QUEST RESOURCE CORPORATION

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2006

TABLE OF CONTENTS


PART I - FINANCIAL INFORMATION				3

	Item 1.	Financial Statements		3

			Condensed Consolidated Balance Sheets:
			June 30, 2006 and December 31, 2005	F-1

			Condensed Consolidated Statements of Operations and Comprehensive Income:
			Three months and Six months ended June 30, 2006 and 2005	F-2

			Condensed Consolidated Statements of Cash Flows:
			Six months ended June 30, 2006 and 2005	F-3

			Condensed Notes to Consolidated Financial Statements	F-4

	Item 2.	Management's Discussion and Analysis of Financial Condition and
		Results of Operations		4

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		9

	Item 4.	Controls and Procedures		9

PART II - OTHER INFORMATION				9

	Item 1.	Legal Proceedings		9

	Item 1A.	Risk Factors		9

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		9

	Item 3.	Defaults Upon Senior Securities		10

	Item 4.	Submission of Matters to a Vote of Security Holders		10

	Item 5.	Other Information		10

	Item 6.	Exhibits		10

SIGNATURES				12

-2-

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 Cherokee, LLC; Quest Cherokee Oilfield Service, LLC; Bluestem Pipeline, LLC; Quest Oil & Gas Corporation; Ponderosa Gas Pipeline Company, Inc.; Quest Energy Service, Inc.; STP Cherokee, Inc.; Producers Service, Incorporated; and J-W Gas Gathering, L.L.C. Our operations are primarily conducted through Quest Cherokee, LLC, Quest Cherokee Oilfield Service, LLC, Bluestem Pipeline, LLC and Quest Energy Service, Inc.

Our unaudited interim financial statements, including a balance sheet as of June 30, 2006, a statement of operations and comprehensive income for the three month and six month periods ended June 30, 2006, and a statement of cash flows for the six month period ended June 30, 2006 and the comparable periods of 2005, are attached hereto as Pages F-1 through F-19 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 financial statements included herein should be read in conjunction with the financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2005.

Reverse Stock Split

In October 2005, our board of directors approved a 2.5 to 1 reverse stock split, and a proportionate reduction of the authorized number of shares, of our common stock. In addition, the reverse stock split resulted in a reclassification of amounts from common stock to additional paid-in capital to reflect the adjusted number of shares outstanding, since the par value of our common stock remained at $0.001 per share. On October 31, 2005, the reverse stock split became effective. All share and per share data information in this Form 10-Q, and the financial statements included herein, for all periods have been retroactively restated to reflect the reverse stock split.

-3-

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30, 2006			December 31, 2005
	(unaudited)
ASSETS
Current assets:
Cash	$	35,361,000		$	2,559,000
Restricted cash		1,149,000			4,318,000
Accounts receivable, trade		6,923,000			9,658,000
Other receivables		333,000			343,000
Other current assets		2,221,000			1,936,000
Inventory		4,124,000			2,782,000
Short-term derivative asset		1,125,000			95,000
Total current assets		51,236,000			21,691,000

Property and equipment, net of accumulated depreciation of $3,892,000 and $2,114,000		16,526,000			13,490,000

Pipeline assets, net of accumulated depreciation of $4,645,000 and $3,598,000		98,809,000			60,150,000
Pipeline assets under construction		12,472,000			12,699,000

Oil and gas properties:
Properties being amortized		259,482,000			201,788,000
Properties not being amortized		20,491,000			18,285,000
		279,973,000			220,073,000
Less: Accumulated depreciation, depletion and amortization		(48,338,000	)		(36,703,000	)
Net oil and gas properties		231,635,000			183,370,000
Other assets, net		6,786,000			6,310,000
Long-term derivative asset		2,245,000			93,000
Total assets	$	419,709,000		$	297,803,000

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	19,788,000		$	12,381,000
Revenue payable		3,025,000			5,044,000
Accrued expenses		2,283,000			649,000
Current portion of notes payable		543,000			407,000
Short-term derivative liability		13,868,000			38,195,000
Total current liabilities		39,507,000			56,676,000

Non-current liabilities:
Long-term derivative liability		13,922,000			23,723,000
Asset retirement obligation		1,275,000			1,150,000
Notes payable		225,931,000			100,988,000
Less current maturities		(543,000	)		(407,000	)
Non-current liabilities		240,585,000			125,454,000

Total liabilities		280,092,000			182,130,000
Commitments and contingencies
Stockholders’ equity:
10% convertible preferred stock, $.001 par value, 50,000,000 shares authorized,
0 shares issued and outstanding at June 30, 2006 and December 31, 2005
Common stock, $.001 par value, 200,000,000 shares authorized and 22,123,514
shares issued and outstanding at June 30, 2006 and 380,000,000 authorized and
22,072,383 shares issued and outstanding at December 31, 2005		22,000			22,000
Additional paid-in capital		204,270,000			203,434,000
Accumulated other comprehensive income		(27,001,000	)		(47,171,000	)
Accumulated deficit		(37,674,000	)		(40,612,000	)
Total stockholders’ equity		139,617,000			115,673,000
Total liabilities and stockholders’ equity	$	419,709,000		$	297,803,000

F-1

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(UNAUDITED)

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005

Revenue:
Oil and gas sales	$	15,306,000		$	12,100,000		$	33,785,000		$	23,366,000
Gas pipeline revenue		1,268,000			901,000			2,350,000			1,707,000
Other revenue (expense)		(2,858,000	)		2,000			(10,299,000	)		(19,000	)
Total revenues		13,716,000			13,003,000			25,836,000			25,054,000

Costs and expenses:
Oil and gas production		4,644,000			2,984,000			8,572,000			5,293,000
Pipeline operating		3,061,000			2,006,000			5,930,000			3,776,000
General and administrative		2,351,000			1,005,000			3,873,000			1,976,000
Depreciation, depletion and amortization		6,869,000			3,874,000			12,768,000			7,228,000
Total costs and expenses		16,925,000			9,869,000			31,143,000			18,273,000

Operating income (loss)		(3,209,000	)		3,134,000			(5,307,000	)		6,781,000

Other income (expense):
Change in derivative fair value		2,383,000			874,000			16,864,000			1,318,000
Sale of assets		23,000			—			43,000			—
Interest income		113,000			2,000			249,000			6,000
Interest expense		(5,090,000	)		(5,917,000	)		(8,912,000	)		(11,110,000	)
Total other income (expense)		(2,571,000	)		(5,041,000	)		8,244,000			(9,786,000	)

Income (loss) before income taxes		(5,780,000	)		(1,907,000	)		2,937,000			(3,005,000	)
Income tax expense - deferred		—			—			—			—
Net income (loss)		(5,780,000	)		(1,907,000	)		2,937,000			(3,005,000	)

Other comprehensive income (loss), net of tax:
Change in fixed-price contract and other derivative fair value, net of tax of $0 and $0		9,444,000			(3,729,000	)		19,507,000			(27,139,000	)
Reclassification adjustments - contract settlements, net of tax of $0 and $0		663,000			3,165,000			663,000			5,395,000
Other comprehensive income (loss)		10,107,000			(564,000	)		20,170,000			(21,744,000	)
Comprehensive income (loss)	$	4,327,000		$	(2,471,000	)	$	23,107,000		$	(24,749,000	)

Net income (loss)	$	(5,780,000	)	$	(1,907,000	)	$	2,937,000		$	(3,005,000	)
Preferred stock dividends		—			(3,000	)		—			(5,000	)
Net income (loss) available to common shareholders	$	(5,780,000	)	$	(1,910,000	)	$	2,937,000		$	(3,010,000	)

Earnings (loss) per common share - basic	$	(0.26	)	$	(0.30	)	$	0.13		$	(0.50	)

Earnings (loss) per common share - diluted	$	(0.26	)	$	(0.30	)	$	0.13		$	(0.50	)

Weighted average common and common equivalent shares:
Basic		22,074,631			6,339,552			22,073,513			6,021,482
Diluted		22,074,631			6,339,552			22,134,156			6,021,482

F-2

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	For the Six Months Ended
	2006			2005

Cash flows from operating activities:
Net income (loss)	$	2,937,000		$	(3,005,000	)
Adjustments to reconcile net income (loss) to cash provided by operations:
Depreciation and depletion		14,647,000			7,638,000
Change in derivative fair value		(16,864,000	)		(1,318,000	)
Stock issued for retirement plan		428,000			266,000
Stock options granted for directors fees		239,000			—
Stock issued for audit committee fees		—			19,000
Stock awards granted to employees		254,000			—
Accrued interest on subordinated note		—			5,158,000
Amortization of loan origination fees		547,000			436,000
Amortization of gas swap fees		83,000			—
Amortization of deferred hedging gains		(275,000	)		(465,000	)
(Gain) loss on sale of assets		(43,000	)		—
Change in assets and liabilities:
Restricted cash		3,169,000			—
Accounts receivable		2,735,000			6,035,000
Other receivables		10,000			(171,000	)
Other current assets		(286,000	)		(471,000	)
Inventory		(1,341,000	)		(265,000	)
Accounts payable		7,406,000			(8,389,000	)
Revenue payable		(2,019,000	)		176,000
Accrued expenses		1,634,000			(95,000	)
Net cash provided by operating activities		13,261,000			5,549,000

