- Quarterly Report (10-Q)

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Share Name	Share Symbol	Market	Type
Quest Energy Partners, L.P. (MM)	NASDAQ:QELP	NASDAQ	Common Stock

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)


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

For the quarterly period ended September 30, 2008.


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

For the transition period from to .

Commission file number: 001-33787

QUEST ENERGY PARTNERS, L.P.

(Exact name of registrant specified in its charter)


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

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

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

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

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

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


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

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

As of July 24, 2009, the issuer had 12,316,521 common units outstanding.

EXPLANATORY NOTE

This Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 includes our consolidated interim financial statements as of September 30, 2008 and for the three and nine month periods ended September 30, 2008, which have not previously been issued, and our Predecessor’s restated carve out financial statements for the three and nine month periods ended September 30, 2007 which have not previously been restated in any other report, for Quest Energy Partners, L.P. (“Quest Energy” or “QELP”). The consolidated balance sheet as of December 31, 2007 included herein was previously restated in our Annual Report on Form 10-K for the year ended December 31, 2008 filed on June 16, 2009, and amended on July 28, 2009 (the “2008 Form 10-K”). References to “our consolidated financial statements” and “the Predecessor’s consolidated financial statements” when used for any period prior to November 15, 2007, include or mean, respectively, the carve out financial statements of our Predecessor.

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

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

As reported on a Current Report on Form 8-K initially filed on January 2, 2009 and amended on February 6, 2009, on December 31, 2008, the board of directors of Quest Energy GP determined that our audited consolidated financial statements as of December 31, 2007, and for the period from November 15, 2007 to December 31, 2007, our 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, the Predecessor’s audited consolidated financial statements as of and for the years ended December 31, 2005 and 2006, and for the period from January 1, 2007 to November 14, 2007 should no longer be relied upon. The Predecessor’s financial statements represent the carve out financial position, results of operations, cash flows and changes in partners’ capital of the Cherokee Basin operations of QRCP, and reflect the operations of Quest Cherokee, LLC (“Quest Cherokee”) and Quest Cherokee Oilfield Service, LLC (“QCOS”), located in the Cherokee Basin (other than its midstream assets), which QRCP contributed to us at the completion of our initial public offering on November 15, 2007. The investigation and determination that our previously issued financial statements should no longer be relied upon resulted in our inability to timely file this Quarterly Report on Form 10-Q for the quarter ended September 30, 2008.

Restatement and Reaudit — In October 2008, Quest Energy GP’s audit committee engaged a new independent registered public accounting firm to audit our consolidated financial statements for 2008 and, in January 2009, engaged them to reaudit our consolidated financial statements as of December 31, 2007 and for the period from November 15, 2007 to December 31, 2007 and the Predecessor’s consolidated financial statements as of and for the years ended December 31, 2005 and 2006, and for the period from January 1, 2007 to November 14, 2007.

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

Comparison of Previously Reported Net Income (Loss) to Restated Net Income (Loss)

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


	Predecessor
	Three Months Ended			Nine Months Ended
	September 30, 2007			September 30, 2007
Net income (loss) as previously reported	$	1,372		$	(7,552	)
Effect of the Transfers		(500	)		(1,500	)
Reversal of hedge accounting		4,108			(2,286	)
Capitalization of costs in full cost pool		(2,325	)		(7,772	)
Recognition of costs in proper periods		(436	)		(868	)
Depreciation, depletion and amortization		(22	)		(677	)
Other errors		(1,406	)		(2,563	)

Net income (loss) as restated	$	791		$	(23,218	)

Reconciliations from amounts previously included in our interim consolidated financial statements to restated amounts on a financial statement line item basis are presented in Note 11. Restatement in the notes to the accompanying consolidated interim financial statements.

All dollar amounts and other data included herein have been revised to reflect the restated amounts, even where such amounts are not labeled as restated.

TABLE OF CONTENTS
FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2008

TABLE OF CONTENTS


PART I — FINANCIAL INFORMATION
Item 1. Financial Statements			3
Balance Sheets: September 30, 2008 and December 31, 2007			F-1
Statements of Operations: Three Months and Nine Months Ended September 30, 2008 and 2007			F-2
Statements of Cash Flows: Nine Months Ended September 30, 2008 and 2007			F-3
Condensed Notes to Unaudited Consolidated Financial Statements			F-4
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			4
Item 3. Quantitative and Qualitative Disclosures About Market Risk			20
Item 4T. Controls and Procedures			22

PART II — OTHER INFORMATION
Item 1. Legal Proceedings			26
Item 1A. Risk Factors			26
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			26
Item 3. Defaults Upon Senior Securities			26
Item 4. Submission of Matters to a Vote of Security Holders			26
Item 5. Other Information			26
Item 6. Exhibits			26
SIGNATURES			28
EX-31.1
EX-31.2
EX-32.1
EX-32.2

GUIDE TO READING THIS REPORT

As used in this report, unless we indicate otherwise:

•

when we use the terms the “Partnership,” “Successor,” “our,” “we,” “us” and similar terms in a historical context prior to November 15, 2007, we are referring to Predecessor, and when we use such terms in a historical context on or after November 15, 2007, in the present tense or prospectively, we are referring to Quest Energy Partners, L.P. and its subsidiaries;

•

when we use the term “Predecessor,” we are referring to the assets, liabilities and operations of QRCP located in the Cherokee Basin (other than its midstream assets), which QRCP contributed to us at the completion of our initial public offering on November 15, 2007;

•

when we use the terms “Quest Energy GP” or “our general partner,” we are referring to Quest Energy GP, LLC, our general partner;

•

when we use the term “QRCP,” we are referring to Quest Resource Corporation (NASDAQ: QRCP), the owner of our general partner and its subsidiaries (other than us); and

•

when we use the term “Quest Midstream,” or “QMLP,” we are referring to our affiliate Quest Midstream Partners, L.P. and its subsidiaries.

In this report we also use some oil and natural gas industry terms that are defined under the caption “Glossary of Selected Terms” at the end of Items 1 and 2, “Business and Properties” of our 2008 Form 10-K.

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Quest Energy Partners, L.P. (“Quest Energy” or “QELP”) is a Delaware limited partnership. Unless the context clearly requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean Quest Energy Partners, L.P. and its consolidated subsidiaries.

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

The financial statements included herein have been prepared internally, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been omitted. However, in our opinion, all adjustments (which include only normal recurring accruals) necessary to fairly present the financial position and results of operations have been made for the periods presented. The Partnership’s results for the nine months ended September 30, 2008 are not necessarily indicative of the results for the year ended December 31, 2008.

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

QUEST ENERGY PARTNERS, L.P AND SUBSIDIARIES

BALANCE SHEETS
($ in thousands except unit data)


	September 30, 2008		December 31, 2007
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	9,717	$	169
Restricted cash		112		1,205
Accounts receivable — trade, net		5,806		86
Other receivables		513		—
Due from affiliates		6,175		15,624
Other current assets		2,971		3,091
Inventory		11,053		4,956
Current derivative financial instrument assets		16,958		8,008

Total current assets		53,305		33,139
Property and equipment, net		18,211		17,116
Oil and gas properties under full cost method of accounting, net		404,720		294,329
Other assets, net		3,837		3,526
Long-term derivative financial instrument assets		11,956		3,467

Total assets	$	492,029	$	351,577

Current liabilities:
Accounts payable	$	14,005	$	17,754
Revenue payable		773		919
Accrued expenses		2,215		639
Due to affiliates		2,758		1,708
Current portion of notes payable		45,025		666
Current derivative financial instrument liabilities		3,211		8,108

Total current liabilities		67,987		29,794
Non-current liabilities:
Long-term derivative financial instrument liabilities		15,334		6,311
Asset retirement obligations		4,453		1,700
Notes payable		183,149		94,042
Commitments and contingencies
Partners’ equity:
Common unitholders — Issued and outstanding — 12,331,521 at September 30, 2008 and December 31, 2007 (9,100,000 — public; 3,231,521 — affiliate);		163,265		162,610
Subordinated unitholder — affiliate; 8,857,981 units issued and outstanding at September 30, 2008 and December 31, 2007		55,165		54,465
General Partner — affiliate; 431,827 units issued and outstanding at September 30, 2008 and December 31, 2007		2,676		2,655

Total partners’ equity		221,106		219,730

Total liabilities and partners’ equity	$	492,029	$	351,577

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

F-1

QUEST ENERGY PARTNERS, L.P AND SUBSIDIARIES

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


	Successor			Predecessor			Successor			Predecessor
	Three months ended						Nine months ended
	September 30,						September 30,
	2008			2007			2008			2007
	Consolidated			Carve Out			Consolidated			Carve Out
				(Restated)						(Restated)
Revenue:
Oil and gas sales	$	49,454		$	23,852		$	136,908		$	76,396

Total revenues		49,454			23,852			136,908			76,396
Costs and expenses:
Oil and gas production		9,821			8,976			34,104			27,991
Transportation expense		8,583			7,469			25,921			20,639
General and administrative expenses		734			3,318			5,501			10,025
Depreciation, depletion and amortization		13,196			8,667			34,750			24,618
Misappropriation of funds		—			500			—			1,500

Total costs and expenses		32,334			28,930			100,276			84,773

Operating income (loss)		17,120			(5,078	)		36,632			(8,377	)
Other income (expense):
Gain (loss) from derivative financial instruments		145,132			13,388			(4,482	)		8,232
Other income (expense)		40			44			154			(185	)
Interest expense		(4,367	)		(7,665	)		(8,867	)		(23,270	)
Interest income		13			102			120			382

Total other income (expense)		140,818			5,869			(13,075	)		(14,841	)

Net income (loss)	$	157,938		$	791		$	23,557		$	(23,218	)

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

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

Net income (loss) per limited partner unit: (basic and diluted)	$	7.31					$	1.09

Weighted average limited partner units outstanding:
Common units (basic and diluted)		12,309,021						12,308,282

