e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended September 30, 2007.


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

For the transition period from to .

Commission file number: 0-17371

QUEST RESOURCE CORPORATION

(Exact name of registrant as specified in its charter)


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)

405-488-1304

Registrant’s telephone number, including area code

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

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

Large accelerated filer o Accelerated filer þ Non-accelerated filer o

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

As of November 7, 2007, the issuer had 22,483,276 shares of common stock outstanding.

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Except as otherwise required by the context, references in this quarterly report to “we,” “our,” “us,” “Quest” or “the Company” refer to Quest Resource Corporation and its subsidiaries: Quest Cherokee, LLC; Quest Cherokee Oilfield Service, LLC; Bluestem Pipeline, LLC; Quest Midstream Partners, L.P.; Quest Midstream GP, LLC; Quest Energy Partners, L.P., Quest Energy 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 condensed consolidated balance sheets as of December 31, 2006 and September 30, 2007, a condensed consolidated statement of operations and comprehensive income for the three month and nine month periods ended September 30, 2006 and 2007, and a condensed consolidated statement of cash flows for the nine month periods ended September 30, 2006 and 2007, and the notes thereto are attached hereto as Pages F-1 through F-17 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 results of operations of any interim period are not necessarily indicative of the results of operations for the full year.

The financial statements included herein should be read in conjunction with the financial statements and notes thereto included in our annual report on Form 10-K/A for the year ended December 31, 2006.

-3-

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
($ in thousands, except per share amounts)


	December 31,			September 30,
	2006			2007
				(unaudited)

ASSETS
Current assets:
Cash	$	41,820		$	21,002
Restricted cash		1,150			1,236
Accounts receivable, trade		9,840			10,425
Other receivables		371			1,466
Other current assets		1,068			2,128
Inventory		5,632			5,792
Short-term derivative asset		10,795			7,286

Total current assets		70,676			49,335

Property and equipment, net of accumulated depreciation of $5,107 and $6,352		16,212			20,206

Pipeline assets, net of accumulated depreciation of $6,104 and $9,674		127,690			150,138
Pipeline assets under construction		880			3,763

Oil and gas properties:
Properties being amortized		316,780			389,315
Properties not being amortized		9,545			14,619

		326,325			403,934
Less: Accumulated depreciation, depletion, amortization and valuation allowance		(92,732	)		(114,541	)

Net oil and gas properties		233,593			289,393
Other assets, net		9,467			10,430
Long-term derivative asset		4,782			8,697

Total assets	$	463,300		$	531,962


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	14,778		$	35,247
Revenue payable		4,540			5,676
Accrued expenses		2,525			3,287
Current portion of notes payable		324			122
Short-term derivative liability		5,244			6,098

Total current liabilities		27,411			50,430

Non-current liabilities:
Long-term derivative liability		7,449			2,067
Asset retirement obligation		1,410			1,619
Notes payable		225,569			280,176
Less current maturities		(324	)		(122	)

Non-current liabilities		234,104			283,740

Total liabilities		261,515			334,170

Minority interest		84,431			82,629
Commitments and contingencies
Stockholders’ equity:
10% convertible preferred stock, $.001 par value, 50,000,000 shares authorized, 0 shares issued and outstanding at December 31, 2006 and September 30, 2007
Common stock, $.001 par value, 200,000,000 shares authorized, 22,206,014 shares issued and outstanding at December 31, 2006 and 22,483,276 shares issued and outstanding at September 30, 2007		22			22
Additional paid-in capital		205,994			209,805
Accumulated other comprehensive income (loss)		428			7
Accumulated deficit		(89,090	)		(94,671	)

Total stockholders’ equity		117,354			115,163

Total liabilities and stockholders’ equity	$	463,300		$	531,962

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

F-1

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(UNAUDITED)
($ in thousands, except per share amounts)


	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2006			2007			2006			2007
Revenue:
Oil and gas sales	$	15,329		$	28,494		$	49,114		$	81,910
Gas pipeline revenue		1,372			1,788			3,722			5,122
Other revenue (expense)		4			(5	)		(63	)		(37	)

Total revenues		16,705			30,277			52,773			86,995

Costs and expenses:
Oil and gas production		5,492			7,280			14,064			22,247
Pipeline operating		3,400			5,004			9,330			14,271
General and administrative		2,723			3,653			6,596			11,698
Depreciation, depletion and amortization		7,875			9,276			20,643			25,610

Total costs and expenses		19,490			25,213			50,633			73,826


Operating income (loss)		(2,785	)		5,064			2,140			13,169


Other income (expense):
Change in derivative fair value		(332	)		5,539			6,300			5,354
(Loss)/gain on sale of assets		(57	)		50			(14	)		(141	)
Interest income		74			102			323			382
Interest expense		(6,973	)		(8,206	)		(15,885	)		(22,928	)

Total other income (expense)		(7,288	)		(2,515	)		(9,276	)		(17,333	)


Income (loss) before minority interest and income taxes		(10,073	)		2,549			(7,136	)		(4,164	)
Minority interest in consolidated subsidiary		—			(576	)		—			(1,660	)

Net income (loss) before income taxes		(10,073	)		1,973			(7,136	)		(5,824	)
Income tax expense — deferred		—			—			—			—

Net income (loss)		(10,073	)		1,973			(7,136	)		(5,824	)

Other comprehensive income (loss), net of tax:
Change in fixed-price contract and other derivative fair value, net of tax of $0 and $0		18,027			5,147			38,197			(421	)

Other comprehensive income (loss)		18,027			5,147			38,197			(421	)

Comprehensive income (loss)	$	7,954		$	7,120		$	31,061		$	(6,245	)


Earnings (loss) per common share — basic	$	(0.46	)	$	0.09		$	(0.32	)	$	(0.26	)


Earnings (loss) per common share — diluted	$	(0.46	)	$	0.09		$	(0.32	)	$	(0.26	)


Weighted average common and common equivalent shares:
Basic		22,123,514			22,296,179			22,090,363			22,240,077
Diluted		22,123,514			22,308,139			22,090,363			22,240,077

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

F-2

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
($ in thousands, except per share amounts)


	For the Nine Months Ended September 30,
	2006			2007
Cash flows from operating activities:
Net income (loss)	$	(7,136	)	$	(5,824	)
Adjustments to reconcile net income (loss) to cash provided by operations:
Depreciation and depletion		23,022			27,617
Change in derivative fair value		(16,532	)		(5,354	)
Stock issued for retirement plan		428			—
Stock options granted for directors fees		358			264
Stock awards granted to employees		466			3,850
Amortization of loan origination fees		874			1,757
Amortization of gas swap fees		146			187
Amortization of deferred hedging gains		(179	)		—
Bad debt expense		42			—
(Gain) loss on sale of assets		14			142
Minority interest		—			1,660
Change in assets and liabilities:
Restricted cash		3,169			(86	)
Accounts receivable		1,456			(585	)
Other receivables		(23	)		(1,095	)
Other current assets		715			(1,060	)
Inventory		(4,381	)		(160	)
Accounts payable		21,858			20,468
Revenue payable		(1,168	)		1,137
Accrued expenses		1,531			788

Net cash provided by operating activities		24,660			43,706

Cash flows from investing activities:
Additions to equipment, development and leasehold costs		(142,944	)		(106,131	)
Net additions to other property and equipment		(5,576	)		(6,289	)

Net cash used in investing activities		(148,520	)		(112,420	)

Cash flows from financing activities:
Proceeds from bank borrowings		139,068			55,000
Change in other long-term liabilities		—			123
Repayments of note borrowings		(331	)		(393	)
Syndication costs paid		(393	)		(48	)
Cash distributions to QMP minority unit holders		—			(3,879	)
Refinancing costs		(1,342	)		(2,907	)

Net cash provided by financing activities		137,002			47,896


Net increase (decrease) in cash		13,142			(20,818	)
Cash, beginning of period		2,559			41,820

Cash, end of period	$	15,701		$	21,002


Supplemental disclosure of cash flow information
Cash paid during the period for:
Interest expense	$	14,039		$	21,558
Income taxes	$	—		$	—

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

F-3

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Concentration of Credit Risk

A significant portion of the Company’s liquidity is concentrated in cash and derivative contracts that enable the Company to hedge a portion of its exposure to price volatility from producing natural gas and oil. These arrangements expose the Company to credit risk from its counterparties. The Company’s accounts receivable are primarily from purchasers of natural gas and oil products. Natural gas sales to one purchaser (ONEOK) accounted for approximately 95% of our natural gas and oil revenues for the nine months ended September 30, 2006. Two purchasers, ONEOK and Tenaska, accounted for approximately 74% and 26%, respectively, of our natural gas and oil revenues for the nine months ended September 30, 2007. This industry and customer concentration has the potential to impact the Company’s overall exposure to credit risk, either positively or negatively, by changes in economic, industry or other conditions that affect the natural gas and oil industry in general and ONEOK and Tenaska in particular.

Other Property and Equipment

During the three months ended September 30, 2006 and 2007, depreciation totaling $500,000 and $253,000, respectively, was capitalized in the full cost pool. During the nine months ended September 30, 2006 and 2007, depreciation totaling $2.4 million and $722,000, respectively, was capitalized in the full cost pool.

Full Cost Pool Test of Ceiling Limitation

Based on the low natural gas prices on September 30, 2007, the Company would have incurred a non-cash impairment loss of approximately $90 million for the third quarter of 2007. However, under the SEC’s accounting guidance in Staff Accounting Bulletin Topic 12(D)(e), if natural gas prices increase sufficiently between the end of a period and the completion of the financial statements for that period to eliminate the need for an impairment charge, an issuer is not required to recognize the non-cash impairment loss in its financial statements for that period. As of November 1, 2007, natural gas prices had improved sufficiently to eliminate the need for an impairment loss at September 30, 2007 and as a result, no impairment loss is reflected in the Company’s financial statements for the quarter ended September 30, 2007.

