e10vq

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: 0-17371

QUEST RESOURCE CORPORATION

(Exact name of registrant specified in its charter)


Nevada		90-0196936
(State or other jurisdiction		(I.R.S. Employer
of incorporation or organization)		Identification No.)

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes 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 þ	Non-accelerated filer o	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 32,344,859 shares of common stock outstanding.

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Except as otherwise required by the context, references in this quarterly report to “we,” “our,” “us,” “Quest” or “the Company” refer to Quest Resource Corporation and its subsidiaries: Quest Energy Partners, L.P.; Quest Energy GP, LLC; Quest Cherokee, LLC; Quest Cherokee Oilfield Service, LLC; Quest Midstream Partners, L.P.; Quest Midstream GP, LLC; Bluestem Pipeline, LLC; Quest Transmission Company, LLC; Quest Kansas Pipeline, L.L.C; Quest Kansas General Partner, L.L.C.; Quest Pipelines (KPC); Quest Oil & Gas, LLC; Quest Energy Service, LLC; Quest Eastern Resource LLC and Quest MergerSub, Inc.. Our operations are primarily conducted through Quest Cherokee, LLC, Quest Cherokee Oilfield Service, LLC, Bluestem Pipeline, LLC, Quest Energy Service, LLC and, beginning July 11, 2008, Quest Eastern Resource LLC.

Our unaudited interim financial statements, including consolidated balance sheets as of December 31, 2007 and June 30, 2008, consolidated statements of operations and comprehensive income for the three and six month periods ended June 30, 2007 and 2008, consolidated statements of cash flows for the six month period ended June 30, 2008 and the comparable period of 2007, and a consolidated statement of stockholders’ equity for the six month period ended June 30, 2008, are attached hereto as Pages F-1 through F-25 and are incorporated herein by this reference.

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, as amended (the “2007 Form 10-K”).

F-1

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	June 30,			December 31,
	2008			2007
	(Unaudited)
	($ in thousands)
ASSETS

Current assets:
Cash	$	31,553		$	16,680
Restricted cash		453			1,236
Accounts receivable, trade		16,635			15,768
Other receivables		3,579			1,632
Other current assets		5,170			3,717
Inventory		12,713			6,622
Short-term derivative asset		151			6,729

Total current assets		70,254			52,384
Property and equipment, net of accumulated depreciation of $8,557 and $6,917		24,319			21,394
Pipeline assets, net of accumulated depreciation of $40,983 and $34,736		309,240			296,039
Pipeline assets under construction		1,312			1,240
Oil and gas properties:
Properties being amortized		466,020			406,665
Properties not being amortized		31,654			22,020

		497,674			428,685
Less: Accumulated depreciation, depletion and amortization		(147,139	)		(127,968	)

Net property, plant and equipment		350,535			300,717
Other assets, net		7,986			8,268
Long-term derivative asset		—			1,568

Total assets	$	763,646		$	681,610

LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)

Current liabilities:
Accounts payable	$	37,786		$	27,911
Revenue payable		7,132			6,806
Accrued expenses		11,795			9,058
Current portion of notes payable		247			666
Short-term derivative liability		66,379			8,241

Total current liabilities		123,339			52,682
Non-current liabilities:
Long-term derivative liability		81,597			5,586
Asset retirement obligation		4,181			3,813
Notes payable		312,724			233,712
Less current maturities		(247	)		(666	)

Non-current liabilities		398,255			242,445

Total liabilities		521,594			295,127
Minority interests		281,244			294,630
Commitments and contingencies		—			—
Stockholders’ equity (deficit):
10% convertible preferred stock, $.001 par value, 50,000,000 shares authorized, 0 shares issued and outstanding at June 30, 2008 and December 31, 2007		—			—
Common stock, $.001 par value, 200,000,000 shares authorized, 23,974,831 shares issued and outstanding at June 30, 2008 and 22,701,029 shares issued and outstanding at December 31, 2007		24			23
Additional paid-in capital		215,777			212,819
Accumulated other comprehensive (loss)		(128,811	)		(1,485	)
Accumulated deficit		(126,182	)		(119,504	)

Total stockholders’ equity (deficit)		(39,192	)		91,853

Total liabilities and stockholders’ equity	$	763,646		$	681,610

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

F-2

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(UNAUDITED)

($ in thousands, except per share amounts)


	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
Revenue:
Oil and gas sales	$	39,903		$	27,867		$	77,256		$	53,416
Gas pipeline revenue		7,148			1,792			14,049			3,334
Other revenue (expense)		72			(19	)		122			(32	)

Total revenues		47,123			29,640			91,427			56,718

Costs and expenses:
Oil and gas production		9,763			7,740			17,971			14,967
Pipeline operating		8,257			4,333			15,506			9,267
General and administrative		6,308			5,407			11,140			8,045
Depreciation, depletion and amortization		14,296			8,471			27,096			16,334

Total costs and expenses		38,624			25,951			71,713			48,613


Operating income		8,499			3,689			19,714			8,105


Other income (expense):
Change in derivative fair value		8,695			279			(15,136	)		(185	)
(Loss)/gain on sale of assets		(30	)		(298	)		—			(191	)
Interest income		104			103			121			280
Interest expense		(5,278	)		(7,610	)		(10,402	)		(14,723	)

Total other income (expense)		3,491			(7,526	)		(25,417	)		(14,819	)


Income (loss) before minority interest and income taxes		11,990			(3,837	)		(5,703	)		(6,714	)
Minority interest in consolidated subsidiaries		(7,026	)		(650	)		(975	)		(1,084	)

Net income (loss) before income taxes		4,964			(4,487	)		(6,678	)		(7,798	)
Income tax expense – deferred		—			—			—			—

Net income (loss)	$	4,964		$	(4,487	)	$	(6,678	)	$	(7,798	)


Earnings (loss) per common share – basic	$	0.21		$	(0.20	)	$	(0.28	)	$	(0.35	)


Earnings (loss) per common share – diluted	$	0.21		$	(0.20	)	$	(0.28	)	$	(0.35	)


Weighted average common and common equivalent shares:
Basic		23,772,788			22,217,048			23,534,132			22,211,561
Diluted		23,831,481			22,217,048			23,534,132			22,211,561

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

F-3

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

($ in thousands)


	For the Six Months Ended June 30,
	2008			2007
Cash flows from operating activities:
Net income (loss)	$	(6,678	)	$	(7,798	)
Adjustments to reconcile net income (loss) to cash provided by operations:
Depreciation and depletion		27,320			17,747
Change in derivative fair value		14,969			185
Stock options granted for directors fees		842			144
Stock awards granted to employees		2,422			2,874
Amortization of loan origination fees		954			1,115
Amortization of gas swap fees		—			125
Amortization of deferred hedging gains		—			—
Bad debt expense		10			—
(Gain) loss on sale of assets		(27	)		234
Minority interest		975			1,084
Change in assets and liabilities:
Restricted cash		784			(10	)
Accounts receivable		(877	)		(2,602	)
Other receivables		(1,947	)		(1,137	)
Other current assets		(1,453	)		(796	)
Inventory		(6,090	)		(2,302	)
Accounts payable		9,032			1,926
Revenue payable		1,170			2,524
Accrued expenses		84			(690	)

Net cash provided by operating activities		41,490			12,623

Cash flows from investing activities:
Additions to equipment, development and leasehold costs		(87,719	)		(58,114	)
Net additions to other property and equipment		(4,679	)		(5,158	)

Net cash used in investing activities		(92,398	)		(63,272	)

Cash flows from financing activities:
Proceeds from bank borrowings		79,000			30,000
Change in other long-term liabilities		167			80
Repayments of note borrowings		(312	)		(299	)
Syndication costs paid		(334	)		(48	)
Cash distributions to unitholders		(12,474	)		(1,809	)
Refinancing costs		(266	)		(2,897	)

Net cash provided by financing activities		65,781			25,027


Net increase (decrease) in cash		14,873			(25,622	)
Cash, beginning of period		16,680			41,820

Cash, end of period	$	31,553		$	16,198


Supplemental disclosure of cash flow information
Cash paid during the period for:
Interest expense	$	9,450		$	12,729
Income taxes	$	—		$	—

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

F-4

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2008

(UNAUDITED)

1. Basis of Presentation

Nature of Business

Quest Resource Corporation is a Nevada corporation formed in July 1982. Unless the context requires otherwise, references to “we,” “us,” “our” or the “Company” are intended to mean Quest Resource Corporation and its consolidated subsidiaries.

