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

o Transition report under Section 13 or 15(d) of the Securities Exchange Act of 1934

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [XX] No o

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

As of May 2, 2007, the issuer had 22,222,474 shares of common stock outstanding.

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 Midstream Partners, L.P.; Quest Midstream GP, LLC; Quest Oil & Gas, LLC; Ponderosa Gas Pipeline Company, LLC; Quest Energy Service, LLC; STP Cherokee, LLC; Producers Service, LLC; 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, LLC.

Our unaudited interim financial statements, including a balance sheet as of March 31, 2007, a statement of operations and a statement of cash flows for the three month period ended March 31, 2007 and the comparable period of 2006, 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 the Company’s annual report on Form 10-K/A for the year ended December 31, 2006.

ASSETS
	March 31, 2007			December 31, 2006
	(unaudited)
	($ in thousands)
Current assets:
Cash	$	29,566		$	21,378
Restricted cash		1,181			21,592
Accounts receivable, trade		11,899			9,840
Other receivables		1,415			371
Other current assets		2,020			1,068
Inventory		5,008			5,632
Short-term derivative asset		2,781			10,795
Total current assets		53,870			70,676

Property and equipment, net of accumulated depreciation of $5,315 and $5,107		18,389			16,212

Pipeline assets, net of accumulated depreciation of $7,230 and $6,104		133,391			127,690
Pipeline assets under construction		880			880

Oil and gas properties:
Properties being amortized		335,067			316,780
Properties not being amortized		13,032			9,545
		348,099			326,325
Less: Accumulated depreciation, depletion and amortization		(99,399	)		(92,732	)
Net property, plant and equipment		248,700			233,593
Other assets, net		10,046			9,467
Long-term derivative asset		2,695			4,782
Total assets	$	467,971		$	463,300

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	19,945		$	14,778
Revenue payable		6,440			4,540
Accrued expenses		2,196			2,525
Current portion of notes payable		228			324
Short-term derivative liability		10,457			5,244
Total current liabilities		39,266			27,411

Non-current liabilities:
Long-term derivative liability		6,078			7,449
Asset retirement obligation		1,477			1,410
Notes payable		235,348			225,569
Less current maturities		(228	)		(324	)
Non-current liabilities		242,675			234,104
Minority interest in QMLP		85,284			84,431
Total liabilities		367,225			345,946
Commitments and contingencies		—			—
Stockholders’ equity:
10% convertible preferred stock, $.001 par value, 50,000,000 shares authorized, 0 shares issued and outstanding at March 31, 2007 and December 31, 2006		—			—
Common stock, $.001 par value, 200,000,000 shares authorized, 22,206,014 shares issued and outstanding at March 31, 2007 and December 31, 2006		22			22
Additional paid-in capital		206,179			205,994
Accumulated other comprehensive income		(13,053	)		428
Accumulated deficit		(92,402	)		(89,090	)
Total stockholders’ equity		100,746			117,354
Total liabilities and stockholders’ equity	$	467,971		$	463,300

	Three months ended March 31,
	2007			2006

Revenue:
Oil and gas sales	$	25,549		$	18,479
Gas pipeline revenue		1,542			1,082
Other revenue (expense)		(13	)		(7,441	)
Total revenues		27,078			12,120

Costs and expenses:
Oil and gas production		7,227			3,928
Pipeline operating		4,934			2,869
General and administrative		2,638			1,522
Depreciation, depletion and amortization		7,863			5,899
Total costs and expenses		22,662			14,218

Operating income (loss)		4,416			(2,098	)

Other income (expense):
Change in derivative fair value		(464	)		14,481
Sale of assets		107			20
Interest income		177			136
Interest expense		(7,113	)		(3,822	)
Total other income (expense)		(7,293	)		10,815

Income (loss) before income taxes		(2,877	)		8,717
Income tax expense – deferred		—			—
Net income (loss) before minority interest		(2,877	)		8,717
Minority interest in continuing operations of QMLP		(434	)		—
Net income (loss)		(3,311	)		8,717

Other comprehensive income (loss), net of tax:
Change in fixed-price contract and other derivative fair value, net of tax of $0 and $0		(12,486	)		2,659
Reclassification adjustments – contract settlements, net of tax of $0 and $0		(995	)		7,404
Other comprehensive income (loss)		(13,481	)		10,063
Comprehensive income (loss)	$	(16,792	)	$	18,780

Net income (loss)	$	(3,311	)	$	8,717
Preferred stock dividends		—			—
Net income (loss) available to common shareholders	$	(3,311	)	$	8,717

Earnings (loss) per common share – basic	$	(0.15	)	$	.39

Earnings (loss) per common share – diluted	$	(0.15	)	$	.39

Weighted average common and common equivalent shares:
Basic		22,206,014			22,072,383
Diluted		22,206,014			22,140,654

	Three months ended March 31,
	2007			2006
	($ in thousands)
Cash flows from operating activities:
Net income (loss)	$	(3,311	)	$	8,717
Adjustments to reconcile net income (loss) to cash provided by operations:
Depreciation and depletion		8,528			6,104
Change in derivative fair value		464			(14,481	)
Stock options granted for directors fees		162			119
Stock awards granted to employees		326			127
Amortization of loan origination fees		479			266
Amortization of gas swap fees		62			21
Amortization of deferred hedging gains		—			(412	)
(Gain) loss on sale of assets		(65	)		(20	)
Minority interest		434			—
Change in assets and liabilities:
Restricted cash		20,411			2,945
Accounts receivable		(2,059	)		2,159
Other receivables		(1,044	)		(16	)
Other current assets		(951	)		271
Inventory		624			(1,478	)
Accounts payable		5,163			10,501
Revenue payable		1,900			(1,618	)
Accrued expenses		(329	)		1,022
Net cash provided by (used in) operating activities		30,794			14,227

Cash flows from investing activities:
Equipment, development and leasehold costs		(28,472	)		(45,962	)
Net additions to other property and equipment		(3,941	)		(3,926	)
Net cash used in investing activities		(32,413	)		(49,888	)

Cash flows from financing activities:
Proceeds from bank borrowings		10,000			50,000
Repayments of note borrowings		(222	)		(129	)
Syndication costs paid		(11	)		(219	)
Change in other long-term liabilities		40			—
Net cash provided by financing activities		9,807			49,652

Net increase (decrease) in cash		8,188			13,991
Cash, beginning of period		21,378			2,559
Cash, end of period	$	29,566		$	16,550

Supplemental disclosure of cash flow information
Cash paid during the period for:
Interest expense	$	5,845		$	2,941
Income taxes	$	—		$	—

Quest Resource Corporation (the “Company”) is an independent energy company with an emphasis on the acquisition, production, transportation, exploration, and development of natural gas (coal bed methane) in the Cherokee Basin in southeastern Kansas and northeastern Oklahoma.