Subordinated units (basic and diluted)		8,857,981						8,857,981

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

F-2

QUEST ENERGY PARTNERS, L.P AND SUBSIDIARIES

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


	Successor			Predecessor
	Nine months ended September 30,
	2008			2007
	Consolidated			Carve Out
				(Restated)
Cash flows from operating activities:
Net income (loss)	$	23,557		$	(23,218	)
Adjustments to reconcile net income (loss) to cash provided by (used in) operations:
Depreciation, depletion and amortization		34,750			24,618
Unit-based compensation		21			—
Change in fair value of derivative financial instruments		(13,312	)		(3,069	)
Contributions for consideration for compensation to employees		—			4,286
Amortization of deferred loan costs		847			1,416
Bad debt expense		97			22
Change in assets and liabilities:
Accounts receivable		(5,818	)		(214	)
Other receivables		(513	)		(1,466	)
Other current assets		120			(795	)
Other assets		13,696			(378	)
Due from affiliates		734			363
Accounts payable		(4,266	)		13,591
Revenue payable		(146	)		1,486
Accrued expenses		(1,222	)		1,382
Other long-term liabilities		(33	)		119
Other		(1	)		43

Net cash provided by operating activities		48,511			18,186
Cash flows from investing activities:
Restricted cash		1,093			(55	)
Acquisition of business — PetroEdge		(71,213	)		—
Equipment, development and leasehold		(78,214	)		(72,531	)

Net cash used in investing activities		(148,334	)		(72,586	)
Cash flows from financing activities:
Proceeds from bank borrowings		45,000			—
Repayments of note borrowings		(534	)		(393	)
Proceeds from revolver note		89,000			25,000
Contributions(distributions)		636			25,923
Distributions to unitholders		(22,573	)		—
Syndication costs		(265	)		—
Refinancing costs		(1,893	)		(1,687	)

Net cash provided by financing activities		109,371			48,843

Net increase (decrease) in cash and cash equivalents		9,548			(5,557	)
Cash and cash equivalents, beginning of period		169			13,334

Cash and cash equivalents, end of period	$	9,717		$	7,777

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

F-3

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
SEPTEMBER 30, 2008
(Unaudited)

1. Basis of Presentation

We were formed in July 2007 by Quest Resource Corporation (“QRCP”) to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. Quest Energy GP, LLC (“Quest Energy GP”) is our general partner and owns all of the general partner interests. Our principal operations and producing properties are located in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma (the “Cherokee Basin Operations”) and the Appalachian Basin in West Virginia, Pennsylvania and New York. Our Appalachian Basin operations are primarily focused on the development of the Marcellus Shale through Quest Eastern Resource LLC (“Quest Eastern”). Our Cherokee Basin Operations are currently focused on developing coal bed methane, or CBM, gas production.

The carve out financial statements for periods prior to November 15, 2007 and related notes thereto represent the carve out financial position, results of operations, cash flows and changes in partners’ capital of the Cherokee Basin Operations of QRCP and reflect the operations of Quest Cherokee, LLC (“Quest Cherokee”) and Quest Cherokee Oilfield Service, LLC (“QCOS”) formerly owned by QRCP (the “Predecessor”). The carve out financial statements have been prepared in accordance with Regulation S-X, Article 3 “General instructions as to financial statements” and Staff Accounting Bulletin (“SAB”) Topic 1-B “Allocations of Expenses and Related Disclosure in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity.” Certain expenses incurred by QRCP are only indirectly attributable to its ownership of the Cherokee Basin Operations as QRCP owns interests in midstream assets and other oil and gas properties. As a result, certain assumptions and estimates were made in order to allocate a reasonable share of such expenses to the Predecessor, so that the carve out financial statements reflect substantially all the costs of doing business.

References to “our consolidated financial statements” and “the Predecessor’s consolidated financial statements” when used for any period prior to November 15, 2007 include or mean, respectively, the carve out financial statements of our Predecessor.

Our unaudited consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain information and disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) have been condensed or omitted. We believe that the presentations and disclosures herein are adequate to make the information not misleading. The unaudited consolidated financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2008 that was filed on June 16, 2009 and amended on July 28, 2009 (the “2008 Form 10-K”).

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

Misappropriation, Reaudit and Restatement

Investigation — On August 22, 2008, in connection with an inquiry from the Oklahoma Department of Securities, the boards of directors of QRCP, Quest Energy GP, and Quest Midstream GP, LLC (“Quest Midstream GP”), the general partner of Quest Midstream Partners, L.P. (“QMLP” or “Quest Midstream”), held a joint working session to

F-4

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(Continued)

address certain unauthorized transfers, repayments and re-transfers of funds (the “Transfers”) to entities controlled by their former chief executive officer, Mr. Jerry D. Cash. These transfers totaled approximately $10 million between 2005 and 2008, of which $9.5 million related to us.

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

Reaudit and Restatement — As reported on a Current Report on Form 8-K initially filed on January 2, 2009 and amended on February 6, 2009, on December 31, 2008, the board of directors of our general partner determined that our audited consolidated financial statements as of December 31, 2007, and for the period from November 15, 2007 to December 31, 2007, our 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, the Predecessor’s audited consolidated financial statements as of and for the years ended December 31, 2005 and 2006, and for the period from January 1, 2007 to November 14, 2007 should no longer be relied upon.

In October 2008, Quest Energy GP’s audit committee engaged a new independent registered public accounting firm to audit our consolidated financial statements for 2008 and, in January 2009, engaged them to reaudit our consolidated financial statements as of December 31, 2007 and for the period from November 15, 2007 to December 31, 2007 and our Predecessor’s consolidated financial statements as of and for the years ended December 31, 2005 and 2006 and for the period from January 1, 2007 to November 14, 2007.

These consolidated financial statements include our interim financial statements as of September 30, 2008 and for the three and nine month periods ended September 30, 2008 and 2007. The consolidated balance sheet as of December 31, 2007 was restated in our 2008 Form 10-K.

Going Concern

The accompanying consolidated financial statements have been prepared assuming that 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, 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 the Transfers.

While we were in compliance with the covenants in our credit agreements as of December 31, 2008 we do not expect to be in compliance for all of 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. The Quest Cherokee Credit Agreement (as defined below) 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

F-5

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(Continued)

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”). The Borrowing Base Deficiency was repaid on July 8, 2009.

Under the terms of our Second Lien Loan Agreement (as defined below) we are required to make quarterly payments of $3.8 million. We have made all required payments through June 30, 2009, and the next payment is due August 15, 2009. The balance remaining after the August 15, 2009 payment is $29.8 million and is due on September 30, 2009. Due to the principal payments made under our Quest Cherokee Credit Agreement in connection with the Borrowing Base Deficiency, no assurance can be given that we will be able to repay such amount in accordance with the terms of the agreement. Failure to make the 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 of our credit agreements, resulting in payment acceleration of both loans.

QRCP has pledged its ownership in our general partner to secure its term loan credit agreement and is almost exclusively dependent upon distributions from its interest in Quest Midstream and the Partnership for revenue and cash flow. QRCP does not expect to receive any distributions from Quest Midstream or the Partnership in 2009. 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. 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 or restructuring of our credit agreements.

We are currently discussing various options with our lenders, however, there can be no assurance that we will be successful in these discussions.

On July 2, 2009, QELP, QRCP, QMLP and certain other parties thereto entered into an Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which the three companies would recombine. The recombination would be effected by forming a new, yet to be named, publicly-traded corporation (“New Quest”) that, through a series of mergers and entity conversions, would wholly-own all three entities (the “Recombination”). The Merger Agreement follows the execution of a non-binding letter of intent by the three Quest entities that was publicly announced on June 3, 2009.

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

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

Recent Accounting Pronouncements

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

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

F-6

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(Continued)

derivative assets and liabilities include amounts attributable to the fair value of the right to reclaim collateral assets held by counterparties or the obligation to return cash collateral received from counterparties. We did not elect to adopt FSP FIN 39-1.

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

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

In March 2008, the FASB issued EITF Issue No. 07-4, Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships , which requires that master limited partnerships use the two-class method of allocating earnings to calculate earnings per unit. EITF Issue No. 07-4 is effective for fiscal years and interim periods beginning after December 15, 2008. We are evaluating the effect this pronouncement will have on our earnings per unit.

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for derivatives, but will require enhanced disclosures about derivative strategies and accounting practices. SFAS 161 is effective for fiscal years beginning after November 15, 2008, and we will comply with any necessary disclosure requirements beginning with the interim financial statements for the three months ended March 31, 2009.

On December 31, 2008, the SEC issued Release No. 33-8995, Modernization of Oil and Gas Reporting , which revises disclosure requirements for oil and gas companies. In addition to changing the definition and disclosure requirements for oil and gas reserves, the new rules change the requirements for determining oil and gas reserve quantities. These rules permit the use of new technologies to determine proved reserves under certain criteria and allow companies to disclose their probable and possible reserves. The new rules also require companies to report the independence and qualifications of their reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit. The new rules also require that oil and gas reserves be reported and the full cost ceiling limitation be calculated using a twelve-month average price rather than period-end prices. The use of a twelve-month average price may have had an effect on our 2008 depletion rates for our oil and gas properties and the amount of 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 assessing the impact the rules will have on our consolidated financial statements.

2. Acquisitions

PetroEdge — On July 11, 2008, QELP acquired interests in producing properties in Appalachia from QRCP. 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. The assets acquired were approximately 78,000 net acres of oil and natural gas producing properties in the Appalachian Basin with estimated net proved reserves of 99.6 Bcfe as of May 1, 2008 and net production of approximately 3.3 million cubic feet equivalent per day (“Mmcfe/d”).

At closing, QRCP sold the producing well bores to our subsidiary, 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 well bores) 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 First Lien Credit Agreement and the proceeds of a $45 million, six-month term loan. See Note 3. Long-Term Debt.

