UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q/A

(Mark One)

þ		QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2008.

o		TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from          to          .

QUEST RESOURCE CORPORATION

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

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

     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 o     No þ

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

 

Large accelerated filer o		Accelerated filer þ		Non-accelerated filer o		Smaller reporting company o
				(Do not check if a smaller reporting company)

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

     As of August 8, 2008, the issuer had 32,344,859 shares of common stock outstanding.

 

 

EXPLANATORY NOTE

     This amended Quarterly Report on Form 10-Q/A for the quarter ended June 30, 2008 includes restated consolidated financial statements as of June 30, 2008 and for the three and six month periods ended June 30, 2008 and 2007 for Quest Resource Corporation (“QRCP” or the “Company”). The consolidated balance sheet as of December 31, 2007 was restated in our Annual Report on Form 10-K for the year ended December 31, 2008 filed on June 3, 2009 (the “2008 Form 10-K”).

     Investigation — On August 22, 2008, in connection with an inquiry from the Oklahoma Department of Securities, the boards of directors of QRCP, Quest Energy GP, LLC (“Quest Energy GP”), the general partner of Quest Energy Partners, L.P. (NASDAQ: QELP) (“Quest Energy” or “QELP”), which is a publicly traded limited partnership controlled by QRCP, and Quest Midstream GP, LLC (“Quest Midstream GP”), the general partner of Quest Midstream Partners, L.P. (“Quest Midstream” or “QMLP”), a private limited partnership controlled by QRCP, held a joint working session to address certain unauthorized transfers, repayments and re-transfers of funds (the “Transfers”) to entities controlled by their former chief executive officer, Mr. Jerry D. Cash.

     A joint special committee comprised of one member designated by each of the boards of directors of QRCP, Quest Energy GP, and Quest Midstream GP was immediately appointed to oversee an independent internal investigation of the Transfers. In connection with this investigation, other errors were identified in prior year financial statements and management and the board of directors concluded that the Company had material weaknesses in its internal control over financial reporting. As of December 31, 2008, these material weaknesses continued to exist.

     As reported on a Current Report on Form 8-K filed on January 2, 2009, on December 31, 2008, the board of directors of QRCP determined that the audited consolidated financial statements of QRCP as of and for the years ended December 31, 2007, 2006 and 2005 and QRCP’s unaudited consolidated financial statements as of and for the three months ended March 31, 2008 and as of and for the three and six month periods ended June 30, 2008 should no longer be relied upon.

     Restatement and Reaudit — In October 2008, QRCP’s audit committee engaged a new independent registered public accounting firm to audit the Company’s consolidated financial statements for 2008 and, in January 2009, engaged them to reaudit the Company’s consolidated financial statements as of December 31, 2007 and 2006 and for the years ended December 31, 2007, 2006 and 2005.

     The restated consolidated financial statements included in this Form 10-Q/A correct errors in a majority of the financial statement line items in the previously issued consolidated financial statements for all periods presented. The most significant errors (by dollar amount) consist of the following:

	•		The Transfers, which were not approved expenditures of QRCP, were not properly accounted for as losses.
	•		Hedge accounting was inappropriately applied for QRCP’s commodity derivative instruments and the valuation of commodity derivative instruments was incorrectly computed.
	•		Certain general and administrative expenses unrelated to oil and gas production were inappropriately capitalized to oil and gas properties, and certain operating expenses were inappropriately capitalized to oil and gas properties being amortized. These items resulted in errors in valuation of the full cost pool, oil and gas production expenses and general and administrative expenses.
	•		Invoices were not properly accrued resulting in the understatement of accounts payable and numerous other balance sheet and income statement accounts.

	•		Capitalized interest was not recorded on pipeline construction. As a result, pipeline assets and accumulated deficit were understated and interest expense was overstated in all periods presented.
	•		Errors were identified in stock-based compensation expense, including the use of incorrect grant dates, valuation errors, and incorrect vesting periods.
	•		As a result of previously discussed errors and an additional error related to the methods used in calculating depreciation, depletion and amortization, errors existed in our depreciation, depletion and amortization expense and our accumulated depreciation, depletion and amortization.
	•		As a result of previously discussed errors relating to oil and gas properties and hedge accounting and errors relating to the treatment of deferred taxes, errors existed in our ceiling test calculations.
	•		Errors were identified in the calculation of outstanding shares in all periods as we inappropriately included restricted share grants in our calculation of issued shares when the restrictions lapsed, rather than the date at which the restricted shares were granted. This error did not affect net income, but did impact our issued and outstanding share amounts as well as our weighted average share amounts.

     Although the items listed above comprise the most significant errors (by dollar amount), numerous other errors were identified and restatement adjustments made. The tables below present previously reported stockholders’ deficit, major restatement adjustments and restated stockholders’ deficit as well as previously reported net income (loss), major restatement adjustments and restated net loss as of and for the periods indicated (in thousands):

		June 30, 2008
Stockholders’ deficit as previously reported		$	(39,192	)
Effect of the Transfers			(10,000	)
Reversal of hedge accounting			3,658
Accounting for formation of Quest Cherokee			(19,003	)
Capitalization of costs in full cost pool			(31,091	)
Recognition of costs in proper periods			(3,252	)
Capitalized interest			1,999
Stock-based compensation			—
Depreciation, depletion and amortization			9,575
Impairment of oil and gas properties			30,719
Other errors			53,419
Stockholders’ deficit as restated		$	(3,168	)

		Three Months Ended
		June 30, 2008				June 30, 2007
Net income (loss) as previously reported		$	4,964			$	(4,487	)
Effect of the Transfers			—				(500	)
Reversal of hedge accounting			(105,179	)			7,685
Accounting for formation of Quest Cherokee			26				26
Capitalization of costs in full cost pool			(3,425	)			(3,028	)
Recognition of costs in proper periods			(2,015	)			(792	)
Capitalized interest			143				86
Stock-based compensation			446				104
Depreciation, depletion and amortization			(484	)			(237	)
Impairment of oil and gas properties			—				—
Other errors(*)			47,638				(237	)
Net loss as restated		$	(57,886	)		$	(1,380	)

		Six Months Ended
		June 30, 2008				June 30, 2007
Net loss as previously reported		$	(6,678	)		$	(7,798	)
Effect of the Transfers			—				(1,000	)
Reversal of hedge accounting			(124,375	)			(6,394	)
Accounting for formation of Quest Cherokee			52				52
Capitalization of costs in full cost pool			(7,155	)			(5,370	)
Recognition of costs in proper periods			(1,265	)			(703	)
Capitalized interest			286				173
Stock-based compensation			15				(241	)
Depreciation, depletion and amortization			(875	)			(776	)
Impairment of oil and gas properties			—				—
Other errors(*)			57,014				(1,383	)
Net loss as restated		$	(82,981	)		$	(23,440	)

     Reconciliations from amounts previously included in QRCP’s consolidated financial statements to restated amounts on a financial statement line item basis are presented in Note 12 to the accompanying consolidated financial statements.

     Other Matters — In addition to the items for which QRCP has restated its consolidated financial statements, the Oklahoma Department of Securities has filed a lawsuit alleging:

	•		An additional theft of approximately $1.0 million by David Grose, the former chief financial officer of QRCP, and Brent Mueller, the former purchasing manager of QRCP. The evidence indicates that this theft occurred in the third quarter of 2008, and therefore did not affect the periods covered by this report.
	•		A kickback scheme involving the former chief financial officer and the former purchasing manager, in which the former chief financial officer and the former purchasing manager received kickbacks totaling approximately $0.9 million each from several related suppliers during the years ended December 31, 2007 and 2008.

     QRCP experienced significant increased costs in the second half of 2008 and continues to experience such increased costs in the first half of 2009 due to, among other things (as more fully described in our 2008 Form 10-K in Items 1. and 2. “Business and Properties — Recent Developments — Internal Investigation; Restatements and Reaudits”):

	•		the necessary retention of numerous professionals, including consultants to perform the accounting and finance functions following the termination of the chief financial officer, independent legal counsel to conduct the internal investigation, investment bankers and financial advisors, and law firms to respond to the class action and derivative suits that have been filed against QRCP and its affiliates and to pursue the claims against the former employees;
	•		costs associated with amending the credit agreements of QRCP, Quest Energy and Quest Midstream;
	•		preparing the restated consolidated financial statements; and
	•		conducting the reaudits of the restated consolidated financial statements.