All of the Company’s natural gas and oil wells and natural gas and oil leasehold interests are owned by Quest Cherokee, with the exception of some immaterial oil and gas properties owned by STP that are located outside of the Cherokee Basin in Oklahoma and Texas. The membership interests of Quest Cherokee are owned by QES, QOG, PGPC, STP, PSI and J-W Gas. QES, QOG, PGPC and STP are wholly-owned by the Company. PGPC is the sole member of PSI and PSI is the sole member of J-W Gas.

Quest Cherokee is the sole member of QCOS. QCOS owns all of the Company’s oilfield service equipment and vehicles and employs all of the Company’s field level employees and first line supervisors that work on the Company’s natural gas and oil wells.

QES employs all of the Company’s non-field employees that work on the Company’s natural gas and oil wells. QES and STP own certain equipment used at the corporate headquarters offices.

Our natural gas gathering pipeline network is owned by Bluestem. Bluestem is wholly owned by Quest Midstream. We own an approximate 49% limited partner interest in Quest Midstream (consisting of 4.9 million class B subordinated units and 35,134 class A subordinated units) and 85% of the member interests in Quest Midstream GP. Quest Midstream GP, the sole general partner of Quest Midstream, owns 200,000 General Partner Units representing a 2% general partner interest in Quest Midstream. Quest Midstream GP’s sole business activity is to act as the general partner of Quest Midstream and employs approximately 46 personnel that perform activities primarily related to the pipeline infrastructure.

Consolidation Policy. Investee companies in which the Company directly or indirectly owns more than 50% of the outstanding voting securities or those in which the Company has effective control over are generally accounted for under the consolidation method of accounting. Under this method, an Investee company’s balance sheet and results of operations are reflected within the Company’s Consolidated Financial Statements. All significant intercompany accounts and transactions have been eliminated. Minority interests in the net assets and earnings or losses of a consolidated Investee are reflected in the caption “Minority interest” in the Company’s Consolidated Balance Sheet and Statement of Operations. Minority interest adjusts the Company’s consolidated results of operations to reflect only the Company’s share of the earnings or losses of the consolidated Investee company. Upon dilution of control below 50%, the accounting method is adjusted to the equity or cost method of accounting, as appropriate, for subsequent periods.

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

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.

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

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.

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

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, 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.

A significant portion of the Company’s liquidity is concentrated in cash and derivative contracts that enable the Company to hedge a portion of its exposure to price volatility from producing natural gas and oil. These 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 two purchasers, ONEOK and Tenaska accounted for approximately 73% and 27%, respectively of our natural gas and oil revenues for the three months ended March 31, 2007. ONEOK accounted for approximately 95% of our natural gas and oil revenues for the three months ended March 31, 2006. The industry concentration has the potential to impact the Company’s overall exposure to credit risk, either positively or negatively, in that the Company’s customers may be similarly affected by changes in economic, industry or other conditions.

The Company 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. Abandonments 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 of accounting, a ceiling test is performed each quarter. Pursuant to this test, 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.

As of December 31, 2006, the Company’s net book value of oil and gas properties exceeded the ceiling. Accordingly, a provision for impairment was recognized in the fourth quarter of 2006 of $30.7 million. The provision for impairment was primarily attributable to declines in the prevailing market prices of oil and gas at the measurement date.

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 is reviewed on an annual basis for impairment and as of December 31, 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.

Included in other assets are costs associated with bank credit facilities. The remaining unamortized debt issue costs at March 31, 2007 and December 31, 2006 totaled $9.7 million and $9.1 million, respectively, and are being amortized over the life of the credit facilities.

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.

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

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.

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.

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 Awards. The Company granted shares of common stock to certain employees in the first quarter of 2007, October, November and December, 2006 and in October 2005. The shares are subject to pro rata vesting which ranges from 0 to 4 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.

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

The Company seeks to reduce its exposure to unfavorable changes in natural gas prices by utilizing energy swaps and collars (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 contains accounting and reporting guidelines for derivative instruments and hedging activities. It requires that all derivative instruments 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 depends

on the intended use of the derivative and the resulting designation. Designation is established at the inception of a derivative, but re-designation is permitted. For derivatives 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.

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 hedge, and, upon the initial adoption of the standard, hedging relationships must be designated anew. Based on the interpretation of these guidelines by the Company, the changes in fair value of all of its derivatives during the period from June 1, 2003 to December 22, 2003 were required to be reported in results of operations, rather than in other comprehensive income. Also, 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 contracts in this document as hedges inasmuch as this was the intent when such contracts were executed, the characterization is consistent with the actual economic performance of the contracts, and the Company expects the contracts to continue to mitigate its commodity price and interest rate risks in the future. The specific accounting for these 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 instruments 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.

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

The Company’s asset retirement obligations relate to the plugging and abandonment of natural gas and oil properties. The Company is unable to predict if and when its pipelines would become completely obsolete and require decommissioning. Accordingly, the Company has recorded no liability or corresponding asset for the pipelines in conjunction with the adoption of SFAS 143 because the future dismantlement and removal dates of the Company’s assets and the amount of any associated costs are indeterminable.

Certain reclassifications have been made to the prior year’s financial statements in order to conform to the current presentation.

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 2006, the FASB issued Interpretation 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”), an interpretation of FASB Statement No. 109,”Accounting for Income Taxes.” FIN 48 clarifies the accounting and reporting for income taxes where interpretation of the law is uncertain. FIN 48 prescribes a comprehensive model for the financial statement recognition, measurement, presentation and disclosure of income tax uncertainties with respect to positions taken or expected to be taken in income tax returns. FIN 48 is effective for fiscal years beginning after December 15, 2006 and has no current applicability to the Company’s financial statements.

In September 2006, the FASB issued Statement No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 addresses how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under generally accepted accounting principles. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands the required disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, with earlier adoption permitted. Management is assessing the impact of the adoption of SFAS No. 157.

In September 2006, the FASB issued Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (“SFAS No. 158”), an amendment of FASB Statements No. 87, 88, 106 and 132(R). SFAS No. 158 requires (a) recognition of the funded status (measured as the difference between the fair value of the plan assets and the benefit obligation) of a benefit plan as an asset or liability in the employer’s statement of financial position, (b) measurement of the funded status as of the employer’s fiscal year-end with limited exceptions, and (c) recognition of changes in the funded status in the year in which the changes occur through comprehensive income. The requirement to recognize the funded status of a benefit plan and the disclosure requirements are effective as of the end of the fiscal year ending after December 15, 2006. The requirement to measure the plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. SFAS No. 158 has no current applicability to the Company’s financial statements.

In September 2006, the Securities Exchange Commission issued Staff Accounting Bulletin No. 108 (“SAB No. 108”). SAB No. 108 addresses how the effects of prior year uncorrected misstatements should be considered when quantifying misstatements in current year financial statements. SAB No. 108 requires companies to quantify misstatements using a balance sheet and income statement approach and to evaluate whether either approach results in quantifying an error that is material in light of relevant quantitative and qualitative factors. When the effect of initial adoption is material, companies will record the effect as a cumulative effect adjustment to beginning of year retained earnings and disclose the nature and amount of each individual error being corrected in the cumulative adjustment.

