Quest Energy Partners, L.P. - Quarterly Report (10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)


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

For the quarterly period ended 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 þ No o

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


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

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

As of August 8, 2008, the issuer had 12,331,521 common units outstanding.

QUEST ENERGY PARTNERS, L.P.

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2008

TABLE OF CONTENTS


PART I — FINANCIAL INFORMATION			4
Item 1. Financial Statements			4
Balance Sheets: June 30, 2008 and December 31, 2007			F-1
Statements of Operations and Comprehensive Income: 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			5
Item 3. Quantitative and Qualitative Disclosures About Market Risk			14
Item 4(T). Controls and Procedures			14

PART II — OTHER INFORMATION			14
Item 1. Legal Proceedings			14
Item 1A. Risk Factors			14
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			16
Item 3. Defaults Upon Senior Securities			16
Item 4. Submission of Matters to a Vote of Security Holders			16
Item 5. Other Information			16
Item 6. Exhibits			17

SIGNATURES			19

-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 our Parent located in the Cherokee Basin (other than its midstream assets), which our Parent 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 “our Parent,” we are referring to Quest Resource Corporation (Nasdaq: QRCP), the owner of our general partner, and its subsidiaries (other than us); and

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

-3-

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements .

Attached hereto as Pages F-1 through F-23 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 and comprehensive income for the three and six months ended June 30, 2008 and consolidated statement of cash flows for the six months ended June 30, 2008 and (ii) the Predecessor’s unaudited interim financial statements, including carve out statements of operations and comprehensive income for the three and six months ended June 30, 2007 and carve out statement of cash flows for the six months ended June 30, 2007.

The financial statements included herein have been prepared internally, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission and the Public Company Accounting Oversight Board. 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 financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007 (the “2007 Form 10-K”).

-4-

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

($ in thousands)


	June 30,			December 31,
	2008			2007
	(Unaudited)			(Audited)
ASSETS
Current assets:
Cash	$	21,505		$	10,170
Restricted cash		112			1,205
Accounts receivable, trade		—			297
Due from affiliated companies		18,948			12,788
Other current assets		3,367			2,923
Inventory		9,845			4,956
Short-term derivative asset		151			6,729

Total current assets		53,928			39,068
Property and equipment, net of accumulated depreciation of $7,481 and $6,183		18,665			17,063
Oil and gas properties:
Properties being amortized		460,646			406,661
Properties not being amortized		19,399			19,328

		480,045			425,989
Less: Accumulated depreciation, depletion, amortization and impairment		(147,139	)		(127,968	)

Net property plant and equipment		332,906			298,021
Other assets, net		3,185			3,526
Long-term derivative asset		—			1,568

Total assets	$	408,684		$	359,246


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	18,815		$	15,195
Accrued expenses		17,448			5,056
Current portion of notes payable		247			666
Short-term derivative liability		66,379			8,241

Total current liabilities		102,889			29,158
Non-current liabilities:
Long-term derivative liability		81,597			5,586
Asset retirement obligation		1,939			1,700
Notes payable		142,396			94,708
Less current maturities		(247	)		(666	)

Non-current liabilities		225,685			101,328

Total liabilities		328,574			130,486

Commitments and contingencies
Partners’ equity:
Partners’ equity		208,921			230,245
Accumulated other comprehensive (loss)		(128,811	)		(1,485	)

Total partners’ equity		80,110			228,760

Total liabilities and partners’ equity	$	408,684		$	359,246

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

F-1

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(UNAUDITED)

($ in thousands, except per unit data)


	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	$	39,901		$	27,867		$	77,252		$	53,416
Other revenue (expense)		71			(19	)		120			(32	)

Total revenues		39,972			27,848			77,372			53,384

Costs and expenses:
Oil and gas production		18,438			14,549			35,282			28,137
General and administrative		1,925			4,093			4,383			5,846
Depreciation, depletion and amortization		9,732			7,326			19,242			14,063

Total costs and expenses		30,095			25,968			58,907			48,046

Operating income		9,877			1,880			18,465			5,338

Other income (expense):
Other income (expense)		(26	)		(304	)		(6	)		(197	)
Change in derivative fair value		8,695			279			(15,136	)		(185	)
Interest income		90			103			107			280
Interest expense		(2,415	)		(7,189	)		(4,555	)		(14,160	)

Total other income (expense)		6,344			(7,111	)		(19,590	)		(14,262	)


Income (loss) before income taxes		16,221			(5,231	)		(1,125	)		(8,924	)
Income tax expense — deferred		—			—			—			—

Net Income (loss)	$	16,221		$	(5,231	)	$	(1,125	)	$	(8,924	)


Comprehensive income (loss)	$	(95,341	)	$	2,682		$	(128,451	)	$	(14,492	)

General partner’s interest in net income (loss)	$	324					$	(23	)

Limited partners’ interest in net income (loss)	$	15,897					$	(1,102	)

Net income (loss) per limited partner unit:
Common units (basic and diluted)	$	0.75					$	(0.05	)

Subordinated units (basic and diluted)	$	0.75					$	(0.05	)

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.

F-2

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

STATEMENTS OF CASH FLOWS

(UNAUDITED)

($ in thousands)


	Successor			Predecessor
	For the Six Months Ended
	June 30,
	2008			2007
	(Consolidated)			(Carve out)
Cash flows from operating activities:
Net (loss)	$	(1,125	)	$	(8,924	)
Adjustments to reconcile net income (loss) to cash provided by (used in) operations:
Depreciation and depletion		20,586			15,316
Change in derivative fair value		14,969			185
Capital contributions for directors’ fees		272			(25	)
Capital contributions for employees		1,555			2,343
Amortization of loan origination fees		456			1,024
Amortization of gas swap fees		—			125
Bad debt expense		10			—
(Gain) loss on sale of assets		(21	)		240
Change in assets and liabilities:
Restricted Cash		1,094			(10	)
Accounts receivable		436			(2,602	)
Other receivables		(72	)		(1,143	)
Other current assets		(444	)		(591	)
Inventory		(4,788	)		(1,083	)
Due from affiliates		(12,462	)		—
Accounts payable		3,539			(3,496	)
Revenue payable		—			2,524
Accrued expenses		(167	)		(1,344	)

Net cash provided by operating activities		23,838			2,539
Cash flows from investing activities:
Equipment, development and leasehold costs		(42,026	)		(41,804	)
Oil and gas property acquisition		(9,500	)		—
Net additions to other property and equipment		(2,925	)		(3,662	)
Proceeds from sale of property and equipment		—			(20	)
Increase in other assets		—			(10	)

Net cash used in investing activities		(54,451	)		(45,496	)
Cash flows from financing activities:
Proceeds from bank borrowings		48,000			10,000
Repayments of note borrowings		(312	)		(300	)
Proceeds from issuance of common stock		(201	)		—
Capital contributions (distributions)		(5,590	)		23,511
Refinancing costs		(116	)		(1,688	)
Change in other long-term liabilities		167			80

Net cash provided by financing activities		41,948			31,603

Net increase (decrease) in cash		11,335			(11,354	)
Cash, beginning of period		10,170			21,334

Cash, end of period	$	21,505		$	9,980

Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest expense	$	4,102		$	14,160
Income taxes	$	—		$	—

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

F-3

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO UNAUDITED 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, “QRC”) 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, QRC 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 QRC’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.

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

2. Basis of Presentation

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, 2007 (the “2007 Form 10-K”).

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.

The accompanying 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 QRC are only indirectly attributable to its ownership of the Cherokee Basin Operations as QRC owns interests in midstream assets and other natural gas and oil 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.

