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

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

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

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

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

As of August 7, 2007, the issuer had 22,222,474 shares of common stock outstanding.

This Form 10-Q/A-1 (Amendment No. 1) is being filed by Quest Resource Corporation to amend its Form 10-Q for the fiscal quarter ended June 30, 2007, filed with the Securities and Exchange Commission on August 9, 2007. This Amendment No. 1 reflects revisions to the discussion regarding results of operations located in Part I - Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Except as otherwise required by the context, references in this quarterly report to "we," "our," "us," "Quest" or "the Company" refer to Quest Resource Corporation and its subsidiaries: Quest Cherokee, LLC; Quest Cherokee Oilfield Service, LLC; Bluestem Pipeline, LLC; Quest Midstream Partners, L.P.; Quest Midstream GP, LLC; Quest Oil & Gas, LLC; Ponderosa Gas Pipeline Company, LLC; Quest Energy Service, LLC; STP Cherokee, LLC; Producers Service, LLC; and J-W Gas Gathering, L.L.C. Our operations are primarily conducted through Quest Cherokee, LLC, Quest Cherokee Oilfield Service, LLC, Bluestem Pipeline, LLC and Quest Energy Service, LLC.

Our unaudited interim financial statements, including balance sheets as of December 31, 2006 and June 30, 2007, a statement of operations and comprehensive income for the three month and six month periods ended June 30, 2006 and 2007, and a statement of cash flows for the six month periods ended June 30, 2006 and 2007, and the notes thereto are attached hereto as Pages F-1 through F-16 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.

		December 31, 2006			June 30, 2007
					(unaudited)
Current assets:
Cash	$	41,820		$	16,198
Restricted cash		1,150			1,191
Accounts receivable, trade		9,840			12,442
Other receivables		371			1,509
Other current assets		1,068			1,865
Inventory		5,632			9,038
Short-term derivative asset		10,795			6,302
Total current assets		70,676			48,545

Property and equipment, net of accumulated depreciation of $5,561 and $5,107		16,212			19,622

Pipeline assets, net of accumulated depreciation of $8,375 and $6,104		127,690			133,825
Pipeline assets under construction		880			7,563

Oil and gas properties:
Properties being amortized		316,780			359,704
Properties not being amortized		9,545			13,706
		326,325			373,410
Less: Accumulated depreciation, depletion and amortization		(92,732	)		(106,646	)
Net oil and gas properties		233,593			266,764
Other assets, net		9,467			11,134
Long-term derivative asset		4,782			1,843
Total assets	$	463,300		$	489,296

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable	$	14,778		$	21,462
Revenue payable		4,540			7,063
Accrued expenses		2,525			1,831
Current portion of notes payable		324			179
Short-term derivative liability		5,244			6,814
Total current liabilities		27,411			37,349

Non-current liabilities:
Long-term derivative liability		7,449			4,198
Asset retirement obligation		1,410			1,546
Notes payable		225,569			255,270
Less current maturities		(324	)		(179	)
Non-current liabilities		234,104			260,835
Total liabilities		261,515			298,184
Minority interest		84,431			84,387
Commitments and contingencies
Stockholders' equity:
10% convertible preferred stock, $.001 par value, 50,000,000 shares authorized,
0 shares issued and outstanding at June 30, 2007 and December 31, 2006
Common stock, $.001 par value, 200,000,000 shares authorized and 22,222,474
shares issued and outstanding at June 30, 2007 and
22,206,014 shares issued and outstanding at December 31, 2006		22			22
Additional paid-in capital		205,994			208,731
Accumulated other comprehensive income (loss)		428			(5,140	)
Accumulated deficit		(89,090	)		(96,888	)
Total stockholders' equity		117,354			106,725
Total liabilities and stockholders' equity	$	463,300		$	489,296

	For the Three						For the Six
	Months Ended June 30,						Months Ended June 30,
	2006			2007			2006			2007
Revenue:
Oil and gas sales	$	15,306		$	27,867		$	33,785		$	53,416
Gas pipeline revenue		1,268			1,792			2,350			3,334
Other revenue (expense)		(30	)		(19	)		(65	)		(32	)
Total revenues		16,544			29,640			36,070			56,718

Costs and expenses:
Oil and gas production		4,644			7,740			8,572			14,967
Pipeline operating		3,061			4,333			5,930			9,267
General and administrative		2,351			5,407			3,873			8,045
Depreciation, depletion and amortization		6,869			8,471			12,768			16,334
Total costs and expenses		16,925			25,951			31,143			48,613

Operating income (loss)		(381	)		3,689			4,927			8,105

Other income (expense):
Change in derivative fair value		(445	)		279			6,630			(185	)
(Loss)/gain on sale of assets		23			(298	)		43			(191	)
Interest income		113			103			249			280
Interest expense		(5,090	)		(7,610	)		(8,912	)		(14,723	)
Total other income (expense)		(5,399	)		(7,526	)		(1,990	)		(14,819	)

Income (loss) before minority interest and income taxes		(5,780	)		(3,837	)		2,937			(6,714	)
Minority interest in consolidated subsidiary		—			(650	)		—			(1,084	)
Net income (loss) before income taxes		(5,780	)		(4,487	)		2,937			(7,798	)
Income tax expense – deferred		—			—			—			—
Net income (loss)		(5,780	)		(4,487	)		2,937			(7,798	)

Other comprehensive income (loss), net of tax:
Change in fixed-price contract and other derivative fair value, net of tax of $0 and $0		9,444			8,341			19,507			(4,145	)
Reclassification adjustments – contract settlements, net of tax of $0 and $0		663			(428	)		663			(1,423	)
Other comprehensive income (loss)		10,107			7,913			20,170			(5,568	)
Comprehensive income (loss)	$	4,327		$	3,426		$	23,107		$	(13,366	)

Earnings (loss) per common share – basic	$	(0.26	)	$	(0.20	)	$	0.13		$	(0.35	)

Earnings (loss) per common share – diluted	$	(0.26	)	$	(0.20	)	$	0.13		$	(0.35	)

Weighted average common and common equivalent shares:
Basic		22,074,631			22,217,048			22,073,513			22,211,561
Diluted		22,074,631			22,217,048			22,134,156			22,211,561

	For the Six Months Ended June 30,
		2006				2007

Cash flows from operating activities:
Net income (loss)	$		2,937		$		(7,798	)
Adjustments to reconcile net income (loss) to cash provided by operations:
Depreciation and depletion			14,647				17,747
Change in derivative fair value			(16,864	)			185
Stock issued for retirement plan			428				—
Stock options granted for directors fees			239				144
Stock awards granted to employees			254				2,874
Amortization of loan origination fees			547				1,115
Amortization of gas swap fees			83				125
Amortization of deferred hedging gains			(275	)			—
(Gain) loss on sale of assets			(43	)			234
Minority interest			—				1,084
Change in assets and liabilities:
Restricted cash			3,169				(10	)
Accounts receivable			2,735				(2,602	)
Other receivables			10				(1,137	)
Other current assets			(286	)			(796	)
Inventory			(1,341	)			(2,302	)
Accounts payable			7,406				1,926
Revenue payable			(2,019	)			2,524
Accrued expenses			1,634				(690	)
Net cash provided by operating activities			13,261				12,623