In February 2007, the FASB issued Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”), an amendment of FASB Statement No. 115. SFAS No. 159 addresses how companies should measure many financial instruments and certain other items at fair value. The objective is to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007, with earlier adoption permitted. Management is assessing the impact of the adoption of SFAS No. 159.

	March 31, 2007		December 31, 2006
	(dollars in thousands)
Senior credit facilities – Quest	$	225,000	$	225,000
Senior credit facilities – Quest Midstream		10,000		--

Notes payable to banks and finance companies, secured by equipment and vehicles, due in installments through October 2013 with interest ranging from 5.5% to 11.5% per annum		348		569

Total long-term debt		235,348		225,569

Less – current maturities		228		324

Total long term debt, net of current maturities	$	235,120	$	225,245

The aggregate scheduled maturities of notes payable and long-term debt for the five years ending December 31, 2012 and thereafter were as follows as of March 31, 2007:

As of March 31, 2007, the Company’s credit facilities consisted of a $100 million Senior Credit Agreement between the Company and Quest Cherokee, Guggenheim Corporate Funding, LLC (“Guggenheim”), as administrative agent and syndication agent, and the lenders party thereto, a $100 million Second Lien Term Loan Agreement between the Company, Quest Cherokee, Guggenheim, as Administrative Agent, and the lenders party thereto and a $75 million Third Lien Term Loan Agreement between the Company, 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.

Availability under the revolving credit facility is tied to a borrowing base that will be re-determined by the lenders every six months taking into account the value of the Company’s reserves and such other information (including, without limitation, the status of title information with respect to the Company’s 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, the Company or the lenders may each request a special re-determination 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 March 31, 2007, the borrowing base under the revolving credit facility was $100 million.

The Company pays a commitment fee equal to 0.75% on the difference between $50 million and the outstanding balance of borrowings and letters of credit under the revolving credit facility.

Interest accrues on the revolving credit facility at LIBOR plus 1.75% or the base rate plus 0.75%, at our option. Interest accrues on the first lien term loan at 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 5.50%. Interest accrues on the third lien term loan at LIBOR plus 8.00%. For the three months ended March 31, 2007, the Company’s weighted average interest rate under the credit facilities was approximately 11%.

Under all three credit agreements “PV-10 value” is generally defined as the future cash flows from the Company’s proved reserves (based on the NYMEX three-year pricing strip and taking into account the effects of its hedge agreements) discounted at 10%.

EBITDA is generally defined in all three of the credit agreements as consolidated net income plus interest, income taxes, depreciation, depletion, amortization and other non-cash charges (including unrealized losses on hedging agreements), plus costs and expenses directly incurred in connection with the credit agreements, the private equity transaction and the buy-out of ArcLight’s investment in Quest Cherokee and any write-off of prior debt issue costs, minus all non-cash 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.

For additional information regarding the Company’s credit facilities, see Note 3 to the consolidated financial statements included in the Company’s Form 10-K/A for the year ended December 31, 2006.

On January 31, 2007, Quest Midstream and Bluestem entered into a new credit agreement consisting of a five-year $75 million revolving credit facility. The credit agreement is among Bluestem, as the borrower, Quest Midstream, as a guarantor, Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto.

Bluestem may, from time to time, request an increase in the $75 million commitment by an amount in the aggregate not exceeding $50 million. However, the lenders are under no obligation to increase the revolving credit facility upon such request.

Bluestem pays a quarterly commitment fee equal to 0.30% to 0.50% (depending on the leverage ratio) on the difference between $75 million and the outstanding balance of borrowings and letters of credit under the revolving credit facility.

In general, interest accrues on the revolving credit facility at either LIBOR plus a margin ranging from 1.25% to 2.00% (depending on the leverage ratio) or the base rate plus a margin ranging from 0.25% to 1.00% (depending on the leverage ratio), at our option. The revolving credit facility may be prepaid, without any premium or penalty, at any time.

Quest Midstream has guaranteed all of Bluestem’s obligations under the credit agreement. The revolving credit facility is secured by a first priority lien on substantially all of the assets of Quest Midstream and Bluestem.

The credit agreement provides that any amounts owing under any hedging agreement entered into with lenders or their affiliates will rank pari passu in right of payment with the obligations under the credit agreement and will be secured by the liens granted under the loan documents.

Bluestem, Quest Midstream and their subsidiaries are required to make certain representations and warranties that are customary for credit agreements of this type. The credit agreement also contains affirmative and negative covenants that are customary for credit agreements of this type. The covenants in the credit agreement include, without limitation, delivery of financial statements and other financial information; notice of defaults and certain other matters; payment of obligations; preservation of legal existence and good standing; maintenance of assets and business; maintenance of insurance; compliance with laws and contractual obligations; maintenance of books and records; permit inspection rights; use of proceeds; execution of guaranties by subsidiaries; perfecting security interests in after-acquired property; maintenance of fiscal year; limitations on liens; limitations on investments; limitation on hedging agreements; limitations on indebtedness; limitations on lease obligations; limitations on fundamental changes; limitations on dispositions of assets; limitations on restricted payments, distributions and redemptions; limitations on nature of business, capital expenditures and risk management; limitations on transactions with affiliates; limitations on burdensome agreements; and compliance with financial covenants.

The credit agreement’s financial covenants prohibit Bluestem, Quest Midstream and any of their subsidiaries from:

Consolidated EBITDA is defined in the credit agreement to mean for Quest Midstream and its subsidiaries on a consolidated basis, an amount equal to the sum of (i) consolidated net income, (ii) consolidated interest charges, (iii) the amount of taxes, based on or measured by income, used or included in the determination of such consolidated net income, (iv) the amount of depreciation, depletion and amortization expense deducted in determining such consolidated net income, and (v) other non-cash charges and expenses, including, without limitation, non-cash charges and expenses related to swap contracts or resulting from accounting convention changes, of Quest Midstream and its subsidiaries on a consolidated basis, all determined in accordance with generally accepted accounting principles.

Consolidated interest charges is defined to mean for Quest Midstream and its subsidiaries on a consolidated basis, the sum of (i) all interest, premium payments, fees, charges and related expenses of Quest Midstream and its subsidiaries in connection with indebtedness (net of interest rate swap contract settlements) (including capitalized interest), in each case to the extent treated as interest in accordance with generally accepted accounting principles, and (ii) the portion of rent expense of Quest Midstream and its subsidiaries with respect to any period under capital leases that is treated as interest in accordance with generally accepted accounting principles.

Consolidated net income is defined to mean for Quest Midstream and its subsidiaries on a consolidated basis, the net income or net loss of Quest Midstream and its subsidiaries from continuing operations, excluding: (i) the income (or loss) of any entity other than a subsidiary, except to the extent that any such income has been actually received by Quest Midstream or such subsidiary in the form of cash dividends or similar cash distributions; (ii) extraordinary gains and losses; (iii) any gains or losses attributable to non-cash write-ups or write-downs of assets; (iv) proceeds of any insurance on property, plant or equipment other than business interruption insurance; (v) any gain or loss, net of taxes, on the sale, retirement or other disposition of assets; and (vi) the cumulative effect of a change in accounting principles.

