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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2008

Commission file number: 0-17371

QUEST RESOURCE CORPORATION

(Exact Name of Registrant as Specified in Its Charter)


Nevada		90-0196936
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

210 Park Avenue, Suite 2750 Oklahoma City, Oklahoma (Address of Principal Executive Offices)		73102 (Zip Code)

Registrant’s telephone number, including area code:

405-600-7704

Securities Registered Pursuant to Section 12(b) of the Exchange Act:


Title of Each Class		Name of Each Exchange on Which Registered

Common Stock		NASDAQ Global Market
Series B Junior Participating Preferred Stock Purchase Rights		NASDAQ Global Market

Securities Registered Pursuant to Section 12(g) of the Exchange Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes o No þ

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 preceding 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 has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

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 Act). Yes o No þ

The aggregate market value of the voting common equity held by non-affiliates computed by reference to the last reported sale of the registrant’s common stock on June 30, 2008, the last business day of the registrant’s most recently completed second fiscal quarter, at $11.41 per share was $221,824,377. This figure assumes that only the directors and officers of the registrant, their spouses and controlled corporations were affiliates. There were 31,867,527 shares outstanding of the registrant’s common stock as of May 15, 2009.

DOCUMENTS INCORPORATED BY REFERENCE

None

TABLE OF CONTENTS


PART I
ITEMS 1. AND 2.	BUSINESS AND PROPERTIES	6
ITEM 1A.	RISK FACTORS	44
ITEM 1B.	UNRESOLVED STAFF COMMENTS	71
ITEM 3.	LEGAL PROCEEDINGS	71
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	76

PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	76
ITEM 6.	SELECTED FINANCIAL DATA	79
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	80
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	112
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	115
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	115
ITEM 9A.	CONTROLS AND PROCEDURES	115
ITEM 9B.	OTHER INFORMATION	118

PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	119
ITEM 11.	EXECUTIVE COMPENSATION	122
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	141
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	143
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	144

PART IV
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	145
SIGNATURES		146
INDEX TO EXHIBITS		147
EX-10.2
EX-10.7
EX-10.10
EX-10.11
EX-10.22
EX-10.23
EX-10.32
EX-10.41
EX-10.42
EX-10.48
EX-10.61
EX-10.62
EX-10.67
EX-10.88
EX-10.89
EX-21.1
EX-23.1
EX-23.2
EX-24.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2

EXPLANATORY NOTE

This Annual Report on Form 10-K for the year ended December 31, 2008 includes restated and reaudited consolidated financial statements for Quest Resource Corporation (“QRCP” or the “Company”) as of December 31, 2007 and 2006 and for the periods ended December 31, 2007, 2006 and 2005. QRCP will subsequently file (i) an amended Quarterly Report on Form 10-Q/A for the quarter ended March 31, 2008 including restated consolidated financial statements as of December 31, 2007 and March 31, 2008 and for the three month periods ended March 31, 2008 and 2007; (ii) an amended Quarterly Report on Form 10-Q/A for the quarter ended June 30, 2008 including restated consolidated financial statements as of December 31, 2007 and June 30, 2008 and for the three and six month periods ended June 30, 2008 and 2007; and (iii) a Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 including restated consolidated financial statements as of December 31, 2007 and for the three and nine month periods ended September 30, 2007.

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 months 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-K 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.

	•	Errors were identified in the accounting for the formation of Quest Cherokee, LLC (“Quest Cherokee”) in December 2003 in which: (i) no value was ascribed to the Quest Cherokee Class A units that were issued to Arclight Energy Partners Fund I, L.P. (“ArcLight”) 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 from ArcLight. 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 and retained earnings were overstated. Subsequent to the 2005 transaction, depreciation, depletion and amortization expense was also overstated due to these errors.


	•	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) equity, major restatement adjustments and restated stockholders’ (deficit) equity as well as previously reported net income (loss), major restatement adjustments and restated net income (loss) as of and for the periods indicated (in thousands):


	As of December 31,
	2007			2006			2005

Stockholders’ (deficit) equity as previously reported	$	91,853		$	117,354		$	115,673
Effect of the Transfers		(10,000	)		(8,000	)		(2,000	)
Reversal of hedge accounting		707			(2,389	)		(8,177	)
Accounting for formation of Quest Cherokee		(19,055	)		(19,159	)		(19,185	)
Capitalization of costs in full cost pool		(23,936	)		(12,748	)		(5,388	)
Recognition of costs in proper periods		(1,987	)		(321	)		(316	)
Capitalized interest		1,713			1,367			286
Stock-based compensation		—			—			—
Depreciation, depletion and amortization		10,450			7,209			3,275
Impairment of oil and gas properties		30,719			30,719			—
Other errors		(3,695	)		809			(383	)

Stockholders’ (deficit) equity as restated	$	76,769		$	114,841		$	83,785


	Years Ended December 31,
	2007			2006			2005

Net income (loss) as previously reported	$	(30,414	)	$	(48,478	)	$	(31,951	)
Effect of the Transfers		(2,000	)		(6,000	)		(2,000	)
Reversal of hedge accounting		1,183			53,387			(42,854	)
Accounting for formation of Quest Cherokee		104			26			(14,402	)
Capitalization of costs in full cost pool		(11,188	)		(7,360	)		(5,388	)
Recognition of costs in proper periods		(1,666	)		(5	)		721
Capitalized interest		346			1,081			154
Stock-based compensation		(702	)		405			(790	)
Depreciation, depletion and amortization		3,241			3,934			757
Impairment of oil and gas properties		—			30,719			—
Other errors(*)		(3,058	)		1,799			(132	)

Net income (loss) as restated	$	(44,154	)	$	29,508		$	(95,885	)

* Includes minority interest impact.

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 18 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 was uncovered prior to the preparation of the financial statements for such period, and therefore did not result in a restatement.

	•	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 beginning in 2005.

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 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.

All dollar amounts and other data presented in previously filed Annual Reports on Form 10-K for prior years have been revised to reflect the restated amounts throughout this Form 10-K, even where such amounts are not labeled as restated.

PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES.

General

Quest Resource Corporation is a Nevada corporation. Our principal executive offices are located at 210 Park Avenue, Suite 2750, Oklahoma City, Oklahoma 73102 and our telephone number is (405) 600-7704. Unless the context clearly requires otherwise, references in this report to “we,” “us,” and “our” refer to the Company and its subsidiaries and affiliates, including Quest Energy and Quest Midstream, on a consolidated basis. Quest Energy is a publicly traded limited partnership engaged in oil and gas production operations. Quest Midstream is a private limited partnership engaged in natural gas pipeline operations.

We are an integrated independent energy company engaged in the acquisition, exploration, development, production and transportation of oil and natural gas.

We divide our operations into two reportable business segments:


	•	Oil and gas production, and

	•	Natural gas pipelines, including transporting, gathering, treating and processing natural gas.

Financial information by segment and revenues from our external customers are located in Item 8. “Financial Statements and Supplementary Data” to this Annual Report on Form 10-K.

Quest Resource Corporation

QRCP’s assets as of May 15, 2009 consist of the following:


	•	Approximately 45,732 net acres, five gross wells in various stages of completion and approximately 183 miles of gas gathering pipeline in the Appalachian Basin, owned by QRCP’s wholly-owned subsidiary, Quest Eastern Resource LLC (“Quest Eastern”).

	•	3,201,521 common units and 8,857,981 subordinated units in Quest Energy representing an approximate 55.9% limited partner interest in Quest Energy.

	•	All of the membership interests in Quest Energy GP, the general partner of Quest Energy, which owns the 2.0% general partner interest in Quest Energy and all of the incentive distribution rights in Quest Energy.

	•	35,134 Class A subordinated units and 4,900,000 Class B subordinated units in Quest Midstream representing an approximate 35.69% limited partner interest in Quest Midstream.

	•	85% of the membership interests in Quest Midstream GP, the general partner of Quest Midstream, which owns the 2.0% general partner interest in Quest Midstream and all of the incentive distribution rights in Quest Midstream.

The following chart reflects a simplified version of our organizational structure to better illustrate how we own our assets.

Since the initial public offering of Quest Energy in November 2007, QRCP’s potential sources of revenue and cash flows consist almost exclusively of distributions on its partnership interests in Quest Energy and Quest Midstream, because its Appalachian Basin assets largely consist of undeveloped acreage. Both Quest Energy and Quest Midstream are required by the terms of their partnership agreements to distribute all cash on hand at the end of each quarter, less reserves established by their general partners in their sole discretion to provide for the proper conduct of their respective businesses or to provide for future distributions.

In light of the decline in QELP’s cash flows from operations due to declines in oil and natural gas prices during the last half of 2008, the costs of the investigation and associated remedial actions, including the reaudit and restatement of its financial statements, and concerns about a potential borrowing base redetermination in the second quarter of 2009 and the need to repay or refinance QELP’s term loan by September 30, 2009, the board of directors of Quest Energy GP decided to suspend distributions on QELP’s subordinated units for the third quarter of 2008 and on all units starting with the distribution for the fourth quarter of 2008 in order to conserve cash to properly conduct operations, maintain strategic options and plan for future required principal payments under Quest Energy’s debt instruments. QRCP would have received approximately $20 million from Quest Energy during 2009 if the minimum quarterly distribution of $0.40 was paid on all of Quest Energy’s units for the full year.

Quest Midstream did not pay any distributions on any of its units for the third or fourth quarters of 2008 because of a restriction imposed under the terms of an amendment to its credit agreement which provided that no distributions could be paid until the audited financial statements for the year ended December 31, 2008 were delivered to the lenders and thereafter could only be paid if, after the payment of such distributions, the total leverage ratio was not greater than 4.0 to 1.0. The Quest Midstream audited financial statements for the year ended December 31, 2008 were delivered on March 31, 2009.

QRCP received cash distributions from Quest Energy of $1.9 million during the first quarter of 2008, $3.8 million during the second quarter of 2008, $4.0 million during the third quarter of 2008 and $0.2 million during the fourth quarter of 2008. QRCP did not receive any cash distributions from Quest Midstream during 2008. No distributions have ever been paid on the Quest Energy or Quest Midstream incentive distribution rights.

QRCP does not expect to receive any distributions from Quest Energy or Quest Midstream in 2009 and is unable to estimate at this time when such distributions may be resumed. In October and November of 2008, QRCP’s credit agreement and the credit agreements for each of Quest Energy and Quest Midstream were amended. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Agreements.” The amended terms of the credit agreements restrict the ability of Quest Energy and Quest Midstream to pay distributions, among other things. Even if the restrictions on the payment of distributions under Quest Energy’s and Quest Midstream’s credit agreements are removed, both partnerships may continue to not pay distributions in order to conserve cash for the repayment of indebtedness or other business purposes.

Arrearages accrue for the unpaid distributions on the common units in Quest Energy and Quest Midstream and the related distributions on the general partner units. Quest Energy and Quest Midstream are not obligated to ever pay these amounts, but they may not make distributions on the subordinated units QRCP owns until all arrearages on the common units and the related general partner units have been paid. The majority of the interests QRCP owns, however, are subordinated units. QRCP owns 8,857,981 subordinated units in Quest Energy and 35,134 Class A subordinated units and 4,900,000 Class B subordinated units in Quest Midstream. QRCP also indirectly owns incentive distribution rights in Quest Energy and Quest Midstream that would entitle it to receive an increasing percentage of cash distributed by each of Quest Energy and Quest Midstream if certain target distribution levels were reached. No incentive distributions can be paid in a quarter until all arrearages on the common units have been paid and the minimum quarterly distribution has been paid for that quarter on all common units and subordinated units. The subordinated units and the incentive distribution rights do not accrue arrearages.

Even if Quest Energy and Quest Midstream do not pay distributions, the Company and all other unitholders may be liable for taxes on their share of each of Quest Energy and Quest Midstream’s taxable income.

Although QRCP is not currently receiving distributions from Quest Energy or Quest Midstream, QRCP continues to require cash to fund general and administrative expenses, debt service requirements, capital expenditures to develop and maintain its undeveloped acreage, drilling commitments and payments to landowners necessary to maintain its oil and gas leases, which are expected to average $2.7 million per quarter for 2009.

As of December 31, 2008, excluding QELP and QMLP, QRCP had cash and cash equivalents of $4.0 million and no ability to borrow under the terms of its credit agreement. QRCP currently estimates that it will not have enough cash to pay its expenses, including capital expenditures and debt service requirements, after August 31, 2009. Our independent registered public accounting firm has expressed doubt about our ability to continue as a going concern. See Item 1A. “Risk Factors — Risks Related to Our Business — Our independent registered public accounting firm has expressed substantial doubt about our ability to continue as a going concern.” The August 31, 2009 date could be extended if QRCP is able to restructure its debt obligations, issue equity securities and/or sell additional assets. If QRCP is not successful in obtaining sufficient additional funds, there is a significant risk that QRCP will be forced to file for bankruptcy protection. See Item 1A. “Risk Factors — Risks Related to Our Business — QRCP’s potential sources of revenue and cash flows consist almost exclusively of distributions from Quest Energy and Quest Midstream, neither of which is expected to pay distributions in 2009 and as a result, we do not expect QRCP to be able to meet its cash disbursement obligations unless it engages in transactions outside the ordinary course of business.”

Oil and Gas Production

Cherokee Basin. We currently conduct our oil and gas production operations in the Cherokee Basin through QELP. QELP’s oil and gas production operations are primarily focused on the development of coal bed methane or CBM in a 15-county region in southeastern Kansas and northeastern Oklahoma known as the Cherokee Basin. As of December 31, 2008, QELP had 152.7 Bcfe of estimated net proved reserves in the Cherokee Basin, of which approximately 97.7% were CBM and 81.6% were proved developed. QELP operates approximately 99% of its existing Cherokee Basin wells, with an average net working interest of approximately 99% and an average net revenue interest of approximately 82%. We believe QELP is the largest producer of natural gas in the Cherokee Basin with an average net daily production of 57.3 Mmcfe for the year ended December 31, 2008. QELP’s estimated net proved reserves in the Cherokee Basin at December 31, 2008 had estimated future net revenues discounted at 10%, which we refer to as the “standardized measure,” of $129.8 million. QELP’s Cherokee Basin reserves have an

average proved reserve-to-production ratio of 7.3 years (5.0 years for QELP’s proved developed properties) as of December 31, 2008. QELP’s typical Cherokee Basin CBM well has a predictable production profile and a standard economic life of approximately 15 years.

As of December 31, 2008, QELP was operating approximately 2,438 gross gas wells in the Cherokee Basin, of which over 95% were multi-seam wells, and 27 gross oil wells. As of December 31, 2008, QELP owned the development rights to approximately 557,603 net acres throughout the Cherokee Basin and had only developed approximately 59.6% of its acreage. For 2009, QELP has budgeted approximately $3.8 million to drill seven new gross wells, connect and complete 49 existing gross wells, and connect and complete three existing salt water disposal wells in the Cherokee Basin. All of these new gas wells will be drilled on locations that are classified as containing proved reserves in our December 31, 2008 reserve report. In 2009, QELP plans to recomplete an estimated 10 gross wells, and has budgeted another $1.9 million for equipment, vehicle replacement, and other capital purchases. Recompletions generally consist of converting wells that were originally completed with single seam completions into multi-seam completions, which allows QELP to produce additional gas from different depths. In addition, QELP has budgeted $2.4 million related to lease renewals and extensions for acreage that is expiring in 2009. However, QELP intends to fund these capital expenditures only to the extent that QELP has available cash from operations after taking into account its debt service obligations. We can give no assurance that any such funds will be available. For 2008, QELP had total capital expenditures of approximately $79 million, including $47 million to complete 328 gross wells and recomplete or restimulate 70 gross wells, which was within the budgeted amount. As of December 31, 2008, QELP’s undeveloped acreage contained approximately 1,893 gross CBM drilling locations, of which approximately 624 were classified as proved undeveloped. Over 97% of the CBM wells that have been drilled on QELP’s acreage to date have been successful. Historically, QELP’s Cherokee Basin acreage was developed utilizing primarily 160-acre spacing. However, during 2008, QELP developed some areas on 80-acre spacing. QELP is currently evaluating the results of this 80-acre spacing program. None of QELP’s acreage or producing wells are associated with coal mining operations.

Seminole County, Oklahoma. We also currently conduct our oil production operations in Seminole County, Oklahoma through Quest Energy. QELP owns 55 gross productive oil wells and the development rights to approximately 1,481 net acres in Seminole County, Oklahoma. As of December 31, 2008, the oil producing properties had estimated net proved reserves of 588,800 Bbls, all of which are proved developed producing. During 2008, net production for QELP’s Seminole County properties was 148 Bbls/d. QELP’s oil production operations in Seminole County are primarily focused on the development of the Hunton Formation. We believe there are approximately 11 horizontal drilling locations for the Hunton Formation on QELP’s acreage. QELP’s ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approval, oil prices, costs and drilling results. There were no proved undeveloped reserves given to these locations as of December 31, 2008.

Appalachian Basin. Both QELP and QRCP own producing properties in Appalachia that are operated by Quest Eastern, formerly PetroEdge Resources (WV), LLC (“PetroEdge”), which we acquired on July 11, 2008. All production for 2008 was owned by QELP. In February 2009, QRCP began production in the Marcellus Shale in Wetzel County, West Virginia.

Our oil and gas production operations in the Appalachian Basin are primarily focused on the development of the Marcellus Shale. We believe there are approximately 334 potential gross vertical well locations and approximately 123 potential gross horizontal well locations for the Marcellus Shale, including significant development opportunities for Devonian Sands and Brown Shales. These potential well locations are located within QRCP’s acreage in West Virginia and New York.

On July 11, 2008, QRCP consummated the acquisition of PetroEdge for approximately $142 million, including transaction costs, after taking into account post-closing adjustments. The assets acquired were approximately 78,000 net acres of oil and natural gas producing properties in the Appalachian Basin with estimated proved reserves of 99.6 Bcfe as of May 1, 2008 and net production of approximately 3.3 Mmcfe/d. Simultaneous with the closing, QRCP sold oil and natural gas producing wells with estimated proved developed reserves of 32.9 Bcfe as of May 1, 2008 and all of the current net production to QELP for cash consideration of approximately $72 million, subject to post-closing adjustment. As of December 31, 2008, there were approximately 10.9 Bcfe of estimated net

proved developed reserves associated with the Appalachian Basin assets sold to QELP. The remaining assets retained by QRCP had, as of December 31, 2008, an additional 7.7 Bcfe of estimated net proved undeveloped reserves. The 18.6 Bcfe of estimated net proved reserves in the Appalachian Basin, as of December 31, 2008 were approximately 68% proved developed. The decrease in estimated reserves is due primarily to a decrease in natural gas prices between May 1, 2008, the date of the PetroEdge reserve report, and year-end (35.5 Bcfe), and revisions due to further technical analysis of the reserves (43.2 Bcfe). Upon further technical analysis, we discovered that the Marcellus zone proved developed non-producing reserves associated with 82 wells, totaling 14.6 Bcfe, were not completed and were not directly offset by productive wells, and were therefore removed. Well performance for certain producing wells was judged not to be meeting expectation and the reserves expected to be recovered from such wells was reduced by 2.6 Bcfe. The proved undeveloped reserves acquired were evaluated by an independent reservoir engineering firm other than Cawley, Gillespie & Associates, Inc. at the time of the PetroEdge acquisition. The evaluation included proved undeveloped locations based upon acre spacing, assuming blanket coverage of the area by productive zones. Securities and Exchange Commission (“SEC”) rules require a proved undeveloped location to be recorded in reserves only if it is directly offset by a productive well. At the time of the acquisition, 145 locations, totaling 26.0 Bcfe, were included in the reserve report that have all been removed from the reserve report prepared at year end December 31, 2008. The personnel responsible for analyzing and validating the reserve report used for this acquisition are no longer employed by the Company.

As of December 31, 2008, QELP owned approximately 500 gross gas wells in the Appalachian Basin. Quest Eastern operates approximately 99% of these existing wells on behalf of QELP, with QELP having an average net working interest of approximately 93% and an average net revenue interest of approximately 75%. QELP’s average net daily production in the Appalachian Basin was approximately 2.9 Mmcfe for the year ended December 31, 2008. QELP’s estimated net proved reserves at December 31, 2008 were 10.9 Bcfe and had a standardized measure of $19.6 million. QELP’s reserves in the Appalachian Basin have an average proved reserve-to-production ratio of 17.5 years (10.7 years for QELP’s proved developed properties) as of December 31, 2008. QELP’s typical Marcellus Shale well has a predictable production profile and a standard economic life of approximately 50 years.

As of December 31, 2008, QRCP owned the development rights to approximately 68,161 net acres throughout the Appalachian Basin and had only developed approximately 12% of its acreage. See “— Recent Developments” below for further information regarding our Appalachian Basin assets. As of December 31, 2008, QRCP’s proved undeveloped acreage contained approximately 22 gross drilling locations.

For 2009, QRCP has budgeted approximately $2.4 million of net expenditures to drill one gross vertical well, complete three gross wells and connect four gross wells. This one new well will be drilled on a location that is classified as containing proved reserves in our December 31, 2008 reserve report. QELP has budgeted another $1.4 million for artificial lift equipment, vehicle replacement and purchases and salt water disposal facilities. However, QRCP and QELP intend to fund these capital expenditures only to the extent that they have available cash after taking into account their debt service and other obligations. We can give no assurance that any such funds will be available based on current commodity prices and other current conditions.

Natural Gas Pipelines Operations

We conduct our natural gas pipelines operations through Quest Midstream and Quest Eastern.

Cherokee Basin. Bluestem Pipeline, LLC, a wholly-owned subsidiary of Quest Midstream (“Bluestem”), owns and operates a natural gas gathering pipeline network of approximately 2,173 miles that serves our acreage position in the Cherokee Basin. Presently, this system has a maximum daily throughput of approximately 85 Mmcf/d and is operating at about 90% capacity. Quest Energy transports 99% of its Cherokee Basin gas production through Bluestem’s gas gathering pipeline network to interstate pipeline delivery points. Approximately 6% of the current throughput on Bluestem’s natural gas gathering pipeline system is for third parties.

As of December 31, 2008, QELP had an inventory of approximately 185 gross drilled CBM wells awaiting connection to QMLP’s gas gathering system.

Interstate Pipeline System. Quest Pipelines (KPC), which we refer to as KPC, owns and operates a 1,120 mile interstate natural gas pipeline (the “KPC Pipeline”) which transports natural gas from northern Oklahoma and western

Kansas to the metropolitan Wichita and Kansas City markets. Further, it is one of only three pipeline systems currently capable of delivering gas into the Kansas City metropolitan market. The KPC system includes three compressor stations with a total of 14,680 horsepower and has a throughput capacity of approximately 160 Mmcf/d. KPC has supply interconnections with pipelines owned and/or operated by Enogex Inc., Panhandle Eastern PipeLine Company and ANR Pipeline Company, allowing QMLP to transport natural gas volumes sourced from the Anadarko and Arkoma basins, as well as the western Kansas and Oklahoma panhandle producing regions. KPC’s two primary customers are Kansas Gas Service (KGS) and Missouri Gas Energy (MGE), both of which are served under firm natural gas transportation contracts. KGS, a division of ONEOK, Inc., is the local distribution company in Kansas for Kansas City and Wichita as well as a number of other municipalities. MGE, a division of Southern Union Company, is a natural gas distribution company that serves over a half-million customers in 155 western Missouri communities.

Appalachian Basin. Quest Eastern owns and operates a gas gathering pipeline network of approximately 183 miles that serves our acreage position in the Appalachian Basin. The pipeline delivers both to intrastate gathering and interstate pipeline delivery points. Presently, this system has a maximum daily throughput of approximately 15.0 Mmcf/d and is operating at about 20% capacity. All of QELP’s Appalachian Basin gas production is transported by Quest Eastern’s gas gathering pipeline network. Less than 1% of the current volumes transported on Quest Eastern’s natural gas gathering pipeline system are for third parties.

Organizational Structure

The following chart reflects our complete organizational structure. The chart excludes 15,000 QELP common units issued, or to be issued, to QELP’s independent directors and 117,877 QMLP common units and 15,000 Class B subordinated units issued, or to be issued, to QMLP’s independent directors and officers.

Recent Developments

PetroEdge Acquisition

As discussed above under “— General — Oil and Gas Production — Appalachian Basin”, on July 11, 2008, QRCP acquired PetroEdge and simultaneously transferred PetroEdge’s oil and natural gas producing wells to Quest Energy. This acquisition followed closely after QRCP’s June 4, 2008 acquisition of a one-year option to purchase certain drilling and other rights in and below the Marcellus Shale (the “Deep Rights”) in and to certain oil and gas leases covering approximately 28,700 acres in Potter County, Pennsylvania for $4 million. Certain provisions of the option agreement gave us rights to drill wells in the Deep Rights during the one-year option period.

Quest Energy funded its purchase of the PetroEdge wellbores with borrowings under its revolving credit facility, which was increased from $160 million to $190 million as part of the acquisition, and the proceeds of a $45 million, six-month term loan under a Second Lien Senior Term Loan Agreement (the “Second Lien Loan Agreement”) with Royal Bank of Canada (“RBC”), as administrative agent and collateral agent, KeyBank National Association, as syndication agent, Société Générale, as documentation agent, and the lenders party thereto.

QRCP funded the balance of the PetroEdge acquisition with proceeds from a public offering of 8,800,000 shares of QRCP common stock at a price of $10.25 per share that closed on July 8, 2008. QRCP received net proceeds from this offering of approximately $85.2 million. Simultaneously with the closing of the PetroEdge acquisition, QRCP entered into an Amended and Restated Credit Agreement (the “Credit Agreement”) to convert its then existing $50 million revolving credit facility to a $35 million term loan with a maturity date of July 11, 2010. The Credit Agreement is among QRCP, as the borrower, RBC, as administrative agent and collateral agent, and the lenders party thereto. RBC required QRCP to use $13 million of the proceeds from the equity offering to reduce the outstanding indebtedness under the Credit Agreement from $48 million to $35 million.

The purpose of the PetroEdge acquisition was to expand our operations to another geologic basin with less basis differential, that had significant resource potential. The acquisition closed during the peak month of natural gas pricing in 2008.

Internal Investigation; Restatements and Reaudits

On August 23, 2008, only six weeks after the PetroEdge transaction closed, our then chief executive officer resigned following the discovery of the Transfers. The Transfers were brought to the attention of the boards of directors of each of the Company, Quest Energy GP and Quest Midstream GP as a result of an inquiry and investigation that had been initiated by the Oklahoma Department of Securities. The Company’s board of directors, jointly with the boards of directors of Quest Energy GP and Quest Midstream GP, formed a joint special committee to investigate the matter and to consider the effect on our consolidated financial statements. The joint special committee retained numerous professionals to assist with the internal investigation and other matters during the period following the discovery of the Transfers. To conduct the internal investigation, independent legal counsel was retained to report to the joint special committee and to interact with various government agencies, including the Oklahoma Department of Securities, the Federal Bureau of Investigation, the Department of Justice, the Securities and Exchange Commission and the Internal Revenue Service (“IRS”). We also retained a new independent registered public accounting firm to reaudit our consolidated financial statements.

The investigation is substantially complete. The investigation revealed that the Transfers resulted in a loss of funds totaling approximately $10 million by the Company. Further, it was determined that our former chief financial officer directly participated and/or materially aided our former chief executive officer in connection with the unauthorized Transfers. In addition, the Oklahoma Department of Securities has filed a lawsuit alleging that our former chief financial officer and our former purchasing manager each received kickbacks of approximately $0.9 million from several related suppliers over a two-year period and that during the third quarter of 2008, they also engaged in the direct theft of $1 million for their personal benefit and use. In March 2009, Mr. Mueller, the former purchasing manager, pled guilty to one felony count of misprision of justice. Sentencing is pending. We have filed lawsuits against all three of these individuals seeking an asset freeze and damages related to the Transfers, kickbacks and thefts and we intend to pursue all remedies available under the law. We settled the lawsuits against Mr. Cash on May 19, 2009. See “— Settlement Agreements” below. There can be no assurance that we will be

successful in recovering any additional amounts. Any additional recoveries may consist of assets other than cash and accurately valuing such assets in the current economic climate may be difficult. Any amounts recovered will be recognized by us for financial accounting purposes only in the period in which the recovery occurs.

QRCP, Quest Energy, Quest Energy GP and certain of their officers and directors have been named as defendants in a number of securities class action lawsuits and stockholder derivative lawsuits arising out of or related to the Transfers. See Item 3. “Legal Proceedings.”

We experienced significant increased costs in the second half of 2008 and continue to experience such increased costs in the first half of 2009 due to, among other things:


	•	We had costs associated with the internal investigation and our responding to inquiries from the Oklahoma Department of Securities, the Federal Bureau of Investigation, the Department of Justice, the SEC and the IRS.

	•	As a result of the termination of the former chief executive officer and chief financial officer, we immediately retained consultants to perform the accounting and finance functions and to assist in the determination of the intercompany debt discussed below under “— Intercompany Accounts.”

	•	We retained law firms to respond to the class action and derivative suits that have been filed against QRCP, Quest Energy GP and QELP and to pursue the claims against the former employees.

	•	We had costs associated with amending the credit agreements of QRCP, QELP and QMLP and obtaining the necessary waivers from our lenders thereunder as well as incremental increased interest expense related thereto. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

	•	We retained external auditors, who completed reaudits of the restated consolidated financial statements for the years ended December 31, 2007, 2006 and 2005.

	•	The Company, QELP and QMLP each retained financial advisors to consider strategic options and each retained outside legal counsel or increased the amount of work being performed by its previously engaged outside legal counsel.

We estimate that the increased costs related to the foregoing will be between approximately $7.0 million and $8.0 million.

Global Financial Crisis and Impact on Capital Markets and Commodity Prices

At about the same time as the Transfers were discovered, the global economy experienced a significant downturn. The crisis began over concerns related to the U.S. financial system and quickly grew to impact a wide range of industries. There were two significant ramifications to the exploration and production industry as the economy continued to deteriorate. The first was that capital markets essentially froze. Equity, debt and credit markets shut down. Future growth opportunities have been and are expected to continue to be constrained by the lack of access to liquidity in the financial markets.

The second impact to the industry was that fear of global recession resulted in a significant decline in oil and gas prices. In addition to the decline in oil and gas prices, the differential from NYMEX pricing to our sales point for our Cherokee Basin gas production has widened and is still at unprecedented levels of volatility.

Our operations and financial condition are significantly impacted by these prices. During the year ended December 31, 2008, the NYMEX monthly gas index price (last day) ranged from a high of $13.58 per Mmbtu to a low of $5.29 per Mmbtu. Natural gas prices came under pressure in the second half of the year as a result of lower domestic product demand that was caused by the weakening economy and concerns over excess supply of natural gas. In the Cherokee Basin, where we produce and sell most of our gas, there has been a widening of the historical discount of prices in the area to the NYMEX pricing point at Henry Hub as a result of elevated levels of natural gas drilling activity in the region and a lack of pipeline takeaway capacity. During 2008, this discount (or basis differential) in the Cherokee Basin ranged from $0.67 per Mmbtu to $3.62 per Mmbtu.

The spot price for NYMEX crude oil in 2008 ranged from a high of $145.29 per barrel in early July to a low of $33.87 per barrel in late December. The volatility in oil prices during the year was a result of the worldwide recession, geopolitical activities, worldwide supply disruptions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets as well as domestic concerns about refinery utilization and petroleum product inventories pushing prices up during the first half of the year. Due to our relatively low level of oil production relative to gas and our existing commodity hedge positions, the volatility of oil prices had less of an effect on our operations.

See Item 1A. “Risk Factors — Risks Related to Our Business — The current financial crisis and economic conditions may have a material adverse impact on our business and financial condition that we cannot predict.”

Management Personnel Changes

In connection with the investigation of the Transfers, Jerry Cash, our former Chairman of the Board and Chief Executive Officer, resigned on August 23, 2008, and David Grose, our former Chief Financial Officer, was placed on administrative leave on August 22, 2008. On August 24, 2008, our Chief Operating Officer, David Lawler, was appointed President, and Jack Collins, our Executive Vice President of Investor Relations, was appointed Interim Chief Financial Officer. On September 13, 2008, Mr. Grose was terminated from all positions with us. Eddie LeBlanc became our Chief Financial Officer on January 9, 2009, with Mr. Collins becoming our Executive Vice President of Finance/Corporate Development. On May 7, 2009, Mr. Lawler was appointed our Chief Executive Officer. On July 11, 2008, Richard Muncrief resigned as President and Chief Operating Officer of Quest Midstream GP to pursue other opportunities, and on September 30, 2008, Michael Forbau was elected the Chief Operating Officer of Quest Midstream GP.

NASDAQ Non-compliance

Our common stock is currently listed on the NASDAQ Global Market. On November 19, 2008, we received a letter from the staff of NASDAQ indicating that, because of our failure to timely file our Form 10-Q for the quarter ended September 30, 2008, we no longer complied with the continued listing requirements set forth in NASDAQ Marketplace Rule 4310(c)(14) (now Rule 5250(c)(1)). As permitted by NASDAQ rules, we timely submitted a plan to NASDAQ staff to regain compliance on January 20, 2009. Following a review of this plan, NASDAQ staff granted us an extension until May 11, 2009 to file our Form 10-Q. We did not file our Form 10-Q for the quarter ended September 30, 2008 on that date. On May 12, 2009, we received a staff determination notice (the “Staff Determination”) from NASDAQ stating that our common stock is subject to delisting since we were not in compliance with the filing requirements for continued listing. The NASDAQ Listing Qualifications Hearing Panel (the “Panel”) granted our request for a hearing to appeal the Staff Determination and has scheduled a hearing for June 11, 2009. The Panel has stayed the delisting of our common stock through such date to allow us additional time to file our delinquent periodic reports with the SEC. If we have not filed all of our delinquent periodic reports by June 11, 2009, there can be no assurances that the Panel will grant a further extension to allow us additional time to file such reports or that our common stock will not be delisted.

Credit Agreement Amendments

In October and November 2008, QRCP, Quest Cherokee and Quest Energy, and Quest Midstream and Bluestem entered into amendments to their respective credit agreements that, among other things, amended and/or waived certain of the representations and covenants contained in each credit agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result of (1) the Transfers and (2) not timely settling certain intercompany accounts among QRCP, Quest Energy and Quest Midstream. The Quest Cherokee amendment also extended the maturity date of the Second Lien Loan Agreement from January 11, 2009 to September 30, 2009 due to our inability to refinance the Second Lien Loan Agreement as a

result of a combination of the ongoing investigation and the global financial crisis. The amendments also restricted the ability of Quest Midstream and Quest Energy to pay distributions to QRCP.

In May 2009, QRCP entered into an amendment to the Credit Agreement to, among other things, waive certain events of default related to its financial covenants and collateral requirements, extend certain financial reporting deadlines and permit the settlement agreements with Mr. Cash discussed below.

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Agreements” for additional information regarding our credit agreements.

Suspension of Distributions and Asset Sales

As discussed above under “General — Quest Resource Corporation,” distributions were suspended on Quest Energy’s subordinated units beginning with the third quarter of 2008 and distributions were suspended on all of Quest Energy’s units, beginning with the fourth quarter of 2008. Distributions were suspended on all of Quest Midstream’s units beginning with the third quarter of 2008. Since these distributions would have been substantially all of QRCP’s cash flows for 2009, the loss of the distributions was material to QRCP’s financial position.

In October 2008, we negotiated an additional $6 million term loan under the Credit Agreement with a maturity date of November 30, 2008. We agreed with our lenders that the additional term loan would be repaid with the net proceeds from asset sales by QRCP and that the first $4.5 million of net proceeds in excess of any additional term loans that were borrowed would be used to repay QRCP’s $35 million term loan.

On October 30, 2008, QRCP sold its interest in approximately 22,600 net undeveloped acres and one well in Somerset County, Pennsylvania to a private party for approximately $6.8 million. On November 26, 2008, QRCP sold its interest in the development rights and related purchase option, which it had purchased on June 4, 2008 covering approximately 28,700 acres in Potter County, Pennsylvania, to an undisclosed party for approximately $3.2 million. On February 13, 2009, QRCP sold its interest in approximately 23,076 net undeveloped acres in the Marcellus Shale and one well in Lycoming County, Pennsylvania to a third party for approximately $8.7 million. Management decided that these undeveloped acres were good candidates for disposition in the current environment given the lack of gathering and transportation infrastructure in the immediate area and the cost and time that would be involved in establishing significant flow of natural gas.

In addition to these sales, on November 5, 2008, QRCP sold a 50% interest in approximately 4,500 net undeveloped acres, three wells in various stages of completion and existing pipelines and facilities in Wetzel County, West Virginia to another party for $6.1 million. QRCP will continue to operate the Wetzel County property. All future development costs will be split equally between QRCP and the other party. This joint venture arrangement allows QRCP to retain a significant interest in the Wetzel County property, which we believe is a desirable asset due to established infrastructure, pipeline taps and proved offset production in the area.

QRCP borrowed $2 million of the additional $6 million term loan under its Credit Agreement in October 2008. A portion of the net proceeds from the asset sales were used to repay the $2 million additional term loan and to reduce QRCP’s $35 million term loan to $28.3 million as of May 15, 2009.

Intercompany Accounts

As part of the investigation, we determined that our former chief financial officer had not been promptly settling intercompany accounts among the Company, Quest Midstream and Quest Energy. Intercompany balances as of September 30, 2008 were quantified and have been paid: QRCP paid Quest Midstream $3.6 million in October 2008, $2.0 million in November 2008 and an additional $0.2 million, including interest, in February 2009; and Quest Energy paid Quest Midstream $4.0 million, including interest, in February 2009. The Company’s payments were funded with the proceeds from the asset sales. The remainder of the proceeds from these sales are being used to fund QRCP’s ongoing operations.