Cash flows from investing activities:
Equipment, development and leasehold costs		(98,997,000	)		(20,532,000	)
Net additions to other property and equipment		(4,915,000	)		(723,000	)
Net cash used in investing activities		(103,912,000	)		(21,255,000	)

Cash flows from financing activities:
Proceeds from bank borrowings		125,170,000			4,682,000
Proceeds from subordinated debt		—			12,000,000
Repayments of note borrowings		(226,000	)		(3,305,000	)
Syndication costs paid on issuance of common stock		(386,000	)		—
Dividends paid		—			(5,000	)
Refinancing costs		(1,105,000	)		(380,000	)
Net cash provided by financing activities		123,453,000			12,992,000

Net increase (decrease) in cash		32,802,000			(2,714,000	)
Cash, beginning of period		2,559,000			6,458,000
Cash, end of period	$	35,361,000		$	3,744,000

Supplemental disclosure of cash flow information
Cash paid during the period for:
Interest expense	$	7,556,000		$	5,522,000
Income taxes	$	—		$	—

F-3

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2006

(UNAUDITED)

1. Basis of Presentation and Summary of Significant Accounting Policies

Nature of Business

Quest Resource Corporation (the “Company”) is an independent energy company with an emphasis on the acquisition, production, gathering, exploration, and development of natural gas (coal bed methane) in southeastern Kansas and northeastern Oklahoma. Quest operations are currently focused on developing coal bed methane gas production in a ten county region that is served by a Company-owned pipeline network.

Principles of Consolidation and Subsidiaries

Ownership of Subsidiaries. The Company’s subsidiaries consist of:

·	STP Cherokee, Inc., an Oklahoma corporation (“STP”),

·	Quest Energy Service, Inc., a Kansas corporation (“QES”),

·	Quest Oil & Gas Corporation, a Kansas corporation (“QOG”),

·	Producers Service, Incorporated, a Kansas corporation (“PSI”),

·	Ponderosa Gas Pipeline Company, a Kansas corporation (“PGPC”),

·	Bluestem Pipeline, LLC, a Delaware limited liability company (“Bluestem”),

·	J-W Gas Gathering, L.L.C., a Kansas limited liability Company (“J-W Gas”),

·	Quest Cherokee, LLC, a Delaware limited liability company (“Quest Cherokee”), and

·	Quest Cherokee Oilfield Service, LLC, a Delaware limited liability company (“QCOS”).

QES, QOG, PGPC and STP are wholly-owned by the Company. PGPC owns all of the outstanding capital stock of PSI and PSI is the sole member of J-W Gas.

Quest Cherokee is the sole member of Bluestem and QCOS.

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

Ownership of Company Assets. Quest Cherokee owns and operates all of the Company’s Cherokee Basin natural gas and oil properties. Quest Cherokee Oilfield Service owns and operates all of the Company’s vehicles and equipment and Bluestem owns all of the Company’s gas gathering pipeline assets in the Cherokee Basin. QES employs all of the Company’s non-field employees. The costs associated with field employees, first level supervisors, exploration, development and operation of the properties and certain other direct charges are borne by QCOS. STP owns properties located in Texas and Oklahoma outside of the Cherokee Basin, and QES and STP own certain equipment used at the corporate headquarters offices.

Minority Investments; Other. Investments in which the Company does not have a majority voting or financial controlling interest are accounted for under the equity method of accounting unless its ownership constitutes less than a 20% interest in such entity for which such investment would then be included in the consolidated financial statements on the cost method. All significant inter-company transactions and balances have been eliminated in consolidation.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires us 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.

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.

F-4

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2006

(UNAUDITED)

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. Periodically, the Company’s cash balances are in excess of this amount.

Accounts Receivable

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 Company’s joint interest and natural gas and oil sales receivables are generally unsecured; however, the Company has not experienced any significant losses to date. Receivables are recorded at the estimate of amounts due based upon the terms of the related agreements.

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

Inventory

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

Concentration of Credit Risk

A significant portion of the Company’s liquidity is concentrated in cash and derivative instruments that enable the Company to hedge a portion of its exposure to price volatility from producing natural gas and oil. These arrangements expose the Company to credit risk from its counterparties. The Company’s accounts receivable are primarily from purchasers of natural gas and oil products. Natural gas sales to one purchaser (ONEOK) accounted for more than 95% of total natural gas and oil revenues for the three months ended June 30, 2006 and 2005. This industry and customer concentration has the potential to impact the Company’s overall exposure to credit risk, either positively or negatively, by changes in economic, industry or other conditions that affect the natural gas and oil industry in general and ONEOK in particular.

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. Investments in unproved reserves and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Abandonment’s of natural gas and oil properties are accounted for as adjustments of capitalized costs; that is, the cost of abandoned properties is charged to the full cost pool and amortized.

Under the full cost method, the net book value of natural gas and oil properties, less related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling is the estimated after-tax future net revenue from proved natural gas and oil properties, discounted at 10% per annum plus the lower of cost or fair market value of unproved properties adjusted for the present value of all future oil and gas hedges. In calculating future net revenues, prices and costs in effect at the time of the calculation are held constant indefinitely, except for changes that are fixed and determinable by existing contracts. The net book value is compared to the ceiling on a quarterly basis. The excess, if any, of the net book value above the ceiling is required to be written off as an expense.

F-5

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2006

(UNAUDITED)

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

Other Property and Equipment

Other property and equipment is reviewed on an annual basis for impairment and as of June 30, 2006, 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	40 years
Buildings	25 years
Equipment	10 years
Vehicles	5 years

During the three months ended June 30, 2006 and 2005, depreciation totaling $1.7 million and $205,000, respectively, was capitalized in the full cost pool. During the six months ended June 30, 2006 and 2005, depreciation totaling $1.9 million and $409,000, respectively, was capitalized in the full cost pool.

Debt Issue Costs

Included in other assets are costs associated with bank credit facilities. The remaining unamortized debt issue costs at June 30, 2006 and December 31, 2005 totaled $6.3 million and $5.8 million, respectively, and are being amortized over the life of the credit facilities.

Other Dispositions

Upon disposition or retirement of property and equipment other than 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, 2006, 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. For the six months ended June 30, 2006, the Company calculated income tax expense of $1.2 million, all of which is offset by our net operating losses, which are carried forward from prior periods, the associated deferred tax asset of which had been subject to a 100% valuation allowance and had not been recognized for financial reporting purposes. Therefore, no income tax expense was recognized for the six months ended June 30, 2006.

F-6

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2006

(UNAUDITED)

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 5 - Earnings Per Share, for a reconciliation of the numerator and denominator of the basic and diluted earnings per share computations.

Reverse Stock Split. In October 2005, the Company’s board of directors approved a 2.5 to 1 reverse stock split, and a proportionate reduction of the authorized number of shares, of the Company’s common stock. In addition, the reverse stock split resulted in a reclassification of amounts from common stock to additional paid-in capital to reflect the adjusted number of shares as the par value of the Company’s common stock remained at $0.001 per share. On October 31, 2005, the reverse stock split became effective. All share and per share data information in this Form 10-Q, and the financial statements included herein, for all periods have been retroactively restated to reflect the reverse stock split.

Change in authorized shares. During the quarter ended June 30, 2006, authorized shares were reduced to 200,000,000 common shares from 380,000,000 common shares.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash, receivables, deposits, hedging 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 hedging 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.

Stock-Based Compensation

Stock Options. In October 2005, the Company granted stock options in the amount of 250,000 shares of its common stock to its five non-employee directors. Prior to 2006, the Company accounted for those options under the recognition and measurement provisions of APB Opinion No. 25, Accounting for Stock Issued to Employees, and related Interpretations. No stock-based employee compensation was reflected in 2005 net income, as all options granted under this plan had an exercise price equal to the market value of the underlying common stock on the date of grant. Effective January 1, 2006, the company adopted the fair value recognition provisions of SFAS 123, Accounting for Stock-Based Compensation, SFAS 123(R), Share-Based Payment and SFAS 148, Accounting for Stock-Based Compensation-Transition and Disclosure.

SFAS 123(R) established standards for the accounting of transactions in which an entity exchanges its equity instruments for goods or services by requiring a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. That cost is recognized over the period during which an employee is required to provide services in exchange for the award. For all unvested options outstanding as of January 1, 2006, the previously measured but unrecognized compensation expense, based on the fair value at the original grant date, will be recognized in our financial statements over the remaining vesting period. For stock options granted or modified subsequent to January 1, 2006, compensation expense, based on the fair value on the date of grant or modification, will be recognized in our financial statements over the vesting period. The fair value of employee stock options is estimated using the Black-Scholes option pricing model. Excess tax benefits are recognized as an addition to paid-in capital. Cash retained as a result of those excess tax benefits is presented in the statement of cash flows as financing cash inflows. The write-off of deferred tax assets relating to unrealized tax benefits associated with recognized compensation cost is recognized as income tax expense unless there are excess tax benefits from previous awards remaining in paid-in capital to which it can be offset.

F-7

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2006

(UNAUDITED)

Under the modified prospective method of adoption selected by the Company under the provision of SFAS 148, compensation cost recognized in 2006 is the same as that which would have been recognized had the recognition provisions of SFAS 123 been applied from its original effective date. Results for prior years have not been restated. For the three and six months ended June 30, 2006 and 2005, we recorded $119,000, $239,000, $0 and $0, respectively, in compensation cost related to the stock options.

