- Amended Quarterly Report (10-Q/A)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

(Amendment No. 1)

(Mark One)


þ		Quarterly report under Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended March 31, 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 as specified in its charter)


Delaware		26-0518546

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

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 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 May 15, 2008, the issuer had 12,301,521common units outstanding.

EXPLANATORY NOTE

This amended Quarterly Report on Form 10-Q/A for the quarter ended March 31, 2008 includes our restated consolidated financial statements as of March 31, 2008 and for the three month period ended March 31, 2008 and our Predecessor’s restated carve out financial statements for the three month period ended March 31, 2007. The consolidated balance sheet as of December 31, 2007 was restated in our Annual Report on Form 10-K for the year ended December 31, 2008 filed on June 16, 2009 (the “2008 Form 10-K”).

We were formed by Quest Resource Corporation (“QRCP”) in 2007 in order to conduct, in a master limited partnership structure, the exploration and production operations previously conducted by QRCP’s wholly-owned subsidiaries, Quest Cherokee, LLC (“Quest Cherokee”) and Quest Cherokee Oilfield Service, LLC (“QCOS”). QRCP owns 100% of our general partner and therefore controls the election of the board of directors of our general partner. Since our initial public offering, our general partner has had the same executive officers as QRCP. We do not have any employees, other than field level employees, and we depend on QRCP to provide us with all general and administrative functions necessary to operate our business. QRCP provides these services to us pursuant to the terms of the management services agreement between us and Quest Energy Service, LLC (“Quest Energy Service”), a wholly-owned subsidiary of QRCP. The management services agreement obligates Quest Energy Service to provide all personnel (other than field personnel) and any facilities, goods and equipment necessary to perform the services we need including acquisition services, general and administrative services such as SEC reporting and filings, Sarbanes-Oxley Act compliance, accounting, audit, finance, tax, benefits, compensation and human resource administration, property management, risk management, land, marketing, legal and engineering.

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, our general partner, and Quest Midstream GP, LLC (“Quest Midstream GP”), the general partner of Quest Midstream, 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 the former chief executive officer, 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. 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.

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 and 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 and 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.

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 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.

The restated consolidated financial statements included in this Form 10-Q/A correct errors in a majority of the financial statement line items in the previously issued consolidated financial statements for all periods presented. The most significant errors (by dollar amount) consist of the following:

	•		The Transfers, which were not approved expenditures, were not properly accounted for as losses.

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

	•		Errors were identified in the accounting for the formation of Quest Cherokee in December 2003 in which: (i) no value was ascribed to the Quest Cherokee Class A units that were issued to ArcLight Energy Partners Fund I, L.P. (“ArcLight”) in connection with the transaction, (ii) a debt discount (and related accretion) and minority interest were not recorded, (iii) transaction costs were inappropriately capitalized to oil and gas properties, and (iv) subsequent to December 2003, interest expense was improperly stated as a result of these errors. In 2005, the debt relating to this transaction was repaid and the Class A units were repurchased from ArcLight. Due to the errors that existed in the previous accounting, additional errors resulted in 2005 including: (i) a loss on extinguishment of debt was not recorded, and (ii) oil and gas properties and retained earnings were overstated. Subsequent to the 2005 transaction, depreciation, depletion and amortization expense was also overstated due to these errors.

	•		Certain general and administrative expenses unrelated to oil and gas production were inappropriately capitalized to oil and gas properties, and certain operating expenses were inappropriately capitalized to oil and gas properties being amortized. These items resulted in errors in valuation of the full cost pool, oil and gas production expenses and general and administrative expenses.

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

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

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

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


	March 31, 2008
Partners’ equity as previously reported	$	184,584
Effect of the Transfers		(9,500	)
Reversal of hedge accounting		(2,725	)
Accounting for formation of Quest Cherokee		(15,102	)
Capitalization of costs in full cost pool		(27,595	)
Recognition of costs in proper periods		(957	)
Depreciation, depletion and amortization		11,429
Impairment of oil and gas properties		30,719
Other errors		3,823

Partners’ equity as restated	$	174,676


	Three Months Ended March 31,
	2008			2007
Net loss as previously reported	$	(17,346	)	$	(3,650	)
Effect of the Transfers		—			(500	)
Reversal of hedge accounting		(19,196	)		(14,079	)
Capitalization of costs in full cost pool		(3,659	)		(2,419	)
Recognition of costs in proper periods		583			(244	)
Stock-based compensation		(431	)		(345	)
Depreciation, depletion and amortization		(491	)		(480	)
Other errors(*)		(225	)		(1,046	)

Net loss as restated	$	(40,765	)	$	(22,763	)


*		Includes minority interest impact.

Reconciliations from amounts previously included in our consolidated financial statements to restated amounts on a financial statement line item basis are presented in Note 14 — Restatement to the accompanying consolidated financial statements.

Other Matters — In addition to the items for which we have restated our consolidated financial statements, the Oklahoma Department of Securities has filed a lawsuit alleging:

	•		The theft of approximately $1.0 million by David E. Grose, the former chief financial officer, and Brent Mueller, the former purchasing manager. The evidence indicates that this theft occurred in the third quarter of 2008 after the periods covered by this report and therefore did not affect the periods covered by this report.

	•		A kickback scheme involving David E. Grose and Brent Mueller, in which each received kickbacks totaling approximately $0.9 million from several related suppliers beginning in 2005.

We experienced significant increased costs in the second half of 2008 and continue to experience such increased costs in the first half of 2009 due to, among other things (as more fully described in our 2008 Form 10-K in Items 1 and 2. “Business and Properties — Recent Developments — Internal Investigation; Restatements and Reaudits”):

	•		the necessary retention of numerous professionals, including consultants to perform the accounting and finance functions following the termination of the chief financial officer, independent legal counsel to conduct the internal investigation, investment bankers and financial advisors, and law firms to respond to the class action and derivative suits that have been filed against us and our affiliates and to pursue the claims against the former employees;

	•		costs associated with amending our credit agreements;

	•		preparing the restated consolidated financial statements; and

	•		conducting the reaudits of the restated consolidated financial statements.

This Amendment No. 1 to the Quarterly Report on Form 10-Q/A restates the Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 in its entirety to reflect the effects of the restatement. However, the Company has not modified nor updated disclosures presented in the Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, except as required to reflect the effects of the matters discussed above. Accordingly, this Amendment No. 1 to the Quarterly Report on Form 10-Q/A does not reflect events occurring after the filing of the Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, initially filed with the SEC on May 15, 2008, or modify or update those disclosures affected by subsequent events or discoveries. Therefore, this Amendment No. 1 to the Quarterly Report on Form 10-Q/A should be read in conjunction with the Company’s 2008 Form 10-K and the other subsequent reports that the Company has filed with the Securities and Exchange Commission.

The Company has also restated the following items, which were impacted by the adjustments described above:

Part I

Item 1 — Financial Statements

Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 3 — Quantitative and Qualitative Disclosures About Market Risk

Item 4(T) — Controls and Procedures

In addition, in accordance with applicable SEC rules, this Amendment No. 1 to the Quarterly Report on Form 10-Q/A includes currently-dated certifications from our Chief Executive Officer and President, who is our principal executive officer, and our Chief Financial Officer, who is our principal financial officer in Exhibits 31.1, 31.2, 32.1 and 32.2.

QUEST ENERGY PARTNERS, L.P.

FORM 10-Q/A

FOR THE QUARTER ENDED MARCH 31, 2008

TABLE OF CONTENTS


PART I — FINANCIAL INFORMATION			7
Item 1. Financial Statements			7
Balance Sheets: March 31, 2008 and December 31, 2007			F-1
Statements of Operations: Three months ended March 31, 2008 and 2007			F-2
Statements of Cash Flows: Three months ended March 31, 2008 and 2007			F-3
Notes to Unaudited Consolidated/Carve Out Financial Statements			F-4
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			8
Item 3. Quantitative and Qualitative Disclosures About Market Risk			14
Item 4(T). Controls and Procedures			15

PART II — OTHER INFORMATION			19
Item 1. Legal Proceedings			19
Item 1A. Risk Factors			19
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			19
Item 3. Defaults Upon Senior Securities			19
Item 4. Submission of Matters to a Vote of Security Holders			19
Item 5. Other Information			19
Item 6. Exhibits			20

SIGNATURES			21
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 “Quest Energy Partners,” “the Company,” “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, Quest Cherokee, LLC and Quest Cherokee Oilfield Service, LLC;

•		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 “QMLP ”or “Quest Midstream,” we are referring to Quest Midstream Partners, L.P. and its subsidiaries.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements .

Attached hereto as Pages F-1 through F-28 and incorporated herein by this reference are (i) our unaudited interim financial statements, including a consolidated balance sheet as of March 31, 2008, a consolidated statement of operations and a consolidated statement of cash flows for the three month period ended March 31, 2008, (ii) the Predecessor’s unaudited interim financial statements, including a carve out statement of operations and a carve out statement of cash flows for the three month period ended March 31, 2007 and (iii) related notes to the financial statements.

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 Company’s results for the three months ended March 31, 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 2007 financial statements and notes, as restated, which have been included in the 2008 Form 10-K.

Restatement of Financial Statements: As discussed in the Explanatory Note to this Quarterly Report on Form 10-Q/A, the financial statements are being restated to reflect the impact of errors in our previously issued financial statements. See further discussion in Note 14 to the accompanying consolidated/carveout financial statements.

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

($ in thousands)


	March 31,		December 31,
	2008		2007
	(Unaudited) (Restated)
ASSETS
Current assets:
Cash and cash equivalents	$	739	$	169
Restricted cash		1,205		1,205
Accounts receivable, trade		57		86
Due from affiliated companies		22,895		15,624
Other current assets		2,468		3,091
Inventory		6,797		4,956
Current derivative financial instrument assets		2,232		8,008

Total current assets		36,393		33,139
Property and equipment, net of accumulated depreciation of $6,168 and $5,473		17,323		17,116
Oil and gas properties under full cost method of accounting, net		314,604		294,329
Other assets, net		3,420		3,526
Long-term derivative financial instrument assets		685		3,467

Total assets	$	372,425	$	351,577


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	17,581	$	18,673
Accrued expenses		3,267		639
Due to affiliates		2,472		1,708
Current portion of notes payable		448		666
Current derivative financial instrument liabilities		32,383		8,108

Total current liabilities		56,151		29,794
Non-current liabilities:
Long-term derivative financial instrument liabilities		16,506		6,311
Asset retirement obligations		2,056		1,700
Notes payable		123,036		94,042

Total liabilities		197,749		131,847

Commitments and contingencies
Partners’ equity:
Common unitholders — Issued and outstanding — 12,301,521 at March 31, 2008 and December 31, 2007, respectively (9,100,000 — public; 3,201,521 — affiliate)		136,707		162,610
Subordinated unitholder — affiliate; 8,857,981 units issued and outstanding at March 31, 2008 and December 31, 2007		36,217		54,465
General Partner — affiliate; 431,827 units issued and outstanding at March 31, 2008 and December 31, 2007		1,752		2,655

Total partners’ equity		174,676		219,730

Total liabilities and partners’ equity	$	372,425	$	351,577

See accompanying notes to unaudited consolidated/carve out financial statements.

F-1

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

STATEMENTS OF OPERATIONS
(Unaudited)
(Restated)

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


	Successor			Predecessor
	Three months ended March 31,
	2008			2007
	(Consolidated)			(Carve out)
Revenue:
Oil and gas sales	$	38,314		$	24,974

Total revenues		38,314			24,974

Costs and expenses:
Oil and gas production		10,386			9,048
Transportation expense		8,663			6,361
General and administrative		3,098			2,374
Depreciation, depletion and amortization		10,700			7,762
Misappropriation of funds		—			500

Total costs and expenses		32,847			26,045


Operating income (loss)		5,467			(1,071	)

Other income (expense):
Other income		69			94
Loss from derivative financial instruments		(44,239	)		(13,547	)
Interest income		17			177
Interest expense		(2,079	)		(8,416	)

Total other income (expense)		(46,232	)		(21,692	)


Net loss	$	(40,765	)	$	(22,763	)


General partner’s interest in net (loss)	$	(815	)

Limited partners’ interest in net (loss)	$	(39,950	)

Net loss per limited partner units – basic and diluted	$	(1.89	)

Weighted average limited partner units outstanding:
Common units (basic and diluted)		12,301,521
Subordinated units (basic and diluted)		8,857,981

See accompanying notes to unaudited consolidated/carve out financial statements.

