board of directors and the board of directors of QRCP, 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

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located in Texas and we received Mr. Cash’s interest in STP Newco, Inc (“STP”) which consisted of 100% of the common stock of the company.

While QRCP estimated 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 and QRCP 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 us, 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 QRCP received prior to the settlement, the estimated fair value of the net assets to be assumed was expected to provide us reimbursement for all of the costs of the internal investigation and the costs of the litigation against Mr. Cash that have been paid by us; 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 and QRCP, believe that the actual estimated fair value of net assets of STP that we received is less than previously expected. We and QRCP 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 and QRCP 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):


Oil & gas properties	$	1,076
Current liabilities		(326	)
Long-term debt		(719	)

Net assets received	$	31

Merger Agreement and Support Agreement

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

Additionally, in connection with the Merger Agreement, on July 2, 2009, we entered into a Support Agreement with QRCP, 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, QRCP has, subject to certain conditions, agreed to vote the common and subordinated units of Quest Energy and Quest Midstream that it owns in favor of the Recombination and the holders of approximately 73% of the common units of Quest Midstream have, subject to certain conditions, agreed to vote their common units in favor of the Recombination.

12. Subsequent Events

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

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

Forward-looking statements

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

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

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

Overview of QELP

We are a publicly traded master limited partnership formed in 2007 by Quest Resource Corporation (“QRCP”) to acquire, exploit and develop oil and natural gas properties. 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 and New York in the Appalachian Basin.

Operating Highlights

Our significant operational highlights include:

	•		We reduced production costs in the current quarter by $0.13 per Mcfe from the prior year quarter.

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

Financial Highlights

Our significant financial highlights include:

•

We reduced total debt by $41.1 million since December 31, 2008.

•

We increased cash and cash equivalents by $14.3 million since December 31, 2008.

•

We repriced our derivatives during the second quarter of 2009 and received $26 million as a result.

Recent Developments

Global Financial Crisis and Impact on Capital Markets and Commodity Prices

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

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

For oil, worldwide demand has decreased by over 5% from 2007 levels creating an oversupply environment similar to natural gas. The recent recovery of oil prices into the $70 per barrel range has had a small positive impact on revenues during the second half of 2009. Our management believes that managing price volatility will continue to be a challenge. The spot market price for oil at Cushing, Oklahoma at September 30, 2009 was $70.46 per barrel, a 30.0% decrease from the price at September 30, 2008. It is impossible to predict the duration or outcome of these price declines or the long-term impact on drilling and operating costs and the impacts, whether favorable or unfavorable, to our results of operations, liquidity and capital resources. Due to our relatively low level of oil production relative to gas and our existing commodity hedge positions, the volatility of oil prices had less of an effect on our operations.

Suspension of Distributions

We suspended distributions on our subordinated units starting with the third quarter of 2008 and on all units starting with the fourth quarter of 2008. Distributions on all of our units continue to be suspended. We do not expect to have any available cash to pay distributions in 2009 and we are unable to estimate at this time when such distributions may, if ever, be resumed. The terms of our credit agreements restrict our ability to pay distributions, among other things. Even if the restrictions on the payment of distributions under our credit agreements are removed, we may continue to not pay distributions in order to conserve cash for the repayment of indebtedness or other business purposes.

Even if we do not pay distributions, our unitholders may be liable for taxes on their share of our taxable income.

Settlement Agreements

As discussed in our 2008 Form 10-K/A, we and QRCP 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 office, seeking, among other things, to recover the funds that were transferred. On May 19, 2009, we, QRCP, and Quest Midstream Partners, L.P. (“Quest Midstream”) 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 our board of directors and the board of directors of QRCP, 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 we received Mr. Cash’s interest in STP Newco, Inc (“STP”) which consisted of 100% of the common stock of the company.