The credit agreement contains some “phase-in” provisions with respect to the calculation of the financial covenants during 2007.

Bluestem is required during each calendar year to have at least 15 consecutive days during which there are no revolving loans outstanding for the purpose of financing working capital or funding quarterly distributions of Quest Midstream.

Events of default under the credit 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, failure to perform or observe covenants and agreements (subject to a 30-day cure period in certain cases), representations and warranties not being correct in any material respect when made, certain acts of bankruptcy or insolvency, cross defaults to other material indebtedness, and change of control. Under the credit agreement a change of control means (i) we fail to own or to have voting control over, at least 51% of the equity interest of Quest Midstream GP, LLC, Quest Midstream’s general partner; (ii) any person acquires beneficial ownership of 51% or more of the equity interest in Quest Midstream; (iii) Quest Midstream fails to own 100% of the equity interests in Bluestem or (iv) we undergo a change in control (the acquisition by a person, or two or more persons acting in concert, of beneficial ownership of 50% or more of our outstanding shares of voting stock, except for a merger with and into another entity where the other entity is the survivor if our stockholders of record immediately preceding the merger hold more than 50% of the outstanding shares of the surviving entity).

$348,000 of notes payable to banks and finance companies were outstanding at March 31, 2007 and are secured by equipment and vehicles, with payments due in monthly installments through October 2013 with interest ranging from 5.5% to 11.5% per annum.

Quest Cherokee, LLC (“Quest Cherokee”), STP Cherokee, Inc. (“STP”), and Bluestem Pipeline, LLC (“Bluestem”) were originally named defendants in a lawsuit (Case #CJ-2003-30) filed by plaintiffs, Eddie R. Hill, et al, on September 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 Quest Cherokee. Bluestem owns the gathering system that is used to gather gas from the

wells in issue. The plaintiffs also allege, among other things, that STP and Quest Cherokee have engaged in self-dealing, have breached their fiduciary duties to the plaintiffs and have acted fraudulently towards the plaintiffs. Plaintiffs also allege that the gathering fees and related charges imposed by Bluestem should not be deducted by STP and Quest Cherokee in paying royalties. In March 2007, plaintiffs filed an amended petition that added 20 additional plaintiffs and Quest Midstream Partners, L.P., Quest Energy Service, Inc., and Quest Midstream GP, LLC as defendants. The plaintiffs are seeking unspecified actual and punitive damages as a result of the alleged conduct by the defendants. The defendants intend to defend vigorously against these claims.

STP, Inc., STP Cherokee, LLC, Quest Cherokee, LLC, Quest Energy Service, LLC and Bluestem have been named defendants in a lawsuit (Case No. CJ-2005-143) by plaintiffs John C. Kirkpatrick, et ux., in the District Court for Craig County, Oklahoma. Plaintiffs have requested an accounting to determine if royalties have been properly paid and stated, that if plaintiffs have suffered any damages for failure to properly pay royalties, plaintiffs have a right to recover those damages and have asserted a claim of fraud. Discovery is ongoing and defendants are vigorously contesting the plaintiffs’ claims. Plaintiffs have not quantified their alleged damages. The defendants intend to defend vigorously against these claims.

Quest Cherokee and Bluestem were named as defendants in a lawsuit (Case No. 04-C-100-PA) filed by plaintiff Central Natural Resources, Inc. on September 1, 2004 in the District Court of Labette County, Kansas. Central Natural Resources owns the coal underlying numerous tracts of land in Labette County, Kansas. Quest Cherokee has obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying some of that land and has drilled wells that produce coal bed methane gas on that land. Plaintiff alleges that it is entitled to the coal bed methane gas produced and revenues from these leases and that Quest Cherokee is a trespasser. Plaintiff is seeking quiet title and an equitable accounting for the revenues from the coal bed methane gas produced. Plaintiff has alleged conversion of the gas and seeks an accounting for all gas produced from the wells in issue. Quest Cherokee contends it has valid leases with the owners of the coal bed methane gas rights. The issue is whether the coal bed methane gas is owned by the owner of the coal rights or by the owners of the gas rights. If Quest Cherokee prevails on that issue, then the plaintiff’s claims fail. All issues relating to ownership of the coal bed methane gas and damages have been bifurcated. Cross motions for summary judgment on the ownership of the coal bed methane were filed by Quest Cherokee and the plaintiff, with summary judgment being awarded in Quest Cherokee’s favor. The plaintiff has appealed the summary judgment and that appeal is pending. Quest Cherokee and Bluestem intend to defend vigorously against these claims.

Quest Cherokee was named as a defendant in a lawsuit (Case No. CJ-06-07) filed by plaintiff Central Natural Resources, Inc. on January 17, 2006, in the District Court of Craig County, Oklahoma. Bluestem is not a party to this lawsuit. Central Natural Resources owns the coal underlying approximately 2,250 acres of land in Craig County, Oklahoma. Quest Cherokee has obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying those lands, and has drilled and completed 20 wells that produce coal bed methane gas on those lands. Plaintiff alleges that it is entitled to the coal bed methane gas produced and revenues from these leases and that Quest Cherokee is a trespasser. Plaintiff seeks to quiet its alleged title to the coal bed methane and an accounting of the revenues from the coal bed methane gas produced by Quest Cherokee. Quest Cherokee contends it has valid leases from the owners of the coal bed methane gas rights. The issue is whether the coal bed methane gas is owned by the owner of the coal rights or by the owners of the gas rights. Quest Cherokee has answered the petition and discovery is ongoing. Quest Cherokee intends to defend vigorously against these claims.

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

Quest Energy Service, Inc. (“QES”) was named as a defendant in a lawsuit (Case No. 2006 CV 103) filed by Western Uniform and Towel Service, Inc. in the district court of Neosho County, Kansas. Plaintiff contends that QES has failed to pay for goods and services provided by the Plaintiff, and that QES wrongfully terminated certain contracts with the plaintiff to provide uniforms and merchandise to QES. Plaintiff has claimed total damages of $520,982.19, which includes $75,170.66 for services and materials provided to QES, $56,448.70 for lost goods and buy back charges, and $389,096.67 in liquidated damages. Discovery in that case is ongoing. QES intends to defend vigorously against plaintiff’s claims.

