QELP Quest Energy Partners, L.P. (MM)

 

 

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 June 30, 2008.

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

For the transition period from            to            .

Commission file number: 001-33787

QUEST ENERGY PARTNERS, L.P.

(Exact name of registrant 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 August 8, 2008, the issuer had 12,331,521 common units outstanding.

 

 

EXPLANATORY NOTE

     This amended Quarterly Report on Form 10-Q/A for the quarter ended June 30, 2008 includes our restated consolidated financial statements as of June 30, 2008 and for the three and six month period ended June 30, 2008 and our Predecessor’s restated and reaudited carve out financial statements for the three and six month periods ended June 30, 2007. The consolidated balance sheet as of December 31, 2007 was restated in our 2008 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 net income (loss), major restatement adjustments and restated net loss as of and for the periods indicated (in thousands):

		June 30, 2008
Partners’ equity as previously reported		$	80,110
Effect of the Transfers			(9,500	)
Reversal of hedge accounting			3,658
Accounting for formation of Quest Cherokee			(15,102	)
Capitalization of costs in full cost pool			(31,091	)
Recognition of costs in proper periods			(2,656	)
Depreciation, depletion and amortization			11,000
Impairment of oil and gas properties			30,719
Other errors			5,136
Partners’ equity as restated		$	72,274

		Three Months Ended June 30,
		2008				2007
Net income (loss) as previously reported		$	16,221			$	(5,231	)
Effect of the Transfers			—				(500	)
Reversal of hedge accounting			(105,179	)			7,689
Capitalization of costs in full cost pool			(3,425	)			(3,028	)
Recognition of costs in proper periods			(1,699	)			(188	)
Stock-based compensation			446				104
Depreciation, depletion and amortization			(429	)			(175	)
Other errors			449				126
Net loss as restated		$	(93,616	)		$	(1,203	)

		Six Months Ended June 30,
		2008				2007
Net loss as previously reported		$	(1,125	)		$	(8,924	)
Effect of the Transfers			—				(1,000	)
Reversal of hedge accounting			(124,375	)			(6,394	)
Capitalization of costs in full cost pool			(7,084	)			(5,447	)
Recognition of costs in proper periods			(1,116	)			(432	)
Stock-based compensation			15				(241	)
Depreciation, depletion and amortization			(920	)			(655	)
Other errors			224				(916	)
Net loss as restated		$	(134,381	)		$	(24,009	)

     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 in the notes 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 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 June 30, 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 June 30, 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 June 30, 2008, initially filed with the SEC on August 12, 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 JUNE 30, 2008

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION			8
Item 1. Financial Statements			8
Balance Sheets: June 30, 2008 and December 31, 2007			F-1
Statements of Operations Three and six months ended June 30, 2008 and 2007			F-2
Statements of Cash Flows: Six months ended June 30, 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			9
Item 3. Quantitative and Qualitative Disclosures About Market Risk			18
Item 4(T). Controls and Procedures			18
PART II — OTHER INFORMATION			21
Item 1. Legal Proceedings			21
Item 1A. Risk Factors			21
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			22
Item 3. Defaults Upon Senior Securities			22
Item 4. Submission of Matters to a Vote of Security Holders			22
Item 5. Other Information			22
Item 6. Exhibits			23
SIGNATURES			25
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-32 and incorporated herein by this reference are (i) our unaudited interim financial statements, including a consolidated balance sheet as of June 30, 2008, consolidated statements of operations for the three and six months ended June 30, 2008 and a consolidated statement of cash flows for the six months ended June 30, 2008, (ii) the Predecessor’s unaudited interim financial statements, including carve out statements of operations for the three and six months ended June 30, 2007 and a carve out statement of cash flows for the six months ended June 30, 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 six months ended June 30, 2008 are not necessarily indicative of the results for the year ended December 31, 2008.

          The financial statements included herein should be read in conjunction with the 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/carve out financial statements.

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

($ in thousands except share data)