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


Proved oil and gas properties	$	73,406
Asset retirement obligations		(2,193	)

Purchase price	$	71,213

Pro Forma Summary Data related to acquisitions (unaudited)

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

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	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2008		2007			2008		2007
Pro forma revenue	$	49,454	$	26,889		$	143,458	$	85,507
Pro forma net income (loss)	$	157,938	$	(1,598	)	$	19,020	$	(30,385	)
Pro forma net income (loss) per limited partner unit — basic and diluted	$	7.31				$	0.88

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

The pro forma information is a result of combining our income statement with the pre-acquisition results of PetroEdge adjusted for 1) recording pro forma interest expense on debt incurred to acquire the PetroEdge assets; and 2) depreciation, depletion and amortization expense calculated based on the adjusted basis of the properties acquired using the purchase method of accounting.

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

3. Long-Term Debt

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


	Successor
	September 30		December 31
	2008		2007
Borrowings under bank senior credit facilities
First Lien Credit Agreement	$	183,000	$	94,000
Second Lien Loan Agreement		45,000		—
Notes payable to banks and finance companies, secured by equipment and vehicles, due in installments through October 2013 with interest ranging from 1.9% to 8.9% per annum		174		708

Total debt		228,174		94,708
Less current maturities included in current liabilities		45,025		666

Total long-term debt	$	183,149	$	94,042

Credit Facilities

Quest Cherokee Credit Agreement .

On November 15, 2007, we entered into an Amended and Restated Credit Agreement (the “Original Cherokee Credit Agreement”) in connection with the closing of our initial public offering. Thereafter, we entered into the following amendments to the Original Cherokee Credit Agreement (collectively, with all amendments, the “Quest Cherokee Credit Agreement”):

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

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

	•		On June 18, 2009, we entered into a Third Amendment to Amended and Restated Credit Agreement that, among other things, permits Quest Cherokee’s obligations under oil and gas derivative contracts with BP Corporation North America, Inc. (“BP”) or any of its affiliates to be secured by the liens under the credit agreement on a pari passu basis with the obligations under the credit agreement.

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

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

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

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

Interest Rate . Until the Second Lien Loan Agreement (as defined below) is paid in full, interest will accrue at either LIBOR plus 4.0% or the base rate plus 3.0%. After the Second Lien Loan Agreement is paid in full, interest will accrue at either LIBOR plus a margin ranging from 2.75% to 3.375% (depending on the utilization percentage) or the base rate plus a margin ranging from 1.75% to 2.375% (depending on the utilization

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percentage). The base rate varies daily and is generally the higher of the federal funds rate plus 0.50%, RBC’s prime rate or LIBOR plus 1.25%.

Second Lien Loan Agreement .

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

•

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

•

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

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

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

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

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

Further, so long as any amounts remain outstanding under the Second Lien Loan Agreement, we and Quest Cherokee must be in compliance with a financial covenant that prohibits each of Quest Cherokee, Quest Energy or any of our respective subsidiaries from permitting Available Liquidity (as defined in the Quest Cherokee

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Agreements) to be less than $14 million at March 31, 2009 and to be less than $20 million at June 30, 2009.

General Provisions Applicable to Quest Cherokee Agreements.

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

Guarantors and Security Interest . The Quest Cherokee Credit Agreement is secured by a first priority lien on substantially all of our assets, including those of Quest Cherokee and QCOS. The Second Lien Loan Agreement is secured by a second priority lien on substantially all of our assets and those of Quest Cherokee and QCOS.

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

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

The Quest Cherokee Agreements’ financial covenants prohibit Quest Cherokee, us and any of our subsidiaries from:

•

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

•

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

•

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

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consolidated funded debt) at any fiscal quarter-end (calculated based on the most recently delivered compliance certificate) to be less than 1.5 to 1.0.

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

Consolidated EBITDA is defined in the Quest Cherokee Agreements to mean for us and our subsidiaries on a consolidated basis, an amount equal to the sum of (i) consolidated net income, (ii) consolidated interest charges, (iii) the amount of taxes, based on or measured by income, used or included in the determination of such consolidated net income, (iv) the amount of depreciation, depletion and amortization expense deducted in determining such consolidated net income, (v) acquisition costs required to be expensed under FAS 141(R), (vi) fees and expenses of the internal investigation relating to the Misappropriation Transaction (as defined in the First Amendment to Second Lien Loan Agreement) and the related restructuring (which are capped at $1,500,000 for purposes of this definition), and (vii) other non-cash charges and expenses, including, without limitation, non-cash charges and expenses relating to swap contracts or resulting from accounting convention changes, of us and our subsidiaries on a consolidated basis, all determined in accordance with GAAP.

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

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

We were in compliance with all of our covenants as of September 30, 2008.

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

4. Derivative Financial Instruments

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

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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.

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

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


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

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

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


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

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


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

5. Fair Value Measurements

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

Effective January 1, 2008, we adopted SFAS No. 157, Fair Value Measurements (“SFAS 157”), for financial assets and liabilities measured on a recurring basis. SFAS 157 defines fair value, establishes a framework for measuring fair value and requires certain disclosures about fair value measurements for assets and liabilities measured on a recurring basis. In February 2008, the FASB issued FSP 157-2, which delayed the effective date of SFAS 157 by one year for non-financial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). We have elected to utilize this deferral and have only partially applied SFAS 157 (to financial assets and liabilities measured at fair value on a recurring basis, as described above). Accordingly, we will apply SFAS 157 to our nonfinancial assets and liabilities for which we disclose or recognize at fair value on a nonrecurring basis, such as asset retirement obligations and other assets and liabilities in the first quarter of 2009. Fair value is the exit price that we would receive to sell an asset or pay to transfer a liability in an orderly transaction between market participants at the measurement date.

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

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

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

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

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

The following table sets forth, by level within the fair value hierarchy, our assets and liabilities that were measured at fair value on a recurring basis as of September 30, 2008 (in thousands):


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

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


*		Amounts represent the effect of legally enforceable master netting agreements between 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 “normal purchases, normal sales”. We classify all of these derivative instruments as “Derivative financial instrument assets” or “Derivative financial instrument liabilities” in our consolidated balance sheets.

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

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

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


	Nine Months
	Ended
	September 30,
	2008
Balance at beginning of period	$	3,444
Realized and unrealized gains included in earnings		5,677
Purchases, sales, issuances, and settlements		(855	)
Transfers into and out of Level 3		—

Balance as of September 30, 2008	$	8,266

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6. Asset Retirement Obligations

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


Asset retirement obligations at beginning of period	$	1,700
Liabilities incurred		93
Liabilities settled		(18	)
Acquisition of PetroEdge		2,193
Accretion		195
Revisions in estimated cash flows		290

Asset retirement obligations at end of period	$	4,453

7. Partners’ Equity

Issuance of Units

Effective November 15, 2007, we completed our initial public offering of 9.1 million common units at a price of $18.00 per unit. Total proceeds from the sale of the common units in the initial public offering were $163.8 million, before underwriting discounts and offering costs of approximately $10.6 million and $2.1 million, respectively. At the closing of the initial public offering, QRCP transferred its ownership interest in Quest Cherokee (which owned all of the Predecessor’s Cherokee Basin oil and gas leases) and QCOS (which owned all of the Cherokee Basin field equipment and vehicles) in exchange for 3,201,521 common units and 8,857,981 subordinated units and a 2% general partner interest.

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During nine months ended September 30, 2008, we declared and paid distributions as follows (in thousands, except per unit amounts):


	2008
	$ per Unit		$ Total
General Partner:
First Quarter	$	0.2043	$	88
Second Quarter	$	0.4100	$	177
Third Quarter	$	0.4300	$	186
Common Units:
First Quarter	$	0.2043	$	2,518
Second Quarter	$	0.4100	$	5,055
Third Quarter	$	0.4300	$	5,302
Subordinated Units:
First Quarter	$	0.2043	$	1,809
Second Quarter	$	0.4100	$	3,631
Third Quarter	$	0.4300	$	3,808

The board of directors of our general partner suspended distributions on our subordinated units for the third quarter of 2008 and on all units starting with the distribution for the fourth quarter of 2008. Factors significantly impacting the determination that there was no available cash for distribution include the following:

	•		the decline in our cash flows from operations due to declines in oil and natural gas prices during the last half of 2008,

	•		the costs of the investigation and associated remedial actions, including the reaudit and restatement of our financial statements,

	•		concerns about a potential borrowing base redetermination in the second quarter of 2009,

	•		the need to conserve cash to properly conduct operations and maintain strategic options, and

	•		the need to repay or refinance our term loan by September 30, 2009.

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.

If distributions are ever resumed, within 45 days after the end of each quarter, we will distribute all of our available cash (as defined in the partnership agreement) to Quest Energy GP and unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter less the amount of cash reserves established by Quest Energy GP to provide for the proper conduct of our business, to comply with applicable law, any of our debt instruments, or other agreements or to provide funds for distributions to unitholders and to Quest Energy GP for any one or more of the next four quarters; plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of

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the quarter. Working capital borrowings are generally borrowings that are made under the credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.

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 restricted common units were awarded under our long-term incentive plan, of which, 7,500 vested during the nine months ended September 30, 2008 and the remaining 22,500 vest one-third on each of November 7, 2008, 2009 and 2010. As of September 30, 2008, there were approximately 2.1 million units available for future awards. Unit-based compensation expense was $0.1 million for the nine months ended September 30, 2008.

8. Net Income Per Limited Partner Unit

Subject to applicability of Emerging Issues Task Force Issue No. 03-06 (“EITF 03-06”), Participating Securities and the Two-Class Method under Financial Accounting Standards Board (“FASB”) Statement No. 128, as discussed below, 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.

EITF 03-06 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 EITF 03-06, 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, 2008. 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			Nine Months
	Ended			Ended
	September 30,			September 30,
	2008			2008
Net Income	$	157,938		$	23,557
Less: General partner 2.0% ownership		(3,159	)		(471	)

Net income available to limited and subordinated partners	$	154,779		$	23,086

Basic and diluted weighted average number of units:
Common units		12,309,021			12,308,282
Subordinated units		8,857,981			8,857,981
Basic and diluted net income per limited partner unit	$	7.31		$	1.09

9. Commitments and Contingencies

Litigation

We are subject, from time to time, to certain legal proceedings and claims in the ordinary course of conducting our business. We record a liability related to our legal proceedings and claims when we have determined that it is probable that we will be obligated to pay and the related amount can be reasonably estimated.