Pro forma Disclosures

Prior to January 1, 2006, we accounted for our employee stock options using the intrinsic value method prescribed by APB 25. As required by SFAS 123(R), we have disclosed below the effect on net income and earnings per share that would have been recorded using the fair value based method for the three and six months ended June 30, 2005:

	Three Months Ended June 30,			Six Months Ended June 30,
	2005			2005
Net income (loss), as reported	$	(1,907,000	)	$	(3,005,000	)
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects		—			—
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		—			—
Pro forma net income (loss)	$	(1,907,000	)	$	(3,005,000	)
Earnings (loss) per share:
Basic - as reported	$	(0.30	)	$	(0.50	)
Basic - pro forma	$	(0.30	)	$	(0.50	)
Diluted - as reported	$	(0.30	)	$	(0.50	)
Diluted - pro forma	$	(0.30	)	$	(0.50	)

Stock Awards. The Company granted shares of common stock to certain employees in October 2005. The shares are subject to pro rata vesting which ranges from 0 to 2.5 years. During this vesting period, the fair value of the stock awards granted is recognized pro rata 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. For the three and six months ended June 30, 2006, the Company recognized $188,000 and $375,000 of total compensation expense related to stock awards. Of this amount, $127,000 and $254,000 was reflected in general and administrative expenses as compensation expense with the remaining $61,000 and $121,000 capitalized to oil and gas properties. For the three and six months ended June 30, 2005, the Company recognized no compensation expense related to stock awards.

Accounting for Derivative Contracts and Hedging Activities

The Company seeks to reduce its exposure to unfavorable changes in natural gas prices by utilizing energy swaps, collars and basis swaps (collectively, “fixed-price contracts”). The Company also enters into interest rate swaps and caps to reduce its exposure to adverse interest rate fluctuations. The Company has adopted SFAS 133, as amended by SFAS 138, Accounting for Derivative Instruments and Hedging Activities, which requires that all derivative contracts be recognized as assets or liabilities in the statement of financial position, measured at fair value. The accounting for changes in the fair value of a derivative contract depends on the intended use of the derivative contract and the resulting designation. Designation is established at the inception of a derivative contract, but re-designation is permitted. For derivative contracts designated as cash flow hedges and meeting the effectiveness guidelines of SFAS 133, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings.

F-8

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2006

(UNAUDITED)

Pursuant to the provisions of SFAS 133, all hedging designations and the methodology for determining hedge ineffectiveness must be documented at the inception of the derivative contract, and, upon the initial adoption of the standard, hedging relationships must be designated anew. All changes in fair value of the Company’s interest rate swaps and caps are reported in results of operations rather than in other comprehensive income because the critical terms of the interest rate swaps and caps do not comply with certain requirements set forth in SFAS 133.

Although the Company’s fixed-price contracts and interest rate swaps and caps may not qualify for special hedge accounting treatment from time to time under the specific guidelines of SFAS 133, the Company has continued to refer to these derivative contracts in this document as hedges inasmuch as this was the intent when such derivative contracts were executed, the characterization is consistent with the actual economic performance of the derivative contracts, and the Company expects the derivative contracts to continue to mitigate its commodity price and interest rate risks in the future. The specific accounting for these derivative contracts, however, is consistent with the requirements of SFAS 133. See Note 4 - Financial Instruments and Hedging Activities.

The Company has established the fair value of all derivative contracts using estimates determined by its counterparties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, futures prices, volatility, and time to maturity and credit risk. The values reported in the financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.

Asset Retirement Obligations

The Company has adopted SFAS 143, Accounting for Asset Retirement Obligations, and FIN 47, Accounting for Conditional Asset Retirement Obligations. FIN 47 requires companies to record the fair value of a liability for an asset retirement obligation when it can be reasonably estimated 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 the decommissioning of its pipeline network. The Company is unable to predict if and when its wells and/or pipelines would become completely obsolete and require plugging or decommissioning, as applicable. Accordingly, the Company has recorded no liability or corresponding asset for the wells and pipelines in conjunction with the adoption of SFAS 143 because the future plugging or dismantlement and removal dates of the Company’s assets and the amount of any associated costs are indeterminable.

Reclassification

Certain reclassifications have been made to the prior year’s financial statements in order to conform to the current presentation. The effect of the 2.5 to 1 reverse stock split was rolled back to all prior periods included in these adjusted financial statements.

Recently Issued Accounting Standards

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

In June 2005, the FASB issued FASB Interpretation No. (FIN) 47, Accounting for Conditional Asset Retirement Obligations. FIN 47 specifies the accounting treatment for conditional asset retirement obligations under the provisions of SFAS 143. FIN 47 is effective no later than the end of the fiscal year ending after December 15, 2005. The Company adopted this statement effective December 31, 2005. Implementation of FIN 47 did not have a material effect on our financial statements.

F-9

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2006

(UNAUDITED)

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3. SFAS 154 requires retrospective application to prior period financial statements for changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS 154 also requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. SFAS 154 is effective for accounting changes made in fiscal years beginning after December 15, 2005. The impact of SFAS 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but the Company does not currently expect SFAS 154 to have a material impact on our financial statements.

In September 2005, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty. EITF Issue 04-13 requires that purchases and sales of inventory with the same counterparty in the same line of business should be accounted for as a single non-monetary exchange, if entered into in contemplation of one another. The consensus is effective for inventory arrangements entered into, modified or renewed in interim or annual reporting periods beginning after June 15, 2006. The adoption of EITF Issue 04-13 is not expected to have a material impact on our financial statements.

In July 2006, the FASB issued FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109. FIN 48 provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS 109, Accounting for Income Taxes. FIN 48 prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. FIN 48 is effective for fiscal years beginning after December 15, 2006. We do not expect that FIN 48 will have a material impact on our financial position, results of operations or cash flows.

2. LONG-TERM DEBT

Long-term debt consists of the following:	June 30, 2006		December 31, 2005
Senior credit facilities	$	225,000,000	$	100,000,000
Other notes payable		931,000		988,000

Total long-term debt		225,931,000		100,988,000
Less - current maturities		543,000		407,000

Total long-term debt, net of current maturities	$	225,388,000	$	100,581,000

The aggregate scheduled maturities of notes payable and long-term debt for the five years ending December 31, 2010 and thereafter were as follows as of June 30, 2006:

2006	$	543,000
2007		210,000
2008		63,000
2009		14,000
2010		6,000
Thereafter		225,095,000
	$	225,931,000

Credit Facilities

On June 9, 2006, we and Quest Cherokee entered into a $75 million six-year Third Lien Term Loan Agreement with Guggenheim Corporate Funding, LLC ("Guggenheim"), as administrative agent, and the other lenders that are a party thereto, which was fully funded at the closing.

F-10

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2006

(UNAUDITED)

Interest will accrue on the third lien term loan at LIBOR plus 8.0%. The third lien term loan may not be repaid prior to June 9, 2007. Thereafter, if we prepay the third lien term loan, we will pay a 2% premium in year 2 following the closing and a 1% premium in year 3 following the closing. Thereafter, we may repay the third lien term loan at any time without any premium or prepayment penalty.

Each of our subsidiaries will guarantee all of the obligations under the Third Lien Term Loan Agreement. The third lien term loan is secured by a third priority lien on substantially all of our assets and our subsidiaries' assets. The Third Lien Term Loan Agreement will also secure on a pari passu basis any hedging agreements entered into with lenders or their affiliates and other approved counterparties if the hedging agreements state that they are secured by the security instruments that secure the Third Lien Term Loan Agreement. Approved counterparties are generally entities that have an A rating from Standard & Poor's or an A2 rating from Moody's or whose obligations are guaranteed by an entity with such a rating.

The Third Lien Term Loan Agreement contains representations and warranties and affirmative and negative covenants that are customary for credit agreements of this type and that are substantially similar to those contained in our existing credit facilities. The covenants in the Third Lien Term Loan Agreement include, without limitation, performance of obligations; delivery of financial statements, other financial information, production reports and information regarding swap agreements; delivery of notices of default and other material developments; operation of properties in accordance with industry practice and in compliance with applicable laws; maintenance of satisfactory insurance; compliance with laws; inspection of books and properties; continued perfection of security interests in existing and subsequently acquired collateral; further assurances; payment of taxes; compliance with environmental laws and delivery of notices related thereto; delivery of reserve reports; limitations on dividends and other distributions on, and redemptions and repurchases of, capital stock and other equity interests; limitations on liens; limitations on loans and investments; limitations on debt, guarantees and hedging arrangements; limitations on mergers, acquisitions and asset sales; limitations on transactions with affiliates; limitations on dissolution; limitations on changes in business conducted by us and our subsidiaries; limitations on the right to enter into hedging arrangements; and prohibitions against agreements limiting any subsidiaries' right to pay dividends or make distributions; as well as certain financial covenants.

The financial covenants applicable to the Third Lien Term Loan Agreement require that:

·	our minimum net sales volumes will not be less than:

2,380 mmcf for the quarter ended June 30, 2006;

3,080 mmcf for the quarter ended September 30, 2006; and

3,430 mmcf for the quarter ended December 31, 2006.