		June 30,				December 31,
		2008				2007
		(Unaudited)
		(Restated)
ASSETS
Current assets:
Cash and cash equivalents		$	11,504			$	169
Restricted cash			112				1,205
Accounts receivable, trade			(274	)			86
Due from affiliated companies			21,595				15,624
Other current assets			3,185				3,091
Inventory			9,845				4,956
Current derivative financial instrument assets			1,837				8,008
Total current assets			47,804				33,139
Property and equipment, net of accumulated depreciation of $ 7,214 and $ 5,473			18,808				17,116
Oil and gas properties under full cost method of accounting, net			325,643				294,329
Other assets, net			3,185				3,526
Long-term derivative financial instrument assets			9,536				3,467
Total assets		$	404,976			$	351,577
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable		$	24,754			$	18,673
Accrued expenses			8,262				639
Due to affiliates			1,504				1,708
Current portion of notes payable			247				666
Current derivative financial instrument liabilities			68,355				8,108
Total current liabilities			103,122				29,794
Non-current liabilities:
Long-term derivative financial instrument liabilities			85,306				6,311
Asset retirement obligation			2,125				1,700
Notes payable			142,149				94,042
Non-current liabilities			229,580				102,053
Total liabilities			332,702				131,847
Commitments and contingencies
Partners’ equity:
Common unitholders — Issued and outstanding — 12,301,521 at June 30, 2008 and December 31, 2007 (9,100,000 — public; 3,201,521 — affiliate)			78,392				162,610
Subordinated unitholder — affiliate; 8,857,981 units issued and outstanding at June 30, 2008 and December 31, 2007			(5,821	)			54,465
General Partner — affiliate; 431,827 units issued and outstanding at June 30, 2008 and December 31, 2007			(297	)			2,655
Total partners’ equity			72,274				219,730
Total liabilities and partners’ equity		$	404,976			$	351,577

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

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

STATEMENTS OF OPERATIONS

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

(Unaudited)
(Restated)

		Successor				Predecessor				Successor				Predecessor
		Three Months								Six Months
		Ended June 30,								Ended June 30,
		2008				2007				2008				2007
		(Consolidated)				(Carve out)				(Consolidated)				(Carve out)
Revenue:
Oil and gas sales		$	49,142			$	27,570			$	87,454			$	52,544
Total revenues			49,142				27,570				87,454				52,544
Costs and expenses:
Oil and gas production			13,898				9,856				24,283				18,904
Transportation expense			8,675				6,920				17,338				13,281
General and administrative			1,669				4,333				4,767				6,707
Depreciation, depletion and amortization			10,855				8,146				21,554				15,951
Misappropriation of funds			—				500				—				1,000
Total costs and expenses			35,097				29,755				67,942				55,843
Operating income (loss)			14,045				(2,185	)			19,512				(3,299	)
Other income (expense):
Gain (loss) from derivative financial instruments			(105,375	)			8,391				(149,614	)			(5,156	)
Other income (expense)			45				(323	)			114				(229	)
Interest income			90				103				107				280
Interest expense			(2,421	)			(7,189	)			(4,500	)			(15,605	)
Total other income (expense)			(107,661	)			982				(153,893	)			(20,710	)
Net loss		$	(93,616	)		$	(1,203	)		$	(134,381	)		$	(24,009	)
General partner’s interest in net loss		$	(1,872	)						$	(2,688	)
Limited partners’ interest in net loss		$	(91,744	)						$	(131,693	)
Net loss per limited partner unit (basic and diluted)		$	(4.33	)						$	(6.22	)
Weighted average limited partner units outstanding:
Common units (basic and diluted)			12,331,521								12,331,521
Subordinated units (basic and diluted)			8,857,981								8,857,981

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

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

STATEMENTS OF CASH FLOWS

($ in thousands)
(Unaudited)
(Restated)

		Successor				Predecessor
		Six Months Ended
		June 30,
		2008				2007
		(Consolidated)				(Carve out)
Cash flows from operating activities:
Net loss		$	(134,381	)		$	(24,009	)
Adjustments to reconcile net loss to cash provided by (used in) operations:
Depreciation, depletion and amortization			21,554				15,951
Gain (loss) from derivative financial instruments			139,344				6,577
Unit-based compensation			17				—
Contributions for consideration for compensation to employees			—				2,770
Amortization of loan origination fees			240				944
Bad debt expense			64				22
Change in assets and liabilities:
Accounts receivable			296				(2,231	)
Other receivables			—				(1,509	)
Other current assets			(94	)			(634	)
Due from affiliates			(6,175	)			241
Other assets			101				193
Accounts payable			7,782				2,642
Revenue payable			(99	)			1,972
Accrued expenses			7,524				174
Other long-term liabilities			445				80
Other			1				—
Net cash provided by operating activities			36,619				3,183
Cash flows from investing activities:
Restricted cash			1,093				(10	)
Equipment, development and leasehold costs			(60,972	)			(47,019	)
Net cash used in investing activities			(59,879	)			(47,029	)
Cash flows from financing activities:
Proceeds from revolver note			48,000				10,000
Repayments of note borrowings			(313	)			(299	)
Capital contributions			450				23,478
Distributions to unitholders			(13,277	)			—
Refinancing costs			(265	)			(1,687	)
Net cash provided by financing activities			34,595				31,492
Net increase (decrease) in cash			11,335				(12,354	)
Cash and cash equivalents, beginning of period			169				13,334
Cash and cash equivalents, end of period		$	11,504			$	980

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

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 (“Quest Cherokee”) 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 natural gas and oil 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 consolidated/carve out financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). 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 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 natural 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 accompanying 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 June 30, 2008 and for the three and six month periods ended June 30, 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 months 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.