Bluestem and Quest Cherokee were named as defendants in a lawsuit (Case No. CJ-2007-325) filed by Permian Land Company (“Permian”) in the district court of Oklahoma County, Oklahoma. Permian is currently asserting a claim against Bluestem in the amount of $120,823.35 and a claim against Quest Cherokee in the amount of $243,422.73 for land

services allegedly rendered to Bluestem and to Quest Cherokee by Permian and for which no payment has been received by Permian. Quest Cherokee and Bluestem have asserted counterclaims against Permian for breach of contract and negligence, among other theories, due to Permian’s failure to file acquired instruments of record and deliver such records to Quest Cherokee and Bluestem, which has caused Quest Cherokee and Bluestem to incur unnecessary costs to re-acquire such instruments. In addition, Permian failed to ascertain whether or not minerals were leased or otherwise burdened and acquired oil and gas leases for Quest Cherokee and Bluestem, which were, in fact, burdened, causing Quest Cherokee and Bluestem to incur thousands of dollars in curative costs to acquire title to such minerals. Further, without approval, Permian inserted non-standard construction completion penalty provisions into said rights-of-way and easements, forcing Quest Cherokee and Bluestem to incur thousands of dollars in damages resulting from the unauthorized construction penalty provisions. Finally, Plaintiff has failed to return confidential information to Quest Cherokee and Bluestem pursuant to the parties’ written confidentiality and non-disclosure agreement. Quest Cherokee and Bluestem seek an undetermined amount of damages, injunctive relief, and an accounting to determine whether and to what extent Permian charged excessive fees for purported services it provided. Discovery in that case is ongoing. Quest Cherokee and Bluestem intend to defend vigorously against Permian’s claims.

Quest Cherokee is a defendant in several lawsuits in which the plaintiffs allege that certain of the oil and gas leases owned by Quest Cherokee are either invalid, have expired by their terms and/or have been forfeited by Quest Cherokee. The plaintiffs in those cases are generally seeking statutory damages of $100 per lease, attorneys fees, and a judicial declaration that Quest Cherokee’s leases have terminated. As of May 8, 2007, the total amount of acreage covered by the leases at issue in these lawsuits was approximately 7,000 acres. Quest Cherokee contends that it has complied with the terms of these oil and gas leases and that they remain in full force and effect. Quest Cherokee intends to vigorously defend against the claims.

Quest Cherokee was named in an Order to Show Cause issued by the Kansas Corporation Commission (the “KCC”) (KCC Docket No. 07-CONS-155-CSHO) filed on February 23, 2007. The KCC has ordered Quest Cherokee to demonstrate why it should not be held responsible for plugging 22 abandoned and unplugged oil wells on a gas lease owned and operated by Quest Cherokee in Wilson County, Kansas. Quest Cherokee denies that it is legally responsible for plugging the wells in issue and intends to vigorously defend against the KCC’s claims. This matter is set for hearing on July 19, 2007.

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.

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 and collars. 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 three months ended March 31, 2007 and 2006, fixed-price contracts hedged approximately 71.6% and 73.0%, respectively, of the Company’s natural gas production. As of March 31, 2007, fixed-price contracts are in place to hedge 17.5 Bcf of estimated future natural gas production. Of this total volume, 8.1 Bcf are hedged for 2007 and 9.4 Bcf thereafter.

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

The following table summarizes the estimated volumes, fixed prices, fixed-price sales and fair value attributable to the fixed-price contracts as of March 31, 2007.

	Nine Months Ending December 31,			Year Ending December 31,
	2007			2008			Total
	(dollars in thousands, except price data)
Natural Gas Swaps:
Contract vols (MMBtu)		1,774,000			2,332,000			4,106,000
Weighted-avg fixed
price per MMBtu (1)	$	7.20		$	7.35		$	7.29
Fixed-price sales	$	12,769		$	17,141		$	29,910
Fair value, net	$	(906	)	$	36		$	(870	)

Natural Gas Collars:
Contract vols (MMBtu):
Floor		6,354,000			7,027,000			13,381,000
Ceiling		6,354,000			7,027,000			13,381,000
Weighted-avg fixed
price per MMBtu (1):
Floor	$	6.63		$	6.54		$	6.58
Ceiling	$	7.54		$	7.53		$	7.53
Fixed-price sales (2)	$	42,109		$	45,973		$	88,082
Fair value, net	$	(6,744	)	$	(3,390	)	$	(10,134	)

Total Natural Gas Contracts:
Contract vols (MMBtu)		8,128,000			9,359,000			17,487,000
Weighted-avg fixed
price per MMBtu (1)	$	6.75		$	6.74		$	6.75
Fixed-price sales (2)	$	54,878		$	63,114		$	117,992
Fair value, net	$	(7,650	)	$	(3,354	)	$	(11,004	)

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.

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 March 31, 2007 and 2006, oil and gas sales included $996,000 and $0, respectively, of net losses associated with realized losses under fixed-price contracts.

For contracts that did not qualify as cash flow hedges, the realized contract profit and loss is included in other revenue and expense in the period for which the underlying production was hedged. For the three months ended March 31, 2007 and 2006, other revenue and expense included $0 and $7.4 million, respectively, of net 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.

Based upon market prices at March 31, 2007, the estimated amount of unrealized gains for fixed-price contracts shown as adjustments to other comprehensive income that are expected to be reclassified into earnings as actual contract cash settlements are realized within the next 12 months is $7.7 million.

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 excess, if any, of the floating rate over the interest rate cap multiplied by the notional amount is the cap gain. This gain 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 instruments 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 instruments are recognized in change in derivative fair value in the statement of operations. 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. The fair value of all interest rate swaps and caps are recorded as assets or liabilities in the balance sheet. Based upon market prices at March 31, 2007, 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 10 months is $122,000.

The following table summarizes the notional amounts, interest rates and the fair value attributable to the interest rate caps as of March 31, 2007 (dollars in thousands).

Change in derivative fair value in the statements of operations for the three months ended March 31, 2007 and 2006 are comprised of the following:

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.

Energy swaps and collars and interest rate swaps and caps provide for a net settlement due to or from the respective party as discussed previously. The counterparties to the derivative contracts are a financial institution and a major energy

corporation. Should a counterparty default on a contract, there can be no assurance that we 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 swap or 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.

The differential between the floating price paid under each energy swap or collar contract and the price received at the wellhead for our production is termed “basis” and is the result of differences in location, quality, contract terms, timing and other variables. For instance, some of our fixed price contracts are tied to commodity prices on the New York Mercantile Exchange (“NYMEX”), that is, we receive the fixed price amount stated in the contract and pay to our counterparty the current market price for gas as listed on the NYMEX. However, due to the geographic location of our natural gas assets and the cost of transporting the natural gas to another market, the amount that we receive when we actually sell our natural gas is based on the Southern Star Central TX/KS/OK (“Southern Star”) first of month index, with a small portion being sold based on the daily price on the Southern Star index. The difference between natural gas prices on the NYMEX and the price actually received by the Company is referred to as a basis differential. Typically, the price for natural gas on the Southern Star first of the month index is less than the price on the NYMEX due to the more limited demand for natural gas on the Southern Star first of the month index. Recently, the basis differential has been increasingly volatile and has on occasion resulted in us receiving a net price for our natural gas that is significantly below the price stated in the fixed price contract.