·	our ratio of total net debt to EBITDA for each quarter ending on the dates set forth below will not be more than:

4.50 to 1.0 for the quarter ended March 31, 2007;

4.25 to 1.0 for the quarter ended June 30, 2007;

4.00 to 1.0 for the quarter ended September 30, 2007;

3.75 to 1.0 for the quarter ended December 31, 2007;

3.50 to 1.0 for the quarter ended March 31, 2008;

3.25 to 1.0 for the quarter ended June 30, 2008; and

3.00 to 1.0 for any quarter ended on or after September 30, 2008.

·	our ratio of PV-10 value for all our proved reserves to total net debt must not be less than 1.5 to 1.

F-11

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2006

(UNAUDITED)

Under the Third Lien Term Loan Agreement, "PV-10 value" is generally defined as the future cash flows from our proved reserves (based on the NYMEX three-year pricing strip and taking into account the effects of our hedge agreements) discounted at 10%.

EBITDA is generally defined as consolidated net income plus interest, income taxes, depreciation, depletion, amortization and other noncash charges (including unrealized losses on hedging agreements), minus all noncash income (including unrealized gains on hedging agreements). The EBITDA for each quarter will be multiplied by four in calculating the above ratios.

Total net debt is generally defined as funded debt, less cash and cash equivalents, reimbursement obligations under letters of credit and certain surety bonds.

Events of default under the Third Lien Term Loan Agreement are customary for transactions of this type and include, without limitation, non-payment of principal when due, non-payment of interest, fees and other amounts for a period of three business days after the due date, representations and warranties not being correct in any material respect when made, non-performance of covenants after any applicable grace period, certain acts of bankruptcy or insolvency, cross defaults to other material indebtedness and change in control. Under the Third Lien Term Loan Agreement, a change in control will generally be deemed to have occurred if any person or group acquires more than 35% of our outstanding common stock or a majority of our directors have either not been nominated or appointed by our board of directors. If an event of default has occurred and is continuing, the interest rate on the credit agreements will increase by 2.5%.

We and Quest Cherokee are also parties to two other credit agreements totaling $200 million entered into with the closing of the private placement of common stock on November 14, 2005. These credit agreements consist of a $100 million Amended and Restated Senior Credit Agreement between us, Quest Cherokee, Guggenheim, as administrative agent and syndication agent, and the lenders party thereto and a $100 million Second Lien Term Loan Agreement between us, Quest Cherokee, Guggenheim, as administrative agent, and the lenders party thereto. The Senior Credit Agreement consists of a five year $50 million revolving credit facility and a five year $50 million first lien term loan. The first lien term loan was fully drawn as of February 14, 2006. The Second Lien Term Loan Agreement consists of a six year $100 million second lien term loan that was fully funded at the closing.

Availability under the revolving credit facility is tied to a borrowing base that will be redetermined by the lenders every six months. Upon receipt of each semi-annual reserve report, the administrative agent will propose an amount for the borrowing base to the lenders, taking into account the value of our reserves and such other information (including, without limitation, the status of title information with respect to our natural gas and oil properties and the existence of any other indebtedness) as the administrative agent deems appropriate and consistent with its normal oil and gas lending criteria as it exists at the particular time. The unanimous consent of the lenders is required to increase the borrowing base and the consent of 66 2/3% of the lenders is required to decrease or maintain the borrowing base. In addition, we or the lenders may each request a special redetermination of the borrowing base once every 12 months. The outstanding principal balance of the first lien term loan and any outstanding letters of credit will be reserved against the borrowing base in determining availability under the revolving credit facility. As of August 14, 2006, we had no borrowings under our revolving credit facility and we had $10 million of availability under our revolving credit agreement set aside to cover outstanding letters of credit, leaving approximately $40 million of additional availability under our revolving credit agreement. The borrowing base is next scheduled to be redetermined by the lenders on or before October 1, 2006.

We pay a commitment fee equal to 0.75% on the difference between the amount available under the revolving credit facility and the outstanding balance of borrowings and letters of credit under the revolving credit facility.

Interest accrues on the revolving credit facility at either LIBOR plus 1.75% or the base rate plus 0.75%, at our option. Interest accrues on the first lien term loan at either LIBOR plus 3.25% or the base rate plus 2.50%, at our option. Interest accrues on the second lien term loan at LIBOR plus 6.00%.

The second lien term loan may not be repaid prior to November 14, 2006. Thereafter, if we prepay the second lien term loan, we will pay a 3% premium in year 2 following the closing, a 2% premium in year 3 following the closing, and a 1% premium in year 4 following the closing. Thereafter, we may repay the second lien term loan at any time without any premium or prepayment penalty. The revolving credit facility and the first lien term loan may be prepaid, without any premium or penalty, at any time.

F-12

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2006

(UNAUDITED)

In connection with the Third Lien Term Loan Agreement, we amended the Amended and Restated Senior Credit Agreement and amended and restated the Second Lien Term Loan Agreement. These amendments, among other things, permitted us to enter into the Third Lien Term Loan Agreement and reduced the interest rate charged on the second lien term loan from LIBOR plus 6% to LIBOR plus 5.5%.

For the quarter ended June 30, 2006, our weighted average interest rate under our credit facilities was 10.1%.

Other Long-Term Indebtedness

As of June 30, 2006, $931,000 of notes payable to banks and finance companies were outstanding. These notes are secured by equipment and vehicles, with payments due in monthly installments through October 2013 with interest rates ranging from 1.9% to 11.7% per annum.

3. COMMITMENTS AND CONTINGENCIES

The Company and STP Cherokee, Inc. ("STP") have been named defendants in a lawsuit (Case #CJ-2003-30) filed by plaintiffs, Eddie R. Hill et al, on June 27, 2003 in the District Court for Craig County, Oklahoma. Plaintiffs are royalty owners who are alleging underpayment of royalties owed them by STP and the Company. The plaintiffs also allege, among other things, that STP and the Company have engaged in self-dealing, have breached their fiduciary duties to the plaintiffs and have acted fraudulently towards the plaintiffs. The plaintiffs are seeking unspecified actual and punitive damages as a result of the alleged conduct by STP and the Company. The Company intends to defend vigorously against these claims.

Quest Cherokee was named as a defendant in a lawsuit (Case No. 04-C-100-PA) filed by plaintiff Central Natural Resources, Inc. on June 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. 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. The Company 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. Quest Cherokee has asserted third party claims against the persons who entered into the gas leases with Quest Cherokee for breach of the warranty of title contained in their leases in the event that the court finds that plaintiff owns the coal bed methane gas. 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 the Company’s favor. The plaintiff is appealing the summary judgment. The Company intends to defend vigorously against these claims.

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. 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. The Company 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. The Company 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. Based on information available to date and the Company’s investigation into this matter, our belief is that the claims are without merit and we intend to defend against them vigorously.

Quest Cherokee and Quest Cherokee Oilfield Services, LLC were named as defendants in a lawsuit (Case No. 06 CV 28) filed by Robert L. Row and Cathy J. Row in the district court of Wilson County, Kansas. Plaintiffs claim that an oil and gas lease owned by Quest Cherokee covering 1,640 acres of land owned by the plaintiffs in Wilson County, Kansas, has expired by its terms. Plaintiffs seek a judicial decree cancelling that oil and gas lease and quieting their title to the land as against Quest Cherokee, statutory damages, and attorneys fees. Discovery in that case has just commenced and is ongoing. Based on information available to date and the Company’s investigation into this matter, our belief is that the claims are without merit and we intend to defend against them vigorously.

F-13

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2006

(UNAUDITED)

Quest Cherokee was named as a defendant in a lawsuit (Case No. 06 CV 11) filed by C. Wilbur Dyer in the district court of Chautauqua County, Kansas. Plaintiff owns 480 acres of land that was leased to Quest Cherokee. Plaintiff contends that Quest Cherokee failed to comply with the terms of those oil and gas leases and, as a result, those leases have terminated. Plaintiff seeks a judicial decree cancelling those oil and gas leases, statutory penalties, and attorneys fees. Discovery in that case has just commenced and is ongoing. Based on information available to date and the Company’s investigation into this matter, our belief is that the claims are without merit and we intend to defend against them vigorously.

Quest Cherokee was named as a defendant in a lawsuit (Case No. 06 CV 61) filed by Roger Dean Daniels in the district court of Montgomery County, Kansas. Plaintiff owns 260 acres of land that was leased to Quest Cherokee. Plaintiff contends that Quest Cherokee failed to comply with the terms of that oil and gas lease and, as a result, those leases have terminated. Plaintiff seeks a judicial decree cancelling that oil and gas lease, statutory penalties, and attorneys fees. Discovery in that case has just commenced and is ongoing. Based on information available to date and the Company’s investigation into this matter, our belief is that the claims are without merit and we intend to defend against them vigorously.

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.

4. FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

Natural Gas Hedging Activities

The Company seeks to reduce its exposure to unfavorable changes in natural gas prices, which are subject to significant and often volatile fluctuation, through the use of fixed-price contracts. The fixed-price contracts are comprised of energy swaps, collars and basis swaps. These contracts allow the Company to predict with greater certainty the effective natural gas prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. Collar structures provide for participation in price increases and decreases to the extent of the ceiling and floor prices provided in those contracts. For the six months ended June 30, 2006, fixed-price contracts hedged 68.0% of the Company’s natural gas production. As of June 30, 2006, fixed-price contracts were in place to hedge 19.2 Bcf of estimated future natural gas production. Of this total volume, 3.7 Bcf are hedged for 2006 and 15.5 Bcf thereafter. Reference is made to the Annual Report on Form 10-K for the year ended December 31, 2005 for a more detailed discussion of the fixed-price contracts.