We are an independent energy company with an emphasis on the acquisition, production, transportation, exploration, and development of natural gas (coal bed methane) in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma. Our operations are currently focused on developing coal bed methane gas production through Quest Energy Partners, L.P. (“Quest Energy”) in a fifteen county region that is served by a pipeline network owned through Quest Midstream Partners, L.P. (“Quest Midstream”). Quest Midstream also owns a 1,120-mile interstate natural gas transmission pipeline that transports natural gas from northwestern Oklahoma and western Kansas to the metropolitan Wichita, Kansas and Kansas City, Missouri markets (the “KPC Pipeline”). In addition, through Quest Oil & Gas, LLC, we are developing acreage located in Pennsylvania that is prospective for the Marcellus Shale.

We conduct our business through two reportable business segments. These segments and the activities performed to provide services to our customers and create value for our stockholders are as follows:

	•		Quest Energy — natural gas and oil production focused on coal bed methane in the Cherokee Basin; and

	•		Quest Midstream — transporting, selling, gathering and treating natural gas.

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. 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. Minority interests in the net assets and earnings or losses of a consolidated investee are reflected in the caption “Minority interest” in the Company’s consolidated balance sheet and statement of operations. Minority interest adjusts the Company’s consolidated results of operations to reflect only the Company’s share of the earnings or losses of the consolidated investee company. 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 with the Company.

2. Summary of Significant Accounting Policies

Reference is hereby made to the Company’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2007 (the “2007 Form 10-K”), which contains a summary of significant accounting policies followed by the Company in the preparation of its consolidated financial statements. These policies were also followed in preparing the consolidated financial statements as of June 30, 2008 and for the three and six months ended June 30, 2008 and 2007.

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 financial statements and accompanying notes. Actual results could differ from those estimates.

F-6

Estimates made in preparing the consolidated 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.

The Company recognizes gathering and transmission revenues at the time the natural gas and liquids are delivered.

Cash Equivalents

For purposes of the consolidated 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.

Other Current Assets

Other current assets totaled $5.2 million at June 30, 2008 as compared to $3.7 million at December 31, 2007. At June 30, 2008, other current assets consisted of deposits of $1.7 million, prepaid insurance and fees of $2.1 million, and other prepaid items of $1.4 million. At December 31, 2007, other current assets consisted of deposits of $1.3 million, prepaid insurance and fees of $1.9 million and other prepaid items of $500,000.

Concentration of Credit Risk

A significant portion of the Company’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.

F-7

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.

KPC Pipeline’s two primary customers are Kansas Gas Service (KGS) and Missouri Gas Energy (MGE), both of which are served under long-term natural gas transportation contracts representing 59% and 37% of the gas transported, respectively for the six months ended June 30, 2008.

The Company conducts the majority of 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 Securities and Exchange Commission (“SEC”). Under the full cost method, all acquisition, exploration, and development costs are capitalized. The Company capitalizes internal costs including: salaries and related fringe benefits of employees directly engaged in the acquisition, exploration and development of 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 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.

F-8

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:


Pipeline		15 to 40 years
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 2007 totaled $7.4 million and $10.9 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 accounts for income taxes pursuant to the provisions of the SFAS 109, Accounting for Income Taxes, which requires an asset and liability approach to calculating deferred income taxes. The asset and liability approach requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the carrying amounts and the tax basis of assets and liabilities. The provision for income taxes differ from the amounts currently payable because of temporary differences (primarily intangible drilling costs and the net operating loss carry forward) in the recognition of certain income and expense items for financial reporting and tax reporting purposes.

The Company has also adopted Financial Accounting Standards Board (FASB) Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109 (FIN 48). Under FIN 48, evaluation of a tax position is a two-step process. The first step is to determine whether it is more-likely-than-not that a tax position will be sustained upon examination, including the resolution of any related appeals or litigation based on the technical merits of that position. The second step is to measure a tax position that meets the more-likely-than-not threshold to determine the amount of benefit to be recognized in the financial statements. A tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement.

Earnings Per Common Share

SFAS 128, Earnings Per Share, requires presentation of “basic” and “diluted” earnings per share on the face of the statements of operations for all entities with complex capital structures. Basic earnings per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted during the period. Dilutive securities having an anti-dilutive effect on diluted earnings per share are excluded from the calculation. See Note 7 — Earnings Per Share, for a reconciliation of the numerator and denominator of the basic and diluted earnings per share computations.

F-9

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.

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 4 for a roll-forward of the asset retirement obligation.

Stock-Based Compensation

Stock Options. Effective January 1, 2006, the Company adopted SFAS 123 (Revised 2004), Share-Based Payment, which requires that compensation related to all stock-based awards, including stock options, be recognized in the financial statements based on their estimated grant-date fair value. The Company has previously recorded stock compensation pursuant to the intrinsic value method under APB Opinion No. 25, whereby compensation was recorded related to performance share and unrestricted share awards and no compensation was recognized for most stock option awards. The Company is using the modified prospective application method of adopting SFAS 123R, whereby the estimated fair value of unvested stock awards granted prior to January 1, 2006 will be recognized as compensation expense in periods subsequent to December 31, 2005, based on the same valuation method used in the Company’s prior pro forma disclosures. The Company has estimated expected forfeitures, as required by SFAS 123R, and the Company is recognizing compensation expense only for those awards expected to vest. Compensation expense is amortized over the estimated service period, which is the shorter of the award’s time vesting period or the derived service period as implied by any accelerated vesting provisions when the common stock price reaches specified levels. All compensation must be recognized by the time the award vests. The cumulative effect of initially adopting SFAS 123R was immaterial.

On March 5, 2008, the Company’s board of directors approved the cancellation of each of the independent directors’ unvested stock options. Replacement bonus shares were awarded such that for every two shares subject to the original options, the director would be entitled to receive one bonus share. The bonus shares will vest on the same dates as the original stock options would have become exercisable.

F-10

Partnership Unit Awards. Quest Energy GP, LLC, the general partner of Quest Energy, granted bonus units to certain members of its Board of Directors 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 to oil and gas properties. For the three and six months ended June 30, 2008, Quest Energy 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 were $68,000 and $272,000, respectively.

Quest Midstream GP, LLC, the general partner of Quest Midstream, granted bonus units to certain employees and certain members of its Board of Directors during the year ended December 31, 2007. The units are subject to a three-year vesting schedule. The fair value of the unit awards granted is recognized over the applicable vesting period as compensation expense. To the extent the compensation expense relates to employees directly involved in acquisition and development of pipeline activities, such amounts are capitalized to the pipeline. Amounts not capitalized to the pipeline are recognized in general and administrative expenses. For the six months ended June 30, 2008, Quest Midstream 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 were $327,000 and $729,000, respectively.

Stock Awards. The Company granted shares of common stock to certain employees in February, April, May and July 2008 and February, March, April, September and December 2007. The shares are subject to three-year and four-year vesting schedules. In March 2008, the Company granted bonus shares to its independent directors in exchange for the cancellation of their unvested stock options. See “Stock Options” above. In May 2008, the Company granted unrestricted shares to its independent directors. The fair value of the stock awards granted is recognized over the applicable vesting period as compensation expense. To the extent the compensation expense relates to employees directly involved in acquisition, exploration and development activities, such amounts are capitalized to oil and gas properties. Amounts not capitalized to oil and gas properties are recognized in general and administrative expenses.

The 1,243,802 shares issued during the six months ended June 30, 2008 include 24,362 shares issued for previously granted bonus shares and the issuance of 1,218,720 shares of restricted stock that had been previously granted but not yet issued.

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-11


	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 stockholders’ equity in the consolidated balance sheets as accumulated other comprehensive income (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 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 and its interstate pipeline assets. The Company is unable to predict if and when its gathering systems would become completely obsolete and require decommissioning. Accordingly, the Company has recorded no liability or corresponding asset for the gathering systems in conjunction with the adoption of SFAS 143 because the future dismantlement and removal dates of the Company’s assets and the amount of any associated costs are indeterminable.

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 6. “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”, 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.

F-12

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 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 for its subsidiaries.

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.

F-13

3. Acquisitions

KPC Pipeline

On November 1, 2007, Quest Midstream completed the purchase of the KPC Pipeline pursuant to a Purchase and Sale Agreement (the “Purchase Agreement”), dated as of October 9, 2007, by and among Quest Midstream, Enbridge Midcoast Energy, L.P. and Midcoast Holdings No. One, L.L.C., whereby Quest Midstream purchased all of the membership interests in the two general partners of Enbridge Pipelines (KPC) (collectively, “KPC”), the owner of the KPC Pipeline for a purchase price of approximately $133 million in cash, subject to adjustment for working capital at closing.