               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 QELP 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 our 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.

          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 June 30, 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).

          In October 2008, Quest Energy GP’s audit committee engaged a new independent registered public accounting firm to audit our consolidated financial statements for 2008 and, in January 2009, engaged them to reaudit our consolidated financial statements as of December 31, 2007 and for the period from November 15, 2007 to December 31, 2007 and our Predecessor’s consolidated financial statements as of and for the years ended December 31, 2005 and 2006 and for the period from January 1, 2007 to November 14, 2007. 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 restated 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 June 30, 2008 and for the three and six months ended June 30, 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.

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Under this method, an Investee company’s balance sheet and results of operations are reflected within the Company’s consolidated 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 restated, consolidated/carve out financial statements and accompanying notes. Actual results could differ from those estimates.

          Estimates made in preparing the restated, consolidated/carve out financial statements include, among other things, estimates of the proved natural 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

          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.

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.

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Other Current Assets

          Other current assets totaled $3.2 million at June 30, 2008 as compared to $3.1 million at December 31, 2007. At June 30, 2008, other current assets consisted of deposits of $1.6 million, prepaid insurance of $0.7 million, and other items of $0.9 million. At December 31, 2007, other current assets consisted of deposits of $1.2 million, prepaid insurance of $1.3 million and $0.6 million of other prepaids.

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 derivative contracts 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 natural gas and oil revenues for the six months ended June 30, 2008. Natural gas sales to two purchasers (ONEOK and Tenaska Marketing Ventures) accounted for 70% and 20% of total natural gas revenues for the six months ended June 30, 2007.

          The Company conducts its operations in the states of Kansas and Oklahoma and operates exclusively in the natural gas and oil industry. 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. The Company’s receivables are generally unsecured; however, the Company has not experienced any significant losses to date.

Oil and Natural Gas Properties

          The Company follows the full cost method of accounting for oil and natural gas properties, prescribed by the 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 natural gas and oil 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 June 30, 2008 and December 31, 2007.

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NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
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          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 natural gas and oil, 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 June 30, 2008 and December 31, 2007 totaled $3.1 million and $3.5 million, respectively, and were 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 June 30, 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

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

Fair Value Measurements

          SFAS 157, Fair Value Measurements (as amended), defines fair value, establishes a framework for measuring fair value, outlines a fair value hierarchy based on inputs used to measure fair value and enhances disclosure requirements for fair value measurements. The Company has not applied the provisions of SFAS 157 to nonrecurring, nonfinancial assets and liabilities as allowed under FASB Staff Position (“FSP”) 157-2.

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
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          Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.

          Beginning January 1, 2008, assets and liabilities recorded at fair value in the consolidated balance sheets are categorized based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels—defined by SFAS 157 and directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities—are as follows:

          Level I—Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date;

          Level II—Inputs (other than quoted prices included in Level I) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life; and

          Level III—Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.

          The fair value of the Company’s derivative contracts are measured using Level II and Level III inputs, and are determined by either market prices on an active market for similar assets or by prices quoted by a broker or other market-corroborated prices.

Derivative Instruments and Hedging Activities

     The Company uses derivatives 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 have been 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 the occur. Both realized and unrealized gains and losses associated with derivative financial instruments are currently recognized in other income (expense) as they occur.

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NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
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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.

Allocation of Costs

          The accompanying 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.

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
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          Historical financial statements of the Cherokee Basin Operations for the three and six months ended June 30, 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 was $0.50 per MMBtu of gas for gathering, dehydration and treating services 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 and six months ended June 30, 2007, the Cherokee Basin Operations were wholly-owned by QRCP. Accordingly, earnings per unit have not been presented for those periods.

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 FASB 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 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 the Company 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. See Note 7. “Financial Instruments and Hedging Activities — Fair Value Measurements”.