Cost-cutting Measures

In addition to the sales of assets and suspension of distributions discussed above, during the third and fourth quarters of 2008, we took significant actions to reduce our costs and retain cash for anticipated debt service requirements for QRCP and Quest Energy during 2009. Among other things, we renegotiated and postponed drilling commitments related to the PetroEdge properties, we significantly reduced our level of maintenance and expansion capital expenditures, we hired Mr. LeBlanc as our Chief Financial Officer (which allowed us to terminate the consultants that had been hired to assist our interim chief financial officer) and we eliminated 56 field positions and 3 corporate positions. We continue to evaluate additional options to further reduce our expenditures.

Decrease in Year-End Reserves; Impairment

Due to the low price for natural gas as of December 31, 2008 as described above, revisions resulting from further technical analysis (see Note 21 — Supplemental Information on Oil and Gas Producing Activities (Unaudited) to the accompanying consolidated financial statements) and production during the year, proved reserves decreased 17.2% to 174.8 Bcfe at December 31, 2008 from 211.1 Bcfe at December 31, 2007, and the standardized measure of our proved reserves decreased 49.1% to $164.1 million as of December 31, 2008 from $286.2 million as of December 31, 2007. The December 31, 2008 reserves were calculated using a spot price of $5.71 per Mmbtu (adjusted for basis differential, prices were $5.93 per Mmbtu in the Appalachian Basin and $4.84 per Mmbtu in the Cherokee Basin). As a result of this decrease, we recognized a non-cash impairment of $298.9 million for the year ended December 31, 2008. As a result, the lenders under QELP’s revolving credit facility are likely to reduce QELP’s borrowing base in the near term. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Sources of Liquidity in 2009 and Capital Requirements — Quest Energy.”

Seminole County Acreage Acquisition

In early February 2008, QELP purchased certain oil producing properties in Seminole County, Oklahoma from a private company for $9.5 million. In connection with the acquisition, QELP entered into crude oil swaps for approximately 80% of the estimated 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. As of December 31, 2008, the properties had estimated net proved reserves of 588,800 Bbls, all of which were proved developed producing.

Settlement Agreements

As discussed above, QRCP and QELP filed lawsuits against Mr. Cash, the entity controlled by Mr. Cash that was used in connection with the Transfers and two former officers, who are the other owners of the controlled-entity, seeking, among other things, to recover the funds that were transferred. On May 19, 2009, QRCP, QELP and QMLP entered into settlement agreements with Mr. Cash, the controlled-entity and the other owners to settle this litigation. Under the terms of the settlement agreements, QRCP received (1) approximately $2.4 million in cash and (2) 60% of the controlled-entity’s interest in a gas well located in Louisiana and a landfill gas development project located in Texas. While QRCP estimates the value of these assets to be less than the amount of the Transfers and cost of the internal investigation, they represent the majority of the value of the controlled-entity. We did not take Mr. Cash’s stock in QRCP, which he represented had been pledged to secure personal loans with a principal balance far in excess of the current market value of the stock. QELP received all of Mr. Cash’s equity interest in STP Newco, Inc. (“STP”), which owns certain oil producing properties in Oklahoma, and other assets as reimbursement for all of the costs of the internal investigation and the costs of the litigation against Mr. Cash that have been paid by QELP.

Pinnacle Merger

On October 15, 2007, we and Pinnacle Gas Resources, Inc. (“Pinnacle”) entered into an Agreement and Plan of Merger, pursuant to which we and Pinnacle agreed to combine our operations (the “Merger Agreement”). On May 16, 2008, the Merger Agreement was terminated. Pursuant to the terms of the Merger Agreement, either we or

Pinnacle had the right to terminate the Merger Agreement if the proposed merger was not completed by May 16, 2008. No termination fee was payable by either of us as a result of the termination of the Merger Agreement.

2008 Operating Results

Our strategy prior to the events discussed above was to create value through the growth of the master limited partnerships of Quest Energy and Quest Midstream. This strategy was supported by a talented engineering and operating team assembled over the last two years. This team separated approximately 400 employees at our peak level of activity into discrete, highly focused groups: Capital Development, Production Operations, Well Servicing, Compression and Pipeline. These teams met or exceeded a number of performance-related goals that were established by management at the beginning of the year. For example, Quest Energy planned to drill 325 wells in the Cherokee Basin in 2008. Quest Energy drilled 338 wells in eight months, three months ahead of schedule, and delivered the results within its capital budget for the year. We did not drill any wells during the final four months of the year due to limited capital availability and low commodity prices. In addition, we had historically struggled to maintain a low level of wells offline due to well failures. For December 2008, on average less than 2% of our approximately 2,500 Cherokee Basin wells were offline per day. This level of performance was achieved through the implementation of rigorous engineering reviews, statistical failure analysis and the latest de-liquification process control technology. Our net production for 2008 was 21.75 Bcfe, which is a 23.4% increase over our net production in 2007 of 17.02 Bcfe. With respect to our midstream activities, we connected 328 wells to our Cherokee Basin gathering system and integrated the KPC Pipeline assets into our operations. We have also improved our safety culture by decreasing OSHA recordable incidents by 35% in 2008 as compared to 2007.

Outlook for 2009; Recombination

Given the liquidity challenges facing the Company, Quest Midstream and Quest Energy, each entity has undertaken a strategic review of its assets and may enter into one or more transactions to dispose of assets in order to raise additional funds for operations and/or to repay indebtedness. In addition, in the current economic environment we believe the complexity and added overhead costs of our structure is negatively affecting our ability to restructure our indebtedness and raise additional equity. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.” On April 28, 2009, the Company, Quest Midstream and Quest Energy entered into a non-binding letter of intent pursuant to the terms of which all three companies would form a new publicly traded holding company that would wholly-own all three entities (the “Recombination”). The new company would continue to develop the unconventional resources of the Cherokee and Appalachian Basins with a clear focus on value creation through efficient operations. The closing of the Recombination is subject to the satisfaction of a number of conditions, including the entry into a definitive merger agreement, the negotiation of a new credit facility for the new company, regulatory approval and the approval of the transaction by the stockholders of the Company and the unitholders of Quest Energy and Quest Midstream. There can be no assurance that the definitive documentation will be agreed to or that the Recombination will close.

Business Strategy

Our business strategy for 2009 has been adjusted in response to the recent turmoil in the financial markets and the economy in general, including the reduction in commodity prices which was then exacerbated by the significantly increased general and administrative costs we have incurred as a result of the investigation and the reaudits and restatements of our consolidated financial statements. See “— Recent Developments.” We are focusing on negotiating documentation and other activities necessary to complete the Recombination while still maintaining a stable asset base, improving the profitability of our assets by increasing their utilization while controlling costs and reducing capital expenditures as discussed elsewhere in this Annual Report on Form 10-K, renegotiating with our lenders and possibly raising equity capital.

Prior to the events discussed above, our goal was to create stockholder value by growing our two master limited partnerships and investing capital to increase reserves, production and cash flow. In favorable product price markets and credit markets, we would accomplish this goal by focusing on the following key strategies:


	•	Seek out opportunities to grow our upstream and midstream master limited partnerships and hence the distributions they make to us;

	•	Efficiently control the drilling and development of our acreage position in the Cherokee and Appalachian Basins and other acquired acreage positions;

	•	Expand Quest Midstream’s gas gathering system throughout the Cherokee Basin in order to accommodate the development of a wider acreage footprint;

	•	Accumulate additional acreage in the Cherokee Basin through Quest Energy in areas where management believes the most attractive development opportunities exist;

	•	Pursue selected strategic acquisitions in the Cherokee Basin through Quest Energy and Quest Midstream that would add attractive development opportunities and critical gas gathering infrastructure;

	•	Maintain operational control over our assets whenever possible;

	•	Limit our reliance on third party contractors with respect to the completion, stimulation and connection of our wells in the Cherokee Basin;

	•	Maintain a low cost and efficient operating structure through the use of remote data monitoring technology;

	•	Pursue opportunities to apply our expertise with conventional and unconventional resource development in other basins; and

	•	Pursue opportunities to apply our expertise with building and operating natural gas gathering and transportation infrastructure in other basins.

We believe the acquisition of PetroEdge was an opportunity to grow our upstream business just as the acquisition of KPC by QMLP in November 2007 was for the midstream business. However, the significant decline in natural gas prices since the PetroEdge acquisition closed has substantially reduced the opportunity for an economic return on the PetroEdge assets.

Additionally, as discussed in more detail under “— Recent Developments”, we have instituted cost control measures, such as work force reductions and other cost savings actions, and have concentrated attention on managing cash flow and planning for future required principal payments. If the Quest entities are not recombined, deployment of any growth strategy will be highly unlikely. Furthermore, should the three individual entities continue without a significant increase in product prices in the near term, combined with longer term forbearance under their credit facilities, each entity would likely face liquidation or bankruptcy.

Description of Our Exploration and Production Properties and Projects

Cherokee Basin

We produce CBM gas out of Quest Energy’s properties located in the Cherokee Basin. The Cherokee Basin is located in southeastern Kansas and northeastern Oklahoma. Geologically, it is situated between the Forest City Basin to the north, the Arkoma Basin to the south, the Ozark Dome to the east and the Nemaha Ridge to the west. The Cherokee Basin is a mature producing area with respect to conventional reservoirs such as the Bartlesville sandstones and the Mississippian limestones, which were developed beginning in the early 1900s.

The Cherokee Basin is part of the Western Interior Coal Region of the central United States. The coal seams we target for development are found at depths of 300 to 1,400 feet. The principal formations we target include the Mulky, Weir-Pittsburgh and the Riverton. These coal seams are blanket type deposits, which extend across large areas of the basin. Each of these seams generally range from two to five feet thick. Additional minor coal seams such as the Summit, Bevier, Fleming and Rowe are found at varying locations throughout the basin. These seams range in thickness from one to two feet.

The rock containing conventional gas, referred to as “source rock,” is usually different from reservoir rock, which is the rock through which the conventional gas is produced, while in CBM, the coal seam serves as both the source rock and the reservoir rock. The storage mechanism is also different. Gas is stored in the pore or void space of the rock in conventional gas, but in CBM, most, and frequently all, of the gas is stored by adsorption. This adsorption allows large quantities of gas to be stored at relatively low pressures. A unique characteristic of CBM is that the gas flow can be increased by reducing the reservoir pressure. Frequently, the coal bed pore space, which is in the form of cleats or fractures, is filled with water. The reservoir pressure is reduced by pumping out the water, releasing the methane from the molecular structure, which allows the methane to flow through the cleat structure to the well bore. Because of the necessity to remove water and reduce the pressure within the coal seam, CBM, unlike conventional hydrocarbons, often will not show immediately on initial production testing. Coalbed formations typically require extensive dewatering and depressuring before desorption can occur and the methane begins to flow at commercial rates. Our Cherokee Basin CBM properties typically dewater for a period of 12 months before peak production rates are achieved.

CBM and conventional gas both have methane as their major component. While conventional gas often has more complex hydrocarbon gases, CBM rarely has more than 2% of the more complex hydrocarbons. Once coalbed methane has been produced, it is gathered, transported, marketed and priced in the same manner as conventional gas. The CBM produced from our Cherokee Basin properties has an Mmbtu content of approximately 970 Mmbtu, compared to conventional natural gas hydrocarbon production which can typically vary from 1,050-1,300 Mmbtus.

The content of gas within a coal seam is measured through gas desorption testing. The ability to flow gas and water to the wellbore in a CBM well is determined by the fracture or cleat network in the coal. While, at shallow depths of less than 500 feet, these fractures are sometimes open enough to produce the fluids naturally, at greater depths the networks are progressively squeezed shut, reducing the ability to flow. It is necessary to provide other avenues of flow such as hydraulically fracturing the coal seam. By pumping fluids at high pressure, fractures are opened in the coal and a slurry of fluid and sand is pumped into the fractures so that the fractures remain open after the release of pressure, thereby enhancing the flow of both water and gas to allow the economic production of gas.

Cherokee Basin Projects

Historically, we have developed our CBM reserves in the Cherokee Basin on 160-acre spacing. However, during 2008 we developed some areas on 80-acre spacing. We are currently evaluating the results of this 80-acre spacing program. Our wells generally reach total depth in 1.5 days and our average cost in 2008 to drill and complete a well, excluding the related pipeline infrastructure, was approximately $135,000. We estimate that for 2009, Quest Energy’s average cost for drilling and completing a well will be between $113,000 and $125,000 excluding the related pipeline infrastructure. For 2009, in the Cherokee Basin, we have budgeted approximately $3.8 million to drill seven new gross wells, connect and complete 49 existing gross wells, and connect and complete three existing salt water disposal wells. All of these new gas wells will be drilled on locations that are classified as containing proved reserves in our December 31, 2008 reserve report. In 2009, QELP plans to recomplete an estimated 10 gross wells and it has budgeted another $1.9 million for equipment, vehicle replacement, and other capital purchases, including the replacement of some of QELP’s existing pumps with submersible pumps that we believe provide enhanced removal of water from the wells. In addition, QELP has budgeted $2.4 million related to lease renewals and extensions for acreage that is expiring in 2009. However, we intend to fund these capital expenditures only to the extent that QELP has available cash from operations after taking into account its debt service. We can give no assurance that any such funds will be available.

We perforate and frac the multiple coal seams present in each well. Our typical Cherokee Basin multi-seam CBM well has net reserves of 130 Mmcf. Our general production profile for a CBM well averages an initial production rate of 5-10 Mcf/d (net), steadily rising for the first twelve months while water is pumped off and the formation pressure is lowered. A period of relatively flat production of 50-55 Mcf/d (net) follows the initial dewatering period for a period of approximately twelve months. After 24 months, production begins to decline. The standard economic life is approximately 15 years. Our completed wells rely on very basic industry technology.

Our development activities in the Cherokee Basin also include a program to recomplete CBM wells that produce from a single coal seam to wells that produce from multiple coal seams. During the year ended

December 31, 2008, we recompleted approximately 10 wellbores in Kansas and an additional four wellbores in Oklahoma. For 2009, we plan to recomplete an estimated 10 gross wells. We believe we have approximately 200 additional wellbores that are candidates for recompletion to multi-seam producers. The recompletion strategy is to add four to five additional pay zones to each wellbore, in a two-stage process at an average cost of approximately $16,000 per well. Adding new zones to a well has a brief negative effect on production by first taking the well offline to perform the work and then by introducing a second dewatering phase of the newly completed formations. However, in the long term, we believe the impact of the multi-seam recompletions will be positive as a result of an increase in the rate of production and the ultimate recoverable reserves available per well.

Wells are equipped with small pumping units to facilitate the dewatering of the producing coal seams. Generally, upon initial production, a single coal seam will produce 50-60 Bbls of water per day. A multi-seam completion produces about 150 Bbls of water per day. Eventually, water production subsides to 30-50 Bbls per day. Produced water is disposed through injection wells we drill into the underlying Arbuckle formation. One disposal well will generally handle the water produced from 25 CBM wells.

Appalachian Basin

The Appalachian Basin is one of the largest and oldest producing basins within the United States. It is a northeast to southwest trending, elongated basin that deepens with thicker sections to the east. This basin takes in southern New York, Pennsylvania, eastern Ohio, extreme western Maryland, West Virginia, Kentucky, extreme western/northwestern Virginia, and portions of Tennessee. The basin is bounded on the east by a line of metamorphic rocks known as the Blue Ridge province which is thrusted to the west over the basin margin. Most prospective sedimentary rocks containing hydrocarbons are found at depths of approximately 1,000-9,000 feet with shallowest production in areas where oil and gas are seeping from the outcrop. Most productive horizons are found in sedimentary strata of Pennsylvanian, Mississippian, Devonian, Silurian, and Ordovician age. The Appalachian Basin has been an active area for oil and gas exploration, production and marketing since the mid-1800s. Although deeper zones are of interest, the main exploration and development targets are the Mississippian and Devonian sections.

Our main area of interest is within West Virginia, where there are producing formations at depths of 1,500 feet to approximately 8,000 feet. Specifically, our main production targets are the lower Devonian Marcellus Shale, the shallow Mississippian (Big Injun, Maxton, Berea, Pocono, Big Lime) and the Upper Devonian (Riley, Benson, Java, Alexander, Elk, Cashaqua, Middlesex, West River and Genesee, including the Huron Shale members, Rhinestreet Shales). Although deeper targets are of interest (Onondaga and Oriskany), they are of lesser importance. The Mississippian formations are a conventional petroleum reservoir with the Devonian sections being a non-conventional energy resource.

The method for exploring and drilling these targets is different in several aspects. The Mississippian and Upper Devonian sections are explored through vertical drilling. The lower Marcellus section is explored by both vertical and horizontal drilling. The Mississippian section is identified by distinct sand and limestone zones with conventional porosity and permeability. Depths range from 1,000-2,500 feet deep. The Upper Devonian sands, siltstones, and shales are identified as multiple stacked pay lenses with depths ranging from 2,500-7,000 feet deep. The Marcellus Shale ranges in depth from 5,900 feet in portions of West Virginia to 7,100 feet in other portions of West Virginia. In certain areas of our leasehold, vertical wells are drilled with combination completions in the Mississippian, Upper Devonian, and the Marcellus. Occasionally, vertical wells might only complete a single section of the three prospective pay intervals.

Our technical team has extensive experience in vertical and horizontal exploration, development and production. We have identified areas within the Appalachian Basin that we believe are prospective for both vertical and horizontal targets. Our leases cover approximately eighteen counties within the Appalachian Basin. Certain counties are vertical drilling targets for development and other counties are horizontal development targets. We believe there are over 334 gross vertical locations that would include potential production from one or all three of the Mississippian, Upper Devonian Sands, and Siltstones. We believe there are approximately 123 gross horizontal locations that would include the primary target for the Marcellus formation. We have recently drilled and set production pipe on two horizontal wells located in Wetzel County, West Virginia. This county in particular, along

with Lewis County, West Virginia and Steuben County, New York, is prospective for horizontal drilling in the Marcellus. Depths to the Marcellus in Lewis County and Wetzel County range from 6,700 feet to 7,100 feet. The thickness of the Marcellus in these counties ranges from just over fifty feet thick to over ninety feet thick.

Appalachian Basin Projects

As discussed under “— Recent Developments,” in July 2008, we completed the PetroEdge acquisition, which expanded our position in the Appalachian Basin. At December 31, 2008, the Appalachian estimated net proved reserves totaled 18.6 Bcfe and were producing approximately 2.9 Mmcfe/d. During 2008, QRCP drilled one gross vertical well in Lycoming County, Pennsylvania, completed one gross vertical well in Somerset County, Pennsylvania, drilled one gross vertical well in Ritchie County, West Virginia, and drilled two gross horizontal wells in Wetzel County, West Virginia. The wells in Lycoming and Somerset Counties were subsequently sold as part of the asset sales discussed under “— Recent Developments — Suspension of Distributions and Asset Sales.” Connections to interstate pipelines have recently been installed near the Wetzel County wells and QRCP intends to complete the wells as soon as capital is available. We can give no assurance that any funds will be available prior to the closing of the Recombination or at all.

For 2009, QRCP has budgeted net capital expenditures of approximately $2.4 million to drill one gross vertical well and complete three gross wells. The new well will be drilled on a location that is classified as containing proved reserves in our December 31, 2008 reserve report. QRCP expects to connect all four of these gross wells in 2009. Quest Energy has budgeted another $1.4 million for artificial lift equipment, vehicle replacement and purchases and salt water disposal facilities. The expenditure of these funds is subject to capital being available. We can give no assurance that any funds will be available prior to the closing of the Recombination or at all.

Seminole County, Oklahoma

Our Seminole County, Oklahoma oil producing property is located in south central Oklahoma. This mature oil producing property was originally discovered in 1926 and has undergone several periods of re-development since that time. Two producing horizons include the Hunton Limestone at approximately 4,100 feet and the First Wilcox Sand at approximately 4,300 feet. The Hunton Limestone is the main current producing horizon in the field. Produced water is disposed on-site. Primary oil recovery from the Hunton with vertical wells was limited by discontinuous porosity development in the Hunton reservoir. Early attempts to waterflood this horizon met with poor results. We plan to further develop the Hunton horizon with horizontal drilling.

Oil and Gas Data

Estimated Net Proved Reserves

The following table presents our estimated net proved oil and gas reserves relating to our oil and natural gas properties as of the dates presented based on our reserve reports as of the dates listed below. The data was prepared by the petroleum engineering firm Cawley, Gillespie & Associates, Inc. in Ft. Worth, Texas. We filed estimates of our oil and gas reserves for the calendar years 2008, 2007 and 2006 with the Energy Information Administration of the U.S. Department of Energy on Form EIA-23. The data on Form EIA-23 was presented on a different basis, and included 100% of the oil and gas volumes from our operated properties only, regardless of our net interest. The difference between the oil and gas reserves reported on Form EIA-23 and those reported in this table exceeds 5%. The standardized measure values shown in the table are not intended to represent the current market value of our estimated oil and gas reserves and do not reflect any hedges. Proved reserves at December 31, 2008 were determined using year-end prices of $44.60 per barrel of oil and $5.71 per Mcf of gas, compared to $96.10 per barrel

of oil and $6.43 per Mcf of gas at December 31, 2007, and $61.06 per barrel of oil and $6.03 per Mcf of gas at December 31, 2006.


	December 31,
	2008(3)			2007			2006

Proved reserves
Gas (Mcf)		170,629,373			210,923,406			198,040,000
Oil (Bbls)		694,620			36,556			32,272
Total (Mcfe)		174,797,093			211,142,742			198,233,632
Proved developed gas reserves (Mcf)		136,544,572			140,966,295			122,390,360
Proved undeveloped gas reserves (Mcf)		34,084,849			69,957,117			75,649,610
Proved developed oil reserves (Bbls)(1)		682,030			36,566			32,272
Proved developed reserves as a percentage of total proved reserves		80.46	%		66.87	%		61.84	%
Standardized measure (in thousands)(2)	$	164,094		$	286,177		$	230,832


(1)		Although we have proved undeveloped oil reserves, they are insignificant, so no effort was made to calculate such reserves.

(2)		Standardized measure is the present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenues. Standardized measure does not give effect to commodity derivative transactions. For a description of our derivative transactions, see Note 8 — Financial Instruments and Note 7 — Derivative Financial Instruments, in the notes to the consolidated financial statements of this Form 10-K. The standardized measure shown should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standards Board (“FASB”) pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

(3)		The total estimated reserves for 2008 reflects all reserves regardless of basin or entity. The table below identifies the estimated reserves owned by QELP and QRCP as of December 31, 2008. As of December 31, 2007, all reserves were owned by Quest Energy. As of December 31, 2006 and prior to the formation of Quest Energy on November 14, 2007, all reserves were owned by QRCP.


	December 31, 2008
	QELP			QRCP			Total

Proved reserves
Gas (Mcf)		162,984,141			7,645,232			170,629,373
Oil (Bbls)		682,031			12,589			694,620
Total (Mcfe)		167,076,327			7,720,766			174,797,093
Proved developed gas reserves (Mcf)		134,837,105			1,707,467			136,544,572
Proved undeveloped gas reserves (Mcf)		28,147,084			5,937,765			34,084,849
Proved developed oil reserves (BBls)		682,030			—			682,030
Proved developed reserves as a percentage of total proved reserves		83.15	%		22.12	%		80.46	%
Standardized measure in (thousands)	$	156,057		$	8,037		$	164,094

The data in the table above represents estimates only. Oil and gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and gas that are ultimately recovered. See Item 1A. “Risk Factors — Risks Related to Our Business — Our estimated proved reserves are based on many

assumptions that may prove to be inaccurate.” Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Production Volumes, Sales Prices and Production Costs

The following table sets forth information regarding the oil and natural gas properties owned by us through our subsidiaries and affiliates. The oil and gas production figures reflect the net production attributable to our revenue interest and are not indicative of the total volumes produced by the wells. All sales data excludes the effects of our derivative financial instruments.


	Year Ended December 31,
	2008		2007		2006

Net Production:
Gas (Bcf)		21.33		16.98		12.30
Oil (Bbls)		69,812		7,070		9,808
Gas equivalent (Bcfe)		21.75		17.02		12.36
Oil and Gas Sales ($ in thousands):
Gas sales	$	141,489	$	104,853	$	71,836
Oil sales		6,448		432		574

Total oil and gas sales	$	147,937	$	105,285	$	72,410
Avg Sales Price:
Gas ($ per Mcf)	$	6.63	$	6.18	$	5.81
Oil ($ per Bbl)	$	92.36	$	61.10	$	58.52
Gas equivalent ($ per Mcfe)	$	6.80	$	6.19	$	5.86
Oil and gas operating expenses ($ per Mcfe):
Lifting	$	1.58	$	1.71	$	1.56
Production and property tax	$	0.45	$	0.42	$	0.49
Net Revenue ($ per Mcfe)	$	4.77	$	4.06	$	3.81

Producing Wells and Acreage

The following tables set forth information regarding our ownership of productive wells and total acres as of December 31, 2006, 2007 and 2008. For purposes of the table below, productive wells consist of producing wells and wells capable of production.


	Productive Wells
	Gas(1)				Oil				Total
	Gross		Net		Gross		Net		Gross		Net

December 31, 2006		1,653		1,635.0		29		28.1		1,682		1,637.8
December 31, 2007		2,225		2,218.2		29		28.1		2,254		2,210.1
December 31, 2008(2)		2,873		2,825.0		82		80.2		2,920		2,863.6


(1)		At December 31, 2008, we had approximately 2,346 gross wells in the Cherokee Basin that were producing from multiple seams.

(2)		Includes approximately 500 gross productive Appalachian Basin wells acquired in the PetroEdge acquisition and 55 gross productive oil wells acquired in Seminole County, Oklahoma.


	Leasehold Acreage
	Producing(1)				Nonproducing				Total
	Gross		Net		Gross		Net		Gross		Net

December 31, 2006		394,795		385,148		132,189		124,774		526,984		509,923
December 31, 2007(2)		403,048		393,480		204,104		187,524		607,152		581,004
December 31, 2008(3)(4)		464,702		446,537		208,224		180,707		672,926		627,244


(1)		Includes acreage held by production under the terms of the lease.


(2)		The leasehold acreage data as of December 31, 2007 includes non-producing leasehold acreage in the States of New Mexico, Texas and Pennsylvania of approximately 24,740 gross and 22,694 net acres. Approximately 45,000 net acres that were included in the 2006 leasehold acreage amounts have expired.

(3)		The leasehold acreage data as of December 31, 2008 includes acreage held by QRCP and QELP in the States of Kansas, Oklahoma, New York, Pennsylvania, and West Virginia.

(4)		The leasehold acreage data as of December 31, 2008 includes approximately 37,723 gross and 31,565 net acres attributable to various farm-out agreements or other mechanisms in the Appalachian Basin. Approximately 6,912 net acres are earned and approximately 24,653 net acres are unearned under these agreements. There are certain drilling or payment obligations that must be met before this unearned acreage is earned.

As of December 31, 2008, in the Cherokee Basin, we had 332,401 net developed acres and 225,202 net undeveloped acres. As of December 31, 2008, in the Appalachian Basin, we had 8,798 net developed acres and 59,592 net undeveloped acres. Subsequent to the divestiture of our acreage in Lycoming County, Pennsylvania, as of March 31, 2009, we had 8,758 net developed acres and 36,974 net undeveloped acres in the Appalachian Basin. Developed acres are acres spaced or assigned to productive wells/units based upon governmental authority or standard industry practice. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas, regardless of whether such acreage contains proved reserves.

Drilling Activities

The table below sets forth the number of wells completed at any time during the period, regardless of when drilling was initiated. Our drilling, recompletion, abandonment, and acquisition activities for the periods indicated are shown below (this information is inclusive of all basins and areas):


	Year Ended				Year Ended				Year Ended
	December 31,				December 31,				December 31,
	2008				2007				2006
	Oil & Gas				Gas(1)				Gas(1)
	Gross		Net		Gross		Net		Gross		Net

Exploratory wells drilled:
Capable of production		1		1		—		—		—		—
Dry		1		1		—		—		—		—
Development wells drilled:
Capable of production		339		338		572		572		621		621
Dry		—		—		—		—		—		—
Wells plugged and abandoned		17		17		—		—		—		—
Wells acquired capable of production(2)		551		514.5		—		—		—		—

Net increase in capable wells		875		837.5		572		572		621		621

Recompletion of old wells:
Capable of production		14		14		50		49		125		122


(1)		No change to oil wells for the years ended December 31, 2007 and 2006.

(2)		Includes 53.5 net and 55 gross oil wells capable of production acquired in Seminole County, Oklahoma in February 2008. The remainder of the acquired wells were acquired as part of the PetroEdge acquisition.

Exploration and Production

General

As the operator of wells in which we have an interest, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Quest Energy Service, LLC, our wholly-owned subsidiary, manages all of our properties and employs production and reservoir engineers, geologists and

other specialists. Quest Cherokee Oilfield Service, LLC, a wholly-owned subsidiary of Quest Energy, employs our Cherokee Basin and Appalachian Basin field personnel.

Field operations conducted by our personnel include duties performed by “pumpers” or employees whose primary responsibility is to operate the wells. Other field personnel are experienced and involved in the activities of well servicing, the development and completion of new wells and the construction of supporting infrastructure for new wells (such as electric service, salt water disposal facilities, and gas feeder lines). The primary equipment categories owned by us are trucks, well service rigs, stimulation assets and construction equipment. We utilize third party contractors on an “as needed” basis to supplement our field personnel.

In the Cherokee Basin, we provide, on an in-house basis, many of the services required for the completion and maintenance of our CBM wells. Internally sourcing these functions significantly reduces our reliance on third party contractors, which typically provide these services. We are also able to realize significant cost savings because we can reduce delays in executing our plan of development, avoid paying price markups and are able to purchase our own supplies at bulk discounts. We rely on third party contractors to drill our wells. Once a well is drilled, either we or a third party contractor will run the casing. We will perform the cementing, fracturing, stimulation and complete our own well site construction. We have our own fleet of 24 well service units that we use in the process of completing our wells, and to perform remedial field operations required to maintain production from our existing wells. In the Appalachian Basin, we rely on third party contractors for these services.

Oil and Gas Leases

As of December 31, 2008, we had over 4,500 leases covering approximately 627,244 net acres. The typical oil and gas lease provides for the payment of royalties to the mineral owner for all oil or gas produced from any well drilled on the lease premises. This amount ranges from 12.5% to 18.75% resulting in an 81.25% to 87.5% net revenue interest to us.

Because the acquisition of oil and gas leases is a very competitive process, and involves certain geological and business risks to identify productive areas, prospective leases are sometimes held by other oil and gas operators. In order to gain the right to drill these leases, we may purchase leases from other oil and gas operators. In some cases, the assignor of such leases will reserve an overriding royalty interest, ranging from 3.125% to 16.5% which further reduces the net revenue interest available to us to between 71.0% and 84.375%.

As of December 31, 2008, approximately 65% of our oil and gas leases were held by production, which means that for as long as our wells continue to produce oil or gas, we will continue to own those respective leases.

Natural Gas Pipelines

Gas Gathering Systems

QMLP’s approximately 2,173-mile low pressure gas gathering pipeline network is owned by Bluestem, a wholly-owned subsidiary of Quest Midstream. QMLP’s natural gas gathering pipeline network is located in the Cherokee Basin and provides a market outlet for natural gas in a region of approximately 1,000 square miles in size and has connections to both intrastate and interstate delivery pipelines. It is the largest gathering system in the Cherokee Basin with a current throughput capacity of approximately 85 Mmcf/d and delivers virtually all its gathered gas into Southern Star Central Gas Pipeline at multiple interconnects. This gathering system includes 83 field compression units comprising approximately 51,000 horsepower of compression in the field (most of which are currently rented) as well as seven CO₂ amine treating facilities.

The pipelines gather all of the natural gas produced by QELP in the Cherokee Basin pursuant to a midstream services and gas dedication agreement (see “— Midstream Services Agreement” below) in addition to some natural gas produced by other companies. The pipeline network is a critical asset for our future growth in the Cherokee Basin because natural gas gathering pipelines are a costly component of the infrastructure required for natural gas production and such pipelines are not easily constructed.

We intend to expand our gas gathering pipeline infrastructure through the development of new pipelines and to a lesser extent, through the acquisition of existing pipelines, if the outlook for commodity prices improves to the point where we believe future development in the Cherokee Basin is justified and Quest Midstream has available capital.

For 2008, our average cost for pipeline infrastructure to connect a Cherokee Basin well was approximately $65,500 per well. We estimate that our cost for pipeline infrastructure to connect a Cherokee Basin well will be approximately $61,000 per well for 2009. We expect to connect 56 wells in the Cherokee Basin in 2009, if the outlook for commodity prices improves to the point where we believe the connection of these wells is justified and Quest Midstream has available capital.

Quest Eastern owns and operates a gas gathering pipeline network of approximately 183 miles that serves our acreage position in the Appalachian Basin. The pipeline delivers both to intrastate gathering and interstate pipeline delivery points. Presently, this system has a maximum daily throughput of approximately 15 Mmcf/d and is operating at about 20% capacity. All of QELP’s Appalachian gas production is transported by Quest Eastern’s gas gathering pipeline network. Less than 1% of the current volumes transported on Quest Eastern’s natural gas gathering pipeline system are for third parties.

The following table sets forth the number of miles of gas gathering pipeline acquired or constructed by Quest Midstream and Quest Eastern during the periods indicated.


	Year Ended December 31,
	2008		2007		2006

Miles constructed		184		315		392
Miles acquired(1)		178		—		—


(1)	Consists of gas gathering system acquired by Quest Eastern as part of the PetroEdge acquisition.

The table below sets forth the natural gas volumes gathered on our gas gathering pipeline networks during the years ended December 31, 2008 and 2007.


	Year Ended December 31,
	2008		2007

Pipeline Natural Gas Vols (Mmcf)
Cherokee Basin		27,093		22,562
Quest Eastern		476		—

Midstream Services Agreement

Quest Energy and Quest Midstream are parties to a midstream services and gas dedication agreement entered into on December 22, 2006, but effective as of December 1, 2006. Pursuant to the midstream services agreement, Quest Midstream gathers and provides certain midstream services, including dehydration, treating and compression, to Quest Energy for all gas produced from Quest Energy’s wells in the Cherokee Basin that are connected to Quest Midstream’s gathering system.

The initial term of the midstream services agreement expires on December 1, 2016, with two additional five-year extension periods that may be exercised by either party upon 180 days’ notice. The fees charged under the midstream services agreement are subject to renegotiation upon the exercise of each five-year extension period.

Under the midstream services agreement, Quest Energy agreed to pay Quest Midstream an initial fee equal to $0.50 per Mmbtu of gas for gathering, dehydration and treating services and $1.10 per Mmbtu of gas for compression services, subject to an annual adjustment to be determined by multiplying each of the gathering services fee and the compression services fee by the sum of (i) 0.25 times the percentage change in the producer price index for the prior calendar year and (ii) 0.75 times the percentage change in the Southern Star first of month index for the prior calendar year. Such adjustment will be calculated within 60 days after the beginning of each year, but will be retroactive to the beginning of the year. Such fees will never be reduced below the initial rates described above. For 2008, the fees were $0.51 per Mmbtu of gas for gathering, dehydration and treating services and $1.13

per Mmbtu of gas for compression services. For 2009, the fees are $0.596 per Mmbtu of gas for gathering, dehydration and treating services and $1.319 per Mmbtu of gas for compression services. Such fees are subject to renegotiation in connection with each renewal period. In addition, at any time after each five year anniversary of the date of the midstream services agreement, each party will have a one-time option to elect to renegotiate the fees and/or the basis for the annual adjustment to the fees if the party believes there has been a material change to the economic returns or financial condition of either party. If the parties are unable to agree on the changes, if any, to be made to such terms, then the parties will enter into binding arbitration to resolve any dispute with respect to such terms.

In accordance with the midstream services agreement, Quest Energy bears the cost to remove and dispose of free water from its gas prior to delivery to Quest Midstream and of all fuel requirements necessary to perform the gathering and midstream services, plus any lost and unaccounted for gas.

Quest Midstream has an exclusive option for sixty days to connect to its gathering system each of the gas wells that Quest Energy develops in the Cherokee Basin. In addition, Quest Midstream will be required to connect to its gathering system, at its expense, any new gas wells that Quest Energy completes in the Cherokee Basin if Quest Midstream would earn a specified internal rate of return from those wells. This rate of return is subject to renegotiation once after the fifth anniversary of the agreement and once during each renewal period at the election of either party. Quest Midstream also has the sole discretion to cease providing services on all or any part of its gathering system if it determines that continued operation is not economically justified. If Quest Midstream elects to do so, it must provide Quest Energy with 90 days written notice and will offer Quest Energy the right to purchase that part of the terminated system. If Quest Energy does acquire that part of the system and it remains connected to any other portion of Quest Midstream’s gathering system, then Quest Energy may deliver its gas from the terminated system to Quest Midstream’s system, and a fee for any services provided by Quest Midstream will be negotiated.