settlement. Based on documents QRCP received prior to the settlement, the estimated fair value of the net assets to be assumed was expected to provide us reimbursement for all of the costs of the internal investigation and the costs of the litigation against Mr. Cash that have been paid by us; 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 and QRCP, believe that the actual estimated fair value of net assets of STP that we received is less than previously expected. We and QRCP 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 and QRCP 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 valued the known assets and liabilities. As additional information becomes available other assets and/or liabilities may be identified and recorded. The fair value of the assets and liabilities we received is as follows (in thousands):


Oil & gas properties	$	1,076
Current liabilities		(326	)
Long-term debt		(719	)

Net assets received	$	31

Recombination

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

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

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

Additionally, in connection with the Merger Agreement, on July 2, 2009, we entered into a Support Agreement with QRCP, 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, QRCP has, subject to certain conditions, agreed to vote the common and subordinated units of us and Quest Midstream that it owns in favor of the Recombination and the holders of approximately 73% of the common units of Quest Midstream have, subject to certain conditions, agreed to vote their common units in favor of the Recombination.

Results of Operations

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

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

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


	Three Months Ended
	September 30,				Increase/
	2009		2008		(Decrease)
Oil and gas sales	$	18,151	$	49,454	$	(31,303	)	(63.3	)%
Oil and gas production costs	$	8,458	$	9,821	$	(1,363	)	(13.9	)%
Transportation expense	$	10,879	$	8,583	$	2,296		26.8	%
Depreciation, depletion and amortization	$	9,076	$	13,196	$	(4,120	)	(31.2	)%
General and administrative expenses	$	5,570	$	734	$	4,836		658.9	%
Gain from derivative financial instruments	$	8,752	$	145,132	$	(136,380	)	(94.0	)%
Interest expense, net	$	3,370	$	4,354	$	(984	)	(22.6	)%

Production. Oil and gas production data for the periods indicated are as follows:


	Three Months Ended
	September 30,				Increase/
	2009		2008		(Decrease)
Production Data:
Natural gas production (Mmcf)		5,317		5,694		(377	)	(6.6	)%
Oil production (Mbbl)		20		19		1		5.3	%
Total production (Mmcfe)		5,437		5,808		(371	)	(6.4	)%
Average daily production (Mmcfe/d)		59.1		63.1		(4.0	)	(6.3	)%
Average Sales Price per Unit:
Natural gas (Mcf)	$	3.18	$	8.30	$	(5.12	)	(61.7	)%
Oil (Bbl)	$	64.21	$	116.89	$	(52.68	)	(45.1	)%
Natural gas equivalent (Mcfe)	$	3.34	$	8.51	$	(5.17	)	(60.8	)%
Average Unit Costs per Mcfe:
Production costs	$	1.56	$	1.69	$	(0.13	)	(7.7	)%
Transportation expense	$	2.00	$	1.48	$	0.52		35.1	%
Depreciation, depletion and amortization	$	1.67	$	2.27	$	(0.60	)	(26.4	)%

Oil and Gas Sales. Oil and gas sales decreased $31.3 million, or 63.3%, to $18.2 million for the three months ended September 30, 2009, from $49.5 million for the three months ended September 30, 2008. This decrease was the result of a decrease in average realized prices and a small decrease in volumes. The decrease in the average realized price accounted for $30.1 million of the decrease. Our average product prices, which exclude hedge settlements, on an equivalent basis (Mcfe) decreased to $3.34 per Mcfe for the three months ended September 30, 2009 from $8.51 per Mcfe for the three months ended September 30, 2008. A decline in volumes of 371 Mmcfe for the quarter further reduced oil and gas sales by $1.2 million for the three months ended September 30, 2009, compared to 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 $0.9 million, or 5.1%, to $19.3 million for the three months ended September 30, 2009, from $18.4 million for the three months ended September 30, 2008.