     This Amendment No. 1 to the Quarterly Report on Form 10-Q/A restates the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 in its entirety to reflect the effects of the restatement. However, the Company has not modified nor updated disclosures presented in the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, except as required to reflect the effects of the matters discussed above. Accordingly, this Amendment No. 1 to the Quarterly Report on Form 10-Q/A does not reflect events occurring after the filing of the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, initially filed with the SEC on August 11, 2008, or modify or update those disclosures affected by subsequent events or discoveries. Therefore, this Amendment No. 1 to the Quarterly Report on Form 10-Q/A should be read in conjunction with the 2008 Form 10-K and the other subsequent reports that the Company has filed with the Securities and Exchange Commission.

     The Company has also restated the following items, which were impacted by the adjustments described above:

     Part I

     Item 1 — Financial Statements

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

     Item 3 — Quantitative and Qualitative Disclosures About Market Risk

     Item 4 — Controls and Procedures

     In addition, in accordance with applicable SEC rules, this Amendment No. 1 to the Quarterly Report on Form 10-Q/A includes currently-dated certifications from our Chief Executive Officer and President, who is our principal executive officer, and our Chief Financial Officer, who is our principal financial officer in Exhibits 31.1, 31.2, 32.1 and 32.2.

QUEST RESOURCE CORPORATION
FORM 10-Q/A
FOR THE QUARTER ENDED JUNE 30, 2008
TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets: June 30, 2008 and December 31, 2007			F-1
Consolidated Statements of Operations Three Months and Six Months Ended June 30, 2008 and 2007			F-2
Consolidated Statements of Cash Flows: Six Months Ended June 30, 2008 and 2007			F-3
Consolidated Statement of Stockholders’ Equity (Deficit): Six Months Ended June 30, 2008			F-4
Condensed Notes to Consolidated Financial Statements			F-5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			3
Item 3. Quantitative and Qualitative Disclosures About Market Risk			16
Item 4. Controls and Procedures			16
PART II — OTHER INFORMATION
Item 1. Legal Proceedings			19
Item 1A. Risk Factors			19
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			20
Item 3. Defaults Upon Senior Securities			20
Item 4. Submission of Matters to a Vote of Security Holders			21
Item 5. Other Information			21
Item 6. Exhibits			21
SIGNATURES			24
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I — FINANCIAL INFORMATION

Item 1.  Financial Statements

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

     Our unaudited interim financial statements, including consolidated balance sheets as of June 30, 2008 and December 31, 2007, consolidated statements of operations for the three and six month periods ended June 30, 2008 and 2007, consolidated statements of cash flows for the six month period ended June 30, 2008 and the comparable period of 2007, and a consolidated statement of stockholders’ equity (deficit) for the six month period ended June 30, 2008, are attached hereto as Pages F-1 through F-34 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. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been omitted. However, in our opinion, all adjustments (which include only normal recurring accruals) necessary to fairly present the financial position and results of operations have been made for the periods presented. The Company’s results for the six months ended June 30, 2008 are not necessarily indicative of the results for the year ended December 31, 2008.

     The financial statements included herein should be read in conjunction with the 2007 financial statements and notes, as restated, which have been included in the 2008 Form 10-K.

     Restatement of Financial Statements: As discussed in the Explanatory Note to this Quarterly Report on Form 10-Q/A the financial statements are being restated to reflect the impact of errors in our previously issued financial statements. See further discussion in Note 12 to the accompanying consolidated financial statements.

		June 30, 2008				December 31, 2007
		(Unaudited)
		(Restated)
ASSETS
Current assets:
Cash and cash equivalents		$	21,553			$	6,680
Restricted cash			453				1,236
Accounts receivable, trade			16,361				15,557
Other receivables			3,466				1,480
Other current assets			4,999				3,962
Inventory			12,713				6,622
Current derivative financial instrument assets			1,837				8,008
Total current assets			61,382				43,545
Property and equipment, net of accumulated depreciation of $7,847 and $6,207			24,481				21,505
Pipeline assets, net of accumulated depreciation of $18,012 and $11,791			297,971				294,526
Oil and gas properties under full cost method of accounting, net			346,005				300,953
Other assets, net			15,594				8,541
Long-term derivative financial instrument assets			9,536				3,467
Total assets		$	754,969			$	672,537
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable		$	43,319			$	31,202
Revenue payable			7,952				7,725
Accrued expenses			9,768				8,387
Current portion of notes payable			247				666
Current derivative financial instrument liabilities			68,355				8,108
Total current liabilities			129,641				56,088
Non-current liabilities:
Long-term derivative financial instrument liabilities			85,306				6,311
Asset retirement obligation			3,411				2,938
Notes payable			312,152				233,046
Non-current liabilities			400,869				242,295
Total liabilities			530,510				298,383
Minority interests			227,627				297,385
Commitments and contingencies
Stockholders’ equity (deficit):
10% convertible preferred stock, $.001 par value, 50,000,000 shares authorized, 0 shares issued and outstanding at June 30, 2008 and December 31, 2007			—				—
Common stock, $.001 par value, 200,000,000 shares authorized, issued — 23,903,592 and 23,553,230 at June 30, 2008 and December 31, 2007, respectively; outstanding — 22,880,600 and 22,471,355 at June 30, 2008 and December 31, 2007, respectively			24				24
Additional paid-in capital			214,896				211,852
Accumulated deficit			(218,088	)			(135,107	)
Total stockholders’ equity (deficit)			(3,168	)			76,769
Total liabilities and stockholders’ equity (deficit)		$	754,969			$	672,537

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
Revenue:
Oil and gas sales		$	49,144			$	27,570			$	87,458			$	52,544
Gas pipeline revenue			7,148				1,792				14,049				3,334
Total revenues			56,292				29,362				101,507				55,878
Costs and expenses:
Oil and gas production			12,631				10,416				23,037				19,889
Pipeline operating			8,164				4,295				15,122				9,191
General and administrative			6,198				6,417				11,941				8,971
Depreciation, depletion and amortization			16,444				8,888				31,333				17,436
Misappropriation of funds			—				500				—				1,000
Total costs and expenses			43,437				30,516				81,433				56,487
Operating income			12,855				(1,154	)			20,074				(609	)
Other income (expense):
(Loss) gain from derivative financial instruments			(105,375	)			8,391				(149,614	)			(5,156	)
Loss on sale of assets			(30	)			(298	)			—				(191	)
Other income (expense)			72				(19	)			122				(32	)
Interest income			104				103				121				280
Interest expense			(5,278	)			(7,514	)			(10,178	)			(15,976	)
Total other income (expense)			(110,507	)			663				(159,549	)			(21,075	)
Loss before minority interest			(97,652	)			(491	)			(139,475	)			(21,684	)
Minority interest			39,766				(889	)			56,494				(1,756	)
Net loss		$	(57,886	)		$	(1,380	)		$	(82,981	)		$	(23,440	)
Net loss per common share – basic and diluted		$	(2.53	)		$	(0.06	)		$	(3.65	)		$	(1.05	)
Weighted average common and common equivalent shares:
Basic			22,844,600				22,351,611				22,742,289				22,307,365
Diluted			22,844,600				22,351,611				22,742,289				22,307,365

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

		Six Months Ended June 30,
		2008				2007
Cash flows from operating activities:
Net loss		$	(82,981	)		$	(23,440	)
Adjustments to reconcile net loss to cash provided by operations:
Depreciation, depletion and amortization			31,333				17,436
Change in derivative fair value			139,344				6,577
Stock-based compensation			3,045				2,978
Stock-based compensation - minority interests			243				379
Amortization of loan origination fees			1,052				1,086
Bad debt expense			73				22
Loss on sale of assets			—				191
Minority interest			(56,494	)			1,756
Change in assets and liabilities:
Accounts receivable			(877	)			(2,602	)
Other receivables			(1,986	)			(1,122	)
Other current assets			(1,037	)			(800	)
Other assets			(341	)			(1,028	)
Accounts payable			13,763				7,476
Revenue payable			227				1,972
Accrued expenses			4,884				848
Other long-term liabilities			427				80
Other			(427	)			—
Net cash provided by operating activities			50,248				11,809
Cash flows from investing activities:
Restricted cash			783				(41	)
Equipment, development, leasehold costs and pipeline			(98,000	)			(64,594	)
Net cash used in investing activities			(97,217	)			(64,635	)
Cash flows from financing activities:
Proceeds from bank borrowings			4,000				—
Proceeds from revolver			75,000				30,000
Repayments of note borrowings			(313	)			(299	)
Cash distributions to unit holders			(16,845	)			(1,810	)
Refinancing costs			—				(1,687	)
Net cash provided by financing activities			61,842				26,204
Net increase (decrease) in cash			14,873				(26,622	)
Cash and cash equivalents, beginning of period			6,680				33,820
Cash and cash equivalents, end of period		$	21,553			$	7,198

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

						Common
						Stock				Additional
		Common				Par				Paid-in				Accumulated
		Shares				Value				Capital				Deficit				Total
Balance, December 31, 2007			23,553,230			$	24			$	211,852			$	(135,107	)		$	76,769
Stock based compensation			—				—				2,944				—				2,944
Restricted stock grant, net			340,362				—				—				—				—
Exercise of stock options			10,000				—				100				—				100
Net loss			—				—				—				(82,981	)			(82,981	)
Balance, June 30, 2008			23,903,592			$	24			$	214,896			$	(218,088	)		$	(3,168	)

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

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

1.  Basis of Presentation and Misappropriation, Reaudit and Restatement

Nature of Business

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

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

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

	•		Quest Energy — oil and natural gas production focused on coal bed methane in the Cherokee Basin; and
	•		Quest Midstream — transporting, selling, gathering and treating natural gas.