In addition, Quest Midstream agreed to install the saltwater disposal lines for Quest Energy’s gas wells connected to Quest Midstream’s gathering system for an initial fee of $1.25 per linear foot and connect such lines to Quest Energy’s saltwater disposal wells for a fee of $1,000 per well, subject to an annual adjustment based on changes in the Employment Cost Index for Natural Resources, Construction, and Maintenance. For 2008, the fees were $1.29 per linear foot to install saltwater disposal lines and $1,030 per well to connect such lines to Quest Energy’s saltwater disposal wells. For 2009, the fees are $1.33 per linear foot to install saltwater disposal lines and $1,061 per well to connect such lines to Quest Energy’s saltwater disposal wells.

Appalachian Gathering Agreement

Quest Cherokee and Quest Eastern are parties to a gas transportation agreement effective as of July 1, 2008. Pursuant to the gas transportation agreement, Quest Eastern receives, transports and processes all gas delivered by Quest Cherokee at certain specified receipt points and redelivers to or for the account of Quest Cherokee at the delivery points the thermal equivalent of the gas received from Quest Cherokee.

Pursuant to the gas transportation agreement, Quest Cherokee has agreed to pay Quest Eastern a fee equal to $0.70 per Mmbtu. Should Quest Cherokee fail to timely remit the full amount owed to Quest Eastern when due, unless such failure is caused by Quest Cherokee disputing in good faith the amount owed to Quest Eastern, Quest Cherokee must pay interest on the unpaid and undisputed portion, which will accrue at a rate equal to prime plus 1%.

The gas transportation agreement will continue until terminated upon 90 days written notice by either party. Upon termination of the agreement, Quest Eastern may require Quest Cherokee to resize the compression within Quest Eastern’s infrastructure and facilities to the capacity necessary without Quest Cherokee’s gas as of the date of termination.

In accordance with the gas transportation agreement, Quest Eastern has the right to decrease or halt the receipt of Quest Cherokee’s gas without prior notification if at any time Quest Cherokee’s gas will materially adversely affect the normal operation of Quest Eastern’s facilities due to the failure of gas delivered by Quest Cherokee to meet the quality standards as outlined in the agreement.

Third Party Gas Gathering

For services rendered to parties other than Quest Energy, Quest Midstream retains a portion of the gas volumes sold. Approximately 6% of the gas transported on Quest Midstream’s natural gas gathering pipeline system in the Cherokee Basin is for third parties.

Interstate Pipelines

KPC, an indirect subsidiary of Quest Midstream, owns and operates an approximately 1,120-mile interstate gas pipeline, which transports natural gas from Oklahoma and western Kansas to the metropolitan Wichita and Kansas City markets. Further, it is one of only three pipeline systems currently capable of delivering gas into the Kansas City metropolitan market. The KPC system includes three compressor stations with a total of 14,680 horsepower and has a throughput capacity of approximately 160 Mmcf/d. KPC has supply interconnections with pipelines owned and/or operated by Enogex Inc., Panhandle Eastern PipeLine Company and ANR Pipeline Company, allowing QMLP to transport natural gas volumes sourced from the Anadarko and Arkoma basins, as well as the western Kansas and Oklahoma panhandle producing regions.

Marketing and Major Customers

Exploration and Production

We market our own natural gas. In the Cherokee Basin for 2008, approximately 98% of our gas production was sold to ONEOK Energy Marketing and Trading Company (“ONEOK”). More than 79% of our natural gas production was sold to ONEOK and 21% was sold to Tenaska Marketing Ventures in 2007. More than 95% of our natural gas production was sold to ONEOK in 2006.

Our oil in the Cherokee Basin is currently being sold to Coffeyville Refining. Previously, it had been sold to Plains Marketing, L.P.

During the year ended December 31, 2008, we sold 100% of our oil in Seminole County, Oklahoma to Sunoco Partners Marketing & Terminals L.P. under sale and purchase contracts, which have varying terms and cannot be terminated by either party, other than following an event of default.

Approximately 73% of our 2008 Appalachian Basin production was sold to Dominion Field Services under contracts with a mix of fixed price and index based sales in place at the time of the PetroEdge acquisition in July 2008. Reliable Wetzel transported and sold approximately 10% of our 2008 Appalachian Basin production under a market sensitive contract that expires in 2010. Another 8% was sold to Hess Corporation under a mix of fixed price and index based sales. The remainder of the Appalachian production was sold to various purchasers under market sensitive pricing arrangements. None of these remaining sales exceeded 4% of total Appalachian Basin production. Due to the history of problematic Northeastern pipeline constraints, we have secured a firm transportation agreement to ensure uninterrupted deliveries of our natural gas production.

Under various sale and purchase contracts, 100% of our oil produced in the Appalachian Basin was sold to Appalachian Oil Purchasers, a division of Clearfield Energy.

If we were to lose any of these oil or gas purchasers, we believe that we would be able to promptly replace them.

Gas Gathering

Approximately 94% of the throughput on Quest Midstream’s gas gathering pipeline system is attributable to Quest Energy production with the balance being other third party customers. Approximately 99% of the throughput on Quest Eastern’s gas gathering pipeline system in the Appalachian Basin is attributable to Quest Energy production.

Interstate Pipelines

KPC’s two primary customers are Kansas Gas Service (KGS) and Missouri Gas Energy (MGE), both of which are served under firm natural gas transportation contracts. For the period from November 1, 2007, the date of the KPC Pipeline acquisition, through December 31, 2007, approximately 60% of KPC’s revenue was from KGS and 36% was from MGE. During 2008, approximately 58% and 36% of KPC’s revenue was from KGS and MGE, respectively. KGS, a division of ONEOK, Inc., is the local distribution company in Kansas for Kansas City and Wichita as well as a number of other municipalities; while MGE, a division of Southern Union Company, is a natural gas distribution company that serves over one-half million customers in 155 western Missouri communities.

Commodity Derivative Activities

Quest Energy sells the majority of its gas in the Cherokee Basin based on the Southern Star first of month index, with the remainder sold on the daily price on the Southern Star index. Quest Energy sells the majority of its gas in the Appalachian Basin based on the Dominion Southpoint index, with the remainder sold on local basis. Quest Energy sells the majority of its oil production under a contract priced at a fixed discount to NYMEX oil prices. Due to the historical volatility of oil and natural gas prices, Quest Energy has implemented a hedging strategy aimed at reducing the variability of prices it receives for the sale of its future production. While we believe that the stabilization of prices and production afforded Quest Energy by providing a revenue floor for its production is beneficial, this strategy may result in lower revenues than Quest Energy would have if it was not a party to derivative instruments in times of rising oil or natural gas prices. As a result of rising commodity prices, Quest Energy may recognize additional charges to future periods. Quest Energy holds derivative contracts based on Southern Star and NYMEX natural gas and oil prices and it has fixed price sales contracts with certain customers in the Appalachian Basin. These derivative contracts and fixed price contracts mitigate Quest Energy’s risk to fluctuating commodity prices but do not eliminate the potential effects of changing commodity prices. Quest Energy’s derivative contracts limit its exposure to basis differential risk as it generally enters into derivative contracts that are based on the same indices on which the underlying sales contracts are based or by entering into basis swaps for the same volume of hedges that settle based on NYMEX prices.

As of December 31, 2008, Quest Energy held derivative contracts and fixed price sales contracts totaling approximately 39.8 Bcf of natural gas and 66,000 Bbls of oil through 2012. Approximately 14.6 Bcf of Quest Energy’s Cherokee Basin natural gas production is hedged utilizing Southern Star contracts at a weighted average price of $7.78/Mmbtu for 2009 and approximately 22.5 Bcf of its Cherokee Basin natural gas production is hedged utilizing Southern Star contracts at a weighted average price of $7.42/Mmbtu for 2010 through 2012. Approximately 0.75 Bcf of Quest Energy’s Appalachian Basin natural gas production is hedged utilizing NYMEX contracts at a weighted average price of $11.00/Mmbtu for 2009 and approximately 1.2 Bcf of its Appalachian Basin natural gas is hedged utilizing NYMEX contracts at a weighted average price of $9.77/Mmbtu for 2010 through 2012. Quest Energy’s fixed price sales contracts hedge approximately 0.65 Bcf of its Appalachian Basin natural gas production at a weighted average price of $8.38/Mmbtu in 2009 and 0.1 Bcf of its Appalachian Basin natural gas production at a weighted average price of $8.96/Mmbtu in 2010.

As of December 31, 2008, approximately 36,000 Bbls of Quest Energy’s Seminole County crude oil production is hedged utilizing NYMEX contracts at a weighted average price of $90.07/Bbl for 2009 and approximately 30,000 Bbls of our Seminole County crude oil production is hedged utilizing NYMEX contracts for 2010 through 2012 at a weighted average price of $87.50/Bbl. For more information on our derivative contracts, see Note 8 — Financial Instruments and Note 7 — Derivative Financial Instruments, in the notes to the consolidated financial statements in Item 8 of this Form 10-K.

Competition

Exploration and Production

We operate in a highly competitive environment for acquiring properties, marketing oil and gas and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. As a result, our competitors may be able to pay more for productive oil and gas properties and exploratory prospects and to evaluate,

bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and gas industry.

Gas Gathering

Quest Midstream’s and Quest Eastern’s gas gathering systems experience minimal competition because approximately 94% and 99%, respectively, of these systems’ throughput is attributable to Quest Energy production.

Interstate Pipelines

We compete with other interstate and intrastate pipelines in the transportation of natural gas for transportation customers primarily on the basis of transportation rates, access to competitively priced supplies of natural gas, markets served by the pipelines, and the quality and reliability of transportation services. Major competitors include Southern Star Central Gas Pipeline, Kinder Morgan Interstate Gas Transmission’s Pony Express Pipeline and Panhandle Eastern Pipeline Company in the Kansas City market, and Southern Star Central Gas Pipeline, Peoples Natural Gas and Mid-Continent Market Center in the Wichita market.

Title to Properties

Oil and Gas Properties

As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of development operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence development operations on a property until we have cured any material title defects on such property. Prior to completing an acquisition of producing oil and gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, we believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and gas industry.

Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or will materially interfere with our use in the operation of our business. In some cases lands over which leases have been obtained are subject to prior liens which have not been subordinated to the leases. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects.

On a small percentage of our acreage (less than 1.0%), the landowner in the past transferred the rights to the coal underlying their land to a third party. With respect to those properties, we have obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying those lands. In Oklahoma and Kansas, the law is unsettled as to whether the owner of the gas rights or the coal rights is entitled to the CBM gas. We are currently involved in litigation with the owner of the coal rights on these lands to determine who has the rights to the CBM gas.

Pipeline Rights-of-Way

Substantially all of our gathering systems and our transmission pipeline are constructed within rights-of-way granted by property owners named in the appropriate land records. All of our compressor stations are located on property owned in fee or on property obtained via long-term leases or surface easements.

Our property or rights-of-way are subject to encumbrances, restrictions and other imperfections. These imperfections have not interfered, and we do not expect that they will materially interfere, with the conduct of our business. In many instances, lands over which rights-of-way have been obtained are subject to prior liens which have not been subordinated to the right-of-way grants. In some cases, not all of the owners named in the appropriate land records have joined in the right-of-way grants, but in substantially all such cases signatures of the owners of majority interests have been obtained. Substantially all permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets, and state highways, where necessary. Substantially all permits have also been obtained from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election.

Certain of our rights to lay and maintain pipelines are derived from recorded oil and gas leases, for wells that are currently in production; however, the leases are subject to termination if the wells cease to produce. In most cases, the right to maintain existing pipelines continues in perpetuity, even if the well associated with the lease ceases to be productive. In addition, because some of these leases affect wells at the end of lines, these rights-of-way will not be used for any other purpose once the related wells cease to produce.

Seasonal Nature of Business

Exploration and Production and Gas Gathering

Seasonal weather conditions and lease stipulations can limit our development activities and other operations and, as a result, we seek to perform a significant percentage of our development during the spring and summer months. These seasonal anomalies can pose challenges for meeting our well development objectives and increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

In addition, freezing weather, winter storms and flooding in the spring and summer have in the past resulted in a number of our wells being off-line for a short period of time, which adversely affects our production volumes and revenues and increases our lease operating costs due to the time spent by field employees to bring the wells back on-line.

Generally, but not always, the demand for gas decreases during the summer months and increases during the winter months thereby affecting the price we receive for gas. Seasonal anomalies such as mild winters and hot summers sometimes lessen this fluctuation.

Interstate Pipelines

Due to the nature of the markets served by the KPC Pipeline, primarily the metropolitan Wichita and Kansas City markets’ heating load, the utilization rate of the KPC Pipeline has traditionally been much higher in the winter months (December through April) than in the remainder of the year. However, due to the nature of the firm transportation agreements under which the vast majority of the KPC Pipeline revenue is derived, we are, to a material degree, profit neutral to these seasonal fluctuations.

Environmental Matters and Regulation

General

Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:


	•	require the acquisition of various permits before drilling commences;

	•	enjoin some or all of the operations of facilities deemed in non-compliance with permits;

	•	restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas drilling, production and transportation activities;


	•	limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, areas inhabited by endangered or threatened species, and other protected areas; and

	•	require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

These laws, rules and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and gas industry could have a significant impact on our operating costs.

The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

Waste Handling

The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous solid wastes. Under the auspices of the federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, production and transportation of oil and gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, and waste oils, which may be regulated as hazardous wastes. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements.

Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, imposes joint and several liabilities, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain environmental studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We currently own, lease or operate numerous properties that have been used for oil and gas exploration, production, and transportation for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. In fact, there is evidence that petroleum spills or releases have occurred in the past at some of the properties owned or leased by us. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform plugging or pit closure operations to prevent future contamination.

Water Discharges

The Clean Water Act (“CWA”) and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants in waste water and storm water, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The CWA regulates storm water run-off from oil and gas production operations and requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of the CWA may require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. Federal and state regulatory agencies can also impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Our operations also produce wastewaters that are disposed via underground injection wells. These activities are regulated by the Safe Drinking Water Act (“SDWA”) and analogous state and local laws. The underground injection well program under the SDWA classifies produced wastewaters and imposes controls relating to the drilling and operation of the wells as well as the quality of the injected wastewaters. This program is designed to protect drinking water sources and requires a permit from the EPA or the designated state agency. Currently, our operations comply with all applicable requirements and have a sufficient number of operating injection wells. However, a change in the regulations or the inability to obtain new injection well permits in the future may affect our ability to dispose of the produced waters and ultimately affect the results of operations.

The primary federal law for oil spill liability is the Oil Pollution Act, or OPA, which addresses three principal areas of oil pollution: prevention, containment, and cleanup. OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, may be subject to oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills.

Air Emissions

The Federal Clean Air Act (“CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. Such laws and regulations may require a facility to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain or strictly comply with air permits containing various emissions and operational limitations or utilize specific emission control technologies to limit emissions. In addition, EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Moreover, depending on the state-specific statutory authority, states may be able to impose air emissions limitations that are more stringent than the federal standards imposed by EPA. Federal and state regulatory agencies can also impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations.

Permits and related compliance obligations under the CAA, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas, may require oil and gas exploration, production and transportation operations to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies. In addition, some oil and gas facilities may be included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under the CAA. Failure to comply with these requirements could subject a regulated entity to monetary penalties, injunctions, conditions or restrictions on operations and enforcement actions. Oil and gas exploration and production facilities may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or use specific

emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. Historically, air pollution control has become more stringent over time. This trend is expected to continue. The cost of technology and systems to control air pollution to meet regulatory requirements is significant today. These costs are expected to increase as air pollution control requirements increase. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

The Kyoto Protocol to the United Nations Framework Convention on Climate Change, or the Protocol, became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as “greenhouse gases”, that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol; however, Congress has recently considered proposed legislation directed at reducing “greenhouse gas emissions”, and certain states have adopted legislation, regulations and/or initiatives addressing greenhouse gas emissions from various sources, primarily power plants. Additionally, on April 2, 2007, the U.S. Supreme Court ruled in Massachusetts v. EPA that the EPA has authority under the CAA to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks). The Court also held that greenhouse gases fall within the CAA’s definition of “air pollutant”, which could result in future regulation of greenhouse gas emissions from stationary sources, including those used in oil and gas exploration, production and transportation operations. The oil and gas industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. Our operations are not adversely impacted by the current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

Hydrogen Sulfide

Hydrogen sulfide gas is a byproduct of sour gas treatment. Exposure to unacceptable levels of hydrogen sulfide (known as sour gas) is harmful to humans, and prolonged exposure can result in death. We employ numerous safety precautions to ensure the safety of our employees. There are various federal and state environmental and safety requirements that apply to facilities using or producing hydrogen sulfide gas. Notwithstanding compliance with such requirements, common law causes of action are available to persons damaged by exposure to hydrogen sulfide gas.

National Environmental Policy Act

Oil and gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. If we were to conduct any exploration and production activities on federal lands in the future, those activities would need to obtain governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and gas projects.

Endangered Species Act

The Endangered Species Act (“ESA”) and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Although we believe that our current operations do not affect endangered or threatened species or their habitats, the existence of endangered or threatened species in areas of future operations and development could cause us to incur additional mitigation costs or become subject to construction or operating restrictions or bans in the affected areas.

OSHA and Other Laws and Regulation

We are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The Occupational Safety and Health Administration’s hazard communication standard, EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other comparable laws.

We believe that we are in substantial compliance with all existing environmental and safety laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. For instance, we did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2008. Additionally, as of the date of this report, we are not aware of any environmental issues or claims that will require material capital expenditures during 2009. However, accidental spills or releases may occur in the course of our operations, and we cannot assure you that we will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. Moreover, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our business, financial condition, or results of operations.

Other Regulation of the Oil and Gas Industry

The oil and gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including gas and oil facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Exploration and Production

Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:


	•	the location of wells;

	•	the method of drilling and casing wells;

	•	the surface use and restoration of properties upon which wells are drilled;

	•	the plugging and abandoning of wells; and

	•	notice to surface owners and other third parties.

Some state laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, some state conservation laws establish maximum rates of production from oil and gas wells. These laws generally prohibit the

venting or flaring of gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, some states impose a production or severance tax with respect to the production and sale of oil, gas and gas liquids within its jurisdiction.

The Cherokee Basin has been an active oil and gas producing region for a number of years. Many of our properties had abandoned oil and conventional gas wells on them at the time the current lease was entered into with the landowner. A number of these wells remain unplugged or were improperly plugged by a prior landowner or operator. Many of the former operators of these wells have ceased operations and cannot be located or do not have the financial resources to plug these wells. We believe that we are not responsible for plugging an abandoned well on one of our leases, unless we have used, attempted to use or invaded the abandoned well bore in our operations on the land or have otherwise agreed to assume responsibility for plugging the wells. The Kansas Corporation Commission’s current interpretation of Kansas law is consistent with our position.

Interstate Pipelines

The availability, terms and cost of transportation significantly affect sales of gas. The interstate transportation of gas and sale for resale of gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to gas pipeline transportation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the gas industry, most notably interstate gas transmission companies that remain subject to FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the gas industry. We cannot predict the ultimate impact of these regulatory changes to our operations, and we note that some of FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action materially differently than other interstate pipelines with which we compete.

The Energy Policy Act of 2005, or EP Act 2005, gave FERC increased oversight and penalty authority regarding market manipulation and enforcement. EP Act 2005 amended the Natural Gas Act of 1938, or NGA, to prohibit market manipulation and also amended the NGA and the Natural Gas Policy Act of 1978, or NGPA, to increase civil and criminal penalties for any violations of the NGA, NGPA and any rules, regulations or orders of FERC to up to $1,000,000 per day, per violation. In addition, FERC issued a final rule effective January 26, 2006 regarding market manipulation, which makes it unlawful for any entity, in connection with the purchase or sale of gas or transportation service subject to FERC’s jurisdiction, to defraud, make an untrue statement or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud. This final rule works together with FERC’s enhanced penalty authority to provide increased oversight of the gas marketplace.

Although gas prices are currently unregulated, FERC promulgated regulations in December 2007 requiring natural gas sellers to submit an annual report, beginning in July 2009, reporting certain information regarding natural gas purchases and sales (e.g., total volumes bought and sold, volumes bought and sold and index prices, etc.). Additionally, Congress historically has been active in the area of gas regulation. We cannot predict whether new legislation to regulate gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and gas liquids are not currently regulated and are made at market prices.

State Regulation

The various states regulate the drilling for, and the production, gathering and sale of, oil and gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Kansas currently imposes a severance tax on the gross value of oil and gas produced from wells having an average daily production during a calendar month with a gross value of more than $87 per day. Kansas also imposes oil and gas conservation assessments per barrel of oil and per 1,000 cubic feet of gas produced. In general, oil and gas leases and oil and gas

wells (producing or capable of producing), including all equipment associated with such leases and wells, are subject to an ad valorem property tax.

Oklahoma imposes a monthly gross production tax and excise tax based on the gross value of the oil and gas produced. Oklahoma also imposes an excise tax based on the gross value of oil and gas produced. All property used in the production of oil and gas is exempt from ad valorem taxation if gross production taxes are paid. Lastly, the rate of taxation of locally assessed property varies from county to county and is based on the fair cash value of personal property and the fair cash value of real property.

West Virginia imposes a severance tax equal to five percent of the gross value of oil and gas produced and a similar severance tax on CBM produced. West Virginia also imposes an additional annual privilege tax equal to 4.7 cents per Mcf of natural gas produced. New York imposes an annual oil and gas charge based on the amount of oil or natural gas produced each year.

States may regulate rates of production and may establish maximum daily production allowables from oil and gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may limit the amounts of oil and gas that may be produced from our wells and may limit the number of wells or locations drilled.

Federal Regulation of Transportation of Gas

FERC regulates interstate natural gas pipelines pursuant to the NGA, NGPA and EP Act 2005. Generally, FERC’s authority over interstate natural gas pipelines extends to:


	•	rates and charges for natural gas transportation services;

	•	certification and construction of new facilities;

	•	extension or abandonment of services and facilities;

	•	maintenance of accounts and records;

	•	relationships between pipelines and certain affiliates;

	•	terms and conditions of service;

	•	depreciation and amortization policies;

	•	acquisition and disposition of facilities; and

	•	initiation and discontinuation of services.

Rates charged by interstate natural gas pipelines may generally not exceed the just and reasonable rates approved by FERC, unless they are filed as “negotiated rates” and accepted by the FERC. In addition, interstate natural gas pipelines are prohibited from granting any undue preference to any person, or maintaining any unreasonable difference in their rates, terms, or conditions of service. Consistent with these requirements, the rates, terms, and conditions of the natural gas transportation services provided by interstate pipelines are governed by tariffs approved by FERC.

We own and operate one interstate natural gas pipeline system that is subject to these regulatory requirements. KPC owns and operates a 1,120-mile interstate natural gas pipeline system, which transports natural gas from Oklahoma and western Kansas to the metropolitan markets of Wichita and Kansas City. As an interstate natural gas pipeline, KPC is subject to FERC’s jurisdiction and the regulatory requirements summarized above. Maintaining compliance with these requirements on a continuing basis requires KPC to incur various expenses. Additional compliance expenses could be incurred if new or amended laws or regulations are enacted or existing laws or regulations are reinterpreted. KPC’s customers, the state commissions that regulate certain of those customers, and other interested parties also have the right to file complaints seeking changes in the KPC tariff, including with respect to the transportation rates stated therein.

Our remaining natural gas pipeline facilities are generally exempt from FERC’s jurisdiction and regulation pursuant to Section 1(b) of the NGA, which exempts pipeline facilities that perform primarily a gathering function, rather than a transportation function. We believe our pipeline facilities (other than the KPC system) meet the traditional tests used by FERC to distinguish gathering facilities from transportation facilities. However, if FERC were to determine that the facilities perform primarily a transportation function, rather than a gathering function, these facilities may become subject to regulation as interstate natural gas pipeline facilities. We believe the expenses associated with seeking certificate authority for construction, service and abandonment, establishing rates and a tariff for these other facilities, and meeting the detailed regulatory accounting and reporting requirements would substantially increase our operating costs and would adversely affect our profitability.

Additionally, while generally exempt from FERC’s jurisdiction, FERC adopted new internet posting requirements in November 2008 that are applicable to certain gathering facilities and other non-interstate pipelines meeting size and other thresholds. Various parties have requested rehearing of the FERC rule adopting the new posting requirements and the FERC has granted an extension of time to comply with the new requirements until 150 days following the issuance of an order addressing the requests for rehearing. If the rules are upheld on rehearing and become applicable to our gathering facilities, they would likely require us to post certain pipeline operational information on a daily basis, which could require us to incur additional compliance expenses.

State Regulation of Natural Gas Gathering Pipelines

Our natural gas gathering pipeline operations are currently limited to the States of Kansas, Oklahoma, New York, and West Virginia. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and compliant-based rate regulation. Bluestem is licensed as an operator of a natural gas gathering system with the KCC and is required to file periodic information reports with the KCC. We are not required to be licensed as an operator or to file reports in Oklahoma, New York or West Virginia.

On those portions of our gas gathering system that are open to third party producers, the producers have the ability to file complaints challenging our gathering rates, terms of services and practice. Our fees, terms and practice must be just, reasonable, not unjustly discriminatory and not unduly preferential. If the KCC or the Oklahoma Corporation Commission (OCC), as applicable, were to determine that the rates charged to a complainant did not meet this standard, the KCC or the OCC, as applicable, would have the ability to adjust our rates with respect to the wells that were the subject of the complaint. We are not aware of any instance in which either the KCC or the OCC has made such a determination in the past.

These regulatory burdens may affect profitability, and management is unable to predict the future cost or impact of complying with such regulations. While state regulation of pipeline transportation does not materially affect our operations, we do own several small, discrete delivery laterals in Kansas that are subject to a limited jurisdiction certificate issued by the KCC. As with FERC regulation described above, state regulation of pipeline transportation may influence certain aspects of our business and the market price for our products.

Sales of Natural Gas

The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry, and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines.

Pipeline Safety

Our pipelines are subject to regulation by the U.S. Department of Transportation, or the DOT, under the Natural Gas Pipeline Safety Act of 1968, as amended, or the NGPSA, pursuant to which the DOT has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The NGPSA covers the pipeline transportation of natural gas and other gases and requires any entity that owns or operates pipeline facilities to comply with the regulations under the NGPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that our pipeline operations are in substantial compliance with applicable NGPSA requirements; however, if new or amended laws and regulations are enacted or existing laws and regulations are reinterpreted, future compliance with the NGPSA could result in increased costs.

Other

In addition to existing laws and regulations, the possibility exists that new legislation or regulations may be adopted which would have a significant impact on our operations or our customers’ ability to use gas and may require us or our customers to change their operations significantly or incur substantial costs. Additional proposals and proceedings that might affect the gas industry are pending before Congress, FERC, the Minerals Management Service, state commissions and the courts. We cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of injunctive relief or both. Moreover, changes in any of these laws and regulations could have a material adverse effect on our business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.

Management believes that our operations comply in all material respects with applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive effect on our method of operations than on other similar companies in the energy industry. We have internal procedures and policies to ensure that our operations are conducted in substantial regulatory compliance.

Employees

At December 31, 2008, we had a staff of 177 field employees in offices located in Kansas, Oklahoma, Pennsylvania, and West Virginia. We have 61 pipeline operations employees. Our staff consists of 72 executive and administrative personnel at the headquarters office in Oklahoma City and the Quest Midstream office in Houston, Texas. None of our employees are covered by a collective bargaining agreement. Management considers its relations with our employees to be satisfactory.

Administrative Facilities

The office space for the corporate headquarters for us and our subsidiaries and affiliates is leased and is located at 210 Park Avenue, Suite 2750, Oklahoma City, Oklahoma 73102. The office lease is for 10 years expiring August 31, 2017 covering approximately 35,000 square feet. We own three buildings located in Chanute, Kansas that are used for administrative offices, a geological laboratory, an operations terminal and a repair facility. We own an additional building and storage yard in Lenapah, Oklahoma.

The office space for Quest Eastern is leased and is located at 2200 Georgetowne Drive, Suite 301, Sewickley, Pennsylvania 15143. The office lease is for five years expiring August 1, 2013 covering approximately 4,744 square feet. Quest Eastern owns a 50% interest in a nine acre lot with building improvements in Wetzel County, West Virginia that is used for equipment storage and office space.

Quest Midstream has 9,801 square feet of office space for some of its management personnel that is leased and is located at 3 Allen Center, 333 Clay Street, Suite 4060, Houston, Texas 77002. The office lease expires on May 6, 2015. Quest Midstream also owns an operational office that is located east of Chanute, Kansas. KPC has leased

facilities at Olathe, Wichita, and Medicine Lodge, Kansas for the operations of its interstate pipeline. The Olathe office consists of approximately 7,650 square feet for a lease term of five years expiring October 31, 2011. The Wichita office consists of approximately 1,240 square feet on a one year lease, with an extension expiring December 31, 2009. The Medicine Lodge field office is leased on a month to month basis.

Where To Find Additional Information

Additional information about us can be found on our website at www.questresourcecorp.com. We also provide free of charge on our website our filings with the SEC, including our annual reports, quarterly reports, and current reports along with any amendments thereto, as soon as reasonably practicable after we have electronically filed such material with, or furnished it to, the SEC.

GLOSSARY OF SELECTED TERMS

The following is a description of the meanings of some of the oil and natural gas industry terms used in this Form 10-K.

Appalachian Basin. One of the United States’ oldest oil and natural gas producing regions that extends from Alabama to Maine.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.

Bcf. One billion cubic feet of gas.

Bcfe. One billion cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of crude oil, condensate or gas liquids.

Brown Shales. Fine grained rocks composed largely of clay minerals that contain little organic matter. Some of these shales immediately overlay the Marcellus Shale.

Btu or British Thermal Unit. The quantity of heat required to raise the temperature of a one pound mass of water by one degree Fahrenheit.

CBM. Coal bed methane.

Cherokee Basin. A fifteen-county region in southeastern Kansas and northeastern Oklahoma.

Completion. The installation of permanent equipment for the production of oil or gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development well. A well drilled within the proved boundaries of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Devonian Sands. Sands generally younger and shallower than the Marcellus Shale that occur in portions of Ohio, New York, Pennsylvania, West Virginia, Kentucky and Tennessee and generally located at depths of less than 5,000 feet.

Dry hole. A well found to be incapable of producing hydrocarbons in paying quantities.

Dth. One dekatherm, equivalent to one million British Thermal Units.

Earned acreage. The number of acres that has been assigned as a result of fulfilling conditions or requirements of an agreement.

Exploitation. A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

Exploratory well. A well drilled: a) to find and produce oil or gas in an area previously considered unproductive; b) to find a new reservoir in a known field, i.e., one previously producing oil and gas from another reservoir, or c) to extend the limit of a known oil or gas reservoir.

Farm-in or farm-out. An agreement under which the owner of a working interest in an oil or gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.” Acreage is considered to be unearned, until the conditions of the agreement are met, and an assignment of interest has been made.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Frac/fracturing. The method used to increase the deliverability of a well by pumping a liquid or other substance into a well under pressure to crack and prop open the hydrocarbon formation.

Gas. Hydrocarbon gas found in the earth, composed of methane, ethane, butane, propane and other gases.

Gathering system. Pipelines and other equipment used to move gas from the wellhead to the trunk or the main transmission lines of a pipeline system.

Gross acres or gross wells. The total acres or wells, as the case may be, in which we have a working interest.

Horizon or formation. The section of rock, from which gas is expected to be produced.

Marcellus Shale. A black, organic-rich shale formation in the Appalachian Basin that occurs in much of Ohio, West Virginia, Pennsylvania and New York and portions of Maryland, Kentucky, Tennessee and Virginia. The fairway of the Marcellus Shale is generally located at depths between 3,500 and 8,000 feet and ranges in thickness from 50 to 150 feet.

Mcf. One thousand cubic feet of gas.

Mcf/d. One Mcf per day.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of crude oil, condensate or gas liquids.

Mmbtu. One million British thermal units.

Mmcf. One million cubic feet of gas.

Mmcf/d. One Mmcf per day.

Mmcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of crude oil, condensate or gas liquids.

Mmcfe/d. One million cubic feet equivalent per day.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or wells, as the case may be.

Net production. Production that is owned by us less royalties and production due others.

Net revenue interest. The percentage of revenues due an interest holder in a property, net of royalties or other burdens on the property.

NGLs. Natural gas liquids being the combination of ethane, propane, butane and natural gasoline that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX. The New York Mercantile Exchange.

Oil. Crude oil, condensate and NGLs.

Permeability. The ability, or measurement of a rock’s ability, to transmit fluids, typically measured in darcies or millidarcies.

Perforation. The making of holes in casing and cement (if present) to allow formation fluids to enter the well bore.

Productive well. A well that produces commercial quantities of hydrocarbons exclusive of its capacity to produce at a reasonable rate of return.

Proved developed non-producing reserves. Proved developed reserves expected to be recovered from zones behind casings in existing wells.

Proved developed reserves. Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. This definition of proved developed reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

Proved reserves. The estimated quantities of crude oil, natural gas and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. This definition of proved reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells drilled to known reservoirs on acreage yet to be drilled for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required to establish production. This definition of proved undeveloped reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reserve. That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.

Reserve-to-production ratio. This ratio is calculated by dividing estimated net proved reserves by the production from the previous year to estimate the number of years of remaining production.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty Interest. A real property interest entitling the owner to receive a specified portion of the gross proceeds of the sale of oil and natural gas production or, if the conveyance creating the interest provides, a specific portion of oil or natural gas produced, without any deduction for the costs to explore for, develop or produce the oil and gas. A royalty interest owner has no right to consent to or approve the operation and development of the property, while the owners of the working interests have the exclusive right to exploit the mineral on the land.

Shut in. To close down a well temporarily.

Standardized measure. The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Standardized measure does not give effect to derivative transactions.

Unconventional resource development. A development in which the targeted reservoirs generally fall into three categories: (1) tight sands, (2) coal beds, and (3) gas shales. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require stimulation treatments or other special recovery processes in order to produce economic flow rate.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas regardless of whether or not such acreage contains proved reserves.

Unearned acreage. The number of acres that has not yet been assigned, but may be developed per the terms of an agreement.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

ITEM 1A. RISK FACTORS

Risks Related to Our Business

Our independent registered public accounting firm has expressed substantial doubt about our ability to continue as a going concern.

The independent auditor’s report accompanying the audited consolidated financial statements included herein contains a statement expressing substantial doubt as to our ability to continue as a going concern. The factors contributing to this concern include our recurring losses from operations, stockholders’ (deficit) equity, and inability to generate sufficient cash flow to meet our obligations and sustain our operations. Please read Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.” Unless QRCP is able to sell additional assets, restructure its indebtedness, issue equity securities and/or complete some other strategic transaction, we may be forced to make a bankruptcy filing or take other actions that could have a material adverse effect on our business, the price of our common stock and our results of operations. Furthermore, the presence of this concern may have an adverse impact on our relationship with third parties with whom we do business, including our customers, vendors and employees and could make it more challenging for us to raise additional financing or refinance our existing indebtedness.

QRCP’s potential sources of revenue and cash flows consist almost exclusively of distributions from Quest Energy and Quest Midstream, neither of which is expected to pay distributions in 2009 and as a result, we do not expect QRCP to be able to meet its cash disbursement obligations unless it engages in transactions outside the ordinary course of business.

QRCP’s potential sources of revenue and cash flows consist almost exclusively of distributions from Quest Energy and Quest Midstream on the partnership interests it owns. We do not expect either Quest Energy or Quest Midstream to pay any distributions to their unitholders in 2009 and are unable to estimate at this time when such distributions may be resumed.

In October and November of 2008, QRCP’s credit agreement and the credit agreement for each of Quest Energy and Quest Midstream were amended. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Agreements.” The amended terms of the credit agreements restrict the ability of Quest Energy and Quest Midstream to pay distributions, among other things. Even if they do not pay distributions, the Company and all other unitholders may be liable for taxes on their share of each of Quest Energy and Quest Midstream’s taxable income. As a result, we currently anticipate that QRCP will not be able to meet its cash disbursement obligations after August 31, 2009, unless QRCP is able to restructure its debt obligations, issue equity securities and/or sell additional assets, in which case there can still be no assurances that QRCP will be able to avoid bankruptcy or the liquidation of its assets.

Quest Energy’s credit agreements allow the payment of distributions only on its common units and the general partner units and only up to $0.40 per unit per quarter as long as the Second Lien Loan Agreement has not been paid in full. Since the majority of the units the Company owns in Quest Energy are subordinated units, Quest Energy is only permitted to pay distributions on approximately one-third of the interests the Company owns, which significantly reduces what was previously anticipated in cash flows. Furthermore, after giving effect to each quarterly distribution, Quest Energy must be in compliance with certain financial covenants which require its Available Liquidity (as defined in each of its credit agreements) to be no less than $14 million at March 31, 2009 and no less than $20 million at June 30, 2009.

Quest Midstream’s credit agreement prohibits the payment of distributions to its unitholders until the total leverage ratio is not greater than 4.0 to 1.0 after giving effect to each quarterly distribution.

Quest Midstream did not pay any distributions on any of its units for the third or fourth quarter of 2008 or the first quarter of 2009 and Quest Energy only paid distributions on its common units and the general partner interest for the third quarter of 2008 and did not pay any distributions on any of its units for the fourth quarter of 2008 or the first quarter of 2009. There is no assurance that unpaid distributions on QRCP’s common units and general partner units will be paid or that any future distributions will be declared and paid on any units.