          In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”), an amendment of FASB 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 September 2007, the Emerging Issues Task Force (“EITF”) reached consensus on EITF Issue No. 07-4, “Application of the two-class method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF No. 07-4”), an update of EITF No. 03-6. EITF No. 07-4 requires the calculation of a master limited partnership’s net earnings per limited partner unit for each period presented according to distributions declared and participation rights in undistributed earnings as if all of

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the earnings for that period had been distributed. In periods with undistributed earnings above specified levels, the calculation per the two-class method results in an increased allocation of such undistributed earnings to the general partner and a dilution of earnings to the limited partners. EITF No. 07-4 is effective for fiscal periods beginning on or after December 15, 2008. The Company does not expect the application of EITF No. 07-4 to have a material effect on its earnings per unit calculation.

          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.

          In April 2008, the FASB issued Staff Position (FSP) FAS 142-3, “ Determination of the Useful Life of Intangible Assets ”. The objective of this statement is to amend the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, Goodwill and Other Intangible Assets . It is the FSP’s intent to improve the consistency between the useful life of a recognized intangible asset under Statement 142 and the period of expected cash flows used to measure the fair value of the asset under FASB Statement No. 141. The effective date for this statement will apply to financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Management is assessing the impact of the adoption of SFAS 142-3.

          In May 2008, the FASB issued SFAS 162, “ The Hierarchy of Generally Accepted Accounting Principles ”. The objective of this statement is to identify the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States (the GAAP hierarchy). This statement will go into effect 60 days following the SEC’s approval of the Public Company Accounting Oversight Board (PCAOB) amendments to AU Section 411, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles . Management is assessing the impact of the adoption of SFAS 162.

4. Equity-Based Compensation

          The General Partner granted 30,000 bonus units to its independent directors, 15,000 each, during the six months ended June 30, 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

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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 and six months ended June 30, 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 and six months ended June 30, 2008 was $17,000 and $35,000, respectively.

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. As of February 1, 2008, the properties had estimated net proved reserves of 761,400 barrels, all of which were proved developed producing. In addition, Quest Cherokee entered into crude oil swaps for approximately 80% of the estimated net production from the property’s proved developed producing reserves at WTI-NYMEX prices per barrel of oil of approximately $96.00 in 2008, $90.00 in 2009, and $87.50 for 2010. The acquisition was financed with borrowings under Quest Cherokee’s credit facility.

6. Long-Term Debt

     Long-term debt consists of the following:

		June 30, 2008				December 31, 2007
		($ in thousands)
Senior credit facility		$	142,000			$	94,000
Notes payable to banks and finance companies, secured by equipment and vehicles, due in installments through October 2013 with interest ranging from 1.9% to 8.9% per annum			396				708
Total long-term debt			142,396				94,708
Less — current maturities			247				666
Total long-term debt, net of current maturities		$	142,149			$	94,042

     The aggregate scheduled maturities of notes payable and long-term debt for the period ending June 30, 2013 and thereafter were as follows as of June 30, 2008 (assuming no payments were made on the revolving credit facility prior to its maturity)(dollars in thousands):

2009		$	59
2010			142,052
2011			26
2012			6
2013			6
Thereafter			—
		$	142,149

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 June 30, 2008, the borrowing base under the credit agreement was $160 million and the amount borrowed under the credit agreement was $142 million. The weighted average interest rate under the credit agreement for the six months ended June 30, 2008 was 6.80%.

          On April 17, 2008, the Company and Quest Cherokee entered into an amendment to the credit agreement. 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

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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.

          See Note 13 — Subsequent Events for a discussion of the increase in the borrowing base of the revolving credit facility and a new second lien senior term loan agreement.

Other Long-Term Indebtedness

          As of June 30, 2008, $396,000 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.

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 June 30, 2008, fixed-price contracts are in place to hedge 46.3 MMBtu of estimated future natural gas production. Of this total volume, 9.2 MMBtu are hedged for 2008 and 37.1 MMBtu thereafter. As of June 30, 2008, fixed-price contracts are in place to hedge 84,000 Bbls of estimated future oil production. Of this total volume, 18,000 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, and fair value attributable to the fixed-price contracts as of June 30, 2008.

		Six 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)			5,659,656				14,629,200			12,499,060			2,000,004			2,000,004			36,787,924
Weighted average fixed price per MMBtu (1)		$	6.98			$	7.78		$	7.42		$	8.00		$	8.11		$	7.57
Fair value, net		$	(22,159	)		$	(47,865	)	$	(34,117	)	$	(3,543	)	$	(3,150	)	$	(110,834	)
Natural Gas Collars:
Contract volumes (MMBtu)
Floor			3,532,984				—			—			3,000,000			3,000,000			9,532,984
Ceiling			3,532,984				—			—			3,000,000			3,000,000			9,532,984