Cash flows from investing activities:
Additions to equipment, development and leasehold costs			(98,997	)			(58,114	)
Net additions to other property and equipment			(4,915	)			(5,158	)
Net cash used in investing activities			(103,912	)			(63,272	)

Cash flows from financing activities:
Proceeds from bank borrowings			125,170				30,000
Change in other long-term liabilities			—				80
Repayments of note borrowings			(226	)			(299	)
Syndication costs paid			(386	)			(48	)
Cash distributions to QMP unit holders			—				(1,809	)
Refinancing costs			(1,105	)			(2,897	)
Net cash provided by financing activities			123,453				25,027

Net increase (decrease) in cash			32,802				(25,622	)
Cash, beginning of period			2,559				41,820
Cash, end of period	$		35,361		$		16,198

Supplemental disclosure of cash flow information
Cash paid during the period for:
Interest expense	$		7,556		$		12,729
Income taxes	$		—		$		—

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 six months ended June 30, 2006. Two purchasers, ONEOK and Tenaska, accounted for approximately 72% and 28%, respectively, of our natural gas and oil revenues for the six months ended June 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.

During the three months ended June 30, 2006 and 2007, depreciation totaling $205,000 and $231,000, respectively, was capitalized in the full cost pool. During the six months ended June 30, 2006 and 2007, depreciation totaling $409,000 and $481,000, respectively, was capitalized in the full cost pool.

Included in other assets are costs associated with bank credit facilities. The remaining unamortized debt issue costs at December 31, 2006 and June 30, 2007 totaled $9.1 million and $10.9 million, respectively, and are being amortized over the life of the credit facilities.

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 six months ended June 30, 2006 and 2007.

The effective tax rate for the six months ended June 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 July 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 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 Awards. The Company granted shares of common stock to certain employees in October 2005, October, November and December, 2006, February, March, April and May, 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.

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.

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

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

In June 2006, the FASB issued 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.

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 June 30, 2007:

As of June 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 June 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 June 30, 2007, the Company's weighted average interest rates under the credit facilities were as follows.

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.

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.

Bluestem has a separate $75 million syndicated revolving credit facility. The credit facility is guaranteed by Quest Midstream. Royal Bank of Canada is the administrative agent and collateral agent. As of June 30, 2007, $20 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 June 30, 2007, the weighted average interest rate under the credit facility was 7.69%.

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

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

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

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

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

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.

As of June 30, 2007, $270,000 of notes payable to banks and finance companies were outstanding. These notes are secured by equipment and vehicles, with payments due in monthly installments through October 2013 with interest rates ranging from 1.9% to 11.7% per annum.

The Company, Quest Cherokee, STP, Bluestem, Quest Energy Service, Inc. ("QES"), Quest Midstream 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 have 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 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, but the Kansas Supreme Court has not yet set the matter for oral argument.

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 August 7, 2007, the total amount of acreage covered by the leases at issue in these lawsuits was approximately 7,300 acres. Quest Cherokee contends that it has complied with the terms of these oil and gas leases and that they remain in full force and effect. Quest Cherokee intends to vigorously defend against the claims.

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

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, and by allocating certain expenses to plaintiffs' interests. 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.

The Company seeks to reduce its exposure to unfavorable changes in natural gas prices, which are subject to significant and often volatile fluctuation, through the use of fixed-price contracts. The fixed-price contracts are comprised of energy swaps, collars and basis swaps. These contracts allow the Company to predict with greater certainty the effective natural gas prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. Collar structures provide for participation in price increases and decreases to the extent of the ceiling and floor prices provided in those contracts. For the six months ended June 30, 2006 and 2007, fixed-price contracts hedged 68.5% and 68.2%, respectively, of the Company's natural gas production. As of June 30, 2007, fixed-price contracts were in place to hedge 20.3 Bcf of estimated future natural gas production. Of this total volume, 5.4 Bcf are hedged for 2007 and 14.9 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.

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

	Six Months Ending
		December 31,			Years Ending December 31,
		2007			2008			2009		Total
		(dollars in thousands, except per MMBtu data)
Natural Gas Swaps:
Contract vols (MMBtu)			1,187,000			2,332,000			9,999,000		13,518,000
Weighted-avg fixed
price per MMBtu (1)		$	7.20		$	7.35		$	7.85	$	7.70
Fixed-price sales		$	8,544		$	17,141		$	78,451	$	104,136
Fair value, net		$	884		$	35		$	25	$	944

Natural Gas Collars:
Contract vols (MMBtu)
Floor			4,251,000			7,028,000			—		11,279,000
Ceiling			4,251,000			7,028,000			—		11,279,000
Weighted-avg fixed
price per MMBtu (1)
Floor		$	6.63		$	6.54			—	$	6.57
Ceiling		$	7.54		$	7.54			—	$	7.54
Fixed-price sales (2)		$	28,174		$	45,973			—	$	74,147
Fair value, net		$	(1,418	)	$	(2,447	)		—	$	(3,865	)

Total Natural Gas Contracts(3):
Contract vols (MMBtu)			5,438,000			9,360,000			9,999,000		24,797,000
Weighted-avg fixed
price per MMBtu (1)		$	6.75		$	6.74		$	7.85	$	7.19
Fixed-price sales (2)		$	36,718		$	63,114		$	78,451	$	178,283
Fair value, net		$	(534	)	$	(2,412	)	$	25	$	(2,921	)

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 June 30, 2006 and 2007, oil and gas sales included a loss of $663,000 and a gain of $427,000, respectively, associated with realized gains and losses under fixed-price contracts. For the six months ended June 30, 2006 and 2007, oil and gas sales included a loss of $663,000 and a gain of $1.4 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 June 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 $8.2 million.

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

For interest rate caps qualifying as cash flow hedges, changes in fair value of the derivative contracts are shown as adjustments to other comprehensive income. For those interest rate caps not qualifying as cash flow hedges, changes in fair value of the derivative contracts are recognized in change in derivative fair value in the statement of operations. All changes in fair value of the Company's interest rate caps are reported in results of operations rather than in other comprehensive income because the critical terms of the interest rate caps do not comply with certain requirements set forth in SFAS 133. The fair value of all interest rate caps are recorded as assets or liabilities in the balance sheet. Based upon market prices at June 30, 2007, the estimated amount of unrealized gains for interest rate caps shown as adjustments to change in derivative fair value in the statement of operations that are expected to be reclassified into earnings as actual contract cash settlements are realized within the next 12 months is $63,000.