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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 against us, Quest Energy GP and QRCP and certain of our current and former officers and directors. The complaints were filed by certain unitholders on behalf of themselves and other unitholders who purchased our common units between November 7, 2007 and August 25, 2008 and by certain stockholders on behalf of themselves and other stockholders who purchased QRCP’s common stock between May 2, 2005 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 our former chief executive officer, Jerry D. Cash. The complaints also allege that, as a result of these actions, our unit price and the stock price of QRCP was artificially inflated during the class period. On December 29, 2008 the court consolidated these complaints as Michael Friedman, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David E. Grose , Case No. 08-cv-936-M, in the Western District of Oklahoma. Various individual plaintiffs have filed multiple rounds of motions seeking appointment as lead plaintiff, however the court has not yet ruled on these motions and appointed a lead plaintiff. Once a lead plaintiff is appointed, the lead plaintiff must file a consolidated amended complaint within 60 days after being appointed. No further activity is expected in the purported class action until a lead plaintiff is appointed and an amended consolidated complaint is filed. We, QRCP and Quest Energy GP intend to defend vigorously against plaintiffs’ claims.

Royalty Owner Class Action

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

Quest Cherokee was named as a defendant in a class action lawsuit filed by several royalty owners in the U.S. District Court for the District of Kansas. The case was filed by the named plaintiffs on behalf of a putative class consisting of all Quest Cherokee’s royalty and overriding royalty owners in the Kansas portion of the Cherokee Basin. Plaintiffs contend that Quest Cherokee failed to properly make royalty payments to them and the putative class by, among other things, paying royalties based on reduced volumes instead of volumes measured at the wellheads, by allocating expenses in excess of the actual costs of the services represented, by allocating production costs to the royalty owners, by improperly allocating marketing costs to the royalty owners, and by making the royalty payments after the statutorily proscribed time for doing so without providing the required interest. Quest Cherokee has answered the complaint and denied plaintiffs’ claims. Discovery in that case is ongoing. Quest Cherokee intends to defend vigorously against these claims.

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Personal Injury Litigation

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

QCOS was named in this lawsuit filed by plaintiffs Segundo Francisco Trigoso and Dana Jara De Trigoso. Plaintiffs allege that Segundo Francisco Trigoso was seriously injured while working for QCOS on September 29, 2006 and that the conduct of QCOS was substantially certain to cause injury to Segundo Francisco Trigoso. Plaintiffs seek unspecified damages for physical injuries, emotional injuries, loss of consortium and pain and suffering. Plaintiffs also seek punitive damages. Various motions for summary judgment have been filed and denied by the court. It is expected that the court will set this matter for trial in Fall 2009. QCOS intends to defend vigorously against plaintiffs’ claims.

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

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

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

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

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

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

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

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

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

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

Litigation Related to Oil and Gas Leases

Quest Cherokee was named as a defendant or counterclaim defendant in several lawsuits in which the plaintiff claims that oil and gas leases owned and operated by Quest Cherokee have either expired by their terms or, for various reasons, have been forfeited by Quest Cherokee. Those lawsuits were originally filed in the district courts of Labette, Montgomery, Wilson, and Neosho Counties, Kansas. Quest Cherokee has drilled wells on some of the oil and gas leases in issue and some of those oil and gas leases do not have a well located thereon but have been unitized with other oil and gas leases upon which a well has been drilled. As of March 1, 2009, the total amount of acreage covered by the leases at issue in these lawsuits was approximately 4,808 acres. Quest Cherokee intends to vigorously defend against those claims. Following is a list of those cases:

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

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

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

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

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

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

Richard L. Bradford, et al. v. Quest Cherokee, LLC, Case No. 2008-CV-67, in the District Court of Wilson County, Kansas, filed September 18, 2008 (Quest Cherokee has resolved these claims as part of a settlement.)

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

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

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

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

Quest Cherokee and Bluestem were named as defendants in a lawsuit filed by Central Natural Resources, Inc. (“Central Natural Resources”) on September 1, 2004 in the District Court of Labette County, Kansas. Central Natural Resources owns the coal underlying numerous tracts of land in Labette County, Kansas. Quest Cherokee has obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying some of that land and has drilled wells that produce coal bed methane gas on that land. Bluestem purchases and gathers the gas produced by Quest Cherokee. Plaintiff alleges that it is entitled to the coal bed methane gas produced and revenues from these leases and that Quest Cherokee is a trespasser and has damaged its coal through its drilling and production operations. Plaintiff is seeking quiet title and an equitable accounting for the revenues from the coal bed methane gas produced. Plaintiff has alleged that Bluestem converted the gas and seeks an accounting for all gas purchased by Bluestem from the wells in issue. Quest Cherokee contends it has valid leases with the owners of the coal bed methane gas rights. The issue is whether the coal bed methane gas is owned by the owner of the coal rights

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or by the owners of the gas rights. If Quest Cherokee prevails on that issue, then the Plaintiff’s claims against Bluestem fail. All issues relating to ownership of the coal bed methane gas and damages have been bifurcated. Cross motions for summary judgment on the ownership of the coal bed methane gas were filed by Quest Cherokee and the plaintiff, with summary judgment being awarded in Quest Cherokee’s favor. Plaintiff appealed the summary judgment and the Kansas Supreme Court has issued an opinion affirming the District Court’s decision and has remanded the case to the District Court for further proceedings consistent with that decision. Quest Cherokee and Bluestem intend to defend vigorously against these claims.

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

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

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

Quest Cherokee was named as a defendant in a lawsuit filed by Edward E. Birk, et ux., and Brian L. Birk, et ux., on April 23, 2009. In that case, the plaintiffs claim that they are entitled to an overriding royalty interest (1/16th in some leases, and 1/32nd in some leases) in 14 oil and gas leases owned and operated by Quest Cherokee. Plaintiffs contend that Quest Cherokee has produced oil and/or gas from wells located on or unitized with those leases, and that Quest has failed to pay plaintiffs their overriding royalty interest in that production. Quest’s answer date is June 15, 2009. We are investigating the factual and legal basis for these claims and intend to defend against them vigorously based upon the results of the investigation.

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

Quest Cherokee, et al. were named as defendants in this action where plaintiffs seek a ruling invalidating certain oil and gas leases. Quest Cherokee has not answered and no discovery has taken place. Quest Cherokee is investigating whether it is a proper party to this lawsuit and intends to vigorously defend against this claim.

Other

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

Quest Cherokee was named as a defendant in two lawsuits filed by Well Refined Drilling Company in the District Court of Neosho County, Kansas (Case No. 2007 CV 91) and in the District Court of Wilson County, Kansas (Case No. 2007 CV 46). In both cases, plaintiff contends that Quest Cherokee owes certain sums for services provided by the plaintiff in connection with drilling wells for Quest Cherokee. Plaintiff has also filed mechanics liens against the oil and gas leases on which those wells are located and also seeks foreclosure of those liens. Quest Cherokee has answered those petitions and has denied plaintiff’s claims. Discovery in those cases is ongoing. Quest Cherokee intends to defend vigorously against these claims.

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.

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QRCP, et al. were named in the above-referenced lawsuit. The lawsuit was served on May 22, 2009. Defendants have not answered and no discovery has taken place. Plaintiffs allege that defendants have wrongfully deducted costs from the royalties of plaintiffs and have engaged in self-dealing contracts and agreements resulting in a less than market price for production. Plaintiffs seek unspecified actual and punitive damages. Defendants intend to defend vigorously against this claim.

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

Quest Cherokee was named in this lawsuit by Barbara Cox. Plaintiff is a landowner in Hobbs, New Mexico and owns the property where the Quest State 9-4 Well was drilled and plugged. Plaintiff alleges that Quest Cherokee violated the New Mexico Surface Owner Protection Act and has committed a trespass and nuisance in the drilling and maintenance of the well. Quest Cherokee denies the allegations of plaintiff. Plaintiff has not articulated any firm damage numbers. Quest Cherokee intends to defend vigorously against plaintiff’s claims.

Environmental Matters — As of September 30, 2008, there were no known environmental or regulatory matters related to our operations which are reasonably expected to result in a material liability to us. Like other oil and gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. Therefore it is extremely difficult to reasonably quantify future environmental related expenditures.

10. Related Party Transactions

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

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

11. Restatement

As reported on a Current Report on Form 8-K initially filed on January 2, 2009 and amended on February 6, 2009, on December 31, 2008, the board of directors of Quest Energy GP determined that our audited consolidated financial statements as of December 31, 2007, and for the period from November 15, 2007 to December 31, 2007, our 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, the Predecessor’s audited consolidated financial statements as of and for the years ended December 31, 2005 and 2006, and for the period from January 1, 2007 to November 14, 2007 should no longer be relied upon as the result of the discovery of the Transfers to entities controlled by Quest Energy GP’s former chief executive officer, Mr. Jerry D. Cash. Management identified other errors in these financial statements, as described below, and the board of directors concluded that we had, and as of December 31, 2008 continued to have, material weaknesses in our internal control over financial reporting.

The Form 10-Q for the quarterly period ended September 30, 2008, to which these consolidated financial statements form a part, includes our Predecessor’s restated carve out financials for the three and nine month periods ended September 30, 2007.

Although the items listed below comprise the most significant errors (by dollar amount), numerous other errors were identified and restatement adjustments made. The tables below present previously reported net income (loss), major restatement adjustments and restated net income (loss) for the periods indicated (in thousands):

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	Predecessor
	Three Months Ended			Nine Months Ended
	September 30, 2007			September 30, 2007
Net income (loss) as previously reported	$	1,372		$	(7,552	)
A — Effects of the transfers		(500	)		(1,500	)
B — Reversal of hedge accounting		4,108			(2,286	)
C — Capitalization of costs in full cost pool		(2,325	)		(7,772	)
D — Recognition of costs in proper periods		(436	)		(868	)
E — Depreciation, depletion and amortization		(22	)		(677	)
F — Other errors		(1,406	)		(2,563	)

Net income (loss) as restated	$	791		$	(23,218	)

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

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

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

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

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

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

(F) We identified other errors during the reaudit and restatement process where the impact on net income was not deemed significant enough to warrant separate disclosure of individual errors.