Oil and gas production costs decreased $1.4 million, or 13.9%, to $8.4 million for the three months ended September 30, 2009, from $9.8 million for 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, including a reduction in field headcount by approximately half while simultaneously reducing overtime hours for the three months ended September 30, 2009 compared to the three months ended

September 30, 2008. In addition, 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 period. Production costs including gross production taxes and ad valorem taxes were $1.56 per Mcfe for the three months ended September 30, 2009 as compared to $1.69 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 $2.3 million, or 26.8%, to $10.9 million for the three months ended September 30, 2009, from $8.6 million for the three months ended September 30, 2008. The increase was primarily due to an increase in the contracted transportation rate. 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.

Depreciation, Depletion and Amortization. We are subject to variances in our depletion rates from period to period due to changes in our proved 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 $4.1 million, or 31.2% , for the three months ended September 30, 2009 to $9.1 million from $13.2 million in 2008. On a per unit basis, we had a decrease of $0.60 per Mcfe to $1.67 per Mcfe for the three months ended September 30, 2009 from $2.27 per Mcfe for 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.

General and Administrative Expenses. General and administrative expenses increased $4.8 million, or 658.9%, to $5.6 million for the three months ended September 30, 2009, from $0.7 million for the three months ended September 30, 2008. The increase is primarily due to increased accounting and audit fees related to our reaudits and restatements as well as increased legal, professional and investment banker fees related to our Recombination activities.

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 $19.6 million realized gain and $10.9 million unrealized loss on our derivative contracts for the three months ended September 30, 2009 compared to a $7.5 million realized loss and $152.7 million unrealized gain 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 $1.0 million, or 22.6% , to $3.4 million for the three months ended September 30, 2009, from $4.4 million for the three months ended September 30, 2008. The decrease in interest expense for the three months ended September 30, 2009 compared to the three months ended September 30, 2008, is due both to lower average outstanding debt levels and to lower interest rates.

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

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


	Nine Months Ended
	September 30,					Increase/
	2009		2008			(Decrease)
Oil and gas sales	$	56,260	$	136,908		$	(80,648	)	(58.9	)%
Oil and gas production costs	$	23,216	$	34,104		$	(10,888	)	(31.9	)%
Transportation expense	$	31,272	$	25,921		$	5,351		20.6	%
Depreciation, depletion and amortization	$	24,766	$	34,750		$	(9,984	)	(28.7	)%
General and administrative expenses	$	13,249	$	5,501		$	7,748		140.8	%
Impairment of oil and gas properties	$	95,169	$	—		$	95,169		*
Gain (loss) from derivative financial instruments	$	31,078	$	(4,482	)	$	35,560		793.4	%
Interest expense, net	$	11,274	$	8,747		$	2,527		28.9	%


*		Not meaningful

Production. Oil and gas production data for the periods indicated are as follows:


	Nine Months Ended
	September 30,				Increase/
	2009		2008		(Decrease)
Production Data:
Natural gas production (Mmcf)		16,107		15,755		352		2.2	%
Oil production (Mbbl)		60		47		13		27.7	%
Total production (Mmcfe)		16,467		16,037		430		2.7	%
Average daily production (Mmcfe/d)		60.3		58.5		1.8		3.1	%
Average Sales Price per Unit:
Natural gas (Mcf)	$	3.30	$	8.36	$	(5.06	)	(60.5	)%
Oil (Bbl)	$	52.27	$	110.40	$	(58.13	)	(52.7	)%
Natural gas equivalent (Mcfe)	$	3.42	$	8.54	$	(5.12	)	(60.0	)%
Average Unit Costs per Mcfe:
Production costs	$	1.41	$	2.13	$	(0.72	)	(33.8	)%
Transportation expense	$	1.90	$	1.62	$	0.28		17.3	%
Depreciation, depletion and amortization	$	1.50	$	2.17	$	(0.67	)	(30.9	)%

Oil and Gas Sales. Oil and gas sales decreased $80.6 million, or 58.9%, to $56.3 million for the nine months ended September 30, 2009, from $136.9 million for the nine months ended September 30, 2008. This decrease was the result of a decrease in average realized prices, partially offset by higher volumes. The decrease in the average realized price accounted for $82.1 million of the decrease. Our average product prices, which exclude hedge settlements, on an equivalent basis (Mcfe) decreased to $3.42 per Mcfe for the nine months ended September 30, 2009 from $8.54 per Mcfe for the nine months ended September 30, 2008. This decrease was offset by slightly higher volumes of 430 Mmcfe, resulting in increased oil and gas sales of $1.5 million for the nine months ended September 30, 2009, compared to the nine months ended September 30, 2008. The increased volumes 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 $5.5 million, or 9.2%, to $54.5 million for the nine months ended September 30, 2009, from $60.0 million for the nine months ended September 30, 2008.