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

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

The change in carrying value of interest rate caps in the balance sheet since December 31, 2006 resulted from an increase in interest rates. 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.

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

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

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 based on the Southern Star Central TX/KS/OK ("Southern Star") first of month index, with a small portion being sold based on the daily price on the Southern Star index. The difference between natural gas prices on the NYMEX and the price actually received by the Company is referred to as a basis differential. Typically, the price for natural gas on the Southern Star first of the month index is less than the price on the NYMEX due to the more limited demand for natural gas on the Southern Star first of the month index.

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

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

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

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

The fair value of all derivative contracts as of June 30, 2007 and December 31, 2006 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 June 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.

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

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

	Income			Shares	Per Share
	(Numerator)			(Denominator)	Amount

For the three months ended June 30, 2006:
Net loss	$	(5,780	)
Preferred stock dividends		—
Basic EPS loss available to common shareholders	$	(5,780	)	22,074,631	$	(0.26	)
Effect of dilutive securities:
Stock options				—
Stock awards		—		—

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

For the three months ended June 30, 2007:
Net loss	$	(4,487	)
Preferred stock dividends		—
Basic EPS available to common shareholders	$	(4,487	)	22,217,048	$	(0.20	)
Effect of dilutive securities:

None		—		—

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

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

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

For the six months ended June 30, 2007:
Net loss	$	(7,798	)
Preferred stock dividends		—
Basic EPS available to common shareholders	$	(7,798	)	22,211,561	$	(0.35	)
Effect of dilutive securities:
None		—		—

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

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

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

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

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

During the three months ended June 30, 2007, the partnership made $1.8 million in distributions to the common unit holders.

On July 19, 2007, the Company's wholly-owned subsidiary, Quest Energy Partners, L.P. ("Quest Energy"), filed a registration statement with the Securities and Exchange Commission for an initial public offering of 8,750,000 common units, representing a 37.0% limited partner interest in it (or 10,062,500 common units, representing a 42.6% limited partner interest, if the underwriters exercise their overallotment option in full). If the offering is completed, Quest Energy will own substantially all of the Company's natural gas and oil exploration and production assets. Quest Energy GP, LLC, a wholly-owned subsidiary of the Company, is the general partner of Quest Energy and will conduct the business and manage the operations of Quest Energy. Pursuant to a management services agreement, Quest Energy Service, LLC, a wholly-owned subsidiary of the Company, will provide legal, accounting, finance, tax, property management, engineering, risk management and acquisition services to Quest Energy.

Beginning with the quarterly period in which the initial public offering of Quest Energy is completed, the Company will consolidate the results of Quest Energy with minority interest treatment for the common units of Quest Energy owned by unitholders other than the Company.

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.

During the first six months of 2007, we continued to be focused on drilling and completing new wells. We drilled 260 gross wells and completed the connection of 251 gross wells during this period. As of June 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 six months, we completed 34 re-completions.

We completed 140 miles of pipeline infrastructure expansion and had a net increase in total number of acres of 25,252 (net) that we leased under natural gas leases.

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 July 19, 2007, the Company's wholly-owned subsidiary, Quest Energy Partners, L.P. ("Quest Energy"), filed a registration statement with the Securities and Exchange Commission for an initial public offering of 8,750,000 common units, representing a 37.0% limited partner interest in it (or 10,062,500 common units, representing a 42.6% limited partner interest, if the underwriters exercise their overallotment option in full). If the offering is completed, Quest Energy will own substantially all of the Company's natural gas and oil exploration and production assets. Quest Energy GP, LLC, a wholly-owned subsidiary of the Company, is the general partner of Quest Energy and will conduct the business and manage the operations of Quest Energy. Pursuant to a management services agreement, Quest Energy Service, a wholly-owned subsidiary of the Company, will provide legal, accounting, finance, tax, property management, engineering, risk management and acquisition services to Quest Energy. We currently anticipate that the net proceeds from the offering would be used to repay a portion of our existing indebtedness outstanding under our credit facilities.

The following discussion is based on the consolidated operations of all our subsidiaries and should be read in conjunction with the financial statements included in this report; and should further be read in conjunction with the audited financial statements and notes thereto included in our annual report on Form 10-K/A for the year ended December 31, 2006. Comparisons made between reporting periods herein are for the three and six month periods ended June 30, 2006 as compared to the same period in 2007.

Revenues. Total revenues were $29.6 million for the three months ended June 30, 2007 compared to $16.5 million for the three months ended June 30, 2006, an increase of $13.1 million, or 79%. Total revenues for the three months ended June 30, 2007 include a $427,000 gain on settlements of gas hedges. The three months ended June 30, 2006 includes a $3.5 million loss on settlements of gas hedges. The settlements for both periods were recorded against gas sales as those hedge contracts did qualify for hedge accounting treatment during the respective periods. Excluding this loss, total revenues for the first three months of 2006 were $20.0 million. Excluding the settlements on gas hedges, the increase in revenue for the three months ended June 30, 2007 was the result of a 41.2% 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.

The additional wells contributed to the production of 4,079,000 net Mcf of gas for the three months ended June 30, 2007, as compared to 2,889,000 net Mcf produced in the same quarter last year. Our product prices on an equivalent basis (Mcfe) increased from $5.57 Mcfe on average for the three months ended June 30, 2006 to $6.70 Mcfe on average for the three months ended June 30, 2007. For the three months ended June 30, 2007, the net product price, after accounting for the gain on hedging settlements of $427,000, averaged $6.81 Mcfe. For the three months ended June 30, 2006, the net product price, after accounting for the loss on hedge settlements of $3.5 million, averaged $4.33 Mcfe.

Operating Expenses. Oil and gas production costs were $7.7 million for the three months ended June 30, 2007 as compared to $4.6 million for the three months ended June 30, 2006, an increase of $3.1 million, or 67.4%. Lease operating costs per Mcfe for the three months ended June 30, 2007 increased to $1.36 per Mcfe as compared to $1.26 per Mcfe for the three months ended June 30, 2006. The lease operating cost per Mcfe increased due to a number of factors, including: 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 and an increase in property taxes due to both the increase in the number of properties that we own and an increase in property tax rates.

Pipeline operating costs increased by approximately 42% from $3.0 million for the three months ended June 30, 2006 to $4.3 million for the three months ended June 30, 2007. Pipeline operating costs per Mcf for the three months ended June 30, 2007 and 2006 were $0.88 per Mcf and $1.06 per Mcf, respectively.