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

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

Misappropriation, Reaudit and Restatement

     These consolidated financial statements include our restated financial statements as of June 30, 2008 and for the three and six month periods ended June 30, 2008 and 2007. The consolidated balance sheet as of December 31, 2007 was restated in our 2008 Annual Report on Form 10-K for the year ended December 31, 2008 filed on June 3, 2009 (the “2008 Form 10-K”).

      Investigation — On August 22, 2008, in connection with an inquiry from the Oklahoma Department of Securities, the boards of directors of QRCP, Quest Energy GP, LLC (“Quest Energy GP”), the general partner of Quest Energy and Quest Midstream GP, LLC (“Quest Midstream GP”), the general partner of Quest Midstream, held a joint working session to address certain unauthorized transfers, repayments and re-transfers of funds (the “Transfers”) to entities controlled by their former chief executive officer, Mr. Jerry D. Cash. These transfers totaled approximately $10 million between 2005 and 2008.

     A joint special committee comprised of one member designated by each of the boards of directors of QRCP, Quest Energy GP, and Quest Midstream GP, was immediately appointed to oversee an independent internal investigation of the Transfers. In connection with this investigation, other errors were identified in prior year financial statements and management and the board of directors concluded that we had material weaknesses in our internal control over financial reporting. As of June 30, and December 31, 2008, these material weaknesses continued to exist.

     As reported on a Current Report on Form 8-K filed on January 2, 2009, on December 31, 2008, the board of directors of QRCP determined that the audited consolidated financial statements of QRCP as of and for the years ended December 31, 2007, 2006 and 2005 and QRCP’s unaudited consolidated financial statements as of and for the three months ended March 31, 2008 and as of and for the three and six months ended June 30, 2008 should no longer be relied upon.

      The restated consolidated financial statements to which these Notes apply also correct errors in a majority of the financial statement line items found in the previously issued consolidated financial statements for all periods presented. See Note 12 — Restatement.

2.  Summary of Significant Accounting Policies

     Reference is hereby made to the 2008 Form 10-K, which contains a summary of significant accounting policies followed by the Company in the preparation of its consolidated financial statements. The 2008 Form 10-K includes restated consolidated financial statements and footnotes for the year ended December 31, 2007. These policies were also followed in preparing the consolidated financial statements as of June 30, 2008 and for the three and six months ended June 30, 2008 and 2007.

Use of Estimates

     The preparation of financial statements in conformity with generally accepted accounting principles requires the Company to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

     Estimates made in preparing the consolidated financial statements include, among other things, estimates of the proved oil and natural gas reserve volumes used in calculating depletion, depreciation and amortization expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment write-down; and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Future changes in the assumptions used could have a significant impact on reported results in future periods.

Basis of Accounting

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

Revenue Recognition

     Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties.

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

Cash Equivalents

     For purposes of the consolidated financial statements, the Company considers investments in all highly liquid instruments with original maturities of three months or less at date of purchase to be cash equivalents.

Uninsured Cash Balances

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

Restricted Cash

     Restricted Cash represents cash pledged to support reimbursement obligations under outstanding letters of credit.

Accounts Receivable

     Receivables are recorded at the estimate of amounts due based upon the terms of the related agreements.

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

Inventory

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

Other Current Assets

     Other current assets totaled $5.0 million at June 30, 2008 as compared to $4.0 million at December 31, 2007. At June 30, 2008, other current assets consisted of deposits of $2.4 million, prepaid insurance of $1.0 million, and other prepaid items of $1.6 million. At December 31, 2007, other current assets consisted of deposits of $1.3 million, prepaid insurance of $1.4 million and other prepaid items of $1.3 million.

Concentration of Credit Risk

     A significant portion of the Company’s liquidity is concentrated in cash and derivative contracts that enable the Company to hedge a portion of its exposure to price volatility from producing oil and natural gas. These derivative contracts expose the Company to credit risk from its counterparties. The Company’s accounts receivable are primarily from purchasers of oil and natural gas products.

Natural gas sales to one purchaser (ONEOK Energy Marketing and Trading Company) accounted for more than 99% of total oil and natural gas revenues for the six months ended June 30, 2008. Natural gas sales to two purchasers (ONEOK and Tenaska Marketing Ventures) accounted for 73% and 27% of total natural gas revenues for the six months ended June 30, 2007.

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

     The Company conducts the majority of its operations in the states of Kansas and Oklahoma and operates exclusively in the oil and natural gas industry. The industry concentration has the potential to impact the Company’s overall exposure to credit risk, either positively or negatively, in that the Company’s customers may be similarly affected by changes in economic, industry or other conditions. The Company’s receivables are generally unsecured; however, the Company has not experienced any significant losses to date.

Oil and Natural Gas Properties

     The Company follows the full cost method of accounting for oil and natural gas properties, prescribed by the Securities and Exchange Commission (“SEC”). Under the full cost method, all acquisition, exploration, and development costs are capitalized. The Company capitalizes internal costs including: salaries and related fringe benefits of employees directly engaged in the acquisition, exploration and development of oil and natural gas properties, as well as other directly identifiable general and administrative costs associated with such activities.

     All capitalized costs of oil and natural gas properties, including the estimated future costs to develop proved reserves, are amortized on the units-of-production method using estimates of proved reserves. The costs of unproved properties are excluded from amortization until the properties are evaluated. The Company reviews all of its unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred. Unevaluated properties are assessed individually when individual costs are significant.

     The Company reviews the carrying value of its oil and natural gas properties under the full-cost accounting rules of the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, plus the cost of properties not being amortized, less any related income tax effects. In calculating future net revenues, current prices and costs used are those as of the end of the appropriate quarterly period. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives qualifying as cash flow hedges. Two primary factors impacting this test are reserve levels and current prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of oil and natural gas reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. Under SEC regulations, the excess above the ceiling is not expensed (or is reduced) if, subsequent to the end of the period, but prior to the release of the financial statements, oil and natural gas prices increase sufficiently such that an excess above the ceiling would have been eliminated (or reduced) if the increased prices were used in the calculations. No impairment is reflected in the Company’s financial statements at June 30, 2008 and December 31, 2007.

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

Other Property and Equipment

     Other property and equipment are stated at cost. Depreciation is calculated using the straight-line method for financial reporting purposes and accelerated methods for income tax purposes.

     The estimated useful lives are as follows:

Pipeline		15 to 40 years
Buildings		25 years
Equipment		10 years
Vehicles		7 years

     Repairs and maintenance are charged to operations when incurred and improvements and renewals are capitalized.

Debt Issue Costs

     Included in other assets are costs associated with bank credit facilities. The remaining unamortized debt issue costs at June 30, 2008 and December 31, 2007 totaled $7.6 million and $8.4 million, respectively, and were being amortized over the life of the credit facilities.

Other Dispositions

     Upon disposition or retirement of property and equipment other than oil and natural gas properties, the cost and related accumulated depreciation are removed from the accounts and the gain or loss thereon, if any, is credited or charged to income.

Marketable Securities

     In accordance with Statement of Financial Accounting Standards (“SFAS”) 115, Accounting for Certain Investments in Debt and Equity Securities, the Company classifies its investment portfolio according to the provisions of SFAS 115 as either held to maturity, trading, or available for sale. At June 30, 2008 and 2007, the Company did not have any investments in its investment portfolio classified as available for sale and held to maturity.