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

		Six Months
		Ending
		December 31,				Years Ending December 31,
		2008				2009			2010			2011			2012			Total
									(dollars in thousands, except per MMBtu and Bbl data)
Weighted average fixed price per MMBtu (1)
Floor		$	6.54			$	—		$	—		$	7.00		$	7.00		$	6.83
Ceiling		$	7.53			$	—		$	—		$	9.40		$	9.60		$	8.77
Fair value, net		$	(18,282	)		$	—		$	—		$	(5,432	)	$	(3,775	)	$	(27,489	)
Total Natural Gas Contracts(2):
Contract volumes (MMBtu)			9,192,640				14,629,200			12,499,060			5,000,004			5,000,004			46,320,908
Weighted average fixed price per MMBtu (1)		$	6.81			$	7.78		$	7.42		$	7.40		$	7.44		$	7.41
Fair value, net		$	(40,441	)		$	(47,865	)	$	(34,117	)	$	(8,975	)	$	(6,925	)	$	(138,323	)
Oil Swaps:
Contract volumes (Bbl)			18,000				36,000			30,000			—			—			84,000
Weighted average fixed price per Bbl (1)		$	95.92			$	90.07		$	87.50			—			—		$	90.91
Fair value, net		$	(805	)		$	(1,755	)	$	(1,405	)	$	—		$	—		$	(3,965	)

Interest Rate Hedging Activities

          At June 30, 2008, the Company had no outstanding interest rate cap or swap agreements.

Gain (loss) from Derivative Financial Instruments

          Gain (loss) from derivative financial instruments in the statements of operations for the three and six months ended June 30, 2008 and 2007 is comprised of the following:

		Successor				Predecessor				Successor				Predecessor
		Three								Six
		Months Ended								Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
		($ in thousands)
Unrealized gains (losses)		$	(96,316	)		$	7,964			$	(139,344	)		$	(6,577	)
Realized gains (losses)			(9,059	)			427				(10,270	)			1,421
Gain (loss) from derivative financial instruments		$	(105,375	)		$	8,391			$	(149,614	)		$	(5,156	)

           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 June 30, 2008 (in thousands):

														Netting and
		Level				Level				Level				Cash				Total Net Fair
		1				2				3				Collateral*				Value
Derivative financial instruments — assets		$	—			$	—			$	11,373			$	—			$	11,373
Derivative financial instruments — liabilities		$	—			$	(29,197	)		$	(124,464	)		$	—			$	(153,661	)
Total		$	—			$	(29,197	)		$	(113,091	)		$	—			$	(142,288	)

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

     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 Purchase, 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 losses included in earnings			(112,595	)
Purchases, sales, issuances, and settlements			(3,940	)
Transfers into and out of Level 3			—
Balance as of June 30, 2008		$	(113,091	)

Fair Value Measurements

          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.

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.

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

          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 natural 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 the Company has 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.

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 and six months ended June 30, 2008 and 2007:

		Successor				Predecessor				Successor				Predecessor
		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
		($ in thousands)
Asset retirement obligation beginning balance		$	2,056			$	1,477			$	1,700			$	1,410
Liabilities incurred			24				41				52				83
Liabilities settled			(5	)			(2	)			(13	)			(3	)
Accretion expense			50				30				96				56
Revisions in estimated cash flows			—				—				290				—
Asset retirement obligation ending balance		$	2,125			$	1,546			$	2,125			$	1,546

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

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 was paid on May 15, 2008 to unitholders of record at the close of business on May 5, 2008. The aggregate amount of the distribution was $8.9 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 period. 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 .

          The following sets forth the net loss allocation using this method (dollars in thousands, except per unit amounts):

		Three Months Ended								Six Months Ended
		June 30, 2008								June 30, 2008
						Per Limited								Per Limited
		$				Partner Unit				$				Partner Unit
Net loss		$	(93,616	)						$	(134,381	)
Less: General partner’s 2% interest in net income (loss)			(1,872	)							(2,688	)
Net loss available for limited partners		$	(91,744	)		$	(4.33	)			(131,693	)		$	(6.22	)

     The board of directors of the General Partner did not declare a cash distribution during the period January 1, 2008 through June 30, 2008 which would result in an incentive distribution to the General Partner as indicated above.

          The General Partner has all of the incentive distribution rights entitling it to receive up to 23% of the Company’s cash distributions above certain target distribution levels in addition to its 2% general partner interest. This increased sharing in the Company’s distributions creates a conflict of interest for the General Partner in determining whether to distribute cash to the Company’s unitholders or reserve it for reinvestment in the business and whether to borrow to pay distributions to the Company’s unitholders. The General Partner may have an incentive to distribute more cash than it would if its only economic interest in the Company were its 2% general partner interest. Furthermore, because of the commodity price sensitivity of the Company’s business, the General Partner may receive incentive distributions due solely to increases in commodity prices as opposed to growth through development drilling or acquisitions.