For the three months ended June 30, 2007, depreciation, depletion and amortization increased to $8.5 million as compared to $6.9 million for the three months ended June 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 $2.4 million for the three months ended June 30, 2006 to $5.4 million for the three months ended June 30, 2007, an increase of $3.0 million, or 125%. This increase resulted primarily from a non-cash charge of approximately $2.5 million for amortization of stock awards. The remainder of the increase is due to an increase in staff personnel, legal, accounting and professional fees related to the increased size and complexity of our operations.

Interest Expense. Interest expense was $7.6 million for the three months ended June 30, 2007 as compared to $5.1 million for the three months ended June 30, 2006, an increase of $2.5 million, or 49.0%. 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 June 30, 2007 was $19,000 as compared to other expense of $30,000 for the three-month period ended June 30, 2006.

Change in Derivative Fair Value. Change in derivative fair value was a non-cash gain of $279,000 for the three months ended June 30, 2007, which included a $285,000 loss attributable to the change in fair value for certain derivatives that did not qualify as cash flow hedges pursuant to SFAS 133 and a gain of $564,000 relating to hedge ineffectiveness. Change in derivative fair value was a non-cash loss of $445,000 for the three months ended June 30, 2006, which included a $1.3 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 $1.1 million relating to hedge ineffectiveness. Amounts recorded in this caption represent non-cash gains and losses created by valuation changes in derivatives that are not entitled to receive hedge accounting. All amounts recorded in this caption are ultimately reversed in this caption over the respective contract term.

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


Lease operating cost		5,638			—			—			5,638
GPT/ad valorem tax		2,103			690			—			2,793
Transport fee/POE		6,809			3,642			(6,809	)		3,642
General and administrative cost		4,094			1,313			—			5,407
Depreciation, depletion and amortization		7,326			1,145			—			8,471
Total costs		25,970			6,790			(6,809	)		25,951

Income from operations		1,878			1,811			—			3,689

(Loss)/gain on sale of assets		(304	)		6			—			(298)
Interest expense		(7,190	)		(420	)		—			(7,610	)
Interest income		103			—			—			103
Change in derivate fair value		279			—			—			279

Net income (loss)	$	(5,234	)	$	1,397		$	—		$	(3,837	)

Revenues. Total revenues were $56.7 million for the six months ended June 30, 2007 compared to $36.1 million for the six months ended June 30, 2006, an increase of $20.6 million, or 57%. Total revenues for the six months ended June 30, 2007 include a $1.4 million gain on settlements of gas hedges. The six months ended June 30, 2006 includes a $10.9 million loss on settlements of gas hedges. The settlements were recorded against gas sales as those hedge contracts did qualify for hedge accounting treatment during the six months ended 2006. Excluding this loss, total revenues for the six months ended June 30, 2006 were $46.9 million. Excluding the settlements on gas hedges, the increase in revenue for the six months ended June 30, 2007 resulted from a 45.6% 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.

The additional wells contributed to the production of 7,842,000 net Mcf of gas for the six months ended June 30, 2007, as compared to 5,387,000 net Mcf produced in the same six month period last year. Our product prices on an equivalent basis (Mcfe) increased from $6.40 Mcfe on average for the six months ended June 30, 2006 to $6.60 Mcfe on average for the six months ended June 30, 2007. For the six months ended June 30, 2007, the net product price, after accounting for the gain on hedging settlements of $1.4 million during the six months, averaged $6.79 Mcfe. For the six months ended June 30, 2006, the net product price, after accounting for the loss on hedge settlements of $10.9 million during the six months, averaged $4.37 Mcfe.

Operating Expenses. Oil and gas production costs were $15.0 million for the six months ended June 30, 2007 as compared to $8.6 million for the six months ended June 30, 2006, an increase of $6.4 million, or 74.4%. Lease operating costs per Mcfe for the six months ended June 30, 2007 increased to $1.39 per Mcfe as compared to $1.18 per Mcfe for the six months ended June 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 and an increase in property taxes due to both the increase in the number of properties that we own and an increase in property tax rates.

Pipeline operating costs increased by approximately 56% from $5.9 million for the six months ended June 30, 2006 to $9.3 million for the six months ended June 30, 2007. Pipeline operating costs per Mcf for the six months ended June 30, 2007 increased to $1.18 per Mcf as compared to $1.10 per Mcf for the six months ended June 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.

For the six months ended June 30, 2007, depreciation, depletion and amortization increased to $16.3 million as compared to $12.8 million for the six months ended June 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 $3.9 million for the six months ended June 30, 2006 to $8.0 million for the six months ended June 30, 2007, an increase of $4.1 million, or 130.8%.

This increase resulted primarily from a non-cash charge of approximately $2.9 million for amortization of stock awards. The remainder of the increase is due to an increase in staff personnel, legal, accounting and professional fees related to the increased size and complexity of our operations.

Interest Expense. Interest expense was $14.7 million for the six months ended June 30, 2007 as compared to $8.9 million for the six months ended June 30, 2006, an increase of $5.8 million, or 65.2%. 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 six months ended June 30, 2007 was $32,000 as compared to other expense of $65,000 for the six-month period ended June 30, 2006.

Change in Derivative Fair Value. Change in derivative fair value was a non-cash loss of $185,000 for the six months ended June 30, 2007, which included a $1.3 million loss attributable to the change in fair value for certain derivatives that did not qualify as cash flow hedges pursuant to SFAS 133 and a gain of $1.1 million relating to hedge ineffectiveness. Change in derivative fair value was a non-cash gain of $6.6 million for the six months ended June 30, 2006, which included a $14.6 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 $2.2 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			Quest			Inter-
	Resource			Midstream			company
	Corporation			Partners			eliminations			Consolidated
Gas/oil sales	$	53,416		$	—		$	—		$	53,416
Pipeline revenue		—			16,504			(03,170	)		3,334
Other expense		(32	)		—			—			(32	)
Total revenues		53,384			16,504			(13,170	)		56,718

Lease operating cost		10,898			—			—			10,898
GPT/ad valorem tax		4,069			1,380			—			5,449
Transport fee/POE		13,170			7,887			(13,170	)		7,887
General and administrative cost		5,846			2,199			—			8,045
Depreciation, depletion and amortization		14,063			2,271			—			16,334
Total costs		48,046			13,737			(13,170	)		48,613

Income from operations		5,338			2,767			—			8,105

(Loss)/gain on sale of assets		(197	)		6			—			(191	)
Interest expense		(14,161	)		(562	)		—			(14,723	)
Interest income		280			—			—			280
Change in derivate fair value		(185	)		—			—			(185	)

Net income (loss)	$	(8,925	)	$	2,211		$	—		$	(6,714	)

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 June 30, 2007, we had $38.5 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 June 30, 2007, Bluestem had $55 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.