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

F-26

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(Continued)

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


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

Total revenues		28,489			(4,637	)		23,852
Costs and expenses:
Oil and gas production		7,280			1,696			8,976
Transportation expense		7,469			—			7,469
General and administrative expenses		2,415			903			3,318
Depreciation, depletion and amortization		7,978			689			8,667
Misappropriation of funds		—			500			500

Total costs and expenses		25,142			3,788			28,930

Operating income (loss)		3,347			(8,425	)		(5,078	)
Other income (expense):
Gain from derivative financial instruments		5,539			7,849			13,388
Other income (expense)		49			(5	)		44
Interest expense		(7,665	)		—			(7,665	)
Interest income		102			—			102

Total other income (expense)		(1,975	)		7,844			5,869

Net income (loss)	$	1,372		$	(581	)	$	791

F-27

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(Continued)

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


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

Total revenues		81,873			(5,477	)		76,396
Costs and expenses:
Oil and gas production		22,247			5,744			27,991
Transportation expense		20,639			—			20,639
General and administrative expenses		8,261			1,764			10,025
Depreciation, depletion and amortization		22,041			2,577			24,618
Misappropriation of funds		—			1,500			1,500

Total costs and expenses		73,188			11,585			84,773

Operating income (loss)		8,685			(17,062	)		(8,377	)
Other income (expense):
Gain from derivative financial instruments		5,354			2,878			8,232
Other expense		(148	)		(37	)		(185	)
Interest expense		(21,825	)		(1,445	)		(23,270	)
Interest income		382			—			382

Total other income (expense)		(16,237	)		1,396			(14,841	)

Net loss	$	(7,552	)	$	(15,666	)	$	(23,218	)

F-28

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(Continued)

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


	Predecessor (carve out)
	Nine Months Ended September 30, 2007
	As Previously			Restatement			As
	Reported			Adjustments			Restated
Cash flows from operating activities:
Net loss	$	(7,552	)	$	(15,666	)	$	(23,218	)
Adjustments to reconcile net income (loss) to cash provided by operations:
Depreciation, depletion and amortization		23,796			822			24,618
Change in fair value of derivative financial instruments		(5,354	)		2,285			(3,069	)
Capital contributions for director fees		12			(12	)		—
Contributions for consideration for compensation to employees		3,015			1,271			4,286
Amortization of deferred loan costs		1,604			(188	)		1,416
Amortization of gas swap fees		187			(187	)		—
Bad debt expense		—			22			22
Loss on sale of assets		148			(148	)		—
Change in assets and liabilities:
Restricted cash		(55	)		55			—
Accounts receivable		(586	)		372			(214	)
Other receivables		(1,101	)		(365	)		(1,466	)
Other current assets		(795	)		—			(795	)
Inventory		56			(56	)		—
Other assets		—			(378	)		(378	)
Due from affiliates		—			363			363
Accounts payable		8,146			5,445			13,591
Revenue payable		1,137			349			1,486
Accrued expenses		(114	)		1,496			1,382
Other long-term liabilities		—			119			119
Other		—			43			43

Net cash provided by (used in) operating activities		22,544			(4,358	)		18,186
Cash flows from investing activities:
Restricted cash		—			(55	)		(55	)
Equipment, development and leasehold costs		(75,631	)		3,100			(72,531	)
Proceeds from sale of property and equipment		125			(125	)		—

Net cash used in investing activities		(75,506	)		2,920			(72,586	)
Cash flows from financing activities:
Proceeds from bank borrowings		25,000			(25,000	)		—
Repayments of note borrowings		(393	)		—			(393	)
Proceeds from revolver note		—			25,000			25,000
Contributions/(distributions) — QRCP		25,873			50			25,923
Refinancing costs		(1,698	)		11			(1,687	)
Change in other long — term liabilities		123			(123	)		—

Net cash provided by (used in) financing activities		48,905			(62	)		48,843

Net decrease in cash		(4,057	)		(1,500	)		(5,557	)
Cash and cash equivalents, beginning of period		21,334			(8,000	)		13,334

Cash and cash equivalents end of period	$	17,277		$	(9,500	)	$	7,777

F-29

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
(Continued)

12. Subsequent Events

Impairment of oil and gas properties

As of December 31, 2008, our net book value of oil and gas properties exceeded the full cost ceiling. Accordingly, an impairment was recognized in the fourth quarter of 2008 of $245.6 million. The impairment charge was primarily attributable to declines in the prevailing market prices of oil and gas at the measurement date and revisions of reserves due to further technical analysis and production of gas during 2008. See our 2008 Form 10-K. Due to a further decline in natural gas prices, subsequent to December 31, 2008, we expect to incur an additional impairment charge on our oil and gas properties of approximately $85.0 million to $105.0 million as of March 31, 2009.

Settlement Agreements

We and QRCP filed lawsuits, related to the Transfers, against Mr. Cash, the entity controlled by Mr. Cash that was used in connection with the Transfers and two former officers, who are the other owners of the controlled-entity, seeking, among other things, to recover the funds that were transferred. On May 19, 2009, we entered into settlement agreements with Mr. Cash, the controlled-entity and the other owners to settle this litigation. Under the terms of the settlement agreements, QRCP received (1) approximately $2.4 million in cash and (2) 60% of the controlled-entity’s interest in a gas well located in Louisiana and a landfill gas development project located in Texas. While QRCP estimates the value of these assets to be less than the amount of the Transfers and cost of the internal investigation, they represent the majority of the value of the controlled-entity. 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. We received all of Mr. Cash’s equity interest in STP Newco, Inc. (“STP”), which owns certain oil producing properties in Oklahoma, as reimbursement for the costs of the internal investigation and the costs of the litigation against Mr. Cash that have been paid by us. We are in the process of establishing the value of the interest in STP.

Federal Derivative Case

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

Credit Agreement Amendments

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

Financial Advisor Contract

On July 1, 2009, Quest Energy GP entered into an amendment to the original agreement with a 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, being paid upon execution of the amendment. The additional financial advisor fees payable if certain transactions occurred were canceled; however, the financial advisor is still entitled to a fairness opinion fee of $650,000 in connection with any merger, sale or acquisition involving Quest Energy GP or Quest Energy.

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 we would form a new, yet to be named, publicly-traded corporation that, through a series of mergers and entity conversions, would wholly-own all three entities.

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”). Pursuant to the Support Agreement, 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 43% of the common units of Quest Midstream have, subject to certain conditions, agreed to vote their common units in favor of the Recombination.

F-30


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

Restatement

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

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

Overview of Our Company

We are a publicly traded master limited partnership formed in 2007 by QRCP to acquire, exploit and develop oil and natural gas properties. In November 2007, we consummated the initial public offering of our common units and acquired the oil and gas properties contributed to us by QRCP in connection with that offering.

Recent Developments

PetroEdge Acquisition

On July 11, 2008, QRCP acquired PetroEdge Resources (WV) LLC (“PetroEdge”) and simultaneously sold PetroEdge’s natural gas producing wells to us. We funded the purchase of the PetroEdge wellbores with borrowings under the Quest Cherokee Credit Agreement (as defined below), which was increased from $160 million to $190 million as part of the acquisition, and the proceeds from the Second Lien Loan Agreement (as defined below). The purpose of the PetroEdge acquisition was to expand our operations to another geologic basin with less basis differential that had significant resource potential. The acquisition closed during the peak month of natural gas pricing in 2008.

Internal Investigation; Restatements and Reaudits

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

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

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

•

We had costs associated with the internal investigation and our responding to inquiries from the Oklahoma Department of Securities, the Federal Bureau of Investigation, the Department of Justice, the SEC and the IRS.

	•		As a result of the resignation of Jerry D. Cash and the termination of David E. Grose, consultants were immediately retained to perform the accounting and finance functions and to assist in the determination of the intercompany debt.

	•		We retained law firms to respond to the class action and derivative suits that have been filed against us, our general partner and QRCP and to pursue the claims against the former employees.

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

	•		We retained new external auditors to reaudit our consolidated financial statements as of December 31, 2007 and for the period from November 15, 2007 to December 31, 2007 and of the Predecessor’s consolidated financial statements as of and for the years ended December 31, 2005 and 2006, and for the period from January 1, 2007 to November 14, 2007.

	•		We retained financial advisors to consider strategic options and retained outside legal counsel or increased the amount of work being performed by our previously engaged outside legal counsel.

We estimate that our share of the increased costs related to the foregoing will be approximately $3.5 million to $4.0 million in total.

Global Financial Crisis and Impact on Capital Markets and Commodity Prices

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

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

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

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

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

Credit Agreements

We are a party, as a guarantor, to an Amended and Restated Credit Agreement with Quest Cherokee, as the borrower, Royal Bank of Canada (“RBC”), as administrative agent and collateral agent, KeyBank National Association, as documentation agent and the lenders party thereto (together with all amendments, the “Quest Cherokee Credit Agreement”). On July 11, 2008, concurrent with the PetroEdge acquisition, we and Quest Cherokee entered into a Second Lien Senior Term Loan Agreement (the “Second Lien Loan Agreement,” together with the Quest Cherokee Credit Agreement, the “Quest Cherokee Agreements”). See “— Liquidity and Capital Resources — Credit Agreements” for additional information regarding the Second Lien Loan Agreement. In October 2008, we entered into amendments to the Quest Cherokee Agreements that, among other things, amended and/or waived certain of the representations and covenants contained in each credit agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result of (1) the questionable Transfers of funds discussed above and (2) not timely settling certain intercompany accounts among us, QRCP and Quest Midstream. The amendment to our Second Lien Loan Agreement also extended the maturity date thereof from January 11, 2009 to September 30, 2009 due to our inability to refinance the Second Lien Loan Agreement as a result of a combination of things including the ongoing investigation and the global financial crisis. The amendments also restricted our ability to pay distributions.