3. Summary of Significant Accounting Policies

Reference is hereby made to the 2007 Form 10-K, which contains a summary of significant accounting policies followed by the Company in the preparation of its consolidated/carve out financial statements. These policies were also followed in preparing the consolidated/carve out 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.

F-4

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

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

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

F-5

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

Other Current Assets

Other current assets totaled $3.4 million at June 30, 2008 as compared to $2.9 million at December 31, 2007. At June 30, 2008, other current assets consisted of deposits of $1.6 million, prepaid insurance and fees of $1.4 million, and other items of $400,000. At December 31, 2007, other current assets consisted of deposits of $1.2 million and prepaid insurance and fees of $1.7 million.

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 natural gas and oil. These derivative contracts expose the Company to credit risk from its counterparties. The Company’s accounts receivable are primarily from purchasers of natural gas and oil 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 72% and 28% 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.

Natural Gas and Oil Properties

The Company follows the full cost method of accounting for natural gas and oil 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 natural gas and oil properties, as well as other directly identifiable general and administrative costs associated with such activities.

All capitalized costs of natural gas and oil 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 (adjusted for cash flow hedges) 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. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives qualifying as cash flow hedges. 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.

Based on the low natural gas prices on December 31, 2007, the Company would have incurred a non-cash impairment loss of approximately $14.9 million for the quarter ended December 31, 2007. However, under the SEC’s accounting guidance in Staff Accounting Bulletin Topic 12(D)(e), if natural gas prices increase sufficiently between the end of a period and the completion of the financial statements for that period to eliminate the need for an impairment charge, an issuer is not required to recognize the non-cash impairment loss in its financial statements for that period. As of March 1, 2008, natural gas prices had improved sufficiently to

F-6

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

eliminate the need for an impairment loss at December 31, 2007 and as a result, no impairment loss is reflected in the Company’s financial statements for the year ended December 31, 2007.

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 is reviewed on an annual basis for impairment and as of December 31, 2007, the Company had not identified any such impairment. Repairs and maintenance are charged to operations when incurred and improvements and renewals are capitalized.

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

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 natural gas and oil 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 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.

F-7

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

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 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.

The Company’s asset retirement obligation is measured using primarily Level III inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs. See Note 8 for a roll-forward of the asset retirement obligation.

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. The Company generally determines the fair value of futures contracts and swap contracts based on the difference between the derivative’s fixed contract price and the underlying market price at the determination date. The fair value of call options and collars are generally determined under the Black-Scholes option-pricing model. Most values are confirmed by counterparties to the derivative contracts.

Realized and unrealized gains and losses on derivative contracts that are not designated as hedges, as well as on the ineffective portion of hedge derivative contracts, are recorded as a derivative fair value gain or loss in the income statement. Unrealized gains and losses on effective cash flow hedge derivative contracts, as well as any deferred gain or loss realized upon early termination of effective hedge derivative contracts, are recorded as a component of accumulated other comprehensive income (loss). When the hedged transaction occurs, the realized gain or loss, as well as any deferred gain or loss, on the hedge derivative contract is transferred from accumulated other comprehensive income (loss) to earnings. Realized gains and losses on commodity hedge derivative contracts are recognized in oil and gas revenues. Settlements of derivative contracts are included in cash flows from operating activities.

To summarize, the Company records its derivative contracts at fair value in its consolidated balance sheets. Gains and losses resulting from changes in fair value and upon settlement are reported as follows:

F-8

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


	Fair Value
Derivative Type	Gains/Losses	Financial Statement Reporting
Non-hedge derivatives and Hedge derivatives— ineffective portion	Unrealized and Realized	Reported in the consolidated income statements as derivative fair value (gain) loss

Hedge derivatives— effective portion	Unrealized	Reported in partners’ equity in the consolidated balance sheets as accumulated other comprehensive (loss)

	Realized	Reported in the consolidated income statements and classified based on the hedged item (e.g., gas revenue or oil revenue)

To designate a derivative contract as a cash flow hedge, the Company documents at the derivative contract’s inception the Company's assessment that the derivative contract will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative contract and the item hedged. The ineffective portion of the derivative contract is calculated as the difference between the change in fair value of the derivative contract and the estimated change in cash flows from the item hedged. If, during the derivative contract’s term, the Company determines the derivative contract is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative contract at that date, are reclassified to earnings as oil or gas revenue when the underlying transaction occurs, but re-designation is permitted.

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.

The Company’s asset retirement obligations relate to the plugging and abandonment of natural gas and oil properties.

Net Income per Limited Partner Unit

The Company calculates net income per limited partner unit in accordance with Emerging Issues Task Force 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 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.

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. QRC 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 QRC on behalf of the Predecessor; however, these allocations may not be indicative of the cost of future operations or the amount of future allocations.

F-9

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

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 QRC 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 13 — Related Party Transactions”.

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

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

	•		third party costs incurred at the QRC 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 QRC, 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 partner’s 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 QRC. 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

F-10

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

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

F-11

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

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 $68,000 and $272,000, 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 9.8% 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 December 31, 2013 and thereafter were as follows as June 30, 2008 (assuming no payments were made on the revolving credit facility prior to its maturity)(dollars in thousands):


2008	$	247
2009		59
2010		142,052
2011		26
2012		6
2013		6
Thereafter		—

	$	142,396

Credit Facility

Quest Cherokee, LLC 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 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

F-12

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

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 14 — 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 9.8% per annum.

7. Financial Instruments and Hedging Activities

Natural Gas and Oil Hedging Activities

The Company seeks to reduce its exposure to unfavorable changes in natural gas and oil 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 natural gas and oil 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. For the six months ended June 30, 2008 and 2007, fixed-price contracts hedged approximately 58.55% and 68.2%, respectively, of the Company’s natural gas production. As of June 30, 2008, fixed-price contracts are in place to hedge 43.2 Bcf of estimated future natural gas production. Of this total volume, 6.0 Bcf are hedged for 2008 and 37.2 Bcf 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. Natural gas and oil 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 natural gas or oil 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 natural gas or oil is between the call and the put strike price, then no payments are due from either party.

The following table summarizes the estimated volumes, fixed prices, fixed-price sales and fair value attributable to the fixed-price contracts as of 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)		2,511,000			14,629,000			12,499,000			2,000,000			2,000,000			33,639,000
Weighted average fixed price per MMBtu (1)	$	8.16		$	7.85		$	7.42		$	8.00		$	8.11		$	7.74
Fixed-price sales	$	20,488		$	114,861		$	92,778		$	16,000		$	16,220		$	260,347
Fair value, net	$	(9,356	)	$	(52,065	)	$	(34,220	)	$	(3,781	)	$	(3,485	)	$	(102,907	)
Natural Gas Collars:
Contract volumes (MMBtu)
Floor		3,533,000			—			—			3,000,000			3,000,000			9,533,000
Ceiling		3,533,000			—			—			3,000,000			3,000,000			9,533,000

F-13

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED 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		$	6.75
Ceiling	$	7.54		$	—		$	—		$	9.60		$	9.40		$	8.44
Fixed-price sales (2)	$	23,112		$	—		$	—		$	21,000		$	21,000		$	65,112
Fair value, net	$	(18,506	)	$	—		$	—		$	(4,564	)	$	(4,353	)	$	(27,423	)
Total Natural Gas Contracts(3):
Contract volumes (MMBtu)		6,044,000			14,629,000			12,499,000			5,000,000			5,000,000			43,172,000
Weighted average fixed price per MMBtu (1)	$	7.21		$	7.85		$	7.42		$	7.40		$	7.44		$	7.54
Fixed-price sales (2)	$	43,600		$	114,861		$	92,778		$	37,000		$	37,220		$	325,459
Fair value, net	$	(27,862	)		($52,065	)		($34,220	)		($8,345	)		($7,838	)	$	(130,330	)
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
Fixed-price sales	$	1,727		$	3,243		$	2,625			—			—		$	7,594
Fair value, net	$	(918	)	$	(1,758	)	$	(1,413	)	$	—		$	—		$	(4,089	)


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

(2)		Assumes ceiling prices for natural gas collar volumes.