Debt Issue Costs

Included in other assets are costs associated with bank credit facilities. The remaining unamortized debt issue costs at December 31, 2006 and September 30, 2007 totaled $9.1 million and $10.3 million, respectively, and are being amortized over the life of the credit facilities. The increase as of September 30, 2007 is due to a fee paid in connection with the amendment to the Company’s credit facilities entered into in April 2007.

Income Taxes

The Company accounts for income taxes pursuant to the provisions of the SFAS 109, Accounting for Income Taxes, which requires an asset and liability approach to calculating deferred income taxes. The asset and liability approach requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the carrying amounts and the tax basis of assets and liabilities. No income tax expense was recognized for the nine months ended September 30, 2006 and 2007.

The effective tax rate for the nine months ended September 30, 2006 and 2007 is less than the federal statutory rate primarily due to our deferred tax assets (primarily intangible drilling costs and the net operating loss carry forward) being fully reserved with a 100% valuation allowance.

Accounting for Uncertainty in Income Taxes. In June 2006, the Financial Accounting Standards Board (FASB) issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109 (FIN 48). FIN 48 is intended to clarify the accounting for uncertainty in income taxes recognized in a company’s financial statements and prescribes the recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

Under FIN 48, evaluation of a tax position is a two-step process. The first step is to determine whether it is more-likely-than-not that a tax position will be sustained upon examination, including the resolution of any related appeals or litigation based

F-4

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

on the technical merits of that position. The second step is to measure a tax position that meets the more-likely-than-not threshold to determine the amount of benefit to be recognized in the financial statements. A tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement.

Tax positions that previously failed to meet the more-likely-than-not recognition threshold should be recognized in the first subsequent period in which the threshold is met. Previously recognized tax positions that no longer meet the more-likely-than-not criteria should be de-recognized in the first subsequent financial reporting period in which the threshold is no longer met.

The adoption of FIN 48 at January 1, 2007 did not have a material effect on the Company’s financial position.

Stock-Based Compensation

Stock Awards. The Company granted shares of common stock to certain employees in October 2005, October, November and December, 2006, February, March, April, May, and September 2007. 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. The value of common stock grants capitalized in the full cost pool for the three and nine month periods ended September 30, 2007 were $342,000, $756,000, respectively, and for the three and nine month periods ended September 30, 2006 were $61,000 and $182,000, respectively. The value of common stock grants included in general and administrative expenses for the three and nine month periods ended September 30, 2007 were $672,000 and $3.0 million, respectively, and for the three and nine month periods ended September 30, 2006 were $212,000,and $466,000, respectively.

Partnership Unit Awards. Quest Midstream GP, LLC granted bonus units to certain employees during the nine months ended September 30, 2007. The units are subject to pro rata vesting which ranges from 0 to 3 years. During this vesting period, the fair value of the unit awards granted is recognized pro rata as compensation expense. To the extent the compensation expense relates to employees directly involved in acquisition and development of pipeline activities, such amounts are capitalized to the pipeline. Amounts not capitalized to the pipeline are recognized in general and administrative expenses. For the three and nine month periods ended September 30, 2007, the Partnership did not capitalize any of the value associated with the bonus unit grants. The value of the bonus unit grants included in general and administrative expenses for the three and nine months ended September 30, 2007 were $394,000 and $1.1 million, respectively.

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. The Company has previously recorded stock compensation pursuant to the intrinsic value method under APB Opinion No. 25, whereby compensation was recorded related to performance share and unrestricted share awards and no compensation was recognized for most stock option awards. The Company is using the modified prospective application method of adopting SFAS 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 the Company’s prior pro forma disclosures. The Company has estimated expected forfeitures, as required by SFAS No. 123R, and the Company is recognizing compensation expense only for those awards expected to vest. Compensation expense is amortized over the estimated service period, which is the shorter of the award’s time vesting period or the derived service period as implied by any accelerated vesting provisions when the common stock price reaches specified levels. All compensation must be recognized by the time the award vests. The cumulative effect of initially adopting SFAS No. 123R was immaterial.

Reclassification

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

Recently Issued Accounting Standards

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

F-5

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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

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. Complying with the requirements of SAB No. 108 had no impact on the Company’s financial statements.

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.

2. LONG—TERM DEBT

Long-term debt consists of the following:



	December 31, 2006		September 30, 2007
	(dollars in thousands)
Senior credit facilities — Quest	$	225,000	$	250,000
Senior credit — Quest Midstream		—		30,000
Other notes payable		569		176


Total long-term debt		225,569		280,176

Less — current maturities		324		122


Total long-term debt, net of current maturities	$	225,245	$	280,054

F-6

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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 September 30, 2007:


2008	$	122
2009		26
2010		8
2011		50,006
2012		230,006
Thereafter		8

	$	280,176

Credit Facilities

Quest Resource Corporation and Quest Cherokee

As of September 30, 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 September 30, 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. The base rate is the greater of the prime rate or the federal funds effective rate plus 0.5%. 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 September 30, 2007, the Company’s weighted average interest rates under the credit facilities were as follows.

•

Revolving credit facility under the Senior Credit Agreement — 8.92%;

•

First lien term loan under the Senior Credit Agreement — 8.67%;

•

Second Lien Term Loan — 10.88%; and

•

Third Lien Term Loan — 13.38%.

The Company failed to comply with the maximum total debt to EBITDA ratio contained in all three credit agreements for the fiscal quarter ended March 31, 2007. On April 25, 2007, the lenders waived the default under the credit agreements due to the Company’s failure to comply with this financial covenant for the fiscal quarter ended March 31, 2007 and the credit facilities were amended to reset the maximum ratio for the remaining quarters of 2007. In connection with the waiver and amendments, the lenders were paid a fee in the aggregate amount equal to $1,687,500.

The financial covenants applicable to the credit agreements require that:

F-7

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

•

for the Senior Credit Agreement, the Company is required to maintain a ratio of PV-10 value for all of its proved reserves to indebtedness under the Senior Credit Agreement (excluding obligations under hedging agreements secured by the Senior Credit Agreement) of not less than 2.0 to 1.0.

•

for the Second and Third Lien Term Loan Agreements, the Company’s ratio of PV-10 value for all of its proved reserves to total net debt must not be less than 1.5 to 1.

•

for all three credit agreements, after giving effect to the amendments described above, the Company’s ratio of total net debt to EBITDA for each quarter ending on the dates set forth below must not be more than:

	•		5.50 to 1.0 for the quarter ended June 30, 2007;

	•		4.75 to 1.0 for the quarter ended September 30, 2007;

	•		4.25 to 1.0 for the quarter ended December 31, 2007;

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

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

	•		3.0 to 1.0 for the quarter ended on or after September 30, 2008.

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.

Quest Midstream Partners, L.P. and Bluestem Pipeline

Bluestem has a separate $75 million syndicated revolving credit facility. The credit facility is guaranteed by Quest Midstream Partners. Royal Bank of Canada is the administrative agent and collateral agent. As of September 30, 2007, $30 million was outstanding under the credit facility.

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. For the three months ended September 30, 2007, the weighted average interest rate under the credit facility was 7.33%.

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

•

permitting the interest coverage ratio (ratio of consolidated EBITDA to consolidated interest charges) at any fiscal quarter-end, commencing with the quarter ended March 31, 2007, to be less than the ratio of 3.01 to 1.0; and

•

permitting the leverage ratio (ratio of cash adjusted consolidated funded debt to consolidated EBITDA) at any fiscal quarter-end, commencing with the quarter ended March 31, 2007, to be greater than 4.0 to 1.0.

F-8

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Consolidated EBITDA is defined in the credit agreement to mean for Quest Midstream Partners 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 Partners 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 Partners and its subsidiaries on a consolidated basis, the sum of (i) all interest, premium payments, fees, charges and related expenses of Quest Midstream Partners 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 Partners 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 Partners and its subsidiaries on a consolidated basis, the net income or net loss of Quest Midstream Partners 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 Partners 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.

For additional information regarding Bluestem’s credit facility, see Note 2 to the consolidated financial statements included in the Company’s Form 10-Q for the three months ended March 31, 2007.

Other Long-Term Indebtedness

As of September 30, 2007, $176,000 of notes payable to banks and finance companies were outstanding. These notes are secured by equipment and vehicles, with payments due in monthly installments through October 2013 with interest rates ranging from 1.9% to 8.0% per annum.

3. COMMITMENTS AND CONTINGENCIES

The Company, Quest Cherokee, STP, Bluestem, Quest Energy Service, Inc. (“QES”), Quest Midstream Partners and Quest Midstream GP, among others, have been 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 to them. Plaintiffs also allege, among other things, that Defendants have engaged in self-dealing, have breached their fiduciary duties to Plaintiffs and have acted fraudulently towards Plaintiffs. Plaintiffs also allege that the gathering fees and related charges imposed by Bluestem should not be deducted in paying royalties. Plaintiffs are seeking unspecified actual and punitive damages as a result of the alleged conduct by the Defendants. Defendants intend to defend vigorously against these claims.

STP, Quest Cherokee, QES and Bluestem, among others, 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 allege that Defendants sold natural gas from wells owned by the Plaintiffs without providing the requisite notice to Plaintiffs. Plaintiffs have also requested an accounting to determine if royalties have been properly paid and state, that if Plaintiffs have suffered any damages for failure to properly pay royalties, Plaintiffs have a right to recover those damages. Plaintiffs have further asserted claims of fraud, alleging generally that Defendants have failed to disclose all deductions taken from Defendants’ royalty, that Defendants took improper deductions, and that Defendants paid Plaintiffs based on an allocated rather than actual volume of production without disclosing the same to Plaintiffs. Plaintiffs have not quantified their alleged damages. Discovery is ongoing and 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

F-9

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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 approximately 1,100 acres 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. Quest Cherokee has asserted third party claims against the persons who entered into the gas leases with Quest Cherokee for breach of the warranty of title contained in their leases in the event that the court finds that Plaintiff owns the coal bed methane gas. The District Court granted Quest Cherokee’s motion for summary judgment, ruling that coal bed methane gas is owned by the owners of the gas rights. That ruling was appealed and the appeal is pending before the Kansas Supreme Court. The appeal has been fully briefed and oral argument is scheduled for December 4, 2007.