In addition, even if the credit agreements did not restrict the payment of distributions, Quest Energy and Quest Midstream may not have sufficient available cash each quarter to pay distributions to their unitholders. The amount of cash each of Quest Energy and Quest Midstream can distribute to its unitholders each quarter depends upon the amount of cash it generates from its operations, which fluctuate from quarter to quarter based on, among other things:


	•	the amount of gas transported by Quest Midstream in its gathering and transmission pipelines;

	•	the price of oil and gas;

	•	operating costs;

	•	prevailing economic conditions;

	•	timing and collectibility of receivables;

	•	the level of capital expenditures they make;

	•	their ability to make borrowings under their credit agreements to pay distributions;

	•	their debt service requirements and other liabilities;

	•	fluctuations in their working capital needs; and

	•	the amount of cash reserves established by their general partner for the proper conduct of their business.

We have identified significant and pervasive material weaknesses in our internal controls, which have and could continue to affect our ability to ensure timely and reliable financial reports and the ability of our auditors to attest to the effectiveness of our internal controls.

During management’s review of our internal controls as of December 31, 2008, control deficiencies that constituted material weaknesses related to the following items were identified:


	•	We did not maintain an effective control environment. The control environment, which is the responsibility of senior management, sets the tone of the organization, influences the control consciousness of its people, and is the foundation for all other components of internal control over financial reporting.

	•	We did not maintain effective monitoring controls to determine the adequacy of our internal control over financial reporting and related policies and procedures.

	•	We did not establish and maintain effective controls over certain of our period-end financial close and reporting processes, including the preparation and review of financial statements and schedules and journal entries.

	•	We did not establish and maintain effective controls to ensure the correct application of generally accepted accounting principles in the United States of America (“GAAP”) related to derivative instruments.

	•	We did not establish and maintain effective controls to ensure completeness and accuracy of stock compensation costs.

	•	We did not establish and maintain effective controls to ensure completeness and accuracy of depreciation, depletion and amortization expense.

	•	We did not establish and maintain effective controls to ensure the accuracy and application of GAAP related to the capitalization of costs related to oil and gas properties and the required evaluation of impairment of such costs.

	•	We did not establish and maintain effective controls to adequately segregate the duties over cash management.

These material weaknesses resulted in the misstatement of our annual and interim consolidated financial statements as of and for the years ended December 31, 2007, 2006 and 2005, the seven months ended December 31, 2004 and the fiscal year ended May 31, 2004 (including the interim periods within those periods) and 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.

Based on management’s evaluation, because of the material weaknesses described above, management has concluded that our internal control over financial reporting was not effective as of December 31, 2008. Our independent registered public accounting firm, UHY LLP, has audited management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2008, and their report appears in this Annual Report on Form 10-K.

While we have taken certain actions to address the deficiencies identified, additional measures will be necessary and these measures, along with other measures we expect to take to improve our internal controls over financial reporting, may not be sufficient to address the deficiencies identified or ensure that our internal control over financial reporting is effective. If we are unable to provide reliable and timely financial external reports, our business and prospects could suffer material adverse effects. In addition, we may in the future identify further material weaknesses or significant deficiencies in our internal control over financial reporting.

Events of default are anticipated under the QRCP credit agreement, which could expose our assets to foreclosure or other collection efforts.

Events of default have recently occurred under our QRCP credit agreement. The QRCP credit agreement contains both financial and ratio covenants. Due to the cancellation of distributions by QELP and QMLP, the decline in oil and gas prices and the decline in the fair market value of the units in QELP and QMLP that it owns, QRCP was not in compliance with all of its financial and ratio covenants as of December 31, 2008 and March 31, 2009. On May 29, 2009, QRCP obtained a waiver of these defaults from the QRCP lender. We do not expect that QRCP will be in compliance with all of its financial and ratio covenants for the remainder of 2009 therefore it may be required to obtain additional waivers or its lender may foreclose on its assets.

QRCP is required to maintain as of the end of each quarter, an Interest Coverage Ratio of not less than 2.5 to 1.0 and a Leverage Ratio of no more than 2.0 to 1.0. As a result of the suspension of the distributions to QRCP from Quest Energy and Quest Midstream discussed above, QRCP was not in compliance with these financial covenants as of December 31, 2008 and March 31, 2009. On May 29, 2009, QRCP obtained a waiver of these defaults from QRCP’s lenders. QRCP does not anticipate that it will be in compliance with these financial covenants and ratios at any time in the foreseeable future. QRCP is also required to make quarterly principal payments of $1.5 million. QRCP has prepaid the quarterly principal payments through and including June 30, 2009 and its next quarterly principal payment is due September 30, 2009. QRCP currently does anticipate being able to make this payment. QRCP’s credit agreement limits the amount that can be outstanding under its term loan to an amount that is equal to (i) 50% of the market value of the common and subordinated units of Quest Energy and Quest Midstream that QRCP has pledged to the lenders and (ii) the value of the oil and gas properties that QRCP has pledged to the lenders. QRCP is required to make a mandatory prepayment equal to any such excess amount outstanding. On May 29, 2009, QRCP obtained a waiver of this mandatory prepayment for the quarters ended December 31, 2008, March 31, 2009 and June 30, 2009. If a deficiency exists after June 30, 2009 that is not waived by QRCP’s lenders, QRCP will be required to sell assets, issue additional equity securities or refinance its credit agreement in order to cure such deficiency, none of which may be possible. Additionally, if the lenders’ exposure under letters of credit exceeds this amount after all borrowings under the credit agreements have been repaid, QRCP will be required to provide additional cash collateral which it may not have.

The QELP borrowing base under its first lien credit agreement could be redetermined to an amount that creates a deficiency that QELP does not have the ability to pay.

Quest Energy is required to be in compliance as of the end of each quarter, with certain financial ratios. Quest Energy is not anticipated to be in compliance with its Total Reserve Leverage Ratio as of June 30, 2009 in light of the significantly reduced capital expenditure program and low natural gas prices or in future periods if conditions do not change. In addition, Quest Energy is required to have Available Liquidity of $14 million and $20 million as of March 31, 2009 and June 30, 2009, respectively. Quest Energy may not be in compliance with this covenant as of June 30, 2009. Quest Energy’s credit facility limits the amount it can borrow to a borrowing base amount, determined by the lenders in their sole discretion. Outstanding borrowings in excess of the borrowing base will be required to be repaid (1) in four equal monthly installments following receipt of notice of the new borrowing base or (2) immediately if the borrowing base is reduced in connection with a sale or disposition of certain properties in excess of 5% of the

borrowing base. The lead agent for QELP’s credit agreement initially proposed that QELP’s borrowing base be reduced, as part of the redetermination being made in connection with the delivery of its year-end reserve report to its lenders, by approximately $50 million to $140 million. Quest Energy is currently pursuing various alternatives, including entering into additional commodity derivative contracts and/or repricing certain existing commodity derivative contracts in order to reduce the borrowing base deficiency. There can be no assurance that such efforts will be successful or that Quest Energy will be able to repay any remaining amount of the deficiency in accordance with the terms of its revolving credit agreement.

The proposed new borrowing base of $140 million has not been approved by the required lenders under the QELP credit agreement. QELP and its lenders are in the process of negotiating the repricing of certain existing hedges and adding new hedges, in order to have the lead agent propose a new borrowing base that would consider such actions. The existing lenders under the first lien credit agreement will not enter into the required new hedges. However, they have agreed in principle to an amendment to the credit agreement which would allow for a major oil and gas company to be the hedge counterparty on such new hedges. In order to accomplish the inclusion of the major oil and gas company into the credit facility, which would allow them to rank pari passu with the existing lenders for their hedge position, the lenders need to execute an intercreditor agreement with the major oil and gas company and are currently negotiating that agreement.

QELP is not able to enter into new hedges and reprice its existing hedges until the amendment to the QELP credit agreement and the related intercreditor agreement between the major oil and gas company and the lenders under the QELP credit agreement are executed. There is no certainty that such amendment and agreement will be executed. Furthermore, QELP is at risk for product price movements that would cause the repricing of existing hedges and adding QELP’s desired new hedges, to no longer satisfy the currently proposed deficiency.

If either the amendment and intercreditor agreement are not executed or the product price environment when such agreement is executed does not allow QELP to satisfy the proposed deficiency, QELP would likely enter a default condition under the first lien credit facility. Such default could lead to foreclosure or other collection efforts.

Additionally, if the lenders’ exposure under letters of credit exceeds this amount after all borrowings under the credit agreements have been repaid, Quest Energy will be required to provide additional cash collateral.

A default under the QELP first lien credit agreement would cause a cross default under the QELP second lien credit agreement.

Under the terms of Quest Energy’s second lien credit agreement, Quest Energy is required to make quarterly payments of $3.8 million. The next payment is due August 15, 2009. The balance remaining, after such payment of $29.8 million, is due on September 30, 2009. Due to the likely principal payments required to be made on its revolving credit facility in connection with the borrowing base redetermination, no assurance can be given that Quest Energy will be able to repay such amount in accordance with the terms of its second lien credit agreement.

A default under QELP’s first lien credit agreement would cause a default under the second lien credit agreement, which could cause payment acceleration. If payment under the second lien credit agreement were accelerated, payment under the first lien credit agreement would be accelerated. Such acceleration of payments could lead to foreclosure, other collection efforts, or bankruptcy of QELP.

The definitive agreement for Recombination, if entered into, is expected to be subject to closing conditions that could result in the completion of the Recombination being delayed or not consummated, which could lead to liquidation or bankruptcy.

It is expected that if definitive documentation is executed, completion of the Recombination will be conditioned upon the satisfaction of closing conditions, including approval of a definitive merger agreement by the Company’s stockholders and Quest Energy’s and Quest Midstream’s unitholders. The required conditions to closing may not be satisfied in a timely manner, if at all, or, if permissible, waived, and the Recombination may not be consummated. Failure to consummate the Recombination could negatively impact the Company’s stock price, future business and operations, and financial condition. Any delay in the consummation of the Recombination or

any uncertainty about the consummation of the Recombination may lead to liquidation or bankruptcy and may adversely affect our future business, growth, revenue and results of operations.

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

The Company’s stockholders and Quest Energy’s and Quest Midstream’s unitholders may not approve the matters relating to the Recombination, if presented to them. If the definitive agreement for the Recombination is not agreed to or if the Recombination is not completed for any reason, we could be subject to several risks including the following:


	•	the diversion of management’s attention directed toward the Recombination and other affirmative and negative covenants in the definitive merger agreement that may restrict our business;

	•	the failure to pursue other beneficial opportunities as a result of management’s focus on the Recombination without realizing any of the anticipated benefits of the Recombination;

	•	the market price of the Company’s common stock may decline to the extent that the current market price reflects a market assumption that the Recombination will be completed; and

	•	incurring substantial transaction costs related to the Recombination, such as investment banking, legal and accounting fees, printing expenses and other related charges that must be paid even if the Recombination is not completed.

The realization of any of these risks may materially adversely affect our business, financial results, and financial condition.

The current financial crisis and economic conditions may have a material adverse impact on our business and financial condition that we cannot predict.

The economic conditions in the United States and throughout the world have deteriorated. Since the second half of 2008, global financial markets have been experiencing a period of unprecedented turmoil and upheaval characterized by extreme volatility and declines in prices of securities, diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse or sale of financial institutions and an unprecedented level of intervention from the U.S. federal government and other governments. In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide any new funding.

A continuation of the economic crisis could result in further reduced demand for oil and natural gas and keep downward pressure on the prices for oil and natural gas, which have fallen dramatically since reaching historic highs in July 2008. These price declines have negatively impacted our revenues and cash flows. Although we cannot predict the impacts on us of the deteriorating economic conditions, they could materially adversely affect our business and financial condition. For example:


	•	our ability to obtain credit and access the capital markets has been and may continue to be restricted at a time when we would need to raise capital for our business, including for exploration or development of our reserves;

	•	our hedging arrangements could become ineffective if our counterparties are unable to perform their obligations or seek bankruptcy;

	•	the values we are able to realize in asset sales or other transactions we engage in to raise capital may be reduced, thus making these transactions more difficult to consummate and less economic; and


	•	the demand for oil and natural gas may decline due to deteriorating economic conditions, which could adversely affect our business, financial condition or results of operations.

Due to these factors, we cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or if funding is available only on unfavorable terms, we may be unable to meet our obligations as they come due or be required to post collateral to support our obligations, or we may be unable to implement our development plans, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues, results of operations, or financial condition.

Energy prices are very volatile, and if commodity prices remain low or continue to decline for a temporary or prolonged period, our revenues, profitability and cash flows will decline. A sustained or further decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The current global credit and economic environment has resulted in significantly lower oil and natural gas prices. The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities, and therefore their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on a variety of additional factors that are beyond our control, such as:


	•	the domestic and foreign supply of and demand for oil and natural gas;

	•	the price and level of foreign imports of oil and natural gas;

	•	the level of consumer product demand;

	•	weather conditions;

	•	overall domestic and global economic conditions;

	•	political and economic conditions in oil and gas producing countries, including embargoes and continued hostilities in the Middle East and other sustained military campaigns, acts of terrorism or sabotage;

	•	actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;

	•	the impact of the U.S. dollar exchange rates on oil and gas prices;

	•	technological advances affecting energy consumption;

	•	domestic and foreign governmental regulations and taxation;

	•	the impact of energy conservation efforts;

	•	the costs, proximity and capacity of gas pipelines and other transportation facilities; and

	•	the price and availability of alternative fuels.

In the past, the prices of gas have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2008, the near month NYMEX natural gas futures price ranged from a high of $13.58 per Mmbtu to a low of $5.29 per Mmbtu.

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


	•	negatively impact the value of our reserves because declines in oil and natural gas prices would reduce the amount of oil and natural gas we can produce economically;


	•	reduce the amount of cash flow available for capital expenditures; and

	•	limit our ability to borrow money or raise additional capital.

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

Lower gas prices may not only decrease our revenues, profitability and cash flows, but also reduce the amount of oil and gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. Substantial decreases in oil and gas prices would render a significant number of our planned exploration and development projects uneconomic. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil or gas properties for impairments. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and may, therefore, require a write-down of such carrying value. For example, for the year ended December 31, 2008, we had an impairment charge of $298.9 million. Due to a further decline in natural gas prices between December 31, 2008 and March 31, 2009, we will incur an additional impairment charge of approximately $75 million to $95 million for the quarter ended March 31, 2009. We may incur further impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our credit agreements.

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

Producing oil and gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. CBM production generally declines at a shallow rate after initial increases in production as a consequence of the dewatering process. Our future oil and gas reserves, production, cash flow and ability to make distributions depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations. Factors that may hinder our ability to acquire additional reserves include competition, access to capital, prevailing gas prices and attractiveness of properties for sale. Because of our financial condition, we will not be able to replace in 2009 the reserves we expect to produce in 2009.

As of December 31, 2008, our proved reserve-to-production ratio was 7.8 years. Because this ratio includes our proved undeveloped reserves, we expect that this ratio will not increase even if those proved undeveloped reserves are developed and the wells produce as expected. The proved reserve-to-production ratio reflected in our reserve report as of December 31, 2008 will change if production from our existing wells declines in a different manner than we have estimated and can change when we drill additional wells, make acquisitions and under other circumstances.

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

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


	•	changes in our reserves;

	•	changes in oil and gas prices;

	•	changes in labor and drilling costs;


	•	our ability to acquire, locate and produce reserves;

	•	changes in leasehold acquisition costs; and

	•	government regulations relating to safety and the environment.

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


	•	our proved reserves;

	•	the level of oil and gas we are able to produce from existing wells;

	•	the prices at which our oil and gas is sold; and

	•	our ability to acquire, locate and produce new reserves.

Historically, we have financed these expenditures primarily with cash generated by operations and proceeds from bank borrowings and equity financings. If our revenues or borrowing base decreases, which is expected, as a result of lower oil and natural gas prices, operating difficulties or declines in reserves, we may have limited ability to expend the capital necessary to undertake or complete future drilling programs. Additional debt or equity financing or cash generated by operations may not be available to meet these requirements. Due to the current low prices for oil and gas and the restrictions in the capital markets due to the global financial crisis, we anticipate that we will not have any significant amounts available during 2009 for capital expenditures.

We face the risks of leverage.

As of December 31, 2008, QRCP had borrowed $29 million, Quest Energy had borrowed $230.2 million, and Quest Midstream had borrowed $128 million under their respective credit agreements. We anticipate that we may in the future incur additional debt for financing our growth. Our ability to borrow funds will depend upon a number of factors, including the condition of the financial markets. In fact, during 2008, availability of credit became severely restricted. Under certain circumstances, the use of leverage may provide a higher return to you on your investment, but will also create a greater risk of loss to you than if we did not borrow. The risk of loss in such circumstances is increased because we would be obligated to meet fixed payment obligations on specified dates regardless of our revenue. If we do not make our debt service payments when due, we may sustain the loss of our equity investment in any of our assets securing such debt, upon the foreclosure on such debt by a secured lender. The interest payable on our debt varies with the movement of interest rates charged by financial institutions. An increase in our borrowing costs due to a rise in interest rates in the market may reduce the amount of income and cash available for the payment of dividends to the holders of our common stock.

Our future level of debt could have important consequences to us, including the following:


	•	our ability to obtain additional debt or equity financing, if necessary, for drilling, expansion, working capital and other business needs may be impaired or such financing may not be available on favorable terms;

	•	a substantial decrease in our revenues as a result of lower oil and natural gas prices, decreased production or other factors could make it difficult for us to pay our liabilities or remain in compliance with the covenants in our credit agreements. Any failure by us to meet these obligations could result in litigation, non-performance by contract counterparties or bankruptcy;

	•	our funds available for operations and future business opportunities will be reduced by that portion of our cash flow required to make interest payments on our debt;

	•	we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

	•	our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying business activities, acquisitions,

investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness or seeking additional equity capital or bankruptcy protection. We may not be able to affect any of these remedies on satisfactory terms or at all.

Our credit agreements have substantial restrictions and financial covenants that may restrict our business and financing activities.

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


	•	incur indebtedness;

	•	grant liens;

	•	make distributions on or redeem or repurchase equity interests;

	•	make certain acquisitions and investments, loans or advances;

	•	lease equipment;

	•	enter into a merger, consolidation or sale of assets;

	•	dispose of property;

	•	enter into hedging arrangements with certain counterparties;

	•	limit the use of loan proceeds;

	•	make capital expenditures above specified amounts; and

	•	enter into transactions with affiliates.

We are also required to comply with certain financial covenants and ratios. In the past, we have not satisfied all of the financial covenants and ratios contained in our credit facilities. In January 2005, we determined that we were not in compliance with the leverage and interest coverage ratios under a prior secured credit agreement and, in connection with a February 2005 amendment to such credit agreement, we were unable to drill any additional wells until our gross daily production reached certain levels. We were unable to reach these production goals without the drilling of additional wells and, in the fourth quarter of 2005, we undertook a significant recapitalization that included a private placement of our common stock and the refinancing of our credit facilities. For the quarter ended March 31, 2007, QRCP’s total debt to EBITDA ratio was 4.77 to 1.0, which exceeded the permitted maximum total debt to EBITDA ratio of 4.5 to 1.0 under its credit facilities. We obtained a waiver of this default from QRCP’s lenders. We refinanced QRCP’s credit facilities in November 2007. In October 2008, we obtained waivers of any defaults or potential defaults under the credit agreements of QRCP, Quest Energy and Quest Midstream related to or arising out of the internal investigation and our not promptly settling intercompany accounts. The current credit agreements for QRCP, Quest Midstream and Quest Energy each contain financial covenants. QRCP was not in compliance with all of these covenants as of December 31, 2008 and March 31, 2009 and we do not expect that QRCP and Quest Energy will be in compliance with all of these covenants for the remainder of 2009. See “— Risks Related to Our Business — Events of default are anticipated under the QRCP credit agreement, which could expose our assets to foreclosure or other collection efforts.” QRCP has obtained a waiver of these defaults from its lenders and we are currently in the process of seeking waivers from QRCP’s and QELP’s lenders with respect to anticipated defaults and to restructure their required principal payments; however, there can be no assurance that we will be successful in obtaining such waivers or restructuring such principal payments.

Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by our results of operations and financial conditions and events or circumstances beyond our control. If market or other economic conditions do not improve, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit agreements, a significant portion of our indebtedness may become immediately due and payable, the interest rates on our credit agreements may increase and the lenders’

commitment, if any, to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments.

An increase in interest rates will cause our debt service obligations to increase.

Borrowings under our credit agreements bear interest at floating rates. The rates are subject to adjustment based on fluctuations in the London Interbank Offered Rate (“LIBOR”) and RBC’s base rate. An increase in the interest rates associated with our floating-rate debt would increase our debt service costs and affect our results of operations and cash flow. In addition, an increase in our interest expense could adversely affect our future ability to obtain financing or materially increase the cost of any additional financing.

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

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

U.S. government and internal investigations could affect our results of operations.

We are currently involved in government and internal investigations involving various of our operations. As discussed in the Explanatory Note immediately preceding Part I of this Annual Report on Form 10-K, an inquiry and investigation initiated by the Oklahoma Department of Securities revealed questionable Transfers of funds belonging to the Company to an entity controlled by our former chief executive officer. The Oklahoma Department of Securities has filed lawsuits against our former chief executive officer, former chief financial officer and former purchasing manager, and the Oklahoma Department of Securities, the Federal Bureau of Investigation, the Department of Justice, the Securities and Exchange Commission, the Internal Revenue Service and other government agencies are currently conducting investigations related to the Transfers and these individuals.

The joint special committee retained independent legal counsel to conduct the investigation and to interact with various government agencies, including the Oklahoma Department of Securities, the Federal Bureau of Investigation, the Department of Justice, the Securities and Exchange Commission, the Internal Revenue Service and other government agencies.

These investigations are ongoing, and we cannot anticipate the timing, outcome or possible impact of these investigations, financial or otherwise. The governmental agencies involved in these investigations have a broad range of civil and criminal penalties they may seek to impose against corporations and individuals for violations of securities laws, and other federal and state statutes, including, but not limited to, injunctive relief, disgorgement, fines, penalties and modifications to business practices and compliance programs. In recent years, these agencies and authorities have entered into agreements with, and obtained a broad range of penalties against, several public corporations and individuals in similar investigations, under which civil and criminal penalties were imposed, including in some cases multi-million dollar fines and other penalties and sanctions. Any injunctive relief, disgorgement, fines, penalties, sanctions or imposed modifications to business practices resulting from these investigations could adversely affect our results of operations and our ability to continue as a going concern.

There is a significant delay between the time QELP drills and completes a CBM well and when the well reaches peak production. As a result, there will be a significant lag time between when QELP expends capital expenditures and when QELP will begin to recognize significant cash flow from those expenditures.

Our general production profile for a CBM well averages an initial 5-10 Mcf/d (net), steadily rising for the first twelve months while water is pumped off and the formation pressure is lowered until the wells reach peak production (an average of 50-55 Mcf/d (net)). In addition, there could be significant delays between the time a well is drilled and completed and when the well is connected to a gas gathering system. This delay between the time when QELP expends capital expenditures to drill and complete a well and when QELP will begin to recognize significant cash flow from those expenditures may adversely affect QELP’s cash flow from operations.

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

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


	•	a constant level of future oil and gas prices;

	•	geological conditions;

	•	production levels;

	•	capital expenditures;

	•	operating and development costs;

	•	the effects of governmental regulations and taxation; and

	•	availability of funds.

If these assumptions prove to be incorrect, our estimates of proved reserves, the economically recoverable quantities of oil and gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly.

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

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


	•	the actual prices we receive for oil and gas;

	•	our actual operating costs in producing oil and gas;

	•	the amount and timing of actual production;

	•	the amount and timing of our capital expenditures;

	•	supply of and demand for oil and gas; and

	•	changes in governmental regulations or taxation.

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

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

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. The cost of drilling, completing and operating a well is often uncertain, and cost factors, as

well as the market price of oil and natural gas, can adversely affect the economics of a well. Furthermore, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:


	•	high costs, shortages or delivery delays of drilling rigs, equipment, labor or other services;

	•	adverse weather conditions;

	•	difficulty disposing of water produced as part of the coal bed methane production process;

	•	equipment failures or accidents;

	•	title problems;

	•	pipe or cement failures or casing collapses;

	•	compliance with environmental and other governmental requirements;

	•	environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;

	•	lost or damaged oilfield drilling and service tools;

	•	loss of drilling fluid circulation;

	•	unexpected operational events and drilling conditions;

	•	increased risk of wellbore instability due to horizontal drilling;

	•	unusual or unexpected geological formations;

	•	natural disasters, such as fires;

	•	blowouts, surface craterings and explosions; and

	•	uncontrollable flows of oil, gas or well fluids.

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

We have limited experience in drilling wells to the Marcellus Shale and less information regarding reserves and decline rates in the Marcellus Shale than in the Cherokee Basin. Wells drilled to the Marcellus Shale are deeper, more expensive and more susceptible to mechanical problems in drilling and completing than wells in the Cherokee Basin.

We have limited experience in drilling wells in the Marcellus Shale reservoir. As of May 1, 2009, we have drilled two vertical and two horizontal gross wells to the Marcellus Shale. Other operators in the Appalachian Basin also have limited experience in the drilling of Marcellus Shale wells. As a result, we have much less information with respect to the ultimate recoverable reserves and the production decline rate in the Marcellus Shale than we have in the Cherokee Basin. The wells to be drilled in the Marcellus Shale will be drilled deeper than in the Cherokee Basin and some may be horizontal wells, which makes the Marcellus Shale wells more expensive to drill and complete. The wells, especially any horizontal wells, will also be more susceptible than those in the Cherokee Basin to mechanical problems associated with the drilling and completion of the wells, such as casing collapse and lost equipment in the wellbore. The fracturing of the Marcellus Shale will be more extensive and complicated than fracturing the geological formations in the Cherokee Basin and requires greater volumes of water than conventional gas wells. The management of water and treatment of produced water from Marcellus Shale wells may be more costly than the management of produced water from other geologic formations.

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

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

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


	•	a counterparty may not perform its obligation under the applicable derivative instrument;

	•	there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and

	•	the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures.

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

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

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

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

We may have difficulty managing growth in our business.

Because of the relatively small size of our business, growth in accordance with our long-term business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As we increase our activities and the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to

upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the recruitment and retention of required personnel could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

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

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


	•	damage to wells, pipelines, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;

	•	inadvertent damage from construction, farm and utility equipment;

	•	leaks of gas or oil spills as a result of the malfunction of equipment or facilities;

	•	fires and explosions; and

	•	other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

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

In accordance with typical industry practice, we currently possess property, business interruption and general liability insurance at levels we believe are appropriate; however, insurance against all operational risk is not available to us. We are not fully insured against all risks, including drilling and completion risks that are generally not recoverable from third parties or insurance. We do not have property insurance on any of Quest Midstream’s underground pipeline systems that would cover damage to the pipelines. Pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets subsequent to the terrorist attacks on September 11, 2001 and the hurricanes in 2005 have made it more difficult for us to obtain certain types of coverage. There can be no assurance that we will be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition and results of operations.

We have been named a defendant in a number of securities class action lawsuits and stockholder derivative lawsuits. These, and potential similar or related litigation, could result in significant expenses, monetary damages, penalties or injunctive relief against us that could significantly reduce our earnings and cash flows and harm our business.

As discussed in Items 1. and 2. “Business and Properties — Recent Developments — Internal Investigation; Restatements and Reaudits,” we conducted an internal investigation into the Transfers of funds effected by our former chief executive officer that totaled approximately $10 million. During the course of the investigation, management identified material errors in our previously issued consolidated financial statements and has restated our previously filed consolidated financial statements. The investigation and restatement have exposed us to risks and expenses associated with litigation and government investigations. Certain putative class action lawsuits and stockholder derivative lawsuits have been asserted against QRCP, Quest Energy, Quest Energy GP and certain of their current and former officers and directors. See Item 3. “Legal Proceedings” for a discussion of the lawsuits. No assurance can be given regarding the outcome of such litigation, and additional claims may arise. The investigation

and restatement and any settlements, payment of claims and other costs could lead to substantial expenses, may materially affect our cash balance and cash flows from operations and may divert management’s attention from our business. In addition, we are a party to indemnification agreements under which we are required to indemnify and advance defense costs to our current and certain of our former directors and officers. Furthermore, considerable legal, accounting and other professional services expenses related to these matters have been incurred to date and significant expenditures may continue to be incurred in the future. We could be required to pay damages and might face remedies that could harm our business, financial condition and results of operations. While we maintain directors and officers liability insurance, there can be no assurance that the proceeds of this insurance will be available with respect to all or part of any damages, costs or expenses that we may incur in connection with the class action and derivative stockholder lawsuits.

We may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental and operational safety regulations or an accidental release of hazardous substances into the environment.

We may incur significant costs and liabilities as a result of environmental, health and safety requirements applicable to our oil and gas exploration, development and production activities. These costs and liabilities could arise under a wide range of federal, state and local environmental, health and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations.

Our operations are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example, (1) the federal CAA and comparable state laws and regulations that impose obligations related to air emissions, (2) the federal RCRA and comparable state laws that impose requirements for the handling, storage, treatment or discharge of waste from our facilities, (3) the federal CERCLA, also known as “Superfund,” and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent waste for disposal and (4) the federal CWA and analogous state laws and regulations that impose detailed permit requirements and strict controls regarding the discharge of pollutants into waters of the United States and state waters. Failure to comply with these laws and regulations or newly adopted laws or regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations. Certain environmental regulations, including CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of oil and natural gas, air emissions related to our operations, and historical industry operations and waste disposal practices. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover these costs from insurance.

We may face unanticipated water disposal costs.

We are subject to regulation that restricts our ability to discharge water produced as part of our gas production operations. Productive zones frequently contain water that must be removed in order for the gas to detach produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether

we can produce gas in commercial quantities. The produced water must be transported from the lease and injected into disposal wells. The availability of disposal wells with sufficient capacity to receive all of the water produced from our wells may affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability.

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


	•	we cannot obtain future permits from applicable regulatory agencies;

	•	water of lesser quality or requiring additional treatment is produced;

	•	our wells produce excess water;

	•	new laws and regulations require water to be disposed in a different manner; or

	•	costs to transport the produced water to the disposal wells increase.

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

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

Quest Energy depends on one customer for sales of its natural gas. A reduction by this customer in the volumes of gas it purchases from Quest Energy could indirectly result in a substantial decline in our revenues and net income.

During the year ended December 31, 2008, Quest Energy sold approximately 98% of its natural gas produced in the Cherokee Basin to ONEOK Energy Marketing and Trading Company (“ONEOK”) under a sale and purchase contract, which has an indefinite term but may be terminated by either party on 30 days’ notice, other than with respect to pending transactions, or less following an event of default. If ONEOK was to reduce the volume of gas it purchases under this agreement, Quest Energy’s revenue and cash flow will decline to the extent it is not able to find new customers for the natural gas it sells.

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

In the Cherokee Basin, as of December 31, 2008, we held oil and gas leases on approximately 557,603 net acres, of which 150,922 net acres are undeveloped and not currently held by production. Unless we establish commercial production on the properties subject to these leases during their term, these leases will expire. Leases covering approximately 29,760 net acres are scheduled to expire before December 31, 2009 and an additional 77,149 net acres are scheduled to expire before December 31, 2010. If our leases expire, we will lose our right to develop the related properties. We typically acquire a three-year primary term when the original lease is acquired, with an option to extend the term for up to three additional years, if the primary three-year term reaches expiration without a well being drilled to establish production for holding the lease.

Subsequent to the divestiture of the Lycoming County, Pennsylvania properties on February 13, 2009, we held oil and gas leases and development rights, by virtue of farm-out agreements or similar mechanisms, on 31,490 net acres in the Appalachian Basin that are still within their original lease or agreement term and are not earned or are

not held by production. Unless we establish commercial production on the properties, or fulfill the requirements specified by the various agreements, during the prescribed time periods, these leases or agreements will expire. Leases or agreements covering approximately 3,600 net acres are scheduled to expire before December 31, 2009 and an additional approximately 6,000 net acres are scheduled to expire before December 31, 2010. Of this acreage, approximately 8,200 net acres can be maintained and held beyond December 31, 2010 by drilling five wells before December 31, 2009 and an additional six wells before December 31, 2010.

Because of our financial condition, we do not expect to be able to meet the drilling and payment obligations to earn or maintain all of this leasehold acreage.

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

Our management has specifically identified drilling locations for our future multi-year drilling activities on our existing acreage. We have identified, as of December 31, 2008, approximately 292 gross proved undeveloped drilling locations and approximately 2,034 additional gross potential drilling locations in the Cherokee Basin and approximately 22 gross proved undeveloped drilling locations and approximately 435 additional gross potential drilling locations in the Appalachian Basin. These identified drilling locations represent a significant part of our future long-term development drilling program. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, gas prices, costs and drilling results. In addition, no proved reserves are assigned to any of the approximately 2,034 Cherokee Basin and 435 Appalachian Basin potential drilling locations we have identified and therefore, there may exist greater uncertainty with respect to the likelihood of drilling and completing successful commercial wells at these potential drilling locations. Our final determination of whether to drill any of these drilling locations will be dependent upon the factors described above, our current financial condition, our ability to obtain additional capital as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, it is unlikely that all of the numerous drilling locations we have identified will be drilled within the timeframe specified in the reserve report or will ever be drilled, and we do not know if we will be able to produce gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could have a significant adverse effect on our financial condition and results of operations.

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

If an examination of the title history of a property reveals that an oil or gas lease has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would be worthless. In such an instance, the amount paid for such oil or gas lease or leases would be lost. It is our practice, in acquiring oil and gas leases, or undivided interests in oil and gas leases, not to incur the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.

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

On a small percentage of our acreage (less than 1.0%), the land owner in the past transferred the rights to the coal underlying their land to a third party. With respect to those properties we have obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying those lands. In Oklahoma and Kansas, the law is unsettled as to whether the owner of the gas rights or the coal rights is entitled to the CBM gas. We are currently

involved in litigation with the owner of the coal rights on these lands to determine who has the rights to the CBM gas. In the event that the courts were to determine that the owner of the coal rights is entitled to extract the CBM gas, we would lose these leases and the associated wells and reserves. In addition, we may be required to reimburse the owner of the coal rights for some of the gas produced from those wells.

A change in the jurisdictional characterization of some of Quest Midstream’s gathering assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of its gathering assets, which may indirectly cause our revenues to decline and operating expenses to increase.

Section 1(b) of the Natural Gas Act of 1938, or NGA, exempts natural gas gathering facilities from FERC jurisdiction. We believe that the facilities comprising Quest Midstream’s gathering system meet the traditional tests used by FERC to distinguish nonjurisdictional gathering facilities from jurisdictional transportation facilities, and that, as a result, the gathering system is not subject to FERC’s jurisdiction. However, FERC regulation still affects Quest Midstream’s gathering business and the markets for its natural gas. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, ratemaking, capacity release and market center promotion, indirectly affect Quest Midstream’s gathering business. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of regular litigation. The classification and regulation of some of Quest Midstream’s gathering facilities may be subject to change based on future determinations by FERC, the courts or Congress.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and complaint-based rate regulation. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. Quest Midstream’s gathering operations are currently limited to the States of Kansas and Oklahoma. Bluestem, a wholly owned subsidiary of Quest Midstream and the owner of the gathering system, is licensed as an operator of a natural gas gathering system with the KCC and is required to file periodic information reports with the KCC. Quest Midstream is not required to be licensed as an operator or to file reports in Oklahoma.

Third party producers on our Cherokee Basin gathering system have the ability to file complaints challenging the rates that Quest Midstream charges. The rates must be just, reasonable, not unjustly discriminatory and not duly preferential. If the KCC or the OCC, as applicable, were to determine that the rates charged to a complainant did not meet this standard, the KCC or the OCC, as applicable, would have the ability to adjust the rates with respect to the wells that were the subject of the complaint. Quest Midstream’s gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on Quest Midstream’s operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

The KPC Pipeline is subject to regulation by FERC, which could have an adverse impact on Quest Midstream’s ability to establish transportation rates that would allow it to recover the full cost of operating the KPC pipeline, including a reasonable return, which may affect Quest Midstream’s business and results of operations.

As an interstate natural gas pipeline, the KPC Pipeline is subject to regulation by FERC under the NGA. FERC’s regulation of interstate natural gas pipelines extends to such matters as:


	•	transportation of natural gas;

	•	rates, operating terms and conditions of service;


	•	the types of services KPC may offer to its customers;

	•	construction of new facilities;

	•	acquisition, extension or abandonment of services or facilities; accounting and recordkeeping;

	•	commercial relationships and communications with affiliated companies involved in certain aspects of the natural gas business; and

	•	the initiation and discontinuation of services.

KPC may only charge transportation rates that it has been authorized to charge by FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

The maximum recourse rates that it may charge for transportation services are established through FERC’s ratemaking process, and those recourse rates, as well as the terms and conditions of service, are set forth in KPC’s FERC-approved interstate tariff. Pipelines may also negotiate rates that are higher than the maximum recourse rates stated in their tariffs, provided such rates are filed with, and approved by, FERC. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint, proposed rate increases may be challenged by protest, and either may be challenged sua sponte by FERC. Any successful challenge against KPC’s rates could have an adverse impact on Quest Midstream’s revenues and ability to pay distributions.

Generally and absent settlement, the maximum filed recourse rates for interstate pipelines are based on the cost of service plus an approved return on equity, which may be determined through the use of a proxy group of similarly situated companies. Specifically, FERC uses a discounted cash flow model that incorporates the use of proxy groups to develop a range of reasonable returns earned on equity interests in companies with corresponding risks. FERC then assigns a rate of return on equity within that range to reflect specific risks of that pipeline when compared to the proxy group companies. Other key determinants in the ratemaking process are capital costs and costs of providing service, including an income tax allowance, and volume throughput and contractual capacity commitment assumptions.