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

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

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 March 31, 2007 and December 31, 2006 and the methods and assumptions used to estimate their fair value:

	March 31, 2007						December 31, 2006
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
	(dollars in thousands)
Derivative assets:
Interest rate swaps and caps	$	122		$	122		$	197		$	197
Basis swaps	$	90		$	90		$	62		$	62
Fixed-price natural gas swaps	$	36		$	36		$	2,207		$	2,207
Fixed-price natural gas collars	$	5,228		$	5,228		$	13,111		$	13,111
Derivative liabilities:
Basis swaps	$	(267	)	$	(267	)	$	377		$	377
Fixed-price natural gas swaps	$	(906	)	$	(906	)	$	—		$	—
Fixed-price natural gas collars	$	(15,362	)	$	(15,362	)	$	(12,316	)	$	(12,316	)
Credit facilities	$	(235,000	)	$	(235,000	)	$	(225,000	)	$	(225,000	)
Other financing agreements	$	(348	)	$	(348	)	$	(569	)	$	(569	)

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 instruments as of March 31, 2007 and December 31, 2006 was based upon estimates determined by the Company’s 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.

Derivative assets and liabilities reflected as current in the March 31, 2007 and December 31, 2006 balance sheets 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, creating the appearance of a working capital deficit from these contracts. 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 and interest rates 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.

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.

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

	Income			Shares	Per Share
	(Numerator)			(Denominator)	Amount
For the three months ended March 31, 2007:
Net income (loss)	$	(3,311	)
Preferred stock dividends		—
Basic EPS available to common shareholders	$	(3,311	)	22,206,014	$	(0.15	)
Effect of dilutive securities:
None		—		—
Diluted EPS available to common shareholders	$	(3,311	)	22,206,014	$	(0.15	)

For the three months ended March 31, 2006:
Net income	$	8,717
Preferred stock dividends		—
Basic EPS available to common shareholders	$	8,717		22,072,383	$	0.39
Effect of dilutive securities:
Stock options		—		64,786
Stock awards		—		3,485

Diluted EPS available to common shareholders	$	8,717		22,140,654	$	0.39

The Company has adopted SFAS 143, Accounting for Asset Retirement Obligations. The following table provides a roll forward of the asset retirement obligations for the three months ended March 31, 2007 and 2006:

The common unit holders in Quest Midstream have the right to receive quarterly distributions of available cash from operating surplus (each as defined in the Quest Midstream partnership agreement) in an amount equal to the minimum quarterly distribution of $0.425 per common unit plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. No arrearages will be paid on the subordinated units during the subordination period.

If the tests for ending the subordination period are satisfied for any three consecutive four-quarter periods ending on or after the last day of the quarter containing the third anniversary of the initial public offering of Quest Midstream, 25% of the subordinated units will convert into an equal number of common units. Similarly, if those tests are also satisfied for any three consecutive four-quarter periods ending on or after the last day of the quarter containing the fourth anniversary of the initial public offering of Quest Midstream, an additional 25% of the subordinated units will convert into an equal number of common units. The second early conversion of subordinated units may not occur, however, until at least one year following the end of the period for the first early conversion of subordinated units.

The Quest Midstream partnership agreement sets forth the levels of distributions to be made to each of the common unit holders and Quest Midstream GP of available cash from operating surplus for any quarter during and after the subordination period. The partnership agreement provides that Quest Midstream GP initially will be entitled to 2% of all distributions that Quest Midstream makes prior to its liquidation. Quest Midstream GP has the right, but not the obligation, to contribute a proportionate amount of capital to Quest Midstream to maintain its 2% general partner interest if Quest Midstream issues additional units. Quest Midstream GP’s 2% interest, and the percentage of Quest Midstream’s cash distributions to which it is entitled, will be proportionately reduced if Quest Midstream issues additional units in the future and Quest Midstream GP partner does not contribute a proportionate amount of capital to Quest Midstream in order to maintain its 2% general partner interest.

During the three months ended March 31, 2007, the partnership made no cash distributions to the common unit holders.

On April 25, 2007, the Company and its subsidiary, Quest Cherokee, LLC, entered into amendments to the following credit agreements:

Under the amendments, the lenders waived the default under the credit agreements due to the Company’s failure to comply with the minimum total debt to EBITDA ratio for the fiscal quarter ended March 31, 2007, and the Company’s maximum ratio of total net debt to EBITDA for future periods was amended as described above in Note 2—Long-term Debt. In connection with the amendments, the Company paid the lenders an aggregate amount equal to $1,687,500.

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/A for the year ended December 31, 2006 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.

We are an independent energy company with an emphasis on the acquisition, exploration, development, production, and transportation of natural gas (coal bed methane) in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma. We also own and operate a gas gathering pipeline network of approximately 1,600 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.

During the first quarter of 2007, we continued to be focused on drilling and completing new wells. We drilled 124 gross wells and completed the connection of 113 gross wells during this period. As of March 31, 2007, we had approximately 130 additional gas wells (gross) that we were in the process of completing and connecting to our gas gathering pipeline 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, we completed 9 re-completions.

We completed 67 miles of pipeline infrastructure expansion and acquired additional natural gas leases covering 23,535 acres (gross).

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.

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/A for the year ended December 31, 2006. Comparisons made between reporting periods herein are for the three month periods ended March 31, 2007 as compared to the same period in 2006.

Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006

Total revenues of $27.1 million for the quarter ended March 31, 2007 represent an increase of approximately 123% when compared to total revenues of $12.1 million for the quarter ended March 31, 2006. Total revenues for the quarter ended March 31, 2007 include a $996,000 gain on settlements of gas hedges. The settlements were recorded against gas sales as those hedge contracts did qualify for hedge accounting treatment during the quarter. Excluding this gain, total revenues for the first quarter of 2007 were $26.1 million. The quarter ended March 31, 2006 includes a $7.4 million loss on settlements of

gas hedges. The settlements were recorded as other expense due to the contracts not qualifying for hedge accounting treatment during the quarter. Excluding this loss, total revenues for the first quarter of 2006 were $19.5 million. Excluding the settlements on gas hedges, the increase in revenue for the quarter ended March 31, 2007 resulted from a 48.7% increase in sales volumes that was achieved by the addition of more producing wells, which was partially offset by the natural decline in production from some of our older gas wells and a decline in natural gas prices between periods.

The increase in oil and gas sales from $18.5 million for the quarter ended March 31, 2006 to $25.5 million for the quarter ended March 31, 2007 was primarily attributable to the increase in sales volumes discussed above and the gain of $996,000 on settlements of gas hedges during the quarter ended March 31, 2007. The remainder of the increase in oil and gas sales and the increase in gas pipeline revenue from $1.1 million to $1.5 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. The additional wells contributed to the production of 3,715,000 mcf of net gas for the quarter ended March 31, 2007, as compared to 2,498,000 net mcf produced in the same quarter last year. Our product prices on an equivalent basis (mcfe) decreased from $7.19 mcfe average for the quarter ended March 31, 2006 to $6.58 mcfe average for the quarter ended March 31, 2007. For the quarter ended March 31, 2007, the net product price, after accounting for the gain on hedging settlements of $996,000 during the quarter, averaged $6.85 mcfe. For the quarter ended March 31, 2006, the net product price, after accounting for the loss on hedge settlements of $7.4 million during the quarter, averaged $4.20 mcfe.