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 2,500 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 it was 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.

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. In July 2007, QES and Plaintiff agreed to settle the dispute and the Plaintiff dismissed the case with prejudice.

Bluestem and Quest Cherokee were named as Defendants in a lawsuit (Case No. CJ-2007-325) filed by Devonian Enterprises, Inc. d/b/a Permian Land Company (“Permian”) in the district court of Oklahoma County, Oklahoma. Permian asserted claims against Quest Cherokee and Bluestem in the amount of $521,252.88 for land services allegedly rendered to Quest Cherokee and Bluestem by Permian and for which no payment has purportedly 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. This matter was recently settled on July 30, 2007.

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 October 31, 2007, the total amount of acreage covered by the leases at issue in these lawsuits was approximately 7,500 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”)

F-10

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(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.

On August 3, 2007, certain alleged mineral and/or overriding royalty interests owners in land located in the Kansas portion of the Cherokee Basin filed a putative class action lawsuit against Quest Cherokee. Hugo Spieker, et al. v. Quest Cherokee, LLC, United States District Court for the District of Kansas, Case No. 07-1225-MLB. The named plaintiffs allege that Quest Cherokee has failed to properly make royalty payments to them and the putative class by, among other things, paying royalties based on reduced volumes instead of volumes of gas measured at the wellheads, by allocating certain expenses to plaintiffs’ interests, and by allocating more than the actual cost of the expenses. Plaintiffs allege that the amount in controversy exceed five million dollars. Quest Cherokee is in the process of investigating and evaluating the claims. Quest Cherokee denies any wrongdoing and intends to vigorously defend against the claims.

The Company, from time to time, may be subject to legal proceedings and claims that arise in the ordinary course of its business. Although no assurance can be given, management believes, based on its experiences to date, that the ultimate resolution of such items will not have a material adverse impact on the Company’s business, financial position or results of operations. Like other natural gas and oil producers and marketers, the Company’s operations are subject to extensive and rapidly changing federal and state environmental regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. Therefore it is extremely difficult to reasonably quantify future environmental related expenditures.

On December 22, 2006, Quest Midstream Partners entered into a registration rights agreement with a group of its investors. The registration rights agreement was amended on November 1, 2007, to add additional investors to the agreement. The agreement currently covers 8,614,866 common units of Quest Midstream Partners.

Under the registration rights agreement, Quest Midstream Partners granted the investors certain piggyback registration rights and certain rights to require Quest Midstream to file and maintain a shelf registration statement for the resale of the common units by the investors. Under the registration rights agreement, at any time on or after the date that is 270 days after December 22, 2006, the investors (by action of the investors holding a majority of the common units subject to registration or action of certain of the investors) may require Quest Midstream Partners to (a) file the shelf registration statement as soon as reasonably practicable, but in any event within 90 days, after notice to Quest Midstream Partners, subject to certain changes in timing if Quest Midstream Partners is then working toward the filing of a registration statement for an initial public offering, (b) use its commercially reasonable efforts to cause the shelf registration statement to be declared effective within 210 days after the initial filing of the shelf registration statement and (c) maintain effectiveness of the shelf registration statement with respect to each common unit included in the shelf registration statement, subject to certain suspension and blackout periods, until (i) the common unit is sold pursuant to a registration statement, (ii) the common unit is distributed to the public pursuant to Rule 144 or is eligible for sale without registration pursuant to Rule 144(k), in the opinion of counsel to Quest Midstream Partners, or (iii) the common unit is sold to Quest Midstream Partners or to the registrant or any subsidiary of the registrant.

Under the registration rights agreement, Quest Midstream Partners is required to pay liquidated damages if the shelf registration statement is not filed or declared effective within the time periods established in the agreement, if the shelf registration statement is not maintained in accordance with the agreement and with respect to any common units required to be included in the shelf registration statement that are not included. The liquidated damages amount payable is $0.175 per common unit entitled to liquidated damages for each 90-day period for which liquidated damages are payable, subject to proration for periods of less than 90 days.

4. FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

Natural Gas Hedging Activities

The Company seeks to reduce its exposure to unfavorable changes in natural gas prices, which are subject to significant and often volatile fluctuation, through the use of fixed-price contracts. The fixed-price contracts are comprised of energy swaps, collars and basis swaps. These contracts allow the Company to predict with greater certainty the effective natural gas prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. Collar structures provide for participation in price increases and decreases to the extent of the ceiling and floor prices provided in those contracts. For the nine months ended September 30, 2006 and 2007, fixed-price contracts hedged 64.0% and 66.17%, respectively, of the Company’s natural gas production. As of September 30, 2007, fixed-price contracts were in place to hedge 28.1 Bcf of estimated future natural gas production. Of this total volume, 2.7 Bcf are hedged for the fourth quarter of 2007 and 25.4 Bcf thereafter. See Note 15 to the Company’s consolidated financial statements included in the Company’s Annual Report on Form 10-K/A for the year ended December 31, 2006 for additional information with respect to the Company’s fixed-price contracts.

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.

F-11

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

The following table summarizes the estimated volumes, fixed prices, fixed-price sales and fair value attributable to the fixed-price contracts as of September 30, 2007.


	Three Months
	Ending
	December 31,		Years Ending December 31,
	2007		2008			2009		2010		Total
			*(dollars in thousands, except per MMBtu data)*
Natural Gas Swaps:
Contract volumes (MMBtu)		593,000		2,332,000			9,999,000		6,000,000		18,924,000
Weighted average fixed price per MMBtu (1)	$	7.20	$	7.35		$	7.85	$	7.55	$	8
Fixed-price sales	$	4,272	$	17,141		$	78,451	$	45,239	$	145,103
Fair value, net	$	282	$	1,495		$	5,265	$	1,922	$	8,964

Natural Gas Collars:
Contract volumes (MMBtu)
Floor		2,125,000		7,028,000			—		—		9,153,000
Ceiling		2,125,000		7,028,000			—		—		9,153,000
Weighted average fixed price per MMBtu (1)
Floor	$	6.63	$	6.54		$	—	$	—	$	7
Ceiling	$	7.54	$	7.54		$	—	$	—	$	8
Fixed-price sales (2)	$	14,087	$	45,973		$	—	$	—	$	60,060
Fair value, net	$	463		($1,608	)	$	—	$	—	$	(1,145	)

Total Natural Gas Contracts(3):
Contract volumes (MMBtu)		2,718,000		9,360,000			9,999,000		6,000,000		28,077,000
Weighted average fixed price per MMBtu (1)	$	6.75	$	6.74		$	7.85	$	7.54	$	7.31
Fixed-price sales (2)	$	18,359	$	63,114		$	78,451	$	45,239	$	205,163
Fair value, net	$	745		($113	)	$	5,265	$	1,922	$	7,819


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

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

(3)		Does not include basis swaps with notional volumes by year, as follows: 2007: 305,000 MMBtu; 2008: 1,464,000 MMBtu.

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 September 30, 2006 and 2007, oil and gas sales included a loss of $3.7 million and a gain of $3.7 million, respectively, associated with realized gains and losses under fixed-price contracts. For the nine months ended September 30, 2006 and 2007, oil and gas sales included a loss of $4.4 million and a gain of $5.2 million, respectively, associated with realized gains and 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 September 30, 2007, the estimated amount of unrealized losses for fixed-price contracts shown as adjustments to other comprehensive income that are expected to be reclassified into earnings as actual contract cash settlements are realized within the next 12 months is $1.2 million.

F-12

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Interest Rate Hedging Activities

At September 30, 2007, the Company had no outstanding interest rate cap or swap agreements.

Change in Derivative Fair Value

Change in derivative fair value in the statements of operations for the three and nine months ended September 30, 2006 and 2007 is comprised of the following:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,

	2006			2007		2006			2007

	*(dollars in thousands)*

Change in fair value of derivatives not qualifying as cash flow hedges	$	(1,330	)	$	4,748	$	13,300		$	3,329
Settlements due to ineffective cash flow hedges		—			—		(10,232	)		—
Ineffective portion of derivatives qualifying as cash flow hedges		998			791		3,232			2,025

	$	(332	)	$	5,539	$	6,300		$	5,354

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

The change in carrying value of interest rate swaps and caps in the balance sheet since December 31, 2006 resulted from the expiration of the Company’s interest rate cap agreement. The change in the carrying value of fixed price contracts in the balance sheet since December 31, 2006 resulted from an increase in gas prices.

Credit Risk

Energy swaps, collars and basis swaps provide for a net settlement due to or from the respective party as discussed previously. The counterparty to the derivative contracts is a major energy corporation. Should a counterparty default on a contract, there can be no assurance that the Company would be able to enter into a new contract with a third party on terms comparable to the original contract. The Company has not experienced non-performance by its counterparties.

Cancellation or termination of a fixed-price contract would subject a greater portion of the Company’s natural gas production to market prices, which, in a low price environment, could have an adverse effect on its future operating results. In addition, the associated carrying value of the derivative contract would be removed from the balance sheet.