At June 30, 2007, we had current assets of $48.5 million. Our working capital (current assets minus current liabilities, excluding the short-term derivative asset and liability of $6.3 million and $6.8 million, respectively) was $11.7 million at June 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 $11.7 million as of June 30, 2007. The changes in working capital were primarily due to the use of cash of $63.3 million, substantially all of which was used for capital expenditures, and an increase in accounts payable of $1.9 million due to the expansion of our wells and pipeline development program, which was partially offset by an increase in revenue payable of $2.5 million resulting from higher production volumes and an increase of $3.2 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.

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:

Management currently estimates that it will be able to drill and develop the approximately 558 new wells planned for 2007 utilizing cash flow from operations, remaining cash from the sale of Quest Midstream common units in December 2006, borrowings available under our revolving credit facility and/or the sale of additional debt or equity securities (including offerings of securities by Quest Midstream or Quest Energy). In addition, in the near term, we intend to fund additional pipeline expansion to connect these new wells to our gas gathering system with borrowings under Bluestem's revolving credit facility. The Company intends to finance capital expenditures during 2008 utilizing a combination of cash flow from operations, additional borrowings, offerings of debt or equity securities (including offerings of securities by Quest Midstream or Quest Energy), joint venture partnerships, production payment financings, asset sales, 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 is limited by covenants in credit facilities. 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 from Operating Activities. Net cash provided by operating activities totaled $12.6 million for the six months ended June 30, 2007 as compared to net cash provided by operations of $13.3 million for the six months ended June 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 $63.3 million for the six months ended June 30, 2007 as compared to $103.9 million for the six months ended June 30, 2006. During the six months ended June 30, 2007, a total of approximately $63.3 million of capital expenditures was invested as follows: $39.2 million was invested in new natural gas wells and properties, $11.5 million in new pipeline facilities, $7.5 million in acquiring leasehold and $5.1 million in other additional capital items.

Cash Flows from Financing Activities. Net cash provided by financing activities totaled $25.0 million for the six months ended June 30, 2007 as compared to $123.5 million for the six months ended June 30, 2006, and related to the financing of capital expenditures. The decrease in cash provided from financing activities was due primarily to a $10

million increase in the Quest Cherokee revolver for the six months ended June 30, 2007 compared to a $125 million increase in the Quest Cherokee revolver during the six months ended June 30, 2006.

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

	Total		2007		2008-2009		2010-2011		thereafter
	(dollars in thousands)
First Lien Term Note	$	50,000	$	—	$	—	$	50,000	$	—
Second Lien Term Note		100,000		—		—		100,000		—
Third Lien Term Note		75,000		—		—		—		75,000
Revolver – Quest (1)		10,000								10,000
Credit Facility – Quest
Midstream (2)		20,000								20,000
Asset retirement obligation		1,546								1,546
Drilling contractor		7,663		3,422		4,241
Notes payable		270		179		69		13		9
Lease obligations		754		123		403		202		26
Derivatives		11,012		6,814		4,198		—		—
Total	$	276,245	$	10,538	$	8,911	$	150,215	$	106,581

(1) We have a $50 million revolving credit facility that matures on November 14, 2010. As of June 30, 2007, $10 million was borrowed under this facility.

(2) Quest Midstream has a revolving credit facility that matures on January 31, 2012. As of June 30, 2007, $20 million was borrowed under this facility.

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 six months of 2007.

At June 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.

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:

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.

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

As of June 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.

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

See Part I, Item 1, Note 3 to our 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.

In connection with the filing of the registration statement on Form S-1 for Quest Energy Partners, L.P., we have updated the Risk Factors related to our business appearing in Part 1, Item 1A. Risk Factors in our Annual Report on Form 10-K/A for the year ended December 31, 2006.

Gas prices are very volatile, and if commodity prices decline significantly for a temporary or prolonged period, our revenues, profitability and cash flows will decline.

The gas market is very volatile, and we cannot predict future gas prices. Prices for gas may fluctuate widely in response to relatively minor changes in the supply of and demand for gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

In the past, the prices of gas have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2006, the NYMEX monthly gas index price (last day) ranged from a high of $11.43 per MMBtu to a low of $4.20 per MMBtu. During the three month period ended June 30, 2007, the NYMEX monthly gas index price (last day) ranged from a high of $7.59 per MMBtu to a low of $7.51 MMBtu.

Our revenue, profitability and cash flow depend upon the prices and demand for gas and oil, and a drop in prices can significantly affect our financial results and impede our growth. In particular, declines in commodity prices will:

Future price declines may result in a write-down of our asset carrying values.

Lower gas prices may not only decrease our revenues, profitability and cash flows, but also reduce the amount of gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. Substantial decreases in gas prices would render a significant number of our planned exploitation projects uneconomic. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our gas properties for impairments. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and may, therefore, require a write-down of such carrying value. For example, for the year ended December 31, 2006, we had an impairment charge of $30.7 million. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our credit facilities.

Unless we replace the reserves that we produce, our existing reserves and production will decline, which would adversely affect our revenues, profitability and cash flows.

Producing gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. CBM production generally declines at a shallow rate after initial increases in production as a consequence of the dewatering process. Our future gas reserves, production, cash flow and ability to make distributions depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations. Factors that may hinder our ability to acquire additional reserves include competition, access to capital, prevailing gas prices and attractiveness of properties for sale.

As of December 31, 2006, our reserve-to-production ratio was 16.1 years. Because this ratio includes our proved undeveloped reserves, we expect that this ratio will not increase even if those proved undeveloped reserves are developed and the wells produce as expected. The reserve-to-production ratio reflected in our reserve report of December 31, 2006 will change if production from our existing wells declines in a different manner than we have estimated and can change when we drill additional wells, make acquisitions and under other circumstances.

We may not be able to replace our reserves or generate cash flows if we are unable to raise capital.

In order to increase our asset base, we will need to make substantial capital expenditures for the exploitation, development, production and acquisition of gas and oil reserves and the construction of additional gas gathering pipelines and related facilities. These maintenance capital expenditures may include capital expenditures associated with drilling and completion of additional wells to offset the production decline from our producing properties or additions to our inventory of unproved properties or our proved reserves to the extent such additions maintain our asset base. These expenditures could increase as a result of:

Our cash flow from operations and access to capital are subject to a number of variables, including:

Historically, we have financed these expenditures primarily with cash generated by operations and proceeds from bank borrowings and equity financings. If our revenues or borrowing base decreases as a result of lower natural gas and oil prices, operating difficulties or declines in reserves, we may have limited ability to expend the capital necessary to undertake or complete future drilling programs. Additional debt or equity financing or cash generated by operations may not be available to meet these requirements.

If we borrow money to expand our business, we will face the risks of leverage.