The Company has some fixed price contracts that are tied to commodity prices on the New York Mercantile Exchange ("NYMEX"), that is, the Company receives the fixed price amount stated in the contract and pays to its counterparty the current market price for natural gas as listed on the NYMEX. However, due to the geographic location of the Company's natural gas assets and the cost of transporting the natural gas to another market, the amount that the Company receives when it actually sells its natural gas generally 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 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 month index. Recently, the basis differential has been increasingly volatile and has on occasion resulted in the Company receiving a net price for its natural gas that is significantly below the price stated in the fixed price contract.

F-14

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2006

(UNAUDITED)

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, 2006.

	Six Months Ending December 31,			Years Ending December 31,
	2006			2007			2008			Total
	(dollars in thousands, except price data)
Natural Gas Swaps:
Contract vols (MMBtu)		2,830,000			-			-			2,830,000
Weighted-avg fixed
price per MMBtu (1)	$	4.49			-			-		$	4.49
Fixed-price sales	$	12,705			-			-		$	12,705
Fair value, net	$	(6,759	)		-			-		$	(6,759	)

Natural Gas Collars:
Contract vols (MMBtu)
Floor		920,000			8,433,000			7,027,000			16,380,000
Ceiling		920,000			8,433,000			7,027,000			16,380,000
Weighted-avg fixed
price per MMBtu (1)
Floor	$	5.30		$	6.63		$	6.54		$	6.52
Ceiling	$	6.35		$	7.54		$	7.53		$	7.47
Fixed-price sales (2)	$	5,842		$	63,545		$	52,948		$	122 ,335
Fair value, net	$	(1,026	)	$	(10,207	)	$	(7,144	)	$	(18,377	)

Total Natural Gas Contracts(3):
Contract vols (MMBtu)		3,750,000			8,433,000			7,027,000			19,210,000
Weighted-avg fixed
price per MMBtu (1)	$	4.95		$	7.54		$	7.53		$	7.03
Fixed-price sales (2)	$	18,547		$	63,545		$	52,948		$	135,040
Fair value, net	$	(7,785	)	$	(10,207	)	$	(7,144	)	$	(25,136	)

(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 notional volumes by year, as follows: 2006: 3.8 TBtu; 2007: 1.8 TBtu;

2008: 1.5 TBtu

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. See “Fair Value of Financial Instruments”.

All fixed-price contracts have been approved by the Company's board of directors. 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 three months ended June 30, 2006 and 2005, oil and gas sales included $663,000 and $3.2 million, respectively, of losses associated with realized losses under fixed-price contracts. For the six months ended June 30, 2006 and 2005, oil and gas sales included $663,000 and $5.4 million, respectively, of 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 other revenue and expense in the period for which the underlying production was hedged. For the three months ended June 30, 2006 and 2005, other revenue and expense included $2.8 million and $0, respectively, of losses associated with realized losses under fixed-price contracts. For the six months ended June 30, 2006 and 2005, other revenue and expense included $10.2 million and $0, respectively, of losses associated with realized losses under fixed-price contracts.

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.

F-15

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2006

(UNAUDITED)

Other comprehensive losses are limited to the portion of the cumulative gain or loss on the derivative necessary to offset the cumulative change in expected future cash flows on the hedged transaction from inception of the hedge less the derivatives gains or losses previously reclassified from accumulated other comprehensive income into earnings. This limitation resulted in a $8.9 million charge against the ineffective portion of hedging gains incurred during the quarter.

Based upon market prices at June 30, 2006, the estimated amount of unrealized losses 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 $13.2 million.

Interest Rate Hedging Activities

The Company has entered into interest rate caps designed to hedge the interest rate exposure associated with borrowings under its credit facilities. All interest rate caps have been approved by the Company's board of directors. The differential between the fixed rate and the floating rate multiplied by the notional amount is the cap gain or loss. This gain or loss is included in interest expense in the period for which the interest rate exposure was hedged.

For interest rate caps qualifying as cash flow hedges, changes in fair value of the derivative contracts are shown as adjustments to other comprehensive income. For those interest rate caps not qualifying as cash flow hedges, changes in fair value of the derivative contracts are recognized in change in derivative fair value in the statement of operations. All changes in fair value of the Company’s interest rate caps are reported in results of operations rather than in other comprehensive income because the critical terms of the interest rate caps do not comply with certain requirements set forth in SFAS 133. The fair value of all interest rate caps are recorded as assets or liabilities in the balance sheet. Based upon market prices at June 30, 2006, the estimated amount of unrealized gains for interest rate caps shown as adjustments to change in derivative fair value in the statement of operations that are expected to be reclassified into earnings as actual contract cash settlements are realized within the next 12 months is $479,000.

At June 30, 2006, the Company had outstanding the following interest rate caps:

Instrument Type	Term	Notional Amount (1)		Fixed Rate / Cap Rate		Floating Rate	Fair Value as of June 30, 2006
		$	98,705,000			3-month
Interest Rate Cap	July 2006 - Sept. 2007	$	70,174,600	5.000	%	LIBOR	$	573,000

(1) Represents the maximum and minimum notional amounts that are hedged during the period.

Change in Derivative Fair Value

Change in derivative fair value in the statements of operations for the three and six months ended June 30, 2006 and 2005 is comprised of the following:

F-16

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2006

(UNAUDITED)

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2006		2005			2006		2005
Change in fair value of derivatives not qualifying as cash flow hedges	$	1,260,000	$	355,000		$	14,630,000	$	(183,000	)
Amortization of derivative fair value gains and losses recognized in earnings prior to actual cash settlements		—		(38,000	)		—		148,000
Ineffective portion of derivatives qualifying as cash flow hedges		1,123,000		557,000			2,234,000		1,353,000

	$	2,383,000	$	874,000		$	16,864,000	$	1,318,000

The amounts recorded in change in derivative fair value do not represent cash gains or losses. Rather, they are temporary valuation swings in the fair value of the contracts. All amounts initially recorded in this caption are ultimately reversed within this same caption over the respective contract terms.

The change in carrying value of fixed-price contracts and interest rate caps in the balance sheet since December 31, 2005 resulted from a decrease in market prices for natural gas and an increase in interest rates.

Fair Value of Financial Instruments

The following information is provided regarding the estimated fair value of the financial instruments, including derivative assets and liabilities as defined by SFAS 133 that the Company held as of June 30, 2006 and December 31, 2005 and the methods and assumptions used to estimate their fair value:

	June 30, 2006			December 31, 2005
Derivative assets:
Interest rate caps	$	573,000		$	188,000
Fixed-price natural gas collars	$	2,636,000		$	—
Natural gas basis swaps	$	161,000		$	—
Derivative liabilities:
Fixed-price natural gas swaps	$	(6,759,000	)	$	(31,185,000	)
Fixed-price natural gas collars	$	(21,013,000	)	$	(30,733,000	)
Natural gas basis swaps	$	(18,000	)	$	—
Bank debt	$	(225,000,000	)	$	(100,000,000	)
Other financing agreements	$	(931,000	)	$	(988,000	)

The carrying amount of cash, receivables, deposits, accounts payable and accrued expenses approximates fair value due to the short maturity of those instruments. The carrying amounts for notes payable approximate fair value due to the variable nature of the interest rates of the notes payable.

The fair value of all derivative contracts as of June 30, 2006 and December 31, 2005 was based upon estimates determined by our counter-parties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, futures prices, volatility, and time to maturity and credit risk. The values reported in the financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.

Derivative assets and liabilities reflected as current in the June 30, 2006 balance sheet represent the estimated fair value of fixed-price contract and interest rate cap settlements scheduled to occur over the subsequent twelve-month period based on market prices for natural gas and fluctuations in interest rates as of the balance sheet date. The offsetting increase in value of the hedged future production has not been accrued in the accompanying balance sheet. The contract settlement amounts are not due and payable until the monthly period that the related underlying hedged transaction occurs. In some cases the recorded liability for certain contracts significantly exceeds the total settlement amounts that would be paid to a counterparty based on prices in effect at the balance sheet date due to option time value. Since the Company expects to hold these contracts to maturity, this time value component has no direct relationship to actual future contract settlements and consequently does not represent a liability that will be settled in cash or realized in any way.

F-17

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2006

(UNAUDITED)

Credit Risk

Energy swaps, collars and basis swaps and interest rate caps provide for a net settlement due to or from the respective party as discussed previously. The counterparties to the derivative contracts are a financial institution and a major energy corporation. 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 production to market prices, which, in a low price environment, could have an adverse effect on its future operating results. Cancellation or termination of an interest rate cap would subject a greater portion of the Company’s long-term debt to market interest rates, which, in an inflationary environment, could have an adverse effect on its future net income. 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 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. The effective price realizations that result from the fixed-price contracts are affected by movements in basis. 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. The Company actively manages its exposure to basis movements and from time to time will enter into contracts designed to reduce such exposure.