Market Risk

The differential between the floating price paid under each energy swap or collar contract and the price received at the wellhead for the Company’s production is termed “basis” and is the result of differences in location, quality, contract terms, timing and other variables. For instance, some of the Company’s fixed price contracts are tied to commodity prices on the New York Mercantile Exchange (“NYMEX”), that is, the Company receives the fixed price amount stated in the contract and pays to its counterparty the current market price for gas as listed on the NYMEX. However, due to the geographic location of the Company’s natural gas assets and the cost of transporting the natural gas to another market, the amount that the Company receives when it actually sells its natural gas is generally based on the Southern Star Central TX/KS/OK (“Southern Star”) first of month index, with the remainder being sold based on the daily price on the Southern Star index. The difference between natural gas prices on the NYMEX and the price actually received by the Company is referred to as a basis differential. Typically, the price for natural gas on the Southern Star first of the month index is less than the price on the NYMEX due to the more limited demand for natural gas on the Southern Star first of the month index.

The 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

F-13

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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.

Fair Value of Financial Instruments

The following information is provided regarding the estimated fair value of the financial instruments, including derivative assets and liabilities as defined by SFAS 133 that the Company held as of December 31, 2006 and September 30, 2007 and the methods and assumptions used to estimate their fair value:


	December 31, 2006						September 30, 2007

	Carrying						Carrying
	Amount			Fair Value			Amount			Fair Value

	*(dollars in thousands)*

Derivative assets:
Interest rate swaps and caps	$	197		$	197		$	—		$	—
Basis swaps	$	62		$	62		$	205		$	205
Fixed-price natural gas swaps	$	2,207		$	2,207		$	8,815		$	8,815
Fixed-price natural gas collars	$	13,111		$	13,111		$	6,963		$	6,963
Derivative liabilities:
Basis swaps	$	(377	)	$	(377	)	$	(57	)	$	(57	)
Fixed-price natural gas collars	$	(12,316	)	$	(12,316	)	$	(8,108	)	$	(8,108	)
Credit facilities	$	(225,000	)	$	(225,000	)	$	(280,000	)	$	(280,000	)
Other financing agreements	$	(569	)	$	(569	)	$	(176	)	$	(176	)

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

The fair value of all derivative contracts as of December 31, 2006 and September 30, 2007 was based upon estimates determined by the Company’s counter-parties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, futures prices, volatility, and time to maturity and credit risk. The values reported in the financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.

Derivative assets and liabilities reflected as current in the September 30, 2007 balance sheet represent the estimated fair value of fixed-price contract and interest rate cap settlements scheduled to occur over the subsequent twelve-month period based on market prices for natural gas and fluctuations in interest rates as of the balance sheet date. The offsetting increase in value of the hedged future production has not been accrued in the accompanying balance sheet. The contract settlement amounts are not due and payable until the monthly period that the related underlying hedged transaction occurs. In some cases the recorded liability for certain contracts significantly exceeds the total settlement amounts that would be paid to a counterparty based on prices in effect at the balance sheet date due to option time value. Since the Company expects to hold these contracts to maturity, this time value component has no direct relationship to actual future contract settlements and consequently does not represent a liability that will be settled in cash or realized in any way.

5. EARNINGS PER SHARE

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

•

For the three and nine months ended September 30, 2006, dilutive shares do not include the assumed exercise of stock options and stock awards because the effects were antidilutive.

F-14

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

•

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

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


	Income			Shares		Per Share
	(Numerator)			(Denominator)		Amount
For the three months ended September 30, 2006:
Net loss	$	(10,073	)

Basic EPS loss available to common shareholders	$	(10,073	)		22,123,514	$	(0.46	)

Effect of dilutive securities:
None		—			—


Diluted EPS loss available to common shareholders	$	(10,073	)		22,123,514	$	(0.46	)


For the three months ended September 30, 2007:
Net income	$	1,973

Basic EPS available to common shareholders	$	1,973			22,296,179	$	0.09

Effect of dilutive securities:
Stock options		—			626
Stock awards		—			11,334


Diluted EPS available to common shareholders	$	1,973			22,308,139	$	0.09


For the nine months ended September 30, 2006:
Net income	$	(7,136	)

Basic EPS loss available to common shareholders	$	(7,136	)		22,090,363	$	(0.32	)

Effect of dilutive securities:
None		—			—


Diluted EPS loss available to common shareholders	$	(7,136	)		22,090,363	$	(0.32	)


For the nine months ended September 30, 2007:
Net loss	$	(5,824	)

Basic EPS available to common shareholders	$	(5,824	)		22,240,077	$	(0.26	)

Effect of dilutive securities:
None		—			—


Diluted EPS available to common shareholders	$	(5,824	)		22,240,077	$	(0.26	)

6. ASSET RETIREMENT OBLIGATIONS

The Company has adopted SFAS 143, Accounting for Asset Retirement Obligations. The following table provides a roll forward of the asset retirement obligations for the three and nine months ended September 30, 2006 and 2007:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,

	2006			2007			2006			2007

	*(dollars in thousands)*

Asset retirement obligation beginning balance	$	1,275		$	1,546		$	1,150		$	1,410
Liabilities incurred		45			44			130			128
Liabilities settled		(2	)		(2	)		(5	)		(5	)
Accretion expense		24			31			67			86
Revisions in estimated cash flows		—			—			—			—

Asset retirement obligation ending balance	$	1,342		$	1,619		$	1,342		$	1,619

F-15

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

7. PARTNERS’ CAPITAL AND CASH DISTRIBUTIONS

The common unit holders in Quest Midstream Partners have the right to receive quarterly distributions of available cash from operating surplus (each as defined in the Quest Midstream Partners 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 Partners, 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 Partners, 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 Partners 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 Partners 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 Partners to maintain its 2% general partner interest if Quest Midstream Partners issues additional units. Quest Midstream GP’s 2% interest, and the percentage of Quest Midstream Partners’ cash distributions to which it is entitled, will be proportionately reduced if Quest Midstream Partners issues additional units in the future and Quest Midstream GP does not contribute a proportionate amount of capital to Quest Midstream Partners in order to maintain its 2% general partner interest.

During the nine months ended September 30, 2007, the partnership made $3.9 million in distributions to the common unit holders.

8. SUBSEQUENT EVENTS

On October 15, 2007, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with its newly-formed subsidiary, Quest Mergersub, Inc., and Pinnacle Gas Resources, Inc. (“Pinnacle”), which provides for the acquisition of Pinnacle by the Company in a stock-for-stock transaction. Consummation of the merger is subject to various conditions, including approval by the stockholders of both the Company and Pinnacle, the closing of the initial public offering of common units of Quest Energy Partners, L.P. and certain other customary conditions. In addition, the Merger Agreement contains termination rights for both the Company and Pinnacle, and further provides that, upon termination of the Merger Agreement under specified circumstances (including an adverse change by either party’s board of directors of its recommendation to stockholders to vote for the merger), a party may be required to pay the other party a termination fee of $3.0 million. It is anticipated that the closing of the merger will occur in the first or second quarter of 2008.

On November 1, 2007, Quest Midstream Partners closed on the acquisition of (i) a 1,120-mile interstate gas pipeline running from Oklahoma to Missouri (the “KPC Pipeline”) and (ii) all of the membership interests in the two general partners of Enbridge Pipelines (KPC), the owner of the KPC Pipeline (the “Enbridge Acquisition”). Quest Midstream Partners completed the purchase of the KPC Pipeline for $133 million in cash, subject to a working capital adjustment, pursuant to a Purchase and Sale Agreement dated October 9, 2007, by and among Enbridge Midcoast Energy, L.P., Midcoast Holdings No. One, L.L.C., and Quest Midstream Partners.

On November 1, 2007, Quest Midstream Partners sold 3,750,000 Common Units, representing an approximate 27.12% interest in Quest Midstream Partners, for $20.00 per Common Unit, or $75 million in the aggregate, in a private placement pursuant to a Purchase Agreement dated October 16, 2007, among Quest Midstream Partners, Quest Midstream GP, the Company and a group of institutional investors. Quest Midstream GP purchased an additional 76,531 general partner units in Quest Midstream Partners and the Company made a capital contribution of approximately $1.3 million in order for Quest Midstream GP to maintain its 2% general partner interest in Quest Midstream Partners. As a result, Quest Midstream GP now holds 276,531 general partner units and continues to hold all of the incentive distribution rights, and the Company continues to hold 35,134 Class A Subordinated Units and 4,900,000 Class B Subordinated Units in Quest Midstream Partners. The proceeds of the offering were used to fund a portion of the purchase price of the Enbridge Acquisition.

F-16

QUEST RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

On November 1, 2007, Quest Midstream Partners and its wholly-owned subsidiary, Bluestem, entered into an Amended and Restated Credit Agreement (the “Credit Agreement”) to increase the aggregate commitment under Bluestem’s existing five-year revolving credit facility from $75 million to $135 million, to add Quest Midstream Partners as a co-borrower instead of a guarantor, and to change the maturity date from January 31, 2012 to November 1, 2012. The Credit Agreement is among Bluestem, Quest Midstream Partners, Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto. As of November 1, 2007, the amount borrowed under the Credit Agreement was $95 million. Further information regarding this transaction is disclosed in the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on November 2, 2007.

On November 1, 2007, J-W Gas Gathering, L.L.C. merged with and into Producers Service, LLC, which then merged with and into Ponderosa Gas Pipeline Company, LLC (“Ponderosa”). On November 2, 2007, Ponderosa and STP Cherokee, LLC merged with and into the Company with the Company being the survivor. These changes were made to simplify the Company’s organizational structure and to eliminate certain inactive subsidiaries.

On November 8, 2007, Quest Energy Partners priced the public offering of 9,100,000 common units, representing a 42.1% limited partner interest in it (or 10,645,000 common units, representing a 48.5% limited partner interest, if the underwriters exercise their overallotment option in full) at a price of $18.00 per unit. Net proceeds of the offering, before expenses, are expected to be approximately $152.7 million (or $176.1 million if the over-allotment option is exercised in full), after deducting the underwriting discount and commissions and a structuring fee. Quest Energy Partners intends to use the net proceeds of the offering to pay down existing indebtedness. If the underwriters exercise their over-allotment option, Quest Energy Partners will use the net proceeds to redeem a number of common units from the Company equal to the number of common units issued upon the exercise of the underwriters’ option. The Company will use the net proceeds from the redemption to reduce its indebtedness.