Oil and gas production costs decreased $10.9 million, or 31.9% to $23.2 million for the nine months ended September 30, 2009, from $34.1 million for the nine months ended September 30, 2008. This decrease was primarily due to cost-cutting and well service improvement measures such as a reduction in field headcount by approximately one-third while overtime hours were simultaneously reduced for the nine months ended September 30, 2009 compared to the nine months ended September 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. In addition, 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 period compared to the prior period. Production costs including gross production taxes and ad valorem taxes were $1.41 per Mcfe for the nine months ended September 30, 2009 as compared to $2.13 per Mcfe for the nine months ended September 30, 2008. The decrease in per unit cost was due to the cost-cutting and well service improvement measures discussed above, as well as higher volumes over which to spread fixed costs.

Transportation expense increased $5.4 million, or 20.6%, to $31.3 million for the nine months ended September 30, 2009, from $25.9 million for the nine months ended September 30, 2008. The increase was due to an increase in the contracted transportation rate and increased volumes. Transportation expense was $1.90 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.

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 $10.0 million, or 28.7%, for the nine months ended September 30, 2009 to $24.8 million from $34.8 million for the nine months ended September 30, 2008. On a per unit basis, we had a decrease of $0.67 per Mcfe to $1.50 per Mcfe for the nine months ended September 30, 2009 from $2.17 per Mcfe for 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, offset by decreases in proved reserves due to the effect of lower prices.

General and Administrative Expenses. General and administrative expenses increased $7.7 million, or 140.8%, to $13.2 million for the nine months ended September 30, 2009, from $5.5 million for the nine months ended September 30, 2008. The increase is primarily due increased legal, audit and other professional fees in connection with the restatement and reaudits of our financial statements as well as increased legal, professional and investment banker fees related to our Recombination activities.

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 base for our spot prices for natural gas is Henry Hub and for oil is Cushing, Oklahoma. We had previously recognized a ceiling test impairment of $95.2 million during the first quarter of 2009 while no impairment was necessary for the second quarter of 2009. As of September 30, 2009, the ceiling test computation utilizing spot prices on that day resulted in the carrying costs of our unamortized proved oil and natural gas properties, net of deferred taxes, exceeding the September 30, 2009 present value of future net revenues by approximately $6.9 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. A ceiling test impairment was not required for the nine months ended September 30, 2008 based on price levels at that time.

Gain/(Loss) from Derivative Financial Instruments. Gain from derivative financial instruments increased $35.6 million to a gain of $31.1 million for the nine months ended September 30, 2009, from a loss of $4.5 million for the nine months ended September 30, 2008. We recorded $83.1 million of realized gain and $52.0 million of unrealized loss on our derivative contracts for the nine months ended September 30, 2009 compared to a $17.8 million realized loss and $13.3 million unrealized gain for the nine months ended September 30, 2008. Included in the current year realized gain was $26 million cash received as a result of amending or exiting certain of our above market derivative financial instruments. 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, increased $2.5 million, or 28.9%, to $11.3 million during the nine months ended September 30, 2009, from $8.7 million during the nine months ended September 30, 2008. The increased interest expense for the nine months ended September 30, 2009 relates to higher average debt balances during the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008 partially offset by lower interest rates in the current year period.

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. Prices of oil and natural gas have historically been very volatile and can significantly impact the cash from the sale our oil and natural gas production. Use of derivative financial instruments help mitigate this price volatility. Cash expenses also impact our operating cash flow and consist primarily of oil and natural gas property operating costs, severance and ad valorem taxes, interest on our indebtedness, general and administrative expenses and taxes on income.