(3)		Does not include basis swaps with a notional volume of 3,156,000 MMBtu for 2008.

The estimates of fair value of the fixed-price contracts are computed based on the difference between the prices provided by the fixed-price contracts and forward market prices as of the specified date, as adjusted for basis. Forward market prices for natural gas are dependent upon supply and demand factors in such forward market and are subject to significant volatility. The fair value estimates shown above are subject to change as forward market prices and basis change.

The differential between the fixed price and the floating price for each contract settlement period multiplied by the associated contract volume is the contract profit or loss. For fixed-price contracts qualifying as cash flow hedges pursuant to SFAS 133, the realized contract profit or loss is included in oil and gas sales in the period for which the underlying production was hedged. For the six months ended June 30, 2008 and 2007, oil and gas sales included $10.1 million and $1.4 million, respectively, of net losses associated with realized losses under fixed-price contracts.

For contracts that did not qualify as cash flow hedges, the realized contract profit and loss is included in the change in derivative fair value in the period for which the underlying production was hedged. For the six months ended June 30, 2008, $166,000 was included in the change in derivative fair value for contracts that did not qualify as cash flow hedges. For the six months ended June 30, 2007, all of the Company’s fixed price contracts qualified as cash flow hedges.

For fixed-price contracts qualifying as cash flow hedges, changes in fair value for volumes not yet settled are shown as adjustments to other comprehensive income. For those contracts not qualifying as cash flow hedges, changes in fair value for volumes not yet settled are recognized in change in derivative fair value in the statement of operations. The fair value of all fixed-price contracts are recorded as assets or liabilities in the balance sheet.

Based upon market prices at June 30, 2008, the estimated amount of unrealized gains for fixed-price contracts shown as adjustments to other comprehensive income that are expected to be reclassified into earnings as actual contract cash settlements are realized within the next 12 months is $70.1 million.

Interest Rate Hedging Activities

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

F-14

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

Change in Derivative Fair Value

Change in derivative fair value 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
	For the Three						For the Six
	Months Ended						Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	($ in thousands)
Change in fair value of derivative not qualifying as cash flow hedges	$	(3,409	)	$	(285	)	$	(26,957	)	$	(1,321	)
Settlements due to ineffective cash flow hedges		(167	)		—			(167	)		—
Ineffective portion of oil derivatives qualifying as cash flow hedges		12,271			564			11,988			1,136

	$	8,695		$	279		$	(15,136	)	$	(185	)

The amounts recorded in change in derivative fair value do not represent cash gains or losses, except for the settlements due to ineffective cash flow hedges. The change in fair value of derivatives not qualifying as cash flow hedges and ineffective portion of oil derivatives qualifying as cash flow hedges are temporary valuation swings in the fair value of the contracts, and as a result, all amounts initially recorded in these captions are ultimately reversed within these same captions over the respective contract terms.

Fair Value Measurements

The estimated fair values of derivative contracts included in the consolidated balance sheets at June 30, 2008 and December 31, 2007 are summarized below. The increase in the net derivative liability from December 31, 2007 to June 30, 2008 is primarily attributable to the effect of higher natural gas and crude oil prices, partially offset by cash settlements of derivatives.


	June 30, 2008						December 31, 2007
	Significant						Significant
	Other			Significant			Other			Significant
	Observable			Unobservable			Observable			Unobservable
	Inputs			Inputs			Inputs			Inputs
	(Level II)			(Level III)			(Level II)			(Level III)
	(in thousands)
Derivative Assets:
Fixed-price natural gas futures and basis swaps	$	151		$	—		$	8,297		$	—
Fixed-price oil futures		—			—			—			—
Derivative Liabilities:											—
Fixed-price natural gas futures and basis swaps		(143,888	)		—			(13,827	)		—
Fixed-price oil futures		(4,088	)		—			—			—

Net derivative liability	$	(147,825	)	$	—		$	(5,530	)	$	—

Asset retirement obligation	$	—		$	(1,939	)	$	—		$	(1,700	)

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 recorded in accordance with the provisions of Statement of Financial Accounting Standards 133, Accounting for Derivative Instruments and Hedging Activities . 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.

F-15

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

Cancellation or termination of a fixed-price contract would subject a greater portion of the Company’s natural gas and oil 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 natural gas and oil that is significantly below the price stated in the fixed-price contract.

Changes in future gains and losses to be realized in natural gas and oil sales upon cash settlements of fixed-price contracts as a result of changes in market prices for natural gas and oil are expected to be offset by changes in the price received for hedged natural gas and oil 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	$	1,820		$	1,477		$	1,700		$	1,410
Liabilities incurred		83			42			171			83
Liabilities settled		(1	)		(2	)		(3	)		(3	)
Accretion expense		37			29			71			56
Revisions in estimated cash flows		—			—			—			—

Asset retirement obligation ending balance	$	1,939		$	1,546		$	1,939		$	1,546

F-16

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

9. Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources. These changes, other than net income, are referred to as “other comprehensive income (loss)” and, for the Company, include changes in the fair value of unrealized hedging contracts related to derivative contracts. A reconciliation of the Company’s comprehensive (loss) for the periods indicated is as follows (in thousands):


	Successor			Predecessor			Successor			Predecessor
	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2008			2007			2008			2007
	(Consolidated)			(Carve out)			(Consolidated)			(Carve out)
Net Income (loss)	$	16,221		$	(5,231	)	$	(1,125	)	$	(8,924	)
Other comprehensive income (loss), net of tax:
Change in fixed-price contract and other derivative fair value, net of tax of $0 for all periods		(121,665	)		8,341			(138,641	)		(4,145	)
Reclassification adjustments — contract settlements, net of tax of $0 for all periods		10,103			(428	)		11,315			(1,423	)

Other comprehensive income (loss)		(111,562	)		7,913			(127,326	)		(5,568	)

Comprehensive income (loss)	$	(95,341	)	$	2,682		$	(128,451	)	$	(14,492	)

10. 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 $8.0 million.

11. Net Income (Loss) Per Limited Partner Unit

The computation of net income (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 income (loss) per limited partner unit is determined by dividing net income (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 income (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 income (loss)	$	16,221	$		$	(1,125	)
Less: General partner’s 2% interest in net income (loss)		324				(23	)

Net income (loss) available for limited partners	$	15,897	$	0.75		(1,102	)	$	(0.05	)

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.

12. 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

F-17

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED 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.

F-18

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED 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 are pending 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. Discovery in those cases is ongoing. 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 14 — 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.

13. 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, QRC 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 QRC, 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 . QRC controls Quest Midstream Partners, L.P. (“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, QRC 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

F-19

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED 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.

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 gas and oil 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 QRC and Quest Midstream and will be reimbursed by QRC 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 QRC 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 QRC 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 QRC are parties to an omnibus agreement, dated November 15, 2007, which governs the Company’s relationship with QRC and its subsidiaries with respect to certain matters not governed by the management services agreement.