In October 2007, the Company entered into additional derivative contracts for 2008, 2009 and 2010. The Company’s current schedule of derivative contracts for these years is as follows:


Hedge Summary
	Hedged Price
	Floor		Ceiling		Vol.(Mmcf)
2008
Southern Star Swap	$	7.35	$	7.35		2,332
Southern Star Collar	$	8.00	$	8.93		2,137
NYMEX Collar (1)	$	4.50	$	5.52		2,928
Southern Star Collar	$	8.00	$	9.02		1,963
NYMEX Swap	$	7.88	$	7.88		4,800
2008 Total						14,160

2009
Southern Star Swap	$	7.82	$	7.82		4,500
Southern Star Swap	$	7.87	$	7.87		4,500
Southern Star Swap	$	7.85	$	7.85		1,000
Southern Star Swap	$	7.13	$	7.13		2,630
2009 Total						12,630

2010
Southern Star Swap	$	7.50	$	7.50		4,000
Southern Star Swap	$	7.615	$	7.615		2,000
Southern Star Swap	$	7.010	$	7.010		4,000
Southern Star Swap	$	7.010	$	7.010		500
2010 Total						10,499


(1)		1,464 Bcf with basis lock @ $1.03 per mcf

F-17

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

Business of Issuer

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 1,800 miles in length within this basin. Our main focus is upon the development of our coal bed methane gas reserves in our pipeline network region and upon the continued enhancement of the pipeline system and supporting infrastructure. Unless otherwise indicated, references to “us”, “we”, the “Company” or “Quest” include our operating subsidiaries.

Significant Developments During the Nine Months Ended September 30, 2007

During the first nine months of 2007, we continued to be focused on drilling and completing new wells. We drilled 452 gross wells and completed the connection of 450 gross wells during this period. As of September 30, 2007, we had approximately 155 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 nine months of 2007, we completed 47 re-completions.

We completed 247 miles of pipeline infrastructure expansion and had a net increase in the total number of acres that we lease under natural gas leases of 24,943 acres (net).

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

On September 30, 2007, our average gross daily production was 62.4 MMcfe/d.

Public Offering of Quest Energy Partners, L.P.

On November 8, 2007, Quest Energy Partners priced the public offering of 9,100,000 common units, representing a 42.1% limited partner interest in it (or 10,645,000 common units, representing a 48.5% limited partner interest, if the underwriters exercise their overallotment option in full) at a price of $18.00 per unit. Net proceeds of the offering, before expenses, are expected to be approximately $152.7 million (or $176.1 million if the over-allotment option is exercised in full), after deducting the underwriting discount and commissions and a structuring fee. Quest Energy Partners intends to use the net proceeds of the offering to pay down existing indebtedness. If the underwriters exercise their over-allotment option, Quest Energy Partners will use the net proceeds to redeem a number of common units from us equal to the number of common units issued upon the exercise of the underwriters’ option. We will use the net proceeds from the redemption to reduce our indebtedness.

Upon completion of the offering, Quest Energy Partners will own substantially all of our natural gas and oil exploration and production assets. Quest Energy GP is the general partner of Quest Energy Partners and will conduct the business and manage the operations of Quest Energy Partners. Pursuant to a management services agreement, QES will provide legal, accounting, finance, tax, property management, engineering, risk management and acquisition services to Quest Energy Partners.

KPC Acquisition

Results of Operations

The following discussion is based on the consolidated operations of all our subsidiaries and should be read in conjunction with the financial statements included in this report; and should further be read in conjunction with the audited financial statements and notes thereto included in our annual report on Form 10-K/A for the year ended December 31, 2006. Comparisons made

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between reporting periods herein are for the three and nine month periods ended September 30, 2006 as compared to the same period in 2007.

Three Months Ended September 30, 2006 and September 30, 2007

Overview. The following table summarizes our results of operations for the three months ended September 30, 2006 and 2007.


	Three Months
	Ended
	September 30,						Increase/
	2006			2007			(Decrease)
	($ in thousands)
Oil and gas sales	$	15,329		$	28,494		$	13,165		85.9	%
Gas pipeline revenue		1,372			1,788			416		30.3	%
Other revenue/(expense)		4			(5	)		(9	)	-225.0	%
Oil and gas production costs, including GPT/Ad valorem tax		5,492			7,280			1,788		32.6	%
Pipeline operating expenses, including Ad valorem tax		3,400			5,004			1,604		47.2	%
Depreciation, depletion and amortization		7,875			9,276			1,401		17.8	%
General and administrative expenses		2,723			3,653			930		34.2	%
Interest expense		6,937			8,206			1,269		18.3	%
Change in derivative fair value		(332	)		5,539			5,871		1,768.4	%

Production. The following table presents the primary components of our revenues, as well as the average costs per Mcfe, for the three months ended September 30, 2006 and 2007.


	Three Months
	Ended
	September 30,				Increase/
	2006		2007		(Decrease)
Production Data:
Total production (MMcfe)		3,331		4,554		1,223		36.7	%
Average daily production (MMcfe/d)		36.21		49.50	$	13.29		36.7	%
Average Sales Price per Unit (Mcfe):
Excluding hedges	$	5.67	$	6.24	$	0.57		10.1	%
Including hedges		4.56		5.43		0.87		19.1	%
Average Unit Costs per Mcfe:
Oil and gas production costs, including GPT/Ad valorem tax	$	1.65	$	1.60	$	(0.05)		-3.0	%

Pipeline operating, including Ad valorem tax		1.02		1.10		0.08		7.7	%

Depreciation, depletion and amortization		2.36		2.04		(0.32	)	-13.8	%
General and administrative expenses		0.82		0.80		(0.02	)	-1.9	%

Revenues. Oil and gas sales were $28.5 million for the three months ended September 30, 2007 compared to $15.3 million for the three months ended September 30, 2006, an increase of $13.2 million, or 85.9%. The increase in oil and gas sales for the three months ended September 30, 2007 was the result of a

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36.7% increase in sales volumes that was achieved by the addition of more producing wells and an increase in natural gas prices between periods, which was partially offset by the natural decline in production from some of our older gas wells.

Gas pipeline revenue was $1.8 million for the three months ended September 30, 2007 compared to $1.4 million for the three months ended September 30, 2006, an increase of $0.4 million, or 30.3%. The increase was due to the increased volumes flowing through our pipelines and an increase in natural gas prices, which resulted in increased revenues for gas transported on a percentage of proceeds basis.

The additional wells contributed to the production of 4,544,000 net Mcf of gas for the three months ended September 30, 2007, as compared to 3,331,000 net Mcf produced in the same quarter last year. Our product prices on an equivalent basis (Mcfe) increased from $5.67 per Mcfe on average for the three months ended September 30, 2006 to $6.24 per Mcfe on average for the three months ended September 30, 2007.

Operating Expenses. Oil and gas production costs, including gross production tax and ad valorem tax were $7.3 million for the three months ended September 30, 2007, as compared to $5.5 million for the three months ended September 30, 2006, an increase of $1.8 million, or 32.6%. Lease operating costs, excluding gross production tax and ad valorem tax, per Mcfe for the three months ended September 30, 2007, decreased to $1.20 per Mcfe as compared to $1.31 per Mcfe for the three months ended September 30, 2006. The lease operating cost per Mcfe decreased due to reductions in several cost categories, including chemical treatment and third party service units.

Pipeline operating costs increased by approximately 47.2% from $3.4 million for the three months ended September 30, 2006 to $5.0 million for the three months ended September 30, 2007. Pipeline operating costs per Mcf for the three months ended September 30, 2007 and 2006 were $1.10 per Mcf and $1.02 per Mcf, respectively. The cost increases incurred for pipeline operations are due to a number of factors, including: excessively wet summer weather conditions (including flooding) 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.

Depreciation, Depletion and Amortization. For the three months ended September 30, 2007, depreciation, depletion and amortization increased to $9.3 million as compared to $7.9 million for the three months ended September 30, 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. General and administrative expenses increased from $2.7 million for the three months ended September 30, 2006 to $3.7 million for the three months ended September 30, 2007, an increase of $1.0 million, or 34.2%. This increase resulted primarily from a non-cash charge of approximately $976,000 for amortization of equity incentive 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. Interest expense was $8.2 million for the three months ended September 30, 2007 as compared to $7.0 million for the three months ended September 30, 2006, an increase of $1.2 million, or 17.7%. This increase was due to an increase in our outstanding borrowings related to equipment, development and leasehold expenditures and higher average interest rates.

Other Expense. Other expense for the three months ended September 30, 2007 was $5,000 as compared to other income of $4,000 for the three-month period ended September 30, 2006.

Change in Derivative Fair Value. Change in derivative fair value was a non-cash gain of $5.5 million for the three months ended September 30, 2007, which included a $4.7 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 $791,000 relating to hedge ineffectiveness. Change in derivative fair value was a non-cash loss of $332,000 for the three months ended September 30, 2006, which included a $1.3 million loss attributable to the change in fair value for certain derivatives that did not qualify as cash flow hedges pursuant to SFAS 133 and a gain of $998,000 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.

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The following table reflects the results of operations we achieved through the exploration and development activities and the results achieved from Quest Midstream Partners 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 Resource			Quest Midstream			Inter-company
	Corporation			Partners			eliminations			Consolidated
Gas/oil sales	$	28,494		$	—		$	—		$	28,494
Pipeline revenue		—			9,256			(7,468	)		1,788
Other expense		(5	)		—			—			(5	)

Total revenues		28,489			9,256			(7,468	)		30,277


Lease operating cost, including GPT/Ad valorem tax		7,280			—			—			7,280

Transport fee/POE, including Ad valorem tax		7,468			5,004			(7,468	)		5,004
General and administrative cost		2,415			1,238			—			3,653
Depreciation, depletion and amortization		7,978			1,298			—			9,276

Total costs		25,141			7,540			(7,468	)		25,213


Income from operations		3,348			1,716			—			5,064

(Loss)/gain on sale of assets		49			1			—			50
Interest expense		(7,665	)		(541	)		—			(8,206	)
Interest income		102			—			—			102
Change in derivate fair value		5,539			—			—			5,539


Net income before minority interest and income taxes	$	1,373		$	1,176		$	—		$	2,549

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2007

Overview. The following table summarizes our results of operations for the nine months ended September 30, 2006 and 2007.