As of June 30, 2007, we had incurred $235 million of indebtedness for borrowed money and $20 million of indebtedness had been incurred by Quest Midstream. We anticipate that we may in the future incur additional debt for financing our growth. Our ability to borrow funds will depend upon a number of factors, including the condition of the financial markets. Under certain circumstances, the use of leverage may provide a higher return to you on your investment, but will also create a greater risk of loss to you than if we did not borrow. The risk of loss in such circumstances is increased because we would be obligated to meet fixed payment obligations on specified dates regardless of our revenue. If we do not make our debt service payments when due, we may sustain the loss of our equity investment in any of our assets securing such debt, upon the foreclosure on such debt by a secured lender. The interest payable on our debt varies with the movement of interest rates charged by financial institutions. An increase in our borrowing costs due to a rise in interest rates in the market may reduce the amount of income and cash available for the payment of dividends to the holders of our common stock.

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.

Our credit agreements contain operating and financial restrictions that may restrict our business and financing activities.

The operating and financial restrictions and covenants in our credit agreements could restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions. Our credit agreements restrict our ability to:

We are also required to comply with certain financial covenants and ratios. In the past, we have not satisfied all of the financial covenants contained in our credit facilities. In January 2005, we determined that we were not in compliance with the leverage and interest coverage ratios under a prior secured credit agreement and, in connection with a February 2005 amendment to such credit agreement, we were unable to drill any additional wells until our gross daily production reached

certain levels. We were unable to reach these production goals without the drilling of additional wells and, in the fourth quarter of 2005, we undertook a significant recapitalization that included a private placement of our common stock and the refinancing of our credit facilities. For the quarter ended March 31, 2007, we were not in compliance with the maximum total debt to EBITDA ratio under our current credit facilities, and we obtained a waiver from our lenders.

Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by our results of operations and financial conditions and events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit agreements, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions will be inhibited and the lenders' commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit agreements are secured by substantially all of our assets, and if we are unable to repay indebtedness under our credit agreements, the lenders could seek to foreclose on our assets.

Our credit agreements limit the amount we can borrow to a borrowing base amount, determined by the lenders in their sole discretion. Outstanding borrowings in excess of the borrowing base will be required to be repaid (1) within 90 days following receipt of notice of the new borrowing base or (2) immediately if the borrowing base is reduced in connection with a sale or disposition of certain properties in excess of 5% of the borrowing base. Additionally, if the lenders' exposure under letters of credit exceeds the borrowing base after all borrowings under the credit agreements have been repaid, we will be required to provide additional cash collateral.

If we do not make acquisitions on economically acceptable terms, our future growth and profitability will be limited.

Our ability to grow and to increase our profitability depends in part on our ability to make acquisitions that result in an increase in our net income. We may be unable to make such acquisitions because we are: (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms or (3) outbid by competitors. If we are unable to acquire properties containing proved reserves, our total level of proved reserves will decline as a result of our production, which will adversely affect our results of operations.

There is a significant delay between the time we drill and complete a coal bed methane ("CBM") well and when the well reaches peak production. As a result, there will be a significant lag time between when we expend capital expenditures and when we will begin to recognize significant cash flow from those expenditures.

Our general production profile for a CBM well averages an initial 15-20 Mcf/d (net), steadily rising for the first twelve months while water is pumped off and the formation pressure is lowered until the wells reach peak production (an average of 55-60 Mcf/d (net)). In addition, there could be significant delays between the time a well is drilled and completed and when the well is connected to a gas gathering system. This delay between the time when we expend capital expenditures to drill and complete a well and when we will begin to recognize significant cash flow from those expenditures may adversely affect our cash flow from operations.

Any acquisitions we complete are subject to substantial risks that could reduce our profitability.

Even if we do make acquisitions that we believe will increase our net income and cash flows, these acquisitions may nevertheless result in a decrease in net income and/or cash flows. Any acquisition involves potential risks, including, among other things:

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and investors will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

In addition, we may pursue acquisitions outside the Cherokee Basin. We currently operate substantially in the Cherokee Basin, and consequently acquisitions in areas outside the Cherokee Basin may not allow us the same operational efficiencies we benefit from in the Cherokee Basin. In addition, acquisitions outside the Cherokee Basin will expose us to different operational risks due to potential differences, among others, in:

Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume environmental and other risks and liabilities in connection with acquired properties.

Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

It is not possible to measure underground accumulations of gas in an exact way. Gas reserve engineering requires subjective estimates of underground accumulations of gas and assumptions concerning future gas prices, production levels and operating and development costs. In estimating our level of gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to:

If these assumptions prove to be incorrect, our estimates of proved reserves, the economically recoverable quantities of gas and oil attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly. For example, if gas prices at December 31, 2006 had been $1.00 less per Mcf, then the standardized measure of our proved reserves as of December 31, 2006 would have decreased by $70.7 million, from $164.9 million to $94.2 million.

Our standardized measure is calculated using unhedged gas prices and is determined in accordance with the rules and regulations of the SEC. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual drilling and production.

The present value of future net cash flows from our estimated proved reserves is not necessarily the same as the current market value of our estimated proved reserves. We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of estimate. However, actual future net cash flows from our gas properties also will be affected by factors such as:

The timing of both our production and our incurrence of expenses in connection with the development and production of gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with the Financial Accounting Standards Board's Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the gas industry in general.

Drilling for and producing gas are costly and high-risk activities with many uncertainties that could adversely affect our financial condition or results of operations.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Furthermore, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances. We may drill wells that are unproductive or, although productive, do not produce gas in economic quantities. Unsuccessful drilling activities could result in higher costs without any corresponding revenues. Furthermore, a successful completion of a well does not ensure a profitable return on the investment.

Our hedging activities could result in financial losses or reduce our income.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of gas, we currently and may in the future enter into derivative arrangements for a significant portion of our gas production that could result in both realized and unrealized hedging losses. The extent of our commodity price exposure is related largely to the effectiveness and scope of our hedging activities.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into hedging transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our hedging activities are subject to the following risks:

Because of our lack of asset and geographic diversification, adverse developments in our operating area would adversely affect our results of operations.

Substantially all of our assets are currently located in the Cherokee Basin. As a result, our business is disproportionately exposed to adverse developments affecting this region. These potential adverse developments could result from, among other things, changes in governmental regulation, capacity constraints with respect to the pipelines connected to our wells, curtailment of production, natural disasters or adverse weather conditions in or affecting this region. Due to our lack of diversification in asset type and location, an adverse development in our business or this operating area would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.

We may be unable to compete effectively with larger companies, which may adversely affect our results of operations.

The gas and oil industry is intensely competitive with respect to acquiring prospects and productive properties, marketing gas and oil and securing equipment and trained personnel, and we compete with other companies that have greater resources. Many of our competitors are major and large independent gas and oil companies, and they not only drill for and produce gas and oil, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. Our larger competitors also possess and employ financial, technical and personnel resources substantially greater than ours. These companies may be able to pay more for gas and oil properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, there is substantial competition for investment capital in the gas and oil industry. These larger companies may have a greater ability to continue drilling activities during periods of low gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with larger companies could have a material impact on our business activities, results of operations and financial condition.