Income Taxes

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

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

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

Fair Value Measurements

     SFAS 157, Fair Value Measurements (as amended), defines fair value, establishes a framework for measuring fair value, outlines a fair value hierarchy based on inputs used to measure fair value and enhances disclosure requirements for fair value measurements. The Company has not applied the provisions of SFAS 157 to nonrecurring, nonfinancial assets and liabilities as allowed under FASB Staff Position (“FSP”) 157-2.

     Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.

     Beginning January 1, 2008, assets and liabilities recorded at fair value in the consolidated balance sheets are categorized based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels—defined by SFAS 157 and directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities—are as follows:

          Level I—Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date;

          Level II—Inputs (other than quoted prices included in Level I) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life; and

          Level III—Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.

     The fair value of the Company’s derivative contracts are measured using Level II and Level III inputs, and are determined by either market prices on an active market for similar assets or by prices quoted by a broker or other market-corroborated prices.

Stock-Based Compensation

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

     On March 5, 2008, the Company’s board of directors approved the conversion of 140,000 stock options held by certain directors into 70,000 bonus shares. As a result, the Company recognized additional compensation expense of $0.1 million for the six months ended June 30, 2008.

     Partnership Unit Awards.  Quest Energy GP, granted bonus units to certain members of its Board of Directors during the six months ended June 30, 2008. The units are subject to vesting with 25% of the units immediately vested and one-third of the remaining units vesting equally on each of the first three anniversaries of the date of the grant. The fair value of the unit awards granted is recognized over the applicable vesting period as compensation expense. Compensation expense amounts are recognized in general and administrative expenses or capitalized to oil and gas properties. For the three and six months ended June 30, 2008, Quest Energy did not capitalize any of the value associated with the bonus unit grants. The value of the bonus unit grants included in general and administrative expenses for the three and six months ended June 30, 2008 were $17,000 and $35,000, respectively.

     Quest Midstream GP, granted bonus units to certain employees and certain members of its Board of Directors during the six months ended June 30, 2008. The units are subject to a three-year vesting schedule. The fair value of the unit awards granted is recognized over the applicable vesting period as compensation expense. The value of the bonus unit grants included in general and administrative expenses for the three and six months ended June 30, 2008 were $334,000 and $715,000, respectively.

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

Accounting for Derivative Instruments and Hedging Activities

     The Company uses derivatives to hedge against changes in cash flows related to product price, as opposed to their use for trading purposes. SFAS 133, Accounting for Derivative Instruments and Hedging Activities, requires that all derivatives be recorded on the balance sheet at fair value. None of our derivative instruments have been designated as hedges. Accordingly, we record all derivative instruments in the consolidated balance sheet at fair value with changes in fair value recognized in earnings as they occur. Both realized and unrealized gains and losses associated with derivative financial instruments are currently recognized in other income (expense) as they occur.

Asset Retirement Obligations

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

     We own oil and gas properties that require expenditures to plug and abandon the wells when the oil and gas reserves in the wells are depleted. These expenditures are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired). Asset retirement obligations are recorded as a liability at their estimated present value at the asset’s inception, with the offsetting increase to property cost. Periodic accretion expense of the estimated liability is recorded in the consolidated statements of operations. We have recorded asset retirement obligations relative to the abandonment of our interstate pipeline assets because we believe we have a legal or constructive obligation relative to asset retirements of the interstate pipeline system. We have not recorded an asset retirement obligation relating to our gathering system because we do not have any legal or constructive obligations relative to asset retirements of the gathering system.

Recently Issued Accounting Standards

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

     On February 6, 2008, the FASB issued FASB Staff Position FAS 157-2, “Effective Date of FASB Statement No. 157.” This Staff Position delays the effective date of SFAS 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The delay is intended to allow the FASB and constituents additional time to consider the effect of various implementation issues that have arisen, or that may arise, from the application of SFAS 157.

     The remainder of SFAS 157 was adopted by the Company effective for fiscal years beginning after November 15, 2007. The adoption of SFAS 157 did not have an impact on the Company’s financial position, results of operations, or cash flows. See Note 6. “Financial Instruments and Hedging Activities — Fair Value Measurements”.

     In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities”, an amendment of FASB SFAS 115. SFAS 159 addresses how companies should measure many financial instruments and certain other items at fair value. The objective is to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS 159 is effective for fiscal years beginning after November 15, 2007, with earlier adoption permitted. SFAS 159 had been adopted and did not have a material impact on the Company’s financial position, results of operations, or cash flows.

     In September 2007, the Emerging Issues Task Force (“EITF”) reached consensus on EITF Issue No. 07-4, “Application of the two-class method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF No. 07-4”), an update of EITF No. 03-6. EITF No. 07-4 requires the calculation of a master limited partnership’s net earnings per limited partner unit for each period presented according to distributions declared and participation rights in undistributed earnings as if all of the earnings for that period had been distributed. In periods with undistributed earnings above specified levels, the calculation per the two-class method results in an increased allocation of such undistributed earnings to the general partner and a dilution of earnings to the limited partners. EITF No. 07-4 is effective for fiscal periods beginning on or after December 15, 2008. The Company does not expect the application of EITF No. 07-4 to have a material effect on its earnings per unit calculation for its subsidiaries.

     In December 2007, the FASB issued SFAS 141R (revised 2007), “Business Combinations.” Although this statement amends and replaces SFAS 141, it retains the fundamental requirements in SFAS 141 that (i) the purchase method of accounting be used for all business combinations; and (ii) an acquirer be identified for each business combination. SFAS 141R defines the acquirer as the entity that obtains control of one or more businesses in the business combination and establishes the acquisition date as the date that the acquirer achieves control. This statement applies to all transactions or other events in which an entity (the acquirer) obtains control of one or more businesses (the acquiree), including combinations achieved without the transfer of consideration; however, this statement does not apply to a combination between entities or businesses under common control. Significant provisions of SFAS 141R concern principles and requirements for how an acquirer (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 with early adoption not permitted. Management is assessing the impact of the adoption of SFAS 141R.

     In December 2007, the FASB issued SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51”. The objective of this statement is to improve the relevant, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements related to noncontrolling or minority interests. The effective date for this statement is for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 with earlier adoption being prohibited. Adoption of this statement will change the method in which minority interests are reflected on the Company’s consolidated financial statements and will add some additional disclosures related to the reporting of minority interests. Management is assessing the impact of the adoption of SFAS 160.

     In March 2008, the FASB issued SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities”. The objective of this statement is to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entity’s financial position, financial performance, and cash flows. The effective date for this statement is for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. Management is assessing the impact of the adoption of SFAS 161.

     In April 2008, the FASB issued Staff Position (FSP) FAS 142-3, “Determination of the Useful Life of Intangible Assets”. The objective of this statement is to amend the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, Goodwill and Other Intangible Assets. It is the FSP’s intent to improve the consistency between the useful life of a recognized intangible asset under Statement 142 and the period of expected cash flows used to measure the fair value of the asset under FASB Statement No. 141. The effective date for this statement will apply to financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Management is assessing the impact of the adoption of SFAS 142-3.

     In May 2008, the FASB issued SFAS 162, “The Hierarchy of Generally Accepted Accounting Principles”. The objective of this statement is to identify the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States (the GAAP hierarchy). This statement will go into effect 60 days following the SEC’s approval of the Public Company Accounting Oversight Board (PCAOB) amendments to AU Section 411, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles. Management is assessing the impact of the adoption of SFAS 162.

3.  Acquisitions

KPC Pipeline

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

     The total cost of the acquisition was allocated to the assets acquired and liabilities assumed based on their estimated fair values on the acquisition date. The preliminary allocation was recorded during 2007 before valuation work was completed on contract-based intangibles. After completing valuation work on the acquired intangibles, a final purchase price allocation was recorded in 2008. The following table summarizes the allocation of the purchase price (in thousands):

Pipeline assets		$	124,936
Contract-related intangible assets			9,934
Liabilities assumed			(1,145	)
Purchase price		$	133,725

Pro Forma Summary Data (unaudited)

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

		Three Months				Six Months
		Ended June 30, 2007				Ended June 30, 2007
Pro forma revenue		$	51,844			$	85,484
Pro forma net (loss)		$	(1,910	)		$	(24,500	)
Pro forma net (loss) per share		$	(0.09	)		$	(1.10	)

Searight

     Quest Energy purchased certain oil producing properties in Seminole County, Oklahoma from a private company for $9.5 million in a transaction that closed in early February 2008. As of February 1, 2008, the properties had estimated net proved reserves of 761,400 barrels, all of which were proved developed producing. In addition, Quest Energy entered into crude oil swaps for approximately 80% of the estimated net production from the property’s proved developed producing reserves at WTI-NYMEX prices per barrel of oil of approximately $96.00 in 2008, $90.00 in 2009, and $87.50 for 2010. The acquisition was financed with borrowings under Quest Energy’s credit facility.