	Nine Months
	Ended
	September 30,						Increase/
	2006			2007			(Decrease)
	($ in thousands)
Oil and gas sales	$	49,114		$	81,910		$	32,796		66.8	%
Gas pipeline revenue		3,722			5,122			1,400		37.6	%
Other revenue/(expense)		(63	)		(37	)		26		-41.3	%
Oil and gas production costs, including GPT/Ad valorem tax		14,064			22,247			8,183		58.2	%
Pipeline operating expenses, including Ad valorem tax		9,330			14,271			4,941		53.0	%
Depreciation, depletion and amortization		20,643			25,610			4,967		24.1	%
General and administrative expenses		6,596			11,698			5,102		77.3	%
Interest expense		15,885			22,928			7,043		44.3	%
Change in derivative fair value		6,300			5,354			(946	)	-15.0	%

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Production. The following table presents the primary components of our revenues, as well as the average costs per Mcfe, for the nine months ended September 30, 2006 and 2007.


	Nine Months
	Ended
	September 30,				Increase/
	2006		2007		(Decrease)
Production Data:
Total production (MMcfe)		8,718		12,338		3,620		40.6	%
Average daily production (MMcfe/d)		31.93		45.19	$	13.26		41.5	%
Average Sales Price per Unit (Mcfe):
Excluding hedges	$	6.08	$	6.21	$	0.13		2.0	%
Including hedges		4.40		6.61		2.21		50.6	%
Average Unit Costs per Mcfe:
Oil and gas production costs, including GPT/Ad valorem tax	$	1.31	$	1.80	$	0.49		37.6	%
Pipeline operating, including Ad Valorem tax		1.07		1.16		0.09		8.1	%
Depreciation, depletion and amortization		2.37		2.08		(0.29	)	-12.3	%
General and administrative expenses		0.76		0.95		0.19		25.3	%

Revenues. Oil and gas sales were $81.9 million for the nine months ended September 30, 2007 compared to $49.1 million for the nine months ended September 30, 2006, an increase of $32.8 million, or 66.8%. The increase in oil and gas sales for the nine months ended September 30, 2007 resulted from a 40.6% 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.

Gas pipeline revenue was $5.1 million for the nine months ended September 30, 2007 compared to $3.7 million for the nine months ended September 30, 2006, an increase of $1.4 million, or 37.6%. The increase was due to the increased volumes flowing through our pipelines and an increase in natural gas prices, which resulted in increased revenues for gas transported on a percentage of proceeds basis.

The additional wells contributed to the production of 12,338,000 net Mcf of gas for the nine months ended September 30, 2007, as compared to 8,718,000 net Mcf produced in the same nine month period last year. Our product prices on an equivalent basis (Mcfe) increased from $6.08 per Mcfe on average for the nine months ended September 30, 2006 to $6.21 per Mcfe on average for the nine months ended September 30, 2007.

Operating Expenses. Oil and gas production costs including gross production tax and ad valorem tax were $22.2 million for the nine months ended September 30, 2007, as compared to $14.1 million for the nine months ended September 30, 2006, an increase of $8.1 million, or 58%. Lease operating costs excluding gross production tax and ad valorem tax, per Mcfe for the nine months ended September 30, 2007 increased to $1.31 per Mcfe as compared to $1.23 per Mcfe for the nine months ended September 30, 2006. The lease operating cost per Mcfe increased due to a number of factors, including: winter weather and excessively wet spring and summer weather conditions (including flooding) that resulted in a larger percentage of the field labor force being charged to operating expense as compared to capital expenditures, 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, an increase in energy and raw material costs.

Pipeline operating costs increased by approximately 53% from $9.3 million for the nine months ended September 30, 2006 to $14.3 million for the nine months ended September 30, 2007. Pipeline operating costs per Mcf for the nine months ended

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September 30, 2007 increased to $1.16 per Mcf as compared to $1.07 per Mcf for the nine months ended September 30, 2006. The cost increases incurred for pipeline operations are due to a number of factors, including: winter weather and excessively wet spring and summer weather conditions (including flooding) 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.

Depreciation, Depletion and Amortization. For the nine months ended September 30, 2007, depreciation, depletion and amortization increased to $25.6 million as compared to $20.6 million for the nine months ended September 30, 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. General and administrative expenses increased from $6.6 million for the nine months ended September 30, 2006 to $11.7 million for the nine months ended September 30, 2007, an increase of $5.1 million, or 77.3%. This increase resulted primarily from a non-cash charge of approximately $3.9 million for amortization of equity incentive 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. Interest expense was $22.9 million for the nine months ended September 30, 2007 as compared to $15.9 million for the nine months ended September 30, 2006, an increase of $7.0 million, or 44.3%. This increase was due to an increase in our outstanding borrowings related to equipment, development and leasehold expenditures and higher average interest rates.

Other Expense. Other expense for the nine months ended September 30, 2007 was $37,000 as compared to other expense of $63,000 for the nine-month period ended September 30, 2006. The decrease is due to a reduction in overhead and pumper charges.

Change in Derivative Fair Value. Change in derivative fair value was a non-cash gain of $5.4 million for the nine months ended September 30, 2007, which included a $3.3 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 $2.0 million relating to hedge ineffectiveness. Change in derivative fair value was a non-cash gain of $6.3 million for the nine months ended September 30, 2006, which included a $13.3 million gain attributable to the change in fair value for certain derivatives that did not qualify as cash flow hedges pursuant to SFAS 133, a $10.2 million loss due to the contracts not qualifying for hedge accounting treatment, and a gain of $3.2 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.


	Quest Resource			Quest Midstream			Inter-company
	Corporation			Partners			eliminations			Consolidated
Gas/oil sales	$	81,910		$	—		$	—		$	81,910
Pipeline revenue		—			25,761			(20,639	)		5,122
Other expense		(37	)		—			—			(37	)

Total revenues		81,873			25,761			(20,639	)		86,995


Lease operating cost, including GPT/ Ad valorem tax		22,247			—			—			22,247

Transport fee/POE, including Ad valorem tax		20,639			14,271			(20,639	)		14,271
General and administrative cost		8,262			3,436			—			11,698
Depreciation, depletion and amortization		22,041			3,569			—			25,610

Total costs		73,189			21,276			(20,639	)		73,826

Income from operations		8,684			4,485			—			13,169

(Loss)/gain on sale of assets		(147	)		6			—			(141	)
Interest expense		(21,824	)		(1,104	)		—			(22,928	)
Interest income		382			—			—			382
Change in derivate fair value		5,354			—			—			5,354


Net income (loss) before minority interest and income taxes	$	(7,551	)	$	3,387		$	—		$	(4,164	)

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Liquidity and Capital Resources

Liquidity

Our primary sources of liquidity are cash generated from our operations, amounts available under our revolving credit facility and Bluestem’s revolving credit facility and funds from future private and public equity and debt offerings. Please read Note 2 to our consolidated financial statements included in this report for additional information regarding our and Bluestem’s credit facilities, including a description of the financial covenants contained in each of the credit facilities.

At September 30, 2007, we had $23.5 million of availability under our revolving credit facility, which was available to fund the drilling and completion of additional gas wells, the recompletion of single seam wells into multi-seam wells, the acquisition of additional acreage, equipment and vehicle replacement and purchases and the construction of salt water disposal facilities.

At September 30, 2007, Bluestem had $45 million of availability under its revolving credit facility, which was available to fund additional pipeline construction, the connection of additional wells to our pipeline system, pipeline acquisitions and working capital for our pipeline operations. On November 1, 2007, in connection with the acquisition of the KPC pipeline, Quest Midstream Partners and Bluestem entered into an Amended and Restated Credit Agreement, which increased the aggregate commitment under Bluestem’s existing revolving credit facility from $75 million to $135 million. For further information regarding this credit facility, see Note 8. Subsequent Events to the financial statements included in this report and our Current Report on Form 8-K filed with the Securities and Exchange Commission on November 2, 2007. Immediately after the acquisition of the KPC Pipeline, Quest Midstream Partners had $40 million of availability under this credit facility.

At September 30, 2007, we had current assets of $49.3 million. Our working capital (current assets minus current liabilities, excluding the short-term derivative asset and liability of $7.3 million and $6.1 million, respectively) was a deficit of $2.3 million at September 30, 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. Working capital (including the short-term derivative assets and liabilities) was a deficit of $1.1 million as of September 30, 2007. The changes in working capital were primarily due to the use of cash of $112.0 million, substantially all of which was used for capital expenditures, and an increase in accounts payable of $20.5 million due to the expansion of our wells and pipeline development program, which was partially offset by an increase in revenue payable of $1.1 million resulting from higher production volumes and an increase of $1.7 million in receivables. A substantial portion of our production is hedged. We are generally required to settle our commodity hedges on either the 5th or 25th day of each month. As is typical in the gas and oil business, we generally do not receive the proceeds from the sale of the hedged production until around the 25th day of the following month. As a result, when gas and oil prices increase and are above the prices fixed in our derivative contracts, we will be required to pay the hedge counterparty the difference between the fixed price in the hedge and the market price before we receive the proceeds from the sale of the hedged production.