We cannot give any assurance regarding the likely future regulations under which KPC will operate the KPC Pipeline or the effect such regulation could have on its business, financial condition, and results of operations. FERC periodically revises and refines its ratemaking and other policies in the context of rulemakings, generic proceedings, and pipeline-specific cases. FERC’s policies may also be modified when FERC decisions are subjected to judicial review. Changes to ratemaking policies may in turn affect the rates we may charge for transportation service. For example, on April 17, 2008, FERC issued a policy statement that, among other things, provides for the inclusion of master limited partnerships in the proxy groups it will use to decide the return on equity of natural gas pipelines. Once this policy is applied in individual rate cases, it may be subject to further review (including judicial review) and potential modification. The final resolution of this issue may reduce the rate of return KPC is allowed in future rate cases.

The outcome of certain rate cases involving FERC policy statements is uncertain and could affect KPC’s ability to include an income tax allowance in its cost of service based rates, which would in turn impact Quest Midstream’s revenues and ability to pay distributions.

In May 2005, FERC issued a policy statement permitting the inclusion of an income tax allowance in the cost of service-based rates of a pipeline organized as a tax pass-through entity to reflect actual or potential income tax liability on public utility income, if the pipeline proves that the ultimate owner of its interests has an actual or potential income tax liability on such income. In May 2007, the U.S. Court of Appeals for the D.C. Circuit issued a decision upholding the policy statement as applied to an individual pipeline. More recent proceedings at FERC have addressed a variety of implementation and application issues, for example, whether the recovery of an income tax allowance by a pipeline should be taken into consideration when establishing return on equity rates for the pipeline. The ultimate outcome of these proceedings, as well as future proceedings in which these types of issues will be adjudicated, could result in changes to FERC’s treatment of income tax allowances or related cost of service components. Depending upon how the policy statement on income tax allowances is applied in practice to pipelines

organized as pass through entities, these decisions might adversely affect Quest Midstream. Under FERC’s current income tax allowance policy, if the KPC Pipeline was to file a rate case or its rates were to otherwise become subject to review for justness and reasonableness before FERC, Quest Midstream would be required to demonstrate that the equity interest owners in the pipeline incur actual or potential income tax liability on their respective shares of partnership public utility income. If Quest Midstream is unable to do so, FERC could decide to reduce its rates from current levels. We can give no assurance that in the future FERC’s current income tax allowance policy or its application will not be changed.

We lack experience with and could be subject to penalties and fines if we fail to comply with FERC regulations.

Quest Midstream acquired the KPC Pipeline, which is its only FERC regulated asset, in November 2007. Given Quest Midstream’s limited experience with FERC regulated pipeline operations, and the complex and evolving nature of FERC regulation, it may incur significant costs related to compliance with FERC regulations. Should Quest Midstream fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines. Under the EP Act 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1,000,000 per day for each violation, to revoke existing certificate authority, and to order disgorgement of profits associated with any violation. Since enactment of the EP Act 2005, FERC has initiated a number of enforcement proceedings and issued penalties to various regulated entities, including other interstate natural gas pipelines.

Pipeline integrity programs and repairs may impose significant costs and liabilities.

Pursuant to the Pipeline Safety Improvement Act of 2002, the DOT has adopted regulations requiring pipeline operators to develop integrity management programs for intrastate and interstate natural gas and natural gas liquids pipelines located near high consequence areas, where a leak or rupture could do the most harm. The regulations require operators to:


	•	perform ongoing assessments of pipeline integrity;

	•	identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

	•	improve data collection, integration and analysis;

	•	repair and remediate the pipeline as necessary; and

	•	implement preventive and mitigating actions.

We currently estimate that Quest Midstream will incur costs of approximately $1.0 million through 2009 to complete the last year of the initial high consequence area integrity testing and $1.5 million in 2012 to implement pipeline integrity management program testing along certain segments of natural gas pipelines. We also estimate that Quest Midstream will incur costs of approximately $0.5 million through 2009 to complete the last year of a Stray Current Survey resulting from a 2004 DOT audit. These costs may be significantly higher and Quest Midstream’s cash available for distribution correspondingly reduced due to the following factors:


	•	Our estimate does not include the costs of repairs, remediation or preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial;

	•	Additional regulatory requirements that are enacted could significantly increase the amount of these expenditures;

	•	The actual implementation costs may be materially higher than we estimate because of increased industry-wide demand for contractors and service providers and the related increase in costs; or

	•	Failure to comply with DOT regulations and any corresponding deadlines, which could subject Quest Midstream to penalties and fines.

Growing our business by constructing new assets is subject to regulatory, political, legal and economic risks.

One of the ways Quest Midstream intends to grow its business in the long term is through the construction of new midstream assets.

The construction of additions or modifications to the Cherokee Basin gathering system and/or the KPC Pipeline, and the construction of new midstream assets, involve numerous operational, regulatory, environmental, political and legal risks beyond our control and may require the expenditure of significant amounts of capital. These potential risks include, among other things:


	•	inability to complete construction of these projects on schedule or at the budgeted cost due to the unavailability of required construction personnel or materials;

	•	failure to receive any material increases in revenues until the project is completed, even though Quest Midstream may have expended considerable funds during the construction phase, which may be prolonged;

	•	facilities may be constructed to capture anticipated future growth in production in a region in which such growth does not materialize;

	•	reliance on third party estimates of reserves in making a decision to construct facilities, which estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating reserves;

	•	inability to obtain rights-of-way to construct additional pipelines or the cost to do so may be uneconomical; and

	•	the construction of additions or modifications to the KPC Pipeline may require the issuance of certificates of public convenience and necessity from FERC, which may result in delays or increase costs.

If third party pipelines and other facilities interconnected to Quest Midstream’s natural gas pipelines become unavailable to transport or produce natural gas, its revenues and cash available for distribution could be adversely affected.

Quest Midstream depends upon third party pipelines and other facilities that provide delivery options to and from its pipelines and facilities for the benefit of its customers. Since Quest Midstream does not own or operate any of these pipelines or other facilities, their continuing operation is not within its control. If any of these third party pipelines and other facilities become unavailable to transport or produce natural gas, Quest Midstream’s revenues and cash available for distribution could be adversely affected.

Failure of the natural gas that Quest Midstream gathers on its gas gathering system to meet the specifications of interconnecting interstate pipelines could result in curtailments by the interstate pipelines.

Natural gas gathered on Quest Midstream’s gathering system is delivered into interstate pipelines. These interstate pipelines establish specifications for the natural gas that they are willing to accept, which include requirements such as hydrocarbon dewpoint, temperature, and foreign content including water, sulfur, carbon dioxide and hydrogen sulfide. These specifications vary by interstate pipeline. If the natural gas delivered from the gathering system fails to meet the specifications of a particular interstate pipeline that pipeline may refuse to accept all or a part of the natural gas scheduled for delivery to it. In those circumstances, Quest Midstream may be required to find alternative markets for that natural gas or to shut-in the producers of the non-conforming natural gas, potentially reducing its throughput volumes or revenues.

Quest Midstream’s interstate natural gas pipeline has recorded certain assets that may not be recoverable from its customers.

Accounting policies for FERC-regulated companies permit certain assets that result from the regulated ratemaking process to be recorded on our balance sheet that could not be recorded under GAAP for nonregulated entities. We consider factors such as regulatory changes and the impact of competition to determine the probability of future recovery of these assets. If Quest Midstream determines future recovery is no longer probable, it would be

required to write off the regulatory assets at that time, potentially reducing its revenues and cash available for distribution.

Reduction in firm reservation agreements and the demand for interruptible services could cause significant reductions in Quest Midstream’s revenues and operating results.

For the year ended December 31, 2008, approximately 63% of Quest Midstream’s firm contracted capacity on our KPC pipeline system was under long-term contracts (i.e., contracts with remaining terms longer than one year). A decision by customers upon the expiration of long-term agreements to substantially reduce or cease to ship volumes of natural gas on Quest Midstream’s KPC pipeline system could cause a significant decline in its revenues. Quest Midstream’s results of operations and cash available for distribution could also be adversely affected by decreased demand for interruptible services.

Operational limitations of the pipeline system could cause a significant decrease in Quest Midstream’s revenues and operating results.

During peak demand periods, failures of compression equipment or pipelines could limit KPC’s ability to meet firm commitments, which may limit its ability to collect reservation charges from its customers and, if so, could negatively impact Quest Midstream’s revenues and ability to make cash distributions.

Quest Midstream’s industry is highly competitive, and increased competitive pressures could adversely affect its business and operating results.

With respect to its Cherokee Basin gathering system, Quest Midstream may face competition in its efforts to obtain additional natural gas volumes from parties other than Quest Energy. Quest Midstream competes principally against other producers in the Cherokee Basin with natural gas gathering services. Its competitors may expand or construct gathering systems in the Cherokee Basin that would create additional competition for the services Quest Midstream provides to its customers.

With respect to the KPC Pipeline, Quest Midstream competes with other interstate and intrastate pipelines in the transportation of natural gas for transportation customers primarily on the basis of transportation rates, access to competitively priced supplies of natural gas, markets served by the pipelines, and the quality and reliability of transportation services. Major competitors include Southern Star Central Gas Pipeline, Kinder Morgan Interstate Gas Transmission’s Pony Express Pipeline and Panhandle Eastern Pipeline Company in the Kansas City market and Southern Star Pipeline, Peoples Natural Gas and Mid-Continent Market Center in the Wichita market.

Natural gas also competes with other forms of energy available to Quest Midstream’s customers, including electricity, coal, hydroelectric power, nuclear power and fuel oil. The impact of competition could be significantly increased as a result of factors that have the effect of significantly decreasing demand for natural gas in the markets served by Quest Midstream’s pipelines, such as competing or alternative forms of energy, adverse economic conditions, weather, higher fuel costs, and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.

Quest Midstream does not own all of the land on which its pipelines are located or on which it may seek to locate pipelines in the future, which could disrupt its operations and growth.

Quest Midstream does not own the land on which its pipelines have been constructed, but does have right-of-way and easement agreements from landowners and governmental agencies, some of which require annual payments to maintain the agreements and most of which have a perpetual term. New pipeline infrastructure construction may subject Quest Midstream to more onerous terms or to increased costs if the design of a pipeline requires redirecting. Such costs could have a material adverse effect on Quest Midstream’s business, results of operations and financial condition and ability to make cash distributions.

In addition, the construction of additions to the KPC Pipeline may require Quest Midstream to obtain new rights-of-way prior to constructing new pipelines. Quest Midstream may be unable to obtain such rights-of-way to expand the KPC Pipeline or capitalize on other attractive expansion opportunities. Additionally, it may become

more expensive to obtain new rights-of-way. If the cost of obtaining new rights-of-way increases, then Quest Midstream’s cash flows and its ability to make distributions could be adversely affected.

The revenues of Quest Midstream’s interstate pipeline business are generated under contracts that must be renegotiated periodically.

Substantially all of KPC Pipeline’s revenues are generated under contracts which expire periodically and must be renegotiated and extended or replaced. Quest Midstream’s contracts with Kansas Gas Service and Missouri Gas Energy represent commitments in the amount of approximately 144,000 Dth/d, of which approximately 55,000 Dth/d extend through October 2009, approximately 12,000 Dth/d extend through 2013, approximately 63,000 Dth/d extend through 2014, and approximately 14,000 Dth/d extend through 2017. If Quest Midstream is unable to extend or replace these contracts when they expire or renegotiate contract terms as favorable as the existing contracts, Quest Midstream could suffer a material reduction in revenues, earnings and cash flows. In particular, Quest Midstream’s ability to extend and replace contracts could be adversely affected by factors it cannot control, including:


	•	competition by other pipelines, including the change in rates or upstream supply of existing pipeline competitors, as well as the proposed construction by other companies of additional pipeline capacity in markets served by our interstate pipelines;

	•	changes in state regulation of local distribution companies, which may cause them to negotiate short-term contracts or turn back their capacity when their contracts expire;

	•	reduced demand and market conditions in the areas Quest Midstream serves;

	•	the availability of alternative energy sources or natural gas supply points; and

	•	regulatory actions.

Fluctuations in energy commodity prices could adversely affect Quest Midstream’s pipeline businesses.

Revenues generated by Quest Midstream’s transmission contracts depend, in part, on volumes and rates, both of which can be affected by the prices of natural gas. Increased prices could result in a reduction of the volumes transported by customers. Increased prices could also result in industrial plant shutdowns or load losses to competitive fuels as well as local distribution companies’ loss of customer base. The success of Quest Midstream’s transmission operations is subject to continued development of additional gas supplies to offset the natural decline from existing wells connected to its systems, which requires the development of additional oil and natural gas reserves and obtaining additional supplies from interconnecting pipelines on or near our systems. A decline in energy prices could cause a decrease in these development activities and could cause a decrease in the volume of reserves available for transmission through Quest Midstream’s systems. Pricing volatility may impact the value of under or over recoveries of retained natural gas and imbalances. If natural gas prices in the supply basins connected to Quest Midstream’s pipeline systems are higher than prices in other natural gas producing regions, its ability to compete with other transporters may be negatively impacted on a short-term basis, as well as with respect to long-term recontracting activities. Furthermore, fluctuations in pricing between supply sources and market areas could negatively impact Quest Midstream’s transportation revenues.

Our success, and the success of Quest Energy and Quest Midstream, depends on our key management personnel, the loss of any of whom could disrupt our respective businesses.

The success of our operations and activities is dependent to a significant extent on the efforts and abilities of our management. We share a large majority of our management and operational personnel with Quest Energy and Quest Midstream, which are similarly dependent on these management and personnel for their continued success. We have not obtained, and do not anticipate that we will obtain, “key man” insurance for any of our management. The loss of services of any of our key management personnel could have a material adverse effect on our business. These key management personnel provide services to two public companies (Quest Energy and QRCP), and a private company (Quest Midstream). As a result, there could be material competition for their time and effort. If the

key personnel do not devote significant time and effort to the management and operation of each of these businesses, our financial results may suffer.

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

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

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


	•	mistaken assumptions about reserves, future production, volumes, revenues and costs, including synergies;

	•	an inability to integrate successfully the businesses we acquire;

	•	a decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the acquisition;

	•	a significant increase in our interest expense or financial leverage if we incur additional debt to finance the acquisition;

	•	the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;

	•	an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;

	•	limitations on rights to indemnity from the seller;

	•	mistaken assumptions about the overall costs of equity or debt;

	•	the diversion of management’s and employees’ attention from other business concerns;

	•	the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges;

	•	unforeseen difficulties operating in new product areas or new geographic areas; and

	•	customer or key employee losses at the acquired businesses.

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

In addition, we may pursue acquisitions outside the Cherokee and Appalachian Basins. Because we currently operate substantially in the Cherokee and Appalachian Basins, we do not have the same level of experience in other basins. Consequently acquisitions in areas outside the Cherokee and Appalachian Basins may not allow us the same operational efficiencies we benefit from in those basins. In addition, acquisitions outside the Cherokee and Appalachian Basins will expose us to different operational risks due to potential differences, among others, in:


	•	geology;

	•	well economics;

	•	availability of third party services;

	•	transportation charges;


	•	content, quantity and quality of oil and gas produced;

	•	volume of waste water produced;

	•	state and local regulations and permit requirements; and

	•	production, severance, ad valorem and other taxes.

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

Risks Relating to Our Common Stock

We currently are not in compliance with NASDAQ’s continued listing requirements, and if our common stock is delisted, it could negatively impact the price of our common stock, our ability to access the capital markets and the liquidity of our common stock.

Our common stock is currently listed on the NASDAQ Global Market. To maintain our listing, we are required to maintain a minimum closing bid price of at least $1.00 per share for our common stock for 30 consecutive business days. Since October 2008, the bid price for our common stock has continuously closed below the minimum $1.00 per share; however, given the current extraordinary market conditions, NASDAQ has suspended enforcement of the minimum bid price requirement through July 19, 2009. As a result, if the closing bid price for our common stock is less than $1.00 for a period of 30 consecutive days after July 19, 2009, we may receive notification from NASDAQ that our common stock will be delisted from the NASDAQ Global Market, unless the stock closes at or above $1.00 per share for at least 10 consecutive days during the 180-day period following such notification.

Additionally, on November 19, 2008, we received a letter from the staff of NASDAQ indicating that, because of our failure to timely file our Form 10-Q for the quarter ended September 30, 2008, we no longer complied with the continued listing requirements set forth in NASDAQ Marketplace Rule 4310(c)(14) (now Rule 5250(c)(1)). As permitted by NASDAQ rules, we timely submitted a plan to NASDAQ staff to regain compliance on January 20, 2009. Following a review of this plan, NASDAQ staff granted us an extension until May 11, 2009 to file our Form 10-Q.

We did not file our Form 10-Q for the quarter ended September 30, 2008 on that date and on May 12, 2009, we received a Staff Determination from NASDAQ stating that our common stock is subject to delisting since we were not in compliance with the filing requirements for continued listing. We requested and were granted a hearing before the NASDAQ Panel to appeal the Staff Determination. The hearing is scheduled for June 11, 2009. The Panel has stayed the delisting of our common stock through such date to allow us additional time to file our delinquent periodic reports with the SEC. If we have not filed all of our delinquent periodic reports by June 11, 2009, there can be no assurances that the Panel will grant a further extension to allow us additional time to file such reports or that our common stock will not be delisted.

Any potential delisting of our common stock from the NASDAQ Global Market would make it more difficult for our stockholders to sell our stock in the public market. Additionally, the delisting of our common stock could materially adversely affect our ability to raise capital that may be needed for future operations. Delisting could also have other negative results, including the potential loss of confidence by customers and employees, the loss of institutional investor interest, and fewer business development opportunities and would likely result in decreased liquidity and increased volatility for our common stock.

Our stock price may be volatile.

The following factors could affect our stock price:


	•	the Recombination and the uncertainty whether it will be successful;

	•	our operating and financial performance and prospects;

	•	quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;

	•	changes in revenue or earnings estimates or publication of research reports by analysts about us or the exploration and production industry;

	•	liquidity and registering our common stock for public resale;

	•	material weaknesses in the control environment;

	•	actual or anticipated variations in our reserve estimates and quarterly operating results;

	•	changes in oil and natural gas prices;

	•	speculation in the press or investment community;

	•	sales of our common stock by significant stockholders;

	•	short-selling of our common stock by investors;

	•	pending litigation, including securities class action and derivative lawsuits;

	•	issuance of a significant number of shares to raise additional capital to fund our operations;

	•	increases in our cost of capital;

	•	changes in applicable laws or regulations, court rulings and enforcement and legal actions;

	•	changes in market valuations of similar companies;

	•	adverse market reaction to any increased indebtedness we incur in the future;

	•	additions or departures of key management personnel;

	•	actions by our stockholders;

	•	general market conditions, including fluctuations in and the occurrence of events or trends affecting the price of oil and natural gas; and

	•	domestic and international economic, legal and regulatory factors unrelated to our performance.

It is unlikely that we will be able to pay dividends on our common stock.

We have never paid dividends on our common stock. We cannot predict with certainty that our operations will result in sufficient revenues to enable us to operate profitably and with sufficient positive cash flow so as to enable us to pay dividends to the holders of common stock. In addition, QRCP’s credit agreement prohibits it from paying any dividend to the holders of our common stock without the consent of the lenders under the credit agreement, other than dividends payable solely in equity interests of the Company.

The percentage ownership evidenced by the common stock is subject to dilution.

We are authorized to issue up to 200,000,000 shares of common stock and are not prohibited from issuing additional shares of such common stock. Moreover, to the extent that we issue any additional common stock, a holder of the common stock is not necessarily entitled to purchase any part of such issuance of stock. The holders of the common stock do not have statutory “preemptive rights” and therefore are not entitled to maintain a proportionate share of ownership by buying additional shares of any new issuance of common stock before others are given the opportunity to purchase the same. Accordingly, you must be willing to assume the risk that your

percentage ownership, as a holder of the common stock, is subject to change as a result of the sale of any additional common stock, or other equity interests in the Company.

Our common stock is an unsecured equity interest.

Just like any equity interest, our common stock will not be secured by any of our assets. Therefore, in the event of our liquidation, the holders of our common stock will receive distributions only after all of our secured and unsecured creditors have been paid in full. There can be no assurance that we will have sufficient assets after paying its secured and unsecured creditors to make any distribution to the holders of our common stock.

Provisions in Nevada law could delay or prevent a change in control, even if that change would be beneficial to our stockholders.

Certain provisions of Nevada law may delay, discourage, prevent or render more difficult an attempt to obtain control of us, whether through a tender offer, business combination, proxy contest or otherwise. The provisions of Nevada law are designed to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with our board of directors.

Specifically, the Nevada Revised Statutes contain a provision prohibiting certain “combinations” (generally defined to include certain mergers, disposition of assets transactions, and share issuance or transfer transactions) between a resident domestic corporation and an “interested stockholder” (generally defined to be the beneficial owner of 10% or more of the voting power of the outstanding shares of the corporation), except those combinations which are approved by the board of directors before the interested stockholder first obtained a 10% interest in the corporation’s stock. There are additional exceptions to the prohibition, which apply to combinations if they occur more than three years after the interested stockholder’s date of acquiring shares. This provision applies unless the corporation elects against its application in its original articles of incorporation or an amendment thereto. Our restated articles of incorporation, as amended, do not currently contain a provision rendering this provision inapplicable.

We have various mechanisms in place to discourage takeover attempts, which may reduce or eliminate our stockholders’ ability to sell their shares for a premium in a change of control transaction.

Various provisions of our articles of incorporation and bylaws may discourage, delay or prevent a change in control or takeover attempt of our company by a third party that is opposed to by our management and board of directors. Public stockholders who might desire to participate in such a transaction may not have the opportunity to do so. These anti-takeover provisions could substantially impede the ability of public stockholders to benefit from a change of control or change in our management and board of directors. These provisions include:


	•	the right of our board of directors to issue and determine the rights and preferences of preferred stock to make it more difficult for a third party to acquire, or to discourage a third party from acquiring, a majority of our outstanding voting stock;

	•	classification of our directors into three classes with respect to the time for which they hold office;

	•	non-cumulative voting for directors;

	•	control by our board of directors of the size of our board of directors;

	•	limitations on the ability of stockholders to call special meetings of stockholders; and

	•	advance notice requirements for nominations by stockholders of candidates for election to our board of directors or for proposing matters that can be acted upon by our stockholders at stockholder meetings.

We have also approved a stockholders’ rights agreement (the “Rights Agreement”) between us and UMB Bank, N.A., (subsequently acquired by Computershare Limited) as Rights Agent. Pursuant to the Rights Agreement, holders of our common stock are entitled to purchase one one-thousandth (1/1,000) of a share (a “Unit”) of Series B Junior Participating Preferred Stock at a price of $75.00 per Unit upon certain events. The purchase price is subject to appropriate adjustment upon the happening of certain events. Generally, in the event a person or entity

acquires, or initiates a tender offer to acquire, at least 15% of our then outstanding common stock, the Rights will become exercisable for shares of common stock equal to (i) the number of Units held by a stockholder multiplied by the then-current purchase price, and (ii) divided by one-half of our then-current stock price. The existence of the Rights Agreement may discourage, delay or prevent a change of control or takeover attempt of us by a third party that is opposed to by our management and board of directors.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

ITEM 3. LEGAL PROCEEDINGS.

We are subject, from time to time, to certain legal proceedings and claims in the ordinary course of conducting our business. We will record a liability related to our legal proceedings and claims when we have determined that it is probable that we will be obligated to pay and the related amount can be reasonably estimated, and we will disclose the related facts in the footnotes to our financial statements, if material. If we determine that an obligation is reasonably possible, we will, if material, disclose the nature of the loss contingency and the estimated range of possible loss, or include a statement that no estimate of loss can be made. We are currently a defendant in the following litigation. We intend to defend vigorously against the claims described below. We are unable to predict the outcome of these proceedings or reasonably estimate a range of possible loss that may result. Like other oil and natural gas producers and marketers, our 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.

Federal Securities Class Actions

Michael Friedman, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David E. Grose, Case No. 08-cv-936-M U.S., District Court for the Western District of Oklahoma, filed September 5, 2008

James Jents, individually and on behalf of all others similarly situated v. Quest Resource Corporation, Jerry Cash, David E. Grose, and John Garrison, Case No. 08-cv-968-M, U.S. District Court for the Western District of Oklahoma, filed September 12, 2008

J. Braxton Kyzer and Bapui Rao, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation and David E. Grose, Case No. 08-cv-1066-M, U.S. District Court for the Western District of Oklahoma, filed October 6, 2008

Paul Rosen, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David E. Grose, Case No. 08-cv-978-M, U.S. District Court for the Western District of Oklahoma, filed September 17, 2008

Four putative class action complaints were filed in the United States District Court for the Western District of Oklahoma against the Company, Quest Energy Partners, L.P., and Quest Energy GP, LLC and certain of our current and former officers and directors. The complaints were filed by certain stockholders on behalf of themselves and other stockholders who purchased our common stock between May 2, 2005 and August 25, 2008 and Quest Energy common units between November 7, 2007 and August 25, 2008. The complaints assert claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and Sections 11 and 15 of the Securities Act of 1933. The complaints allege that the defendants violated the federal securities laws by issuing false and misleading statements and/or concealing material facts concerning certain unauthorized transfers of funds from subsidiaries of the Company to entities controlled by the Company’s former chief executive officer, Mr. Jerry D. Cash. The complaints also allege that, as a result of these actions, our stock price and the unit price of Quest Energy was artificially inflated during the class period. On December 29, 2008 the court consolidated these complaints as Michael Friedman, individually and on behalf of all others similarly situated v. Quest Energy Partners LP, Quest Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David E. Grose, Case No. 08-cv-936-M, in the

Western District of Oklahoma. Various individual plaintiffs have filed multiple rounds of motions seeking appointment as lead plaintiff, however the court has not yet ruled on these motions and appointed a lead plaintiff. Once a lead plaintiff is appointed, the lead plaintiff must file a consolidated amended complaint within 60 days after being appointed. No further activity is expected in the purported class action until a lead plaintiff is appointed and an amended consolidated complaint is filed. The Company, Quest Energy and Quest Energy GP intend to defend vigorously against plaintiffs’ claims.

Federal Derivative Case

James Stephens, derivatively on behalf of nominal defendant Quest Resource Corporation. v. William H. Damon III, Jerry Cash, David Lawler, David E. Grose, James B. Kite Jr., John C. Garrison and Jon H. Rateau, Case No. 08-cv-1025-M, U.S. District Court for the Western District of Oklahoma, filed September 25, 2008

On September 25, 2008 a complaint was filed in the United States District Court for the Western District of Oklahoma, purportedly on our behalf, entitled James Stephens, derivatively on behalf on nominal defendant Quest Resource Corporation v. William H. Damon III, Jerry Cash, David Lawler, David E. Grose, James B. Kite Jr., John C. Garrison and Jon H. Rateau, Case No. 08-cv-1025-M. The complaint names certain of our current and former officers and directors as defendants. The factual allegations mirror those in the purported class actions described above, and the complaint asserts claims for breach of fiduciary duty, abuse of control, gross mismanagement, waste of corporate assets, and unjust enrichment. The complaint seeks disgorgement, costs, expenses, and equitable and/or injunctive relief. On October 16, 2008, the court stayed this case pending the court’s ruling on any motions to dismiss the class action claims. The Company intends to defend vigorously against these claims.

State Court Derivative Cases

Tim Bodeker, derivatively on behalf of nominal defendant Quest Resource Corporation v. Jerry Cash, David E. Grose, Bob G. Alexander, David C. Lawler, James B. Kite, John C. Garrison, Jon H. Rateau and William H. Damon III, Case No. CJ-2008-9042, in the District Court of Oklahoma County, State of Oklahoma, filed October 8, 2008

William H. Jacobson, derivatively on behalf of nominal defendant Quest Resource Corporation v. Jerry Cash, David E. Grose, David C. Lawler, James B. Kite, Jon H. Rateau, Bob G. Alexander, William H. Damon III, John C. Garrison, Murrell, Hall, McIntosh & Co., LLP, and Eide Bailly, LLP, Case No. CJ-2008-9657, in the District Court of Oklahoma County, State of Oklahoma, filed October 27, 2008

Amy Wulfert, derivatively on behalf of nominal defendant Quest Resource Corporation, v. Jerry D. Cash, David C. Lawler, Jon C. Garrison, John H. Rateau, James B. Kite Jr., William H. Damon III, David E. Grose, N. Malone Mitchell III, and Bryan Simmons, Case No. CJ-2008-9042 — consolidated December 30, 2008, in the District Court of Oklahoma County, State of Oklahoma (Original Case No. CJ-2008-9624, filed October 24, 2008)

The factual allegations in these petitions mirror those in the purported class actions discussed above. All three petitions assert claims for breach of fiduciary duty, abuse of control, gross mismanagement, and unjust enrichment. The Jacobson petition also asserts claims against the two auditing firms named in that suit for professional negligence and aiding and abetting the director defendants’ breaches of fiduciary duties. The Wulfert petition also asserts a claim against Mr. Bryan Simmons for aiding and abetting Messrs. Cash’s and Grose’s breaches of fiduciary duties. The petitions seek damages, costs, expenses, and equitable relief. On November 12, 2008, the parties to these lawsuits filed a motion to consolidate the actions and appoint lead counsel. The court has not yet ruled on this motion. Under the proposed order, the defendants need not respond to the individual petitions. Once the actions are consolidated, the proposed order provides that counsel for the parties shall meet and confer, within thirty days from the date of the entry of the order, regarding the scheduling of the filing of a consolidated derivative petition and the defendants’ responses to that petition. The Company intends to defend vigorously against plaintiffs’ claims.

Royalty Owner Class Action

Hugo Spieker, et al. v. Quest Cherokee, LLC Case No. 07-1225-MLB in the U.S. District Court, District of Kansas, filed August 6, 2007

Quest Cherokee was named as a defendant in a class action lawsuit filed by several royalty owners in the U.S. District Court for the District of Kansas. 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.

Personal Injury Litigation

Segundo Francisco Trigoso and Dana Jara De Trigoso v. Quest Cherokee Oilfield Service, LLC, CJ-2007-11079, in the District Court of Oklahoma County, State of Oklahoma, filed December 27, 2007

Quest Cherokee Oilfield Service, LLC (“QCOS”) has been named in this lawsuit filed by plaintiffs Segundo Francisco Trigoso and Dana Jara De Trigoso. Plaintiffs allege that Segundo Francisco Trigoso was seriously injured while working for QCOS on September 29, 2006 and that the conduct of QCOS was substantially certain to cause injury to Segundo Francisco Trigoso. Plaintiffs seek unspecified damages for physical injuries, emotional injuries, loss of consortium and pain and suffering. Plaintiffs also seek punitive damages. Various motions for summary judgment have been filed and denied by the court. It is expected that the court will set this matter for trial in Fall 2009. QCOS intends to defend vigorously against plaintiffs’ claims.

St. Paul Surplus Lines Insurance Company v. Quest Cherokee Oilfield Service, LLC, et al, CJ-2009-1078, in the District Court of Tulsa County, State of Oklahoma, filed February 11, 2009

QCOS has been named as a defendant in this declaratory action. This action arises out of the Trigoso matter discussed above. Plaintiff alleges that no coverage is owed QCOS under the excess insurance policy issued by plaintiff. The contentions of plaintiff primarily rest on their position that the allegations made in Trigoso are intentional in nature and that the excess insurance policy does not cover such claims. QCOS will vigorously defend the declaratory action.

Billy Bob Willis, et al. v. Quest Resource Corporation, et al., Case No. CJ-09-00063, District Court of Nowata County, State of Oklahoma, filed April 28, 2009

Quest Resource Corporation, et al. have been named in the above-referenced lawsuit. The lawsuit has not been served. At this time and due to the recent filing of the lawsuit, the Company is unable to provide further detail.

Larry Reitz, et al. v. Quest Resource Corporation, et al., Case No. CJ-09-00076, District Court of Nowata County, State of Oklahoma, filed May 15, 2009

Quest Resource Corporation, et al. have been named in the above-referenced lawsuit. The lawsuit was served on May 22, 2009. Defendants have not answered and no discovery has taken place. Plaintiffs allege that defendants have wrongfully deducted costs from the royalties of plaintiffs and have engaged in self-dealing contracts and agreements resulting in a less than market price for production. Plaintiffs seek unspecified actual and punitive damages. Defendants intend to defend vigorously against this claim.

Berenice Urias v. Quest Cherokee, LLC, et al., CV-2008-238C in the Fifth Judicial District, County of Lea, State of New Mexico (Second Amended Complaint filed September 24, 2008)

Quest Cherokee was named in this wrongful death lawsuit filed by Berenice Urias. Plaintiff was the surviving fiancée of the decedent Montano Moreno. The decedent was killed while working for United Drilling, Inc. United Drilling was transporting a drilling rig between locations when the decedent was electrocuted. All claims against Quest Cherokee have been dismissed with prejudice.

Litigation Related to Oil and Gas Leases

Quest Cherokee has been named as a defendant or counterclaim defendant in several lawsuits in which the plaintiff claims 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 are pending in the district courts of Labette, Montgomery, Wilson, and Neosho 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 March 1, 2009, the total amount of acreage covered by the leases at issue in these lawsuits was approximately 4,808 acres. Discovery in those cases is ongoing. Quest Cherokee intends to vigorously defend against those claims. Following is a list of those cases:

Roger Dean Daniels v. Quest Cherokee, LLC, Case No. 06-CV-61, in the District Court of Montgomery County, State of Kansas, filed May 5, 2006

Carol R. Knisely, et al. v. Quest Cherokee, LLC, Case No. 07-CV-58-I, in the District Court of Montgomery County, State of Kansas, filed April 16, 2007

Quest Cherokee, LLC v. David W. Hinkle, et al., Case No. 2006-CV-74, in the District Court of Labette County, State of Kansas, filed September 5, 2006

Scott Tomlinson, et al. v. Quest Cherokee, LLC, Case No. 2007-CV-45, in the District Court of Wilson County, State of Kansas, filed August 29, 2007

Ilene T. Bussman et al. v. Quest Cherokee, LLC, Case No. 07-CV-106-PA, in the District Court of Labette County, State of Kansas, filed November 26, 2007

Gary Dale Palmer, et al. v. Quest Cherokee, LLC, Case No. 07-CV-107-PA, in the District Court of Labette County, State of Kansas, filed November 26, 2007

Richard L. Bradford, et al. v. Quest Cherokee, LLC, Case No. 2008-CV-67, in the District Court of Wilson County, Kansas, filed September 18, 2008

Richard Winder v. Quest Cherokee, LLC, Case Nos. 07-CV-141 and 08-CV-20, in the District Court of Wilson County, Kansas, filed December 7, 2007, and February 27, 2008

Housel v. Quest Cherokee, LLC, 06-CV-26-I, in the District Court of Montgomery County, State of Kansas, filed March 2, 2006

Quest Cherokee was named as a defendant in a lawsuit filed by Charles Housel and Meredith Housel on March 2, 2006. Plaintiffs allege that the primary term of the lease at issue has expired and that based upon non-production, plaintiffs are entitled to cancellation of said lease. A judgment was entered against Quest Cherokee on May 15, 2006. Quest Cherokee, however, was never properly served with this lawsuit and did not learn of this lawsuit until on or about April 23, 2007. Quest Cherokee filed a Motion to Set Aside Default Judgment and the parties have since agreed to set aside the default judgment that was entered. Quest Cherokee has answered the complaint. On April 1, 2008, Quest Cherokee sought leave from the court to bring a third party claim against Layne Energy Operating, LLC (“Layne”) on the basis that it, among other things, has committed a trespass and has converted the well and gas and/or proceeds at issue. Quest Cherokee was granted leave to file its claim against Layne. Layne has moved to dismiss the Third Party Petition and Quest Cherokee has objected. Quest Cherokee intends to defend vigorously against plaintiffs’ claims and pursue vigorously its claims against Layne.

Central Natural Resources, Inc. v. Quest Cherokee, LLC, et al., Case No. 04-C-100-PA in the District Court of Labette County, State of Kansas, filed on September 1, 2004

Quest Cherokee and Bluestem were named as defendants in a lawsuit filed by Central Natural Resources, Inc. (“Central Natural Resources”) 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 and has damaged its coal through its drilling and production operations. 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 gas were filed by Quest Cherokee and the plaintiff, with summary judgment being awarded in Quest Cherokee’s favor. Plaintiff appealed the summary judgment and the Kansas Supreme Court has issued an opinion affirming the District Court’s decision and has remanded the case to the District Court for further proceedings consistent with that decision. Quest Cherokee and Bluestem intend to defend vigorously against these claims.

Central Natural Resources, Inc. v. Quest Cherokee, LLC, et al., Case No. CJ-06-07 in the District Court of Craig County, State of Oklahoma, filed January 17, 2006

Quest Cherokee was named as a defendant in a lawsuit filed by Central Natural Resources, Inc. on January 17, 2006, in the District Court of Craig County, Oklahoma. Central Natural Resources owns the coal underlying approximately 2,250 acres of land in Craig County, Oklahoma. Quest Cherokee has obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying those lands, and has drilled and completed 20 wells that produce coal bed methane gas on those lands. Plaintiff alleges that it is entitled to the coal bed methane gas produced and revenues from these leases and that Quest Cherokee is a trespasser. Plaintiff seeks to quiet its alleged title to the coal bed methane and an accounting of the revenues from the coal bed methane gas produced by Quest Cherokee. 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 has been stayed by agreement of the parties. Quest Cherokee intends to defend vigorously against these claims.