In accordance with the terms of the Purchase Agreement, the purchase price, current assets and certain assumed liabilities were allocated as follows (dollars in thousands):


Pipeline assets	$	135,069
Asset retirement obligation assumed		(2,069	)

Purchase price	$	133,000

Pro Forma Summary Data (unaudited)

The following pro forma summary data for the three and six months ending June 30, 2007 presents the consolidated results of operations as if the acquisition of KPC made on November 1, 2007 had occurred on January 1, 2007. These pro forma results have been prepared for comparative purposes only and do not purport to be indicative of what would have occurred had the acquisition been made at January 1, 2007 or of results that may occur in the future (dollars in thousands, except per share data).


	For the Three Months			For the Six Months
	Ended June 30, 2007			Ended June 30, 2007
Pro forma revenue	$	34,576		$	66,640
Pro forma net (loss)	$	(1,771	)	$	(4,034	)
Pro forma net (loss) per share	$	(0.08	)	$	(0.18	)

Searight

Quest Energy 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 Energy 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 Energy’s credit facility.

4. 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:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
				*(Dollars in thousands)*

Asset retirement obligation beginning balance	$	3,998		$	1,477		$	3,813		$	1,410
Liabilities incurred		83			42			171			83
Liabilities settled		(1	)		(2	)		(3	)		(3	)
Accretion expense		101			29			200			56
Revisions in estimated cash flows		—			—			—			—

Asset retirement obligation ending balance	$	4,181		$	1,546		$	4,181		$	1,546

F-14

5. Long-Term Debt

Long-term debt consists of the following:


	June 30,		December 31,
	2008		2007
	(Dollars in thousands)
Senior credit facilities	$	312,325	$	233,000
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		399		712

Total long-term debt		312,724		233,712
Less — current maturities		247		666

Total long term debt, net of current maturities	$	312,477	$	233,046

The aggregate scheduled maturities of notes payable and long-term debt for the period ending December 31, 2013 and thereafter were as follows as of June 30, 2008 (assuming no payments were made on the revolving credit facilities prior to their maturity) (dollars in thousands):


2008	$	247
2009		59
2010		142,053
2011		26
2012		170,332
2013		6
Thereafter		1

	$	312,724

Credit Facilities

The Company and its subsidiaries are parties to three credit facilities. See Note 3 to the consolidated financial statements included in the 2007 Form 10-K for descriptions of the material terms of the credit facilities.

Quest Energy Partners, L.P. and Quest Cherokee, LLC. Quest Cherokee, LLC (“Quest Cherokee”) is a party to an Amended and Restated Credit Agreement dated as of November 15, 2007 with Royal Bank of Canada, as administrative agent and collateral agent (“RBC”), KeyBank National Association, as documentation agent, and the lenders party thereto. Quest Energy is a guarantor of the credit agreement. As of June 30, 2008, the borrowing base under this credit agreement was $160 million and the amount borrowed under the credit agreement was $142 million. The weighted average interest rate under this credit agreement for the six months ended June 30, 2008 was 6.80%.

On April 17, 2008, Quest Energy 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 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 12 – 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.

Quest Resource Corporation. The Company is a party to a Credit Agreement dated as of November 15, 2007 with RBC, as administrative agent and collateral agent, and the lenders party thereto. As of June 30, 2008, the borrowing base under this credit agreement was $50 million and the amount borrowed under the credit agreement was $48 million. The weighted average interest rate under this credit agreement for the six months ended June 30, 2008 was 7.62%. See Note 12 – Subsequent Events for a discussion of the refinancing of the credit facility.

Quest Midstream Partners, L.P. and Bluestem Pipeline, LLC. Quest Midstream and Bluestem Pipeline, LLC are parties to an Amended and Restated Credit Agreement dated as of November 1, 2007 with RBC, as administrative agent and collateral agent, and the lenders party thereto. As of June 30, 2008, the amount borrowed under the credit agreement was $122 million and the total amount available was $135 million. The weighted average interest rate under this credit agreement for the six months ended June 30, 2008 was 6.61%.

F-15

Other Long-Term Indebtedness

$399,000 of notes payable to banks and finance companies were outstanding at June 30, 2008 and are secured by equipment and vehicles, with payments due in monthly installments through October 2013 with interest ranging from 1.9% to 9.8% per annum.

6. 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			Years Ending December 31,
	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
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

F-16


	Six Months
	Ending			Years Ending December 31,
	December 31,
	2008			2009			2010			2011			2012			Total
				(Dollars in thousands, except per MMBtu and Bbl data)
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.

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:

F-17


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	*(Dollars in thousands)*

Change in fair value of derivatives 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 (dollars in thousands).


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

Cancellation or termination of a fixed-price contract would subject a greater portion of the Company’s natural gas or 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

F-18

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 pay 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 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.

7. Earnings Per Share

SFAS 128 requires a reconciliation of the numerator and denominator of the basic and diluted earnings per share (EPS) computations. The following securities were not included in the calculation of diluted earnings per share because their effect was antidilutive.

	•		For the three and six months ended June 30, 2007, dilutive shares do not include the assumed exercise of stock options and stock awards because the effects were antidilutive.

	•		For the three months ended June 30, 2008, dilutive shares include the assumed exercise of stock options and stock awards.

	•		For the six months ended June 30, 2008, dilutive shares do not include the assumed exercise of stock options and stock awards because the effects were antidilutive.

The following reconciles the components of the EPS computation (dollars in thousands, except per share amounts):


	Income			Shares		Per Share
	(Numerator)			(Denominator)		Amount
For the three months ended June 30, 2008:
Net income	$	4,964
Basic EPS available to common shareholders	$	4,964			23,772,788	$	0.21

Effect of dilutive securities:
Stock awards		—			58,693


Diluted EPS available to common shareholders	$	4,964			23,831,481	$	0.21


For the three months ended June 30, 2007:
Net loss	$	(4,487	)
Basic EPS available to common shareholders	$	(4,487	)		22,217,048	$	(0.20	)

Effect of dilutive securities:
None		—			—


Diluted EPS available to common shareholders	$	(4,487	)		22,217,048	$	(0.20	)

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	Income			Shares		Per Share
	(Numerator)			(Denominator)		Amount
For the six months ended June 30, 2008:
Net loss	$	(6,678	)
Basic EPS available to common shareholders	$	(6,678	)		23,534,132	$	(0.28	)

Effect of dilutive securities:
None		—			—


Diluted EPS available to common shareholders	$	(6,678	)		23,534,132	$	(0.28	)


For the six months ended June 30, 2007:
Net loss	$	(7,798	)
Basic EPS available to common shareholders	$	(7,798	)		22,211,561	$	(0.35	)

Effect of dilutive securities:
None		—			—


Diluted EPS available to common shareholders	$	(7,798	)		22,211,561	$	(0.35	)

8. 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):


	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
Net income (loss)	$	4,964		$	(4,487	)	$	(6,678	)	$	(7,798	)
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)	$	(106,598	)	$	3,426		$	(134,004	)	$	(13,366	)

9. Partners’ Capital and Cash Distributions

Quest Energy Distributions to Unitholders

Minimum Quarterly Distribution. Quest Energy will distribute to the holders of its common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.40 per unit, or $1.60 per year, to the extent Quest Energy has sufficient cash from its operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner. However, there is no guarantee that Quest Energy will pay the minimum quarterly distribution on the units in any quarter. Even if Quest Energy’s cash distribution policy is not modified or revoked, the amount of distributions paid under its policy and the decision to make any distribution is determined by its general partner, taking into consideration the terms of Quest Energy’s partnership agreement. Quest Energy will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under its credit facility. Please read Note 3 to the consolidated financial statements included in the 2007 Form 10-K for a discussion of the restrictions included in Quest Energy’s credit facility that may restrict its ability to make distributions.

General Partner Interest and Incentive Distribution Rights. Initially, Quest Energy’s general partner will be entitled to 2% of all quarterly distributions since inception that Quest Energy makes prior to its liquidation. The 2% general partner interest in the distributions may be reduced if Quest Energy issues additional units in the future and its general partner does not contribute a proportionate amount of capital to Quest Energy to maintain its 2% general partner interest. Quest Energy’s general partner has all of the incentive distribution rights entitling it to receive up to 23% of Quest Energy’s cash distributions above certain target distribution levels in addition to its 2% general partner interest. See Item 5. “Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities — Cash Distributions to Unitholders” in Quest Energy’s Annual Report on Form 10-K for the year ended December 31, 2007 for further discussion of its cash distributions.