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 are expected to be offset by changes in the price received for hedged natural gas production.

5. 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 months ended June 30, 2006, dilutive shares do not include the assumed exercise of stock options and stock awards (convertible into 81,000 and 12,000 common shares, respectively) because the effects were antidilutive.

·	For the three and six months ended June 30, 2005, dilutive shares do not include the assumed conversion of the outstanding 10% Series A preferred stock (convertible into 16,000 common shares) because the effects were antidilutive.

·	For the three and six months ended June 30, 2005, dilutive shares do not include the assumed conversion of convertible debt (convertible into 2,000 and 3,000 common shares, respectively) because the effects were antidilutive.

F-18

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2006

(UNAUDITED)

The following reconciles the components of the EPS computation:

	Income (Numerator)			Shares (Denominator)		Per Share Amount
For the three months ended June 30, 2006:
Net income	$	(5,780,000	)
Preferred stock dividends		—
Basic EPS available to common shareholders	$	(5,780,000	)		22,074,631	$	(0.26	)
Effect of dilutive securities:
Stock options		—			—
Stock awards		—			—

Diluted EPS available to common shareholders	$	(5,780,000	)		22,074,631	$	(0.26	)

For the three months ended June 30, 2005:
Net loss	$	(1,907,000	)
Preferred stock dividends		(3,000	)
Basic EPS loss available to common shareholders	$	(1,910,000	)		6,339,552	$	(0.30	)
Effect of dilutive securities:
None		—			—

Diluted EPS loss available to common shareholders	$	(1,910,000	)		6,339,552	$	(0.30	)

For the six months ended June 30, 2006:
Net income	$	2,937,000
Preferred stock dividends		—
Basic EPS available to common shareholders	$	2,937,000			22,073,513	$	0.13
Effect of dilutive securities:
Stock options		—			52,103
Stock awards		—			8,540

Diluted EPS available to common shareholders	$	2,937,000			22,134,156	$	0.13

For the six months ended June 30, 2005:
Net loss	$	(3,005,000	)
Preferred stock dividends		(5,000	)
Basic EPS loss available to common shareholders	$	(3,010,000	)		6,021,482	$	(0.50	)
Effect of dilutive securities:
None		—			—

Diluted EPS loss available to common shareholders	$	(3,010,000	)		6,021,482	$	(0.50	)

6. 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, 2006 and 2005:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Asset retirement obligation beginning balance	$	1,210,000		$	938,000		$	1,150,000		$	871,000
Liabilities incurred		44,000			57,000			84,000			113,000
Liabilities settled		(2,000	)		(1,000	)		(3,000	)		(3,000	)
Accretion expense		23,000			17,000			44,000			30,000
Revisions in estimated cash flows		—			—			—			—
Asset retirment obligation ending balance	$	1,275,000		$	1,011,000		$	1,275,000		$	1,011,000

F-19

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

This quarterly report contains forward-looking statements. For this purpose, any statements contained herein that are not statements of historical fact may be deemed to be forward-looking statements. These statements relate to future events or to our future financial performance. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms or other comparable terminology. These statements are only predictions. Actual events or results may differ materially. There are a number of factors that could cause our actual results to differ materially from those indicated by such forward-looking statements. See Item 1A—"Risk Factors" in our annual report on Form 10-K for the year ended December 31, 2005 for a discussion of some of these factors.

Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance, or achievements. Moreover, we do not assume responsibility for the accuracy and completeness of such forward-looking statements. We are under no duty to update any of the forward-looking statements after the date of this report to conform such statements to actual results.

Business of Issuer

We are an independent energy company with an emphasis on the acquisition, exploration, development and production of natural gas (coal bed methane) in a ten county region in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma. We also own and operate a gas gathering pipeline network of approximately 1,300 miles in length within this basin. Our main focus is upon the development of our coal bed methane gas reserves in our pipeline network region and upon the continued enhancement of the pipeline system and supporting infrastructure. Unless otherwise indicated, references to “us”, “we”, the “Company” or “Quest” include our operating subsidiaries.

Significant Developments During the Three and the Six Months Ended June 30, 2006

During the second quarter of 2006, we have continued to be focused on drilling and completing new wells. We drilled 189 gross wells and completed the connection of 178 gross wells to our gas gathering system during this period. For the six months ended June 30, 2006, we drilled 372 gross wells and completed the connection of 329 gross wells to our gas gathering system. As of June 30, 2006, we had 98 additional gas wells (gross) that we were in the process of completing and connecting to our gas gathering system.

We also continued our program of re-completing our existing single seam wells into multi-seam wells (that is, opening up production of additional gas from different depths), which management anticipates will in the long term increase overall natural gas production. However, the re-completion program may in the short term negatively affect natural gas production as natural gas wells are taken off line for the re-completions and then undergo a period of "dewatering" after they are re-connected. During the first quarter, 39 wells were re-completed and during the second quarter, 44 wells were re-completed and production from these wells has increased by approximately 14% during the six months ended June 30, 2006, and we anticipate additional volumes from these wells after dewatering of the newly opened producing zones is completed.

We are also evaluating 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.

On June 30, 2006, our gross daily production, including third parties, was 47.5 Mmcfe/d.

Results of Operations

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 annual report on Form 10-K for the year ended December 31, 2005. Comparisons made between reporting periods herein are for the three and six month periods ended June 30, 2006 as compared to the same periods in 2005.

Three Months Ended June 30, 2006 Compared to Three Months Ended June 30, 2005

Total revenues of $13.7 million for the quarter ended June 30, 2006 represent an increase of approximately 6% when compared to total revenues of $13.0 million for the quarter ended June 30, 2005. The quarter ended June 30, 2006 includes a $3.5 million loss on settlements of gas hedges. Of these settlements, $2.8 million were recorded as other expense due to the contracts not qualifying for hedge accounting treatment during the quarter. Excluding these settlements, total revenues for the second quarter of 2006 were $17.2 million. Excluding the settlements on gas hedges, the increase in revenue for the quarter ended June 30, 2006 was achieved by a combination of the addition of more producing wells, which was partially offset by the natural decline in production from some of our older gas wells and lower natural gas prices.

-4-

The increase in oil and gas sales from $12.1 million for the quarter ended June 30, 2005 to $15.3 million for the quarter ended June 30, 2006 was primarily attributable to the classification of the hedge settlements discussed above. The remainder of the increase in oil and gas sales and the increase in gas pipeline revenue from $901,000 to $1.3 million resulted from the additional wells and pipelines acquired or completed during the past 12 months, which was partially offset by the natural decline in production from some of our older gas wells and lower natural gas prices. The additional wells contributed to the production of 2,889,000 mcf of net gas for the quarter ended June 30, 2006, as compared to 2,393,000 net mcf produced in the same quarter last year. Our product prices on an equivalent basis (mcfe) decreased from $6.39 mcfe average for the quarter ended June 30, 2005 to $5.57 mcfe average for the quarter ended June 30, 2006. For the quarter ended June 30, 2006, the net product price, after accounting for hedge settlements of $3.5 million during the quarter, averaged $4.33 mcfe. For the quarter ended June 30, 2005, the net product price, after accounting for hedging settlement of $3.2 million during the quarter, averaged $5.06 mcfe.

Other expense for the three months ended June 30, 2006 was $2.9 million as compared to other income of $2,000 for the three-month period ended June 30, 2005. Other expense for the three months ended June 30, 2006 was the result of a reclassification from gas sales of cash settlements for contracts that did not qualify as cash flow hedges for the quarter.

The oil and gas production costs increased to $4.6 million for the quarter ended June 30, 2006 as compared to the operating costs of $3.0 million incurred for the quarter ended June 30, 2005. Lease operating costs per mcf for the quarter ended June 30, 2006 increased to $1.26 per mcf as compared to $0.81 per mcf for the quarter ended June 30, 2005. Pipeline operating costs increased by approximately 53% from $2.0 million for the quarter ended June 30, 2005 to $3.1 million for the quarter ended June 30, 2006. The lease operating cost per mcf increased due to: an increase in the size of the field labor force, as a result of our increased development program; an increase in wage rates; an increase in well repairs, utilities, and fuel costs due to the increase in the number of wells being operated and an increase in energy and raw material costs; and an increase in property taxes due to both the increase in the number of properties that we own and an increase in property tax rates. Additionally, approximately $260,000 was recorded in the second quarter for the shares of common stock representing the Company's contribution to its profit sharing plan. The cost increases incurred for pipeline operations are due to the number of wells completed and operated during the quarter, the increased miles of pipeline and compression in service and increased property taxes due to both the increased miles of pipeline and an increase in property tax rates. For the quarter ended June 30, 2006, depreciation, depletion and amortization increased to $6.9 million as compared to $3.9 million for the quarter ended June 30, 2005. The increase in depreciation, depletion and amortization is a result of the increased number of producing wells and miles of pipelines acquired and developed and the higher volumes of gas and oil produced and the resulting increased depletion rate and development costs.

General and administrative expenses increased from $1.0 million for the quarter ended June 30, 2005 to $2.4 million for the quarter ended June 30, 2006. This increase resulted from a non-cash charge of approximately $400,000 for amortization of equity compensation awards and an accrual of paid time off costs. The remainder of the increase is due to the increased size and complexity of our operations and an increase in legal, accounting and professional fees related to our preparation for our first audit of our internal control over financial reporting that is required by the Sarbanes-Oxley Act in connection with the audit of our 2006 financial statements.