Under the omnibus agreement, QRC 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, QRC 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

F-20

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED 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, QRC 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, QRC 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). QRC’s maximum liability for the environmental indemnification obligations will not exceed $5.0 million and QRC will not have any indemnification obligation for environmental claims or title defects until the Company’s aggregate losses exceed $500,000. QRC 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 QRC against environmental liabilities related to the Company’s assets to the extent QRC is not required to indemnify the Company. The Company also will indemnify QRC for all losses attributable to post-November 15, 2007 operations of the assets contributed to the Company, to the extent not subject to QRC’s indemnification obligations.

Any or all of the provisions of the omnibus agreement, other than the indemnification provisions described above, are terminable by QRC 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 QRC so long as the Company is an affiliate of QRC and QRC 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.

F-21

QUEST ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED 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 QRC entered into a contribution, conveyance and assumption agreement to effect, among other things, the transfer of QRC’s Cherokee Basin Operations to the Company, the issuance of 3,201,521 common units and 8,857,981 subordinated units to QRC and the issuance to the General Partner of 431,827 general partner units and the incentive distribution rights. The Company agreed to indemnify QRC 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.

14. Subsequent Events

PetroEdge Acquisition

On July 11, 2008, the Company purchased over 400 natural gas and oil 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 QRC in exchange for cash consideration of approximately $71.6 million, subject to post-closing adjustments. QRC 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 QRC, 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.

F-22

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

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.

F-23

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

Business of Issuer

We are a Delaware limited partnership formed in July 2007 by our Parent to acquire, exploit and develop oil and natural gas properties. Our primary business objective is to generate stable cash flows allowing us to make quarterly cash distributions to our unitholders at our current distribution rate and, over time, to increase our quarterly cash distributions. As of June 30, 2008, our operations were focused on the development of coal bed methane in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma.

Significant Developments During the Six Months Ended June 30, 2008

During the six months ended June 30, 2008, we continued to be focused on drilling and completing new wells. We drilled 243 gross wells and completed the connection of 183 gross wells during this period. As of June 30, 2008, we had approximately 60 additional gas wells (gross) that we were in the process of completing and connecting to Quest Midstream’s gas gathering pipeline system.

We acquired additional natural gas leases in the Cherokee Basin covering approximately 22,600 acres (net) during the six months ended June 30, 2008.

For the six months ended June 30, 2008, our average net daily production was 56.4 million cubic feet of natural gas equivalents per day ("Mmcfe/d").

We purchased certain oil producing properties in Seminole County, Oklahoma from a private company for $9.5 million in a transaction that closed in early February 2008. As of February 1, 2008, the properties had estimated net proved reserves of 761,400 barrels, all of which are proved developed producing. In addition, we entered into crude oil swaps for approximately 80% of the estimated net production from the property’s proved developed producing reserves at WTI-NYMEX prices per barrel of oil of approximately $96.00 in 2008, $90.00 in 2009, and $87.50 for 2010. The acquisition was financed with borrowings under our credit facility.

Recent Developments

PetroEdge Acquisition

On June 5, 2008, our Parent entered into a purchase and sale agreement to acquire all the equity interests in PetroEdge for approximately $142 million, subject to closing adjustments. On July 11, 2008, the acquisition of PetroEdge was finalized.

Simultaneous with the closing of this acquisition, we purchased from our Parent all of its interest in wellbores and related assets in West Virginia and New York associated with proved developed producing and proved developed non-producing reserves for approximately $71.6 million, subject to post-closing adjustments. The purchase price was based on the value of the proved reserves associated with the wellbores transferred to us. We purchased over 400 natural gas and oil wellbores with estimated proved net reserves of 32.9 Bcfe as of May 1, 2008 and net production of approximately 3.2 Mmcfe/d as of July 11, 2008 from our Parent. An additional 66.7 Bcfe of estimated net proved undeveloped reserves and property acquired in the acquisition were retained by our Parent.

PetroEdge was a growth oriented energy company engaged in the acquisition, exploration and exploitation of natural gas and crude oil properties. PetroEdge’s focus was an aggressive acquisition and development program focused on the Eastern United States, in the Marcellus, Mississippian and Devonian formations in the Appalachian Basin.

At May 1, 2008, PetroEdge’s total net proved reserves were estimated at 99.6 Bcfe, of which approximately 95.5% were natural gas and 33.0% were classified as proved developed, with a standardized measure of approximately $257.9 million. PetroEdge has an average net revenue interest of 81% on an 8/8 ^ths basis.

PetroEdge’s properties consist of approximately 78,000 net acres in West Virginia, Pennsylvania and New York of which approximately 70,600 net acres are located within the generally recognized fairway of the Marcellus Shale. Included in this acreage is approximately 22,200 net acres in Lycoming County, Pennsylvania, which has seen high leasing activity by companies active in the Marcellus Shale. At the time of the acquisition, PetroEdge had over 400 wellbores, with 113 of the wells having been recently drilled by PetroEdge. Of these recently drilled wells, 100 have confirmed Marcellus Shale, and 42 wells are currently producing from the Marcellus Shale. Additionally, we believe there are over 700 potential vertical well locations for the Marcellus Shale, including significant development opportunities for Devonian Sands and Brown Shales in the same wellbore.

During the year ended December 31, 2007 and the three months ended March 31, 2008, PetroEdge sold approximately 88% and 81%, respectively, of its gas to Dominion Field Services, Inc. No other customer accounted for more than 10% of revenues for the year ended December 31, 2007 or the three months ended March 31, 2008. In general, PetroEdge sold its gas under sale and purchase contracts, which have indefinite terms but may be terminated by either party on 30 days’ notice, other than with respect to pending transactions, or less following an event of default. In general, the contracts provide for sales prices equal to current market prices. However, PetroEdge has entered into fixed-price contracts covering 95,000 MMbtu per month through March 31,

2009 at prices ranging from $8.20/MMbtu to $9.32/MMbtu, 50,000 MMbtu per month from April 1, 2009 through October 31, 2009 at prices ranging from $8.76/MMbtu to $9.08/MMbtu and 40,000 MMbtu per month from November 1, 2009 through March 31, 2010 at a price of $8.76/MMbtu. We have agreed to sell gas to our Parent in the quantities, times and prices necessary for our Parent to fulfill its obligations under these contracts.

On July 11, 2008, we funded the purchase of the wellbores from our Parent with borrowings under our existing revolving credit facility and a six-month $45 million bridge facility. In connection with the acquisition, our lenders increased the borrowing base of our revolving credit facility to $190 million from $160 million.

Results of Operations

The following discussion of the results of operations and period-to-period comparisons presented below includes the historical results of the Predecessor. This discussion should be read in conjunction with the financial statements included in this report; and should further be read in conjunction with the audited financial statements and notes thereto of the Predecessor included in our 2007 Form 10-K. Comparisons made between reporting periods herein are for the three and six month periods ended June 30, 2008 as compared to the same periods in 2007. As discussed under Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Factors That Significantly Affect Comparability of Our Results” in our 2007 Form 10-K, the Predecessor’s historical results of operations and period-to-period comparisons of its results may not be indicative of our future results.

Overview. The following discussion of results of operations will compare balances for the three and six months ended June 30, 2008 and 2007.