4.  Asset Retirement Obligations

     The Company has adopted SFAS 143, Accounting for Asset Retirement Obligations. The following table provides a roll forward of the asset retirement obligations for the three and six months ended June 30, 2008 and 2007:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
						(Dollars in thousands)
Asset retirement obligation beginning balance		$	3,320			$	1,477			$	2,938			$	1,410
Liabilities incurred			24				41				52				83
Liabilities settled			(5	)			(2	)			(13	)			(3	)
Accretion expense			72				30				143				56
Revisions in estimated cash flows			—				—				291				—
Asset retirement obligation ending balance		$	3,411			$	1,546			$	3,411			$	1,546

5.  Long-Term Debt

     Long-term debt consists of the following:

		June 30,				December 31,
		2008				2007
		(Dollars in thousands)
Senior credit facilities		$	312,000			$	233,000
Notes payable to banks and finance companies, secured by equipment and vehicles, due in installments through October 2013 with interest ranging from 1.9% to 8.9% per annum			399				712
Total long-term debt			312,399				233,712
Less — current maturities			247				666
Total long term debt, net of current maturities		$	312,152			$	233,046

     The aggregate scheduled maturities of notes payable and long-term debt for the period ending December 31, 2012 and thereafter were as follows as of June 30, 2008 (assuming no payments were made on the revolving credit facilities prior to their maturity) (dollars in thousands):

2009		$	59
2010			142,053
2011			26
2012			170,007
Thereafter			7
		$	312,152

Credit Facilities

     The Company and its subsidiaries are parties to three credit facilities. See Note 3 to the consolidated financial statements included in the Annual Report on Form 10-K for the year ended December 31, 2007 (the “2007 Form 10-K”) for descriptions of the material terms of the credit facilities.

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

     On April 17, 2008, Quest Energy and Quest Cherokee entered into an amendment to the credit agreement. The amendment changed the maturity date from November 15, 2012 to November 15, 2010, and increased the applicable rate at which interest will accrue by 1% to either LIBOR plus a margin ranging from 2.25% to 2.875% (depending on the utilization percentage) or the base rate plus a margin ranging from 1.25% to 1.875% (depending on the utilization percentage). The amendment also eliminated the “accordion” feature in the credit agreement, which gave Quest Cherokee the option to request an increase in the aggregate revolving commitment from $250 million to $350 million. There was no commitment on the part of the lenders to agree to such a request.

     See Note 11 – Subsequent Events for a discussion of the increase in the borrowing base of the revolving credit facility and a new second lien senior term loan agreement.

     Quest Resource Corporation.  The Company is a party to a Credit Agreement dated as of November 15, 2007 with RBC, as administrative agent and collateral agent, and the lenders party thereto. As of June 30, 2008, the borrowing base under this credit agreement was $50 million and the amount borrowed under the credit agreement was $48 million. The weighted average interest rate under this credit agreement for the six months ended June 30, 2008 was 7.62%. See Note 11 – Subsequent Events for a discussion of the refinancing of the credit facility.

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

     Other Long-Term Indebtedness

     Approximately $399,000 of notes payable to banks and finance companies were outstanding at June 30, 2008 and are secured by equipment and vehicles, with payments due in monthly installments through October 2013 with interest ranging from 1.9% to 8.9% per annum.

6. Financial Instruments and Hedging Activities

     Natural Gas and Oil Hedging Activities

     The Company seeks to reduce its exposure to unfavorable changes in oil and natural gas prices, which are subject to significant and often volatile fluctuation, through the use of fixed-price contracts. The fixed-price contracts are comprised of energy swaps and collars. These contracts allow the Company to predict with greater certainty the effective oil and 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. As of June 30, 2008, fixed-price contracts are in place to hedge 46.3 MMBtu of estimated future natural gas production. Of this total volume, 9.2 MMBtu are hedged for 2008 and 37.1 MMBtu thereafter. As of June 30, 2008, fixed-price contracts are in place to hedge 84,000 Bbls of estimated future oil production. Of this total volume, 18,000 Bbls are hedged for 2008 and 66,000 Bbls thereafter.

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

     The following table summarizes the estimated volumes, fixed prices and fair value attributable to the fixed-price contracts as of June 30, 2008.

		Six Months
		Ending				Year Ending December 31,
		December 31,
		2008				2009				2010				2011				2012				Total
						(Dollars in thousands, except per MMBtu and Bbl data)
Natural Gas Swaps:
Contract volumes (MMBtu)			5,659,656				14,629,200				12,499,060				2,000,004				2,000,004				36,787,924
Weighted average fixed price per MMBtu(1)		$	6.98			$	7.78			$	7.42			$	8.00			$	8.11			$	7.57
Fair value, net		$	(22,159	)		$	(47,865	)		$	(34,117	)		$	(3,543	)		$	(3,150	)		$	(110,834	)
Natural Gas Collars:
Contract volumes (MMBtu):
Floor			3,532,984				—				—				3,000,000				3,000,000				9,532,984
Ceiling			3,532,984				—				—				3,000,000				3,000,000				9,532,984
Weighted average fixed price per MMBtu(1):
Floor		$	6.54			$	—			$	—			$	7.00			$	7.00			$	6.83
Ceiling		$	7.53			$	—			$	—			$	9.40			$	9.60			$	8.77
Fair value, net		$	(18,282	)		$	—			$	—			$	(5,432	)		$	(3,775	)		$	(27,489	)
Total Natural Gas Contracts(2):
Contract volumes (MMBtu)			9,192,640				14,629,200				12,499,060				5,000,004				5,000,004				46,320,908
Weighted average fixed price per MMBtu(1)		$	6.81			$	7.78			$	7.42			$	7.40			$	7.44			$	7.41
Fair value, net		$	(40,441	)		$	(47,865	)		$	(34,117	)		$	(8,975	)		$	(6,925	)		$	(138,323	)
Oil Swaps:
Contract volumes (Bbl)			18,000				36,000				30,000				—				—				84,000
Weighted average fixed price per Bbl(1)		$	95.92			$	90.07			$	87.50				—				—			$	90.91
Fair value, net		$	(805	)		$	(1,755	)		$	(1,405	)		$	—			$	—			$	(3,965	)

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2008				2007				2008				2007
		(Dollars in thousands)
Unrealized gains (losses)		$	(96,316	)		$	7,964			$	(139,344	)		$	(6,577	)
Realized gains (losses)			(9,059	)			427				(10,270	)			1,421
(Loss) gain from derivative financial instruments		$	(105,375	)		$	8,391			$	(149,614	)		$	(5,156	)

     The following table sets forth, by level within the fair value hierarchy, our assets and liabilities that were measured at fair value on a recurring basis as of June 30, 2008 (in thousands):

														Netting and
		Level				Level				Level				Cash				Total Net Fair
		1				2				3				Collateral*				Value
Derivative financial instruments — assets		$	—			$	—			$	11,373			$	—			$	11,373
Derivative financial instruments — liabilities		$	—			$	(29,197	)		$	(124,464	)		$	—			$	(153,661	)
Total		$	—			$	(29,197	)		$	(113,091	)		$	—			$	(142,288	)

     Interest Rate Hedging Activities

     At June 30, 2008, the Company had no outstanding interest rate cap or swap agreements.

     Gain (Loss) from Derivative Financial Instruments

     Change in derivative fair value in the statements of operations for the three and six months ended June 30, 2008 and 2007 is comprised of the following:

     Risk management assets and liabilities in the table above represent the current fair value of all open derivative positions, excluding those derivatives designated as “normal purchases, normal sales”. We classify all of these derivative instruments as “Derivative financial instrument assets” or “Derivative financial instrument liabilities” in our consolidated balance sheets.

     In order to determine the fair value amounts presented above, we utilize various factors, including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and parental guarantees), but also the impact of our nonperformance risk on our liabilities. We utilize observable market data for credit default swaps to assess the impact of non-performance credit risk when evaluating our assets from counterparties.