As of June 30, 2008, Quest Energy has accrued cash distributions for the quarter ended June 30, 2008 to all of its unitholders totaling $9.3 million or $0.43 per unit on all of its units. For the quarter ended March 31, 2008, Quest Energy declared a cash distribution to all of its unitholders totaling $8.0 million or $0.41 per unit on all of its units.

Quest Midstream Distributions to Unitholders

Minimum Quarterly Distribution. Quest Midstream will distribute to the holders of its common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.425 per unit, or $1.70 per year, plus any arrearages in payment of the

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minimum quarterly distribution on common units from prior quarters, to the extent Quest Midstream has sufficient cash from its operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner. However, there is no guarantee that Quest Midstream will pay the minimum quarterly distribution on the units in any quarter. Even if Quest Midstream’s cash distribution policy is not modified or revoked, the amount of distributions paid under its policy and the decision to make any distribution is determined by its general partner, taking into consideration the terms of Quest Midstream’s partnership agreement. Quest Midstream will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under its credit facility. Please read Note 3 to the consolidated financial statements included in the 2007 Form 10-K for a discussion of the restrictions included in Quest Midstream’s credit facility that may restrict its ability to make distributions.

General Partner Interest and Incentive Distribution Rights. Initially, Quest Midstream’s general partner will be entitled to 2% of all quarterly distributions since inception that Quest Midstream makes prior to its liquidation. The 2% general partner interest in the distributions may be reduced if Quest Midstream issues additional units in the future and its general partner does not contribute a proportionate amount of capital to Quest Midstream to maintain its 2% general partner interest. Quest Midstream’s general partner has all of the incentive distribution rights entitling it to receive up to 48% of Quest Midstream’s cash distributions above certain target distribution levels in addition to its 2% general partner interest.

As of June 30, 2008, Quest Midstream accrued cash distributions for the quarter ended June 30, 2008 to its unitholders totaling $3.82 million or $0.425 per unit on its common units. For the quarter ended March 31, 2008, Quest Midstream declared a cash distribution to its unitholders totaling $3.8 million or $0.425 per unit on its common units.

10. Commitments and Contingencies

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

STP, Inc., STP Cherokee, Inc. (now STP Cherokee, LLC), Bluestem Pipeline, LLC, Quest Cherokee, LLC, and Quest Energy Service, LLC (improperly named Quest Energy Services, LLC) 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 had 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 12. “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.

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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 intend to defend vigorously against the plaintiff’s claims.

Quest Cherokee was named as a defendant in a putative class action lawsuit (Case No. 07-1225-MLB) filed by several royalty owners in the U.S. District Court for the District of Kansas. The plaintiffs have not yet filed a motion asking the court to certify the class and the court has not determined that the case may properly proceed as a class action. The case was filed by the named plaintiffs on behalf of a putative class consisting of all Quest Cherokee’s royalty and overriding royalty owners in the Kansas portion of the Cherokee Basin. Plaintiffs contend that Quest Cherokee failed to properly make royalty payments to them and the putative class by, among other things, paying royalties based on reduced volumes instead of volumes measured at the wellheads, by allocating expenses in excess of the actual costs of the services represented, by allocating production costs to the royalty owners, by improperly allocating marketing costs to the royalty owners, and by making the royalty payments after the statutorily proscribed time for doing so without providing the required interest. Quest Cherokee has answered the complaint and denied plaintiffs’ claims. Discovery in that case is ongoing. Quest Cherokee intends to defend vigorously against these claims.

Quest Cherokee has been named as a defendant or counterclaim 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 12 — Subsequent Events.

F-22

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.

11. Operating Segment Information

We divide our operations into two reportable business segments:

	•		Quest Energy — natural gas and oil production focused on coal bed methane production in the Cherokee Basin; and

	•		Quest Midstream — transporting, selling, gathering and treating natural gas.

Each segment uses the same accounting policies as those described in the summary of significant accounting policies (see Note 2). Our reportable segments are strategic business units that offer different products and services. Each segment is managed separately because each segment involves different products and marketing strategies. The Company does not allocate income taxes to its operating segments.

Prior to the formation of Quest Energy in November 2007, all amounts were allocated to the segments with no amounts being allocated to “corporate”. Operating segment data for the three and six months ended June 30, 2008 and 2007 follows (dollars in thousands):


	For the three months						For the six months
	ended June 30,						ended June 30,
	2008			2007			2008			2007
Quest Energy (Natural Gas and Oil Production)

Revenues	$	39,903		$	27,867		$	77,256		$	53,416
Costs and expenses		(23,826	)		(32,877	)		(78,639	)		(62,392	)

Segment profit (loss)	$	16,077		$	(5,010	)	$	(1,383	)	$	(8,976	)


Quest Midstream (Natural Gas Pipelines):
Revenues -
Gathering—Third party		2,201			1,792			4,220			3,334
Gathering-Intercompany		8,675			6,809			17,338			13,170
KPC Pipeline		4,947			—			9,829			—

Total natural gas pipelines revenue		15,823			8,601			31,387			16,504
Costs and expenses		(15,620	)		(7,211	)		(29,918	)		(14,298	)

Segment profit (loss)	$	203		$	1,390		$	1,469		$	2,206


Reconciliation of segment profit (loss) to net income (loss) before tax and minority interest:
Segment profit (loss) -
Gas and oil production	$	16,077		$	(5,010	)	$	(1,383	)	$	(8,976	)

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	For the three months						For the six months
	ended June 30,						ended June 30,
	2008			2007			2008			2007
Natural gas pipelines		203			1,390			1,469			2,206


Total segment profit (loss)		16,280			(3,620	)		86			(6,770	)
Intercompany pipeline revenue		(8,675	)		(6,809	)		(17,338	)		(13,170	)
Intercompany transportation expense		8,675			6,809			17,338			13,170
Corporate general and administrative expenses		(2,125	)		—			(2,674	)		—
Corporate depreciation		(1,396	)		—			(1,464	)		—
Corporate interest expense		(912	)		—			(1,895	)		—
Other income (expenses)		143			(217	)		244			56

Net income (loss) before income tax and minority interest	$	11,990		$	(3,837	)	$	(5,703	)	$	(6,714	)


	June 30, 2008		December 31, 2007
Total Assets:
Natural Gas and oil production	$	419,095	$	364,310
Natural Gas pipelines		332,414		309,873
Corporate and other		12,137		7,427

Total	$	763,646	$	681,610

Operating profit (loss) per segment represents total revenues less costs and expenses attributable thereto, excluding general corporate expenses.

12. Subsequent Events

Equity Offering

On July 8, 2008, the Company closed on a public offering of 8,800,000 shares of its common stock at a price of $10.25 per share, resulting in net proceeds, after payment of expenses, of approximately $84 million. The Company used the net proceeds of the offering (1) to fund a portion of the $141.6 million acquisition, subject to post-closing adjustments, of privately held PetroEdge Resources (WV) LLC (“PetroEdge”), (2) to repay a portion of the Company’s existing revolving credit facility, (3) to pay fees and expenses related to the PetroEdge acquisition and (4) for general corporate purposes, including drilling and development activities.

PetroEdge Acquisition

On July 11, 2008, the Company completed the purchase of all of the membership interests in PetroEdge, the owner of oil and gas leasehold interests covering approximately 78,000 net acres and related assets in West Virginia, Pennsylvania and New York, of which approximately 86% is prospective for the Marcellus Shale, pursuant to a membership interest purchase agreement with PetroEdge Resources Partners, LLC for approximately $141.6 million in cash, subject to post-closing adjustments. Simultaneous with the closing of this acquisition, PetroEdge changed its name to Quest Eastern Resource LLC (“Quest Eastern”) and Quest Energy purchased from the Company all of Quest Eastern’s 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 $72.0 million, subject to post-closing adjustments. Quest Energy purchased over 400 natural gas and oil wellbores with estimated net proved developed reserves of 32.9 Bcfe and current net production of approximately 3.3 Mmcfe/d from the Company. The purchase price was based on the value of the proved reserves associated with the wellbores transferred to Quest Energy.