F-2

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

STATEMENTS OF CASH FLOWS
(Unaudited)
(Restated)

($ in thousands)


	Successor			Predecessor
	Three months ended
	March 31,
	2008			2007
	(Consolidated)			(Carve out)
Cash flows from operating activities:
Net loss	$	(40,765	)	$	(22,763	)
Adjustments to reconcile net loss to cash provided by operations:
Depreciation, depletion and amortization		10,700			7,762
Change in derivative fair value		43,028			14,541
Unit awards granted to employees		12			447
Amortization of loan origination fees		120			472
Bad debt expense		26			22
Change in assets and liabilities:
Accounts receivable		3			(1,688	)
Other receivables		—			(1,415	)
Other current assets		623			(828	)
Other assets		(13	)		1,745
Due from affiliates		(6,507	)		345
Accounts payable		185			10,735
Revenue payable		251			1,479
Accrued expenses		2,592			1,093
Other long-term liabilities		354			41

Net cash provided by operating activities		10,609			11,988
Cash flows from investing activities:
Equipment, development and leasehold costs		(34,514	)		(21,607	)

Net cash used in investing activities		(34,514	)		(21,607	)
Cash flows from financing activities:
Proceeds from revolver note		29,000			—
Repayments of note borrowings		(224	)		(221	)
Syndication costs		(265	)		—
Capital contributions (distributions)		375			(1,807	)
Distributions to unitholders		(4,411	)		—
Refinancing costs		—			(1,687	)

Net cash provided by (used in) financing activities		24,475			(3,715	)

Net increase (decrease) in cash		570			(13,334	)
Cash and cash equivalents, beginning of period		169			13,334

Cash and cash equivalents, end of period	$	739		$	—

See accompanying notes to unaudited consolidated/carve out financial statements.

F-3

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS

(Unaudited)

1. Formation of the Company and Description of Business

Quest Energy Partners, L.P., a Delaware limited partnership (the “Company”), was formed in July 2007 by Quest Resource Corporation (together with its subsidiaries, “QRCP”) to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. On November 15, 2007, the Company completed an initial public offering of its common units representing limited partner interests (the “Offering”). At the closing of the Offering, QRCP contributed Quest Cherokee, LLC to the Company in exchange for general partner units, the incentive distribution rights, common units and subordinated units in the Company. At the time, Quest Cherokee owned all of QRCP’s oil and natural gas properties and related assets in the Cherokee Basin, a fifteen-county region in southeastern Kansas and northeastern Oklahoma (the “Cherokee Basin Operations”).

The Company’s operations are currently focused on developing coal bed methane gas production in the Cherokee Basin. In addition to its producing properties, the Company has a significant inventory of potential drilling locations and acreage in the Cherokee Basin.

QRCP currently owns an approximate 57% limited partner interest in the Company. Quest Energy GP, LLC (the “General Partner” or “Quest Energy GP”) is a wholly-owned subsidiary of QRCP and is the general partner of the Company.

2. Basis of Presentation and Misappropriation, Reaudit and Restatement

The Company’s unaudited condensed consolidated/carve out financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, certain information and disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted. The Company believes that the presentations and disclosures herein are adequate to make the information not misleading. The unaudited condensed consolidated/carve out financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year. These interim financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 (the “2008 Form 10-K”). The 2008 Form 10-K includes restated consolidated financial statements and footnotes for the year ended December 31, 2007.

All intercompany accounts and transactions have been eliminated in preparing the consolidated/carve out financial statements. In these notes to unaudited consolidated/carve out financial statements, all dollar and unit amounts in tabulations are in thousands of dollars and units, respectively, unless otherwise indicated.

These carve out financial statements and related notes thereto represent the carve out financial position, results of operations and cash flows of the Cherokee Basin Operations, referred to as Quest Energy Partners, L.P. Predecessor (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. The allocations and related estimates and assumptions are described more fully in Note 3 — Summary of Significant Accounting Policies below.

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.

Misappropriation, Reaudit and Restatement

These consolidated financial statements include our restated financial statements as of March 31, 2008 and for the three month periods ended March 31, 2008 and 2007. The consolidated balance sheet as of December 31, 2007 was restated in our 2008 Form 10-K. We will subsequently file a Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and for the three and nine month periods ended September 30, 2007.

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 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.

Additionally, the amended 8-K reported that our management had concluded that the reported cash balances and partners’ equity of the Predecessor will be reduced by a total of $9.5 million as of November 14, 2007, which represents the total amount of the Transfers that had been funded by Quest Cherokee as of the closing of our initial public offering. Our management concluded that such Transfers had indirectly resulted in Quest Cherokee borrowing an additional $9.5 million under its credit facilities prior to November 15, 2007. QRCP repaid this additional indebtedness of Quest Cherokee at the closing of our initial public offering. We have no obligation to repay such amount to QRCP. Notwithstanding the foregoing, our reported cash balances and partners’ equity as of December 31, 2007 and March 31, 2008 continued to reflect the Transfers and accordingly were overstated by $10 million (consisting of the $9.5 million funded by Quest Cherokee that had been repaid by QRCP at the closing of our initial public offering and an additional $0.5 million that was recorded on our balance sheet in error — the additional $0.5 million was funded after the closing of our initial public offering by another subsidiary of QRCP in which we have no ownership interest).

The restated consolidated financial statements to which these Notes apply also correct errors in a majority of the financial statement line items found in the previously issued consolidated financial statements for all periods presented. See Note 14 — Restatement.

3. Summary of Significant Accounting Policies

Reference is hereby made to the 2008 Form 10-K, which contains a summary of significant accounting policies followed by the Company in the preparation of its consolidated/carve out financial statements. The 2008 Form 10-K includes restated consolidated financial statements and footnotes as of and for the year ended December 31, 2007. These policies were also followed in preparing the consolidated/carve out restated financial statements as of March 31, 2008 and for the three months ended March 31, 2008 and 2007.

Consolidation Policy

Investee companies in which the Company directly or indirectly owns more than 50% of the outstanding voting securities or those in which the Company has effective control over are generally accounted for under the consolidation method of accounting.

F-4

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS

(Unaudited)

Under this method, an Investee company’s balance sheet and results of operations are reflected within the Company’s financial statements. All significant intercompany accounts and transactions have been eliminated. Upon dilution of control below 50% and the loss of effective control, the accounting method is adjusted to the equity or cost method of accounting, as appropriate, for subsequent periods.

Financial reporting by the Company’s subsidiaries is consolidated into one set of financial statements for the Company.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires the Company to make estimates and assumptions that affect the amounts reported in the consolidated/carve out financial statements and accompanying notes. Actual results could differ from those estimates.

Estimates made in preparing the consolidated/carve out financial statements include, among other things, estimates of the proved gas and oil reserve volumes used in calculating depletion, depreciation and amortization expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment write-down; and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Future changes in the assumptions used could have a significant impact on reported results in future periods.

Basis of Accounting

The Company’s financial statements are prepared using the accrual method of accounting. Revenues are recognized when earned and expenses when incurred.

Revenue Recognition

Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties.

Cash Equivalents

For purposes of the financial statements, the Company considers investments in all highly liquid instruments with original maturities of three months or less at date of purchase to be cash equivalents.

Uninsured Cash Balances

The Company maintains its cash balances at several financial institutions. Accounts at the institutions are insured by the Federal Deposit Insurance Corporation up to $100,000. The Company’s cash balances typically are in excess of this amount.

Restricted Cash

Restricted cash represents cash pledged to support reimbursement obligations under outstanding letters of credit.

Accounts Receivable

The Company conducts its operations in the States of Kansas and Oklahoma and operates exclusively in the oil and natural gas industry. The Company’s joint interest and oil and natural gas sales receivables are generally unsecured; however, the Company has not experienced any significant losses to date. Receivables are recorded at the estimate of amounts due based upon the terms of the related agreements.

Management periodically assesses the Company’s accounts receivable and establishes an allowance for estimated uncollectible amounts. Accounts determined to be uncollectible are charged to operations when that determination is made.

F-5

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS

(Unaudited)

Inventory

Inventory, which is included in current assets, includes tubular goods and other lease and well equipment which the Company plans to utilize in its ongoing exploration and development activities and is carried at the lower of cost or market using the specific identification method.

Concentration of Credit Risk

A significant portion of the Company’s and the Predecessor’s liquidity is concentrated in cash and derivative contracts that enable the Company to hedge a portion of its exposure to price volatility from producing oil and natural gas. These arrangements expose the Company to credit risk from its counterparties. The Company’s accounts receivable are primarily from purchasers of oil and natural gas products. Natural gas sales to one purchaser (ONEOK Energy Marketing and Trading Company) accounted for more than 99% of total oil and natural gas revenues for the three months ended March 31, 2008. Natural gas sales to two purchasers (ONEOK and Tenaska Marketing Ventures) accounted for 70% and 30% of total natural gas revenues for the three months ended March 31, 2007.

The industry concentration has the potential to impact the Company’s overall exposure to credit risk, either positively or negatively, in that the Company’s customers may be similarly affected by changes in economic, industry or other conditions.

Oil and Natural Gas Properties

The Company follows the full cost method of accounting for oil and natural gas properties, prescribed by the Securities and Exchange Commission (“SEC”). Under the full cost method, all acquisition, exploration, and development costs are capitalized. The Company capitalizes internal costs including: salaries and related fringe benefits of employees directly engaged in the acquisition, exploration and development of oil and natural gas properties, as well as other directly identifiable general and administrative costs associated with such activities.

All capitalized costs of oil and natural gas properties, including the estimated future costs to develop proved reserves, are amortized on the units-of-production method using estimates of proved reserves. The costs of unproved properties are excluded from amortization until the properties are evaluated. The Company reviews all of its unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred. Unevaluated properties are assessed individually when individual costs are significant.

The Company reviews the carrying value of its oil and natural gas properties under the full-cost accounting rules of the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues less estimated future expenditures to be incurred in developing and producing the proved reserves, plus the cost of properties not being amortized, less any related income tax effects. In calculating future net revenues, current prices and costs used are those as of the end of the appropriate quarterly period. Two primary factors impacting this test are reserve levels and current prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of oil and natural gas reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. Under SEC regulations, the excess above the ceiling is not expensed (or is reduced) if, subsequent to the end of the period, but prior to the release of the financial statements, oil and natural gas prices increase sufficiently such that an excess above the ceiling would have been eliminated (or reduced) if the increased prices were used in the calculations. No impairment is reflected in the Company’s financial statements at March 31, 2008 and December 31, 2007.

F-6

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS

(Unaudited)

Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between the capitalized costs and proved reserves of oil and natural gas, in which case the gain or loss is recognized in income.

Other Property and Equipment

Other property and equipment are stated at cost. Depreciation is calculated using the straight-line method for financial reporting purposes and accelerated methods for income tax purposes.

The estimated useful lives are as follows:

	•		Buildings: 25 years

	•		Equipment: 10 years

	•		Vehicles: 7 years

Repairs and maintenance are charged to operations when incurred and improvements and renewals are capitalized.

Debt Issue Costs

Included in other assets are costs associated with bank credit facilities. The remaining unamortized debt issue costs at March 31, 2008 and December 31, 2007 totaled $3.4 million and $3.5 million, respectively, and are being amortized over the life of the credit facilities.

Other Dispositions

Upon disposition or retirement of property and equipment other than oil and natural gas properties, the cost and related accumulated depreciation are removed from the accounts and the gain or loss thereon, if any, is credited or charged to income.

Marketable Securities

In accordance with Statement of Financial Accounting Standards (“SFAS”) 115, Accounting for Certain Investments in Debt and Equity Securities , the Company classifies its investment portfolio according to the provisions of SFAS 115 as either held to maturity, trading, or available for sale. At March 31, 2008 and December 31, 2007, the Company did not have any investments in its investment portfolio classified as available for sale and held to maturity.