     In certain instances, we may utilize internal models to measure the fair value of our derivative instruments. Generally, we use similar models to value similar instruments. Valuation models utilize various inputs which include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the assets or liabilities, and market-corroborated inputs, which are inputs derived principally from or corroborated by observable market data by correlation or other means.

     The following table sets forth a reconciliation of changes in the fair value of risk management assets and liabilities classified as Level 3 in the fair value hierarchy (in thousands):

Balance at beginning of year		$	3,444
Realized and unrealized gains included in earnings			(112,595	)
Purchases, sales, issuances, and settlements			(3,940	)
Transfers into and out of Level 3			—
Balance as of June 30, 2008		$	(113,091	)

     Credit Risk

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

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

     Market Risk

     The differential between the floating price paid under each energy swap or collar contract and the price received at the wellhead for the Company’s production is termed “basis” and is the result of differences in location, quality, contract terms, timing and other variables. For

instance, some of the Company’s fixed-price contracts are tied to commodity prices on the NYMEX, that is, the Company receives the fixed price amount stated in the contract and pay to its counterparty the current market price for natural gas as listed on the NYMEX. However, due to the geographic location of the Company’s natural gas assets and the cost of transporting the natural gas to another market, the amount that the Company receives when it actually sells its natural gas is based on the Southern Star Central TX/KS/OK (“Southern Star”) first of month index, with a small portion being sold based on the daily price on the Southern Star index. The difference between natural gas prices on the NYMEX and the price actually received by the Company is referred to as a basis differential. Typically, the price for natural gas on the Southern Star first of the month index is less than the price on the NYMEX due to the more limited demand for natural gas on the Southern Star first of the month index. The crude oil production for which the Company has entered into swap agreements is sold at a contract price based on the average daily settling price of NYMEX less $1.10/Bbl, which eliminates our exposure to changing differentials on this production. This contract runs through March 2009 with automatic extensions thereafter unless terminated by either party.

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

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

     Fair Value Measurements

     The Company’s financial instruments consist of cash, receivables, deposits, derivative contracts, accounts payable, accrued expenses and notes payable. The carrying amount of cash, receivables, deposits, accounts payable and accrued expenses approximates fair value because of the short-term nature of those instruments. The derivative contracts are not designated as hedges, and therefore, are recorded at fair value. The carrying amounts for notes payable approximate fair value due to the variable nature of the interest rates of the notes payable.

7. Earnings Per Share

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

	•		For the three and six months ended June 30, 2007, dilutive shares do not include the assumed exercise of stock options and stock awards.
	•		For the three and six months ended June 30, 2008, dilutive shares do not include the assumed exercise of stock options and stock awards.

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

		Income				Shares				Per Share
		(Numerator)				(Denominator)				Amount
Three months ended June 30, 2008:
Net loss		$	(57,886	)
Basic EPS available to common shareholders		$	(57,886	)			22,844,600			$	(2.53	)
Effect of dilutive securities:
None							—				—
Diluted EPS available to common shareholders		$	(57,886	)			22,844,600			$	(2.53	)
Three months ended June 30, 2007:
Net loss		$	(1,380	)
Basic EPS available to common shareholders		$	(1,380	)			22,351,611			$	(0.06	)
Effect of dilutive securities:
None							—				—
Diluted EPS available to common shareholders		$	(1,380	)			22,351,611			$	(0.06	)

		Income				Shares				Per Share
		(Numerator)				(Denominator)				Amount
Six months ended June 30, 2008:
Net loss		$	(82,981	)
Basic EPS available to common shareholders		$	(82,981	)			22,742,289			$	(3.65	)
Effect of dilutive securities:
None			—				—				—
Diluted EPS available to common shareholders		$	(82,981	)			22,742,289			$	(3.65	)
Six months ended June 30, 2007:
Net loss		$	(23,440	)
Basic EPS available to common shareholders		$	(23,440	)			22,307,365			$	(1.05	)
Effect of dilutive securities:
None			—				—				—
Diluted EPS available to common shareholders		$	(23,440	)			22,307,365			$	(1.05	)

8. Partners’ Capital and Cash Distributions

     Quest Energy Distributions to Unitholders

     Minimum Quarterly Distribution. Quest Energy will distribute to the holders of its common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.40 per unit, or $1.60 per year, to the extent Quest Energy has sufficient cash from its operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner. However, there is no guarantee that Quest Energy will pay the minimum quarterly distribution on the units in any quarter. Even if Quest Energy’s cash distribution policy is not modified or revoked, the amount of distributions paid under its policy and the decision to make any distribution is determined by its general partner, taking into consideration the terms of Quest Energy’s partnership agreement. Quest Energy will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under its credit facility. Please read Note 4 to the consolidated financial statements included in the 2008 Form 10-K for a discussion of the restrictions included in Quest Energy’s credit facility that restrict its ability to make distributions.

     General Partner Interest and Incentive Distribution Rights. Initially, Quest Energy’s general partner will be entitled to 2% of all quarterly distributions since inception that Quest Energy makes prior to its liquidation. The 2% general partner interest in the distributions may be reduced if Quest Energy issues additional units in the future and its general partner does not contribute a proportionate amount of capital to Quest Energy to maintain its 2% general partner interest. Quest Energy’s general partner has all of the incentive distribution rights entitling it to receive up to 23% of Quest Energy’s cash distributions above certain target distribution levels in addition to its 2% general partner interest. See Item 5. “Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities — Cash Distributions to Unitholders” in Quest Energy’s Annual Report on Form 10-K for the year ended December 31, 2008 for further discussion of its cash distributions.

     Quest Midstream Distributions to Unitholders

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

minimum quarterly distribution on common units from prior quarters, to the extent Quest Midstream has sufficient cash from its operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner. However, there is no guarantee that Quest Midstream will pay the minimum quarterly distribution on the units in any quarter. Even if Quest Midstream’s cash distribution policy is not modified or revoked, the amount of distributions paid under its policy and the decision to make any distribution is determined by its general partner, taking into consideration the terms of Quest Midstream’s partnership agreement. Quest Midstream will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under its credit facility. Please read Note 4 to the consolidated financial statements included in the 2008 Form 10-K for a discussion of the restrictions included in Quest Midstream’s credit facility that restrict its ability to make distributions.

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

9. Commitments and Contingencies

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

     STP, Inc., STP Cherokee, Inc. (now STP Cherokee, LLC), Bluestem Pipeline, LLC, Quest Cherokee, LLC, and Quest Energy Service, LLC (improperly named Quest Energy Services, LLC) were named defendants in a lawsuit by Plaintiffs John C. Kirkpatrick and Suzan M. Kirkpatrick in the District Court for Craig County (Case No. CJ-2005-143). Plaintiffs alleged that STP, Inc., et al., sold natural gas from wells owned by the Plaintiffs without providing the requisite notice to Plaintiffs. Plaintiffs further alleged that Defendants failed to include deductions on the check stubs of Plaintiffs in violation of state law and that Defendants deducted for items other than compression in violation of the lease terms. Plaintiffs asserted claims of actual and constructive fraud and further seek an accounting stating that if Plaintiffs had suffered any damages for failure to properly pay royalties, Plaintiffs had a right to recover those damages. Plaintiffs had not quantified their alleged damages. In August 2008, the parties entered into a settlement agreement and the lawsuit was dismissed with prejudice. See Note 11 — Subsequent Events.

     Quest Cherokee Oilfield Services, LLC has been named in this lawsuit filed by Plaintiffs Segundo Francisco Trigoso and Dana Jara De Trigoso in the District Court of Oklahoma County, Oklahoma (Case No. CJ-2007-11079). Plaintiffs allege that Plaintiff Segundo Trigoso was injured while working for Defendant on September 29, 2006 and that such injuries were intentionally caused by Defendant. Plaintiffs seek unspecified damages for physical injuries, emotional injuries, loss of consortium and pain and suffering. Plaintiffs also seek punitive damages. Defendant intends to defend vigorously against Plaintiffs’ claims.