	For the Three Months											For the Six Months
	Ended June 30,											Ended June 30,
	Successor		Predecessor			Increase						Successor			Predecessor			Increase
	2008		2007			(Decrease)						2008			2007			(Decrease)
									($ in thousands)
Oil and gas sales	$	39,901	$	27,867		$	12,034			43.2	%	$	77,252		$	53,416		$	23,836		44.6	%
Other revenue/(expense)	$	71	$	(19	)	$	90			n/m		$	120		$	(32	)	$	152		n/m
Oil and gas production costs	$	9,763	$	7,723		$	2,040			26.4	%	$	17,944		$	14,967		$	2,977		19.9	%
Transportation expense (related affiliate)	$	8,675	$	6,809		$	1,866			27.4	%	$	17,338		$	13,170		$	4,168		31.6	%
Depreciation, depletion and amortization	$	9,732	$	7,326		$	2,406			32.8	%	$	19,242		$	14,063		$	5,179		36.8	%
General and administrative expense	$	1,925	$	4,093		$	(2,168	)		-53.0	%	$	4,383		$	5,846		$	(1,463	)	-25.0	%
Change in derivative fair value	$	8,695	$	279		$	8,416			n/m		$	(15,136	)	$	(185	)	$	(14,951	)	n/m
Interest expense	$	2,415	$	7,189		$	(4,774	)		-66.4	%	$	4,555		$	14,160		$	(9,605	)	-67.8	%


n/m	— not meaningful

Production. The following table presents the primary components of revenues, as well as the average costs per Mcfe, for the three and six months ended June 30, 2008 and 2007.


	For the Three Months									For the Six Months
	Ended June 30,									Ended June 30,
					Increase									Increase
	2008		2007		(Decrease)					2008		2007		(Decrease)
Production Data (net):
Natural gas production (MMcf)		5,113		4,058		1,055		26	%		10,104		7,774		2,330		30	%
Oil production (Bbl)		16,599		1,935		14,664		758	%		27,787		3,955		23,832		603	%
Total production (MMcfe)		5,213		4,069		1,144		28	%		10,271		7,797		2,474		32	%
Average daily production (MMcfe/d)		57.3		44.7		12.6		28	%		56.4		43.3		13.1		30	%

Average Sales Price per Unit:
Natural gas equivalents (Mcfe) —
Excluding hedges	$	9.36	$	6.50	$	2.86		44	%	$	8.50	$	6.67	$	1.83		27	%
Including hedges	$	7.62	$	6.85	$	0.77		11	%	$	7.51	$	6.85	$	0.66		10	%

Natural gas (Mcf) —
Excluding hedges	$	9.18	$	6.49	$	2.69		41	%	$	8.35	$	6.66	$	1.69		25	%
Including hedges	$	7.44	$	6.84	$	0.60		9	%	$	7.35	$	6.85	$	0.50		9	%

Oil (Bbl) —
Excluding hedges	$	111.25	$	55.32	$	55.93		101	%	$	105.96	$	52.77	$	53.19		101	%
Including hedges	$	101.21	$	55.32	$	45.09		83	%	$	99.96	$	52.77	$	47.19		89	%

Average Unit Costs per Mcfe:
Production costs	$	1.87	$	1.90	$	(0.03	)	-2	%	$	1.75	$	1.93	$	(0.18	)	-9	%
Transportation expense (intercompany)	$	1.66	$	1.68	$	(0.02	)	-1	%	$	1.69	$	1.69	$	0.00		0.00	%
Depreciation, depletion and amortization	$	1.87	$	1.80	$	0.07		4	%	$	1.87	$	1.80	$	0.07		4	%
General and administrative expense	$	0.37	$	1.01	$	(0.64	)	-63	%	$	0.43	$	0.75	$	(0.32	)	-43	%
Interest expense	$	0.46	$	1.77	$	(1.30	)	-74	%	$	0.44	$	1.82	$	(1.38	)	-76	%

Three Months Ended June 30, 2008 Compared with the Three Months Ended June 30, 2007

Oil and Gas Sales. The $12.0 million (43.2%) increase in oil and gas sales from $27.9 million for the three months ended June 30, 2007 to $39.9 million for the three months ended June 30, 2008 was primarily attributable to the increase in production volumes and sales prices reflected in the table above. The increase in production volumes was achieved by the addition of more producing wells, which was mostly offset by the natural decline in production from some of our older natural gas wells. The additional wells contributed to the production of 5,113 MMcf of net natural gas for the three months ended June 30, 2008, as compared to 4,058 MMcf produced for the three months ended June 30, 2007. Our product prices on an equivalent basis (Mcfe) increased from an average of $6.50 per of net natural gas Mcfe for the three months ended June 30, 2007 to an average of $9.36 per Mcfe for the three months ended June 30, 2008. For the three months ended June 30, 2008, the net product price, after accounting for the loss on hedging settlements of $8.9 million, averaged $7.62 per Mcfe. For the three months ended June 30, 2007, the net product price, after accounting for the gain on hedging settlements of $427,000, averaged $6.85 per Mcfe.

Other Revenue/(Expense) . Other revenue for the three months ended June 30, 2008 was $71,000 as compared to other expense of $19,000 for the three-month period ended June 30, 2007 due to an increase in marketing fees.

Operating Expenses. Operating expenses, which consist of oil and gas production costs and transportation expense, totaling $18.4 million for the three months ended June 30, 2008, were comprised of lease operating costs of $6.3 million, production taxes of $2.4 million, ad valorem taxes of $961,000, and transportation expenses of $8.7 million. The current operating expenses compared to $14.5 million for the three months ended June 30, 2007, comprised of lease operating costs of $5.6 million, production taxes of $1.2 million, ad valorem taxes of $883,000, and transportation expenses of $6.8 million, a total increase of $3.9 million, or 26.9%. The increase in total operating costs is due to the acquisition of oil properties in February 2008, legal fees, electrical costs and road work. Production taxes increased by approximately 100% due to increased production and a 41% increase in wellhead natural gas prices.

Unit production costs, excluding gross production and ad valorem taxes, were $1.22 per Mcfe for the three months ended June 30, 2008 compared to $1.38 per Mcfe for the three months ended June 30, 2007 representing an 11.6% decrease. Unit production costs, inclusive of gross production and ad valorem taxes, were $1.90 per Mcfe for the 2007 period as compared to $1.87 per Mcfe for the three months ended June 30, 2008 period, representing a 1.6% decrease.

Transportation expense increased $1.9 million from $6.8 million for the three months ended June 30, 2007 compared to $8.7 million for the three months ended June 30, 2008. The transportation expense per Mcfe was essentially flat ($1.66 in 2008 and $1.68 in 2007).

Depreciation, Depletion and Amortization. We are subject to variances in our depletion rates from period to period, including the periods described below. These variances result from changes in our oil and natural gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our natural gas and oil properties. Our depletion of natural gas and oil properties as a percentage of natural gas and oil revenues was 24% for the three months ended June 30, 2008 compared to 26% for the three months ended June 30, 2007. Depreciation, depletion and amortization expense was $1.87 per Mcfe for the three months ended June 30, 2008 compared to $1.80 per Mcfe the three months ended June 30, 2007. Increases in our depletable basis and production volumes caused depreciation, depletion and amortization expense to increase $2.4 million to $9.7 million for the three months ended June 30, 2008 compared to $7.3 million for the three months ended June 30, 2007.

General and Administrative Expense. General and administrative expense decreased from $4.1 million for the three months ended June 30, 2007 to $1.9 million for the three months ended June 30, 2008. This decrease is due in part to a decrease in legal fees that are not allocable to specific properties, salaries including stock awards to employees, and an increase in capitalized general and administrative costs to the full cost pool offset by an increase in board fees, larger corporate offices, and professional fees. The decrease in general and administrative expense in 2008 is due in part to the fact that prior to our formation in 2007 our Parent allocated all of its general and administrative expenses to our Predecessor and Quest Midstream and did not have any unallocated corporate general and administrative expense.