Because of the relatively small size of our business, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As we increase our activities and the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the recruitment and retention of required personnel could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs that is not fully insured, our operations and financial results could be adversely affected.

There are a variety of risks inherent in our operations that may generate liabilities, including contingent liabilities, and financial losses to us, such as:

Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial revenue losses.

In accordance with typical industry practice, we currently possess property, business interruption and general liability insurance at levels we believe are appropriate; however, insurance against all operational risk is not available to us. We are not fully insured against all risks, including drilling and completion risks that are generally not recoverable from third parties or insurance. Pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to

obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets subsequent to the terrorist attacks on September 11, 2001 and the hurricanes in 2005 have made it more difficult for us to obtain certain types of coverage. There can be no assurance that we will be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition and results of operations.

Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters applicable to gas and oil exploitation and production operations.

We may incur significant costs and liabilities as a result of environmental, health and safety requirements applicable to our gas and oil exploitation and production activities. These costs and liabilities could arise under a wide range of federal, state and local environmental, health and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for damages as a result of environmental and other impacts.

Strict, joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our results of operations and financial condition could be adversely affected.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our gas and oil exploitation, development and production operations are subject to complex and stringent laws, rules and regulations. In order to conduct our operations in compliance with these laws, rules and regulations, we must obtain and maintain numerous permits, licenses, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws, rules and regulations. In addition, our costs of compliance may increase if existing laws, rules and regulations are revised or reinterpreted, or if new laws, rules and regulations become applicable to our operations.

The Cherokee Basin has been an active gas and oil producing region for a number of years. Many of our properties had abandoned oil and conventional gas wells on them at the time the current lease was entered into with the landowner. A number of these wells remain unplugged or were improperly plugged by a prior landowner or operator. Many of the former operators of these wells have ceased operations and cannot be located or do not have the financial resources to plug these wells. We believe that we are not responsible for plugging an abandoned well on one of our leases, unless we have used, attempted to use or invaded the abandoned well bore in our operations on the land or have otherwise agreed to assume responsibility for plugging the wells. The law is unsettled in the State of Kansas as to who has the responsibility to plug such abandoned wells and the Kansas Corporation Commission, or KCC, has recently issued a Show Cause Order requiring our operating company, Quest Cherokee, LLC, to demonstrate why it should not be held responsible for plugging 22 abandoned and unplugged oil wells on land covered by a gas lease that is owned and operated by Quest Cherokee in Wilson County, Kansas, and upon which Quest Cherokee has drilled and is operating a gas well. If it is ultimately determined that we are responsible for plugging all of the wells located on our leased acreage that were abandoned by former operators, the costs for plugging and abandoning those wells would increase our costs and decrease our cash available for distribution. At this time, we are unable to determine the total number of wells located on our leased acreage that have been abandoned by prior operators.

We are subject to regulation that restricts our ability to discharge water produced as part of our CBM gas production operations. Coal beds frequently contain water that must be removed in order for the gas to detach from the coal and flow to the well bore, and our ability to remove and dispose of sufficient quantities of water from the coal seam will determine whether we can produce gas in commercial quantities. The produced water must be transported from the lease and injected into disposal wells. The availability of disposal wells with sufficient capacity to receive all of the water produced from our

wells may affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability.

Where water produced from our projects fail to meet the quality requirements of applicable regulatory agencies, our wells produce water in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of all applicable regulatory agencies, or we are unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur:

Shortages of crews could delay our operations, adversely affect our ability to increase our reserves and production and adversely affect our results of operations.

Higher gas and oil prices generally stimulate increased demand and result in increased wages for crews and personnel in our production operations. These types of shortages or wage increases could increase our costs and/or restrict or delay our ability to drill the wells and conduct the operations that we currently have planned. Any delay in the drilling of new wells or significant increase in labor costs could adversely affect our ability to increase our reserves and production and reduce our revenue and cash available for distribution. Additionally, higher labor costs could cause certain of our projects to become uneconomic and therefore not be implemented, reducing our production and adversely affecting our results of operations.

We depend on two customers for sales of our gas. To the extent these customers reduce the volumes of gas they purchase from us and are not replaced by new customers, our revenues and net income could decline.

During the year ended December 31, 2006 and the six months ended June 30, 2007, we sold approximately 95% and 72%, respectively, of our gas to ONEOK Energy Marketing and Trading Company ("ONEOK") and 5% and 28%, respectively, of our gas to Tenaska Marketing Ventures ("Tenaska") under sale and purchase contracts, which have indefinite terms but may be terminated by either party on 30 days' notice, other than with respect to pending transactions, or less following an event of default. Tenaska was added as a purchaser in December 2006 and is expected to purchase 10% or more of our gas during 2007. If either of these customers were to reduce the volume of gas it purchases from us, our revenue and net income for distribution will decline to the extent we are not able to find new customers for our production.

We are exposed to trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our customers and by counterparties to our derivative contracts. Some of our customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our customers and/or counterparties could adversely affect our results of operations and financial condition.

Certain of our undeveloped leasehold acreage is subject to leases that may expire in the near future.

As of December 31, 2006, we held gas leases on approximately 138,780 net acres in the Cherokee Basin that are still within their original lease term and are not currently held by production. Unless we establish commercial production on the properties subject to these leases during their term, these leases will expire. Leases covering approximately 31,323 net acres are scheduled to expire before December 31, 2007 and an additional 8,154 net acres are scheduled to expire before December 31, 2008. If our leases expire, we will lose our right to develop the related properties. We typically acquire a three-year primary term when the original lease is acquired, with an option to extend the term for up to three additional years, if the primary three-year term reaches expiration without a well being drilled to establish production for holding the lease.

Our identified drilling location inventories will be developed over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, resulting in temporarily lower cash from operations, which may impact our results of operations.

Our management has specifically identified drilling locations for our future multi-year drilling activities on our existing acreage. We have identified, as of December 31, 2006, 250 gross proved undeveloped drilling locations and approximately 1,510 additional gross potential drilling locations. These identified drilling locations represent a significant

part of our future development drilling program for the Cherokee Basin. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, gas prices, costs and drilling results. In addition, no proved reserves are assigned to any of the approximately 1,510 potential drilling locations we have identified and therefore, there may exist greater uncertainty with respect to the likelihood of drilling and completing successful commercial wells at these potential drilling locations. Our final determination of whether to drill any of these drilling locations will be dependent upon the factors described above as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, we do not know if the numerous drilling locations we have identified will be drilled within our expected timeframe or will ever be drilled or if we will be able to produce gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could have a significant adverse effect on our financial condition and results of operations.