In connection with the PetroEdge acquisition, the Company entered into an amended and restated credit agreement with RBC to convert the Company’s existing $50 million revolving credit facility to a $35 million term loan. The new term loan is secured by a first priority lien on substantially all of the Company’s assets and its subsidiaries’ assets (excluding Quest Midstream, its general

F-24

partner, each of their subsidiaries, Quest Energy, its general partner, and each of their subsidiaries). The maturity date is July 11, 2010. In general, interest will accrue at either LIBOR plus 5.0% or the prime rate plus 4.0%. Quarterly principal payments will be payable in the amount of $1.5 million, commencing with the first full quarter following the closing. The Company borrowed $35 million under the term loan at the closing of the PetroEdge acquisition to refinance a portion of its existing revolving credit facility. For a further description of the terms of the agreement, see the Company’s Current Report on Form 8-K filed on July 16, 2008.

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

Other

On July 16, 2008, Quest Cherokee received a favorable decision regarding the Order to Show Cause issued by the Kansas Corporation Commission (the “KCC”) (KCC Docket No. 07-CONS-155-CSHO) filed on February 23, 2007. The KCC agreed that Quest Cherokee was not legally responsible for plugging 22 abandoned oil wells on a gas lease owned and operated by Quest Cherokee in Wilson County, Kansas.

On July 24, 2008, Quest Energy filed a registration statement on Form S-1 with the SEC relating to a proposed offering of 4,600,000 common units. Quest Energy 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 Quest Energy’s 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.

On August 5, 2008, the board of directors of Quest Midstream’s general partner declared a cash distribution for the quarter ended June 30, 2008 to its common unitholders totaling $3.82 million or $0.425 per unit on its common units.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations Forward-looking Information

We are an independent energy company with an emphasis on the acquisition, exploration, development, production, and transportation of natural gas (coal bed methane) in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma. We also own and operate a gas gathering pipeline network of approximately 2,000 miles in length within this basin. Additionally, we own a 1,120-mile interstate natural gas transmission pipeline that transports natural gas from northwestern Oklahoma and western Kansas to the metropolitan Wichita, Kansas and Kansas City, Missouri markets (the “KPC Pipeline”). Our main focus is upon the development of our coal bed methane gas reserves in the Cherokee Basin and upon the continued enhancement of our pipeline systems and supporting infrastructure. Unless otherwise indicated, references to “us”, “we”, the “Company” or “Quest” include our operating subsidiaries.

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 our gas gathering pipeline system.

We completed approximately 118 miles of natural gas gathering pipeline infrastructure expansion and acquired additional natural gas leases in the Cherokee Basin covering approximately 22,600 acres (net).

We are also continuing the evaluation of the operation of our natural gas gathering system to determine whether changes in compression or other alterations in the operation of the pipeline system might improve production.

For the six months ended June 30, 2008, our average net daily production was 56.4 Mmcfe/d.

Quest Energy 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, Quest Energy 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 Energy’s credit facility.

During May 2008, we determined that our test well in New Mexico was unsuccessful. During the second quarter, we sold our acreage in New Mexico and Texas and expensed approximately $1.26 million to plug and abandon the New Mexico test well.

On June 4, 2008, we acquired rights to farm in approximately 28,700 acres (net) in Potter County, Pennsylvania.

Recent Developments

Equity Offering

On July 8, 2008, we closed on a public offering of 8,800,000 shares of our common stock at a price of $10.25 per share, resulting in net proceeds, after payment of expenses, of approximately $84 million. We used the net proceeds of the offering (1) to fund a portion of the approximately $141.6 million acquisition, subject to post-closing adjustments, of privately held PetroEdge Resources (WV) LLC (“PetroEdge”) discussed below, (2) to repay a portion of our existing revolving credit facility, (3) to pay fees and expenses related to the PetroEdge acquisition and (4) for general corporate purposes, including drilling and development activities.

PetroEdge Acquisition

On June 5, 2008, we entered into a purchase and sale agreement to acquire all the equity interests in PetroEdge for approximately $141.6 million, subject to closing adjustments. On July 11, 2008, the acquisition of PetroEdge was finalized.

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 operates more than 400 wells that produced an average of 3.3 MMcfe/d net during the three months ended March 31, 2008. 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.

In connection with the PetroEdge acquisition, we entered into a new two-year single draw $35 million term loan agreement with RBC. The new term loan was secured by a first priority lien on substantially all of our assets and our subsidiaries’ assets (excluding Quest Midstream, its general partner, each of their subsidiaries, Quest Energy, its general partner, and each of their subsidiaries). In general, interest will accrue at either LIBOR plus 5.0% or the prime rate plus 4.0%. Quarterly principal payments will be payable in the amount of $1.5 million, commencing with the first full quarter following the closing. We borrowed $35 million under the term loan at the closing of the PetroEdge acquisition to refinance a portion of our existing revolving credit facility.

Also on July 11, 2008, Quest Energy purchased over 400 of the PetroEdge natural gas and oil wellbores with estimated proved developed reserves of 32.9 Bcfe and current net production of approximately 3.3 MMcfe/d in exchange for cash consideration of approximately $72 million, subject to post-closing adjustments. Quest Energy funded the purchase of the wellbores with $30 million borrowings under its existing revolving credit facility and a $45 million, six-month, bridge facility. In connection with the acquisition, Quest Energy’s lenders increased the borrowing base of its revolving credit facility to $190 million from $160 million.

Results of Operations

As a result of the acquisition of Quest Pipelines (KPC) (“KPC”), the owner of the KPC Pipeline in November 2007, we have begun reporting our results of operations as two segments: Quest Energy (natural gas and oil production) and Quest Midstream (natural gas pipelines). Previously reported amounts have been adjusted to reflect this change, which did not impact our consolidated financial statements. As a result of our acquisition of PetroEdge discussed above, we intend to begin reporting a third business segment, Quest Eastern, commencing with the third quarter of 2008.

The following discussion is based on the consolidated operations of all our subsidiaries and 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 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.

Quest Energy (Natural Gas and Oil Production Segment)

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


	For the Three Months										For the Six Months
	Ended June 30,					Increase					Ended June 30,						Increase
	2008		2007			(Decrease)					2008			2007			(Decrease)
	($ in thousands)
Oil and gas sales	$	39,903	$	27,867		$	12,036		43.2	%	$	77,256		$	53,416		$	23,840		44.6	%
Other revenue/(expense)	$	72		($19	)	$	91		N/M		$	122		$	(32	)	$	154		N/M
Oil and gas production costs	$	9,763	$	7,740		$	2,023		26.1	%	$	17,971		$	14,967		$	3,004		20.1	%
Transportation expense (intercompany)	$	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	$	4,094		$	(2,169	)	-53.0	%	$	4,383		$	5,847		$	(1,464	)	-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	$	7,190		$	(4,775	)	-66.4	%	$	4,555		$	14,161		$	(9,606	)	-67.8	%


N/M — not meaningful

Production. The following table presents the primary components of revenues of our Natural Gas and Oil Production Segment (natural gas and oil production and average natural gas and oil prices), 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,				Increase				Ended June 30,				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	7	%

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	%


	For the Three Months									For the Six Months
	Ended June 30,				Increase					Ended June 30,				Increase
	2008		2007		(Decrease)					2008		2007		(Decrease)
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		—
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	$	(1.31	)	-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 sales prices and production volumes 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 of net natural gas 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 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 $72,000 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 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 $1.22 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 fee per Mcf for both periods 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 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 for 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 $7.7 million for the three months ended June 30, 2007.

General and Administrative Expense. General and administrative expenses decreased from $4.1 million for the three months ended June 30, 2007 to $1.9 million for the quarter ended June 30, 2008. This decrease is due in part to a decrease in legal fees that are not allocable 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 expenses in 2008 is also due in part to the fact that prior to the formation of Quest Energy in November 2007, all of our general and administrative expenses were allocated to our segments and we did not have any corporate unallocated items.

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, the Company recognized a negative change in derivative value under other comprehensive loss totaling $121.7 million for the three months ended June 30, 2008 as compared to a positive change of $8.3 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 Quest Energy’s 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 six 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 partially offset by the natural decline in production from some of our older natural 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 ended 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 $122,000 as compared to other expense of $32,000 for the six-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 $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 $1.9 million due to increased production and increased 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 six months ended June 30, 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. This increase primarily resulted from the annual increase in the fees charged under the midstream services agreement with Quest Midstream and increased production.

Depreciation, Depletion and Amortization. We are subject to variances in our depletion rates from period to period, including the periods described below. These variances result from changes in our oil and 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 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 expenses 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, and 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 also due in part to the fact that prior to the formation of Quest Energy in November 2007, all of our general and administrative expenses were allocated to our segments and we did not have any corporate unallocated items.