Change in Derivative Fair Value. Change in derivative fair value was a non-cash gain of $8.7 million for the three months ended June 30, 2008, which included a $3.4 million loss attributable to the change in fair value for certain derivative contracts that did not qualify as cash flow hedges pursuant to SFAS 133 and a gain of $12.3 million relating to hedge ineffectiveness. Change in derivative fair value was a non-cash gain of $279,000 for the three months ended June 30, 2007, which included a $285,000 loss attributable to the change in fair value for certain derivative contracts that did not qualify as cash flow hedges pursuant to SFAS 133 and a gain of $564,000 relating to hedge ineffectiveness. Amounts recorded in this caption represent non-cash gains and losses created by valuation changes in derivative contracts that are not entitled to receive hedge accounting. All amounts recorded in this caption are ultimately reversed in this caption over the respective contract term. In addition, we recognized a negative change in derivative value under other comprehensive loss totaling $111.6 million for the three months ended June 30, 2008 as compared to a positive change of $7.9 million for the three months ended June 30, 2007.

Interest Expense. Interest expense decreased to approximately $2.4 million for the three months ended June 30, 2008 from $7.2 million for the three months ended June 30, 2007, due to the refinancing of our credit facilities in November 2007 in connection with our initial public offering, which resulted in lower outstanding borrowings and lower interest rates.

Six Months Ended June 30, 2008 Compared with the Six Months Ended June 30, 2007

Oil and Gas Sales. The $23.8 million (44.6%) increase in oil and gas sales from $53.4 million for the six months ended June 30, 2007 to $77.3 million for the quarter ended June 30, 2008 was primarily attributable to the increase in production volumes and sales prices reflected in the table above. The increase in production volumes was achieved by the addition of more producing wells, which was partially offset by the natural decline in production from some of our natural older gas wells. The additional wells contributed to the production of 10,104 MMcf of net natural gas for the six months ended June 30, 2008, as compared to 7,774 MMcf of net natural gas produced in the same period last year. Our product prices on an equivalent basis (Mcfe) increased from an average of $6.67 per Mcfe for the six months ended June 30, 2007 to an average of $8.50 per Mcfe for the six months ended June 30, 2008. For the six months ended June 30, 2008, the net product price, after accounting for the loss on hedging settlements of $10.1 million during the period, averaged $7.51 per Mcfe. For the six months June 30, 2007, the net product price, after accounting for the gain on hedging settlements of $1.4 million during the period, averaged $6.85 per Mcfe.

Other Revenue/(Expense) . Other revenue for the six months ended June 30, 2008 was $120,000 as compared to other expense of $32,000 for the six-month period ended June 30, 2007, that was due to an increase in marketing fees.

Operating Expenses. Operating expenses, which consist of oil and natural gas production costs and transportation expense, totaling $35.3 million for the six months ended June 30, 2008, were comprised of lease operating costs of $12.0 million, production taxes of $4.2 million, ad valorem taxes of $1.8 million, and transportation expenses of $17.3 million. The current operating expenses compared to $28.1 million for the six months ended June 30, 2007, comprised of lease operating costs of $10.7 million, production taxes of $2.3 million, ad valorem taxes of $1.8 million, and transportation expenses of $13.2 million, a total increase of $7.2 million, or 25.6%. The increase in operating costs is due to the acquisition of oil properties during February 2008, legal fees, electrical costs and road work.

Production taxes increased by approximately 100% due to increased production and a 41% increase in wellhead natural gas prices. Unit production costs, excluding gross production and ad valorem taxes, were $1.17 per Mcfe for the six months ended June 30, 2008 compared to $1.40 per Mcfe for the six months ended June 30, 2007 representing a 16.4% decrease. Unit production costs, inclusive of gross production and ad valorem taxes, were $1.93 per Mcfe for the 2007 period as compared to $1.75 per Mcfe for the six months ended June 30, 2008 period, representing a 9.3% decrease.

Transportation expense increased $4.1 million from $13.2 million for the six months ended June 30, 2007 compared to $17.3 million for the six months ended June 30, 2008, resulting in an average transportation expense of $1.69 per Mcfe for both periods.

Depreciation, Depletion and Amortization. We are subject to variances in our depletion rates from period to period, including the periods described below. These variances result from changes in our oil and natural gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our natural gas and oil properties. Our depletion of natural gas and oil properties as a percentage of gas and oil revenues was 25% for the six months ended June 30, 2008 compared to 26% for the six months ended June 30, 2007. Depreciation, depletion and amortization expense was $1.87 per Mcfe for the six months ended June 30, 2008 compared to $1.80 per Mcfe for the six months ended June 30, 2007. Increases in our depletable basis and production volumes caused depreciation, depletion, and amortization expense to increase $5.1 million to $19.2 million for the six months ended June 30, 2008 compared to $14.1 million for the six months ended June 30, 2007.

General and Administrative Expense. General and administrative expense decreased from $5.8 million for the six months ended June 30, 2007 to $4.4 million for the six months ended June 30, 2008. This decrease is due in part to a decrease in legal fees that are not allocated to specific properties, stock awards to employees, and an increase in capitalized general and administrative costs to the full cost pool offset by an increase in board fees, larger corporate offices, and professional fees. The decrease in general and administrative expense in 2008 is due in part to the fact that prior to our formation in 2007 our Parent allocated all of its general and administrative expenses to our Predecessor and Quest Midstream and did not have any unallocated corporate general and administrative expense.

Change in Derivative Fair Value. Change in derivative fair value was a non-cash loss of $15.1 million for the six months ended June 30, 2008, which included a $27.0 million loss attributable to the change in fair value for certain derivative contracts that did not qualify as cash flow hedges pursuant to SFAS 133 and a gain of $12.0 million relating to hedge ineffectiveness. Change in derivative fair value was a non-cash loss of $185,000 for the six months ended June 30, 2007, which included a $1.3 million loss attributable to the change in fair value for certain derivatives that did not qualify as cash flow hedges pursuant to SFAS 133 and a gain of $1.1 million relating to hedge ineffectiveness. Amounts recorded in this caption represent non-cash gains and losses created by valuation changes in derivatives that are not entitled to receive hedge accounting. All amounts recorded in this caption are ultimately reversed in this caption over the respective contract term. In addition, we recognized a negative change in derivative value under other comprehensive loss totaling $127.3 million for the six months ended June 30, 2008 as compared to a negative change of $5.6 million for the six months ended June 30, 2007.

Interest Expense. Interest expense decreased to approximately $4.6 million for the six months ended June 30, 2008 from $14.2 million for the six months ended June 30, 2007, due to the refinancing of our credit facilities in 2007 in connection with our initial public offering, which resulted in lower outstanding borrowings and lower interest rates.

Net Income (Loss)

We recorded a net income of $16.2 million for the three months ended June 30, 2008 as compared to a net loss of $5.2 million for the three months ended June 30, 2007, each period inclusive of the non-cash net gain or loss derived from the change in derivative fair value as stated above for the quarters ended June 30, 2008 and 2007.

We recorded a net loss of $1.1 million for the six months ended June 30, 2008 as compared to a net loss of $8.9 million for the six months ended June 30, 2007, each period inclusive of the non-cash net gain or loss derived from the change in derivative fair value as stated above for the six months ended June 30, 2008 and 2007.

Liquidity and Capital Resources

Liquidity

Our primary sources of liquidity are cash generated from our operations, amounts available under our revolving credit facility and funds from future private and public equity and debt offerings. Please read Note 6 to our financial statements included in this report for additional information regarding our revolving credit facilities.