Other expense for the three months ended March 31, 2007 was $13,000 as compared to other expense of $7.4 million for the three-month period ended March 31, 2006. Other expense for the three months ended March 31, 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 $7.2 million for the quarter ended March 31, 2007 as compared to the operating costs of $3.9 million incurred for the quarter ended March 31, 2006. Lease operating costs per mcf for the quarter ended March 31, 2007 increased to $1.42 per mcf as compared to $1.10 per mcf for the quarter ended March 31, 2006. The lease operating cost per mcf increased due to winter weather conditions that resulted in a larger percentage of the field labor force being charged to operating expense as compared to capital expenditures, as a result of our increased development program, an increase in wage rates due to a tight labor market for skilled workers in the Cherokee Basin, 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. Pipeline operating costs increased by approximately 69% from $2.9 million for the quarter ended March 31, 2006 to $4.9 million for the quarter ended March 31, 2007. Pipeline operating costs per mcf for the quarter ended March 31, 2007 increased to $1.14 per mcf as compared to $1.04 per mcf for the quarter ended March 31, 2006. The cost increases incurred for pipeline operations are due to winter weather conditions that resulted in significant overtime hours for our field labor force working to restore production, the number of wells acquired, 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 March 31, 2007, depreciation, depletion and amortization increased to $7.9 million as compared to $5.9 million for the quarter ended March 31, 2006. The increase in depreciation, depletion and amortization is a result of the increased number of producing wells and miles of pipelines developed and the higher volumes of gas and oil produced.

General and administrative expenses increased from $1.5 million for the quarter ended March 31, 2006 to $2.6 million for the quarter ended March 31, 2007. This increase resulted from a non-cash charge of approximately $326,000 for amortization of stock awards. The remainder of the increase is due to an increase in staff personnel, legal, accounting and professional fees related to the increased size and complexity of our operations.

Interest expense increased to $7.1 million for the quarter ended March 31, 2007 from $3.8 million for the quarter ended March 31, 2006, due to an increase in our outstanding borrowings related to equipment, development and leasehold expenditures and higher average interest rates.

Change in derivative fair value was a non-cash loss of $464,000 for the three months ended March 31, 2007, which included a $1.04 million loss attributable to the change in fair value for certain derivatives that did not qualify as cash flow hedges pursuant to SFAS 133 and a gain of $572,000 relating to hedge ineffectiveness. Change in derivative fair value was a non-cash gain of $14.5 million for the three months ended March 31, 2006, which included a $13.4 million gain attributable to the change in fair value for certain derivatives that did not qualify as cash flow hedges pursuant to SFAS 133 and a gain of $1.1 million relating to hedge ineffectiveness. Amounts recorded in this caption represent non-cash gains and losses created by valuation changes in derivatives that are not entitled to receive hedge accounting. All amounts recorded in this caption are ultimately reversed in this caption over the respective contract term.

We recorded a net loss of $3.3 million for the quarter ended March 31, 2007 as compared to net income of $8.7 million for the quarter ended March 31, 2006, each period inclusive of the non-cash net gain or loss derived from the change in derivative fair value as stated above and inclusive of the loss from our minority interest in continuing operations of Quest Midstream for the quarter ended March 31, 2007.

The following table reflects the results of operations we achieved through the exploration and development activities and the results achieved from Quest Midstream through the pipeline activity. The required inter-company elimination entries are listed that result in the consolidated results of operations as listed in this quarterly filing ($ in thousands).

	Quest			Quest Midstream			Inter-co eliminations			Consolidated
Gas/oil sales	$	25,549		$	—		$	—		$	25,549
Pipeline revenue		—			7,903			(6,361	)		1,542
Other expense		(13	)		—			—			(13	)
Total revenues		25,536			7,903			(6,361	)		27,078

Lease operating cost		5,260			—			—			5,260
GPT/ad valorem tax		1,966			690			—			2,656
Transport fee/POE		6,361			4,245			(6,361	)		4,245
G/A cost		1,752			886			—			2,638
DDA		6,737			1,126			—			7,863
Total costs		22,076			6,947			(6,361	)		22,662

Income from operations		3,460			956			—			4,416

Sale of assets		107			—			—			107
Interest expense		(6,971	)		(142	)		—			(7,113	)
Interest income		177			—			—			177
Chg derivate fair value		(464	)		—			—			(464	)

Net income (loss)	$	(3,691	)	$	814		$	—		$	(2,877	)

At March 31, 2007, we had current assets of $51.5 million, working capital (current assets minus current liabilities, excluding the short-term derivative assets and liabilities) of $22.2 million and had $30.8 million of net cash provided by operations during the three months ended March 31, 2007. Working capital (including the short-term derivative assets and liabilities) totals $14.6 million.

During the three months ended March 31, 2007, a total of approximately $32.4 million of capital expenditures was invested as follows: $18.3 million was invested in new natural gas wells and properties, $6.7 million in new pipeline facilities, $3.5 million in acquiring leasehold and $3.9 million in other additional capital items. These investments were funded by cash flow from operations, remaining cash from the proceeds of the Quest Midstream transaction and borrowings of $10 million under the new $75 million revolving credit facility for Quest Midstream that was closed in January 2007.

Net cash provided by operating activities totaled $30.8 million for the three months ended March 31, 2007 as compared to net cash provided by operations of $14.2 million for the three months ended March 31, 2006. This resulted from the change in derivative fair value, a decrease in restricted cash, an increase in accounts receivable and accounts payable and an increase in revenue payable and other receivables.

Our working capital (current assets minus current liabilities, excluding the short-term derivative asset and liability of $2.8 million and $10.4 million, respectively) was $22.2 million at March 31, 2007, compared to working capital (excluding the short-term derivative asset and liability of $10.8 million and $5.2 million, respectively) of $37.7 million at December 31, 2006. The changes in working capital were primarily due to an increase in revenue payable of $1.9 million resulting from higher production volumes; an increase in accounts payable of $5.2 million due to the expansion of our wells and pipeline development program and an increase of $3.2 million in receivables. Additionally, the change in working capital is due to the

formation of Quest Midstream in December 2006 and the issuance of common units in Quest Midstream to a group of investors for approximately $90 million before expenses.

During 2007, we intend to focus on drilling and completing up to 550 additional new wells. We also currently intend to drill approximately 550 wells during 2008. Management currently estimates that it will require over the next two years a capital investment of approximately $113 million per year to drill and develop these wells and approximately $35 million per year for the pipeline expansion to connect the new wells to our existing gas gathering pipeline network. Management currently estimates that it will be able to drill and develop the approximately 550 new wells planned for 2007 utilizing cash flow from operations, remaining cash from the Quest Midstream transaction, borrowings available under the revolving credit facility and/or the sale of additional equity interests. In addition, in the near term, we intend to fund additional pipeline expansion to connect these new wells to our gas gathering system with Bluestem’s new $75 million revolving credit facility that was closed in January 2007. The Company intends to finance capital expenditures during 2008 utilizing a combination of cash flow from operations, additional borrowings and/or the sale of equity. However, no assurances can be given that such sources will be sufficient to fund the proposed capital expenditures.