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

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

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) were 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 alleged that STP, Inc., et al. , sold natural gas from wells owned by the Plaintiffs without providing the requisite notice to Plaintiffs. Plaintiffs further alleged 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 asserted 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 had a right to recover those damages. Plaintiffs had not quantified their alleged damages. In August 2008, the parties entered into a settlement agreement and the lawsuit was dismissed with prejudice. See Note 14, “Subsequent Events.”

          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 ruling, and the appeal is pending before the Kansas Supreme Court. The case was argued on December 4, 2007, and to date, the Kansas Supreme Court has not yet issued an opinion.

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

          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 ratify the class and the court has not yet 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 or counter claim defendant in several lawsuits in which the plaintiffs claim that oil and gas leases owned and operated by Quest Cherokee have either expired by their terms or, for various reasons, have been forfeited by Quest Cherokee. Those lawsuits were originally filed in the district courts of Labette, Montgomery, Wilson, Neosho and Elk Counties, Kansas. Quest Cherokee has drilled wells on some of the oil and gas leases in issue and some of those oil and gas leases do not have a well located thereon but have been unitized with other oil and gas leases upon which a well has been drilled. As of July 31, 2008, the total amount of acreage covered by the leases at issue in these lawsuits was approximately 7,553 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 had 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 denied that it is legally responsible for plugging the wells in issue. On July 16, 2008, Quest Cherokee received a favorable ruling on this matter. See Note 13 — Subsequent Events.

          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 natural gas and oil 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, LLC (“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

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

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 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

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

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;
	•		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.

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

          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.

          The General Partner has all of the incentive distribution rights entitling it to receive up to 23% of the Company’s cash distributions above certain target distribution levels in addition to its 2% general partner interest. This increased sharing in the Company’s distributions creates a conflict of interest for the General Partner in determining whether to distribute cash to the Company’s unitholders or reserve it for reinvestment in the business and whether to borrow to pay distributions to the Company’s unitholders. The General Partner may have an incentive to distribute more cash than it would if its only economic interest in the Company were its 2% general partner interest. Furthermore, because of the commodity price sensitivity of the Company’s business, the General Partner may receive incentive distributions due solely to increases in commodity prices as opposed to growth through development drilling or acquisitions.

13. Subsequent Events

      PetroEdge Acquisition

          On July 11, 2008, the Company purchased over 400 oil and natural gas wellbores with estimated net proved developed reserves of 32.9 billion cubic feet of natural gas equivalent (Bcfe) and current net production of approximately 3.3 million cubic feet of natural gas equivalent production per day (Mmcfe/d) in the Appalachian Basin from QRCP in exchange for cash consideration of approximately $72.0 million, subject to post-closing adjustments. QRCP acquired the wellbores as part of its purchase of privately held PetroEdge Resources (WV) LLC, the owner of oil and gas leasehold interests covering approximately 78,000 net acres and related assets in West Virginia, Pennsylvania and New York, and simultaneously sold the wellbores and proved developed reserves to the Company.

          To fund the purchase of the PetroEdge wellbores from QRCP, on July 11, 2008, (i) the Company and Quest Cherokee entered into a six month $45 million Second Lien Senior Term Loan Agreement (the “Second Lien Loan Agreement”) and (ii) Quest Cherokee’s lenders increased the borrowing base of its revolving credit facility to $190 million from $160 million. The Second Loan Agreement is among Quest Cherokee, as the borrower, the Company, as a guarantor, RBC, as administrative agent and collateral agent, KeyBank National Association, as syndication agent, Société Générale, as documentation agent, and the lenders party thereto. Interest will accrue on the term loan (i) from July 11, 2008 through October 11, 2008 at either LIBOR plus 6.5% or the base rate plus 5.5% and (ii) after October 11, 2008 at either LIBOR plus 7.0% or the base rate plus 6.0%. The base rate is generally the higher of the federal funds rate plus 0.50% or RBC’s prime rate. The term loan was fully drawn and $30 million was borrowed under the revolving credit facility at the closing of the acquisition of the PetroEdge wellbores to fund the purchase of the wellbores and pay fees and expenses related to the acquisition. For a further description of the terms of the Second Lien Loan Agreement, see the Company’s Current Report on Form 8-K filed on July 16, 2008.

      Other

          On July 16, 2008, Quest Cherokee received a favorable decision regarding the 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 agreed that Quest Cherokee was not legally responsible for plugging 22 abandoned oil wells on a gas lease owned and operated by Quest Cherokee in Wilson County, Kansas.