Future Capital Expenditures

During 2007, we intend to focus on drilling and completing up to 558 new wells. We also currently intend to drill approximately 325 wells during 2008. Management currently estimates that it will require for 2007 and 2008 capital investments of:

	•		$76.0 million and $49.5 million, respectively, to drill and complete these wells and recomplete an estimated 80 gross wells in the Cherokee Basin;

	•		$37.0 million and $29.0 million, respectively, for acreage, equipment and vehicle replacement and purchases and salt water disposal facilities in the Cherokee Basin;

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	•		$38.0 million and 25.0 million, respectively, for the pipeline expansion to connect the new wells to our existing gas gathering pipeline network in the Cherokee Basin; and

	•		$3.0 million in 2007 and $4.4 million in 2008 for areas outside of the Cherokee Basin.

In connection with the closing of the Quest Energy Partners initial public offering, Quest Energy Partner’s principal operating subsidiary (Quest Cherokee) will enter into a new 5-year $250 million revolving credit agreement, with an initial borrowing base of $160.0 million, with a syndicate of financial institutions. We anticipated that $75 million will be outstanding under this credit agreement upon the closing of the offering. In addition, we intend to enter into a new 3-year, $50 million revolving credit agreement at the closing of Quest Energy Partners’ initial public offering. We anticipated that approximately $41.5 million will be outstanding under this credit agreement upon the closing of the offering.

Our capital expenditures will consist of, the following:

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

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

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

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

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

We cannot assure you that needed capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness will be limited by covenants in our credit facility and the credit facilities of Quest Midstream Partners and Quest Energy Partners. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves and maintain our pipeline volumes. Please read Note 2 to our consolidated financial statements included in this report for a description of the financial covenants contained in each of the credit facilities. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves.

Cash Flows

Cash Flows from Operating Activities. Net cash provided by operating activities totaled $43.7 million for the nine months ended September 30, 2007 as compared to net cash provided by operations of $24.7 million for the nine months ended September 30, 2006. This increase resulted from a change in derivative fair value, an increase in accounts receivable and accounts payable and an increase in revenue payable and other receivables.

Cash Flows Used in Investing Activities. Net cash used in investing activities totaled $112.4 million for the nine months ended September 30, 2007 as compared to $148.5 million for the nine months ended September 30, 2006. During the nine months ended September 30, 2007, a total of approximately $112.4 million of capital expenditures was invested as follows: $75.4 million was invested in new natural gas wells and properties, $25.6 million in new pipeline facilities, $5.1 million in acquiring leasehold and $6.3 million in other additional capital items.

Cash Flows from Financing Activities. Net cash provided by financing activities totaled $47.9 million for the nine months ended September 30, 2007 as compared to $139.1 million for the nine months ended September 30, 2006, and related to the financing of capital expenditures. The decrease in cash provided from financing activities was due primarily to a $55 million

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increase in borrowings under the Quest Cherokee credit facilities for the nine months ended September 30, 2007 compared to a $125 million increase under the Quest Cherokee credit facilities during the nine months ended September 30, 2006.

Contractual Obligations

Future payments due on our contractual obligations as of September 30, 2007 are as follows:


	Total		2007		2008-2009		2010-2011		thereafter
	($ 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)		25,000		—		—		—		25,000
Credit Facility — Quest Midstream (2)		30,000		—		—		—		30,000
Interest payment Obligation (3)		122,899		7,278		58,177		51,934		5,510
Asset retirement obligation		1,619		—		—		—		1,619
Drilling contractor		5,952		1,711		4,241
Notes payable		176		122		34		12		8
Lease obligations		6,950		219		1,665		1,465		3,601
Derivatives		8,165		6,098		2,067		—		—

Total	$	425,761	$	15,428	$	66,184	$	203,411	$	140,738


(1)		We have a $50 million revolving credit facility that matures on November 14, 2010. As of September 30, 2007, $25 million was borrowed under this facility.

(2)		Quest Midstream Partners has a revolving credit facility that matures on January 31, 2012. As of September 30, 2007, $30 million was borrowed under this facility.

(3)		The interest payment obligation was computed using the LIBOR interest rate as of September 30, 2007. If the interst rate were to change 1%, then the interest payment obligation would change by $11.7 million.

Critical Accounting Policies

Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of our financial statements. We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Our critical accounting policies are available in Item 7 of our Annual Report on Form 10-K/A for the year ended December 31, 2006. There have been no significant changes with respect to these policies during the first nine months of 2007.

Off-Balance Sheet Arrangements

At September 30, 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.

Forward-looking Information

This quarterly report contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about:

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	•		our ability to implement our business strategy;

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

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

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

	•		land issues;

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

	•		labor problems;

	•		environmental related problems;

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

	•		production variances from expectations;

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

	•		disruptions, capacity constraints in or other limitations on our pipeline systems;

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

	•		the need to develop and replace reserves;

	•		competition;

	•		dependence upon key personnel;

	•		the lack of liquidity of our equity securities;

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

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

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

	•		climatic conditions;

	•		natural disasters;

	•		acts of terrorism;

	•		availability and cost of material and equipment;

	•		delays in anticipated start-up dates;

	•		our ability to find and retain skilled personnel;

	•		availability of capital;

	•		the strength and financial resources of our competitors; and

	•		general economic conditions.

All of these types of statements, other than statements of historical fact included in this report, are 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,” “could,” “expect,” “plan,” “anticipates,” “believes,” “estimates,” “predicts,” “potential,” “project,” “intend,” “pursue,” “target” or “continue” or the negative of such terms or other comparable terminology. The forward-looking statements contained in this report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors listed in Item 1A—“Risk Factors” in our annual report on Form 10-K/A for the year ended December 31, 2006 and in Part II, Item 1A in this report. All forward-looking statements speak only as of the date of this report. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

See Note 4 to our consolidated financial statements which are included elsewhere in this report and incorporated by reference.

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Item 4. Controls and Procedures

As of September 30, 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. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective as of such date to provide reasonable assurance that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Controls

There has been no change in our internal control over financial reporting during the quarter ended September 30, 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

See Part I, Item 1, Note 3 to our condensed consolidated financial statements entitled “Commitments and Contingencies”, which is incorporated herein by reference.

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

Item 1A. Risk Factors

Except as set forth below with respect to the pending merger of Pinnacle Gas Resources, Inc. (“Pinnacle”) into one of our subsidiaries, there have not been any material changes from the risk factors previously disclosed in our Form 10-Q for the quarter ended June 30, 2007 in response to Item 1A. to Part II of Form 10-Q.

The value of the consideration received by Pinnacle stockholders will vary with the value of our common stock.

The exchange ratio in the merger is fixed and will not be adjusted in the event of any change in the stock prices of Pinnacle or us prior to the merger. Accordingly, the value of the consideration that Pinnacle stockholders will be entitled to receive pursuant to the merger will depend on the trading price of our common stock. This means that there is no “price protection” mechanism contained in the merger agreement that would adjust the number of shares that Pinnacle stockholders will receive based on any increases or decreases in the trading price of our common stock. If our stock price increases, the market value of the consideration will also increase. Stock price changes may result from a variety of factors, including general market and economic conditions, changes in oil and natural gas prices, changes in our respective businesses, operations and prospects, and regulatory considerations. Many of these factors are beyond our control.

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

We will face significant challenges in consolidating functions and integrating Pinnacle’s and our organizations, procedures and operations within a timely and efficient manner, as well as retaining key personnel. The integration of Pinnacle with us will be complex and time-consuming due to the size and complexity of each organization. The principal challenges will include the following:

	•		integrating Pinnacle’s and our existing businesses;

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

	•		consolidating and integrating duplicative facilities and operations; and

	•		addressing differences in business cultures, preserving employee morale and retaining key employees, while maintaining focus on meeting the operational and financial goals of the combined company.

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Our management will have to dedicate substantial effort to integrating the businesses. These efforts could divert management’s focus and resources from other day-to-day tasks, corporate initiatives or strategic opportunities during the integration process.

We and Pinnacle will incur significant transaction and merger-related integration costs in connection with the merger.

We and Pinnacle expect to pay significant transaction costs. These transaction fees include investment banking, legal and accounting fees and expenses, SEC filing fees, printing expenses, mailing expenses and other related charges, as well as payments to some of Pinnacle’s employees pursuant to change of control agreements. A portion of the transaction costs will be incurred regardless of whether the merger is consummated.

We anticipate that we will incur substantial costs to integrate Pinnacle’s operations with our existing business. We are in the early stages of assessing the magnitude of these costs, and, therefore, are unable at this time to estimate the costs that may be incurred in the integration of Pinnacle’s business with our business.

While the merger is pending, we will be subject to business uncertainties and contractual restrictions that could adversely affect their businesses.

Uncertainty about the effect of the merger on employees, customers and suppliers may have an adverse effect on both us and Pinnacle and, consequently, on the combined company. These uncertainties may impair our and Pinnacle’s ability to attract, retain and motivate key personnel until the merger is consummated and for a period of time thereafter, and could cause customers, suppliers and others who deal with us and Pinnacle to seek to change existing business relationships with us and Pinnacle. Employee retention may be particularly challenging during the pendency of the merger because employees may experience uncertainty about their future roles with the combined company. If, despite our and Pinnacle’s retention efforts, key employees depart because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, the combined company’s business could be seriously harmed. In addition, the merger agreement restricts us and Pinnacle, without the other party’s consent and subject to certain exceptions, from making certain acquisitions and taking other specified actions until the merger occurs or the merger agreement terminates. These restrictions may prevent us and Pinnacle from pursuing otherwise attractive business opportunities and making other changes to our businesses that may arise prior to completion of the merger or termination of the merger agreement.

Failure to complete the merger could negatively impact our stock price and future business and financial results because of, among other things, the disruption that would occur as a result of uncertainties relating to a failure to complete the merger.