Edward E. Birk, et ux., and Brian L. Birk, et ux., v. Quest Cherokee, LLC, Case No. 09-CV-27, in the District Court of Neosho County, State of Kansas, filed April 23, 2009

Quest Cherokee was named as a defendant in a lawsuit filed by Edward E. Birk, et ux., and Brian L. Birk, et ux., on April 23, 2009. In that case, the plaintiffs claim that they are entitled to an overriding royalty interest (1/16^th in some leases, and 1/32^nd in some leases) in 14 oil and gas leases owned and operated by Quest Cherokee. Plaintiffs contend that Quest Cherokee has produced oil and/or gas from wells located on or unitized with those leases, and that Quest Cherokee has failed to pay plaintiffs their overriding royalty interest in that production. Quest Cherokee’s answer date is June 15, 2009. We are investigating the factual and legal basis for these claims and intend to defend against them vigorously based upon the results of the investigation.

Robert C. Aker, et al. v. Quest Cherokee, LLC, et al., U.S. District Court for the Western District of Pennsylvania, Case No. 3-09CV101, filed April 16, 2009

Quest Cherokee, et al. were named as defendants in this action where plaintiffs seek a ruling invalidating certain oil and gas leases. Quest Cherokee has not answered and no discovery has taken place. Quest Cherokee is investigating whether it is a proper party to this lawsuit and intends to vigorously defend against this claim.

Other

Well Refined Drilling Co. v. Quest Cherokee, LLC, Case No. 2007-CV-91, in the District Court of Neosho County, State of Kansas, filed July 19, 2007; and Well Refined Drilling Co. v. Quest Cherokee, LLC, Case No. 2007-CV-46, in the District Court of Wilson County, State of Kansas, filed September 4, 2007

Quest Cherokee has been named as a defendant in two lawsuits filed by Well Refined Drilling Company in the District Court of Neosho County, Kansas (Case No. 2007 CV 91) and in the District Court of Wilson County, Kansas (Case No. 2007 CV 46). In both cases, plaintiff contends that Quest Cherokee owes certain sums for services provided by the plaintiff in connection with drilling wells for Quest Cherokee. Plaintiff has also filed mechanics liens against the oil and gas leases on which those wells are located and also seeks foreclosure of those liens. Quest

Cherokee has answered those petitions and has denied plaintiff’s claims. Discovery in those cases is ongoing. Quest Cherokee intends to defend vigorously against these claims.

Barbara Cox v. Quest Cherokee, LLC, U.S. District Court for the District of New Mexico, Case No. CIV-08-0546, filed April 18, 2008

Quest Cherokee has been named in this lawsuit by Barbara Cox. Plaintiff is a landowner in Hobbs, New Mexico and owns the property where the Quest State 9-4 Well was drilled and plugged. Plaintiff alleges that Quest Cherokee violated the New Mexico Surface Owner Protection Act and has committed a trespass and nuisance in the drilling and maintenance of the well. Quest Cherokee denies the allegations of plaintiff. Plaintiff has not articulated any firm damage numbers. Quest Cherokee intends to defend vigorously against plaintiff’s claims.

Juana Huerter v. Quest Cherokee Oilfield Services, LLC, et al., Case No. 2008 CV-50, District Court of Neosho County, State of Kansas, filed May 5, 2008

QCOS, et al. has been named in this personal injury lawsuit arising out of an automobile collision. Initial written discovery is being conducted. There is no pending trial date. QCOS intends to defend vigorously against this claim.

Bradley Haviland, Jr., v. Quest Cherokee Oilfield Services, LLC, et al., Case No. 2008 CV-78, District Court of Neosho County, State of Kansas, filed July 25, 2008

QCOS, et al. has been named in this personal injury lawsuit arising out of an automobile collision. There is no pending trial date. QCOS intends to defend vigorously against this claim.


ITEM 4.	*SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.*

No matters were submitted to a vote of security holders during the fourth quarter of 2008.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Market Information

The Company’s common stock trades on The NASDAQ Global Market under the symbol “QRCP”. The table set forth below lists the range of high and low prices of the Company’s common stock on NASDAQ for each quarter of the last two years.


Fiscal Quarter and Period Ended	High Price		Low Price

December 31, 2008	$	2.84	$	0.23
September 30, 2008	$	10.86	$	2.15
June 30, 2008	$	13.45	$	6.96
March 31, 2008	$	8.10	$	6.35
December 31, 2007	$	10.82	$	6.66
September 30, 2007	$	11.96	$	9.00
June 30, 2007	$	12.08	$	8.50
March 31, 2007	$	9.70	$	7.50

The closing price for QRCP stock on May 15, 2009 was $0.49.

Record Holders

As of May 15, 2009, there were 31,867,527 shares of common stock outstanding held of record by approximately 646 stockholders.

Dividends

The payment of dividends on QRCP’s common stock is within the discretion of the board of directors and will depend on our earnings, capital requirements, financial condition and other relevant factors. We have not declared any cash dividends on QRCP’s common stock and do not anticipate paying any dividends on QRCP’s common stock in the foreseeable future.

Our ability to pay dividends on QRCP’s common stock is subject to restrictions contained in its credit agreement. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Agreements” for a discussion of these restrictions.

In addition, the partnership agreements for Quest Energy and Quest Midstream restrict the ability of Quest Energy and Quest Midstream to pay distributions on the subordinated units of such partnerships that QRCP owns if the minimum quarterly distribution has not been paid on all of the common units of such partnerships. The credit agreements for Quest Energy and Quest Midstream also restrict the ability of Quest Energy and Quest Midstream to pay any distributions. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Agreements.” The third and fourth quarter 2008 distributions for Quest Midstream were not paid, the third quarter 2008 distribution on Quest Energy’s subordinated units was not paid and the fourth quarter 2008 distribution on all of Quest Energy’s units, including common units, for Quest Energy was not paid. There can be no assurance that minimum quarterly distributions on the common units for those quarters will be paid or that any future distributions will be paid.

Recent Sales of Unregistered Securities

None.

Purchases of Equity Securities

We have reacquired shares of stock from employees upon the vesting of restricted stock that was granted under our 2005 Omnibus Stock Award Plan. These shares were surrendered by the employees and reacquired by us to satisfy a portion of the minimum statutory tax withholding obligations arising from the lapse of restrictions on the shares. The following table provides information with respect to these purchases during the year ended December 31, 2008.

Maximum

Total Number of

Number (or

Shares

Approximate

Purchased as

Dollar Value) of

Part of Publicly

Shares that May

Total Number

Average Price

Announced

Yet Be Purchased

of Shares

Paid per

Plans or

Under the Plans

Period

Purchased

Share

Programs

or Programs

December 1 through December 31, 2008

21,955

0.32

—

STOCK PRICE PERFORMANCE GRAPH

The following graph compares the performance of our common stock to a published industry index (AMEX Natural Resources) and a market index (Nasdaq Composite Index) for the past five years. We have also included a peer group in our SIC code index that was included in our Stock Price Performance Graph last year. The peer group consists of the following companies: Abraxas Petroleum Corporation; Credo Petroleum Corporation; Double Eagle Petroleum Company; Dune Energy Inc; Edge Petroleum Corporation; Evolution Petroleum Corporation; FX Energy Inc.; Georesources Inc.; Houston American Energy Corporation; Kodiak Oil & Gas Corporation; Meridian Resource Corporation; Ngas Resources Inc.; Northern Oil & Gas Inc.; Pinnacle Gas Resources Inc.; Platinum Energy Resources Inc.; Primeenergy Corporation; South Texas Oil Company; Toreador Resources Corporation; and Tri Valley Corporation.

The peer group was chosen last year to reflect a comparison of companies closely aligned with our market capitalization value. Beginning this year, we have decided to switch from a self-selected peer group to a published industry index (AMEX Natural Resources) because we believe the broader index provides more meaningful stockholder return information.

The graph assumes the investment of $100 on December 31, 2003 and the reinvestment of all dividends. The graph shows the value of the investment at the end of each year.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN

Among Quest Resource Corporation, AMEX Natural Resources, Nasdaq Composite Index and a Peer Group

ITEM 6. SELECTED FINANCIAL DATA.

The following table sets forth selected financial information. The data for the years ended December 31, 2008, 2007, 2006 and 2005 are derived from our audited and, for 2007, 2006 and 2005, restated consolidated financial statements included elsewhere in this report. The data for the seven month transition period ended December 31, 2004 and the fiscal year ended May 31, 2004 are derived from unaudited management accounts for such periods, not from our previously filed audited financial statements, which have been restated. See Note 18 — Restatement to the consolidated financial statements for a discussion of the restatements.


													7 Months
													Ended			Fiscal Year
	Year Ended December 31,												December 31,			Ended May 31,
	2008			2007			2006			2005			2004			2004
				(Restated)			(Restated)			(Restated)			(Unaudited)			(Unaudited)
													(Restated)			(Restated)
	($ in thousands, except per share data)

Statement of Operations Data:
Revenues:
Oil and gas sales	$	147,937		$	105,285		$	72,410		$	70,628		$	28,593		$	30,707
Gas pipeline revenue		28,176			9,853			5,014			3,939			1,918			2,707

Total revenues		176,113			115,138			77,424			74,567			30,511			33,414
Costs and expenses:
Oil and gas production		44,111			36,295			25,338			18,532			5,181			6,835
Pipeline operating		29,742			21,098			13,151			7,703			4,451			3,506
General and administrative		28,269			21,023			8,655			6,218			2,765			2,925
Depreciation, depletion and amortization		70,445			39,782			27,011			22,244			7,933			5,488
Impairment of oil and gas properties		298,861			—			—			—			—			—
Loss from misappropriation of funds		—			2,000			6,000			2,000			—			—

Total costs and expenses		471,428			120,198			80,155			56,697			20,330			18,754

Operating income (loss)		(295,315	)		(5,060	)		(2,731	)		17,870			10,181			14,660
Other income (expense):
Gain (loss) from derivative financial instruments		80,707			1,961			52,690			(73,566	)		(6,085	)		(19,788	)
Gain (loss) on sale of assets		24			(322	)		3			12			—			(6	)
Loss on early extinguishment of debt		—			—			—			(12,355	)		(1,834	)		—
Other income (expense)		305			(9	)		99			389			37			(843	)
Interest expense, net		(25,373	)		(43,628	)		(20,567	)		(28,225	)		(11,537	)		(8,388	)

Total other income and (expense)		55,663			(41,998	)		32,225			(113,745	)		(19,419	)		(29,025	)

Loss before income taxes and minority interests		(239,652	)		(47,058	)		29,494			(95,875	)		(9,238	)		(14,365	)
Income tax benefit (expense)		—			—			—			—			—			245

Net income (loss) before minority interests		(239,652	)		(47,058	)		29,494			(95,875	)		(9,238	)		(14,120	)
Minority interests in continuing operations		72,268			2,904			14			—			—			—

Cumulative effect of accounting change, net of tax		—			—			—			—			—			(28	)

Net income (loss)		(167,384	)		(44,154	)		29,508			(95,875	)		(9,238	)		(14,148	)
Preferred stock dividends		—			—			—			(10	)		(6	)		(10	)

Net income (loss) available to common shareholders	$	(167,384	)	$	(44,154	)	$	29,508		$	(95,885	)	$	(9,244	)	$	(14,158	)


												7 Months
												Ended			Fiscal Year
	Year Ended December 31,											December 31,			Ended May 31,
	2008			2007			2006		2005			2004			2004
				(Restated)			(Restated)		(Restated)			(Unaudited)			(Unaudited)
												(Restated)			(Restated)
	($ in thousands, except per share data)

Net income (loss) available to common shareholders per share:
Basic	$	(6.20	)	$	(1.97	)	$	1.33	$	(11.48	)	$	(1.63	)	$	(2.51	)
Diluted	$	(6.20	)	$	(1.97	)	$	1.33	$	(11.48	)	$	(1.63	)	$	(2.49	)
Weighted average common and common equivalent shares outstanding:
Basic		27,010,690			22,379,479			22,119,497		8,351,945			5,661,096			5,645,077

Diluted		27,010,690			22,379,479			22,198,799		8,351,945			5,661,096			5,675,077

Balance Sheet Data (at end of period):
Total assets	$	650,176		$	672,537		$	467,936	$	274,768		$	245,996		$	190,184
Long-term debt, net of current maturities	$	343,094		$	233,046		$	225,245	$	100,581		$	134,609		$	105,379

Comparability of information in the above table between years is affected by (1) changes in the annual average prices for oil and gas, (2) increased production from drilling and development activity, (3) significant acquisitions that were made during the fiscal year ended May 31, 2004, (4) the change in the fiscal year end on December 31, 2004, (5) formation of Quest Midstream in December 2006, (6) the acquisition of KPC on November 1, 2007, (7) Quest Energy’s initial public offering effective November 15, 2007 and (8) the acquisition of PetroEdge in July 2008. The table should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements, including the notes, appearing in Items 7 and 8 of this report, respectively.


ITEM 7.	*MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS*

Restatement

As discussed in the Explanatory Note to this Annual Report on Form 10-K and in Note 18 — Restatement to our consolidated financial statements, we are restating the consolidated financial statements included in this Annual Report on Form 10-K as of December 31, 2007 and 2006 and for the three years ended December 31, 2007. We are also restating previously issued Quarterly Financial Data for 2008 and 2007 presented in Note 20 — Supplemental Financial Information — Quarterly Financial Data (Unaudited) to the consolidated financial statements. This Management’s Discussion and Analysis of Financial Condition and Results of Operations for the years ended December 31, 2008, 2007, 2006 and 2005 reflects the restatements.

The following discussion should be read together with the consolidated financial statements and the notes to consolidated financial statements, which are included in Item 8 of this Form 10-K, and the Risk Factors, which are set forth in Item 1A.

Overview of Our Company

Since QRCP controls the general partner interests in Quest Energy and Quest Midstream, QRCP reflects its ownership interest in these partnerships on a consolidated basis, which means that our financial results are combined with Quest Energy’s and Quest Midstream’s financial results and the results of our other subsidiaries. The interest owned by non-controlling partners’ share of income is reflected as an expense in our results of operations. Since the initial public offering of Quest Energy in November 2007, QRCP’s potential sources of revenue and cash flows consist almost exclusively of distributions on its partnership interests in Quest Energy and Quest Midstream, because QRCP’s Appalachian assets largely consist of undeveloped acreage. Our consolidated results of operations are derived from the results of operations of Quest Energy and Quest Midstream and also include interest of non-

controlling partners in Quest Energy’s and Quest Midstream’s net income, interest income (expense) and general and administrative expenses not reflected in Quest Energy’s and Quest Midstream’s results of operations. Accordingly, the discussion of our financial position and results of operations in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” primarily reflects the operating activities and results of operations of Quest Energy and Quest Midstream.

We are an integrated independent energy company involved in the acquisition, development, transportation, exploration, and production of natural gas, primarily from coal seams (coal bed methane, or “CBM”), and oil. Our principal operations and producing properties are located in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma; Seminole County, Oklahoma; and West Virginia, New York and Pennsylvania in the Appalachian Basin. We conduct substantially all of our production operations through Quest Energy and our natural gas transportation, gathering, treating and processing operations through Quest Midstream. Our Cherokee Basin operations are currently focused on developing CBM gas production through Quest Energy, which is served by a gas gathering pipeline network owned through Quest Midstream. Quest Midstream also owns an interstate natural gas transmission pipeline. Our Appalachian Basin operations are primarily focused on the development of the Marcellus Shale through Quest Energy and Quest Eastern.

Recent Developments

The following is a discussion of some of the more significant events that occurred during 2008 and the first part of 2009. Please read Items 1. and 2. “Business and Properties — Recent Developments” for additional information regarding these and other events that occurred during the year.

PetroEdge Acquisition

On July 11, 2008, QRCP acquired PetroEdge and simultaneously transferred PetroEdge’s natural gas producing wells to Quest Energy. Quest Energy funded its purchase of the PetroEdge wellbores with borrowings under its revolving credit facility, which was increased from $160 million to $190 million as part of the acquisition and the proceeds from the Second Lien Loan Agreement. QRCP funded the balance of the PetroEdge acquisition with proceeds from a public offering of 8,800,000 shares of QRCP common stock at a price of $10.25 per share that closed on July 8, 2008. QRCP received net proceeds from this offering of approximately $84.2 million. Simultaneously with the closing of the PetroEdge acquisition, QRCP converted its then existing $50 million revolving credit facility to a $35 million term loan with a maturity date of July 11, 2010. RBC required QRCP to use $13 million of the proceeds from the equity offering to reduce the outstanding indebtedness under the Credit Agreement from $48 million to $35 million. The purpose of the PetroEdge acquisition was to expand our operations to another geologic basin with less basins differential, that had significant resource potential. The acquisition closed during the peak month of natural gas pricing in 2008.

Internal Investigation; Restatements and Reaudits

The investigation revealed that the Transfers resulted in a loss of funds totaling approximately $10 million by the Company. Further, it was determined that our former chief financial officer directly participated and/or materially aided our former chief executive officer in connection with the unauthorized Transfers. In addition, the Oklahoma Department of Securities has filed a lawsuit alleging that our former chief financial officer and our former purchasing manager each received kickbacks of approximately $0.9 million from several related suppliers over a two-year period and that during the third quarter of 2008, they also engaged in the direct theft of $1 million for their personal benefit and use.

We experienced significant increased costs in the second half of 2008 and continue to experience such increased costs in the first half of 2009 due to, among other things:


	•	We had costs associated with the internal investigation and our responding to inquiries from the Oklahoma Department of Securities, the Federal Bureau of Investigation, the Department of Justice, SEC and the IRS.

	•	As a result of the termination of the former chief executive officer and chief financial officer, we immediately retained consultants to perform the accounting and finance functions and to assist in the determination of the intercompany debt discussed under Items 1. and 2. “Business and Properties — Recent Developments — Intercompany Accounts.”

	•	We retained law firms to respond to the class action and derivative suits that have been filed against QRCP and Quest Energy GP and QELP and to pursue the claims against the former employees.

	•	We had costs associated with amending the credit agreements of QRCP, QELP and QMLP and obtaining the necessary waivers from our lenders thereunder as well as incremental increased interest expense related thereto. See “— Liquidity and Capital Resources.”

	•	We retained external auditors, who completed reaudits of the restated consolidated financial statements for the years ended December 31, 2007, 2006 and 2005.

	•	Each of QRCP, QELP and QMLP retained financial advisors to consider strategic options and each retained outside legal counsel or increased the amount of work being performed by its previously engaged outside legal counsel.

We estimate that the increased costs related to the foregoing will be approximately $7.0 million to $8.0 million in total.

Global Financial Crisis and Impact on Capital Markets and Commodity Prices

Overall, as a result, our operating profitability was seriously adversely affected during the second half of 2008 and is expected to continue to be impaired during 2009. While our existing commodity hedge position mitigates the impact of commodity price declines, it does not eliminate the potential effects of changing commodity prices. See Item 1A. “Risk Factors — Risks Related to Our Business — The current financial crisis and deteriorating economic conditions may have a material adverse impact on our business and financial condition that we cannot predict.”

Credit Agreement Amendments

In October and November 2008, QRCP, Quest Cherokee and Quest Energy, and Quest Midstream and Bluestem entered into amendments to their respective credit agreements that, among other things, amended and/or waived certain of the representations and covenants contained in each credit agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result of (1) the questionable Transfers of funds discussed above and (2) not timely settling certain intercompany accounts among QRCP, Quest Energy and Quest Midstream. The Quest Cherokee amendment also extended the maturity date of the Second Lien Loan Agreement from January 11, 2009 to September 30, 2009 due to our inability to refinance the Second Lien Loan Agreement as a result of a combination of the ongoing investigation and the global financial crisis. The amendments also restricted the ability of Quest Midstream and Quest Energy to pay distributions to QRCP.

See “— Liquidity and Capital Resources — Credit Agreements” for additional information regarding our credit agreements.

Suspension of Distributions and Asset Sales

Distributions were suspended on Quest Energy’s subordinated units beginning with the third quarter of 2008 and distributions were suspended on all of Quest Energy’s units, including its common units, beginning with the fourth quarter of 2008. Since these distributions would have been substantially all of QRCP’s cash flows for 2009, the loss of the Quest Energy distributions was material to QRCP’s financial position.

Management decided that these undeveloped acres were good candidates for disposition in the current environment given the lack of gathering and transportation infrastructure in the immediate area and the cost and time that would be involved in establishing significant flow of natural gas.

QRCP borrowed $2 million of the additional $6 million term loan under its Credit Agreement in October 2008. QRCP’s portion of the proceeds from the asset sales were used to repay the $2 million additional term loan and to reduce QRCP’s $35 million term loan to $28.3 million as of May 15, 2009.

Decrease in Year-End Reserves; Impairment

Due to the low price for natural gas as of December 31, 2008 as described above, revisions resulting from further technical analysis (see Note 21 — Supplemental Information on Oil and Gas Producing Activities (Unaudited) to the accompanying consolidated financial statements and production during the year, proved reserves decreased 17.2% to 174.8 Bcfe at December 31, 2008 from 211.1 Bcfe at December 31, 2007, and the standardized measure of our proved reserves decreased 49.1% to $164.1 million as of December 31, 2008 from $286.2 million as of December 31, 2007. Proved reserves also decreased as a result of our production during the year. Our proved reserves at December 31, 2008 were calculated using a spot price of $5.71 per Mmbtu (adjusted for basis differential, prices were $5.93 per Mmbtu in the Appalachian Basin and $4.84 per Mmbtu in the Cherokee Basin). As a result of this decrease, we recognized a non-cash impairment of $298.9 million for the year ended December 31, 2008.

As a result, the lenders under QELP’s revolving credit facility are likely to reduce QELP’s borrowing base in the near term. See “— Liquidity and Capital Resources — Sources of Liquidity in 2009 and Capital Requirements — Quest Energy.”

Settlement Agreements

As discussed above, we filed lawsuits against Mr. Cash, the entity controlled by Mr. Cash that was used in connection with the Transfers and two former officers, who are the other owners of the controlled-entity, seeking, among other things, to recover the funds that were transferred. On May 19, 2009, QRCP, QELP and QMLP entered into settlement agreements with Mr. Cash, the controlled-entity and the other owners to settle this litigation. Under the terms of the settlement agreements, QRCP received (1) approximately $2.4 million in cash and (2) 60% of the controlled-entity’s interest in a gas well located in Louisiana and a landfill gas development project located in Texas. While QRCP estimates the value of these assets to be less than the amount of the Transfers and cost of the internal investigation, they represent the majority of the value of the controlled-entity. We did not take Mr. Cash’s stock in QRCP, which he represented had been pledged to secure personal loans with a principal balance far in excess of the current market value of the stock. QELP received all of Mr. Cash’s equity interest in STP, which owns certain oil producing properties in Oklahoma, and other assets as reimbursement for all of the costs of the internal investigation and the costs of the litigation against Mr. Cash that have been paid by QELP.

Outlook for 2009; Recombination

Given the liquidity challenges facing the Company, Quest Midstream and Quest Energy, each entity has undertaken a strategic review of its assets and may enter into one or more transactions to dispose of assets in order to raise additional funds for operations and/or to repay indebtedness. In addition, in the current economic environment we believe the complexity and added overhead costs of our structure is negatively affecting our ability to restructure our indebtedness and raise additional equity. See “— Liquidity and Capital Resources.” On April 28, 2009, the Company, Quest Midstream and Quest Energy entered into a non-binding letter of intent to enter into the Recombination, pursuant to the terms of which all three companies would form a new publicly traded holding company that would wholly-own all three entities. The new company would continue to develop the unconventional resources of the Cherokee and Appalachian Basins with a clear focus on value creation through efficient operations. The closing of the Recombination is subject to the satisfaction of a number of conditions, including the entry into a definitive merger agreement, the negotiation of a new credit facility for the new company, regulatory approval and the approval of the transaction by the stockholders of the Company and the unitholders of Quest Energy and Quest Midstream. There can be no assurance that the definitive documentation will be agreed to or that the Recombination will close.

Segment Overview

After the acquisition of the KPC Pipeline in November 2007, we began reporting our results of operations as two business segments. These segments and the activities performed to provide services to our customers and create value for our stockholders are as follows:


	•	Oil and gas production; and

	•	Natural gas pipelines, including transporting, gathering, treating and processing natural gas.

Previously reported amounts have been adjusted to reflect this change, which did not impact our consolidated financial statements. Operating segment data for the years ended December 31, 2008, 2007, 2006, and 2005 follows (in thousands):


	2008			2007			2006			2005

Revenues:
Oil and gas production	$	147,937		$	105,285		$	72,410		$	70,628
Natural gas pipelines		63,722			39,032			25,833			11,732
Elimination of inter-segment revenue		(35,546	)		(29,179	)		(20,819	)		(7,793	)

Natural gas pipelines, net of inter-segment revenue		28,176			9,853			5,014			3,939

Total segment revenues	$	176,113		$	115,138		$	77,424		$	74,567

Operating profit (loss):
Oil and gas production(a)	$	(284,244	)	$	5,999		$	1,861		$	23,508
Natural gas pipelines		17,198			11,964			10,063			2,580

Total segment operating profit (loss)		(267,046	)		17,963			11,924			26,088
General and administrative expenses		28,269			21,023			8,655			6,218
Misappropriation of funds		—			2,000			6,000			2,000

Total operating income (loss)	$	(295,315	)	$	(5,060	)	$	(2,731	)	$	17,870


(a)		2008 includes impairment of oil and gas properties of $298.9 million in 2008.

Results of Operations

The following discussion of financial condition and results of operations should be read in conjunction with the consolidated financial statements and the notes to the consolidated financial statements, which are included elsewhere in this report.

Oil and Gas Production Segment

Year ended December 31, 2008 compared to the year ended December 31, 2007

Overview. The following discussion of results of operations compares amounts for the year ended December 31, 2008 to the amounts for the year ended December 31, 2007, as follows:


	Year Ended
	December 31,				Increase/
	2008		2007		(Decrease)
	($ in thousands)

Oil and gas sales	$	147,937	$	105,285	$	42,652	40.5	%
Oil and gas production costs	$	44,111	$	36,295	$	7,816	21.5	%
Transportation expense (intercompany)	$	35,546	$	29,179	$	6,367	21.8	%
Depreciation, depletion and amortization	$	53,663	$	33,812	$	19,851	58.7	%
Impairment charge	$	298,861	$	—	$	298,861	*	%


*		Not meaningful

Production. The following table presents the primary components of revenues of our Oil and Gas Production Segment (oil and gas production and average oil and gas prices), as well as the average costs per Mcfe, for the fiscal years ended December 31, 2008 and 2007.


	Year Ended
	December 31,				Increase/
	2008		2007		(Decrease)

Production Data:
Total production (Mmcfe)		21,748		17,017		4,731		27.8	%
Average daily production (Mmcfe/d)		59.4		46.6		12.8		27.5	%
Average Sales Price per Unit (Mcfe):	$	6.80	$	6.19	$	0.61		9.9	%
Average Unit Costs per Mcfe:
Production costs	$	2.03	$	2.13	$	(0.10	)	(4.7	)%
Transportation expense (intercompany)	$	1.63	$	1.71	$	(0.08	)	(4.7	)%
Depreciation, depletion and amortization	$	2.47	$	1.99	$	0.48		24.1	%

Oil and Gas Sales. Oil and gas sales increased $42.7 million, or 40.5%, to $147.9 million during the year ended December 31, 2008. This increase was the result of increased sales volumes and an increase in average realized prices. Additional volumes of 4,731 Mmcfe accounted for $32.2 million of the increase. The increased volumes resulted from additional wells completed in 2008. The remaining increase of $10.4 million was attributable to an increase in the average product price in 2008. Our average product prices, which exclude hedge settlements, on an equivalent basis (Mcfe) increased to $6.80 per Mcfe for the 2008 period from $6.19 per Mcfe for the 2007 period.

Oil and Gas Operating Expenses. Oil and gas operating expenses consist of oil and gas production costs, which include lease operating expenses, severance taxes and ad valorem taxes, and transportation expense. Oil and gas operating expenses increased $14.2 million, or 21.7%, to $79.7 million during the year ended December 31, 2008, from $65.5 million during the year ended December 31, 2007.

Oil and gas production costs increased $7.8 million, or 21.5%, to $44.1 million during the year ended December 31, 2008, from $36.3 million during the year ended December 31, 2007. This increase was primarily due to increased volumes in 2008. Production costs including gross production taxes and ad valorem taxes were $2.03 per Mcfe for the year ended December 31, 2008 as compared to $2.13 per Mcfe for the year ended December 31, 2007. The decrease in per unit cost was due to higher volumes over which to spread fixed costs.

Transportation expense increased $6.4 million, or 21.8%, to $35.5 million during the year ended December 31, 2008, from $29.2 million during the year ended December 31, 2007. The increase was primarily due to increased volumes, which resulted in additional expense of approximately $7.6 million. This increase was offset by a decrease in

per unit cost of $0.08 per Mcfe. Transportation expense was $1.63 per Mcfe for the year ended December 31, 2008 as compared to $1.71 per Mcfe for the year ended December 31, 2007. This decrease in per unit cost was due to increased volumes, over which to spread fixed costs.

Depreciation, Depletion and Amortization. We are subject to variances in our depletion rates from period to period due to changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties. Our depreciation, depletion and amortization increased approximately $19.9 million, or 58.7%, in 2008 to $53.7 million from $33.8 million in 2007. On a per unit basis, we had an increase of $0.48 per Mcfe to $2.47 per Mcfe in 2008 from $1.99 per Mcfe in 2007. This increase was primarily due to downward revisions in our proved reserves, resulting in an increase in the per unit rate. In addition, depreciation and amortization increased approximately $5.5 million primarily due to additional vehicles, equipment and facilities acquired in 2008.

Impairment of oil and gas properties. We recognized impairments of our oil and gas properties of $298.9 million for the year ended December 31, 2008. Under full cost method accounting, we are required to compute the after-tax present value of our proved oil and gas properties using spot market prices for oil and gas at our balance sheet date. The base for our spot prices for gas is Henry Hub. On December 31, 2008, the spot price for gas at Henry Hub was $5.71 per Mcf and the spot oil price was $44.60 per Bbl compared to $6.43 per Mcf and $92.01 per barrel, at December 31, 2007.

Year ended December 31, 2007 compared to the year ended December 31, 2006

Overview. The following discussion of results of operations compares amounts for the year ended December 31, 2007 to the amounts for the year ended December 31, 2006, as follows:


	Year Ended December 31,				Increase/
	2007		2006		(Decrease)
	($ in thousands)

Oil and gas sales	$	105,285	$	72,410	$	32,875	45.4	%
Oil and gas production costs	$	36,295	$	25,338	$	10,957	43.2	%
Transportation expense (intercompany)	$	29,179	$	20,819	$	8,360	40.1	%
Depreciation, depletion and amortization	$	33,812	$	24,392	$	9,420	38.6	%


	Year Ended December 31,				Increase/
	2007		2006		(Decrease)

Production Data:
Total production (Mmcfe)		17,017		12,364		4,653	37.6	%
Average daily production (Mmcfe/d)		46.6		33.9		12.7	37.5	%
Average Sales Price per Unit (Mcfe):	$	6.19	$	5.86	$	0.33	5.6	%
Average Unit Costs per Mcfe:
Production costs	$	2.13	$	2.05	$	0.08	3.9	%
Transportation expense (intercompany)	$	1.71	$	1.68	$	0.03	1.8	%
Depreciation, depletion and amortization	$	1.99	$	1.97	$	0.02	1.0	%

Oil and Gas Sales. Oil and gas sales increased $32.9 million, or 45.4%, to $105.3 million during the year ended December 31, 2007, from $72.4 million during the year ended December 31, 2006. This increase was due to increased sales volumes. Higher volumes represented $28.8 million of the increase. The increase in production volumes was due to additional wells completed during 2007. The additional increase of $4.1 million was due to higher average sales prices. Our average sales prices, which exclude hedge settlements, on an equivalent basis (Mcfe) increased to $6.19 per Mcfe for 2007 from $5.86 per Mcfe for 2006.

Oil and Gas Operating Expenses. Oil and gas operating expenses consist of oil and gas production costs, which include lease operating expenses, severance taxes and ad valorem taxes, and transportation expense. Oil and gas operating expenses increased $19.3 million, or 41.8%, to $65.5 million during the year ended December 31, 2007, from $46.2 million during the year ended December 31, 2006.

Oil and gas production costs increased $11.0 million, or 43.2%, to $36.3 million during the year ended December 31, 2007, from $25.3 million during the year ended December 31, 2006. This increase was a result of the higher production volumes in 2007. Production costs including gross production taxes and ad valorem taxes were $2.13 per Mcfe for the year ended December 31, 2007 as compared to $2.05 per Mcfe for the year ended December 31, 2006. The increase in per unit costs was due to an overall increase in the costs of goods and services used in our operations partially offset by higher volumes over which fixed costs were spread.

Transportation expense increased $8.4 million, or 40.1%, to $29.2 million during the year ended December 31, 2007, from $20.8 million during the year ended December 31, 2006. Transportation expense was $1.71 per Mcfe for the year ended December 31, 2007 as compared to $1.68 per Mcfe for the year ended December 31, 2006. This increase primarily resulted from additional volumes as well as from the midstream services agreement with Quest Midstream that became effective December 1, 2006, which provided for a fixed transportation fee that was higher than the fees in the prior year.

Depreciation, Depletion and Amortization. We are subject to variances in our depletion rates from period to period due to changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties. Our depreciation, depletion and amortization increased approximately $9.4 million, or 38.6%, in 2007 to $33.8 million from $24.4 million in 2007. On a per unit basis, we had an increase of $0.02 per Mcfe to $1.99 in 2007 from $1.97 per Mcfe in 2006. This increase was primarily due to an increase in depletion of $9.3 million. This increase was due to additional production volumes in 2007.

Year ended December 31, 2006 compared to the year ended December 31, 2005

Overview. The following discussion of results of operations compares amounts for the year ended December 31, 2006 to the amounts for the year ended December 31, 2005, as follows:


	Year Ended December 31,				Increase/
	2006		2005		(Decrease)
	($ in thousands)

Oil and gas sales	$	72,410	$	70,628	$	1,782	2.5	%
Oil and gas production costs	$	25,338	$	18,532	$	6,806	36.7	%
Transportation expense (intercompany)	$	20,819	$	7,793	$	13,026	167.2	%
Depreciation, depletion and amortization	$	24,392	$	20,795	$	3,597	17.3	%

Production. The following table presents the primary components of revenues of the Oil and Gas Production Segment (oil and gas production and average oil and gas prices), as well as the average costs per Mcfe, for the fiscal years ended December 31, 2006 and 2005.


	Year Ended December 31,				Increase/
	2006		2005		(Decrease)

Production Data:
Total production (Mmcfe)		12,364		9,629		2,735		28.4	%
Average daily production (Mmcfe/d)		33.9		26.4		7.5		28.4	%
Average Sales Price per Unit (Mcfe):	$	5.86	$	7.33	$	(1.47	)	(20.1	)%
Average Unit Costs per Mcfe:
Production costs	$	2.05	$	1.92	$	0.13		6.8	%
Transportation expense (intercompany)	$	1.68	$	0.81	$	0.87		107.4	%
Depreciation, depletion and amortization	$	1.97	$	2.16	$	(0.19	)	(8.8	)%

Oil and Gas Sales. Oil and gas sales increased $1.8 million, or 2.5%, to $72.4 million during the year ended December 31, 2006, from $70.6 million during the year ended December 31, 2005. Additional volumes of 2,735 Mmcfe increased revenues by $16.0 million. The increase in volumes resulted from the additional wells completed during 2006. This increase was offset by a decrease in average prices of $1.47 per Mcfe, resulting in decreased revenues of $14.2 million. Our average sales prices, which exclude hedge settlements, on an equivalent basis (Mcfe) decreased to $5.86 per Mcfe in 2006 from $7.33 per Mcfe in 2005.

Oil and Gas Operating Expenses. Oil and gas operating expenses consist of oil and gas production costs, which include lease operating expenses, severance taxes and ad valorem taxes, and transportation expense. Oil and gas production expense increased $19.8 million, or 75.3%, to $46.1 million during the year ended December 31, 2006, from $26.3 million during the year ended December 31, 2005. This increase was due to increased sales volumes.

Oil and gas production costs increased $6.8 million, or 36.7%, to $25.3 million during the year ended December 31, 2006, from $18.5 million during the year ended December 31, 2005. Production expenses excluding gross production and ad valorem taxes were $1.56 per Mcfe for the year ended December 31, 2006 compared to $1.51 per Mcfe for the year ended December 31, 2005. Production costs including gross production taxes and ad valorem taxes were $2.05 per Mcfe for the year ended December 31, 2006 as compared to $1.92 per Mcfe for the year ended December 31, 2005. This increase was a result of a general increase in the costs of goods and services used in our operations in 2006.

Transportation expense increased $13.0 million, or 167.2%, to $20.8 million during the year ended December 31, 2006, from $7.8 million during the year ended December 31, 2005. Transportation expense was $1.68 per Mcfe for the year ended December 31, 2006 as compared to $0.81 per Mcfe for the year ended December 31, 2005. The increase primarily resulted from increases in volumes, as well as from increases in compression rental and property taxes assessed on pipelines and related equipment during 2006.