Our primary sources of liquidity are cash generated from our operations, amounts, if any, available in the future under the Amended and Restated Credit Agreement, as amended (the “Quest Cherokee Credit Agreement”) and funds from future private and public equity and debt offerings.

At September 30, 2009 we had no availability under the Quest Cherokee Credit Agreement. In July 2009, the borrowing base under the Quest Cherokee Credit Agreement was reduced from $190 million to $160 million, which 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, we amended or exited certain of our above market natural gas price derivative contracts and, in return, received approximately $26 million. At the same time, 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. On June 30, 2009, using these proceeds, we made a principal payment of $15 million on the Quest Cherokee Credit Agreement. On July 8, 2009, we repaid the $14 million borrowing base deficiency. We anticipate that in connection with the redetermination of our borrowing base in November 2009, our borrowing base will be further reduced from its current level of $160 million. In the event of a borrowing base reduction, we expect to be able to make the required payments resulting from the borrowing base deficiency out of our existing funds. The Second Lien Senior Term Loan Agreement, as amended (the “Second Lien Loan Agreement”) originally due and maturing on September 30, 2009, has been extended to November 16, 2009. Management is currently pursuing various options to restructure or refinance our credit agreements. There can be no assurance that such efforts will be successful or that the terms of any new or restructured indebtedness will be favorable to us.

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

Cash flows from operations totaled $57.8 million for the nine months ended September 30, 2009 as compared to cash flows from operations of $48.5 million for the nine months ended September 30, 2009. The increase is attributable primarily to higher realized gains on derivatives partially offset by lower revenues as a result of lower realized prices on oil and gas.

Cash Flows from Investing Activities. Net cash used in investing activities totaled $1.5 million for the nine months ended September 30, 2009 as compared to $148.3 million for the nine months ended September 30, 2008. In 2009, we significantly curbed our acquisition and development activity due to the decline in oil and gas prices as well as liquidity constraints. Cash outflows from investing activities in the nine months ended September 30, 2008 included $71.2 million related to the acquisition of the PetroEdge assets. The following table sets forth our capital expenditures by major categories for the nine months ended September 30, 2009.


	Nine Months Ended
	September 30, 2009
	(in thousands)
Capital expenditures:
Leasehold acquisition	$	1,027
Development		212
Other items		145

Total capital expenditures	$	1,384

Cash Flows from Financing Activities. Net cash used in financing activities totaled $42.0 million for the nine months ended September 30, 2009 as compared to cash provided by financing activities of $109.4 million for the nine months ended September 30, 2008. In 2009, cash used by financing was primarily comprised of $41.8 million of repayment on our revolving facility and term loan discussed under “ Credit Agreements” below.

Working Capital. At September 30, 2009, we had current assets of $60.9 million. Our working capital (current assets minus current liabilities, excluding the short-term derivative assets and liabilities of $19.6 million and $1.4 million, respectively) was $0.1 million at September 30, 2009, compared to a working capital (excluding the short-term derivative assets and liabilities of $43.0 million and $12,000, respectively) deficit of $30.0 million at December 31, 2008. The change is primarily due to our realized gains on derivatives partially including $26 million received from the early exit or amendment of derivatives that were subsequently reset to market prices.

Credit Agreements

A. Quest Cherokee Credit Agreement.

Quest Cherokee, LLC (“Quest Cherokee”) is a party to the “Quest Cherokee Credit Agreement”, with Royal Bank of Canada (“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 $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%.

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

B. Second Lien Loan Agreement.

Quest Energy 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 under the Second Lien Loan Agreement 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 our prior year end on December 31, 2008.

On July 1, 2009, Quest Energy GP, LLC (“Quest Energy GP”) entered into an amendment to the original agreement with its financial advisor, which provided that the monthly advisory fee increased to $200,000 per month with a total of $800,000, representing the aggregate fees for each of April, May, June and July 2009, which amount was paid upon execution of the amendment. Fees through July 2009 have been expensed and properly accrued as of September 30, 2009. The additional financial advisor fees payable if certain transactions occurred were canceled; however, the financial advisor was 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.