Both our stockholders and those of Pinnacle may not approve the merger. If the merger is not completed for any reason, we could be subject to several risks, including the following:

	•		being required to pay Pinnacle a termination fee of up to $3.0 million in certain circumstances;

	•		having had the focus of our management directed toward the merger and integration planning instead of on our core business and other opportunities that could have been beneficial to us; and

	•		incurring substantial transaction costs related to the merger.

In addition, we would not realize any of the expected benefits of having completed the merger.

If the merger is not completed, the price of our common stock may decline to the extent that the current market price of our common stock reflects a market assumption that the merger will be completed and that the related benefits and synergies will be realized, or as a result of the market’s perceptions that the merger were not consummated due to an adverse change in our business. In addition, our business may be harmed, and the price of our stock may decline as a result, to the extent that suppliers and others believe that we cannot compete in the marketplace as effectively without the merger or otherwise remain uncertain about our future prospects in the absence of the merger. Similarly, our current and prospective employees may experience uncertainty about their future roles with the resulting company and choose to pursue other opportunities, which could adversely affect us if the merger is not completed. The realization of any of these risks may materially adversely affect our business, financial results, financial condition and stock price.

The merger agreement limits our ability to pursue an alternative acquisition proposal and require us to pay a termination fee of up to $3.0 million if we do.

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The merger agreement prohibits us from soliciting, initiating or encouraging alternative merger or acquisition proposals with any third party. The merger agreement also provides for the payment by us of a termination fee of up to $3.0 million if the merger agreement is terminated in certain circumstances in connection with a competing acquisition proposal or the withdrawal by our board of directors of its recommendation that our stockholders vote for the adoption of the merger agreement.

These provisions limit our ability to pursue offers from third parties that could result in greater value to our stockholders. The obligation to make the termination fee payment also may discourage a third party from pursuing an alternative acquisition proposal.

The price of Quest’s common stock may experience volatility.

Following the consummation of the merger, the price of our common stock may be volatile. Some of the factors that could affect the price of our common stock are quarterly increases or decreases in revenue or earnings, changes in revenue or earnings estimates by the investment community, our ability to implement our integration strategy and to realize the expected synergies and other benefits from the merger and speculation in the press or investment community about our financial condition or results of operations. General market conditions and U.S. or international economic factors and political events unrelated to our performance may also affect our stock price. For these reasons, investors should not rely on recent trends in the price of our common stock to predict the future price of our common stock or our financial results.

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

None

Item 3. Default Upon Senior Securities

None

Item 4. Submission of Matters to Vote of Security Holders

None.

Item 5. Other Information

None.

Item 6. Exhibits


2.1*		Agreement and Plan of Merger, dated as of October 15, 2007, by and among Quest Resource Corporation, Pinnacle Gas Resources, Inc., and Quest Mergersub, Inc. (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on October 16, 2007).

2.2*		Purchase and Sale Agreement, dated as of October 9, 2007, by and among Enbridge Midcoast Energy, L.P., Midcoast Holdings No. One, L.L.C., and Quest Midstream Partners, L.P. (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on November 2, 2007).

3.1*		Second Amended and Restated Bylaws of Quest Resource Corporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on October 18, 2005).

3.2*		First Amendment to the Second Amended and Restated Bylaws of Quest Resource Corporation (incorporated herein by reference to Exhibit 3.1(b) to the Company’s Current Report on Form 8-K filed on October 17, 2007).

10.1*		Amendment No. 1 to the Midstream Services and Gas Dedication Agreement, dated as of August 9, 2007, by and between Quest Resource Corporation and Bluestem Pipeline, LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 13, 2007).

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10.2*		Employment Agreement dated September 19, 2007 between Quest Midstream GP, LLC and Richard E. Muncrief (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 25, 2007).

10.3*		Support Agreement, dated as of October 15, 2007, by and between Quest Resource Corporation and certain stockholders of Pinnacle Gas Resources, Inc. (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 16, 2007).

10.4*		Purchase Agreement, dated as of October 16, 2007, by and among Quest Midstream Partners, L.P., Quest Midstream GP, LLC, Quest Resource Corporation, Alerian Opportunity Partners IX, L.P., Bel Air MLP Energy Infrastructure Fund, LP, Tortoise Capital Resources Corporation, Tortoise Gas and Oil Corporation, Dalea Partners, LP, Hartz Capital MLP, LLC, ZLP Fund, L.P., KED MME Investment Partners, LP, Eagle Income Appreciation Partners, L.P., Eagle Income Appreciation II, L.P., Citigroup Financial Products, Inc., and The Northwestern Mutual Life Insurance Company (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on November 2, 2007).

10.5*		Amended and Restated Investors’ Rights Agreement, dated as of November 1, 2007, by and among Quest Midstream Partners, L.P., Quest Midstream GP, LLC, Quest Resource Corporation, Alerian Opportunity Partners IV, L.P., Swank MLP Convergence Fund, LP, Swank Investment Partners, LP, The Cushing MLP Opportunity Fund I, LP, The Cushing GP Strategies Fund, LP, Tortoise Capital Resources Corporation, Alerian Opportunity Partners IX, L.P., Bel Air MLP Energy Infrastructure Fund, LP, Tortoise Gas and Oil Corporation, Dalea Partners, LP, Hartz Capital MLP, LLC, ZLP Fund, L.P., KED MME Investment Partners, LP, Eagle Income Appreciation Partners, L.P., Eagle Income Appreciation II, L.P., Citigroup Financial Products, Inc., and The Northwestern Mutual Life Insurance Company (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on November 2, 2007).

10.6*		Second Amended and Restated Agreement of Limited Partnership of Quest Midstream Partners, L.P., dated as of November 1, 2007, by and among Quest Midstream GP, LLC, Quest Resource Corporation, Alerian Opportunity Partners IV, L.P., Swank MLP Convergence Fund, LP, Swank Investment Partners, LP, The Cushing MLP Opportunity Fund I, LP, The Cushing GP Strategies Fund, LP, Tortoise Capital Resources Corporation, Alerian Opportunity Partners IX, L.P., Bel Air MLP Energy Infrastructure Fund, LP, Tortoise Gas and Oil Corporation, Dalea Partners, LP, Hartz Capital MLP, LLC, ZLP Fund, L.P., KED MME Investment Partners, LP, Eagle Income Appreciation Partners, L.P., Eagle Income Appreciation II, L.P., Citigroup Financial Products, Inc., and The Northwestern Mutual Life Insurance Company (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on November 2, 2007).

10.7*		First Amendment to Registration Rights Agreement, dated as of November 1, 2007, by and among Quest Midstream Partners, L.P., Quest Resource Corporation, Alerian Opportunity Partners IV, L.P., Swank MLP Convergence Fund, LP, Swank Investment Partners, LP, The Cushing MLP Opportunity Fund I, LP, The Cushing GP Strategies Fund, LP, Tortoise Capital Resources Corporation, Alerian Opportunity Partners IX, L.P., Bel Air MLP Energy Infrastructure Fund, LP, Tortoise Gas and Oil Corporation, Dalea Partners, LP, Hartz Capital MLP, LLC, ZLP Fund, L.P., KED MME Investment Partners, LP, Eagle Income Appreciation Partners, L.P., Eagle Income Appreciation II, L.P., Citigroup Financial Products, Inc., and The Northwestern Mutual Life Insurance Company (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on November 2, 2007).

10.8*		Amended and Restated Credit Agreement, dated as of November 1, 2007, by and among Quest Midstream Partners, L.P., Bluestem Pipeline, LLC, Royal Bank of Canada, RBC Capital Markets and the Lenders party thereto (incorporated herein by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on November 2, 2007).

10.9		Guaranty by Quest Kansas General Partner, L.L.C., Quest Kansas Pipeline, L.L.C., and Quest Pipeline (KPC) in favor of Royal Bank of Canada, dated as of November 1, 2007.

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10.10		Pledge and Security Agreement by Quest Kansas General Partner, L.L.C. in favor of Royal Bank of Canada, dated as of November 1, 2007.

10.11		Pledge and Security Agreement by Quest Kansas Pipeline, L.L.C. in favor of Royal Bank of Canada, dated as of November 1, 2007.

10.12		Pledge and Security Agreement by Quest Pipelines (KPC) in favor of Royal Bank of Canada, dated as of November 1, 2007.

10.13		Amended and Restated Pledge and Security Agreement by Bluestem Pipeline, LLC in favor of Royal Bank of Canada, dated as of November 1, 2007.

10.14		Amended and Restated Pledge and Security Agreement by Quest Midstream Partners, L.P. in favor of Royal Bank of Canada, dated as of November 1, 2007.

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

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

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

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

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


*		Incorporated by reference

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


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

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PART I — FINANCIAL INFORMATION			3

Item 1. Financial Statements			3

Condensed Consolidated Balance Sheets: December 31, 2006 and September 30, 2007			F-1

Condensed Consolidated Statements of Operations and Comprehensive Income: Three Months and Nine Months Ended September 30, 2006 and 2007			F-2

Condensed Consolidated Statements of Cash Flows: Nine Months Ended September 30, 2006 and 2007			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			13

Item 4. Controls and Procedures			14

PART II — OTHER INFORMATION			14

Item 1. Legal Proceedings			14

Item 1A. Risk Factors			14

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			16

Item 3. Defaults Upon Senior Securities			16

Item 4. Submission of Matters to a Vote of Security Holders			16

Item 5. Other Information			16

Item 6. Exhibits			16

SIGNATURES			19
Guaranty
Pledge and Security Agreement
Pledge and Security Agreement
Pledge and Security Agreement
Amended and Restated Pledge and Security Agreement
Amended and Restated Pledge and Security Agreement
Statement Re: Computaion of Ratios of Earnings to Combined Fixed Charges
Certification by Chief Executive Officer Pursuant to Rule 13a-14(a)
Certification by Chief Financial Officer Pursuant to Rule 13a-14(a)
Certification by Chief Executive Officer Pursuant to Section 906
Certification by Chief Financial Officer Pursuant to Section 906