Income Taxes

We are not a taxable entity for federal income tax purposes. As such, we do not directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our consolidated statement of income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined as we do not have access to information about each partner’s tax attributes in us.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash, receivables, deposits, derivative contracts, accounts payable, accrued expenses and notes payable. The carrying amount of cash, receivables, deposits, accounts payable and accrued expenses approximates fair value because of the short-term nature of those instruments. The derivative contracts are not designated as hedges, and therefore, are recorded at fair value. The carrying amounts for notes payable approximate fair value due to the variable nature of the interest rates of the notes payable.

F-7

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS

(Unaudited)

Accounting for Derivative Instruments and Hedging Activities

The Company uses derivative to hedge against changes in cash flows related to product price, as opposed to their use for trading purposes. SFAS 133, Accounting for Derivative Instruments and Hedging Activities, requires that all derivatives be recorded on the balance sheet at fair value. None of our derivative instruments are designated as hedges. Accordingly, we record all derivative instruments in the consolidated balance sheet at fair value with changes in fair value recognized in earnings as they occur. Both realized and unrealized gains and losses associated with derivative financial instruments are currently recognized in other income (expense) as they occur.

Asset Retirement Obligations

The Company has adopted FASB’s SFAS 143, Accounting for Asset Retirement Obligations . SFAS 143 requires companies to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement.

We own oil and gas properties that require expenditures to plug and abandon the wells when the oil and gas reserves in the wells are depleted. These expenditures are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired). Asset retirement obligations are recorded as a liability at their estimated present value at the asset’s inception, with the offsetting increase to property cost. Periodic accretion expense of the estimated liability is recorded in the consolidated statements of operations.

Net Income per Limited Partner Unit

The Company calculates net income per limited partner unit in accordance with Emerging Issues Task Force 03-06, Participating Securities and the Two-Class Method under FASB Statement No. 128 (“EITF 03-06”). EITF 03-06 requires that in any accounting period where the Company’s aggregate net income exceeds its aggregate distribution for such period, it is required to present earnings per unit as if all of the earnings for the periods were distributed, regardless of whether those earnings would actually be distributed during a particular period from an economic or practical perspective.

Business Segment Reporting

The Company operates in one reportable segment engaged in the exploitation, development and production of oil and natural gas properties and all of its operations are located in the United States.

F-8

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

Allocation of Costs

The accompanying restated carve out financial statements of the Predecessor have been prepared in accordance with SAB Topic 1-B. These rules require allocations of costs for salaries and benefits, depreciation, rent, accounting, and legal services, and other general and administrative expenses. QRCP has allocated general and administrative expenses to the Predecessor based on time and other costs required to properly manage the assets. In management’s estimation, the allocation methodologies used are reasonable and result in an allocation of the cost of doing business borne by QRCP on behalf of the Predecessor; however, these allocations may not be indicative of the cost of future operations or the amount of future allocations.

Historical financial statements of the Cherokee Basin Operations for the three months ended March 31, 2007 are presented. The historical financial statements were prepared as follows:

	•		Revenues include all revenues earned by the Cherokee Basin Operations, before elimination of intercompany sales with QRCP and its subsidiaries. Pursuant to the midstream services agreement with an affiliate of the Company, Bluestem Pipeline, LLC (“Bluestem”), for 2007 the fee for gathering, dehydration and treating services was $0.50 per MMBtu of gas and $1.10 per MMBtu of gas for compression services, subject to annual adjustment. Please read Note 12 — Related Party Transactions.

	•		Certain common expenses of QRCP’s operations and the Cherokee Basin Operations were treated as follows:

	•		general and administrative expenses associated with the pipeline operations were eliminated;

	•		costs associated with the salt water disposal system, which were previously reported in Bluestem operations prior to the formation of Quest Midstream in December 2006, were allocated to the Cherokee Basin Operations; and

	•		third party costs incurred at the QRCP level that are clearly identifiable as Cherokee Basin Operations costs, such as insurance premiums related to the Cherokee Basin Operations and legal fees of outside counsel related to contracts entered into or claims made by or against the Cherokee Basin Operations and salaries and benefits of Cherokee Basin Operations executives paid by QRCP, were allocated to the Cherokee Basin Operations.

	•		Non-producing acreage located outside of the Cherokee Basin and not transferred to the Company was eliminated from the balance sheet and related expenses were eliminated.

	•		To the extent that the common expenses described above were charged to the Cherokee Basin Operations in the past, the reduction in expenses was retroactively reflected with the offsetting debit to partners’ equity.

	•		Since the Company is not subject to entity level income taxes, no allocation of income taxes or deferred income taxes was reflected in the financial statements.

	•		Derivative transactions remained with the Cherokee Basin Operations.

	•		Management’s estimates of the expenses of the Cherokee Basin Operations on a stand-alone basis were not expected to be significantly different from those reflected in the statements.

Earnings per Unit

During the three months ended March 31, 2007, the Cherokee Basin Operations were wholly-owned by QRCP. Accordingly, earnings per unit have not been presented for that period.

Recently Issued Accounting Standards

The Financial Accounting Standards Board recently issued the following standards which the Company reviewed to determine the potential impact on its financial statements upon adoption.

On February 6, 2008, the FASB issued Financial Staff Position FAS 157-2, “Effective Date of FASB Statement No. 157.” This Staff Position delays the effective date of SFAS 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The delay is intended to allow

F-9

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS

(Unaudited)

the FASB and constituents additional time to consider the effect of various implementation issues that have arisen, or that may arise, from the application of SFAS 157.

The remainder of SFAS 157 was adopted by us effective for fiscal years beginning after November 15, 2007. The adoption of SFAS 157 did not have an impact on the Company’s financial position, results of operations, or cash flows.

In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”), an amendment of SFAS 115. SFAS 159 addresses how companies should measure many financial instruments and certain other items at fair value. The objective is to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS 159 is effective for fiscal years beginning after November 15, 2007, with earlier adoption permitted. SFAS 159 had been adopted and did not have a material impact on the Company’s financial position, results of operations, or cash flows.

In December 2007, the FASB issued SFAS 141R (revised 2007), “Business Combinations.” Although this statement amends and replaces SFAS 141, it retains the fundamental requirements in SFAS 141 that (i) the purchase method of accounting be used for all business combinations; and (ii) an acquirer be identified for each business combination. SFAS 141R defines the acquirer as the entity that obtains control of one or more businesses in the business combination and establishes the acquisition date as the date that the acquirer achieves control. This Statement applies to all transactions or other events in which an entity (the acquirer) obtains control of one or more businesses (the acquiree), including combinations achieved without the transfer of consideration; however, this Statement does not apply to a combination between entities or businesses under common control. Significant provisions of SFAS 141R concern principles and requirements for how an acquirer (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 with early adoption not permitted. Management is assessing the impact of the adoption of SFAS 141R.

In December 2007, the FASB issued SFAS 160, “ Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51 ”. The objective of this statement is to improve the relevant, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements related to noncontrolling or minority interests. The effective date for this Statement is for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 with earlier adoption being prohibited. Adoption of this Statement will change the method in which minority interests are reflected on the Company’s consolidated financial statements and will add some additional disclosures related to the reporting of minority interests. Management is assessing the impact of the adoption of SFAS 160.

In March 2008, the FASB issued SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities" . The objective of this statement is to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entity’s financial position, financial performance, and cash flows. The effective date for this statement is for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. Management is assessing the impact of the adoption of SFAS 161.

4. Equity-Based Compensation

The General Partner granted 30,000 bonus units to its independent directors during the three months ended March 31, 2008. The units are subject to vesting with 25% of the units immediately vested and one-third of the remaining units vesting equally on each of the first three anniversaries of the date of the grant. The fair value of the unit awards granted is recognized over the applicable vesting period as compensation expense. Compensation expense amounts are recognized in general and administrative expenses or capitalized to oil and gas properties. In addition, the directors are entitled to quarterly cash distribution equivalents equal to the number of unvested bonus units and the amount of the cash distribution that the Company pays per common unit.

For the three months ended March 31, 2008, the Company did not capitalize any of the value associated with the bonus unit grants. The value of the bonus unit grants included in general and administrative expenses for the three months ended March 31, 2008 was $17,000.

F-10

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS

(Unaudited)

5. Acquisition

Quest Cherokee 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. The properties have estimated proved reserves of 712,000 barrels, all of which are proved developed producing. In addition, Quest Cherokee entered into crude oil swaps for approximately 80% of the estimated production from the property’s proved developed producing reserves at WTI-NYMEX prices per barrel of oil of approximately $96.00 in 2008, $90.00 in 2009, and $87.50 for 2010. The acquisition was financed with borrowings under Quest Cherokee’s credit facility.

6. Long-Term Debt

Long-term debt consists of the following:


	March 31, 2008		December 31, 2007
	*($ in thousands)*
Senior credit facility	$	123,000	$	94,000
Other notes payable		484		708

Total long-term debt		123,484		94,708
Less — current maturities		448		666

Total long-term debt, net of current maturities	$	123,036	$	94,042

The aggregate scheduled maturities of notes payable and long-term debt for the period ending March 31, 2013 and thereafter were as follows as of March 31, 2008 (assuming no payments were made on the revolving credit facility prior to its maturity) (dollars in thousands):


2009	$	14
2010		123,005
2011		6
2012		7
2013		4
Thereafter		—

	$	123,036

Credit Facility

Quest Cherokee is a party to an Amended and Restated Credit Agreement dated as of November 15, 2007 with Royal Bank of Canada, as administrative agent and collateral agent (“RBC”), KeyBank National Association, as documentation agent, and the lenders party thereto. The Company is a guarantor of the credit agreement. See Note 4 to the financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007 (the 2007 Form 10-K) for a more detailed description of the material terms of the credit agreement. As of March 31, 2008, the borrowing base under the credit agreement was $160 million and the amount borrowed under the credit agreement was $123 million. The weighted average interest rate under the credit agreement for the three months ended March 31, 2008 was 6.88%. See Note 13 — Subsequent Events for a description of the amendments to the credit agreement that became effective April 15, 2008.

Other Long-Term Indebtedness

As of March 31, 2008, $484,000 of notes payable to banks and finance companies were outstanding. These notes are secured by equipment and vehicles, with payments due in monthly installments through October 2013 with interest rates ranging from 1.9% to 8.9% per annum.

F-11

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS

(Unaudited)

7. Financial Instruments and Hedging Activities

Oil and Natural Gas Hedging Activities

The Company seeks to reduce its exposure to unfavorable changes in oil and natural gas prices, which are subject to significant and often volatile fluctuation, through the use of fixed-price contracts. The fixed-price contracts are comprised of energy swaps and collars. These contracts allow the Company to predict with greater certainty the effective oil and natural gas prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. Collar structures provide for participation in price increases and decreases to the extent of the ceiling and floor prices provided in those contracts. As of March 31, 2008, fixed-price contracts are in place to hedge 42.9 MMBtu Bcf of estimated future natural gas production. Of this total volume, 13.7 MMBtu are hedged for 2008 and 29.2 MMBtu thereafter. As of March 31, 2008, fixed-price contracts are in place to hedge 93,000 Bbls of estimated future oil production. Of this total volume, 27,000 Bbls are hedged for 2008 and 66,000 Bbls thereafter.

For energy swap contracts, the Company receives a fixed price for the respective commodity and pays a floating market price, as defined in each contract (generally a regional spot market index or in some cases, New York Mercantile Exchange (“NYMEX”) future prices), to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. Oil and natural gas collars contain a fixed floor price (put) and ceiling price (call) (generally a regional spot market index or in some cases, NYMEX future prices). If the market price of oil or natural gas exceeds the call strike price or falls below the put strike price, then the Company receives the fixed price and pays the market price. If the market price of oil or natural gas is between the call and the put strike price, then no payments are due from either party.

The following table summarizes the estimated volumes, fixed prices, fixed-price sales and fair value attributable to the fixed-price contracts as of March 31, 2008.