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

In July 2009, the borrowing base under the Quest Cherokee Credit Agreement was reduced from $190 million to $160 million, which, following the principal payment of $15 million 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”). 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 proved developed 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 Borrowing Base Deficiency. Management believes that we have sufficient capital resources to pay the $3.8 million principal payment due under the Second Lien Term Loan Agreement on August 15, 2009. Management is currently pursuing various options to restructure or refinance the Quest Cherokee Term Loan Agreement. There can be no assurance that such efforts will be successful or that the terms of any new or restructured indebtedness will be favorable to us.

Suspension of Distributions

	•		the decline in our cash flows from operations due to declines in oil and natural gas prices during the last half of 2008,

	•		the costs of the investigation and associated remedial actions, including the reaudit and restatement of our financial statements,

	•		concerns about a potential borrowing base redetermination in the second quarter of 2009,

	•		the need to conserve cash to properly conduct operations and maintain strategic options, and

	•		the need to repay or refinance our term loan by September 30, 2009.

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 amended 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.

Decrease in Year-End Reserves; Impairment

Due to the low price for natural gas as of December 31, 2008 as described above, revisions resulting from further technical analysis (see our 2008 Form 10-K) and production during the year, 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. Our proved reserves at December 31, 2008 were calculated using a spot price of $5.71 per Mmbtu (adjusted for basis differential, prices were $5.93 per Mmbtu in the Appalachian Basin and $4.84 per Mmbtu in the Cherokee Basin). As a result of this decrease, we recognized a non-cash impairment of $245.6 million for the year ended December 31, 2008.

As a result, the lenders under our First Lien Credit Agreement reduced our borrowing base from $190 million to $160 million in July, 2009. See “— Liquidity and Capital Resources — Sources of Liquidity in 2009 and Capital Requirements” in our 2008 Form 10-K.

Settlement Agreements

We and QRCP filed lawsuits against Mr. Cash, the entity controlled by Mr. Cash that was used in connection with the Transfers and two former officers, who are the other owners of this controlled-entity, 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, his controlled-entity and the other owners to settle this litigation. Under the terms of the settlement agreements, QRCP received (1) approximately $2.4 million in cash and (2) 60% of the controlled-entity’s interest in a gas well located in Louisiana and a landfill gas development project located in Texas. While QRCP estimates the value of these assets to be less than the amount of the Transfers and cost of the internal investigation, they represent the majority of the value of the controlled-entity. 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. We received all of Mr. Cash’s equity interest in STP, which owns certain oil producing properties in Oklahoma, as reimbursement for a portion of the costs of the internal investigation and the costs of the litigation against Mr. Cash that have been paid by us. We are in the process of establishing the value of the interest in STP.

Recombination

Given the liquidity challenges we are facing, we have undertaken a strategic review of our assets and have evaluated and continue to evaluate transactions to dispose of assets, liquidate existing derivative contracts, or enter into new derivative contracts in order to raise additional funds for operations and/or to repay indebtedness. On July 2, 2009, QELP, QRCP, QMLP and certain other parties thereto entered into an Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which the three companies would recombine. The recombination would be effected by forming a new, yet to be named, publicly-traded corporation (“New Quest”) that, through a series of mergers and entity conversions, would wholly-own all three entities (the “Recombination”). The Merger Agreement follows the execution of a non-binding letter of intent by the three Quest entities that was publicly announced on June 3, 2009.

Factors That Significantly Affect Comparability of Our Results

Our future results of operations and cash flows could differ materially from the historical results of the Predecessor due to a variety of factors, including the following:

Midstream Services Agreement. Prior to the formation of our affiliate Quest Midstream in December 2006, a wholly-owned subsidiary of QRCP provided our Predecessor with gas gathering, treating, dehydration and compression services pursuant to a gas transportation agreement that was entered into in December 2003. Since these services were being provided by one wholly-owned subsidiary of QRCP to another wholly-owned subsidiary, no amendments were made to this prior contract to reflect increases in the costs of providing these services. As part of the formation of Quest Midstream, QRCP and Quest Midstream entered into the midstream services agreement, which provided for negotiated fees for these services that were significantly higher than those that had been previously paid.

Under the midstream services agreement, Quest Midstream was paid $0.50 and $0.51 per Mmbtu of gas for gathering, dehydration and treating services and $1.10 and $1.13 per Mmbtu of gas for compression services during 2007 and 2008, respectively. These fees are subject to annual adjustment based on changes in gas prices and the producer price index. Such fees will never be reduced below these initial rates and are subject to renegotiation upon the exercise of each five-year extension period. Under the terms of some of our gas leases, we may not be able to charge the full amount of these fees to royalty owners, which would increase the average fees per Mmbtu that we effectively pay under the midstream services agreement. For 2009, the fees are $0.596 per Mmbtu of gas for gathering, dehydration and treating services and $1.319 per Mmbtu of gas for compression services. For more information about the midstream services agreement, please see our 2008 Form 10-K.

Results of Operations

The discussion of the results of operations and period-to-period comparisons presented below includes the historical results of the Predecessor. As discussed above under “— Factors That Significantly Affect Comparability of Our Results,” the Predecessor’s historical results of operations and period-to-period comparisons of its results may not be indicative of our future results. The following discussion of financial condition and results of operations should be read in conjunction with the consolidated financial statements and the notes to the consolidated financial statements, which are included elsewhere in this report.

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

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


	Three Months Ended
	September 30,				Increase/
	2008		2007		(Decrease)
			($ in thousands)
Oil and gas sales	$	49,454	$	23,852	$	25,602		107.3	%
Oil and gas production costs	$	9,821	$	8,976	$	845		9.4	%
Transportation expense	$	8,583	$	7,469	$	1,114		14.9	%
Depreciation, depletion and amortization	$	13,196	$	8,667	$	4,529		52.3	%
General and administrative expenses	$	734	$	3,318	$	(2,584	)	(77.9	)%
Gain from derivative financial instruments	$	145,132	$	13,388	$	131,744		984.0	%
Misappropriation of funds	$	—	$	500	$	(500	)	(100.0	)%
Interest expense, net	$	4,354	$	7,563	$	(3,209	)	(42.4	)%

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


	Three Months Ended
	September 30,				Increase/
	2008		2007		(Decrease)
Production Data:
Natural gas production (Mmcf)		5,694		4,375		1,319		30.1	%
Oil production (Bbbl)		19		2		17		850.0	%
Total production (Mmcfe)		5,808		4,387		1,421		32.4	%
Average daily production (Mmcfe/d)		63.1		47.7		15.4		32.3	%
Average Sales Price per Unit:
Natural gas (Mcf)	$	8.30	$	5.42	$	2.88		53.1	%
Oil (Bbl)	$	116.89	$	65.64	$	51.25		78.1	%
Natural gas equivalent (Mcfe)	$	8.51	$	5.44	$	3.07		56.4	%
Average Unit Costs per Mcfe:
Production costs	$	1.69	$	2.05	$	(0.36	)	(17.6	)%
Transportation expense	$	1.48	$	1.70	$	(0.22	)	(12.9	)%
Depreciation, depletion and amortization	$	2.27	$	1.98	$	0.29		14.6	%

Oil and Gas Sales. Oil and gas sales increased $25.5 million, or 107.3%, to $49.5 million during the three months ended September 30, 2008, from $23.9 million during the three months ended September 30, 2007. This increase was the result of increased sales volumes and an increase in average realized prices. The increase in the average realized price accounted for $17.8 million of the total. Our average product prices, on an equivalent basis (Mcfe), increased to $8.51 per Mcfe for the three months ended September 30, 2008 from $5.44 per Mcfe for the three months ended September 30, 2007. The remaining increase of $7.7 million resulted from additional volumes of 1,421 Mmcfe. The increased volumes resulted from the 2008 acquisitions as well as additional wells completed in 2008.

Oil and Gas Operating Expenses. Oil and gas operating expenses consist of oil and gas production costs, which include lease operating expenses, severance taxes and ad valorem taxes, and transportation expense. Oil and gas operating expenses increased $2.0 million, or 11.9%, to $18.4 million during the three months ended September 30, 2008, from $16.4 million during the three months ended September 30, 2007.

Oil and gas production costs increased $0.8 million, or 9.4%, to $9.8 million during the three months ended September 30, 2008, from $9.0 million during the three months ended September 30, 2007. This increase was primarily due to increased volumes in 2008. Production costs including gross production taxes and ad valorem taxes were $1.69 per Mcfe for the three months ended September 30, 2008 as compared to $2.05 per Mcfe for the three months ended September 30, 2007. The decrease in per unit cost was due to higher volumes over which to spread fixed costs.

Transportation expense increased $1.1 million, or 14.9%, to $8.6 million during the three months ended September 30, 2008, from $7.5 million during the three months ended September 30, 2007. The increase was due to increased volumes, which resulted in additional expense of approximately $2.4 million. This increase was offset by a decrease in per unit cost of $0.22 per Mcfe. Transportation expense was $1.48 per Mcfe for the three months ended September 30, 2008 as compared to $1.70 per Mcfe for the three months ended September 30, 2007.

Depreciation, Depletion and Amortization. We are subject to variances in our depletion rates from period to period due to changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties. Our depreciation, depletion and amortization increased approximately $4.5 million, or 52.3%, for the three months ended September 30, 2008 to $13.2 million from $8.7 million for the three months ended September 30, 2007. On a per unit basis, we had an increase of $0.29 per Mcfe to $2.27 per Mcfe for the three months ended September 30, 2008 from $1.98 per Mcfe for the three months ended September 30, 2007. This increase was primarily due to the increase in depletion of $4.3 million primarily due to downward revisions in our proved reserves, resulting in an increase in the per unit rate. In addition, depreciation and amortization increased approximately $0.2 million, primarily due to additional vehicles, equipment and facilities acquired in 2008.