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, the Company recognized a negative change in derivative value under other comprehensive loss totaling $138.6 million for the six months ended June 30, 2008 as compared to a negative change of $4.1 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 Quest Energy’s public offering which resulted in lower outstanding borrowings and lower interest rates.

Quest Midstream (Natural Gas Pipelines Segment)


	For the Three
	Months									For the Six Months
	Ended June 30,									Ended June 30,
					Increase									Increase
	2008		2007		(Decrease)					2008		2007		(Decrease)
Pipeline Revenue ($ in thousands):
Gathering — Intercompany	$	8,675	$	6,809	$	1,866		27	%	$	17,338	$	13,170	$	4,168	32	%
Gathering — Third Party		2,201		1,792		409		23	%		4,220		3,334		886	27	%
KPC		4,947		—		4,947		N/M			9,829		—		9,829	N/M

Total gas pipeline revenue	$	15,823	$	8,601	$	7,222		N/M		$	31,387	$	16,504	$	14,880	N/M

Pipeline Operating Expense:
Gathering	$	6,054	$	4,333	$	1,721		40	%	$	11,873	$	9,267	$	2,606	28	%
KPC		2,203		—		2,203		N/M			3,633		—		3,633	N/M

Total pipeline operating expense		8,257		4,333		12,181		N/M			15,506		9,267		6,239	N/M

Depreciation and amortization	$	3,155	$	1,145	$	2,010		N/M		$	6,376	$	2,271	$	4,105	N/M
General and administrative expense	$	2,258	$	1,313	$	945		N/M		$	4,083	$	2,199	$	1,884	N/M
Interest expense	$	1,951	$	420	$	1,531		N/M		$	3,952	$	562	$	3,390	N/M

Operating Statistics (MMcf):
Gathering volumes — Intercompany		6,201		5,000		1,201		24	%		12,284		9,570		2,714	28	%
Gathering volumes — Third Party		428		447		(19	)	4	%		857		847		10	1	%
KPC firm transportation contracted capacity (1)		13,992		—		13,992		N/M			27,838		—		27,838	N/M
KPC interruptible throughput volumes (1)		771		—		771		N/M			1,501		—		1,501	N/M

Average Pipeline Operating Costs per MMcf:
Gathering pipeline operating costs	$	0.91	$	0.80	$	0.11		14	%	$	0.90	$	0.89	$	0.01	2	%


(1)		In accordance with the terms of the KPC Pipeline tariff, all volumes are in dekatherm. For purposes of these financial statements, we have assumed one dekatherm is equal to one Mcf.

N/M		— not meaningful

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

Pipeline Revenue. Our third party gathering revenues were $2.2 million for the three months ended June 30, 2008, an increase of $409,000 (23%) from $1.8 million for the three months ended June 30, 2007. KPC, which was acquired November 1, 2007, had transmission revenues of $4.9 million for the three months ended June 30, 2008.

The intercompany gathering revenues were $8.7 million for the three months ended June 30, 2008 as compared to $6.8 million for the three months ended June 30, 2007, an increase of $1.9 million, or 27%. The increase was due to the 24% increase in throughput volumes on our Cherokee Basin gathering system and the increase in gathering and compression fees resulting from the annual price adjustment under the midstream services agreement that became effective January 1, 2008, which resulted in a fixed transportation fee that was higher than the fees in the year earlier period.

Pipeline Operating Expense. Pipeline operating costs for the three months ended June 30, 2008 totaled approximately $8.3 million, $6.1 million for our Cherokee Basin gathering system ($0.91 per MMcf) and $2.2 million for the KPC Pipeline, as compared to pipeline operating costs of $4.3 million ($0.80 per MMcf) for our Cherokee Basin gathering system for the three months ended June 30, 2007. This increase in operating costs was due primarily to additional compressors on our Cherokee Basin gathering system in anticipation of increased gathering volumes, the number of wells completed and operated during the year, the increased miles of pipeline in service, the increase in property taxes and the operations of the KPC Pipeline and the firm transportation volumes associated with KPC.

Depreciation and Amortization. Depreciation and amortization expense was $3.2 million for the three months ended June 30, 2008 compared to $1.1 million in 2007. The increase is due to the acquisition of KPC on November 1, 2007 and the additional natural gas gathering pipeline installed since June 30, 2007.

General and Administrative Expense. General and administrative expenses increased from $1.3 million for the three months ended June 30, 2007 to $2.3 million for the three months ended June 30, 2008. This increase primarily resulted from a non-cash charge of amortization of stock and unit awards. The remainder of the increase is due to an increase in staff personnel, legal, accounting and professional fees, travel expenses for presentations to increase our visibility with investors, costs for establishing a Houston office and staffing requirements, increased staffing to support the KPC Pipeline and higher levels of development and operational activity and the added resources to enhance our internal controls.

Interest Expense. Interest expense increased to $2.0 million for the three months ended June 30, 2008 from $420,000 for the three months ended June 30, 2007, due to additional borrowings under our credit facility to finance the acquisition of KPC during 2007 and the construction of additional gas gathering pipeline.

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

Pipeline Revenue. Our third party gathering revenues were $4.2 million for the six months ended June 30, 2008, an increase of $886,000 (27%) from $3.3 million for the six months ended June 30, 2007. KPC, which was acquired November 1, 2007, had transmission revenues of $9.8 million for the six months ended June 30, 2008.

The intercompany gathering revenues were $17.3 million for the six months ended June 30, 2008 as compared to $13.2 million for the six months ended June 30, 2007, an increase of $4.1 million, or 32%. The increase is due to the 28% increase in throughput volumes on our Cherokee Basin gathering system and the increase in gathering and compression fees resulting from the annual price adjustment under the midstream services agreement that became effective January 1, 2008, which resulted in a fixed transportation fee that was higher than the fees in the year earlier period.

Pipeline Operating Expense. Pipeline operating costs for the six months ended June 30, 2008 totaled approximately $15.5 million, $11.9 million for our Cherokee Basin gathering system ($0.90 per MMcf) and $3.6 million for the KPC Pipeline, as compared to pipeline operating costs of $9.3 million ($0.89 per MMcf) for our Cherokee Basin gathering system for the six months ended June 30, 2007. This increase in operating costs was due primarily to additional compressors on our Cherokee Basin gathering system in anticipation of increased pipeline volumes, the number of wells completed and operated during the year, the increased miles of pipeline in service, the increase in property taxes and the operations of the KPC Pipeline and the firm transportation volumes associated with KPC.

Depreciation and Amortization. Depreciation and amortization expense was $6.4 million for the six months ended June 30, 2008 compared to $2.3 million in 2007. The increase is due to the acquisition of KPC on November 1, 2007 and the additional natural gas gathering pipeline installed since June 30, 2007.

General and Administrative Expense. General and administrative expenses increased from $2.2 million for the six months ended June 30, 2007 to $4.1 million for the six months ended June 30, 2008. This increase resulted primarily from a non-cash charge amortization of stock and unit awards. The remainder of the increase is due to an increase in staff personnel, legal, accounting and professional fees, travel expenses for presentations to increase our visibility with investors, costs for a Houston office and staffing requirements, increased staffing to support the KPC Pipeline and higher levels of development and operational activity and the added resources to enhance our internal controls.

Interest Expense. Interest expense increased to $4.0 million for the six months ended June 30, 2008 from $562,000 for the six months ended June 30, 2007, due to additional borrowings under of our credit facility to finance the acquisition of KPC during 2007 and the construction of additional gas gathering pipeline.

Corporate Unallocated Items

The following discussion of results of operations will disuss the amounts for the three and six months ended June 30, 2008. In 2007, all amounts were fully allocated between our two segments.

Three Months Ended June 30, 2008

General and Administrative Expense. Unallocated general and administrative expenses were $2.1 million for the quarter ended June 30, 2008, consisting of a non-cash charge of approximately $164,000 for amortization of stock and unit awards, board fees, larger corporate offices and $1.2 million of costs incurred pursuing acquisitions which were not consummated.

Depreciation Expense. Unallocated depreciation and amortization expense was $1.4 million for the three months ended June 30, 2008, consisting of $136,000 of depreciation expense for new office space and furniture and equipment to meet staffing requirements and approximately $1.26 million to plug and abandon the New Mexico test well.