	Nine Months
	Ending
	December 31,						Years Ending December 31,
	2008			2009			2010			2011		2012		Total
				*(dollars in thousands, except per MMBtu and Bbl data)*
Natural Gas Swaps:
Contract volumes (MMBtu)		8,458,725			14,629,200			12,499,060			—		2,000,004		37,586,989
Weighted average fixed price per MMBtu (1)	$	6.98		$	7.78		$	7.42		$	—	$	8.11	$	7.50
Fair value, net	$	(12,429	)	$	(11,212	)	$	(9,283	)	$	—	$	44	$	(32,880	)
Natural Gas Collars:
Contract volumes (MMBtu)
Floor		5,280,275			—			—			—		—		5,280,275
Ceiling		5,280,275			—			—			—		—		5,280,275
Weighted average fixed price per MMBtu (1)
Floor	$	6.54		$	—		$	—		$	—	$	—	$	6.54
Ceiling	$	7.53		$	—		$	—		$	—	$	—	$	7.53
Fair value, net	$	(12,602	)	$	—		$	—		$	—	$	—	$	(12,602	)
Total Natural Gas Contracts(2):
Contract volumes (MMBtu)		13,739,000			14,629,200			12,499,060			—		2,000,004		42,867,264
Weighted average fixed price per MMBtu (1)	$	6.81		$	7.78		$	7.42		$	—	$	8.11	$	7.38
Fair value, net	$	(25,031	)	$	(11,212	)	$	(9,283	)	$	—	$	44	$	(45,482	)
Oil Swaps:
Contract volumes (Bbl)		27,000			36,000			30,000			—		—		93,000
Weighted average fixed price per Bbl (1)	$	95.92		$	90.07		$	87.50			—	$	—	$	90.94
Fair value, net	$	(97	)	$	(205	)	$	(188	)	$	—	$	—	$	(490	)


(1)		The prices to be realized for hedged production are expected to vary from the prices shown due to basis.

(2)		Does not include basis swaps with notional volumes by year, as follows: 2008: 4,716,000 MMBtu.

F-12

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS

(Unaudited)

Interest Rate Hedging Activities

At March 31, 2008, the Company had no outstanding interest rate cap or swap agreements.

Loss from Derivative Financial Instruments

Change in derivative fair value in the statements of operations for the three months ended March 31, 2008 and 2007 is comprised of the following:


	Successor			Predecessor
	Three Months Ended
	March 31,
	2008			2007
	($ in thousands)
Unrealized losses	$	(43,028	)	$	(14,541	)
Realized (losses) gains		(1,211	)		994

Loss from derivative financial instruments	$	(44,239	)	$	(13,547	)

Fair Value — 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 March 31, 2008 (in thousands):


									Netting and
	Level		Level			Level			Cash			Total Net Fair
At March 31, 2008	1		2			3			Collateral*			Value
Derivative financial instruments — assets	$	—	$	5		$	2,244		$	668		$	2,917
Derivative financial instruments — liabilities	$	—	$	(19,579	)	$	(28,642	)	$	(668	)	$	(48,889	)

Total	$	—	$	(19,574	)	$	(26,398	)	$	—		$	(45,972	)


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

Risk management assets and liabilities in the table above represent the current fair value of all open derivative positions, excluding those derivatives designated as “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 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):


Balance at beginning of year	$	3,444
Realized and unrealized gains included in earnings		(29,470	)
Purchases, sales, issuances, and settlements		(372	)
Transfers into and out of Level 3		—

Balance as of March 31, 2008	$	(26,398	)

F-13

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS

(Unaudited)

Credit Risk

Energy swaps, collars and basis swaps provide for a net settlement due to or from the respective party as discussed previously. The counterparties to the derivative contracts are financial institutions. Should a counterparty default on a contract, there can be no assurance that the Company would be able to enter into a new contract with a third party on terms comparable to the original contract. The Company has not experienced non-performance by its counterparties.

Cancellation or termination of a fixed-price contract would subject a greater portion of the Company’s oil or natural gas production to market prices, which, in a low price environment, could have an adverse effect on its future operating results. In addition, the associated carrying value of the derivative contract would be removed from the balance sheet.

Market Risk

The differential between the floating price paid under each energy swap or collar contract and the price received at the wellhead for the Company’s production is termed “basis” and is the result of differences in location, quality, contract terms, timing and other variables. For instance, some of the Company’s fixed price contracts are tied to commodity prices on the NYMEX, that is, the Company receives the fixed price amount stated in the contract and pays to its counterparty the current market price for gas as listed on the NYMEX. However, due to the geographic location of the Company’s natural gas assets and the cost of transporting the natural gas to another market, the amount that the Company receives when it actually sells its natural gas is generally based on the Southern Star Central TX/KS/OK (“Southern Star”) first of month index, with a small portion being sold based on the daily price on the Southern Star index. The difference between natural gas prices on the NYMEX and the price actually received by the Company is referred to as a basis differential. Typically, the price for natural gas on the Southern Star first of the month index is less than the price on the NYMEX due to the more limited demand for natural gas on the Southern Star first of the month index. The crude oil production for which we have entered into swap agreements is sold at a contract price based on the average daily settling price of NYMEX less $1.10/Bbl, which eliminates our exposure to changing differentials on this production. This contract runs through March 2009 with automatic extensions thereafter unless terminated by either party.

The effective price realizations that result from the fixed-price contracts are affected by movements in this basis differential. Basis movements can result from a number of variables, including regional supply and demand factors, changes in the portfolio of the Company’s fixed-price contracts and the composition of its producing property base. Basis movements are generally considerably less than the price movements affecting the underlying commodity, but their effect can be significant. Recently, the basis differential has been increasingly volatile and has on occasion resulted in the Company receiving a net price for its oil and natural gas that is significantly below the price stated in the fixed price contract.

Changes in future gains and losses to be realized in oil and natural gas sales upon cash settlements of fixed-price contracts as a result of changes in market prices for oil and natural gas are expected to be offset by changes in the price received for hedged oil and natural gas production.

F-14

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

8. Asset Retirement Obligations

The Company has adopted SFAS 143, Accounting for Asset Retirement Obligations . The following table provides a roll forward of the asset retirement obligations for the three months ended March 31, 2008 and 2007:


	Successor			Predecessor
	Three Months Ended
	March 31,
	2008			2007
	*($ in thousand)*
Asset retirement obligation beginning balance	$	1,700		$	1,410
Liabilities incurred		28			42
Liabilities settled		(8	)		(1	)
Accretion expense		46			26
Revisions in estimated cash flows		290			—

Asset retirement obligation ending balance	$	2,056		$	1,477

9. Partners’ Equity

On January 21, 2008, the board of directors of the General Partner declared a $0.2043 per unit distribution for the fourth quarter of 2007 on all common and subordinated units. This distribution was based on the initial quarterly distribution rate of $0.40 per unit, but was prorated for the actual number of days the units were outstanding. The distribution was paid on February 14, 2008 to unitholders of record at the close of business on February 7, 2008. The aggregate amount of the distribution was $4.4 million.

On April 25, 2008, the board of directors of the General Partner declared a $0.41 per unit distribution for the first quarter of 2008 on all common and subordinated units. The distribution will be paid on May 15, 2008 to unitholders of record at the close of business on May 5, 2008. The aggregate amount of the distribution will be $8.85 million.

10. Net Loss Per Limited Partner Unit

The computation of net loss per limited partner unit is based on the weighted average number of common and subordinated units outstanding during the year. Basic and diluted net loss per limited partner unit is determined by dividing net loss, after deducting the amount allocated to the general partner interest (including its incentive distribution in excess of its 2% interest), by the weighted average number of outstanding limited partner units during the period in accordance with Emerging Issues Task Force 03-06, Participating Securities and the Two-Class Method under FASB Statement No. 128 .

F-15

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

The following sets forth the net loss allocation using this method:


	Successor
	Three Months Ended
	March 31, 2008
				Per Limited
	$			Partner Unit
Net loss	$	(40,765	)
Less: General partner’s 2% interest in net loss		815

Net loss available for limited partners	$	(39,950	)	$	(1.89	)

The board of directors of the General Partner did not declare a cash distribution during the period January 1, 2008 through March 31, 2008 which would result in an incentive distribution to the General Partner as indicated above.

11. Commitments and Contingencies

Quest Resource Corporation, Bluestem Pipeline, LLC, STP, Inc., Quest Cherokee, LLC, Quest Energy Service, LLC, Quest Midstream Partners, LP, Quest Midstream GP, LLC, and STP Cherokee, Inc. (now STP Cherokee, LLC) have been named Defendants in a lawsuit filed by Plaintiffs, Eddie R. Hill, et al . in the District Court for Craig County, Oklahoma (Case No. CJ-2003-30). Plaintiffs are royalty owners who are alleging underpayment of royalties owed to them. Plaintiffs also allege, among other things, that Defendants have engaged in self-dealing and breached fiduciary duties owed to Plaintiffs, and that Defendants have acted fraudulently toward the Plaintiffs. Plaintiffs also allege that the gathering fees and related charges should not be deducted in paying royalties. Plaintiffs’ claims relate to a total of 84 wells located in Oklahoma and Kansas. Plaintiffs are seeking unspecified actual and punitive damages. Defendants intend to defend vigorously against Plaintiffs’ claims.

STP, Inc., STP Cherokee, Inc. (now STP Cherokee, LLC), Bluestem Pipeline, LLC, Quest Cherokee, LLC, and Quest Energy Service, LLC (improperly named Quest Energy Services, LLC) have been named defendants in a lawsuit by Plaintiffs John C. Kirkpatrick and Suzan M. Kirkpatrick in the District Court for Craig County (Case No. CJ-2005-143). Plaintiffs allege that STP, Inc., et al. , sold natural gas from wells owned by the Plaintiffs without providing the requisite notice to Plaintiffs. Plaintiffs further allege that Defendants failed to include deductions on the check stubs of Plaintiffs in violation of state law and that Defendants deducted for items other than compression in violation of the lease terms. Plaintiffs assert claims of actual and constructive fraud and further seek an accounting stating that if Plaintiffs have suffered any damages for failure to properly pay royalties, Plaintiffs have a right to recover those damages. Plaintiffs have not quantified their alleged damages. Discovery is ongoing and Defendants intend to defend vigorously against Plaintiffs’ claims.

Quest Cherokee Oilfield Services, LLC has been named in this lawsuit filed by Plaintiffs Segundo Francisco Trigoso and Dana Jara De Trigoso in the District Court of Oklahoma County, Oklahoma (Case No. CJ-2007-11079). Plaintiffs allege that Plaintiff Segundo Trigoso was injured while working for Defendant on September 29, 2006 and that such injuries were intentionally caused by Defendant. Plaintiffs seek unspecified damages for physical injuries, emotional injuries, loss of consortium and pain and suffering. Plaintiffs also seek punitive damages. Defendant intends to defend vigorously against Plaintiffs’ claims.

Quest Cherokee and Bluestem were named as defendants in a lawsuit (Case No. 04-C-100-PA) filed by plaintiff Central Natural Resources, Inc. 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. Plaintiff is seeking quiet title and an equitable accounting for the revenues from the coal bed methane gas produced. Plaintiff has alleged that Bluestem converted the gas and seeks an accounting for all gas purchased by Bluestem from the wells in issue. Quest Cherokee contends it has valid leases with the owners of the coal bed methane gas rights. The issue is whether the coal bed methane gas is owned by the owner of the coal rights or by the owners of the gas rights. If Quest Cherokee prevails on that issue, then the plaintiff’s claims against Bluestem fail. All issues relating to ownership of the coal bed methane gas and damages have been bifurcated. Cross motions for summary judgment on the ownership of the coal bed methane were filed by Quest Cherokee and the plaintiff, with summary judgment being awarded in Quest Cherokee’s favor. The plaintiff has appealed the summary judgment and that appeal is pending. Quest Cherokee and Bluestem intend to defend vigorously against these claims.

F-16

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS

(Unaudited)

Quest Cherokee was named as a defendant in a lawsuit (Case No. CJ-06-07) filed by plaintiff Central Natural Resources, Inc. on January 17, 2006, in the District Court of Craig County, Oklahoma. Bluestem is not a party to this lawsuit. 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 is ongoing. Quest Cherokee intends to defend vigorously against these claims.