General and Administrative Expenses. General and administrative expenses decreased $2.6 million, or 77.9%, to $0.7 million during the three months ended September 30, 2008, from $3.3 million during the three months ended September 30, 2007. The decrease is primarily due to the forfeiture of non-vested equity awards, which resulted in a reversal of compensation expense of $2.1 million for the three months ended September 30, 2008. The remaining decrease was due to the cost-cutting measures implemented in the third quarter of 2008. General and administrative expenses per Mcfe was $0.13 for the three months ended September 30, 2008 compared to $0.76 for the three months ended September 30, 2007.

Gain from Derivative Financial Instruments. Gain from derivative financial instruments increased $131.7 million to $145.1 million during the three months ended September 30, 2008, from a gain of $13.4 million during the three months ended September 30, 2007. Due to the increase in average crude oil and natural gas prices during 2008, we recorded a $152.7 million unrealized gain and $7.5 million realized loss on our derivative contracts for the three months ended September 30, 2008 compared to a $9.6 million unrealized gain and $3.7 million realized gain for the three months ended September 30, 2007. Unrealized gains are attributable to changes in oil and natural gas prices and volumes hedged from one period end to another.

Misappropriation of Funds. As previously disclosed, in connection with the Transfers, we recorded a loss from misappropriation of funds of $0.5 million for the three months ended September 30, 2007.

Interest Expense, net. Interest expense, net decreased $3.2 million, or 42.4%, to $4.4 million during the three months ended September 30, 2008, from $7.6 million during the three months ended September 30, 2007. The decreased interest expense for the three months ended September 30, 2008 was due to the refinancing of our credit facilities in 2007, lower outstanding borrowings, as well as lower interest rates during the three months ended September 30, 2008 compared to the same period in 2007.

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

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


	Nine Months Ended
	September 30,					Increase/
	2008			2007		(Decrease)
				($ in thousands)
Oil and gas sales	$	136,908		$	76,396	$	60,512		79.2	%
Oil and gas production costs	$	34,104		$	27,991	$	6,113		21.8	%
Transportation expense	$	25,921		$	20,639	$	5,282		25.6	%
Depreciation, depletion and amortization	$	34,750		$	24,618	$	10,132		41.2	%
General and administrative expenses	$	5,501		$	10,025	$	(4,524	)	(45.1	)%
Gain (loss) from derivative financial instruments	$	(4,482	)	$	8,232	$	(12,714	)	(154.4	)%
Misappropriation of funds	$	—		$	1,500	$	(1,500	)	(100.0	)%
Interest expense, net	$	8,747		$	22,888	$	(14,141	)	(61.8	)%


	Nine Months Ended
	September 30,				Increase/
	2008		2007		(Decrease )
Production Data:
Natural gas production (Mmcf)		15,755		12,211		3,544		29.0	%
Oil production (Bbbl)		47		6		41		683.3	%
Total production (Mmcfe)		16,037		12,247		3,790		30.9	%
Average daily production (Mmcfe/d)		58.5		44.9		13.6		30.3	%
Average Sales Price per Unit:
Natural gas (Mcf)	$	8.36	$	6.23	$	2.13		34.2	%
Oil (Bbl)	$	110.40	$	57.06	$	53.34		93.5	%
Natural gas equivalent (Mcfe)	$	8.54	$	6.24	$	2.30		36.9	%
Average Unit Costs per Mcfe:
Production costs	$	2.13	$	2.29	$	(0.16	)	(7.0	)%
Transportation expense	$	1.62	$	1.69	$	(0.07	)	(4.1	)%
Depreciation, depletion and amortization	$	2.17	$	2.01	$	0.16		8.0	%

Oil and Gas Sales. Oil and gas sales increased $60.5 million, or 79.2%, to $136.9 million during the nine months ended September 30, 2008, from $76.4 million during the nine months ended September 30, 2007. This increase was the result of increased sales volumes and an increase in average realized prices. The increase in the average sales price accounted for $36.9 million of the increase. Our average product prices on an equivalent basis (Mcfe), increased to $8.54 per Mcfe for the nine months ended September 30, 2008 from $6.24 per Mcfe for the nine months ended September 30, 2007. Additional volumes of 3,790 Mmcfe accounted for the remaining increase of $23.7 million. The increased volumes resulted from the 2008 acquisitions, as well as additional wells completed in 2008.

Oil and Gas Operating Expenses. Oil and gas operating expenses consist of oil and gas production costs, which include lease operating expenses, severance taxes and ad valorem taxes, and transportation expense. Oil and gas operating expenses increased $11.4 million, or 23.4%, to $60.0 million during the nine months ended September 30, 2008, from $48.6 million during the nine months ended September 30, 2007.

Oil and gas production costs increased $6.1 million, or 21.8% to $34.1 million during the nine months ended September 30, 2008, from $28.0 million during the nine months ended September 30, 2007. This increase was primarily due to increased volumes in 2008. Production costs including gross production taxes and ad valorem taxes were $2.13 per Mcfe for the nine months ended September 30, 2008 as compared to $2.29 per Mcfe for the nine months ended September 30, 2007. The decrease in per unit cost was due to higher volumes over which to spread fixed costs.

Transportation expense increased $5.3 million, or 25.6%, to $25.9 million during the nine months ended September 30, 2008, from $20.6 million during the nine months ended September 30, 2007. The increase was due to increased volumes, which resulted in additional expense of approximately $6.4 million. This increase was offset by a decrease in per unit cost of $0.07 per Mcfe. Transportation expense was $1.62 per Mcfe for the nine months ended September 30, 2008 as compared to $1.69 per Mcfe for the nine months ended September 30, 2007.

Depreciation, Depletion and Amortization. We are subject to variances in our depletion rates from period to period due to changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties. Our depreciation, depletion and amortization increased approximately $10.1 million, or 41.2%, for the nine months ended September 30, 2008 to $34.8 million from $24.6 million for the nine months ended September 30, 2007. On a per unit basis, we had an increase of $0.16 per Mcfe to $2.17 per Mcfe in 2008 from $2.01 per Mcfe in 2007. This increase was primarily due to the increase in depletion of $10.3 million due to downward revisions in our proved

reserves, resulting in an increase in the per unit rate.

General and Administrative Expense. General and administrative expenses decreased $4.5 million, or 45.1%, to $5.5 million during the nine months ended September 30, 2008, from $10.0 million during the nine months ended September 30, 2007. The decrease is due to the forfeiture of non-vested equity awards, which resulted in a reversal of compensation of $2.1 million, and cost-cutting measures implemented in the third quarter of 2008. General and administrative expenses per Mcfe was $0.34 for the nine months ended September 30, 2008 compared to $0.82 for the nine months ended September 30, 2007.

Gain (Loss) from Derivative Financial Instruments. Gain (loss) from derivative financial instruments decreased $12.7 million to a loss of $4.5 million during the nine months ended September 30, 2008, from a gain of $8.2 million during the nine months ended September 30, 2007. Due to the increase in average crude oil and natural gas prices during 2008, we recorded a $13.3 million unrealized gain and $17.8 million realized loss on our derivative contracts for the nine months ended September 30, 2008 compared to a $3.1 million unrealized gain and $5.2 million realized gain for the nine months ended September 30, 2007. Unrealized gains and losses are attributable to changes in crude oil and natural gas prices and volumes hedged from one period end to another.

Misappropriation of Funds. As previously disclosed, in connection with the Transfers, we recorded a loss from misappropriation of funds of $1.5 million for the nine months ended September 30, 2007.

Interest Expense, net. Interest expense, net decreased $14.1 million, or 61.8%, to $8.7 million during the nine months ended September 30, 2008, from $22.9 million during the nine months ended September 30, 2007. The decreased interest expense for the nine months ended September 30, 2008 is due to the refinancing of our credit facilities in 2007, lower outstanding borrowings, as well as lower interest rates during the nine months ended September 30, 2008, compared to the same period in 2007.

Liquidity and Capital Resources

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

At September 30, 2008, we had $6.0 million available under the Quest Cherokee Credit Agreement. In July 2009, the borrowing base under the Quest Cherokee Credit Agreement was reduced from $190 million to $160 million, which, following the payment discussed below, resulted in the outstanding borrowings under the Quest Cherokee Credit Agreement exceeding the new borrowing base by $14 million (the “Borrowing Base Deficiency”). In anticipation of the reduction in the borrowing base, 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 proved developed 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 Borrowing Base Deficiency. Management believes that we have sufficient capital resources to pay the $3.8 million principal payment due under the Second Lien Loan Agreement on August 15, 2009. Management is currently pursuing various options to restructure or refinance the Second Lien Loan Agreement. There can be no assurance that such efforts will be successful or that the terms of any new or restructured indebtedness will be favorable to 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 $48.5 million for the nine months ended September 30, 2008 as compared to cash flows from operations of $18.2 million for the nine months ended September 30, 2007. The increase is attributable primarily to higher average oil and natural gas prices in 2008 compared with average oil and natural gas prices in 2007.

Cash Flows Used in Investing Activities. Net cash used in investing activities totaled $148.3 million for the nine months ended September 30, 2008 as compared to $72.6 million for the nine months ended September 30, 2007. The following table sets forth our capital expenditures by major categories for the nine months ended 2008.


	Nine Months Ended
	September 30,
	2008
	(In thousands)
Capital expenditures:
Leasehold acquisition and development	$	55,498
Acquisition of PetroEdge assets		71,213
Acquisition of Seminole County, Oklahoma property		9,500
Other items		13,216

Total capital expenditures	$	149,427

Cash Flows from Financing Activities. Net cash provided by financing activities totaled $109.4 million for the nine months ended September 30, 2008 as compared to $48.8 million for the nine months ended September 30, 2007. In 2008, cash provided by financing was primarily comprised of $134.0 million of additional borrowings offset by $22.6 million of distributions to unitholders.

Working Capital Deficit. At September 30, 2008, we had current assets of $53.3 million. Our working capital (current assets minus current liabilities, excluding the short-term derivative asset and liability of $17.0 million and $3.2 million, respectively) was a deficit of $28.4 million at September 30, 2008, compared to working capital (excluding the short-term derivative asset and liability of $8.0 million and $8.1 million, respectively) of $3.4 million at December 31, 2007. This change is mostly due to the $45 million second lien term loan incurred in connection with the PetroEdge acquisition, which is reflected as current in the consolidated balance sheet as of September 30, 2008.