          On July 24, 2008, the Company filed a registration statement on Form S-1 with the SEC relating to a proposed offering of 4,600,000 common units. The Company intends to use any net proceeds from the sale of such units to repay indebtedness, including its Second Lien Loan Agreement.

          On July 25, 2008, the board of directors of the General Partner declared a $0.43 per unit distribution for the second quarter of 2008 on all common and subordinated units payable on August 14, 2008 to unitholders of record as of the close of business on August 4, 2008. The aggregate amount of the distribution will be $9.30 million.

           The parties involved in the Kirkpatrick lawsuit (Case No. CJ-2005-143) entered into a confidential settlement agreement and release dated July 31, 2008, and the lawsuit will be dismissed with prejudice.

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 June 30, 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 June 30, 2008, to which these consolidated financial statements form a part, includes our restated consolidated financial statements as of June 30, 2008 and for the three and six month periods ended June 30, 2008 and our Predecessor’s restated and reaudited carve out financial statements for the three and six month periods ended June 30, 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 income (loss), major restatement adjustments and restated net loss as of and for the periods indicated (in thousands):

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

		June 30, 2008
Partners’ equity as previously reported		$	80,110
A — Effect of the Transfers			(9,500	)
B — Reversal of hedge accounting			3,658
C — Accounting for formation of Quest Cherokee			(15,102	)
D — Capitalization of costs in full cost pool			(31,091	)
E — Recognition of costs in proper periods			(2,656	)
F — Depreciation, depletion and amortization			11,000
G — Impairment of oil and gas properties			30,719
H — Other errors			5,136
Partners’ equity as restated		$	72,274

		Three Months Ended June 30,
		2008				2007
Net income (loss) as previously reported		$	16,221			$	(5,231	)
A — Effect of the Transfers			—				(500	)
B — Reversal of hedge accounting			(105,179	)			7,689
C — Accounting for formation of Quest Cherokee			—				—
D — Capitalization of costs in full cost pool			(3,425	)			(3,028	)
E — Recognition of costs in proper periods			(1,699	)			(188	)
F — Depreciation, depletion and amortization			(429	)			(175	)
G — Impairment of oil and gas properties			—				—
H — Other errors			895				230
Net loss as restated		$	(93,616	)		$	(1,203	)

		Six Months Ended June 30,
		2008				2007
Net loss as previously reported		$	(1,125	)		$	(8,924	)
A — Effect of the Transfers			—				(1,000	)
B — Reversal of hedge accounting			(124,375	)			(6,394	)
C — Accounting for formation of Quest Cherokee			—				—
D — Capitalization of costs in full cost pool			(7,084	)			(5,447	)
E — Recognition of costs in proper periods			(1,116	)			(432	)
F — Depreciation, depletion and amortization			(920	)			(655	)
G — Impairment of oil and gas properties			—				—
H — Other errors			239				(1,157	)
Net loss as restated		$	(134,381	)		$	(24,009	)

     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 June 30, 2008, and loss from misappropriation of funds was understated and net income was overstated for the three and six months ended June 30, 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 understated by $5.5 million as of June 30, 2008. In addition, we incorrectly presented

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

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 June 30, 2008, and oil and gas sales and gain (loss) from derivative financial instruments were over/(under)stated for the three and six months ended June 30, 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 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 June 30, 2008, and oil and gas production expenses and general and administrative expenses were over/(under)stated for the three and six months ended June 30, 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 June 30, 2008, and oil and gas production expenses, pipeline operating expenses and general and administrative expenses were over/(under)stated for the three and six months ended June 30, 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 June 30, 2008 and depreciation, depletion and amortization expense was over/(under)stated for the three and six months ended June 30, 2008 and 2007.

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

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

     The following tables outline the effects of the restatement adjustments on our Consolidated Statements of Operations for the periods indicated (in thousands, except unit and per unit data):