Quest Cherokee was named as a defendant in a lawsuit (Case No. 05 CV 41) filed by Labette Energy, LLC in the district court of Labette County, Kansas. Plaintiff claims to own a 3.2 mile gas gathering pipeline in Labette County, Kansas, and that Quest Cherokee used that pipeline without plaintiff’s consent. Plaintiff also contends that the defendants slandered its alleged title to that pipeline and suffered damages from the cancellation of their proposed sale of that pipeline. Plaintiff claims that they were damaged in the amount of $202,375. Discovery in that case is ongoing and Quest Cherokee intends to defend vigorously against the plaintiff’s claims.

Quest Cherokee was named as a defendant in a putative class action lawsuit (Case No. 07-1225-MLB) filed by several royalty owners in the U.S. District Court for the District of Kansas. The plaintiffs have not yet filed a motion asking the court to certify the class and the court has not determined that the case may properly proceed as a class action. 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.

Quest Cherokee has been named as a defendant in several lawsuits in which the plaintiff claims that an oil and gas lease owned and operated by Quest Cherokee has 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, and Wilson 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. The plaintiffs in those cases are generally seeking statutory damages of $100 per lease, attorneys’ fees, and a judicial declaration that Quest Cherokee’s leases have terminated. As of May 7, 2008, the total amount of acreage covered by the leases at issue in these lawsuits was approximately 7,481 acres. Quest Cherokee intends to vigorously defend against those claims.

Quest Cherokee was named in an Order to Show Cause issued by the Kansas Corporation Commission (the “KCC”) (KCC Docket No. 07-CONS-155-CSHO) filed on February 23, 2007. The KCC has ordered Quest Cherokee to demonstrate why it should not be held responsible for plugging 22 abandoned oil wells on a gas lease owned and operated by Quest Cherokee in Wilson County, Kansas. Quest Cherokee denies that it is legally responsible for plugging the wells in issue and intends to vigorously defend against the KCC’s claims.

Quest Cherokee was named as a defendant in two lawsuits (Case No. 07-CV-141 and Case No. 08-CV-20) filed in Neosho County District Court by Richard Winder, d/b/a Winder Oil Company. Plaintiff claims to own an oil and gas lease covering lands upon which Quest Cherokee also claims to own an oil and gas lease and upon which Quest Cherokee has drilled two producing wells. Plaintiff claims that his lease is prior and superior to Quest Cherokee’s leases and seeks damages for trespass and conversion. Quest Cherokee contends that plaintiffs leases have expired by their terms and that Quest Cherokee’s leases are valid. Discovery in that case is ongoing. Quest Cherokee intends to vigorously defend against the Plaintiff’s claims.

The Company, from time to time, may be subject to legal proceedings and claims that arise in the ordinary course of its business. Although no assurance can be given, management believes, based on its experiences to date, that the ultimate resolution of such items will not have a material adverse impact on the Company’s business, financial position or results of operations. Like other

F-17

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS

(Unaudited)

oil and natural gas producers and marketers, the Company’s 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.

12. Related Party Transactions

The Company employs its own field employees and first level supervisor. The management level and general and administrative employees supporting the operations of the Company are employees of Quest Energy Service (“Quest Energy Service”), a Company affiliate. In addition to employee payroll-related expenses, QRCP incurred general and administrative expenses related to leasing of office space and other corporate overhead type expenses during the period covered by these financial statements. A portion of the consolidated general and administrative and indirect lease operating overhead expenses of QRCP, determined based on time and other costs required to properly manage the assets, has been allocated to the Company and included in the accompanying statements of operations for each of the periods presented.

Midstream Services Agreement . QRCP controls Quest Midstream through its 85% ownership of Quest Midstream’s general partner and its ownership of approximately 35% of Quest Midstream’s limited partner interests. Quest Midstream owns and operates an over 1,800 mile gas gathering pipeline system in the Cherokee Basin. Effective November 15, 2007, QRCP assigned all of its rights in that certain Midstream Services and Gas Dedication Agreement (“Midstream Services Agreement”) to the Company. Under the Midstream Services Agreement, Quest Midstream gathers and provides certain midstream services to the Company for all gas produced from the Company’s wells in the Cherokee Basin that are connected to Quest Midstream’s gathering system. The initial term of the Midstream Services Agreement expires on December 1, 2016, with two additional five-year renewal periods that may be exercised by either party upon 180 days’ notice. Under the Midstream Services Agreement, the Company pays Quest Midstream $0.51 per MMBtu of gas for gathering, dehydration and treating services and $1.13 per MMBtu of gas for compression services, subject to annual adjustment based on changes in gas prices and the producer price index. Such fees are subject to renegotiation upon the exercise of each five-year extension period. In addition, at any time after each five year anniversary of the date of the midstream services agreement, each party will have a one-time option to elect to renegotiate the fees and/or the basis for the annual adjustment to the fees if the party believes there has been a material change to the economic returns or financial condition of either party. If the parties are unable to agree on the changes, if any, to be made to such terms, then the parties will enter into binding arbitration to resolve any dispute with respect to such terms.

Under the terms of some of the Cherokee Basin Operations gas leases, the Company may not be able to charge the full amount of these fees to royalty owners, which would increase the average fees per MMBtu that the Company effectively pays under the Midstream Services Agreement.

Quest Midstream has an exclusive option for sixty days to connect to its gathering system all of the gas wells that the Company develops in the Cherokee Basin. In addition, Quest Midstream is required to connect to its gathering system, at its expense, any new gas wells that the Company completes in the Cherokee Basin if Quest Midstream would earn a specified internal rate of return from those wells. This rate of return is subject to renegotiation once after the fifth anniversary of the agreement and once during each renewal period at the election of either party. The Midstream Services Agreement also requires the drilling of a minimum of 750 new wells in the Cherokee Basin during the two year period ending December 1, 2008.

In addition, Quest Midstream agreed to install the saltwater disposal lines for the Company’s gas wells connected to Quest Midstream’s gathering system for a fee of $1.25 per linear foot and connect such lines to the Company’s saltwater disposal wells for a fee of $1,000 per well, subject to an annual adjustment based on changes in the Employment Cost Index for Natural Resources, Construction, and Maintenance. For 2008, the fees are $1.29 per linear foot to install saltwater disposal lines and $1,030 per well to connect such lines to the Company’s saltwater disposal wells.

Management Services Agreement. The Company and Quest Energy Service are parties to a management services agreement, dated November 15, 2007, pursuant to which Quest Energy Service provides the Company with legal, information technology, accounting, finance, insurance, tax, property management, engineering, administrative, risk management, corporate development, commercial and marketing, treasury, human resources, audit, investor relations and acquisition services in respect of opportunities for the Company to acquire long-lived, stable and proved oil and gas reserves.

The Company reimburses Quest Energy Service for the reasonable costs of the services it provides to the Company. The employees of Quest Energy Service also manage the operations of QRCP and Quest Midstream and will be reimbursed by QRCP and

F-18

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS

(Unaudited)

Quest Midstream for general and administrative services incurred on their respective behalf. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for the Company or on its behalf, and expenses allocated to Quest Energy Service by its affiliates. The General Partner is entitled to determine in good faith the expenses that are allocable to the Company.

The General Partner has the right and the duty to review the services provided, and the costs charged, by Quest Energy Service under the management services agreement. The General Partner may in the future cause the Company to hire additional personnel to supplement or replace some or all of the services provided by Quest Energy Service, as well as employ third-party service providers. If the Company were to take such actions, they could increase the overall costs of the Company’s operations.

The management services agreement is not terminable by the Company without cause so long as QRCP controls the General Partner. Thereafter, the agreement is terminable by either the Company or Quest Energy Service upon six months’ notice. The management services agreement is terminable by the Company or QRCP upon a material breach of the agreement by the other party and failure to remedy such breach for 60 days (or 30 days in the event of nonpayment) after receiving notice of the breach.

Quest Energy Service will not be liable to the Company for its performance of, or failure to perform, services under the management services agreement unless its acts or omissions constitute gross negligence or willful misconduct.

Omnibus Agreement. The Company and QRCP are parties to an omnibus agreement, dated November 15, 2007, which governs the Company’s relationship with QRCP and its subsidiaries with respect to certain matters not governed by the management services agreement.

Under the omnibus agreement, QRCP and its subsidiaries agreed to give the Company a right to purchase any natural gas or oil wells or other natural gas or oil rights and related equipment and facilities that they acquire within the Cherokee Basin, but not including any midstream or downstream assets. Except as provided above, QRCP is not restricted, under either the Company’s partnership agreement or the omnibus agreement, from competing with the Company and may acquire, construct or dispose of additional gas and oil properties or other assets in the future without any obligation to offer the Company the opportunity to acquire those assets.

Under the omnibus agreement, QRCP will indemnify the Company for three years after November 15, 2007 against certain potential environmental claims, losses and expenses associated with the operation of the assets occurring before the closing date of the offering. Additionally, QRCP will indemnify the Company for losses attributable to title defects (for three years after November 15, 2007), retained assets and income taxes attributable to pre-closing operations (for the applicable statute of limitations). QRCP’s maximum liability for the environmental indemnification obligations will not exceed $5.0 million and QRCP will not have any indemnification obligation for environmental claims or title defects until the Company’s aggregate losses exceed $500,000. QRCP will have no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after November 15, 2007. The Company has agreed to indemnify QRCP against environmental liabilities related to the Company’s assets to the extent QRCP is not required to indemnify the Company. The Company also will indemnify QRCP for all losses attributable to post-November 15, 2007 operations of the assets contributed to the Company, to the extent not subject to QRCP’s indemnification obligations.

Any or all of the provisions of the omnibus agreement, other than the indemnification provisions described above, are terminable by QRCP at its option if the General Partner is removed without cause and units held by the General Partner and its affiliates are not voted in favor of that removal. The omnibus agreement will also terminate in the event of a change of control of the Company or the General Partner.

Midstream Omnibus Agreement. The Company is subject to a midstream omnibus agreement dated as of December 22, 2006, among Quest Midstream, Quest Midstream’s general partner, Quest Midstream’s operating subsidiary and QRCP so long as the Company is an affiliate of QRCP and QRCP or any of its affiliates controls Quest Midstream.

The midstream omnibus agreement restricts the Company from engaging in the following businesses (each of which is referred to as a “Restricted Business”):

	•		the gathering, treating, processing and transporting of gas in North America;

	•		the transporting and fractionating of gas liquids in North America;

F-19

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

	•		any other midstream activities, including but not limited to crude oil storage, transportation, gathering and terminaling;

	•		constructing, buying or selling any assets related to the foregoing businesses; and

	•		any line of business other than those described in the preceding bullet points that generates “qualifying income”, within the meaning of Section 7704(d) of the Code, other than any business that is primarily engaged in the exploration for and production of oil or gas and the sale and marketing of gas and oil derived from such exploration and production activities.

If a business described in the last bullet point above has been offered to Quest Midstream and it has declined the opportunity to purchase that business, then that line of business is no longer considered a Restricted Business.

The following are not considered a Restricted Business:

	•		the ownership of a passive investment of less than 5% in an entity engaged in a Restricted Business;

	•		any business in which Quest Midstream permits the Company to engage;

	•		the ownership or operation of assets used in a Restricted Business if the value of the assets is less than $4 million; and

	•		any business that the Company has given Quest Midstream the option to acquire and it has elected not to purchase.

Subject to certain exceptions, if the Company were to acquire any midstream assets in the future pursuant to the above provisions, then Quest Midstream will have a preferential right to acquire those midstream assets in the event of a sale or transfer of those assets by the Company.

If the Company acquires any acreage located outside the Cherokee Basin that is not subject to any existing agreement with an unaffiliated party to provide midstream services, Quest Midstream will have a preferential right to offer to provide midstream services to the Company in connection with wells to be developed by the Company on that acreage.