In addition, we are a party to a management services agreement with Quest Energy Service, pursuant to which Quest Energy Service, through its affiliates and employees, carries out the directions of our general partner and provides us with legal, accounting, finance, tax, property management, engineering and risk management services. Quest Energy Service may additionally provide us with acquisition services in respect of opportunities for us to acquire long-lived, stable and proved oil and gas reserves.

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 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

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.


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 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 of our general partner, 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, the principal executive officer and principal financial officer of our general partner 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 by 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 (7) 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 our 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 our 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, depreciation, depletion and amortization, impairment of oil and gas properties and cash management described in items (2) to (7) 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 (7) 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)

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.

(6)

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.

(7)

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.

Each of the control deficiencies described in items (1) through (7) above could result in a misstatement of the aforementioned account balances or disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected.

Changes in Internal Control Over Financial Reporting

As discussed above, as of December 31, 2008, we had material weaknesses in our internal control over financial reporting.

The remediation efforts, outlined below, are intended both to address the identified material weaknesses and to enhance our overall financial control environment. In January 2009, Mr. Eddie M. LeBlanc, III was appointed Chief Financial Officer (our principal financial and accounting officer). In May 2009, Mr. David C. 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.

Under the management services agreement between us and Quest Energy Service, LLC (“Quest Energy Service”) all of our financial reporting services are provided by Quest Energy Service. QRCP has advised us that it is currently in the process of remediating the weaknesses in internal control over financial reporting referred to above by designing and implementing new procedures and controls throughout QRCP and its subsidiaries and affiliates for whom it is responsible for providing accounting and finance services, including us, and by strengthening the accounting department through adding new personnel and resources. QRCP has obtained, and has advised us that it will continue to seek, the assistance of the Audit Committee of our general partner in connection with this process of remediation.

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, Quest Energy Service has effected personnel changes in its accounting and financial reporting functions. It has also advised us that it has 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, Quest Energy Service has 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.

During 2009, we have made the following changes to address the previously reported material weaknesses in internal control over financial reporting and disclosure controls and procedures:

We hired additional experienced accounting personnel with specific experience in (1) financial reporting for 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.

We implemented a closing calendar and consolidation process that includes accrual based financial statements being reviewed by qualified personnel in a timely manner.

We review consolidating financial statements with senior management, the audit committee of the board of directors and the full board of directors.

We complete disclosure checklists for both GAAP and SEC required disclosures to ensure disclosures are complete.

We have created a disclosure committee as part of our SEC filing process.

In addition, during the third quarter of 2009, we have:

Communicated internally to employees regarding ethics and the availability of our internal fraud hotline;

Evaluated and prioritized the material weaknesses noted above and developed specific actions necessary in order to remediate them;

Performed a preliminary assessment of our accounting and disclosure policies and procedures and begun the process of updating and revising them; and

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 10 to our 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. As of September 30, 2009, as a result of the Transfers and the restatements of our financial statements, we are involved in litigation outside the ordinary course of our business. Except for those legal proceedings listed in Part I, Item I, Note 10 to our 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. Like other oil and natural gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. Therefore it is extremely difficult to reasonably quantify future environmental related expenditures.


ITEM 1A.		*RISK FACTORS.*

Risks Related to the Recombination

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 QRCP’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.

QRCP’s control over us may preclude us from pursuing alternative transactions that may be more beneficial to our common unitholders than the Recombination.

As the holder of all of our subordinated units, which has a class vote on merger proposals, QRCP effectively has veto power over any alternative transactions that we might consider pursuing, even alternative transactions that could be more beneficial to our common unitholders than the Recombination.

Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to holders of our common units and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

The Recombination involves conflicts of interest between us and our public unitholders, on the one hand, and QEGP and it affiliates, including QRCP, on the other hand. As permitted by Delaware law, our partnership agreement contains certain provisions concerning the resolution of conflicts of interest that reduce the fiduciary standards to which QEGP, the board of directors of QEGP and the conflicts committee of QEGP would otherwise be held under state law and that restrict the remedies available to unitholders for actions taken by QEGP, the board of directors of QEGP or the conflicts committee of QEGP in resolving such conflicts of interest. Specifically, under the our partnership agreement:

	•		any conflict of interest and any resolution thereof shall be permitted and deemed approved by all of our partners, and shall not constitute a breach of our partnership agreement or of any duty stated or implied by law or equity, if the resolution or course of action in respect of conflict of interest is approved by a majority of the members of the conflicts committee acting in good faith (meaning they believed that such approval was in our best interests);

	•		it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and

	•		our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees for any acts or omissions, unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.

The conflicts committee of the board of directors of QEGP has unanimously (i) determined that the Merger Agreement and the QELP merger are advisable, fair to and in the best interests of us and the holders of our common units (other than QEGP and its affiliates), (ii) approved the Merger Agreement and the QELP merger and (iii) recommended approval and adoption of the Merger Agreement and the QELP merger by the holders of our common units (other than QEGP and its affiliates). The members of the conflicts committee, although meeting the independence standards required of directors who serve on an audit committee of a board of directors of a company listed or admitted to trading on the Nasdaq Global Market, were appointed by QRCP, as the sole member of QEGP, and not elected by our unitholders.

Our financial projections may not prove accurate.

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 unitholders and the QRCP stockholders 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 the board of directors of QRCP and the conflicts committee of each of QEGP and QMLP’s general partner, the approval of the transaction by our unitholders, QRCP stockholders and 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 the conflicts committee of each of QEGP and QMLP’s general partner finds reasonably acceptable. In addition, we, QRCP and QMLP can agree not to consummate the Recombination even if our unitholders, QRCP stockholders 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 units 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 our bankruptcy (please read “— 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 units 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;

•

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, QELP, QRCP and QMLP 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 and QMLP will each pay 45% of the combined transaction costs and QRCP will pay 10% of the combined transaction costs, except that we and QRCP 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, QRCP stockholders and our 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, the former chairman, president and chief executive officer of QRCP, QEGP and QMGP, resigned and David E. Grose, the former chief financial officer of QRCP, QEGP and QMGP, was terminated, following the discovery of the misappropriation of $10 million principally from QRCP 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, the former purchasing manager of QRCP, 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, QELP, QRCP 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 a 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.

QELP and QRCP 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 QELP, QRCP 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, QELP’s unit price and QRCP’s stock 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 10 to our consolidated financial statements in this quarterly report and Note 11 to our consolidated financial statements in our 2008 Form 10-K/A.

We 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 us that are not covered by insurance or which exceed the policy limits. We may also be obligated to indemnify certain of the individual defendants in the securities cases, which indemnity obligations may not be covered by insurance. We have received letters from our 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. We received a letter from our directors’ and officers’ liability insurance carrier stating 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. We are reviewing the letter and evaluating our 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. We and PostRock 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 our financial condition and the price of our common units. Furthermore, certain of the 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 QELP 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 QELP 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 the 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. We and our predecessor have incurred significant losses from 2004 through 2008, mainly attributable to operations, impairment of oil and gas properties, unrealized gains and losses from derivative financial instruments, legal restructurings, financings, the current legal and operational structure and the losses attributable to certain unauthorized transfers, repayments and re-transfers of funds to entities controlled by the former chief executive officer of each of QELP, QRCP and QMLP and the associated costs to investigate such transfers. If the Recombination is not consummated and we are unable to restructure our indebtedness 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 units 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 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.

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.

Under the management services agreement between us and Quest Energy Service, LLC, all of our financial reporting services are provided by Quest Energy Service. While certain actions have been taken 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 be taken 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 general partner’s board of directors determined on December 31, 2008 that the audited consolidated financial statements for us or our predecessor 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.