Depreciation, Depletion and Amortization. We are subject to variances in our depletion rates from period to period due to changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties. Our depreciation, depletion and amortization increased approximately $3.6 million, or 17.3%, in 2006 to $24.4 million from $20.8 million in 2005. Depletion accounted for $2.9 million of the increase, while the remaining increase was due to depreciation and amortization. On a per unit basis, we had a decrease of $0.19 per Mcfe to $1.97 in 2006 from $2.16 per Mcfe in 2005. This decrease was primarily due to a decrease in our depletion rate per Mcfe of $0.20. This decreased rate was attributable to an increase in our proved reserves.

Natural Gas Pipelines Segment

Year ended December 31, 2008 compared to year ended December 31, 2007


	Year Ended December 31,
	2008		2007		Increase/(Decrease)
	($ in thousands)

Natural Gas Pipeline Revenue:
Gas pipeline revenue — Third Party	$	28,176	$	9,853	$	18,323		186.0	%
Gas pipeline revenue — Intercompany	$	35,546	$	29,179	$	6,367		21.8	%

Total natural gas pipeline revenue	$	63,722	$	39,032	$	24,690		63.3	%
Pipeline operating expense	$	29,742	$	21,098	$	8,644		41.0	%
Depreciation and amortization expense	$	16,782	$	5,970	$	10,812		181.1	%
Throughput Data (Mmcf):
Throughput — Third Party		11,125		1,686		9,439		559.8	%
Throughput — Intercompany		25,177		17,148		8,029		46.8	%

Total throughput (Mmcf)		36,302		18,834		17,468		92.7	%
Average Pipeline Operating Costs per Mmcf:
Pipeline operating expense	$	0.82	$	1.12	$	(0.30	)	(26.8	)%
Depreciation and amortization	$	0.46	$	0.32	$	0.14		43.8	%

Pipeline Revenue. Total natural gas pipeline revenue increased $24.6 million, or 63.3%, to $63.7 million during the year ended December 31, 2008, from $39.0 million during the year ended December 31, 2007.

Third party natural gas pipeline revenue increased $18.3 million, or 186.0%, to $28.2 million during the year ended December 31, 2008, from $9.9 million during the year ended December 31, 2007. The increase was primarily related to KPC, which was acquired November 1, 2007. During the year ended December 31, 2008, KPC had revenues of $19.5 million compared to $3.2 million for the period from November 1, 2007 through December 31, 2007. The remaining increase of $2.0 million was due to additional third party volumes on our gathering system.

Intercompany natural gas pipeline revenue increased $6.4 million, or 21.8%, to $35.5 million during the year ended December 31, 2008, from $29.2 million during the year ended December 31, 2007. The increase is due to the 46.8% increase in throughput volumes from our Cherokee Basin properties and the higher gathering and compression fees resulting from the midstream services agreement that became effective January 1, 2008.

Pipeline Operating Expense. Pipeline operating expense increased $8.6 million, or 41.0%, to $29.7 million during the year ended December 31, 2008, from $21.1 million during the year ended December 31, 2007. This increase is primarily the result of our KPC acquisition in November 2007. Therefore, 2007 only had two months of expenses versus 12 months in 2008. During the year ended December 31, 2008, KPC had pipeline operating costs of $7.7 million compared to operating costs of $1.9 million during the period from November 1, 2007 through December 31, 2007. The remaining increase of $1.7 million is due to increased throughput volumes in 2008. Pipeline operating costs per unit decreased $0.30 per Mcf during 2008, from $1.12 per Mcf to $0.82 per Mcf. The decrease in per unit cost was the result of higher volumes, over which to spread fixed costs, as well as our cost-cutting efforts implemented in the third quarter of 2008.

Depreciation and Amortization. Depreciation and amortization expense increased $10.8 million, or 181.1%, to $16.8 million during the year ended December 31, 2008, from $6.0 million during the year ended December 31, 2007. The increase is primarily due to the amortization of our intangibles of $4.3 million acquired in the KPC acquisition, as well as an increase in depreciation on our pipelines of $1.7 million. During the year ended December 31, 2008, KPC had depreciation and amortization expense of $5.6 million compared to $0.8 million for the period from November 1, 2007 through December 31, 2007. The remaining increase is due to the additional natural gas gathering pipeline installed during the year ended December 31, 2008.

Year ended December 31, 2007 compared to year ended December 31, 2006


	Year Ended
	December 31,
	2007		2006		Increase/(Decrease)
			($ in thousands)

Natural Gas Pipeline Revenue:
Gas pipeline revenue — Third Party	$	9,853	$	5,014	$	4,839	96.5	%
Gas pipeline revenue — Intercompany	$	29,179	$	20,819	$	8,360	40.2	%

Total natural gas pipeline revenue	$	39,032	$	25,833	$	13,199	51.1	%
Pipeline operating expense	$	21,098	$	13,151	$	7,947	60.4	%
Depreciation and amortization expense	$	5,970	$	2,619	$	3,351	127.9	%
Throughput Data (Mmcf):
Throughput — Third Party		1,686		1,463		223	15.2	%
Throughput — Intercompany		17,148		12,341		4,807	39.0	%

Total throughput (Mmcf)		18,834		13,804		5,030	36.4	%
Average Pipeline Operating Costs per Mmcf:
Pipeline operating expense	$	1.12	$	0.95	$	0.17	17.9	%
Depreciation and amortization	$	0.32	$	0.19	$	0.13	68.4	%

Pipeline Revenue. Total natural gas pipeline revenue increased $13.2 million, or 51.1%, to $39.0 million during the year ended December 31, 2007, from $25.8 million during the year ended December 31, 2006.

Third party natural gas pipeline revenue increased $4.8 million, or 96.5%, to $9.9 million during the year ended December 31, 2007, from $5.0 million during the year ended December 31, 2006. KPC had revenues of $3.2 million during the period from November 1, 2007 through December 31, 2007. The remaining increase of $6.7 million was due to additional third party volumes on our gathering system.

Intercompany natural gas pipeline revenue increased $8.4 million, or 40.2%, to $29.2 million during the year ended December 31, 2007, from $20.8 million during the year ended December 31, 2006. The increase is due to the 39.0% increase in throughput volumes from our Cherokee Basin properties and the higher gathering and compression fees resulting from the midstream services agreement that became effective December 1, 2006.

Pipeline Operating Expense. Pipeline operating expense increased $7.9 million, or 60.4%, to $21.1 million during the year ended December 31, 2007, from $13.2 million during the year ended December 31, 2006. Pipeline operating costs per Mcf increased $0.17 per Mcf during 2007, from $0.95 per Mcf during 2006 to $1.12 per Mcf during 2007. During the period from November 1, 2007 through December 31, 2007, KPC had operating costs of $1.9 million. The remaining increase was due to the delivery of additional compressors in anticipation of increased pipeline volumes, the number of wells completed and operated during the year, the increased miles of pipeline in service and the increase in property taxes.

Depreciation and Amortization. Depreciation and amortization expense increased $3.4 million, or 127.9%, to $6.0 million during the year ended December 31, 2007, from $2.6 million during the year ended December 31, 2006. During the period from November 1, 2007 through December 31, 2007, KPC had depreciation and amortization expense of $0.8 million. The remaining increase is due to the additional natural gas gathering pipeline installed during the year ended December 31, 2007.

Year ended December 31, 2006 compared to year ended December 31, 2005

Overview. The following discussion of pipeline operations will compare amounts for the year ended December 31, 2006 to the amounts for the year ended December 31, 2005, as follows:


	Year Ended
	December 31,
	2006		2005		Increase/(Decrease)
			($ in thousands)

Natural Gas Pipeline Revenue:
Gas pipeline revenue — Third Party	$	5,014	$	3,939	$	1,075	27.3	%
Gas pipeline revenue — Intercompany	$	20,819	$	7,793	$	13,026	167.2	%

Total natural gas pipeline revenue	$	25,833	$	11,732	$	14,101	120.2	%
Pipeline operating expense	$	13,151	$	7,703	$	5,448	70.7	%
Depreciation and amortization expense	$	2,619	$	1,449	$	1,170	80.7	%
Throughput Data (Mmcf):
Throughput — Third Party		1,463		1,179		284	24.1	%
Throughput — Intercompany		12,341		9,620		2,721	28.3	%

Total throughput (Mmcf)		13,804		10,799		3,005	27.8	%
Average Pipeline Operating Costs per Mmcf:
Pipeline operating expense	$	0.95	$	0.71	$	0.24	33.8	%
Depreciation and amortization	$	0.19	$	0.13	$	0.06	46.2	%

Pipeline Revenue. Total natural gas pipeline revenue increased $14.1 million, or 120.2%, to $25.8 million during the year ended December 31, 2006, from $11.7 million during the year ended December 31, 2005.

Third party natural gas pipeline revenue increased $1.1 million, or 27.3%, to $5.0 million during the year ended December 31, 2006, from $3.9 million during the year ended December 31, 2005. This increase was primarily due to an increase in third party wells connected to our gathering system.

Intercompany natural gas pipeline revenue increased $13.0 million, or 167.2%, to $20.8 million during the year ended December 31, 2006, from $7.8 million during the year ended December 31, 2005. The increase is due to the 28.3% increase in throughput volumes from our Cherokee Basin properties and higher gathering and compression fees charged.

Pipeline Operating Expense. Pipeline operating expense increased $5.4 million, or 70.7%, to $13.1 million during the year ended December 31, 2006, from $7.7 million during the year ended December 31, 2005. Pipeline operating costs per Mcf increased $0.24 per Mcf during 2006, from $0.71 per Mcf during 2005 to $0.95 per Mcf during 2006. The increase was due to the delivery of additional compressors in anticipation of increased pipeline volumes, the number of wells completed and operated during the year, the increased miles of pipeline in service and the increase in property taxes.

Depreciation and amortization. Depreciation and amortization expense increased $1.2 million, or 80.7%, to $2.6 million during the year ended December 31, 2006, from $1.4 million during the year ended December 31, 2005. The increase is due to the additional natural gas gathering pipeline installed during the years ended December 31, 2006 and 2005.

Unallocated Items

The following discussion of results of operations will compare amounts for the years ended December 31, 2008, 2007, 2006 and 2005.

General and Administrative Expenses

General and administrative expenses increased $7.2 million, or 34.5%, to $28.2 million during the year ended December 31, 2008, from $21.0 million during the year ended December 31, 2007. The increase is primarily due to

the internal investigation and restatements and reaudits ($4.7 million), increased rent in connection with establishing a Houston Office and new corporate headquarters ($1.7 million), the inclusion of KPC for all of 2008 compared to two months in 2007 ($2.5 million), and headcount (7%) and salary (10%) increases to support the growth of the Company ($0.8 million). These amounts were partially offset by lower stock compensation expense ($3.9 million) in connection with the departure of our former chief executive and financial officers. The remaining increase was the result of the costs associated with Quest Energy being a separate publicly traded company.

General and administrative expenses increased $12.4 million, or 143.0%, to $21.0 million during the year ended December 31, 2007, from $8.6 million during the year ended December 31, 2006. The increase is mainly due to stock compensation expense ($4.9 million), and headcount (41%) and salary (10%) increases to support the growth of the Company ($1.5 million). Other increases relate to additional costs associated with Quest Energy becoming a separate public entity and the acquisition of KPC in November 2007.

General and administrative expenses increased $2.4 million, or 39.2%, to $8.6 million during the year ended December 31, 2006, from $6.2 million during the year ended December 31, 2005. The increase is mainly due to headcount (39%) and salary (10%) increases to support the growth of the Company ($0.9 million). The remaining increase was associated with costs related to the formation of Quest Midstream.

Loss on Early Extinguishment of Debt

Loss on debt refinancing. The loss on early extinguishment of debt of $12.4 million for the year ended December 31, 2005 relates to the refinancing of subordinated debt entered into in connection with the creation of Quest Cherokee in 2003.

Loss from Misappropriation of Funds

Loss from misappropriation of funds. As disclosed previously, in connection with the Transfers, we have recorded a loss from misappropriation of funds of $2.0 million, $6.0 million and $2.0 million for the years ended December 31, 2005, 2006 and 2007, respectively.

Other Income (Expense)

Gain (loss) from derivative financial instruments. Gain from derivative financial instruments increased $78.7 million to $80.7 million during the year ended December 31, 2008, from $2.0 million during the year ended December 31, 2007. Due to the decline in average natural gas and crude oil prices during the second half of 2008, we recorded a $72.5 million unrealized gain and $8.2 million realized gain on our derivative contracts for the year ended December 31, 2008 compared to a $5.3 million unrealized loss and $7.3 million realized gain for the year ended December 31, 2007. Unrealized gains are attributable to changes in natural gas prices and volumes hedged from one period end to another.

Gain from derivative financial instruments decreased $50.7 million to $2.0 million during the year ended December 31, 2007, from $52.7 million during the year ended December 31, 2006. We recorded a $5.3 million unrealized loss and $7.3 million realized gain on our derivative contracts for the year ended December 31, 2007 compared to a $70.4 million unrealized gain and $17.7 million realized loss for the year ended December 31, 2006.

We recorded a gain from derivative financial instruments of $52.7 million for the year ended December 31, 2006 and a loss from derivative financial instruments of $73.6 million for the year ended December 31, 2005. We recorded a $70.4 million unrealized gain and $17.7 million realized loss on our derivative contracts for the year ended December 31, 2006 compared to a $46.6 million unrealized loss and $27.0 million realized loss for the year ended December 31, 2005.

Interest Expense

Interest expense, net. Interest expense, net decreased $18.3 million, or 41.8%, to $25.4 million during the year ended December 31, 2008, from $43.6 million during the year ended December 31, 2007. The decreased interest expense for the year ended December 31, 2008 relates to the write-off of $9.9 million of deferred debt

issuance costs recorded in connection with the refinancing of our credit facilities during 2007 and lower interest rates during 2008.

Interest expense, net increased $23.1 million, or 112.1%, to $43.6 million during the year ended December 31, 2007, from $20.6 million during the year ended December 31, 2006. The increased interest expense for the year ended December 31, 2007 relates to the write-off of $9.9 million of debt issuance costs recorded in connection with the refinancing of our credit facilities during 2007 and higher average outstanding debt balances during 2007.

Interest expense, net decreased $7.7 million, or 27.1%, to $20.6 million during the year ended December 31, 2006, from $28.2 million during the year ended December 31, 2005. The decrease in interest expense for the year ended December 31, 2006 is primarily due to the repayment of the ArcLight subordinated notes in November 2005, which had higher interest rates than the funds borrowed in 2006. In addition, we wrote off the deferred financing costs of $0.8 million associated with these notes in 2005. Additionally, we capitalized approximately $0.9 million more interest in 2006.

Liquidity and Capital Resources

Historical Cash Flows and Liquidity

Cash Flows from Operating Activities. Our operating cash flows are driven by the quantities of our production of oil and natural gas and the prices received from the sale of this production and revenue generated from our pipeline operating activities. Prices of oil and natural gas have historically been very volatile and can significantly impact the cash from the sale our oil and natural gas production. Use of derivative financial instruments help mitigate this price volatility. Cash expenses also impact our operating cash flow and consist primarily of oil and natural gas property operating costs, severance and ad valorem taxes, interest on our indebtedness, general and administrative expenses and taxes on income.

Cash flows from operations totaled $61.9 million for the year ended December 31, 2008 as compared to cash flows from operations of $28.8 million for the year ended December 31, 2007. The increase is attributable primarily to net cash from increased production and from higher average oil and natural gas prices in 2008 (although 2008 prices began to decline significantly in the third quarter of 2008) compared with average prices during 2007.

Cash Flows Used in Investing Activities. Net cash used in investing activities totaled $266.6 million for the year ended December 31, 2008 as compared to $272.5 million for the year ended December 31, 2007. The following table sets forth our capital expenditures by major categories in 2008 and 2007.


	Year Ended December 31,
	2008		2007
	(In thousands)

Capital expenditures:
Leasehold acquisition	$	18,945	$	15,847
Exploration		1,273		—
Development		58,070		67,586
Acquisition of PetroEdge		142,618		—
Acquisition of Seminole County, Oklahoma property		9,500		—
Acquisition of KPC		—		124,936
Pipelines		27,649		48,668
Other items (primarily capitalized overhead and interest)		9,061		7,832

Total capital expenditures	$	267,116	$	264,869

Cash Flows from Financing Activities. Net cash provided by financing activities totaled $211.8 million for the year ended December 31, 2008 as compared to $216.5 million for the year ended December 31, 2007. The cash provided from financing activities was primarily due to an increase in borrowings of $169.4 million and proceeds

from issuance of common stock of $84.8 million, partially offset by repayments of note borrowings of $15.0 million, and $24.4 million of distributions to unitholders.

Working Capital Deficit. At December 31, 2008, we had current assets of $97.8 million. Our working capital (current assets minus current liabilities, excluding the short-term derivative asset and liability of $43.0 million and $12,000, respectively) was a deficit of $41.5 million at December 31, 2008, compared to a working capital (excluding the short-term derivative asset and liability of $8.0 million and $8.1 million, respectively) deficit of $12.4 million at December 31, 2007. Amounts in 2007 included a change in working capital due to the formation of Quest Energy in November 2007 and the issuance of common units in Quest Midstream to a group of investors for approximately $75 million before expenses. Additionally, inventory, accounts payable and accrued expenses balances increased in 2008 as we expanded our operations.

Credit Agreements

Quest Resource. On July 11, 2008, the Company and Royal Bank of Canada (“RBC”) entered into an Amended and Restated Credit Agreement (the “Credit Agreement”) to convert the Company’s then-existing $50 million revolving credit facility to a $35 million term loan, due and maturing on July 11, 2010 (the “Original Term Loan”). On October 24, 2008, the Company and RBC entered into a First Amendment to Amended and Restated Credit Agreement (the “First Amendment to Credit Agreement”), which, among other things, added a $6 million term loan (the “Additional Term Loan”) to the $35 million term loan under the Credit Agreement. The maturity date for the Additional Term Loan was November 30, 2008. On October 24, 2008, the Company borrowed $2 million of the $6 million available under the Additional Term Loan. On November 4, 2008, the Company entered into a Second Amendment to Amended and Restated Credit Agreement (the “Second Amendment to Credit Agreement”) which clarified that the $6 million commitment under the Additional Term Loan would be reduced dollar for dollar to the extent the Company retained net cash proceeds from dispositions in accordance with the terms of the Credit Agreement. On January 30, 2009, the Company entered into a Third Amendment to Amended and Restated Credit Agreement (the “Third Amendment to Credit Agreement”) and on May 29, 2009, the Company entered into a Fourth Amendment to Amended and Restated Credit Agreement (the “Fourth Amendment to Credit Agreement”).

Interest accrues on the Original Term Loan, and accrued on the Additional Term Loan, at either LIBOR plus 10% (with a LIBOR floor of 3.5%) or the base rate plus 9.0%. The base rate varies daily and is generally the higher of the federal funds rate plus 0.50%, RBC’s prime rate or LIBOR plus 2.5% (but without the LIBOR floor). The Original Term Loan may be prepaid without any premium or penalty, at any time.

The Original Term Loan is payable in quarterly installments of $1.5 million on the last business day of each March, June, September and December commencing on September 30, 2008, with the remaining principal amount being payable in full on July 11, 2010. As discussed in the next paragraph, the Company has prepaid all of the quarterly principal payment requirements of $1.5 million through June 30, 2009 and therefore has no quarterly principal payments due until September 30, 2009; however the Company does not anticipate being able to make this payment. If the outstanding amount of the Original Term Loan is at any time more than 50% of the market value of the Company’s partnership interests in Quest Midstream and Quest Energy pledged to secure the loan plus the value of the Company’s Oil and Gas Properties (as defined in the Credit Agreement) pledged to secure the loan, the Company will be required to either repay the term loan by the amount of such excess or pledge additional assets to secure the term loan.

As part of the Second Amendment to Credit Agreement, the Company agreed to apply any net cash proceeds from a sale of assets or a sale of equity interests in certain subsidiaries as follows: first, to repay any amounts borrowed under the Additional Term Loan (this was done on October 30, 2008); second, to prepay the next three quarterly principal payments due on the Original Term Loan on the last business day of December 2008, March 2009 and June 2009 (this was done in October and November 2008); third, subject to certain conditions being met and the net cash proceeds being received by January 31, 2009, up to $20 million for the Company’s own use for working capital and to make capital expenditures for the development of its Oil and Gas Properties; and fourth, any excess net cash proceeds to repay the Original Term Loan. The Third Amendment to Credit Agreement provided that in connection with the sale of the Company’s Lycoming County, Pennsylvania acreage in February 2009, the

Company could retain all of the net proceeds from such sale in excess of $750,000. The Company will be required to apply all of the net cash proceeds from the issuance of any debt and 50% of the net cash proceeds from the sale of any equity securities to first repay the Original Term Loan and then to the Company.

The Second Amendment to Credit Agreement also amended and/or waived certain of the representations and covenants contained in the Credit Agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result of (1) the Transfers and (2) not timely settling certain intercompany accounts among QRCP, Quest Energy and Quest Midstream. The Fourth Amendment to Credit Agreement, among other things, waived certain events of default related to the financial covenants and collateral requirements under the Credit Agreement, extended certain financial reporting deadlines and permitted the settlement agreements with Mr. Cash discussed elsewhere in this Annual Report on Form 10-K.

Quest Oil & Gas, LLC (“QOG”), Quest Energy Service, LLC (“QES”), Quest Mergersub, Inc. and Quest Eastern guarantee all of the Company’s obligations under the Credit Agreement. The Credit Agreement is secured by a first priority lien on QRCP’s ownership interests in Quest Energy and Quest Midstream and their general partners and the Oil and Gas Properties owned by Quest Eastern in the Appalachian Basin, which are substantially all of QRCP’s assets. The assets of each of Quest Midstream GP, Quest Midstream and each of their subsidiaries and Quest Energy GP, Quest Energy and each of their subsidiaries (collectively the “Excluded MLP Entities”) are not pledged to secure the Credit Agreement.

The Credit Agreement provides that all obligations arising under the loan documents, including obligations under any hedging agreement entered into with lenders or their affiliates, will be secured pari passu by the liens granted under the loan documents.

At December 31, 2008, $29 million was outstanding under the Original Term Loan. The Additional Term Loan was repaid on October 30, 2008.

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

The Credit Agreement’s financial covenants prohibit the Company and any of its subsidiaries (excluding the Excluded MLP Entities) from:


	•	permitting the interest coverage ratio (ratio of consolidated EBITDA (or consolidated annualized EBITDA for periods ending on or before December 31, 2008) to consolidated interest charges (or consolidated annualized interest charges for periods ending on or before December 31, 2008)) at any fiscal quarter-end, commencing with the quarter-ended September 30, 2008, to be less than 2.5 to 1.0 (calculated based on the most recently delivered compliance certificate); and

	•	permitting the leverage ratio (ratio of consolidated funded debt to consolidated EBITDA (or consolidated annualized EBITDA for periods ending on or before December 31, 2008)) at any fiscal quarter-end, commencing with the quarter-ended September 30, 2008, to be greater than 2.0 to 1.0 (calculated based on the most recently delivered compliance certificate).

Consolidated EBITDA is defined in the Credit Agreement to mean for the Company and its subsidiaries (excluding the Excluded MLP Entities) on a consolidated basis, an amount equal to the sum of (i) consolidated net income, (ii) consolidated interest charges, (iii) the amount of taxes, based on or measured by income, used or included in the determination of such consolidated net income, (iv) the amount of depreciation, depletion and

amortization expense deducted in determining such consolidated net income, (v) merger and acquisition costs incurred by the Company that are required to be expensed as a result of the termination of the merger agreement with Pinnacle Gas Resources, Inc., (vi) merger and acquisition costs required to be expensed under FAS 141(R), (vii) fees and expenses of the internal investigation relating to the Misappropriation Transaction (as defined in the First Amendment to Credit Agreement) and the related restructuring which were capped at $1,500,000 for purposes of this definition and (viii) other non-cash charges and expenses deducted in the determination of such consolidated net income, including, without limitation, non-cash charges and expenses relating to swap contracts or resulting from accounting convention changes, of the Company and its subsidiaries (excluding the Excluded MLP Entities) on a consolidated basis, all determined in accordance with GAAP.

Consolidated annualized EBITDA means, for the Company and its subsidiaries (excluding the Excluded MLP Entities) on a consolidated basis, (i) for the fiscal quarter ended September 30, 2008, consolidated EBITDA for the nine month period ended September 30, 2008 multiplied by 1.33, and (ii) for the fiscal quarter ended December 31, 2008, consolidated EBITDA for the twelve month period ended December 31, 2008.

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

Consolidated annualized interest charges means, for the Company and its subsidiaries (excluding the Excluded MLP Entities) on a consolidated basis, (i) for the fiscal quarter ended September 30, 2008, consolidated interest charges for the nine month period ended September 30, 2008 multiplied by 1.33, and (ii) for the fiscal quarter ended December 31, 2008, consolidated interest charges for the twelve month period ended December 31, 2008.

Consolidated funded debt means, for the Company and its subsidiaries (excluding the Excluded MLP Entities) on a consolidated basis, the sum of (i) the outstanding principal amount of all obligations and liabilities, whether current or long-term, for borrowed money (including obligations under the Credit Agreement), (ii) all reimbursement obligations relating to letters of credit that have been drawn and remain unreimbursed, (iii) attributable indebtedness pertaining to capital leases, (iv) attributable indebtedness pertaining to synthetic lease obligations, and (v) without duplication, all guaranty obligations with respect to indebtedness of the type specified in subsections (i) through (iv) above.

Events of default under the Credit Agreement are customary for transactions of this type and include, without limitation, non-payment of principal when due, non-payment of interest, fees and other amounts for a period of three business days after the due date, failure to perform or observe covenants and agreements (subject to a 30-day cure period in certain cases), representations and warranties not being correct in any material respect when made, cross-defaults to other material indebtedness, certain acts of bankruptcy or insolvency, and change of control. Under the Credit Agreement, a change of control means the acquisition by any person, or two or more persons acting in concert, of beneficial ownership (within the meaning of Rule 13d-3 of the SEC under the Securities Exchange Act of 1934) of 50% or more of the Company’s outstanding shares of voting stock; provided, however, that a merger of the Company into another entity in which the other entity is the survivor will not be deemed a change of control if the Company’s stockholders of record as constituted immediately prior to such acquisition hold more than 50% of the outstanding shares of voting stock of the surviving entity.

Quest Energy. On November 15, 2007, Quest Energy, as a guarantor, entered into an Amended and Restated Credit Agreement (the “Quest Cherokee Credit Agreement”) with the Company, as the initial co-borrower, Quest Cherokee, as the borrower, RBC, as administrative agent and collateral agent, KeyBank National Association, as documentation agent and the lenders party thereto. Quest Cherokee and the Company had previously been parties to the following credit agreements with Guggenheim Corporate Funding, LLC (“Guggenheim”): (i) Amended and Restated Senior Credit Agreement, dated February 7, 2006, as amended; (ii) Amended and Restated Second Lien Term Loan Agreement, dated June 9, 2006, as amended; and (iii) Third Lien Term Loan Agreement, dated June 9, 2006, as amended (collectively, the “Prior Credit Agreements”). Guggenheim and the lenders under the Prior Credit

Agreements assigned all of their interests and rights (other than certain excepted interests and rights) in the Prior Credit Agreements to RBC and the new lenders under the Quest Cherokee Credit Agreement pursuant to a Loan Transfer Agreement, dated November 15, 2007, by and among the Company, Quest Cherokee, QOG, QES, Quest Cherokee Oilfield Service, LLC (“QCOS”), Guggenheim, Wells Fargo Foothill, Inc., the lenders under the Prior Credit Agreements and RBC. The Quest Cherokee Credit Agreement amended and restated the Prior Credit Agreements in their entirety. In connection with the closing of the initial public offering and the application of the net proceeds thereof, the Company was released as a borrower under the Quest Cherokee Credit Agreement. On April 15, 2008, Quest Energy and Quest Cherokee entered into a First Amendment to Amended and Restated Credit Agreement that, among other things, amended the interest rate and maturity date pursuant to the “market flex” rights contained in the commitment papers related to the Quest Cherokee Credit Agreement.

The credit facility under the Quest Cherokee Credit Agreement, as amended, consists of a three-year $250 million revolving credit facility. Availability under the revolving credit facility is tied to a borrowing base that will be redetermined by RBC and the lenders every six months taking into account the value of Quest Cherokee’s proved reserves. In addition, Quest Cherokee and RBC each have the right to initiate a redetermination of the borrowing base between each six-month redetermination. As of December 31, 2008, the borrowing base was $190 million, and the amount borrowed under the Quest Cherokee Credit Agreement was $189 million. No amounts were available for borrowing because the remaining $1.0 million was supporting letters of credit issued under the Quest Cherokee Credit Agreement.

Quest Cherokee will pay a quarterly revolving commitment fee equal to 0.30% to 0.50% (depending on the utilization percentage) of the actual daily amount by which the lesser of the aggregate revolving commitment and the borrowing base exceeds the sum of the outstanding balance of borrowings and letters of credit under the revolving credit facility.

During the Transition Period (as defined in the Quest Cherokee Credit Agreement, as amended), interest will accrue at either LIBOR plus 4.0% or the base rate plus 3.0%. After the Transition Period ends, interest will accrue at either LIBOR plus a margin ranging from 2.75% to 3.375% (depending on the utilization percentage) or the base rate plus a margin ranging from 1.75% to 2.375% (depending on the utilization percentage). The base rate varies daily and is generally the higher of the federal funds rate plus 0.50%, RBC’s prime rate or LIBOR plus 1.25%. The Transition Period will generally end once the repayment of the Second Lien Loan Agreement (discussed below) has occurred.

On July 11, 2008, concurrent with Quest Energy’s acquisition of 32.9 Bcfe of proved developed reserves in the Appalachian Basin from the Company, Quest Energy and Quest Cherokee entered into a Second Lien Senior Term Loan Agreement (the “Second Lien Loan Agreement,” together with the Quest Cherokee Credit Agreement, as amended, the “Quest Cherokee Agreements”) for a six-month, $45 million term loan. 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.

On October 28, 2008, Quest Energy and Quest Cherokee entered into a First Amendment to Second Lien Loan Agreement (the “First Amendment to Second Lien Loan Agreement”) to, among other things, extend the maturity date to September 30, 2009 and to amend and/or waive certain of the representations and covenants contained in the Second Lien Loan Agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result or (1) the Transfers and (2) not timely settling certain intercompany accounts among QRCP, Quest Energy and Quest Midstream. At the same time, a Second Amendment to the Quest Cherokee Credit Agreement was entered into to amend and/or waive certain of the representations and covenants contained in the Second Lien Loan Agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result of (1) the Transfers and (2) not timely settling certain intercompany accounts among QRCP, Quest Energy and Quest Midstream.

The First Amendment to Second Lien Loan Agreement requires Quest Cherokee to make repayments of principal in quarterly installments of $3.8 million on the 15th day of each February, May, August and November while amounts borrowed under the Second Lien Loan Agreement are outstanding. As of December 31, 2008, $41.2 million was outstanding under the Second Lien Loan Agreement.

Interest accrues on the term loan at either LIBOR plus 9.0% (with a LIBOR floor of 3.5%) or the base rate plus 8.0%. The base rate varies daily and is generally the higher of the federal funds rate plus 0.5%, RBC’s prime rate or LIBOR plus 1.25%. The term loan may be prepaid without any premium or penalty, at any time.

Subject to certain restrictions, Quest Cherokee and its subsidiaries are required to apply all net cash proceeds from sales of assets that yield gross proceeds of over $5 million to repay the term loan. Under the terms of the Second Lien Loan Agreement, Quest Energy is required by June 30, 2009 to (i) complete a private placement of its equity securities or debt, (ii) engage one or more investment banks reasonably satisfactory to RBC Capital Markets to publicly sell or privately place common equity securities or debt of Quest Energy, which offering must close prior to August 14, 2009 (the deadline for closing and funding the securities offering may be extended up until September 30, 2009) or (iii) engage RBC Capital Markets to arrange financing to refinance the term loan under the Second Lien Loan Agreement on the prevailing terms in the credit market.

The Quest Cherokee Agreements restrict the amount of quarterly distributions Quest Energy may declare and pay to its unitholders to not exceed $0.40 per common unit per quarter as long as the term loan has not been paid in full. Further, after giving effect to each quarterly distribution, Quest Energy and Quest Cherokee must be in compliance with a financial covenant that prohibits each of Quest Cherokee, Quest Energy or any of their respective subsidiaries from permitting Available Liquidity (as defined in the Quest Cherokee Agreements) to be less than $14 million at March 31, 2009 and to be less than $20 million at June 30, 2009. The $3.8 million quarterly principal payments discussed above must also be paid before any distributions may be paid. Quest Cherokee’s capital expenditures are limited to $30 million for 2009.

Quest Energy and QCOS guarantee all of Quest Cherokee’s obligations under the Quest Cherokee Agreements. The revolving credit facility is secured by a first priority lien on substantially all of the assets of Quest Energy, Quest Cherokee and QCOS. The term loan is secured by a second priority lien on substantially all of the assets of Quest Energy, Quest Cherokee and QCOS.

The Quest Cherokee Agreements provide that all obligations arising under the loan documents, including obligations under any hedging agreement entered into with lenders or their affiliates, will be secured pari passu by the liens granted under the loan documents.

Quest Energy, Quest Cherokee, Quest Energy GP and their subsidiaries are required to make certain representations and warranties that are customary for credit agreements of these types. The Quest Cherokee Agreements also contain affirmative and negative covenants that are customary for credit agreements of these types. The covenants in the Quest Cherokee Agreements include, without limitation, periodic delivery of financial statements and other financial information; notice of defaults and certain other matters; payment of obligations; preservation of legal existence and good standing; maintenance of assets and business; maintenance of insurance; compliance with laws and contractual obligations; maintenance of books and records; inspection rights; limitations on use of proceeds; execution of guaranties by subsidiaries; perfecting security interests in after-acquired property; curing title defects; maintaining material leases; operation of properties; notification of change of purchasers of production; maintenance of fiscal year; certain limitations on liens, investments, hedging agreements, indebtedness, lease obligations, fundamental changes, dispositions of assets, restricted payments, distributions and redemptions, nature of business, capital expenditures and risk management, transactions with affiliates, and burdensome agreements; and compliance with financial covenants.

The Quest Cherokee Agreements’ financial covenants prohibit Quest Cherokee, Quest Energy and any of their subsidiaries from:


	•	permitting the ratio (calculated based on the most recently delivered compliance certificate) of Quest Energy’s consolidated current assets (including the unused availability under the revolving credit facility, but excluding non-cash assets under FAS 133) to consolidated current liabilities (excluding non-cash obligations under FAS 133, asset and asset retirement obligations and current maturities of indebtedness under the Quest Cherokee Credit Agreement) at any fiscal quarter-end to be less than 1.0 to 1.0; provided, however, that current assets and current liabilities will exclude mark-to-market values of swap contracts, to the extent such values are included in current assets and current liabilities;


	•	permitting the interest coverage ratio (calculated on the most recently delivered compliance certificate) of adjusted consolidated EBITDA to consolidated interest charges at any fiscal quarter-end to be less than 2.5 to 1.0 measured on a rolling four quarter basis; and

	•	permitting the leverage ratio (calculated based on the most recently delivered compliance certificate) of consolidated funded debt to adjusted consolidated EBITDA at any fiscal quarter-end to be greater than 3.5 to 1.0 measured on a rolling four quarter basis.

The Second Lien Loan Agreement contains an additional financial covenant that prohibits Quest Cherokee, Quest Energy and any of their subsidiaries from permitting the total reserve leverage ratio (ratio of total proved reserves to consolidated funded debt) at any fiscal quarter-end (calculated based on the most recently delivered compliance certificate) to be less than 1.5 to 1.0.

Adjusted consolidated EBITDA is defined in the Quest Cherokee Agreements to mean the sum of (i) consolidated EBITDA plus (ii) the distribution equivalent amount (for each fiscal quarter of Quest Energy, the amount of cash paid to the members of Quest Energy GP’s management group and non-management directors with respect to restricted common units, bonus units and/or phantom units of Quest Energy that are required under GAAP to be treated as compensation expense prior to vesting (and which, upon vesting, are treated as limited partner distributions under GAAP)).

Consolidated EBITDA is defined in the Quest Cherokee Agreements to mean for Quest Energy and its subsidiaries on a consolidated basis, an amount equal to the sum of (i) consolidated net income, (ii) consolidated interest charges, (iii) the amount of taxes, based on or measured by income, used or included in the determination of such consolidated net income, (iv) the amount of depreciation, depletion and amortization expense deducted in determining such consolidated net income, (v) acquisition costs required to be expensed under FAS 141(R), (vi) fees and expenses of the internal investigation relating to the Misappropriation Transaction and the related restructuring (which shall be capped at $1,500,000 for purposes of this definition), and (vii) other non-cash charges and expenses, including, without limitation, non-cash charges and expenses relating to swap contracts or resulting from accounting convention changes, of Quest Energy and its subsidiaries on a consolidated basis, all determined in accordance with GAAP.

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

Consolidated funded debt is defined to mean for Quest Energy and its subsidiaries on a consolidated basis, the sum of (i) the outstanding principal amount of all obligations and liabilities, whether current or long-term, for borrowed money (including obligations under the Quest Cherokee Agreements, but excluding all reimbursement obligations relating to outstanding but undrawn letters of credit), (ii) attributable indebtedness pertaining to capital leases, (iii) attributable indebtedness pertaining to synthetic lease obligations, and (iv) without duplication, all guaranty obligations with respect to indebtedness of the type specified in subsections (i) through (iii) above.