Credit Agreements

Quest Cherokee Credit Agreement .

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

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

	•		On June 18, 2009, we entered into a Third Amendment to Amended and Restated Credit Agreement that, among other things, permits Quest Cherokee’s obligations under oil and gas derivative contracts with BP Corporation North America, Inc. (“BP”) or any of its affiliates to be secured by the liens under the credit agreement on a pari passu basis with the obligations under the credit agreement.

•

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

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

Second Lien Loan Agreement .

•

contained in the Second Lien Loan Agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result or (1) the Transfers and (2) not timely settling certain intercompany accounts among QRCP, Quest Energy and Quest Midstream.

•

General Provisions Applicable to Quest Cherokee Agreements.

Security Interest . The Quest Cherokee Credit Agreement is secured by a first priority lien on substantially all of our assets, including those of Quest Cherokee and QCOS. The Second Lien Loan Agreement is secured by a second priority lien on substantially all of our assets and those of Quest Cherokee and QCOS.

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

The Quest Cherokee Agreements’ financial covenants prohibit Quest Cherokee, us and any of our subsidiaries from:

•

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

Consolidated EBITDA is defined in the Quest Cherokee Agreements to mean for us and our subsidiaries on a consolidated basis, an amount equal to the sum of (i) consolidated net income, (ii) consolidated interest charges, (iii) the amount of taxes, based on or measured by income, used or included in the determination of such consolidated net income, (iv) the amount of depreciation, depletion and amortization expense deducted in determining such consolidated net income, (v) acquisition costs required to be expensed under FAS No. 141(R), (vi) fees and expenses of the internal investigation relating to the Misappropriation Transaction (as defined in the First Amendment to Second Lien Loan Agreement) and the related restructuring (which are capped at $1,500,000 for purposes of this definition), and (vii) other non-cash charges

and expenses, including, without limitation, non-cash charges and expenses relating to swap contracts or resulting from accounting convention changes, of us and our subsidiaries on a consolidated basis, all determined in accordance with GAAP.

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

We were in compliance with all of its covenants as of September 30, 2008.

Contractual Obligations

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


	Payments Due by Period
			Less Than		1-3		4-5		More Than
	Total		1 Year		Years		Years		5 Years
	(In thousands)
First Lien Credit Agreement	$	183,000	$	—	$	183,000	$	—	$	—
Second Lien Loan Agreement		45,000		45,000		—		—		—
Other note obligations		174		25		111		32		6
Interest expense on credit agreements (1)		27,212		14,130		13,579		3		—
Operating lease obligations		718		162		301		255		—

Total commitments	$	256,604	$	59,317	$	196,991	$	290	$	6


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

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, 2008, we did not have any relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.

Critical Accounting Policies

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

Recent Accounting Pronouncements

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

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

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

In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS 159”), including an amendment to SFAS 115. Under SFAS 159, entities may elect to measure specified financial instruments and warranty and insurance contracts at fair value on a contract-by-contract basis,

with changes in fair value recognized in earnings each reporting period. The election, called the fair value option, enables entities to achieve an offset accounting effect for changes in fair value of certain related assets and liabilities without having to apply complex hedge accounting provisions. SFAS 159 is expected to expand the use of fair value measurement consistent with the FASB’s long-term objectives for financial instruments. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We have assessed the provisions of SFAS 159 and we have elected not to apply fair value accounting to our existing eligible financial instruments. As a result, the adoption of SFAS 159 did not have an impact on our financial statements.

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

Forward-Looking Statements

Various statements in this report, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These include such matters as projections and estimates concerning the timing and success of specific projects; financial position; business and financial strategy; budgets; availability and terms of capital; amount, nature and timing of capital expenditures, including future development costs; drilling of wells;

acquisition and development of oil and natural gas properties; timing and amount of future production of oil and gas; operating costs and other expenses; estimated future net revenues from oil and natural gas reserves and the present value thereof; cash flow and anticipated liquidity; and other plans and objectives for future operations.

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

	•		current financial instability and deteriorating economic conditions;

	•		our current financial instability;

	•		volatility of oil and gas prices;

	•		completion of the Recombination;

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

	•		our restrictive debt covenants;

	•		results of our hedging activities;

	•		developments in oil and gas producing countries;

	•		the impact of weather and the occurrence of natural disasters such as fires;

	•		competition in the oil and gas industry;

	•		availability of drilling and production equipment, labor and other services;

	•		drilling, operational and environmental risks; and

	•		regulatory changes and litigation risks.

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Commodity Price Risk

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

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


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

Interest Rate Risk

As of September 30, 2008 we had outstanding $228.2 million of variable-rate debt. A 1% increase in our interest rates would increase gross interest expense approximately $2.3 million per year. As of September 20, 2008, we did not have any interest rate hedging activities.

ITEM 4T. 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 our 2008 Form 10-K and this Quarterly Report on Form 10-Q, our management, under the supervision and with the participation of the current principal executive officer and current principal financial officer 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, 2008. 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, 2008. Under the management services agreement between us and 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. Notwithstanding this determination, our management believes that the consolidated financial statements in this Quarterly Report on Form 10-Q fairly present, in all material respects, our financial position and results of operations and cash flows as of the dates and for the periods presented, in conformity with GAAP.

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

(1)

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

Additionally, 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.

Remediation Plan

Under the management services agreement between us and 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. These remediation efforts, outlined below, are intended both to address the identified material weaknesses and to enhance our overall financial control environment. In August 2008, Mr. David C. Lawler was appointed President (and in May 2009 was appointed as the Chief Executive Officer) (our principal executive officer) and in September 2008, Mr. Jack Collins was appointed Chief Compliance Officer. In January 2009, Mr. Eddie M. LeBlanc, III was appointed Chief Financial Officer (our principal financial and accounting officer). The design and implementation of these and other remediation efforts are the commitment and responsibility of this new leadership team.

In addition, Gary M. Pittman, one of our independent directors, was elected as Chairman of the Board, and J. Philip McCormick, who has significant prior public company audit committee experience, was added to our Board of Directors and Audit Committee.

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

As a result of the initiatives already underway to address the control deficiencies described above, 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, we have implemented additional training and/or increased supervision and established segregation of duties regarding the initiation, approval and reconciliation of cash transactions, including wire transfers.

The Board of Directors has directed management to develop a detailed plan and timetable for the implementation of the foregoing remedial measures (to the extent not already completed) and will monitor their implementation. In addition, under the direction of the Board of Directors, management will continue to review and make necessary

changes to the overall design of our internal control environment, as well as policies and procedures to improve the overall effectiveness of internal control over financial reporting.

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

Changes in Internal Control Over Financial Reporting

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

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

We are subject, from time to time, to certain legal proceedings and claims in the ordinary course of conducting our business. As of September 30, 2008, as a result of the Transfers and the restatements of our financial statements, we are involved in litigation outside the ordinary course of our business. Except for those legal proceedings listed in Part I, Item I, Note 9 to our consolidated financial statements, entitled “Commitments and Contingencies,” which is incorporated herein by reference, we believe there are no pending legal proceedings in which we are currently involved which, if adversely determined, could have a material adverse effect on our financial position, results of operations or cash flow. Like other oil and natural gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. Therefore it is extremely difficult to reasonably quantify future environmental related expenditures.

ITEM 1A. RISK FACTORS.

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

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

None

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None

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

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

ITEM 5. OTHER INFORMATION.

None.

ITEM 6. EXHIBITS


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

*10.1		Second Lien Senior Term Loan Agreement, dated as of July, 11, 2008, by and among Quest Cherokee, LLC, Quest Energy Partners, L.P., Royal Bank of Canada, KeyBank National Association, Société Générale, the lenders party thereto and RBC Capital Markets (incorporated herein by reference to Exhibit 10.1 to Quest Energy Partners, L.P.’s Current Report on Form 8-K filed on July 16, 2008).

*10.2		Guaranty for Second Lien Term Loan Agreement by Quest Cherokee Oilfield Service, LLC in favor of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.2 to Quest Energy Partners, L.P.’s Current Report on Form 8-K filed on July 16, 2008).



*10.3		Guaranty for Second Lien Term Loan Agreement by Quest Energy Partners, L.P. in favor of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.3 to Quest Energy Partners, L.P.’s Current Report on Form 8-K filed on July 16, 2008).

*10.4		Pledge and Security Agreement for Second Lien Term Loan Agreement by Quest Cherokee Oilfield Service, LLC for the benefit of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.4 to Quest Energy Partners, L.P.’s Current Report on Form 8-K filed on July 16, 2008).

*10.5		Pledge and Security Agreement for Second Lien Term Loan Agreement by Quest Energy Partners, L.P. for the benefit of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.5 to Quest Energy Partners, L.P.’s Current Report on Form 8-K filed on July 16, 2008).

*10.6		Pledge and Security Agreement for Second Lien Term Loan Agreement by Quest Cherokee, LLC for the benefit of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.6 to Quest Energy Partners, L.P.’s Current Report on Form 8-K filed on July 16, 2008).

*10.7		Intercreditor Agreement, dated as of July 11, 2008, by and between Royal Bank of Canada and Quest Cherokee, LLC (incorporated herein by reference to Exhibit 10.7 to Quest Energy Partners, L.P.’s Current Report on Form 8-K filed on July 16, 2008).

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

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

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

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


*		Incorporated by reference.

		PLEASE NOTE: Pursuant to the rules and regulations of the Securities and Exchange Commission, we have filed or incorporated by reference the agreements referenced above as exhibits to this Quarterly Report on Form 10-Q. The agreements have been filed to provide investors with information regarding their respective terms. The agreements are not intended to provide any other factual information about the 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 28 ^th day of July, 2009.


	Quest Energy Partners, L.P.
	By:	Quest Energy GP, LLC, its general partner

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


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

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