At June 30, 2008, we had $18 million of availability under our revolving credit facility, which was available to fund the drilling and completion of additional gas wells, the recompletion of single seam wells into multi-seam wells, the acquisition of additional acreage, equipment and vehicle replacement and purchases and the construction of salt water disposal facilities. We funded the purchase of the PetroEdge wellbores with $30 million of borrowings under our existing revolving credit facility and a six-month $45 million bridge facility. In connection with the acquisition, our lenders increased the borrowing base of our revolving credit facility to $190 million from $160 million.

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

At June 30, 2008, we had current assets of $53.9 million. Our working capital (current assets minus current liabilities, excluding the short-term derivative asset and liability of $151,000 and $66.4 million, respectively) was $17.3 million and $11.4 million at December 31, 2007. The changes in working capital were primarily due to the change in derivative fair value.

Because of the seasonal nature of gas and oil, we may make short-term working capital borrowings in order to level out our distributions during the year. In addition, a substantial portion of our production is hedged. We are generally required to settle a portion of our commodity hedges on each of the 5 ^th and 25 ^th day of each month. As is typical in the gas and oil and gas business, we do not generally receive the proceeds from the sale of the hedged production until around the 25 ^th day of the following month. As a result, when gas and oil prices increase and are above the prices fixed in our derivative contracts, we will be required to pay the hedge counterparty the difference between the fixed price in the derivative contract and the market price before we receive the proceeds from the sale of the hedged production. If this were to occur, we may make working capital borrowings to fund our distributions. Because we will distribute our available cash, we will not have those amounts available to reinvest in our business to increase our reserves and production. Because we will distribute a substantial amount of our cash flows (after making principal and interest payments on our indebtedness) rather than reinvest those cash flows in our business, we may not grow as quickly as other companies or at all.

Capital Expenditures

During the six months ended June 30, 2008, a total of approximately $54.4 million of capital expenditures was invested as follows: $39.7 million was invested in new natural gas wells and properties, $9.5 million in acquiring oil producing properties in Seminole County, Oklahoma, $2.4 million in acquiring leasehold in the Cherokee Basin and $2.8 million in other additional capital items. These investments were funded by cash flow from operations and the proceeds of our borrowings of $48 million under Quest Cherokee’s credit facility.

During 2008, we intend to focus on drilling and completing up to 325 new wells in the Cherokee Basin. Management currently estimates that it will require for each of 2008 and 2009 capital investments in the Cherokee Basin and Seminole County of:

	•		$41.0 million to drill and complete these wells and recomplete an estimated 52 gross wells in the Cherokee Basin;

	•		$37.5 million for acreage, equipment and vehicle replacement and purchases and salt water disposal facilities in the Cherokee Basin;

Our capital expenditures will consist of the following:

•

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

•

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

Management intends to recommend to the board of directors of our General Partner the spending of approximately $4 million on capital projects in the Appalachian Basin in the third and fourth quarters of 2008 including the completion of existing wells in the Marcellus Shale or Devonian Sand formations in Ritchie County, West Virginia and increasing production from other existing wells through various optimization techniques including stimulations, recompletions and enhancing production infrastructure.

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

We cannot assure you that needed capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness will be limited by covenants in our credit facility. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves and maintain our pipeline volumes. Please read Note 4 — Long-Term Debt to our financial statements included in our 2007 Form 10-K for a description of the financial covenants contained in our revolving credit facility. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves.

Cash Flows

Cash Flows from Operating Activities. Net cash provided by operating activities totaled $23.8 million for the six months ended June 30, 2008 as compared to $2.5 million for the six months ended June 30, 2007. This increase resulted from a change in derivative fair value, an increase in inventory, and accrued expenses.

Cash Flows Used in Investing Activities. Net cash used in investing activities totaled $54.5 million for the six months ended June 30, 2008 as compared to $45.5 million for the six months ended June 30, 2007. During the six months ended June 30, 2008, a total of approximately $54.4 million of capital expenditures was invested as follows: $39.7 million was invested in new natural gas wells and properties, $9.5 million in acquiring oil producing properties in Seminole County, Oklahoma, $2.4 million in acquiring leasehold in the Cherokee Basin and $2.8 million in other additional capital items.

Cash Flows from Financing Activities. Net cash provided by financing activities totaled $41.9 million for the six months ended June 30, 2008 as compared to $31.6 million for the six months ended June 30, 2007, and related to the financing of capital expenditures. The net cash provided from financing activities during the six months ended June 30, 2008 was due primarily to $48 million of borrowings under the Quest Cherokee credit facility and $5.6 million in distributions to unitholders.

Contractual Obligations

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


	Payments Due by Period
			Less						More
			Than 1		1-3		4-5		Than 5
	Total		Year		Years		Years		Years
	*($ in thousands)*
Revolving Credit Facility	$	142,000	$	—	$	142,000	$	—	$	—
Notes payable		396		247		111		32		6
Interest expense obligation (1)		22,782		4,911		17,868		2		1
Drilling contractor		856		856		—		—		—
Asset retirement obligation		1,939		—		—		—		1,939
Derivatives		147,976		66,379		65,414		16,183		—

Total	$	315,949	$	72,393	$	225,393	$	16,217	$	1,946


(1)		The interest payment obligation was computed using the LIBOR interest rate as of June 30, 2008. If the interest rate were to change 1%, then the total interest payment obligation would change by $3.3 million.

Critical Accounting Policies and Estimates

The consolidated/carve out financial statements are prepared in conformity with accounting principles generally accepted in the United States. As such, we are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. A summary of the significant accounting policies is contained in Note 3 to our consolidated carve out financial statements. See also Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our 2007 Form 10-K.

Off-Balance Sheet Arrangements

At June 30, 2008 and December 31, 2007, we did not have any relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. In addition, we do not engage in trading activities involving non-exchange traded contracts. As such, we are not exposed to any financing, liquidity, market, or credit risk that could arise if we had engaged in such activities.

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

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

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

	•		financial position;

	•		business strategy;

	•		budgets;

	•		amount, nature and timing of capital expenditures;

	•		drilling of wells;

	•		acquisition and development of natural gas and oil properties;

	•		timing and amount of future production of natural gas and oil;

	•		operating costs and other expenses;

	•		estimated future net revenues from natural gas and oil reserves and the present value thereof;

	•		cash flow and anticipated liquidity; and

	•		other plans and objectives for future operations.

When we use the words “believe,” “intend,” “expect,” “may,” “will,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this report speak only as of the date of this report; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. All subsequent oral and written forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these factors. These risks, contingencies and uncertainties relate to, among other matters, the following:

	•		our ability to implement our business strategy;

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

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

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

	•		land issues;

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

	•		labor problems;

	•		environmental related problems;

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

	•		production variances from expectations;

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

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

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

	•		the need to develop and replace reserves;

	•		competition;

	•		dependence upon key personnel;

	•		the lack of liquidity of our equity securities;

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

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

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

	•		climatic conditions;

	•		natural disasters;

	•		acts of terrorism;

	•		availability and cost of material and equipment;

	•		delays in anticipated start-up dates;

	•		our ability to find and retain skilled personnel;

	•		availability of capital;

	•		the strength and financial resources of our competitors; and

	•		general economic conditions.

When you consider these forward-looking statements, you should keep in mind these risk factors and the other factors discussed under Item 1A. “Risk Factors” in our 2007 Form 10-K and Part II, Item 1A. of this report.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2007, in Item 7A of our 2007 Form 10-K. For more information on our risk management activities, see Note 7 to our consolidated/carve out financial statements.