Interest Expense. Unallocated interest expense was $912,000 for the three months ended June 30, 2008. During the first three months of 2007, all of the indebtedness under our prior credit facilities was allocated to our oil and production segment. In connection with the formation of Quest Energy, the portion of this debt that was not refinanced with the proceeds from Quest Energy’s initial public offering and Quest Energy’s new credit facility was deemed to be unallocated.

Six Months Ended June 30, 2008

General and Administrative Expense. Unallocated general and administrative expenses were $2.7 million for the six months ended June 30, 2008, consisting of a non-cash charge of approximately $712,000 for amortization of stock and unit awards board fees, larger corporate offices and $1.2 million in costs incurred pursuing acquisitions which were not consummated.

Depreciation Expense. Unallocated depreciation and amortization expense was $1.5 million for the six months ended June 30, 2008, consisting of $204,000 of depreciation expense for new office space and furniture and equipment to meet staffing requirements and approximately $1.26 million to plug and abandon the New Mexico test well.

Interest Expense. Unallocated interest expense was $1.9 million for the six months ended June 30, 2008. During the first six months of 2007, all of the indebtedness under our prior credit facilities was allocated to our oil and production segment. In connection with the formation of Quest Energy, the portion of this debt that was not refinanced with the proceeds from Quest Energy’s initial public offering and Quest Energy’s new credit facility was deemed to be unallocated.

Net Income (Loss)

We recorded net income of $5.0 million for the three months ended June 30, 2008 as compared to a net loss of $4.5 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 and after excluding the minority interest in continuing operations of Quest Midstream and Quest Energy.

We recorded a net loss of $6.7 million for the six months ended June 30, 2008 as compared to a net loss of $7.8 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 and after excluding the minority interest in continuing operations of Quest Midstream and Quest Energy.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from our operations, amounts available under our revolving credit facilities and funds from future private and public equity and debt offerings. Please read Note 3 — Long-Term Debt to our consolidated financial statements included in our 2007 Form 10-K for additional information relating to our credit facilities, including a description of the financial covenants contained in each of the credit facilities.

At June 30, 2008, we had $2 million of availability under our revolving credit facility, which was available for general corporate purposes. In connection with the PetroEdge acquisition, we entered into a new two-year single draw $35 million term loan agreement with RBC. The new term loan is secured by a first priority lien on substantially all of our assets and our subsidiaries’ assets (excluding Quest Midstream, its general partner, each of their subsidiaries, Quest Energy, its general partner, and each of their subsidiaries). In general, interest will accrue at either LIBOR plus 5.0% or the prime rate plus 4.0%. Quarterly principal payments will be payable in the amount of $1.5 million, commencing with the first full quarter following the closing. We borrowed $35 million under the term loan at the closing of the PetroEdge acquisition to refinance a portion of our existing revolving credit facility. The remainder of our revolving credit facility was repaid with the proceeds of our public offering of 8.8 million common shares that closed on July 8, 2008.

At June 30, 2008, Quest Energy had $18 million of availability under its 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. Quest Energy funded the purchase of the PetroEdge wellbores with $30 million of borrowings under its existing revolving credit facility and a

$45 million, six-month, bridge facility. In connection with the acquisition, Quest Energy’s lenders increased the borrowing base of its revolving credit facility to $190 million from $160 million.

At June 30, 2008, Quest Midstream had $13 million of availability under its revolving credit facility, which was available to fund additional pipeline construction and related facilities, the connection of additional wells to our pipeline system, pipeline acquisitions and working capital for our pipeline operations.

At June 30, 2008, we had current assets of $70.3 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 $13.1 million at June 30, 2008, compared to working capital (excluding the short-term derivative asset and liability of $6.7 million and $8.2 million, respectively) of $1.2 million at December 31, 2007. The changes in working capital were primarily due to an increase in inventory, accounts payable and accrued expenses.

A substantial portion of our production is hedged. We are generally required to settle a portion of our commodity hedges on each of the 5th and 25th day of each month. As is typical in the gas and oil business, we generally do not receive the proceeds from the sale of the hedged production until around the 25th 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 hedge and the market price before we receive the proceeds from the sale of the hedged production.

Capital Expenditures

During the six months ended June 30, 2008, a total of approximately $92.4 million of capital expenditures was invested as follows: $45.0 million was invested in new natural gas wells and properties, $19.5 million in new pipeline facilities, $9.5 million in acquiring oil producing properties in Seminole County, Oklahoma, $9.0 million in acquiring leasehold in Pennsylvania, West Virginia and New York ($5 million was related to a nonrefundable deposit for the acquisition of PetroEdge, which closed July 11, 2008), $4.7 million in acquiring additional leasehold in the Cherokee Basin and $4.6 million in other additional capital items. These investments were funded by cash flow from operations and additional proceeds from Quest Midstream borrowings of $27 million, Quest Energy borrowings of $48 million, and our borrowings of $4 million under the respective credit facilities.

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

	•		$21.5 million for the pipeline expansion to connect the new wells to our existing gas gathering pipeline network in the Cherokee Basin;

	•		$15.5 million for line looping, KPC activities, and the development of new facilities; and

	•		$2.0 million for exploration and production activities in areas outside of 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 and pipeline volumes 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, our asset base or our pipeline volumes over the long term.

Quest Energy and Quest Midstream will be responsible for the Cherokee Basin capital expenditures described above. Quest Midstream will be responsible for the KPC expenditures described above. In general, Quest Energy and Quest Midstream intend to finance future maintenance capital expenditures generally from cash flow from operations and expansion capital expenditures generally with borrowings under their credit facilities and/or the issuance of debt or equity securities.

We will be responsible for the capital expenditures outside the Cherokee Basin described above. We intend to finance these capital expenditures through either borrowings under our revolving credit facility, the issuance of debt or equity securities and/or distributions from Quest Energy and/or Quest Midstream.

In connection with the PetroEdge acquisition, the Company plans to significantly increase our capital expenditure budget for the remainder of 2008. Management intends to recommend to our board of directors of the Company the spending, during the third and fourth quarters of 2008, of between $10 million and $15 million on projects in the Appalachian Basin to convert proved undeveloped reserves to proved developed and to add new reserves and production from currently unproven acreage. We are currently drilling our first two horizontal wells targeting the Marcellus shale formation in Wetzel County, West Virginia with completion expected in the fourth quarter of 2008 and are permitting our initial drilling locations in Lycoming County, Pennsylvania with two vertical wells planned before year end.

Management intends to recommend to the board of directors of the general partner of Quest Energy 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 and the credit facilities of Quest Midstream and Quest Energy. 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 5. Long-Term Debt to our consolidated financial statements included in this report for a description of the financial covenants contained in each of the credit facilities. 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 $41.5 million for the six months ended June 30, 2008 as compared to net cash provided by operations of $12.6 million for the six months ended June 30, 2007. This resulted from the change in derivative fair value, an increase in accounts receivable and inventory offset by a decrease in restricted cash, revenue payable and accrued expenses.

Cash Flows Used in Investing Activities. Net cash used in investing activities totaled $92.4 million for the six months ended June 30, 2008 as compared to $63.3 million for the six months ended June 30, 2007. During the six months ended June 30, 2008, $92.4 million of capital expenditures was invested as follows: $45.0 million was invested in new natural gas wells and properties, $19.5 million in new pipeline facilities, $9.5 million in acquiring oil producing properties in Seminole County, Oklahoma, $9.0 million in acquiring leasehold in Pennsylvania, West Virginia and New York ($5 million was related to a nonrefundable deposit for the acquisition of PetroEdge, which closed July 11, 2008), $4.7 million in acquiring additional leasehold in the Cherokee Basin and $4.6 million in other additional capital items.

Cash Flows from Financing Activities. Net cash provided by financing activities totaled $65.8 million for the six months ended June 30, 2008 as compared to $25.0 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 Quest Midstream borrowings of $27 million, Quest Energy borrowings of $48 million, and our borrowings of $4 million under the respective credit facilities.

Contractual Obligations

Future payments due on our contractual obligations as of June 30, 2008 are as follows:


	Payments Due by Period
			Less Than		1-3		4-5		More Than
	Total		1 Year		Years		Years		5 Years
	(In thousands)
Revolving Credit Facility — Quest Resource	$	48,000	$	—	$	48,000	$	—	$	—
Revolving Credit Facility — Quest Energy		142,000		—		142,000		—		—
Revolving Credit Facility — Quest Midstream		122,000		—		—		122,000		—
Notes Payable		399		247		111		34		7
Interest expense obligation(1)		68,609		10,234		38,988		19,387		—
Drilling contractor		856		856		—		—		—
Asset retirement obligations		4,181		—		—		—		4,181
Lease obligations		10,003		664		2,673		2,614		4,052
Derivatives		147,976		66,379		65,414		16,183		—

Total	$	544,024	$	78,380	$	297,186	$	160,218	$	8,240


(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 $10.7 million.