	•		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.

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 agreements. In June 2009, we entered into amendments to our credit agreements that, among other things, deferred until August 15, 2009 the obligation to deliver to RBC certain financial information.

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

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

In July 2009, our borrowing base under our 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 first lien loan agreement. On July 8, 2009, Quest Cherokee repaid the $14 million borrowing base deficiency. We anticipate that in connection with the redetermination of our borrowing base in November 2009, our borrowing base will be further reduced from its current level of $160 million. In the event of a borrowing base reduction, we expect to be able to make the required payments resulting from the borrowing base deficiency out of our existing funds.

If we are required to make these prepayments or pay the full amounts of the indebtedness upon acceleration, we 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 we 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 we are unable to obtain waivers from our lenders or to obtain alternative financing to repay the credit facilities, we may be required to obtain additional waivers or our lender may foreclose on our 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.

During the first half of 2010, we believe we will need to raise a significant amount of equity capital to fund our proposed 2010 drilling program and pay down outstanding indebtedness. 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 common units in an equity offering, our unitholders’ ownership will be diluted and our unit price may decrease due to the additional common units 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 20.8% to 167.1 Bcfe at December 31, 2008 from 211.1 Bcfe at December 31, 2007, and the standardized measure of our proved reserves decreased 51.6% to $156.1 million as of December 31, 2008 from $322.5 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 $245.6 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 $95.2 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 their credit agreements, 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 budget from $155.4 million in 2008 to $9.7 million in 2009. In addition, we plan to drill only seven new wells in 2009, after drilling 328 new wells in 2008. We do 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 we may not be able to maintain our reserves levels and 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.” Our failure to maintain our reserve levels could adversely affect the borrowing base under the Quest Cherokee Credit Agreement.

We face the risks of leverage.

As of September 30, 2009, we had borrowed $160 million under the Quest Cherokee Credit Agreement. 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 unitholders 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.

We are also be required to comply with certain 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.

Under the midstream services agreement we are required to pay fees for gathering, dehydration and treating services and fees for compression services to Quest Midstream for each Mmbtu of gas produced from our wells in the Cherokee Basin. 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. 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 10 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, we sold substantially all of our 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 93% and 83% 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 our 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. Our failure to maintain our reserve levels could adversely affect the borrowing base under the Quest Cherokee Credit Agreement.

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.

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. 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 our acquisition of the PetroEdge assets 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 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 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 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.

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, 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. 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, results of operations and ability to resume and sustain the payment of cash distributions to our unitholders.

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, we 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.

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 270 gross proved undeveloped drilling locations and approximately 1,599 additional gross potential drilling locations in the Cherokee 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 1,599 Cherokee 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.

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. 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 which could adversely affect our ability to resume and continue the payment of distributions.

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. 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.

Recent and future environmental laws and regulations may significantly limit, and increase the cost of, our exploration, production and transportation 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 capital and 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 emissions 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, may allow it to begin regulating emissions of GHGs from stationary and mobile sources 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 capital expenditures and 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.

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.

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.

Please see Item 1A. “Risk Factors—Risks Inherent in an Investment in Our Common Units” and “—Tax Risks to Our Common Unitholders” in our 2008 Form 10-K/A for additional risk factors.


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

None.


ITEM 3.		*DEFAULTS UPON SENIOR SECURITIES.*

None.


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

None.


ITEM 5.		*OTHER INFORMATION.*

None.


ITEM 6.		*EXHIBITS*

*2.1		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).

*10.1		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 Energy Partners, L.P.’s Current Report on Form 8-K filed on October 1, 2009).

*10.2		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 Energy Partners, L.P.'s Current Report on Form 8-K filed on November 2, 2009).

*10.3		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)

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

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

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

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


*		Incorporated by reference.

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

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized this 5th day of November, 2009.


		Quest Energy Partners, L.P.

		By:		Quest Energy GP, LLC, its general partner

		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

Quest Energy Partners, L.P. 10-Q