     Quest Cherokee and Bluestem were named as defendants in a lawsuit (Case No. 04-C-100-PA) filed by plaintiff Central Natural Resources, Inc. on September 1, 2004 in the District Court of Labette County, Kansas. Central Natural Resources owns the coal underlying numerous tracts of land in Labette County, Kansas. Quest Cherokee has obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying some of that land and has drilled wells that produce coal bed methane gas on that land. Bluestem purchases and gathers the gas produced by Quest Cherokee. Plaintiff alleges that it is entitled to the coal bed methane gas produced and revenues from these leases and that Quest Cherokee is a trespasser. Plaintiff is seeking quiet title and an equitable accounting for the revenues from the coal bed methane gas produced. Plaintiff has alleged that Bluestem converted the gas and seeks an accounting for all gas purchased by Bluestem from the wells in issue. Quest Cherokee contends it has valid leases with the owners of the coal bed methane gas rights. The issue is whether the coal bed methane gas is owned by the owner of the coal rights or by the owners of the gas rights. If Quest Cherokee prevails on that issue, then the plaintiff’s claims against Bluestem fail. All issues relating to ownership of the coal bed methane gas and damages have been bifurcated. Cross motions for summary judgment on the ownership of the coal bed methane were filed by Quest Cherokee and the plaintiff, with summary judgment being awarded in Quest Cherokee’s favor. The plaintiff has appealed the summary judgment ruling, and the appeal is pending before the Kansas Supreme Court. The case was argued on December 4, 2007, and to date, the Kansas Supreme Court has not yet issued an opinion.

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

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

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

     Quest Cherokee has been named as a defendant or counterclaim defendant in several lawsuits in which the plaintiffs claim that oil and gas leases owned and operated by Quest Cherokee have either expired by their terms or, for various reasons, have been forfeited by Quest Cherokee. Those lawsuits were originally filed in the district courts of Labette, Montgomery, Wilson, Neosho and Elk Counties, Kansas. Quest Cherokee has drilled wells on some of the oil and gas leases in issue and some of those oil and gas leases do not have a well located thereon but have been unitized with other oil and gas leases upon which a well has been drilled. As of July 31, 2008, the total amount of acreage covered by the leases at issue in these lawsuits was approximately 7,553 acres. Quest Cherokee intends to vigorously defend against those claims.

     Quest Cherokee was named in an Order to Show Cause issued by the Kansas Corporation Commission (the “KCC”) (KCC Docket No. 07-CONS-155-CSHO) filed on February 23, 2007. The KCC had ordered Quest Cherokee to demonstrate why it should not be held responsible for plugging 22 abandoned oil wells on a gas lease owned and operated by Quest Cherokee in Wilson County, Kansas. Quest Cherokee denied that it is legally responsible for plugging the wells in issue. On July 16, 2008, Quest Cherokee received a favorable ruling on this matter. See Note 11 — Subsequent Events.

     Quest Cherokee was named as a defendant in two lawsuits (Case No. 07-CV-141 and Case No. 08-CV-20) filed in Neosho County District Court by Richard Winder, d/b/a Winder Oil Company. Plaintiff claims to own an oil and gas lease covering lands upon which Quest Cherokee also claims to own an oil and gas lease and upon which Quest Cherokee has drilled two producing wells. Plaintiff claims that his lease is prior and superior to Quest Cherokee’s leases and seeks damages for trespass and conversion. Quest Cherokee contends that plaintiffs leases have expired by their terms and that Quest Cherokee's leases are valid. Discovery in that case is ongoing. Quest Cherokee intends to vigorously defend against the Plaintiff's claims.

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

10. Operating Segment Information

     We divide our operations into two reportable business segments:

	•		Quest Energy — oil and natural gas production focused on coal bed methane production in the Cherokee Basin; and
	•		Quest Midstream — transporting, selling, gathering and treating natural gas.

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

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

		Three months								Six months
		ended June 30,								ended June 30,
		2008				2007				2008				2007
Quest Energy (Oil and Natural Gas Production)
Revenues		$	49,144			$	27,570			$	87,458			$	52,544
Costs and expenses			33,529				25,079				63,225				48,317
Segment (loss) profit		$	15,615			$	2,491			$	24,233			$	4,227
Quest Midstream (Natural Gas Pipelines):
Revenues -
Gathering—Third party		$	7,148			$	1,792			$	14,049			$	3,334
Gathering-Intercompany			8,675				6,920				17,338				13,281
Total natural gas pipelines revenue			15,823				8,712				31,387				16,615
Costs and expenses			12,385				5,440				23,605				11,480
Segment profit		$	3,438			$	3,272			$	7,782			$	5,135
Reconciliation of segment (loss) profit to net loss before income taxes and minority interests:
Segment (loss) profit -
Oil and gas production		$	15,615			$	2,491			$	24,233			$	4,227

		Three months								Six months
		ended June 30,								ended June 30,
		2008				2007				2008				2007
Natural gas pipelines			3,438				3,272				7,782				5,135
Total segment profit			19,053				5,763				32,015				9,362
General and administrative expenses			(6,198	)			(6,417	)			(11,941	)			(8,971	)
Misappropriation of funds			—				(500	)			—				(1,000	)
Total operating loss			12,855				(1,154	)			20,074				(609	)
Interest expense, net			(5,174	)			(7,411	)			(10,057	)			(15,696	)
(Loss) gain on derivative financial instruments			(105,375	)			8,391				(149,614	)			(5,156	)
Other income (expenses) and sale of assets			42				(317	)			122				(223	)
Net loss before income taxes and minority interests		$	(97,652	)		$	(491	)		$	(139,475	)		$	(21,684	)

		June 30, 2008				December 31, 2007
Identifiable Assets:
Quest Energy (oil and natural gas production)		$	368,042			$	320,880
Quest Midstream (Natural gas pipelines)			300,415				296,104
Total		$	668,457			$	616,984

11. Subsequent Events

     Equity Offering

     On July 8, 2008, the Company closed on a public offering of 8,800,000 shares of its common stock at a price of $10.25 per share, resulting in net proceeds, after payment of expenses, of approximately $85.2 million. The Company used the net proceeds of the offering (1) to fund a portion of the $141.6 million acquisition, subject to post-closing adjustments, of privately held PetroEdge Resources (WV) LLC (“PetroEdge”), (2) to repay a portion of the Company’s existing revolving credit facility, (3) to pay fees and expenses related to the PetroEdge acquisition and (4) for general corporate purposes, including drilling and development activities.

     PetroEdge Acquisition

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

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

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

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

Other

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

     On July 24, 2008, Quest Energy filed a registration statement on Form S-1 with the SEC relating to a proposed offering of 4,600,000 common units. Quest Energy intends to use any net proceeds from the sale of such units to repay indebtedness, including its Second Lien Loan Agreement.

     On July 25, 2008, the board of directors of Quest Energy’s general partner declared a $0.43 per unit distribution for the second quarter of 2008 on all common and subordinated units payable on August 14, 2008 to unitholders of record as of the close of business on August 4, 2008. The aggregate amount of the distribution will be $9.30 million.

     The parties involved in the Kirkpatrick lawsuit (Case No. CJ-2005-143) entered into a confidential settlement agreement and release dated July 31, 2008, and the lawsuit will be dismissed with prejudice.

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

     As reported on a Current Report on Form 8-K filed on January 2, 2009, on December 31, 2008, the board of directors of QRCP determined that the consolidated financial statements of QRCP as of and for the years ended December 31, 2007, 2006 and 2005 and its unaudited consolidated financial statements as of and for the three months ended March 31, 2008 and as of and for the three and six months ended June 30, 2008 should no longer be relied upon as the result of the discovery of the Transfers to entities controlled by QRCP’s former chief executive officer, Mr. Jerry D. Cash. Management identified other errors in these financial statements, as described below, and the board of directors concluded that QRCP had, and as of December 31, 2008 continued to have, material weaknesses in its internal control over financial reporting.

     The Form 10-Q/A for the quarterly period ended June 30, 2008, to which these consolidated financial statements form a part, includes restated consolidated financial statements for QRCP as of June 30, 2008 and for the three and six month periods ended June 30, 2008 and for the three and six month periods ended and June 30, 2007. The financial statements, as of December 31, 2007 were restated in the 2008 Annual Report on Form 10-K.