We may incur losses as a result of title deficiencies in the properties in which we invest.

If an examination of the title history of a property reveals that a gas or oil lease has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would be worthless. In such an instance, the amount paid for such gas or oil lease or leases would be lost.

It is our practice, in acquiring gas and oil leases, or undivided interests in gas and oil leases, not to incur the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease. Rather, we rely upon the judgment of gas and oil lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.

Prior to drilling a gas or oil well, however, it is the normal practice in the gas and oil industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed gas or oil well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such curative work entails expense. The work might include obtaining affidavits of heirship or causing an estate to be administered. Our failure to obtain these rights may adversely impact its ability in the future to increase production and reserves.

On a small percentage of our acreage (less than 1.0%), the land owner in the past transferred the rights to the coal underlying their land to a third party. With respect to those properties we have obtained gas and oil leases from the owners of the oil, gas, and minerals other than coal underlying those lands. In Oklahoma and Kansas, the law is unsettled as to whether the owner of the gas rights or the coal rights is entitled to the CBM gas. We are currently involved in litigation with the owner of the coal rights on these lands to determine who has the rights to the CBM gas. In the event that the courts were to determine that the owner of the coal rights is entitled to extract the CBM gas, we would lose these leases and the associated wells and reserves. In addition, we may be required to reimburse the owner of the coal rights for some of the gas produced from those wells.

We depend on a limited number of key management personnel, who would be difficult to replace.

Our operations and activities are dependent to a significant extent on the efforts and abilities of our executive officers and key employees. The loss of any member of our executive officers or other key employees could negatively impact our ability to execute our strategy.

There are risks associated with our previously-announced proposed initial public offering of Quest Energy Partners, L.P. ("Quest Energy").

Quest Energy has filed an initial registration statement to register the sale of 8,750,000 common units representing a 37.0% limited partner interest (assuming the underwriters do not exercise their overallotment option). We may not complete the initial public offering, or IPO, of Quest Energy common units, in which event we will have incurred significant expenses which we will be unable to recover, and for which we will not receive any benefit. If we do not complete the IPO, we will need to pursue alternative means of raising additional capital or pursue strategic alternatives.

If the IPO is completed, Quest Energy would be a new public company. We are unable to predict what the market price of our common stock would be after the IPO. We cannot assure you that the IPO, if completed, will produce any increase for our shareholders in the market value of their holdings in our company. In addition, the market price of our common stock could be volatile for several months after the IPO and may continue to be more volatile than our common stock would have been if a transaction had not occurred.

Our 2007 Annual Meeting of Stockholders was held on June 7, 2007, at which time a vote was taken to elect two Class I directors to our board of directors. The stockholders elected the following directors as Class I directors:

On May 31, 2007, we entered into a ten-year office lease for a new corporate headquarters location in downtown Oklahoma City, Oklahoma. The lease is for approximately 35,000 square feet, with a monthly rental expense of $52,590. The lease term is currently anticipated to commence in November 2007.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized this 10th day of August, 2007.

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



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

PART I - FINANCIAL INFORMATION	3

Item 1. Financial Statements	3

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

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

Condensed Consolidated Statements of Cash Flows:
Six Months Ended June 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	10

Item 4. Controls and Procedures	10

PART II – OTHER INFORMATION	11

Item 1. Legal Proceedings	11

Item 1A.Risk Factors	11

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	21

Item 3. Defaults Upon Senior Securities	21

Item 4. Submission of Matters to a Vote of Security Holders	21

Item 5. Other Information	21

Item 6. Exhibits	21

SIGNATURES	23

	December 31, 2006		June 30, 2007
	(dollars in thousands)
Senior credit facilities – Quest	$	225,000	$	235,000
Senior credit – Quest Midstream		—		20,000
Other notes payable		569		270

Total long-term debt		225,569		255,270

Less - current maturities		324		179

Total long-term debt, net of current maturities	$	225,245	$	255,091

		Notional	Fixed Rate /	Floating	Fair Value as of
Instrument Type	Term	Amount (1)	Cap Rate	Rate	June 30, 2007
		$ 98,705,000		3-month
Interest Rate Cap	July 2007 - Sept. 2007	$ 70,174,600	5.000%	LIBOR	$ 63,000

	December 31, 2006				June 30, 2007
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(dollars in thousands)
Derivative assets:
Interest rate swaps and caps	$	197	$	197	$	63	$	63
Basis swaps	$	62	$	62	$	101	$	101
Fixed-price natural gas swaps	$	2,207	$	2,207	$	944	$	944
Fixed-price natural gas collars	$	13,111	$	13,111	$	7,037	$	7,037

2008	$	179
2009		58
2010		11
2011		50,006
2012		205,007
Thereafter		9
	$	255,270

	Three Months Ended						Three Months Ended
	June 30,						June 30,
	2006			2007			2006			2007
	(dollars in thousands)
Change in fair value of derivatives not
qualifying as cash flow hedges	$	1,260		$	(285	)	$	14,630			(1,321	)
Settlements due to ineffective cash flow
hedges		(2,828	)		—			(10,234	)		—
Ineffective portion of derivatives qualifying
as cash flow hedges		1,123			564			2,234			1,136

	$	(445	)	$	279		$	6,630		$	(185	)

Derivative liabilities:
Basis swaps	$	(377	)	$	(377	)	$	(110	)	$	(110	)
Fixed-price natural gas collars	$	(12,316	)	$	(12,316	)	$	(10,902	)	$	(10,902	)
Credit facilities	$	(225,000	)	$	(225,000	)	$	(255,000	)	$	(255,000	)
Other financing agreements	$	(569	)	$	(569	)	$	(270	)	$	(270	)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2007			2006			2007
	(dollars in thousands)
Asset retirement obligation beginning
balance	$	1,210		$	1,477		$	1,150		$	1,410
Liabilities incurred		44			42			84			83
Liabilities settled		(2	)		(2	)		(3	)		(3	)
Accretion expense		23			29			44			56
Revisions in estimated cash flows		—			—			—			—
Asset retirement obligation
ending balance	$	1,275		$	1,546		$	1,275		$	1,546

	Quest Resource Corporation			Quest Midstream Partners		Inter-company eliminations			Consolidated
Gas/oil sales	$	27,867		$	—	$	—		$	27,867
Pipeline revenue		—			8,601		(6,809	)		1,792
Other expense		(19	)		—		—			(19	)
Total revenues		27,848			8,601		(6,809	)		29,640

Director	Director Class	Term Expiring In	Votes For	Votes Withheld
John C. Garrison	I	2010	14,948,205	974,819
Jon H. Rateau	I	2010	15,541,445	381,579

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.

	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