Interest expense decreased to $5.1 million for the quarter ended June 30, 2006 from $5.9 million for the quarter ended June 30, 2005, due to lower average interest rates as a result of the successful completion of a private offering of equity in November 2005 and a new credit facility affording us improved interest rates on our borrowings, which was partially offset by higher average outstanding borrowings.

Change in derivative fair value was a non-cash gain of $2.4 million for the three months ended June 30, 2006, which included a $1.3 million gain 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 $1.1 million relating to hedge ineffectiveness. Change in derivative fair value was a non-cash gain of $874,000 for the three months ended June 30, 2005, which included a $355,000 gain attributable to the change in fair value for certain derivative contracts that did not qualify as cash flow hedges pursuant to SFAS 133, a $38,000 net loss attributable to the reversal of contract fair value gains and losses recognized in earnings prior to actual settlement, and a gain of $557,000 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.

-5-

We recorded a net loss of $5.8 million for the quarter ended June 30, 2006 as compared to a net loss of $1.9 million for the quarter ended June 30, 2005, each period inclusive of the non-cash net gain or loss derived from the change in derivative fair value as stated above.

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005

Total revenues of $25.8 million for the six months ended June 30, 2006 represent an increase of approximately 3% when compared to total revenues of $25.1 million for the six months ended June 30, 2005. The six months ended June 30, 2006 includes a $10.9 million loss on settlements of gas hedges. Of these settlements, $10.2 million was recorded as other expense due to the contracts not qualifying for hedge accounting treatment during the six months. Excluding these settlements, total revenues for the first six months of 2006 were $36.7 million. Total revenues for the six months ended June 30, 2005 include a $5.4 million loss on settlements of gas hedges. The settlements were recorded against gas sales as those hedge contracts did qualify for hedge accounting treatment during the six months. Excluding this loss, total revenues for the first six months of 2005 were $30.5 million. Excluding the settlements on gas hedges, the increase in revenue for the six months ended June 30, 2006 was achieved by a combination of the addition of more producing wells and slightly higher natural gas prices which was partially offset by the natural decline in production from some of our older gas wells.

The increase in oil and gas sales from $23.4 million for the six months ended June 30, 2005 to $33.8 million for the six months ended June 30, 2006 was primarily attributable to the classification of the hedge settlements discussed above. The remainder of the increase in oil and gas sales and the increase in gas pipeline revenue from $1.7 million to $2.4 million resulted from the additional wells and pipelines acquired or completed during the past 12 months and higher natural gas prices, which was partially offset by the natural decline in production from some of our older gas wells. The additional wells contributed to the production of 5,387,000 mcf of net gas for the six months ended June 30, 2006, as compared to 4,574,000 net mcf produced in the same six months last year. Our product prices on an equivalent basis (mcfe) increased from $6.29 mcfe average for the six months ended June 30, 2005 to $6.40 mcfe average for the six months ended June 30, 2006. For the six months ended June 30, 2006, the net product price, after accounting for hedge settlements of $10.9 million during the six months, averaged $4.37 mcfe. For the six months ended June 30, 2005, the net product price, after accounting for hedging settlement of $5.4 million during the six months, averaged $5.11 mcfe.

Other expense for the six months ended June 30, 2006 was $10.3 million as compared to other expense of $19,000 for the six-month period ended June 30, 2005. Other expense for the six months ended June 30, 2006 was the result of a reclassification from gas sales of cash settlements for derivative contracts that did not qualify as cash flow hedges for the six months.

The oil and gas production costs increased to $8.6 million for the six months ended June 30, 2006 as compared to the operating costs of $5.3 million incurred for the six months ended June 30, 2005. Lease operating costs per mcf for the six months ended June 30, 2006 increased to $1.18 per mcf as compared to $0.78 per mcf for the six months ended June 30, 2005. Pipeline operating costs increased by approximately 57% from $3.8 million for the six months ended June 30, 2005 to $5.9 million for the six months ended June 30, 2006. The lease operating cost per mcf increased due to: an increase in the size of the field labor force, as a result of our increased development program; an increase in wage rates; an increase in well repairs, utilities, and fuel costs due to the increase in the number of wells being operated and an increase in energy and raw material costs; and an increase in property taxes due to both the increase in the number of properties that we own and an increase in property tax rates. Additionally, approximately $260,000 was recorded in the six months for the shares of common stock representing the Company's contribution to its profit sharing plan. The cost increases incurred for pipeline operations are due to the number of wells acquired, completed and operated during the six months, the increased miles of pipeline and compression in service and increased property taxes due to both the increased miles of pipeline and an increase in property tax rates. For the six months ended June 30, 2006, depreciation, depletion and amortization increased to $12.8 million as compared to $7.2 million for the six months ended June 30, 2005. The increase in depreciation, depletion and amortization is a result of the increased number of producing wells and miles of pipelines acquired and developed and the higher volumes of gas and oil produced and the resulting increased depletion rate and development costs.

General and administrative expenses increased from $2.0 million for the six months ended June 30, 2005 to $3.9 million for the six months ended June 30, 2006. This increase resulted from a non-cash charge of approximately $646,000 for amortization of stock awards and an accrual of paid time off costs. The remainder of the increase is due to the increased size and complexity of our operations and to an increase in legal, accounting and professional fees related to our preparation for our first audit of our internal control over financial reporting that is required by the Sarbanes-Oxley Act in connection with the audit of our 2006 financial statements.

-6-

Interest expense decreased to $8.9 million for the six months ended June 30, 2006 from $11.1 million for the six months ended June 30, 2005, due to lower average interest rates as a result of the successful completion of a private offering of equity in November 2005 and a new credit facility affording us improved interest rates on our borrowings, which was partially offset by higher average outstanding borrowings.

Change in derivative fair value was a non-cash gain of $16.9 million for the six months ended June 30, 2006, which included a $14.7 million gain 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 $2.2 million relating to hedge ineffectiveness. Change in derivative fair value was a non-cash gain of $1.3 million for the six months ended June 30, 2005, which included a $183,000 loss attributable to the change in fair value for certain derivative contracts that did not qualify as cash flow hedges pursuant to SFAS 133, a $148,000 net gain attributable to the reversal of contract fair value gains and losses recognized in earnings prior to actual settlement, and a gain of $1.4 million 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.

We recorded net income of $2.9 million for the six months ended June 30, 2006 as compared to a net loss of $3.0 million for the six months ended June 30, 2005, each period inclusive of the non-cash net gain or loss derived from the change in derivative fair value as stated above.

Liquidity and Capital Resources

At June 30, 2006, we had current assets of $51.2 million, working capital (current assets minus current liabilities, excluding the short-term derivative assets and liabilities) of $24.5 million and had $13.3 million of net cash provided by operations during the six months ended June 30, 2006. At June 30, 2006, our working capital (including the short-term derivative assets and liabilities) totals $11.7 million.

During the six months ended June 30, 2006, a total of approximately $103.9 million was invested in new natural gas wells and properties, new pipeline facilities, and other additional capital items. This investment was funded by cash flow from operations and borrowings under our credit facilities.

Net cash provided by operating activities totaled $13.3 million for the six months ended June 30, 2006 as compared to net cash provided by operating activities of $5.5 million for the six months ended June 30, 2005. This resulted from the change in derivative fair value, an increase in restricted cash and accounts receivable and an increase in accounts payable.

Our working capital (current assets minus current liabilities, excluding the short-term derivative asset and liability of $1.1 million and $13.9 million, respectively) was $24.5 million at June 30, 2006, compared to working capital (excluding the short-term derivative asset and liability of $95,000 and $38.2 million, respectively) of $3.1 million at December 31, 2005. The changes in working capital were primarily due to the net effect of an increase in cash of $32.8 million, representing borrowings under our credit facilities; an increase of $1.0 million in inventory due to purchases of poly pipe due to a tightness in the market place; a decrease in revenue payable of $2.0 million resulting from lower product prices; an increase in accounts payable of $7.4 million due to the expansion of our wells and pipeline development program; an increase of $1.6 million in accrued expenses; and a decrease of $2.8 million in accounts receivable.

On June 9, 2006, we and Quest Cherokee entered into a $75 million six-year Third Lien Term Loan Agreement with, Guggenheim Corporate Funding, LLC ("Guggenheim"), as administrative agent, and the other lenders that are a party thereto, which was fully funded at the closing.

Each of our subsidiaries will guarantee all of the obligations under the Third Lien Term Loan Agreement. The third lien term loan is secured by a third priority lien on substantially all of our assets and our subsidiaries' assets. The Third Lien Term Loan Agreement will also secure on a pari passu basis any hedging agreements entered into with lenders, their affiliates and other approved counterparties if the hedging agreements state that they are secured by the security instruments that secure the Third Lien Term Loan Agreement. Approved counterparties are generally entities that have an A rating from Standard & Poor's or an A2 rating from Moody's or whose obligations are guaranteed by an entity with such a rating.

-7-

See Note 2 to the consolidated financial statements included elsewhere in this report for a more detailed description of the terms of the credit agreements. As of August 14, 2006, we had no borrowings under our revolving credit facility and we had $10 million of availability under our revolving credit agreement set aside to cover outstanding letters of credit, leaving approximately $40 million of additional availability under our revolving credit agreement.