Contribution, Conveyance and Assumption Agreement. On November 15, 2007, the Company and QRCP entered into a contribution, conveyance and assumption agreement to effect, among other things, the transfer of QRCP’s Cherokee Basin Operations to the Company, the issuance of 3,201,521 common units and 8,857,981 subordinated units to QRCP and the issuance to the General Partner of 431,827 general partner units and the incentive distribution rights. The Company agreed to indemnify QRCP for liabilities arising out of or related to existing litigation relating to the assets, liabilities and operations located in the Cherokee Basin transferred to the Company.

13. Subsequent Events

On April 17, 2008, the Company and Quest Cherokee entered into an amendment to the Amended and Restated Credit Agreement with the Royal Bank of Canada, as administrative agent and collateral agent, Keybank National Association, as documentation agent, and the lenders party thereto (the “Amendment”). The Amendment changed the maturity date from November 15, 2012 to November 15, 2010, and increased the applicable rate at which interest will accrue by 1% to either LIBOR plus a margin ranging from 2.25% to 2.875% (depending on the utilization percentage) or the base rate plus a margin ranging from 1.25% to 1.875% (depending on the utilization percentage). The Amendment also eliminated the “accordion” feature in the credit agreement, which gave Quest Cherokee the option to request an increase in the aggregate revolving commitment from $250 million to $350 million. There was no commitment on the part of the lenders to agree to such a request.

F-20

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

(Unaudited)

14. 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 and 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/A for the quarter ended March 31, 2008, to which these consolidated financial statements form a part, includes our restated consolidated financial statements as of March 31, 2008 and for the three months ended March 31, 2008 and our Predecessor’s restated carve out financials for the three months ended March 31, 2007. The financial statements as of December 31, 2007 were restated in the 2008
Form 10-K.

Although the items listed below comprise the most significant errors (by dollar amount), numerous other errors were identified and restatement adjustments made. We have recorded restatement adjustments to properly reflect the amounts as of and for the periods affected. The tables below present previously reported partners’ equity, major restatement adjustments and restated partners’ equity as well as previously reported net loss, major restatement adjustments and restated net loss as of and for the periods indicated (in thousands):


	March 31, 2008
Partners’ equity as previously reported	$	184,584
A — Effect of the Transfers		(9,500	)
B — Reversal of hedge accounting		(2,725	)
C — Accounting for formation of Quest Cherokee		(15,102	)
D — Capitalization of costs in full cost pool		(27,595	)
E — Recognition of costs in proper periods		(957	)
F — Depreciation, depletion and amortization		11,429
G — Impairment of oil and gas properties		30,719
H — Other errors		3,823

Partners’ equity as restated	$	174,676


	Three Months Ended March 31,
	2008			2007
Net loss as previously reported	$	(17,346	)	$	(3,650	)
A — Effect of the Transfers		—			(500	)
B — Reversal of hedge accounting		(19,196	)		(14,079	)
C — Accounting for formation of Quest Cherokee		(3,659	)		(2,419	)
D — Capitalization of costs in full cost pool		583			(244	)
E — Recognition of costs in proper periods		(431	)		(345	)
F — Depreciation, depletion and amortization		(491	)		(480	)
G — Impairment of oil and gas properties		—			—
H — Other errors		(225	)		(1,046	)

Net loss as restated	$	(40,765	)	$	(22,763	)

F-21

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

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, cash and partners’ equity were overstated as of March 31, 2008, and loss from misappropriation of funds was understated and net income was overstated for the three months ended March 31, 2007.

(B) Hedge accounting was inappropriately applied for our commodity derivative instruments and the valuation of commodity derivative instruments was incorrectly computed. The fair value of the commodity derivative instruments previously reported were over stated by $0.8 million as of March 31, 2008. 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, current and long-term derivative financial instrument assets, current and long-term derivative financial instrument liabilities, accumulated other comprehensive income and partners’ equity were over/(under)stated as of March 31, 2008, and oil and gas sales and gain (loss) from derivative financial instruments were over/(under)stated for the three months ended March 31, 2008 and 2007.

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

(D) Certain general and administrative expenses unrelated to oil and gas production were inappropriately capitalized to oil and gas properties, and certain operating expenses were inappropriately capitalized to oil and gas properties being amortized. These items resulted in errors in valuation of the full cost pool, oil and gas production expenses and general and administrative expenses. As a result of these errors, oil and gas properties being amortized and partners’ equity were over/(under)stated as of March 31, 2008, and oil and gas production expenses and general and administrative expenses were over/(under)stated for the three months ended March 31, 2008 and 2007.

(E) Invoices were not properly accrued resulting in the understatement of accounts payable and numerous other balance sheet and income statement accounts. As a result of these errors, accounts receivable, other current assets, property and equipment, pipeline assets, properties being and not being amortized and partners’ equity were over/(under)stated as of March 31, 2008, and oil and gas production expenses, pipeline operating expenses and general and administrative expenses were over/(under)stated for the three months ended March 31, 2008 and 2007.

(F) 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, accumulated depreciation, depletion and amortization were over/(under)stated as of March 31, 2008, and depreciation, depletion and amortization expense was over/(under)stated for the three months ended March 31, 2008 and 2007.

F-22

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

(G) As a result of previously discussed errors relating to oil and gas properties and hedge accounting and errors relating to the treatment of deferred taxes, errors existed in our ceiling test calculations. As a result of these errors, we incorrectly recorded a $30.7 million impairment to our oil and gas properties during the year ended December 31, 2006.

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

F-23

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

(Unaudited)

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


	Three Months Ended March 31, 2008
	As
	Previously			Restatement			As
	Reported			Adjustments			Restated
Revenue:
Oil and gas sales	$	37,353		$	961		$	38,314
Other revenue (expense)		50			(50	)		—

Total revenues		37,403			911			38,314
Costs and expenses:
Oil and gas production		8,182			2,204			10,386
Transportation expense		8,663			—			8,663
General and administrative		2,458			640			3,098
Depreciation, depletion and amortization		9,511			1,189			10,700

Total costs and expenses		28,814			4,033			32,847
Operating income (loss)		8,589			(3,122	)		5,467
Other income (expense):
Loss from derivative financial instruments		(23,831	)		(20,408	)		(44,239	)
Miscellaneous other income		19			50			69
Interest expense		(2,140	)		61			(2,079	)
Interest income		17			—			17

Total other income (expense)		(25,935	)		(20,297	)		(46,232	)

Net loss	$	(17,346	)	$	(23,419	)	$	(40,765	)


General partner’s interest in net loss	$	(347	)	$	(468	)	$	(815	)

Limited partners’ interest in net loss	$	(16,999	)	$	(22,951	)	$	(39,950	)


Net loss per limited partner units – basic and diluted	$	(0.80	)	$	(1.09	)	$	(1.89	)


Weighted average limited partner units outstanding:
Common units (basic and diluted)		12,301,521			—			12,301,521

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

F-24

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

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


	Three Months Ended March 31, 2008
	As
	Previously			Restatement
	Reported			Adjustments			As Restated
Cash flows from operating activities:
Net loss	$	(17,346	)	$	(23,419	)	$	(40,765	)
Adjustments to reconcile net loss to cash (used in) provided by operations:
Depreciation, depletion and amortization		10,191			509			10,700
Change in derivative fair value		23,831			19,197			43,028
Unit awards granted to employees		—			12			12
Capital contributions for director fees		203			(203	)		—
Capital contributions for employees		868			(868	)		—
Amortization of loan origination fees		177			(57	)		120
Bad debt expense		—			26			26
(Gain) loss on sale of assets		(47	)		47			—
Change in assets and liabilities:
Accounts receivable		30			(27	)		3
Other receivables		(24	)		24			—
Other current assets		233			390			623
Other assets		(1,842	)		1,829			(13	)
Due from affiliates		(21,093	)		14,586			(6,507	)
Accounts payable		(1,989	)		2,174			185
Revenue payable		—			251			251
Accrued expenses		34			2,558			2,592
Other long-term liabilities		—			354			354

Net cash (used in) provided by operating activities		(6,774	)		17,383			10,609

Cash flows from investing activities:
Oil & gas property acquisition		(9,500	)		9,500			—
Equipment, development and leasehold costs		(19,261	)		(15,253	)		(34,514	)
Net additions to other property and equipment		(627	)		627			—

Net cash used in investing activities		(29,388	)		(5,126	)		(34,514	)

Cash flows from financing activities:
Proceeds from revolver note		29,000			—			29,000
Repayments of note borrowings		(223	)		(1	)		(224	)
Capital contributions (distributions)		(1,859	)		2,234			375
Distributions to unitholders		—			(4,411	)		(4,411	)
Syndication costs		(201	)		(64	)		(265	)
Refinancing costs		(71	)		71			—
Change in other long-term liabilities		86			(86	)		—

Net cash provided by financing activities		26,732			(2,257	)		24,475

Net (decrease) increase in cash		(9,430	)		10,000			570
Cash and cash equivalents, beginning of period		10,170			(10,001	)		169

Cash and cash equivalents, end of period	$	740		$	(1	)	$	739

F-25

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

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


	Three Months Ended March 31, 2008
	As
	Previously			Restatement
	Reported			Adjustments			As Restated
ASSETS
Current assets:
Cash and cash equivalents	$	740		$	(1	)	$	739
Restricted cash		1,205			—			1,205
Accounts receivable, trade		294			(237	)		57
Due from affiliates		29,726			(6,831	)		22,895
Other current assets		2,688			(220	)		2,468
Inventory		6,797			—			6,797
Current derivative financial instrument assets		223			2,009			2,232

Total current assets		41,673			(5,280	)		36,393
Property and equipment, net		17,057			266			17,323
Oil and gas properties under full cost method of accounting, net		318,183			(3,579	)		314,604
Other assets, net		3,420			—			3,420
Long-term derivative financial instrument assets		599			86			685

Total assets	$	380,932		$	(8,507	)	$	372,425

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	13,012		$	4,569		$	17,581
Accrued expenses		12,084			(8,817	)		3,267
Due to affiliates		—			2,472			2,472
Current portion of notes payable		448			—			448
Current derivative financial instrument liabilities		28,745			3,638			32,383

Total current liabilities		54,289			1,862			56,151
Non-current liabilities:
Long-term derivative financial instrument liabilities		17,203			(697	)		16,506
Asset retirement obligation		1,820			236			2,056
Notes payable		123,036			—			123,036

Total liabilities		196,348			1,401			197,749

Commitments and contingencies
Partners’ equity:
Partner’s equity		201,833			(201,833	)		—
Accumulated other comprehensive income (loss)		(17,249	)		17,249			—
Common unitholders		—			136,707			136,707

Subordinated unitholder — affiliate		—			36,217			36,217

General partner — affiliate		—			1,752			1,752

Total partners’ equity		184,584			(9,908	)		174,676

Total liabilities and partners’ equity	$	380,932		$	(8,507	)	$	372,425

F-26

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

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


	Three Months Ended March 31, 2007
	As
	Previously			Restatement
	Reported			Adjustments			As Restated
Revenue:
Oil and gas sales	$	25,549		$	(575	)	$	24,974
Other revenue (expense)		(13	)		13			—

Total revenues		25,536			(562	)		24,974
Costs and expenses:
Oil and gas production		7,227			1,821			9,048
Transportation expense		6,361			—			6,361
General and administrative		1,753			621			2,374
Depreciation, depletion and amortization		6,694			1,068			7,762
Misappropriation of funds		—			500			500

Total costs and expenses		22,035			4,010			26,045
Operating income (loss)		3,501			(4,572	)		(1,071	)
Other income (expense):
Loss from derivative financial instruments		(464	)		(13,083	)		(13,547	)
Miscellaneous other income		107			(13	)		94
Interest expense		(6,971	)		(1,445	)		(8,416	)
Interest income		177			—			177

Total other income (expense)		(7,151	)		(14,541	)		(21,692	)

Net loss	$	(3,650	)	$	(19,113	)	$	(22,763	)