Critical Accounting Policies

The consolidated 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 2 to our consolidated 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 and construction of pipeline infrastructure;

	•		acquisition and development of natural gas and oil properties and related pipeline infrastructure;

	•		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, including pipeline infrastructure;

	•		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 construction of pipelines and 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 our pipeline systems;

	•		costs associated with perfecting title for natural gas rights and pipeline easements and rights of way 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 6 to our consolidated financial statements in this report.

Item 4. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer (our principal executive officer) and our Chief Financial Officer (our principal financial officer), we evaluated the effectiveness of our disclosure controls and procedures (as defined under Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on this evaluation, our Chief Executive Officer and our Chief Financial Officer believe that the disclosure controls and procedures as of June 30, 2008 were effective at a reasonable assurance level to ensure that information we are required to disclose 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 and are effective to ensure that information required to be disclosed by us is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, 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 10 to our consolidated 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 Relating to the Acquisition of PetroEdge

The integration of PetroEdge following the acquisition will present significant challenges that may reduce the anticipated potential benefits of the acquisition.

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

	•		integrating PetroEdge’s existing operations;

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

	•		addressing differences in business cultures while maintaining focus on meeting the operational and financial goals of the combined company; and

	•		incurring significant transaction and integration costs.

Management will have to dedicate substantial effort to integrating PetroEdge. These efforts could divert management’s focus and resources from other day-to-day tasks, corporate initiatives or strategic opportunities during the integration process. We do not expect to retain the personnel of PetroEdge and will enter into a one-year transition services agreement with PetroEdge’s parent, which will include PetroEdge’s existing management team, to assist in the integration process. We 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 business, 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 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 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 primary areas, 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 Acquisition Financing by Quest Energy

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, Quest Energy obtained a bridge loan in the amount of $45.0 million and borrowed approximately $30.0 million under its revolving credit facility. The bridge loan is secured by a second lien on the assets of Quest Energy and will mature within six months of the date of closing of the PetroEdge acquisition. As of August 6, 2008, Quest Energy has approximately $18.0 million of availability under its revolving credit facility. To repay the bridge loan and to obtain additional capital to fund a portion of Quest Energy’s 2009 capital expenditure budget, Quest Energy expects 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 Quest Energy 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 its future capital expenditures. Failure to raise sufficient funds to repay the bridge loan could expose Quest Energy’s assets to foreclosure or other collection efforts. Failure to raise sufficient additional funds to finance its 2009 capital expenditures could result in a reduction in the pace at which Quest Energy develops its properties, which in turn could adversely affect its ability to make distributions on its units and comply with the financial covenants in its credit facilities.

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

Our 2008 Annual Meeting of Stockholders was held on June 19, 2008, at which time a vote was taken to elect two Class II directors to our board of directors. The stockholders elected the following directors as Class II directors:


Director	Term Expiring In		Votes For		Votes Withheld
Bob Alexander		2011		18,524,480		745,856
William H. Damon III		2011		17,619,347		1,650,989

The stockholders approved amendments to our 2005 Omnibus Stock Award Plan, with 12,515,653 votes for, 2,912,688 votes against and 1,090,240 votes abstaining.

The stockholders approved our Amended and Restated Management Annual Incentive Plan, dated May 1, 2008 with 13,670,468 votes for, 1,753,071 votes against and 1,089,042 votes abstaining.

Item 5. Other Information

None

Item 6. Exhibits


2.1*		Membership Interest Purchase Agreement, by and between PetroEdge Resources Partners, LLC and Quest Resource Corporation, dated as of June 5, 2008 (incorporated herein by reference to Exhibit 2.1 to Quest Resource Corporation’s amended Current Report on Form 8-K/A filed on June 19, 2008).

2.2*		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 Resource Corporation’s Current Report on Form 8-K filed on July 16, 2008).

3.1*		Third Amended and Restated Bylaws of Quest Resource Corporation (as adopted on May 7, 2008) (incorporated herein by reference to Exhibit 3.1 to Quest Resource Corporation’s Quarterly Report on Form 10-Q filed on May 12, 2008).

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 the Company’s Current Report on Form 8-K filed on April 23, 2008).

10.2*		Amended and Restated Credit Agreement, dated as of July 11, 2008, by and among Quest Resource Corporation, Royal Bank of Canada, the lenders party thereto and RBC Capital Markets (incorporated herein by reference to Exhibit 10.1 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 16, 2008).

10.3*		Pledge and Security Agreement for Amended and Restated Credit Agreement by Quest Eastern Resource LLC for the benefit of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.2 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 16, 2008).

10.4*		Pledge and Security Agreement for Amended and Restated Credit Agreement by Quest MergerSub, Inc. for the benefit of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.3 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 16, 2008).


10.5*		First Amendment to Pledge and Security Agreement for Amended and Restated Credit Agreement by Quest Resource Corporation for the benefit of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.4 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 16, 2008).

10.6*		Guaranty for Amended and Restated Credit Agreement by Quest Eastern Resource LLC in favor of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.5 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 16, 2008).

10.7*		Guaranty for Amended and Restated Credit Agreement by Quest MergerSub, Inc. in favor of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.6 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 16, 2008).

10.8*		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 10.7 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 16, 2008).

10.9*		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 10.8 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 16, 2008).

10.10*		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 10.9 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 16, 2008).

10.11*		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 10.10 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 16, 2008).

10.12*		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 10.11 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 16, 2008).

10.13*		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 10.12 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 16, 2008).

10.14*		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 10.13 to Quest Resource Corporation’s Current Report on Form 8-K filed on July 16, 2008).

10.15		Employment Agreement dated July 14, 2008 between Quest Resource Corporation and Tom Lopus.

10.16*		Amendments to Quest Resource Corporation’s 2005 Omnibus Stock Award Plan (incorporated herein by reference to Appendix A to Quest Resource Corporation’s Proxy Statement filed on May 20, 2008).

10.17*		Amended and Restated Quest Resource Corporation Management Annual Incentive Plan (incorporated herein by reference to Appendix C to Quest Resource Corporation’s Proxy Statement filed on May 20, 2008).

12.1		Ratio of Earnings to Fixed Charges

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.


PART I — FINANCIAL INFORMATION

Item 1. Financial Statements			F-1
Consolidated Balance Sheets: June 30, 2008 and December 31, 2007			F-2
Consolidated Statements of Operations and Comprehensive Income: Three Months and Six Months Ended June 30, 2008 and 2007			F-3
Consolidated Statements of Cash Flows: Six Months Ended June 30, 2008 and 2007			F-4
Consolidated Statement of Stockholders’ Equity: Six Months Ended June 30, 2008			F-5
Condensed Notes to Consolidated Financial Statements			F-6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			3
Item 3. Quantitative and Qualitative Disclosures About Market Risk			16
Item 4. Controls and Procedures			16

PART II — OTHER INFORMATION

Item 1. Legal Proceedings			16
Item 1A. Risk Factors			16
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			17
Item 3. Defaults Upon Senior Securities			17
Item 4. Submission of Matters to a Vote of Security Holders			18
Item 5. Other Information			18
Item 6. Exhibits			18
SIGNATURES			21


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.


	QUEST RESOURCE CORPORATION
	By:	/s/ Jerry D. Cash
		Jerry D. Cash
		Chief Executive Officer


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


			Common					Accumulated
			Stock		Additional			Other
	Common		Par		Paid-in			Comprehensive			Accumulated
	Shares		Value		Capital			Income (Loss)			Deficit			Total
	($ in thousands)
Balance, December 31, 2007		22,701,029	$	23	$	212,819		$	(1,485	)	$	(119,504	)	$	91,853
Comprehensive income:
Net loss												(6,678	)		(6,678	)
Other comprehensive loss, net of tax:
Change in fixed-price contract and other derivative fair value									(127,326	)					(127,326	)

Total comprehensive loss															(134,004	)
Equity offering costs						(39	)								(39	)
Stock awards granted to employees		1,243,802		1		2,510									2,511
Stock awards granted to directors		30,000		—		487			—			—			487

Balance, June 30, 2008		23,974,831	$	24	$	215,777		$	(128,811	)	$	(126,182	)	$	(39,192	)