		Three Months Ended June 30, 2008
		As Previously				Restatement
		Reported				Adjustments				As Restated
Revenue:
Oil and gas sales		$	39,901			$	9,241			$	49,142
Other revenue (expense)			71				(71	)			—
Total revenues			39,972				9,170				49,142
Costs and expenses:
Oil and gas production			9,763				4,135				13,898
Transportation expense			8,675				—				8,675
General and administrative			1,925				(256	)			1,669
Depreciation, depletion and amortization			9,732				1,123				10,855
Total costs and expenses			30,095				5,002				35,097
Operating income			9,877				4,168				14,045
Other income (expense):
Gain (loss) from derivative financial instruments			8,695				(114,070	)			(105,375	)
Other income (expense)			(26	)			71				45
Interest income			90				—				90
Interest expense			(2,415	)			(6	)			(2,421	)
Total other income (expense)			6,344				(114,005	)			(107,661	)
Net income (loss)		$	16,221			$	(109,837	)		$	(93,616	)
General partner’s interest in net income (loss)			324				(2,196	)			(1,872	)
Limited partners’ interest in net income (loss)			15,897				(107,641	)			(91,744	)
Net income (loss) per limited partner unit (basic and duluted)		$	0.75			$	(5.08	)		$	(4.33	)
Weighted average limited partner units outstanding:
Common units (basic and diluted)			12,331,521				—				12,331,521
Subordinated units (basic and diluted)			8,857,981				—				8,857,981

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

		Six Months Ended June 30, 2008
		As Previously				Restatement
		Reported				Adjustments				As Restated
Revenue:
Oil and gas sales		$	77,252			$	10,202			$	87,454
Other revenue (expense)			120				(120	)			—
Total revenues			77,372				10,082				87,454
Costs and expenses:
Oil and gas production			17,944				6,339				24,283
Transportation expense			17,338				—				17,338
General and administrative			4,383				384				4,767
Depreciation, depletion and amortization			19,242				2,312				21,554
Total costs and expenses			58,907				9,035				67,942
Operating income			18,465				1,047				19,512
Other income (expense):
Loss from derivative financial instruments			(15,136	)			(134,478	)			(149,614	)
Other income (expense)			(6	)			120				114
Interest income			107				—				107
Interest expense			(4,555	)			55				(4,500	)
Total other income (expense)			(19,590	)			(134,303	)			(153,893	)
Net loss		$	(1,125	)		$	(133,256	)		$	(134,381	)
General partner’s interest in loss			(23	)			(2,665	)			(2,688	)
Limited partners’ interest in loss			(1,102	)			(130,591	)			(131,693	)
Net loss per limited partner unit (basic and diluted)		$	(0.05	)		$	(6.17	)		$	(6.22	)
Weighted average limited partner units outstanding:
Common units (basic and diluted)			12,331,521				—				12,331,521
Subordinated units (basic and diluted)			8,857,981				—				8,857,981

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):

		Six Months Ended June 30, 2008
		As Previously				Restatement
		Reported				Adjustments				As Restated
Cash flows from operating activities:
Net loss		$	(1,125	)		$	(133,256	)		$	(134,381	)
Adjustments to reconcile net income (loss) to cash provided by operations:
Depreciation, depletion and amortization			20,586				968				21,554
Gain (loss) from derivative financial instruments			14,969				124,375				139,344
Unit based compensation			—				17				17
Capital contributions for director fees			272				(272	)			—
Capital contributions for employees			1,555				(1,555	)			—
Amortization of loan origination fees			456				(216	)			240
Bad debt expense			10				54				64
(Gain) loss on sale of assets			(21	)			21				—
Change in assets and liabilities:
Restricted cash			1,094				(1,094	)			—
Accounts receivable, trade			436				(140	)			296
Other receivables			(72	)			72				—
Other current assets			(444	)			350				(94	)
Inventory			(4,788	)			4,788				—
Due from affiliates			(12,462	)			6,287				(6,175	)
Other assets			—				101				101
Accounts payable			3,539				4,243				7,782
Revenue payable			—				(99	)			(99	)
Accrued expenses			(167	)			7,691				7,524
Other long-term liabilities			—				445				445
Other			—				1				1
Net cash provided by operating activities			23,838				12,781				36,619
Cash flows from investing activities:
Restricted cash			—				1,093				1,093
Equipment, development and leasehold			(54,451	)			(6,521	)			(60,972	)
Net cash used in investing activities			(54,451	)			(5,428	)			(59,879	)
Cash flows from financing activities:
Proceeds from revolver note			48,000				—				48,000
Repayments of note borrowings			(312	)			(1	)			(313	)
Capital contributions (distributions)			(5,590	)			6,040				450
Distributions to unitholders			—				(13,277	)			(13,277	)
Proceeds from issuance of common units			(201	)			201				—
Refinancing costs			(116	)			(149	)			(265	)
Change in other long-term liabilities			167				(167	)			—
Net cash provided by financing activities			41,948				(7,353	)			34,595
Net increase (decrease) in cash			11,335				—				11,335
Cash and cash equivalents beginning of period			10,170				(10,001	)			169
Cash and cash equivalents end of period		$	21,505			$	(10,001	)		$	11,504