F-27

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

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


	Three Months Ended March 31, 2007
	As
	Previously			Restatement
	Reported			Adjustments			As Restated
Cash flows from operating activities:
Net loss	$	(3,650	)	$	(19,113	)	$	(22,763	)
Adjustments to reconcile net loss to cash provided by operations:
Depreciation, depletion and amortization		7,332			430			7,762
Change in derivative fair value		464			14,077			14,541
Unit awards granted to employees		—			447			447
Capital contributions for employees		120			(120	)		—
Amortization of loan origination fees		479			(7	)		472
Amortization of gas swap fees		62			(62	)		—
Bad debt expense		—			22			22
(Gain) loss on sale of assets		(65	)		65			—
Change in assets and liabilities:
Accounts receivable		(2,059	)		371			(1,688	)
Other receivables		(1,044	)		(371	)		(1,415	)
Other current assets		(806	)		(22	)		(828	)
Other assets		(604	)		2,349			1,745
Due from affiliates		—			345			345
Accounts payable		1,028			9,707			10,735
Revenue payable		1,900			(421	)		1,479
Accrued expenses		(429	)		1,522			1,093
Other long-term liabilities		—			41			41

Net cash provided by operating activities		2,728			9,260			11,988

Cash flows from investing activities:
Equipment, development and leasehold costs		(20,864	)		(743	)		(21,607	)
Net additions to other property and equipment		(2,458	)		2,458			—
Proceeds from sale of property and equipment		922			(922	)		—

Net cash used in investing activities		(22,400	)		793			(21,607	)

Cash flows from financing activities:
Repayments of note borrowings		(221	)		—			(221	)
Capital contributions (distributions)		23,077			(24,884	)		(1,807	)
Refinancing costs		—			(1,687	)		(1,687	)
Change in other long-term liabilities		40			(40	)		—

Net cash provided by (used in) financing activities		22,896			(26,611	)		(3,715	)

Net increase (decrease) in cash		3,224			(16,558	)		(13,334	)
Cash and cash equivalents, beginning of period		21,334			(8,000	)		13,334

Cash and cash equivalents, end of period	$	24,558		$	(24,558	)	$	—

F-28

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Business of Issuer

We are a Delaware limited partnership formed in July 2007 by QRCP to acquire, exploit and develop oil and natural gas properties. Our primary business objective is to generate stable cash flows allowing us to make quarterly cash distributions to our unitholders at our initial distribution rate and, over time, to increase our quarterly cash distributions. Our operations are currently focused on the development of coal bed methane in the Cherokee Basin.

Restatement

As discussed in the Explanatory Note to this Quarterly Report on Form 10-Q/A and in Note 14 — Restatement to our consolidated financial statements, we are restating the consolidated financial statements included in this Quarterly Report on Form 10-Q/A as of March 31, 2008 and for the three months ended March 31, 2008 and our Predecessor’s restated carve out financials for the three months ended March 31, 2007. This Management’s Discussion and Analysis of Financial Condition and Results of Operations for the three month periods ended March 31, 2008 and 2007 reflects the restatements.

Significant Developments During the Three Months Ended March 31, 2008

During the first quarter of 2008, we continued to be focused on drilling and completing new wells. We drilled 118 gross wells and completed the connection of 101 gross wells during this period. As of March 31, 2008, we had approximately 130 additional gas wells (gross) that we were in the process of completing and connecting to Quest Midstream’s gas gathering pipeline system.

For the three months ended March 31, 2008, our average net daily production was 55.6 Mmcfe/d.

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. The properties have estimated net proved reserves of 712,000 barrels, all of which are proved developed producing. In addition, we entered into crude oil swaps for approximately 80% of the estimated net production from the property’s proved developed producing reserves at WTI-NYMEX prices per barrel of oil of approximately $96.00 in 2008, $90.00 in 2009, and $87.50 for 2010. The acquisition was financed with borrowings under our credit facility.

Results of Operations

The following discussion of the results of operations and period-to-period comparisons presented below includes the historical results of the Predecessor. This discussion should be read in conjunction with the financial statements included in this report, and should further be read in conjunction with the audited financial statements and notes thereto of the Predecessor included in our 2008 Form 10-K. Comparisons made between reporting periods herein are for the three month periods ended March 31, 2008 as compared to the same period in 2007. As discussed under Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Factors That Significantly Affect Comparability of Our Results” in our 2008 Form 10-K, the Predecessor’s historical results of operations and period-to-period comparisons of its results may not be indicative of our future results.

Overview. The following discussion of results of operations will compare balances for the three months ended March 31, 2008 and 2007.


	Successor		Predecessor
	Three Months
	Ended
	March 31,				Increase/
	2008		2007		(Decrease)
			*($ in thousands)*
Oil and gas sales	$	38,314	$	24,974	$	13,340		53.4	%
Oil and gas production costs	$	10,386	$	9,048	$	1,338		14.8	%
Transportation expense (related affiliate)	$	8,663	$	6,361	$	2,302		36.2	%
Depreciation, depletion and amortization	$	10,700	$	7,762	$	2,938		37.9	%
General and administrative expenses	$	3,098	$	2,374	$	724		30.5	%
Loss from derivative financial instruments	$	44,239	$	13,547	$	30,692		226.6	%
Interest expense, net	$	2,062	$	8,239	$	(6,177	)	(75.0	)%

Production. The following table presents the primary components of revenues, as well as the average costs per Mcfe, for the three months ended March 31, 2008 and 2007.


	Successor		Predecessor
	Three months ended
	March 31,				Increase
	2008		2007		(Decrease)
Production Data (net):
Natural gas production (MMcf)		4,966		3,724		1,242		33.4	%
Oil production (BBbl)		11		2		9		450.0	%
Total production (MMcfe)		5,032		3,736		1,296		34.7	%
Average daily production (MMcfe/d)		55.3		41.5		13.8		33.3	%
Average Sales Price per Unit:
Natural gas equivalents (Mcfe)	$	7.61	$	6.68	$	0.93		13.9	%
Natural gas (Mcf)	$	7.49	$	6.68	$	0.81		12.1	%
Oil (Bbl)	$	98.12	$	50.35	$	47.77		94.9	%
Average Unit Costs per Mcfe:
Production costs	$	2.06	$	2.42	$	(0.36	)	(14.9	)%
Transportation expense (related affiliate)	$	1.72	$	1.70	$	0.02		1.2	%
Depreciation, depletion and amortization	$	2.13	$	2.08	$	0.05		2.4	%
General and administrative expenses	$	0.62	$	0.64	$	(0.02	)	(3.1	)%
Interest expense, net	$	0.41	$	2.21	$	(1.80	)	(81.4	)%

Oil and Gas Sales. The $13.3 million (53.4%) increase in oil and gas sales from $25.0 million for the quarter ended March 31, 2007 to $38.3 million for the quarter ended March 31, 2008 was primarily attributable to the increase in production volumes and sales prices reflected in the table above. The increase in production volumes was achieved by the addition of more producing wells, which was partially offset by the natural decline in production from some of our older gas wells. The additional wells contributed to the production of 4,966,000 Mcf of net gas for the quarter ended March 31, 2008, as compared to 3,724,000 Mcf of net gas produced in the same quarter last year. Our product prices on an equivalent basis (Mcfe) increased from an average of $6.68 per Mcfe for the quarter ended March 31, 2007 to an average of $7.61 per Mcfe for the quarter ended March 31, 2008.

Operating Expenses. Operating expenses, which consist of oil and gas production costs and transportation expense, totaling $19.0 million for the three months ended March 31, 2008, were comprised of lease operating costs of $7.8 million, production taxes of $1.7 million, ad valorem taxes of $0.8 million, and transportation expenses of $8.7 million. The operating expenses for the three months ended March 31, 2008 compared to $15.4 million for the three months ended March 31, 2007, comprised of lease operating costs of $7.0 million, production taxes of $1.1 million, ad valorem taxes of $0.9 million, and transportation expenses of $6.4 million, increased a total of $3.6 million, or 23.6%.

During the three months ended March 31, 2008, management implemented cost controls which have kept lease operating costs relatively flat, while connecting approximately 600 new wells since the same quarter of 2007. inclusive of gross production and ad valorem taxes, were $2.42 per Mcfe for the three months ended March 31, 2007 as compared to $2.06 per Mcfe for the three months ended March 31, 2008, representing a 14.9% decrease.

Transportation expense increased $2.3 million from $6.4 million for the three months ended March 31, 2007 compared to $8.7 million for the three months ended March 31, 2008, resulting in $1.72 per Mcfe for the three months ended March 31, 2008. This increase primarily resulted from the annual increase in the fees charged under the midstream services agreement with Quest Midstream and increased production.

Depreciation, Depletion and Amortization. We are subject to variances in our depletion rates from period to period, including the periods described below. These variances result from changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our gas and oil properties. Our depletion of oil and gas properties as a percentage of oil and gas revenues was 26.0% in the three months ended March 31, 2008 compared to 27.0% in 2007. Depreciation, depletion and amortization expense was $2.13 per Mcfe in the three months ended March 31, 2008 compared to $2.08 per Mcfe in the three months ended March 31, 2007. Increases in our depletable basis and production volumes caused depletion expense to increase $2.9 million to $10.7 million in the three months ended March 31, 2008 compared to $7.8 million in the three months ended March 31, 2007.

General and Administrative Expenses. General and administrative expenses increased from $2.4 million for the quarter ended March 31, 2007 to $3.1 million for the quarter ended March 31, 2008. This increase is due to an increase in board fees, professional fees, Nasdaq listing fees, travel expenses for presentations to increase our visibility with investors, larger corporate offices, and increased staffing to support the higher levels of development and operational activity.

Loss from Derivative Financial Instruments . Loss from derivative financial instruments increased $30.7 million to $44.2 million during the three months ended March 31, 2008, from $13.5 million during the three months ended March 31, 2007. Due to the increase in average oil and natural gas prices during 2008, we recorded a $43.0 million unrealized loss and a $1.2 million realized loss on our derivative contracts for the three months ended March 31, 2008 compared to a $14.5 million unrealized loss and $1.0 million realized gain for the three months ended March 31, 2007. Gains and losses are all attributable to changes in natural gas prices and volumes hedged from one period end to another.

Interest Expense, Net. Interest expense, net decreased to approximately $2.1 million for the quarter ended March 31, 2008 from $8.2 million for the quarter ended March 31, 2007, due to the refinancing of our credit facilities in 2007 in connection with our initial public offering and lower outstanding borrowings.

Net Loss

We recorded a net loss of $40.8 million for the quarter ended March 31, 2008 as compared to a net loss of $22.8 million for the quarter ended March 31, 2007. The increase in net loss was, primarily, due to the loss from derivative financial instruments of $44.2 million for the three months ended March 31, 2008.

Liquidity and Capital Resources

Liquidity

Our primary sources of liquidity are cash generated from our operations, amounts available under our revolving credit facility and funds from future private and public equity and debt offerings. In connection with the closing of our initial public offering, Quest Cherokee, our principal operating subsidiary, entered into a new 5-year $250 million revolving credit agreement, with an initial borrowing base of $160.0 million, with a syndicate of financial institutions. As of March 31, 2008, we had $123 million borrowed under our revolving credit facility. Please read Notes 6 and 13 to our financial statements included in this report for additional information regarding our revolving credit facility.

At March 31, 2008, we had $37 million of availability under our revolving credit facility, which was available to fund the drilling and completion of additional gas wells, the recompletion of single seam wells into multi-seam wells, the acquisition of additional acreage, equipment and vehicle replacement and purchases and the construction of salt water disposal facilities.

Our partnership agreement requires that we distribute our available cash. In making cash distributions, our general partner will attempt to avoid large variations in the amount we distribute from quarter to quarter. In order to facilitate this, our partnership agreement permits our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters. In addition, our partnership agreement allows our general partner to borrow funds to make distributions.

At March 31, 2008, we had current assets of $36.4 million. Our working capital (current assets minus current liabilities, excluding the short-term derivative asset and liability of $2.2 million and $32.4 million, respectively) was $10.4 million at March 31, 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. The changes in working capital were primarily due to an increase in accounts receivable.