Our initial target for 2006 was to drill, complete and connect up to 600 additional new wells. Due to the increased level of activity over our initial targets, we are experiencing increased costs for labor, raw materials, fuel and supplies, which are currently running approximately 19% over our initial budgeted amounts. At present, our cash flow from operations is limited due to the decreases in the existing natural gas product price environment and due to the negative effects from our existing hedging agreements. We believe that cash on hand, expected cash flow from operations and our borrowing available under the revolving credit facility will provide sufficient capital from our second half of 2006 development program to drill, complete and connect between 550 to 600 wells during 2006.

We also currently intend to drill approximately 800 wells per year for each of 2007 and 2008. Management currently estimates that it will require over the next three years a capital investment of approximately $150 million per year for drilling and developing these wells and related salt water disposal wells, pipeline expansion to connect the new wells to our existing gas gathering pipeline network, leasing of additional acreage, expenditures for our re-completion program and additions to our rolling stock inventory. We intend to finance capital expenditures during 2007 and 2008 utilizing a combination of cash flow from operations, additional borrowings, the sale of equity and possibly strategic transactions. Although we believe that we will have adequate additional reserves and other resources to support future development plans, no assurance can be given that we will be able to obtain funding sufficient to support all of our development plans or that such funding will be on terms favorable to us.

Contractual Obligations

Future payments due on our contractual obligations as of June 30, 2006 are as follows:

	Total		2006		2007-2008		2009-2010		thereafter
Second Lien Term Note	$	100,000,000	$	—	$	—	$	—	$	100,000,000
Third Lien Term Note		75,000,000		—		—		—		75,000,000
First Lien Term Note		50,000,000		—		—		50,000,000		—
Notes payable		931,000		543,000		273,000		20,000		95,000
Lease obligations		384,000		140,000		244,000		—		—
Derivatives		27,790,000		13,868,000		13,922,000		—		—
Total	$	254,105,000	$	14,551,000	$	14,439,000	$	50,020,000	$	175,095,000

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 described in Note 1 to the consolidated financial statements.

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Off-Balance Sheet Arrangements

At June 30, 2006 and December 31, 2005, 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.

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, 2005, in Item 7A of our 2005 Form 10-K report. For more information on our risk management activities, see Note 4 to our consolidated financial statements included elsewhere in this report.

Item 4. Controls and Procedures

As of June 30, 2006, our management, including the Chief Executive Officer and the Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. Based upon and as of the date of the evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective in all material respects to provide reasonable assurance that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and 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.

It should be noted, however, that no matter how well designed and operated, a control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events. Because of these and other inherent limitations of control systems (including faulty judgments in decision making or breakdowns resulting from simple errors or mistakes), there can be no assurance that any design will succeed in achieving its stated goals under all potential conditions. Additionally, controls can be circumvented by individual acts, collusion or by management override of the controls in place.

There has been no change in our internal control over financial reporting during the quarter ended June 30, 2006 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 3 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

There have been no material changes to the risk factors disclosed in Item 1A “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2005.

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

None

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Item 3. Default Upon Senior Securities

None

Item 4. Submission of Matters to Vote of Security Holders

Our 2006 Annual Meeting of Stockholders was held on May 31, 2006, at which time a vote was taken to elect our directors and implement classification of our board of directors. The stockholders elected the following directors to the following classes:

Director	Director Class	Term Expiring In	Votes For	Votes Withheld
Jerry D. Cash	III	2009	14,424,547	21,420
James B. Kite, Jr.	III	2009	14,433,487	12,480
Kevin R. White	II	2008	14,433,047	12,920
Ronnie K. Irani	II	2008	14,169,803	276,164
John C. Garrison	I	2007	14,159,708	286,259
Jon H. Rateau	I	2007	14,169,808	276,159

The stockholders also voted to amend our Restated Articles of Incorporation to decrease the number of shares of common stock we may issue from 380,000,000 to 200,000,000 as follows:

Votes For		Votes Against		Votes Abstained		Broker Non-Votes
14,431,289		13,493		1,185		0

The stockholders also voted to approve the 2005 Omnibus Stock Award Plan, which provides for grants of non-qualified stock options, restricted shares, bonus shares, deferred shares, stock appreciation rights, performance units, performance shares and incentive stock options to our key employees and non-employee directors, as follows:

Votes For		Votes Against		Votes Abstained		Broker Non-Votes
10,811,782		1,039,657		1,143		2,593,085

The stockholders also voted to approve the Management Annual Incentive Plan, which qualifies bonuses paid to our executive officers and key employees to be fully tax-deductible to us under the Internal Revenue Code, as follows:

Votes For		Votes Against		Votes Abstained		Broker Non-Votes
11,065,507		785,391		1,984		2,593,085

Item 5. Other Information

None

Item 6. Exhibits

3.1*		The Company’s Restated Articles of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Registration Statement on Form 8-A12G/A (Amendment No. 2) filed on December 7, 2005).

3.2*		Certificate of Designations for Series B Junior Participating Preferred Stock (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 1, 2006).

3.3*		Amendment to the Company’s Restated Articles of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 6, 2006).

4.1*		Rights Agreement dated as of May 31, 2006, between Quest Resource Corporation and UMB Bank, n.a., which includes as Exhibit A, the Certificate of Designations Preferences and Rights of Series B Preferred Stock, as Exhibit B, the Form of Rights Certificate, and as Exhibit C, the Summary of Rights to Purchase Preferred Stock (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on June 1, 2006).

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4.2*		Amendment No. 1 to Amended and Restated Senior Credit Agreement by and among Quest Resource Corporation, Quest Cherokee, LLC, Guggenheim Corporate Funding, LLC, and the Lenders party thereto, dated as of the 9th day of June, 2006 (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on June 14, 2006).

4.3*		Amended and Restated Second Lien Term Loan Agreement by and among Quest Cherokee, LLC, Quest Resource Corporation, Guggenheim Corporate Funding, LLC, and the Lenders party thereto, dated as of the 9th day of June, 2006 (incorporated herein by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on June 14, 2006).

4.4*		Amended and Restated Security Agreement for the Amended and Restated Second Lien Term Loan Agreement by and among Quest Cherokee, LLC, Quest Resource Corporation, and the Guarantors party thereto in favor of Guggenheim Corporate Funding, LLC, dated as of the 9th day of June, 2006 (incorporated herein by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on June 14, 2006).

4.5*		Reaffirmation of Guaranty for Amended and Restated Second Lien Term Loan Agreement by Bluestem Pipeline, LLC, J-W Gas Gathering, L.L.C., Ponderosa Gas Pipeline Company, Inc., Producers Service Incorporated, Quest Cherokee Oilfield Service, LLC, Quest Energy Service, Inc., Quest Oil & Gas Corporation, and STP Cherokee, Inc. in favor of Guggenheim Corporate Funding, LLC, dated as of the 9th day of June, 2006 (incorporated herein by reference to Exhibit 4.4 to the Company’s Current Report on Form 8-K filed on June 14, 2006).

4.6*		Third Lien Term Loan Agreement by and among Quest Cherokee, LLC, Quest Resource Corporation, Guggenheim Corporate Funding, and the Lenders party thereto, dated as of the 9th day of June, 2006 (incorporated herein by reference to Exhibit 4.5 to the Company’s Current Report on Form 8-K filed on June 14, 2006).

4.7*		Security Agreement for Third Lien Term Loan Agreement by Quest Cherokee, LLC, Quest Resource Corporation, and the Guarantors party thereto in favor of Guggenheim Corporate Funding, LLC, dated as of the 9th day of June, 2006 (incorporated herein by reference to Exhibit 4.6 to the Company’s Current Report on Form 8-K filed on June 14, 2006).

4.8*		Guaranty for Third Lien Term Loan Agreement by Bluestem Pipeline, LLC, J-W Gas Gathering, L.L.C., Ponderosa Gas Pipeline Company, Inc., Producers Service Incorporated, Quest Cherokee Oilfield Service, LLC, Quest Energy Service, Inc., Quest Oil & Gas Corporation, and STP Cherokee, Inc. in favor of Guggenheim Corporate Funding, LLC, dated as of the 9th day of June, 2006 (incorporated herein by reference to Exhibit 4.7 to the Company’s Current Report on Form 8-K filed on June 14, 2006).

4.9*		Second Amended and Restated Intercreditor Agreement by and among Quest Resource Corporation, Quest Cherokee, LLC, STP Cherokee, Inc., Quest Oil & Gas Corporation, Quest Energy Service, Inc., Ponderosa Gas Pipeline Company, Inc., Producers Service Incorporated, J-W Gas Gathering, L.L.C., Bluestem Pipeline, LLC Quest Cherokee Oilfield Service, LLC, and Guggenheim Corporate Funding, LLC, dated as of the 9th day of June, 2006 (incorporated herein by reference to Exhibit 4.8 to the Company’s Current Report on Form 8-K filed on June 14, 2006).

12.1		Statement Re: Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Dividends.

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

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

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

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

* Incorporated by reference.

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SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized this 14th day of August, 2006.


	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

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

9520 N. May Avenue, Suite 300, Oklahoma City, OK	73120
(Address of principal executive offices)	(Zip Code)