Item 4(T). Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We have established and maintain a system of disclosure controls and procedures to provide reasonable assurances that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Based on the evaluation of our disclosure controls and procedures as of the end of the period covered by this report, the principal executive officer and principal financial officer of our general partner have concluded that our disclosure controls and procedures as of June 30, 2008 were effective, at a reasonable assurance level, in ensuring that the information required to be disclosed by us in reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and is accumulated and communicated to our management, including our principal executive officer and principal financial officer of our general partner, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Controls

There has been no change in our internal control over financial reporting during the three months ended June 30, 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

See Part I, Item 1, Note 12 to our consolidated/carve out financial statements entitled “Commitments and Contingencies”, which is incorporated herein by reference.

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

Item 1A. Risk Factors

Except as set forth below, there have been no material changes to the risk factors disclosed in Item 1A “Risk Factors” in our 2007 Form 10-K.

Risks Related to Our Business

The economic terms of the midstream services agreement may become unfavorable to us.

Under the midstream services agreement, we pay Quest Midstream, which is a party related to us, a fee per MMBtu for gathering, dehydration and treating services and a compression fee. These fees are subject to an annual upward adjustment based on increases in the producer price index and the market price for gas for the prior calendar year. If these fees increase at a faster rate than the realized prices that we receive from sale of our gas, our ability to make cash distributions to our unitholders may be adversely affected. Such fees are subject to renegotiation in connection with each of the two five year renewal terms, beginning after the initial term expires on December 1, 2016. In addition, at any time after each five year anniversary of the date of the midstream services agreement, each party will have a one-time option to elect to renegotiate the fees and/or the basis for the annual adjustment to the fees if the party believes there has been a material change to the economic returns or financial condition of either party. If the parties are unable to agree on the changes, if any, to be made to such terms, then the parties will enter into binding arbitration to resolve any dispute with respect to such terms. The renegotiated fees may not be as favorable to us as the initial fees. For 2008, the fees are $0.51 per MMBtu of gas for gathering, dehydration and treating services and $1.13 per MMBtu of gas for compression services. For additional information regarding the midstream services agreement, please read “— Gas Gathering” under Item 1 of our 2007 Form 10-K.

A default by our Parent under its credit facilities could result in a change of control of our general partner, which would be an event of default under our credit facilities and could adversely affect our operating results.

Our Parent has pledged its ownership interest in our general partner and in the general partner of Quest Midstream to secure its term loan credit facility. If our Parent were to default under its credit facility, the lenders under our Parent’s credit facility could obtain control of our general partner and the general partner of Quest Midstream or sell control of our general partner and the general partner of Quest Midstream to a third party. In the past, our Parent has not satisfied all of the financial covenants contained in its credit facilities. See Item 1A. “Risk Factors — Risks Related to Our Business — The credit facility of our operating subsidiary, Quest Cherokee, (to which we are a guarantor) has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions” in our 2007 Form 10-K.

A change of control of our general partner would be an event of default under our credit facilities, which could result in a significant portion of our indebtedness becoming immediately due and payable. In addition, our ability to make distributions would be restricted and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make accelerated repayments of our debt. In addition, our obligations under our credit facilities are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facilities, the lenders could seek to foreclose on our assets.

In addition, the new owner of our general partner may replace our existing management with new management that is not familiar with our existing assets and operations, which could adversely affect our results of operations and the amount of cash available for distributions. Furthermore, it is possible that a different person could end up with control of our general partner and Quest Midstream’s general partner. In such an event, the advantages that we have from being under common control with Quest Midstream would be lost, which could adversely affect our results of operations and the amount of cash available for distributions.

Risks Relating to the Acquisition of the Appalachian Basin Assets

The integration of the PetroEdge wellbore assets presents significant challenges that may reduce the anticipated potential benefits of the acquisition.

We face significant challenges in consolidating functions and integrating the PetroEdge wellbore assets, and related procedures and operations in a timely and efficient manner. Their integration will be complex and time-consuming due to the size and complexity of the assets and operations. The principal challenges include the following:

	•		integrating the existing operations of the acquired assets;

	•		coordinating geographically disparate organizations, systems and facilities;

	•		preserving customer, supplier and other important relationships and resolving potential conflicts that may arise as a result of the acquisition;

	•		integrating internal controls, compliances under the Sarbanes-Oxley Act of 2002 and other corporate governance matters; and

	•		incurring significant transaction and integration costs.

Management will have to dedicate substantial effort to integrating the PetroEdge wellbore assets. These efforts could divert management’s focus and resources from other day-to-day tasks, corporate initiatives or strategic opportunities during the integration process. Neither our Parent nor we expect to retain the personnel of PetroEdge and our Parent has entered into a one-year transition services agreement with PetroEdge’s parent, which includes PetroEdge’s existing management team, to assist in the integration process. Our Parent will be required to hire employees and retain service providers for our Appalachian Basin operations. There can be no assurance that these arrangements will be successful as we integrate the PetroEdge wellbore assets, or that we will be successful in our efforts to hire and retain competent employees and service providers.

Risks of Entry into the Marcellus Shale Reservoir of the Appalachian Basin

We have limited experience in drilling wells in the Marcellus Shale. Appalachian Basin wells are more expensive to drill and complete and are more susceptible to mechanical problems than in the Cherokee Basin.

We and our Parent have limited experience in drilling development wells in the Marcellus Shale reservoir of the Appalachian Basin. Other operators in the Appalachian Basin also have limited experience in drilling wells to the Marcellus Shale. Thus, we have much less information with respect to the ultimate recoverable reserves and the production decline rate in the Marcellus Shale than we have in our other areas of operation. In addition, the wells to be drilled in the Marcellus Shale will be drilled deeper than in our other areas of operation, which makes the Marcellus Shale wells more expensive to drill and complete. The wells will also be more susceptible to mechanical problems associated with the drilling and completion of the wells, such as casing collapse and lost equipment in the wellbore. In addition, the fracturing of the Marcellus Shale will be more extensive and complicated than fracturing the geological formations in our other areas of operation.

Risks Related to Our Acquisition Financing

To fund the acquisition price for PetroEdge’s interest in producing wellbores and related assets associated with proved developed producing and proved developed non-producing reserves, we obtained a bridge loan in the amount of $45.0 million and borrowed approximately $30.0 million under our revolving credit facility. The bridge loan is secured by a second lien on our assets and will mature within six months of the date of the closing of the PetroEdge acquisition. As of August 6, 2008, we have approximately $18.0 million of availability under our revolving credit facility. To repay the bridge loan and to obtain additional capital to fund a portion of our 2009 capital expenditure budget, we expect to raise additional funds pursuant to an equity offering, the incurrence of additional debt or a combination of both. There can be no assurances that we will be able to raise sufficient funds on reasonable terms, if at all, prior to maturity of the bridge loan to repay it in a timely manner and to fund our future capital expenditures. Failure to raise sufficient funds to repay the bridge loan could expose our assets to foreclosure or other collection efforts. Failure to raise sufficient additional funds to finance our 2009 capital expenditures could result in a reduction in the pace at which we develop our properties, which in turn could adversely affect our ability to make distributions on our units and comply with the financial covenants of our credit facilities.

Tax Risks to Common Unitholders

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Default Upon Senior Securities

None.

Item 4. Submission of Matters to Vote of Security Holders

None.

Item 5. Other Information

None.

Item 6. Exhibits


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

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

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

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

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

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

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

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

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

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

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

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


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

32.1		Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		Previously filed.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized this 11 ^th day of August, 2008.


	QUEST ENERGY PARTNERS, L.P.
	By:	Quest Energy GP, LLC, its general partner

	By:	/s/ Jerry D. Cash
		Jerry D. Cash
		Chief Executive Officer

	By:	/s/ David E. Grose
		David E. Grose
		Chief Financial Officer