Because of the seasonal nature of oil and gas production, we may make short-term working capital borrowings in order to level out our distributions during the year. In addition, a substantial portion of our production is hedged. We are generally required to settle a portion of our commodity hedges on each of the 5 ^th and 25 ^th day of each month. As is typical in the oil and gas business, we generally do not receive the proceeds from the sale of the hedged production until around the 25 ^th day of the following month. As a result,

when oil and gas prices increase and are above the prices fixed in our derivative contracts, we will be required to pay the hedge counterparty the difference between the fixed price in the hedge and the market price before we receive the proceeds from the sale of the hedged production. If this were to occur, we may make working capital borrowings to fund our distributions. Because we will distribute our available cash, we will not have those amounts available to reinvest in our business to increase our reserves and production. Because we will distribute a substantial amount of our cash flows (after making principal and interest payments on our indebtedness) rather than reinvest those cash flows in our business, we may not grow as quickly as other companies or at all.

Capital Expenditures

During the three months ended March 31, 2008, we spent a total of approximately $34.5 million on capital expenditures.

During 2008, our capital expenditures will consist of the following:

	•		maintenance capital expenditures, which are those capital expenditures required to maintain our production levels and asset base over the long term; and

	•		expansion capital expenditures, which are those capital expenditures that we expect will increase our production of our gas and oil properties and our asset base over the long term.

In the event we make one or more additional acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we would reduce the expected level of capital expenditures and/or seek additional capital. If we seek additional capital for that or other reasons, we may do so through traditional reserve base borrowings, joint venture partnerships, production payment financings, asset sales, offerings of debt or equity securities or other means.

We cannot assure you that needed capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness will be limited by covenants in our credit facility. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves and maintain our pipeline volumes. Please read Note 4 — Long-Term Debt to our financial statements included in our 2008 Form 10-K for a description of the financial covenants contained in our revolving credit facility. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves.

Cash Flows

Cash Flows from Operating Activities. Net cash provided by operating activities totaled $10.6 million for the three months ended March 31, 2008 as compared to $12.0 million in net cash provided by operating activities for the three months ended March 31, 2007. This decrease resulted from changes in current assets and liabilities.

Cash Flows Used in Investing Activities. Net cash used in investing activities totaled $34.5 million for the three months ended March 31, 2008 as compared to $21.6 million for the three months ended March 31, 2007. All cash used in investing activities was for capital expenditures.

Cash Flows from Financing Activities. Net cash provided by financing activities totaled $24.5 million for the three months ended March 31, 2008 as compared to cash used in financing activities of $3.7 million for the three months ended March 31, 2007.

The net cash provided from financing activities during the three months ended March 31, 2008 was due primarily to $29 million of borrowings under the Quest Cherokee credit facility.

Contractual Obligations

Future payments due on our contractual obligations as of March 31, 2008 are as follows:


	Payments Due By Period
			Less						More
			Than 1		1-3		4-5		Than 5
	Total		Year		Years		Years		Years
	*($ in thousands)*

Revolving credit facility (2)	$	123,000	$	—	$	123,000	$	—	$	—
Notes payable		484		448		19		13		4
Interest expense obligation (1)(2)		22,254		8,613		13,638		3		—
Drilling contractor		2,548		2,548		—		—		—
Lease obligation		534		111		205		187		31

Total	$	148,820	$	11,720	$	136,862	$	203	$	35


(1)		The interest expense obligation was computed using the LIBOR interest rate as of March 31, 2008. If the interest rate were to change 1%, then the total interest payment obligation would change by $3.1 million. Effective April 15, 2008, the interest rate on our revolving credit facility was increased by 1%. This change has been reflected in the table above. See Note 13 to the consolidated financial statements included in this report.

(2)		Effective April 15, 2008, the maturity date for the revolving credit facility was changed from November 15, 2012 to November 15, 2010. This change has been reflected in the table above. See Note 13 to the consolidated financial statements included in this report.

Critical Accounting Policies and Estimates

The consolidated/carve out financial statements are prepared in conformity with accounting principles generally accepted in the United States. As such, we are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. A summary of the significant accounting policies is contained in Note 3 to our consolidated/carve out financial statements. 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.

Off-Balance Sheet Arrangements

At March 31, 2008 and December 31, 2007, we did not have any relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. In addition, we do not engage in trading activities involving non-exchange traded contracts. As such, we are not exposed to any financing, liquidity, market, or credit risk that could arise if we had engaged in such activities.

Cautionary Statements for Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995

We are including the following discussion to inform you of some of the risks and uncertainties that can affect our company and to take advantage of the “safe harbor” protection for forward-looking statements that applicable federal securities law affords. Various statements this report contains, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements. These include such matters as:

	•		projections and estimates concerning the timing and success of specific projects;

	•		financial position;

	•		business strategy;

	•		budgets;

	•		amount, nature and timing of capital expenditures;

	•		drilling of wells;

	•		acquisition and development of oil and natural gas properties;

	•		timing and amount of future production of oil and natural 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 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. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. All subsequent oral and written forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these factors. These risks, contingencies and uncertainties relate to, among other matters, the following:

	•		our ability to implement our business strategy;

	•		the extent of our success in discovering, developing and producing reserves, including the risks inherent in exploration and development drilling, well completion and other development activities;

	•		fluctuations in the commodity prices for crude oil and natural gas;

	•		engineering and mechanical or technological difficulties with operational equipment, in well completions and workovers, and in drilling new wells;

	•		land issues;

	•		the effects of government regulation and permitting and other legal requirements;

	•		labor problems;

	•		environmental related problems;

	•		the uncertainty inherent in estimating future oil and natural gas production or reserves;

	•		production variances from expectations;

	•		the substantial capital expenditures required for the drilling of wells and the related need to fund such capital requirements through commercial banks and/or public securities markets;

	•		disruptions, capacity constraints in or other limitations on Quest Midstream’s pipeline systems;

	•		costs associated with perfecting title for oil and natural gas rights in some of our properties;

	•		the need to develop and replace reserves;

	•		competition;

	•		dependence upon key personnel;

	•		the lack of liquidity of our equity securities;

	•		operating hazards attendant to the oil and natural gas business;

	•		down-hole drilling and completion risks that are generally not recoverable from third parties or insurance;

	•		potential mechanical failure or under-performance of significant wells;

	•		climatic conditions;

	•		natural disasters;

	•		acts of terrorism;

	•		availability and cost of material and equipment;

	•		delays in anticipated start-up dates;

	•		our ability to find and retain skilled personnel;

	•		availability of capital;

	•		the strength and financial resources of our competitors; and

	•		general economic conditions.

When you consider these forward-looking statements, you should keep in mind these risk factors and the other factors discussed under Item 1A. “Risk Factors” in our 2008 Form 10-K.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

The following table summarizes the estimated volumes, fixed prices, fixed-price sales and fair value attributable to the fixed-price contracts as of March 31, 2008.


	Nine Months
	Ending
	December 31,						Years Ending December 31,
	2008			2009			2010			2011		2012		Total
				*(dollars in thousands, except per MMBtu and Bbl data)*
Natural Gas Swaps:
Contract volumes (MMBtu)		8,458,725			14,629,200			12,499,060			—		2,000,004		37,586,989
Weighted average fixed price per MMBtu (1)	$	6.98		$	7.78		$	7.42		$	—	$	8.11	$	7.50
Fair value, net	$	(12,429	)	$	(11,212	)	$	(9,283	)	$	—	$	44	$	(32,880	)
Natural Gas Collars:
Contract volumes (MMBtu)
Floor		5,280,275			—			—			—		—		5,280,275
Ceiling		5,280,275			—			—			—		—		5,280,275
Weighted average fixed price per MMBtu (1)
Floor	$	6.54		$	—		$	—		$	—	$	—	$	6.54
Ceiling	$	7.53		$	—		$	—		$	—	$	—	$	7.53
Fair value, net	$	(12,602	)	$	—		$	—		$	—	$	—	$	(12,602	)
Total Natural Gas Contracts(2):
Contract volumes (MMBtu)		13,739,000			14,629,200			12,499,060			—		2,000,004		42,867,264
Weighted average fixed price per MMBtu (1)	$	6.81		$	7.78		$	7.42		$	—	$	8.11	$	7.38
Fair value, net	$	(25,031	)	$	(11,212	)	$	(9,283	)	$	—	$	44	$	(45,482	)
Oil Swaps:
Contract volumes (Bbl)		27,000			36,000			30,000			—		—		93,000
Weighted average fixed price per Bbl (1)	$	95.92		$	90.07		$	87.50			—	$	—	$	90.94
Fair value, net	$	(97	)	$	(205	)	$	(188	)	$	—	$	—	$	(490	)


(1)		The prices to be realized for hedged production are expected to vary from the prices shown due to basis.

(2)		Does not include basis swaps with notional volumes by year, as follows: 2008: 4,716,000 MMBtu.

There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2008, in Item 7A of our 2008 Form 10-K. For more information on our risk management activities, see Note 7 to our consolidated/carve out financial statements.

Item 4(T). 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 the originally filed Form 10-Q for the quarter ended March 31, 2008, our former principal executive officer and former principal financial officer evaluated disclosure controls and procedures and concluded they were effective. Subsequent to the original filing, we identified material weaknesses as reported in our Annual Report on Form 10-K for the year ended December 31, 2008.

In connection with the preparation of this Quarterly Report on Form 10-Q/A, 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 March 31, 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 March 31, 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/A 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 March 31, 2008:

(1)

Control environment — We did not maintain an effective control environment. The control environment, which is the responsibility of senior management, sets the tone of the organization, influences the control consciousness of its people, and is the foundation for all other components of internal control over financial reporting. Each of these control environment material weaknesses contributed to the material weaknesses discussed in items (2) through (7) below. We did not maintain an effective control environment because of the following material weaknesses:

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

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

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

The control environment material weaknesses described above contributed to the material weaknesses related to the transfers that were the subject of the internal investigation and to our internal control over financial reporting, period end financial close and reporting, accounting for derivative instruments, depreciation, depletion and amortization, impairment of oil and gas properties and cash management described in items (2) to (7) below.

(2)

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

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

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

Each of these material weaknesses relating to the monitoring of our internal control over financial reporting contributed to the material weaknesses described in items (3) through (7) below.

(3)

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

(a)

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

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

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

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

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

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

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

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

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

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. These material weaknesses resulted in the misstatement of our audited consolidated financial statements as of December 31, 2007 and for the period from November 15, 2007 to December 31, 2007 and 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 and 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 and the Predecessor’s unaudited consolidated financial statements as of and for the three months ended March 31, 2007 and as of and for the three and six months ended June 30, 2007 and as of and for the three and nine months ended September 30, 2007.

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 Controls

Except as described above, there were no other changes in our internal control over financial reporting during the quarter ended March 31, 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

See Part I, Item 1, Note 11 to our consolidated/carve out financial statements entitled “Commitments and Contingencies”, which is incorporated herein by reference.

In addition, from time to time, we may be subject to legal proceedings and claims that arise in the ordinary course of our business. Although no assurance can be given, management believes, based on its experiences to date, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position or results of operations.

Item 1A. Risk Factors

There have been no material changes to the risk factors disclosed 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. Default Upon Senior Securities

None.

Item 4. Submission of Matters to Vote of Security Holders

None.

Item 5. Other Information

None.

Item 6. Exhibits


	3.1*		Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Quest Energy Partners, L.P., effective as of January 1, 2007, by Quest Energy GP, LLC (incorporated herein by reference to Exhibit 3.1 to Quest Energy Partners, L.P.’s Current Report on Form 8-K filed on April 11, 2008).

	3.2*		First Amended and Restated Agreement of Limited Partnership of Quest Energy Partners, L.P., dated as of November 15, 2007, by and between Quest Energy GP, LLC and Quest Resource Corporation (incorporated herein by reference to Exhibit 3.1 to Quest Energy Partners, L.P.’s Current Report on Form 8-K filed on November 21, 2007).

	10.1*		First Amendment to Amended and Restated Credit Agreement, effective as of April 15, 2008, by and among Quest Cherokee, LLC, Royal Bank of Canada, KeyBank National Association and the Lenders Party Thereto (incorporated herein by reference to Exhibit 10.1 to Quest Energy Partners, L.P.’s Current Report on Form 8-K filed on April 23, 2008).

	31.1		Certification by Chief 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 Chief 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 Chief 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 Chief 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.

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 13 ^th day of July, 2009.

QUEST ENERGY PARTNERS, L.P.

By: Quest Energy GP, LLC, its general partner