Future payments due on our contractual obligations as of March 31, 2007 are as follows:

	Total		2007		2008-2009		2010-2011		thereafter
	(dollars in thousands)
First Lien Term Note	$	50,000	$	—	$	—	$	50,000	$	—
Second Lien Term Note		100,000		—		—		100,000		—
Third Lien Term Note		75,000		—		—		—		75,000
Revolver – Quest (1)		—		—		—		—		—
Credit Facility-Midstream		10,000		—		—		—		10,000
Asset retirement obligation		1,477		—		—		—		1,477
Drilling contractor		9,356		5,115		4,241		—		—
Notes payable		348		228		96		13		11
Lease obligations		815		185		403		202		25
Derivatives		16,535		10,457		6,078		—		—
Total	$	263,531	$	15,985	$	10,818	$	150,215	$	86,513

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 our consolidated financial statements.

At March 31, 2007 and December 31, 2006, 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.

There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2006, in Item 7A of our 2006 Form 10-K/A report. For more information on our risk management activities, see Note 4 to our consolidated financial statements.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of March 31, 2007, 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 to ensure 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 March 31, 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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.

There have been no material changes to the risk factors disclosed in Item 1A “Risk Factors” in our Annual Report on Form 10-K/A for the year ended December 31, 2006.

4.1*	Waiver and Amendment No. 3 to Amended and Restated Senior Credit Agreement, dated as of April 25, 2007, by and among Quest Cherokee, LLC, Quest Resource Corporation, the financial institutions from time to time parties thereto, and Guggenheim Corporate Funding, LLC (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on April 26, 2007).
4.2*	Waiver and Amendment No. 2 to Amended and Restated Second Lien Term Loan Agreement, dated as of April 25, 2007, by and among Quest Cherokee, LLC, Quest Resource Corporation, the financial institutions from time to time parties thereto, and Guggenheim Corporate Funding, LLC (incorporated herein by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on April 26, 2007).
4.3*	Waiver and Amendment No. 2 to Third Lien Term Loan Agreement, dated as of April 25, 2007, by and among Quest Cherokee, LLC, Quest Resource Corporation, the financial institutions from time to time parties thereto, and Guggenheim Corporate Funding, LLC (incorporated herein by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on April 26, 2007).
4.4*	Credit Agreement dated as of January 31, 2007, by and among Bluestem Pipeline, LLC, Quest Midstream Partners, L.P., Royal Bank of Canada, and the Lenders party thereto (incorporated herein by reference to Exhibit 4.19 to the Company’s Annual Report on Form 10-K filed on March 16, 2007).
4.5*	Guaranty for Credit Agreement by Quest Midstream Partners, L.P. in favor of Royal Bank of Canada, dated as of January 31, 2007 (incorporated herein by reference to Exhibit 4.20 to the Company’s Annual Report on Form 10-K filed on March 16, 2007).
4.6*	Pledge and Security Agreement for Credit Agreement by Quest Midstream Partners, L.P. for the benefit of Royal Bank of Canada, dated as of January 31, 2007 (incorporated herein by reference to Exhibit 4.21 to the Company’s Annual Report on Form 10-K filed on March 16, 2007).
4.7*	Pledge and Security Agreement for Credit Agreement by Bluestem Pipeline, LLC for the benefit of Royal Bank of Canada, dated as of January 31, 2007 (incorporated herein by reference to Exhibit 4.22 to the Company’s Annual Report on Form 10-K filed on March 16, 2007).
4.8*	Mortgage, Assignment, Security Agreement, Fixture Filing and Financing Statement (KS) by Bluestem Pipeline, LLC to Royal Bank of Canada, dated January 31, 2007 (incorporated herein by reference to Exhibit 4.23 to the Company’s Annual Report on Form 10-K filed on March 16, 2007).
4.9*	Mortgage, Assignment, Security Agreement, Fixture Filing and Financing Statement (OK) by Bluestem Pipeline, LLC to Royal Bank of Canada, dated January 31, 2007 (incorporated herein by reference to Exhibit 4.24 to the Company’s Annual Report on Form 10-K filed on March 16, 2007).
10.1*	Employment Agreement dated April 2, 2007 between Quest Resource Corporation and Jerry D. Cash (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 10, 2007).
10.2*	Employment Agreement dated April 2, 2007 between Quest Resource Corporation and David E. Grose (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on April 10, 2007).
10.3*	Executive Employment Agreement dated February 24, 2007 and effective as of January 1, 2007 between Quest Midstream GP, LLC and Richard Andrew Hoover (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 1, 2007).
10.4*	Employment Agreement dated March 21, 2007 between Quest Resource Corporation and Richard Marlin (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 22, 2007).

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 10th day of May, 2007.

	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)

PART I - FINANCIAL INFORMATION	3

Item 1. Financial Statements	3

Consolidated Balance Sheets:
March 31, 2007 and December 31, 2006	F-1

Consolidated Statements of Operations and Comprehensive Income:
Three months ended March 31, 2007 and 2006	F-2

Consolidated Statements of Cash Flows:
Three months ended March 31, 2007 and 2006	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	7

Item 4. Controls and Procedures	8

PART II – OTHER INFORMATION	8

Item 1. Legal Proceedings	8

Item 1A Risk Factors	8

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	8

Item 3. Defaults Upon Senior Securities	8

Item 4. Submission of Matters to a Vote of Security Holders	8

Item 5. Other Information	8

Item 6. Exhibits	9

SIGNATURES	11

Instrument Type	Term	Notional Amount (1)		Fixed Rate / Cap Rate	Floating Rate	Fair Value as of March 31, 2007
		$	98,705		3-month
Interest Rate Cap	March 2007 – Jan. 2008	$	70,175	5.000%	LIBOR	$	122

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

10.5*	Employment Agreement dated April 10, 2007 between Quest Resource Corporation and David Lawler (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 13, 2007).
10.6	Employment Agreement dated March 7, 2007 between Quest Resource Corporation and David Bolton.
10.7	Employment Agreement dated March 5, 2007 between Quest Resource Corporation and Steve Hochstein.
10.8	Form of Restricted Stock Agreement
12.1	Ratio of Earnings to Fixed Charges
31.1	Certification by Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification by Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
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

	405-488-1304
Registrant’s telephone number, including area code

2008	$	228
2009		77
2010		19
2011		50,006
2012		110,007
Thereafter		75,011
	$	235,348

	For the Three Months Ended
	March 31,
	2007			2006
	(dollars in thousands)
Change in fair value of derivatives not qualifying as cash flow hedges	$	(1,036	)	$	13,370
Amortization of derivative fair value gains and losses recognized in earnings prior to actual cash settlements		--			--
Ineffective portion of derivatives qualifying as cash flow hedges		572			1,111
	$	(464	)	$	14,481

	Three Months Ended
	March 31,
	2007			2006
	(dollars in thousand)
Asset retirement obligation beginning balance	$	1,410		$	1,150
Liabilities incurred		42			40
Liabilities settled		(1	)		(1	)
Accretion expense		26			21
Revisions in estimated cash flows		—			—
Asset retirement obligation ending balance	$	1,477		$	1,210

	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