     Although the items listed below comprise the most significant errors (by dollar amount), numerous other errors were identified and restatement adjustments made. The tables below present previously reported stockholders’ deficit, major restatement adjustments and restated stockholders’ deficit  as well as previously reported net income (loss), major restatement adjustments and restated net loss as of and for the periods indicated (in thousands):

		June 30, 2008
Stockholders’ deficit  as previously reported		$	(39,192	)
A — Effect of the Transfers			(10,000	)
B — Reversal of hedge accounting			3,658
C — Accounting for formation of Quest Cherokee			(19,003	)
D — Capitalization of costs in full cost pool			(31,091	)
E — Recognition of costs in proper periods			(3,252	)
F — Capitalized interest			1,999
G — Stock-based compensation			—
H — Depreciation, depletion and amortization			9,575
I — Impairment of oil and gas properties			30,719
J — Other errors			53,419
Stockholders’ deficit  as restated		$	(3,168	)

		Three Months Ended
		June 30,
		2008				2007
Net income (loss) as previously reported		$	4,964			$	(4,487	)
A — Effect of the Transfers			—				(500	)
B — Reversal of hedge accounting			(105,179	)			7,685
C — Accounting for formation of Quest Cherokee			26				26
D — Capitalization of costs in full cost pool			(3,425	)			(3,028	)
E — Recognition of costs in proper periods			(2,015	)			(792	)
F — Capitalized interest			143				86
G — Stock-based compensation			446				104
H — Depreciation, depletion and amortization			(484	)			(237	)
I — Impairment of oil and gas properties			—				—
J — Other errors (*)			47,638				(237	)
Net loss as restated		$	(57,886	)		$	(1,380	)

		Six Months Ended June 30,
		2008				2007
Net loss as previously reported		$	(6,678	)		$	(7,798	)
A — Effect of the Transfers			—				(1,000	)
B — Reversal of hedge accounting			(124,375	)			(6,394	)
C — Accounting for formation of Quest Cherokee			52				52
D — Capitalization of costs in full cost pool			(7,155	)			(5,370	)
E — Recognition of costs in proper periods			(1,265	)			(703	)
F — Capitalized interest			286				173
G — Stock-based compensation			15				(241	)
H — Depreciation, depletion and amortization			(875	)			(776	)
I — Impairment of oil and gas properties			—				—
J — Other errors (*)			57,014				(1,383	)
Net loss as restated		$	(82,981	)		$	(23,440	)

     The most significant errors (by dollar amount) consist of the following:

     (A) The Transfers, which were not approved expenditures of QRCP, were not properly accounted for as losses. As a result of these losses not being recorded, cash and accumulated deficit were overstated as of June 30, 2008 and December 31, 2007, and loss from misappropriation of funds was understated was overstated for the year ended December 31, 2007.

     (B) Hedge accounting was inappropriately applied for the Company’s commodity derivative instruments and the valuation of commodity derivative instruments was incorrectly computed. The fair value of the commodity derivative instruments previously reported were under stated by $5.5 million as of June 30, 2008. In addition, we incorrectly presented realized gains and losses related to commodity derivative instruments within oil and gas sales. As a result of these errors, current and long-term derivative financial instrument assets, current and long-term derivative financial instrument liabilities, accumulated other comprehensive income and accumulated deficit were over/(under)stated as of June 30, 2008 and December 31, 2007, and oil and gas sales, gain (loss) from derivative financial instruments were over/(under)stated for the three and six month periods ended June 30, 2008 and for the three and six month periods ended and June 30, 2007.

     (C) Errors were identified in the accounting for the formation of Quest Cherokee in December 2003 in which: (i) no value was ascribed to the subsidiary Class A units that were issued to ArcLight Energy Partners Fund I, L.P. in connection with the transaction, (ii) a debt discount (and related accretion) and minority interest were not recorded, (iii) transaction costs were inappropriately capitalized to oil and gas properties, and (iv) subsequent to December 2003, interest expense was improperly stated as a result of these errors. In 2005, the debt relating to this transaction was repaid and the Class A units were repurchased. Due to the errors that existed in the previous accounting, additional errors resulted in 2005 including: (i) a loss on extinguishment of debt was not recorded, and (ii) oil and gas properties, pipeline assets were overstated. Subsequent to the 2005 transaction, depreciation, depletion and amortization expense was also overstated due to these errors.

     (D) Certain general and administrative expenses unrelated to oil and gas production were inappropriately capitalized to oil and gas properties, and certain operating expenses were inappropriately capitalized to oil and gas properties being amortized. These items resulted in errors in valuation of the full cost pool, oil and gas production expenses and general and administrative expenses. As a result of these errors, oil and gas properties being amortized and accumulated deficit were over/(under)stated as of June 30, 2008 and December 31, 2007, and oil and gas production expenses, general and administrative expenses were over/(under)stated for the three and six month periods ended June 30, 2008 and for the three and six month periods ended and June 30, 2007.

     (E) Invoices were not properly accrued resulting in the understatement of accounts payable and numerous other balance sheet and income statement accounts. As a result of these errors, accounts receivable, other current assets, property and equipment, pipeline assets, properties being and not being amortized and accumulated deficit were over/(under)stated as of June 30, 2008 and December 31, 2007, and oil and gas production expenses, pipeline operating expenses, and general and administrative expenses were over/(under)stated for the three and six month periods ended June 30, 2008 and for the three and six month periods ended and June 30, 2007.

     (F) Capitalized interest was not recorded on pipeline construction. As a result of this error, pipeline assets and accumulated deficit were understated as of June 30, 2008 and December 31, 2007, and interest expense was overstated for the three and six month periods ended June 30, 2008 and for the three and six month periods ended and June 30, 2007.

     (G) Errors were identified in stock-based compensation expense, including the use of incorrect grant dates, valuation errors, and incorrect vesting periods. As a result of these errors, additional paid-in capital and accumulated deficit were over/(under)stated as of June 30, 2008, and general and administrative expenses were over/(under)stated for the three and six month periods ended June 30, 2008 and for the three and six month periods ended and June 30, 2007.

     (H) As a result of previously discussed errors and an additional error related to the method used in calculating depreciation, depletion and amortization, errors existed in our depreciation, depletion and amortization expense and our accumulated depreciation, depletion and amortization. As a result of these errors, accumulated depreciation, depletion and amortization were over/(under)stated as of June 30, 2008 and depreciation, depletion and amortization expense was over/(under)stated for the three and six month periods ended June 30, 2008 and for the three and six month periods ended and June 30, 2007.

     (I) As a result of previously discussed errors relating to oil and gas properties and hedge accounting and errors relating to the treatment of deferred taxes, errors existed in our ceiling test calculations. As a result of these errors, the Company incorrectly recorded a $30.7 million impairment to its oil and gas properties during the year ended December 31, 2006.

     (J) We identified other errors during the restatement process where the impact on net income was not deemed significant enough to warrant separate disclosure of individual errors. Included in this amount is the minority interest effect of the errors discussed above.

     Outstanding shares — Errors were identified in the calculation of outstanding shares in all periods as we inappropriately included restricted share grants in our calculation of issued shares when the restrictions lapsed, rather than the date at which the restricted shares were granted. This error did not affect net income, but did impact our issued and outstanding share amounts as well as our weighted average share amounts (in thousands):

		June 30, 2008
Previously reported issued shares			23,975
Total restatement adjustments			(71	)
Restated issued shares			23,904

		June 30, 2008
Previously reported outstanding shares			23,975
Total restatement adjustments			(1,094	)
Restated outstanding shares			22,881

     The following table outlines the effects of the restatement adjustments on our Consolidated Statement of Operations for the period indicated (in thousands, except share and per share data):

		Three Months Ended June 30, 2008
		As Previously Reported				Restatement Adjustments				As Restated
Revenue:
Oil and gas sales		$	39,903			$	9,241			$	49,144
Gas pipeline revenue			7,148				—				7,148
Other revenue (expense)			72				(72	)			—
Total revenues			47,123				9,169				56,292
Costs and expenses:
Oil and gas production			9,763				2,868				12,631
Pipeline operating			8,257				(93	)			8,164
General and administrative			6,308				(110	)			6,198
Depreciation, depletion and amortization			14,296				2,148				16,444
Total costs and expenses			38,624				4,813				43,437
Operating income (loss)			8,499				4,356				12,855
Other income (expense):
Sale of assets			(30	)			—				(30	)
Gain (loss) from derivative financial instruments			8,695				(114,070	)			(105,375	)
Other income (expense)			—				72				72
Interest expense			(5,278	)			—				(5,278	)
Interest income			104				—				104
Total other income (expense)			3,491				(113,998	)			(110,507	)
Net income (loss) before minority interest			11,990				(109,642	)			(97,652	)
Minority interest			(7,026	)			46,792				39,766
Net income (loss)		$	4,964			$	(62,850	)		$	(57,886	)
Net income (loss) per common share — basic		$	0.21			$	(2.74	)		$	(2.53	)
Net income (loss) per common share — diluted		$	0.21			$	(2.74	)		$	(2.53	)
Weighted average common and common equivalent shares:
Basic			23,772,788				(928,188	)			22,844,600
Diluted			23,831,481				(986,881	)			22,844,600