Events of default under the Quest Cherokee Agreements are customary for transactions of this type and include, without limitation, non-payment of principal when due, non-payment of interest, fees and other amounts for a period of three business days after the due date, failure to perform or observe covenants and agreements (subject to a 30-day cure period in certain cases), representations and warranties not being correct in any material respect when made, certain acts of bankruptcy or insolvency, cross defaults to other material indebtedness, borrowing base deficiencies, and change of control. Under the Quest Cherokee Agreements, a change of control means (i) the Company fails to own or to have voting control over at least 51% of the equity interest of Quest Energy GP, (ii) any person acquires beneficial ownership of 51% or more of the equity interest in Quest Energy; (iii) Quest Energy fails to own 100% of the equity interests in Quest Cherokee, or (iv) the Company undergoes a change in control (the acquisition by a person, or two or more persons acting in concert, of beneficial ownership of 50% or more of the Company’s outstanding shares of voting stock, except for a merger with and into another entity where

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the other entity is the survivor if the Company’s stockholders of record immediately preceding the merger hold more than 50% of the outstanding shares of the surviving entity).

Quest Midstream. Quest Midstream and its wholly-owned subsidiary, Bluestem, have a separate $135 million syndicated revolving credit facility. On November 1, 2007, Quest Midstream and Bluestem entered into an Amended and Restated Credit Agreement and First Amendment to Amended and Restated Credit Agreement (together, the “Quest Midstream Credit Agreement”) with RBC, as administrative agent and collateral agent, and the lenders party thereto. On October 28, 2008, Quest Midstream and Bluestem entered into a Second Amendment to the Quest Midstream Credit Agreement (the “Quest Midstream Second Amendment”). The Quest Midstream Credit Agreement together with the Quest Midstream Second Amendment are referred to collectively as the “Amended Quest Midstream Credit Agreement.” As of December 31, 2008, the amount borrowed under the Amended Quest Midstream Credit Agreement was $128 million.

The Quest Midstream Second Amendment, among other things, amended and/or waived certain of the representations and covenants contained in the Quest Midstream Credit Agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result of (1) the Transfers and (2) not timely settling certain intercompany accounts among QRCP, Quest Energy and Quest Midstream.

Quest Midstream and Bluestem may, from time to time, request an increase in the $135 million commitment by an amount in the aggregate not exceeding $75 million. However, the lenders are under no obligation to increase the revolving credit facility upon such request.

Quest Midstream and Bluestem will pay a quarterly revolving commitment fee equal to 0.375% to 0.50% (depending on the total leverage ratio) on the difference between $135 million and the outstanding balance of borrowings and letters of credit under the revolving credit facility.

During the Transition Period (as defined in the Amended Quest Midstream Credit Agreement), interest will accrue on the revolving credit facility at either LIBOR plus 4% or the base rate plus 3.0%. After the Transition Period ends, interest will accrue at either LIBOR plus a margin ranging from 2.0% to 3.50% (depending on the total leverage ratio) or the base rate plus a margin ranging from 1.0% to 2.5% (depending on the total leverage ratio), at our option. The base rate is generally the higher of the federal funds rate plus 0.50%, RBC’s prime rate or LIBOR plus 1.25%. The Transition Period ended on March 31, 2009 when Quest Midstream audited financial statements for 2008 were delivered to RBC.

If the total leverage ratio is greater than 4.5 to 1.0 for any fiscal quarter ending on or after December 31, 2008, Quest Midstream and Bluestem must prepay the revolving loans in an amount equal to 75% of Excess Cash Flow (as defined in the Amended Quest Midstream Credit Agreement) for such fiscal quarter. Additionally, the lenders’ revolving commitment will be temporarily reduced dollar for dollar by the amount of any such prepayment. Once the total leverage ratio is less than 4.0 to 1.0 at the end of any fiscal quarter, any reductions in the revolving commitments will be reinstated and no further prepayments will be required.

The Amended Quest Midstream Credit Agreement places limitations on capital expenditures for each of Quest Midstream and Bluestem as follows: (i) $5 million for the fourth fiscal quarter of 2008; (ii) $7 million for the first fiscal quarter of 2009; (iii) $7 million for the second fiscal quarter of 2009; (iv) $3 million for the third fiscal quarter of 2009; and (v) $3 million for the fourth fiscal quarter of 2009.

The Amended Quest Midstream Credit Agreement restricts Quest Midstream’s ability to make distributions on its units unless the total leverage ratio is not greater than 4.0 to 1.0 after giving effect to the quarterly distribution.

Quest Kansas General Partner, Quest Kansas Pipeline, and Quest KPC guarantee all of Quest Midstream’s and Bluestem’s obligations under the Amended Quest Midstream Credit Agreement. The revolving credit facility is secured by a first priority lien on substantially all of the assets of Quest Midstream and Bluestem and their subsidiaries (including the KPC Pipeline).

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The Amended Quest Midstream Credit Agreement provides that all obligations arising under the loan documents, including obligations under any hedging agreement entered into with lenders or their affiliates, will be secured pari passu by the liens granted under the loan documents.

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

The Amended Quest Midstream Credit Agreement’s financial covenants prohibit Bluestem, Quest Midstream and any of their subsidiaries from:


	•	permitting the interest coverage ratio (ratio of adjusted consolidated EBITDA to consolidated interest charges) on a rolling four quarter basis (calculated based on the most recently delivered compliance certificate), commencing with the fiscal quarter ending December 31, 2007, to be less than 2.50 to 1.00 for any fiscal quarter ending on or prior to December 31, 2008, increasing to 2.75 to 1.00 for each fiscal quarter end thereafter; and

	•	permitting the total leverage ratio (ratio of adjusted consolidated funded debt to adjusted consolidated EBITDA) on a rolling four quarter basis (calculated based on the most recently delivered compliance certificate), commencing with the fiscal quarter ending December 31, 2007 and ending December 31, 2008, to be greater than 5.00 to 1.00, decreasing to 4.50 to 1.00 for each fiscal quarter end thereafter.

Adjusted consolidated EBITDA is defined in the Amended Quest Midstream Credit Agreement to mean the sum of (i) consolidated EBITDA plus (ii) the distribution equivalent amount (for each fiscal quarter of Quest Midstream, the amount of cash paid to the members of Quest Midstream GP’s management group and non-management directors with respect to restricted common units, bonus units and/or phantom units of Quest Midstream that are required under GAAP to be treated as compensation expense prior to vesting (and which, upon vesting, are treated as limited partner distributions under GAAP)).

Consolidated EBITDA is defined in the Amended Quest Midstream Credit Agreement for Quest Midstream and its subsidiaries on a consolidated basis, an amount equal to the sum of (i) consolidated net income, (ii) consolidated interest charges, (iii) the amount of taxes, based on or measured by income, used or included in the determination of consolidated net income, (iv) the amount of depreciation, depletion and amortization expense deducted in determining consolidated net income, (v) merger and acquisition costs required to be expensed under FAS 141(R), (vi) fees and expenses of the internal investigation relating to the Misappropriation Transaction and the related restructuring which are capped at $1,500,000 for purposes of the definition of Consolidated EBITDA and (vii) other non-cash charges and expenses, including, without limitation, non-cash charges and expenses related to swap contracts or resulting from accounting convention changes, of Quest Midstream and its subsidiaries on a consolidated basis, all determined in accordance with GAAP.

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

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

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

Events of default under the Amended Quest Midstream Credit Agreement are customary for transactions of this type and include, without limitation, non-payment of principal when due, non-payment of interest, fees and other amounts for a period of three business days after the due date, failure to perform or observe covenants and agreements (subject to a 30-day cure period in certain cases), representations and warranties not being correct in any material respect when made, certain acts of bankruptcy or insolvency, cross defaults to other material indebtedness, and change of control. Under the Quest Midstream Credit Agreement a change of control means (i) the Company fails to own or to have voting control over, at least 51% of the equity interest of Quest Midstream GP; (ii) any person acquires beneficial ownership of 51% or more of the equity interest in Quest Midstream; (iii) Quest Midstream fails to own 100% of the equity interests in Bluestem or (iv) the Company undergoes a change in control (the acquisition by a person, or two or more persons acting in concert, of beneficial ownership of 50% or more of the Company’s outstanding shares of voting stock, except for a merger with and into another entity where the other entity is the survivor if the Company’s stockholders of record immediately preceding the merger hold more than 50% of the outstanding shares of the surviving entity).

Sources of Liquidity in 2009 and Capital Requirements

Quest Resource. Since the initial public offering of Quest Energy in November 2007, QRCP’s potential sources of revenue and cash flows consist almost exclusively of distributions on its partnership interests in Quest Energy and Quest Midstream, because its Appalachian assets largely consist of undeveloped acreage. While QRCP has historically been successful in raising additional funds through issuing equity securities and proceeds from borrowings, in the current capital markets, we do not expect QRCP to be able to raise any funds through the issuance of debt or equity under our current organizational structure.

Quest Energy is required by its partnership agreement to distribute all its cash on hand at the end of each quarter, less reserves established by its general partner in its sole discretion to provide for the proper conduct of Quest Energy’s business or to provide for future distributions.

Through QRCP’s ownership of Quest Energy GP, it also owns the incentive distribution rights in Quest Energy, which would entitle it to receive an increasing percentage of cash distributed by Quest Energy as certain target distribution levels are reached. Specifically, they entitle QRCP to receive 13.0% of all cash distributed in a quarter after each unit has received $0.46 for that quarter, and 23.0% of all cash distributed after each unit has received $0.50 for that quarter. Quest Energy has not paid any quarterly distributions in excess of the first target distribution level, and as a result, QRCP has not received any incentive distributions.

Quest Energy paid quarterly distributions at or slightly above the $0.40 per unit minimum quarterly distribution amount on all of its units for the fourth quarter of 2007 (pro rated) and the first and second quarters of 2008. It paid the $0.40 minimum quarterly distribution amount on only its common units for the third quarter of 2008 and has not paid any distributions on any of its units for any subsequent periods.

Quest Energy suspended distributions on its subordinated units beginning with the third quarter of 2008 as a result of the amendments to the Quest Cherokee Agreements which required quarterly payments under its Second Lien Loan Agreement equal to $3.8 million (the amount of the minimum quarterly distribution for its subordinated units). Quest Energy suspended distributions on all of its units beginning with the fourth quarter of 2008 as a result

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of a decline in its cash flows from operations due to declines in oil and natural gas prices during the last half of 2008, the costs of the investigation and associated remedial actions, including the reaudit and restatement of its consolidated financial statements, and concerns about a potential borrowing base redetermination in the second quarter of 2009 and the need to repay or refinance the Second Lien Loan Agreement by September 30, 2009.

The partnership agreement for Quest Midstream contains similar provisions relating to the distribution of available cash. However, most of QRCP’s interest in Quest Midstream is in the form of subordinated units and Quest Midstream generally has not paid any distributions on its subordinated units. As a result, QRCP has not received any material distributions from Quest Midstream.

At this time, we are not able to estimate when Quest Midstream and/or Quest Energy will resume the payment of distributions.

In addition, QRCP also receives reimbursements by Quest Energy and Quest Midstream for general and administrative expenses incurred by it on their behalf and allocated to them. However, these reimbursements do not cover all of QRCP’s general and administrative expenses.

In response to the recent developments, QRCP has adjusted its business strategy for 2009 to focus on negotiating documentation and other activities necessary to complete the Recombination while still maintaining a stable asset base, improving the profitability of its assets by increasing their utilization while controlling costs and reducing capital expenditures as discussed elsewhere in this Annual Report on Form 10-K, renegotiating with its lenders and possibly raising equity capital. For 2009, QRCP has budgeted approximately $2.4 million of net expenditures to drill one gross vertical well, complete three gross wells and connect four gross wells in the Appalachian Basin. This one new well will be drilled on a location that is classified as containing proved reserves in our December 31, 2008 reserve report. However, QRCP intends to fund these capital expenditures only to the extent that it has available cash after taking into account its debt service and other obligations. We can give no assurance that any such funds will be available.

As discussed above under “— Credit Agreements — Quest Resource,” QRCP is required to maintain as of the end of each quarter, an Interest Coverage Ratio of not less than 2.5 to 1.0 and a Leverage Ratio of no more than 2.0 to 1.0. As a result of the suspension of the distributions to QRCP from Quest Energy and Quest Midstream discussed above, QRCP was not in compliance with these financial covenants as of December 31, 2008 and March 31, 2009 and QRCP does not anticipate that it will be in compliance at any time in the foreseeable future. On May 29, 2009, QRCP obtained a waiver of these defaults from its lenders for the quarters ended December 31, 2008 and March 31, 2009 and is currently negotiating with its lender to obtain a waiver of these requirements for future periods. There can be no assurance that QRCP will be able to obtain such waivers.

Under the terms of the Credit Agreement, QRCP is required to make quarterly principal payments of $1.5 million. QRCP has prepaid the quarterly principal payments through and including June 30, 2009 and its next quarterly principal payment is due September 30, 2009. QRCP currently does anticipate being able to make this payment and is negotiating with its lenders to obtain a waiver. There can be no assurance that QRCP will be able to obtain such waiver.

Under the terms of the Credit Agreement, the outstanding principal amount of borrowings may not exceed the sum of (i) the value of QRCP’s oil and gas properties in the Appalachian Basin (as determined by the administrative agent under the Credit Agreement in its reasonable discretion) and (ii) 50% of the market value of QRCP’s interests in Quest Energy and Quest Midstream (such excess is referred to as a “Collateral Deficiency”). QRCP is required to make a mandatory prepayment equal to any such Collateral Deficiency. On May 29, 2009, QRCP obtained a waiver of this mandatory prepayment for the quarters ended December 31, 2008, March 31, 2009 and June 30, 2009. If a Collateral Deficiency exists after June 30, 2009 that is not waived by QRCP’s lender, QRCP will be required to sell assets, issue additional equity securities or refinance the Credit Agreement in order to cure such deficiency. There can be no assurance that QRCP will be successful in raising sufficient funds to cure such deficiency in the future. QRCP is currently negotiating with its lenders to obtain a waiver of this requirement for future periods. There can be no assurance that QRCP will be able to obtain such a waiver.

In addition, QRCP failed to timely deliver its 2008 audited financial statements to its lender. QRCP has received an extension of this deadline to June 30, 2009.

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As of December 31, 2008, QRCP had cash and cash equivalents of $4.0 million and no ability to borrow under the terms of the Credit Agreement. QRCP currently estimates that it will not have enough cash to pay its expenses, including capital expenditures and debt service requirements after August 31, 2009. This date could be extended if QRCP is able to restructure its debt obligations, issue equity securities and/or sell additional assets. Our independent registered public accounting firm has expressed doubt about our ability to continue as a going concern. See Item 1A. “Risk Factors — Our independent registered public accounting firm has expressed substantial doubt about our ability to continue as a going concern.” If QRCP is not successful in obtaining sufficient additional funds, there is a significant risk that QRCP will be forced to file for bankruptcy protection.

Quest Energy. Historically, Quest Energy has been successful in accessing capital from financial institutions to fund the growth of its operations and in generating sufficient cash flow from its operations to satisfy its debt service requirements, operating expenses, maintenance capital expenditures and distributions to its unitholders. However, due to the lack of liquidity in the financial and equity markets coupled with the significant decline in oil and natural gas prices in the second half of 2008 and the uncertainties associated with Quest Energy’s financial condition as a result of the matters relating to the internal investigation and the restatement of our consolidated financial statements, Quest Energy’s access to capital has been, and is expected to continue to be, severely limited in 2009. As a result, Quest Energy has significantly reduced its growth plans during 2009 in order to maximize the amount of cash flow from operations that is available to repay indebtedness.

For 2009, QELP has budgeted approximately $3.8 million to drill seven new gross wells, connect and complete 49 existing gross wells, and connect and complete three existing salt water disposal wells in the Cherokee Basin. All of these wells will be drilled on locations that are classified as containing proved reserves in our December 31, 2008 reserve report. In 2009, QELP plans to recomplete an estimated 10 gross wells, and has budgeted another $1.9 million for equipment, vehicle replacement, and other capital purchases. In addition, QELP has budgeted $2.4 million related to lease renewals and extensions for Cherokee Basin acreage that is expiring in 2009. Additionally, QELP has budgeted for 2009 $1.4 million for artificial lift equipment, vehicle replacement and purchases and salt water disposal activities in the Appalachian Basin. However, QELP intends to fund these capital expenditures only to the extent that QELP has available cash from operations after taking into account its debt service obligations. We can give no assurance that any such funds will be available. As discussed above under “— Quest Resource”, Quest Energy has suspended distributions on its common and subordinated units and does not intend to resume distributions until after it has repaid its Second Lien Loan Agreement, at the earliest.

As discussed above under “— Credit Agreements — Quest Energy,” Quest Energy is required to be in compliance as of the end of each quarter with certain financial ratios. As of December 31, 2008, Quest Energy was in compliance with all of its financial covenants.

Quest Energy is expected to be in compliance with the Total Reserve Leverage Ratio as of March 31, 2009. However, there can be no assurance that Quest Energy will be able to remain in compliance with this ratio in future periods in light of the significantly reduced capital expenditures program and low natural gas prices.

In addition, Quest Energy is required to have Available Liquidity of $14 million and $20 million as of March 31, 2009 and June 30, 2009, respectively. Available Liquidity is generally defined in the Quest Cherokee Agreements as cash and cash equivalents, plus any availability under its revolving credit facility, plus any reductions in the principal amount of its Second Lien Loan Agreement in excess of the $3.8 million required per quarter. Quest Energy is not anticipated to be in compliance with this covenant as of June 30, 2009. Quest Energy is currently negotiating with its lenders to obtain a waiver of this covenant.

As discussed above under “— Credit Agreements — Quest Energy”, the amount available under the Quest Cherokee Credit Agreement may not exceed a borrowing base, which is subject to redetermination on a semi-annual basis. The price of oil and gas has significantly decreased since the borrowing base was last redetermined. The lead agent for QELP’s credit agreement initially proposed that QELP’s borrowing base be reduced, as part of the redetermination being made in connection with the delivery of its year-end reserve report to its lenders, by approximately $50 million to $140 million. However, the actual borrowing base may be more or less than this amount. Under the terms of the Quest Cherokee Credit Agreement, Quest Energy is required to reduce the amount outstanding under the Quest Cherokee Credit Agreement by the amount that the outstanding borrowings exceed the amount of the new borrowing base (which is referred to as a “Borrowing Base Deficiency”). Quest Energy will be

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required to repay the amount of the Borrowing Base Deficiency in four equal monthly installments after such amount has been determined. Quest Energy is currently pursuing various alternatives, including entering into additional derivative contracts and/or repricing existing derivative contracts in order to reduce the borrowing base deficiency. There can be no assurance that such efforts will be successful or that Quest Energy will be able to repay any remaining amount of the Borrowing Base Deficiency in accordance with the terms of the Quest Cherokee Credit Agreement. See “Risk Factors — Risks Related to Our Business — The QELP borrowing base under its first lien credit agreement could be redetermined to an amount that creates a deficiency that QELP does not have the ability to pay.”

Under the terms of Quest Energy’s Second Lien Loan Agreement, Quest Energy is required to make quarterly principal payments of $3.8 million. The next payment is due August 15, 2009. The balance remaining after such payments of $29.8 million is due on September 30, 2009. Due to the likely principal payments required to be made under the Quest Cherokee Credit Agreement in connection with the Borrowing Base Deficiency, Quest Energy is currently seeking to restructure the required principal payments under its Second Lien Loan Agreement; however, there can be no assurance that Quest Energy will be successful in restructuring such principal payments.

Quest Energy is actively pursuing lawsuits against the former chief financial officer and purchasing manager and others related to the matters arising out of the investigation. There can be no assurance that it will be successful in collecting any amounts in settlement of such claims.

As of May 15, 2009, Quest Energy had $14.6 million of cash and cash equivalents. Based on our current estimates of Quest Energy’s operating and administrative expenses and budgeted capital expenditures, we anticipate that Quest Energy would have sufficient resources to satisfy these expenditures for the foreseeable future, if it can restructure its debt service obligations discussed above.

Quest Midstream. Historically, Quest Midstream has been successful in accessing capital from both the equity market and financial institutions to fund the growth of its operations and in generating sufficient cash flow from its operations to satisfy its debt service requirements, operating expenses, maintenance capital expenditures and distributions to its unitholders. However, due to the lack of liquidity in the financial and equity markets coupled with the leveling off of production by Quest Energy and the uncertainties associated with Quest Midstream’s financial condition as a result of the matters relating to the internal investigation and the restatement of our financial statements, Quest Midstream’s access to capital has been, and is expected to continue to be, severely limited in 2009. As a result, Quest Midstream has significantly reduced its growth plans during 2009 in order to maximize the amount of cash flow from operations that is available to repay indebtedness. We estimate that our cost for pipeline infrastructure to connect a Cherokee Basin well will be approximately $61,000 per well for 2009. If commodity prices improve, we expect to connect 56 wells in the Cherokee Basin in 2009.

As discussed above under “— Quest Resource,” Quest Midstream is restricted from paying distributions on its common and subordinated units until its leverage ratio is less than or equal to 4.0 to 1.0. At this time, we are unable to estimate when Quest Midstream will satisfy this requirement.

As discussed above under “— Credit Agreements — Quest Midstream,” Quest Midstream is required to be in compliance as of the end of each quarter, with certain financial ratios. As of December 31, 2008, Quest Midstream was in compliance with all of its financial covenants.

As of May 15, 2009, Quest Midstream had $3.7 million of cash and cash equivalents. Based on our current estimates of Quest Midstream’s operating and administrative expenses and budgeted capital expenditures, we anticipate that Quest Midstream would have sufficient resources to satisfy its obligations for the foreseeable future.

Recombination. In connection with the proposed Recombination, we intend to enter into a credit facility that would refinance all of our existing credit agreements. There can be no assurance that we will be able to obtain such a credit facility on terms favorable to us, if at all. The lenders for any such new credit facility may require us to obtain additional equity capital as a condition to such a new credit facility. There can be no assurance that we will be able to obtain any additional equity capital on terms favorable to us, if at all.

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Contractual Obligations

We have numerous contractual commitments in the ordinary course of business, debt service requirements and operating lease commitments. The following table summarizes these commitments at December 31, 2008:


	Payments Due by Period
			Less Than		1-3		4-5		More Than
	Total		1 Year		Years		Years		5 Years
	(In thousands)

Term Loan — Quest Resource		29,000		3,000		26,000		—		—
Revolving Credit Facility — Quest Energy		189,000		—		189,000		—		—
Term Loan — Quest Energy		41,200		41,200		—		—		—
Revolving Credit Facility — Quest Midstream		128,000		—		—		128,000		—
Other Note obligations		906		813		79		13		1
Interest expense on bank credit facilities(1)		52,411		21,647		24,355		6,409		—
Operating lease obligations		14,549		4,922		3,934		3,003		2,690
Financial advisor contracts		2,675		675		2,000		—		—

Total commitments	$	457,741	$	72,257	$	245,368	$	137,425	$	2,691


(1)		The interest payment obligation was computed using the LIBOR interest rate as of December 31, 2008. Assumes no reduction in the outstanding principal amount borrowed under the revolving credit facilities prior to maturity.

Off-balance Sheet Arrangements

At December 31, 2008, we did not have any relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. In addition, we do not engage in trading activities involving non-exchange traded contracts. As such, we are not exposed to any financing, liquidity, market, or credit risk that could arise if we had engaged in such activities.

Critical Accounting Policies

The preparation of our consolidated financial statements requires us to make assumptions and estimates that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated the financial statements and the reported amounts of revenues and expenses during the reporting periods. We base our estimates on historical experiences and various other assumptions that we believe are reasonable; however, actual results may differ. Our significant accounting policies are described in Note 2 — Summary of Significant Accounting Policies to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements.

Oil and Gas Reserves

Our most significant financial estimates are based on estimates of proved oil and gas reserves. Proved reserves represent estimated quantities of oil and gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production, and timing of development expenditures, including many factors beyond our control. The estimation process relies on assumptions and interpretations of available geologic, geophysical, engineering, and production data and, the accuracy of reserves estimates is a function of the quality and quantity of available data, engineering and geologic interpretation, and judgment. In addition, as a result of changing market conditions, commodity prices and future development costs will change from year to year, causing estimates of proved reserves to also change. Estimates of proved reserves are key components of our most significant financial estimates involving our unevaluated properties, our rate for recording depreciation, depletion

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and amortization and our full cost ceiling limitation. Our reserves are estimated on an annual basis by independent petroleum engineers.

In December 2008, the SEC released the final rule for the “Modernization of Oil and Gas Reporting.” The rule’s disclosure requirements will permit reporting of oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices and the use of new technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Companies will also be allowed to disclose probable and possible reserves in SEC filed documents. In addition, companies will be required to report the independence and qualifications of its reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit. The rule’s disclosure requirements become effective for our Annual Report on Form 10-K for the year ended December 31, 2009. The SEC is coordinating with the FASB to obtain the revisions necessary to provide consistency with the new rules. In the event that consistency is not achieved in time for companies to comply with the new rules, the SEC will consider delaying the compliance date. The calculation of reserves using an average price is a significant change that should reduce the volatility of our reserve calculation and could impact any potential future impairments arising from our ceiling test.

Oil and Gas Properties

The method of accounting for oil and natural gas properties determines what costs are capitalized and how these cost are ultimately matched with revenues and expenses. We use the full cost method of accounting for oil and natural gas and oil properties. Under the full cost method, all direct costs and certain indirect costs associated with the acquisition, exploration, and development of our oil and gas properties are capitalized.

Oil and gas properties are depleted using the units-of-production method. The depletion expense is significantly affected by the unamortized historical and future development costs and the estimated proved oil and gas reserves. Estimation of proved oil and gas reserves relies on professional judgment and use of factors that cannot be precisely determined. Holding all other factors constant, if proved oil and gas reserves were revised upward or downward, earnings would increase or decrease, respectively. Subsequent proved reserve estimates materially different from those reported would change the depletion expense recognized during the future reporting period. No gains or losses are recognized upon the sale or disposition of oil and gas properties unless the sale or disposition represents a significant quantity of reserves, which would have a significant impact on the depreciation, depletion, and amortization rate.

Under the full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of future net revenues, discounted at 10% per annum, plus the lower of cost or fair value of unevaluated properties less income tax effects (the “ceiling limitation”). We perform a quarterly ceiling test to evaluate whether the net book value of our full cost pool exceeds the ceiling limitation. If capitalized costs (net of accumulated depreciation, depletion, and amortization) less related deferred taxes are greater than the discounted future net revenues or ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of our full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation, depletion, and amortization expense in future periods. Once incurred, a write-down is not reversible at a later date. The risk that we will be required to write down the carrying value of our oil and gas properties increases when gas prices are depressed, even if low prices are temporary. In addition, a write-down may occur if estimates of proved reserves are substantially reduced or estimates of future development costs increase significantly.

The ceiling test is calculated using natural gas prices in effect as of the balance sheet date and adjusted for “basis” or location differential, held constant over the life of the reserves. In addition, subsequent to the adoption of SFAS 143, Accounting for Asset Retirement Obligations, the future cash outflows associated with settling asset retirement obligations are not included in the computation of the discounted present value of future net revenues for the purpose of the ceiling test calculation.

Unevaluated Properties

The costs directly associated with unevaluated properties and properties under development are not initially included in the amortization base and relate to unproved leasehold acreage, seismic data, wells and production

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facilities in progress and wells pending determination together with interest costs capitalized for these projects. Unevaluated leasehold costs are transferred to the amortization base once determination has been made or upon expiration of a lease. Geological and geophysical costs associated with a specific unevaluated property are transferred to the amortization base with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. All items included in our unevaluated property balance are assessed on a quarterly basis for possible impairment or reduction in value. Any impairment to unevaluated properties is transferred to the amortization base. See Note 21 — Supplemental Information on Oil and Gas Producing Activities (Unaudited) in the notes to the consolidated financial statements for a summary by year of unevaluated costs.

Future Abandonment Costs

We have significant legal obligations to plug, abandon and dismantle existing wells and facilities that we have acquired, constructed, or developed. Liabilities for asset retirement obligations are recorded at fair value in the period incurred. Upon initial recognition of the asset retirement liability, the asset retirement cost is capitalized by increasing the carrying amount of the long-lived asset by the same amount as the liability. Asset retirement costs included in the carrying amount of the related asset are subsequently allocated to expense as part of our depletion calculation. Additionally, increases in the discounted asset retirement liability resulting from the passage of time are recorded as lease operating expense.

Estimating the future asset retirement liability requires us to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. We use the present value of estimated cash flows related to our asset retirement obligations to determine the fair value. Present value calculations inherently incorporate numerous assumptions and judgments. These include the ultimate retirement and restoration costs, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing assets retirement liability, a corresponding adjustment will be made to the carrying cost of the related asset.

We have not recorded any asset retirement obligations relating to our gathering systems as of December 31, 2008, 2007 and 2006 because we do not have any legal or constructive obligations relative to asset retirements of the gathering systems. We have recorded asset retirement obligations relating to the abandonment of our interstate pipeline assets (see discussion in Note 9 — Asset Retirement Obligations to the consolidated financial statements).

Derivative Instruments

Due to the historical volatility of oil and natural gas prices, we have implemented a hedging strategy aimed at reducing the variability of prices we receive for our production. Currently, we use collars, fixed-price swaps and fixed price sales contracts as our mechanism for hedging commodity prices. Our current derivative instruments are not accounted for as hedges for accounting purposes in accordance with SFAS No. 133, Derivative Instruments and Hedging Activities. As a result, we account for our derivative instruments on a mark-to-market basis, and changes in the fair value of derivative instruments are recognized as gains and losses which are included in other income and expense in the period of change. While we believe that the stabilization of prices and production afforded us by providing a revenue floor for our production is beneficial, this strategy may result in lower revenues than we would have if we were not a party to derivative instruments in times of rising natural gas prices. As a result of rising commodity prices, we may recognize additional charges to future periods; however, for the year ended December 31, 2008 prices decreased, and we recognized a total gain on derivative financial instruments in the amount of $80.7 million, consisting of a $7.3 million realized gain and a $73.4 million unrealized gain. Our estimates of fair value are determined by the use of an option-pricing model that is based on various assumptions and factors including the time value of options, volatility, and closing NYMEX market indices.

Revenue Recognition

We derive revenue from our oil and natural gas operations from the sale of produced oil and natural gas. We use the sales method of accounting for the recognition of oil and gas revenue. Because there is a ready market for oil and natural gas, we sell our oil and natural gas shortly after production at various pipeline receipt points at which time

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title and risk of loss transfers to the buyer. Revenue is recorded when title and risk of loss is transferred based on our net revenue interests. Oil and gas sold in production operations is not significantly different from our share of production based on our interest in the properties.

Settlement of oil and gas sales occur after the month in which the oil and gas was produced. We estimate and accrue for the value of these sales using information available at the time the financial statements are generated. Differences are reflected in the accounting period that payments are received from the purchaser.

Revenue from our pipeline operations is recognized at the time the natural gas is gathered or transported through the system and delivered to a third party.

Income Taxes

We record our income taxes using an asset and liability approach in accordance with the provisions of the Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (“SFAS No. 109”). This results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences (primarily intangible drilling costs and the net operating loss carry forward) between the book carrying amounts and the tax bases of assets and liabilities using enacted tax rates at the end of the period. Under SFAS No. 109, the effect of a change in tax rates of deferred tax assets and liabilities is recognized in the year of the enacted change. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Estimating the amount of valuation allowance is dependent on estimates of future taxable income, alternative minimum tax income, and changes in stockholder ownership that could trigger limits on use of net operating losses under Internal Revenue Code section 382. We have a significant deferred tax asset associated with net operating loss carry-forward (NOLs).

Recent Accounting Pronouncements

In February 2008, the FASB issued Staff Position FAS 157-2, Effective Date of FASB Statement No. 157 (“FSP 157-2”). FSP 157-2 delays the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those recognized or disclosed at fair value in the financial statements on a recurring basis, at least annually. We implemented this standard on January 1, 2009. The adoption of FSP 157-2 is not expected to have a material impact on our financial condition, operations or cash flows.

Effective upon issuance, the FASB issued Staff Position FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active, (“FSP 157-3”) in October 2008. FSP 157-3 clarifies the application of SFAS No. 157 in determining the fair value of a financial asset when the market for that financial asset is not active. As of December 31, 2008, we had no financial assets with a market that was not active. Accordingly, FSP 157-3 is not expect to have an impact on our consolidated financial statements.

In September 2006, the SEC issued Staff Accounting Bulletin No. 108 (“SAB No. 108”). SAB No. 108 addresses how the effects of prior year uncorrected misstatements should be considered when quantifying misstatements in current year financial statements. SAB No. 108 requires companies to quantify misstatements using a balance sheet and income statement approach and to evaluate whether either approach results in quantifying an error that is material in light of relevant quantitative and qualitative factors. When the effect of initial adoption is material, companies will record the effect as a cumulative effect adjustment to beginning of year retained earnings and disclose the nature and amount of each individual error being corrected in the cumulative adjustment. SAB No. 108 became effective beginning January 1, 2007 and applies to our restatements included in this filing but its adoption did not have a material impact on our financial position, results of operations, or cash flows.

In December 2007, FASB issued SFAS No. 141(R), Business Combinations, which replaces SFAS No. 141. SFAS No. 141(R) establishes principles and requirements for how the acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree. In addition, SFAS No. 141(R) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase. SFAS No. 141(R) also establishes disclosure requirements to enable users to evaluate the nature and financial effects of the business combination.

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SFAS No. 141(R) is effective as of the beginning of an entity’s fiscal year that begins after December 15, 2008, with early adoption prohibited. We are currently assessing the impact this standard might have on our results of operations, cash flows and financial position.

In December 2007, the FASB issued SFAS No. 160, Non-controlling Interests in Consolidated Financial Statements — An Amendment of ARB No. 51. SFAS No. 160 establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the non-controlling interest, and changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary. In addition, SFAS No. 160 establishes principles for valuation of retained non-controlling equity investments and measurement of gain or loss when a subsidiary is deconsolidated. SFAS No. 160 also establishes disclosure requirements to clearly identify and distinguish between interests of the parent and the interests of the non-controlling owners. SFAS No. 160 is effective for fiscal years and interim periods beginning after December 15, 2008, with early adoption prohibited. We are currently assessing the impact this standard will have on our results of operations, cash flows and financial position.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 133 (“SFAS 161”). This statement does not change the accounting for derivatives but will require enhanced disclosures about derivative strategies and accounting practices. SFAS 161 is effective for fiscal years beginning after January 15, 2008, and we will comply with any necessary disclosure requirements beginning with the interim financial statements for the three months ended March 31, 2009.

On December 31, 2008, the SEC issued Release No. 33-8995, Modernization of Oil and Gas Reporting, which revises disclosure requirements for oil and gas companies. In addition to changing the definition and disclosure requirements for oil and gas reserves, the new rules change the requirements for determining oil and gas reserve quantities. These rules permit the use of new technologies to determine proved reserves under certain criteria and allow companies to disclose their probable and possible reserves. The new rules also require companies to report the independence and qualifications of their reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit. The new rules also require that oil and gas reserves be reported and the full cost ceiling limitation be calculated using a twelve-month average price rather than period-end prices. The use of a twelve-month average price could have had an effect on our 2009 depletion rates for our natural gas and crude oil properties and the amount of the impairment recognized as of December 31, 2008 had the new rules been effective for the period. The new rules are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, pending the potential alignment of certain accounting standards by the FASB with the new rule. We plan to implement the new requirements in our Annual Report on Form 10-K for the year ended December 31, 2009. We are currently evaluating the impact of the new rules on our consolidated financial statements.

Forward-Looking Statements

Various statements in this report, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These include such matters as projections and estimates concerning the timing and success of specific projects; financial position; business strategy; budgets; amount, nature and timing of capital expenditures; drilling of wells and construction of pipeline infrastructure; acquisition and development of oil and natural gas properties and related pipeline infrastructure; timing and amount of future production of oil and gas; operating costs and other expenses; estimated future net revenues from oil and natural gas reserves and the present value thereof; cash flow and anticipated liquidity; and other plans and objectives for future operations.

When we use the words “believe,” “intend,” “expect,” “may,” “will,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The factors impacting these risks and uncertainties include, but are not limited to:


	•	current financial instability and deteriorating economic conditions;

	•	our current financial instability;

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	•	volatility of oil and gas prices;

	•	completion of the Recombination;

	•	increases in the cost of drilling, completion and gas gathering or other costs of developing and producing our reserves;

	•	our restrictive debt covenants;

	•	results of our hedging activities;

	•	drilling, operational and environmental risks; and

	•	regulatory changes and litigation risks.

You should consider carefully the statements in Item 1A. “Risk Factors” and other sections of this report, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements.

We have based these forward-looking statements on our current expectations and assumptions about future events. The forward-looking statements in this report speak only as of the date of this report; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. Readers are urged to carefully review and consider the various disclosures made by us in our reports filed with the SEC, which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operation and cash flows. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those expected or projected.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Quantitative and Qualitative Disclosures about Market Risk

The discussion in this section provides information about the financial instruments we use to manage commodity price and interest rate volatility. All contracts are financial contracts, which are settled in cash and do not require the actual delivery of a commodity quantity to satisfy settlement.

Commodity Price Risk

Our most significant market risk relates to the prices we receive for our oil and natural gas production. For example, NYMEX-WTI oil prices have declined from a record high of $147.55 per barrel in July 2008 to approximately $33.87 per barrel in December 2008. Meanwhile, near month NYMEX natural gas futures prices during 2008 ranged from as high as $13.58 per Mmbtu in July 2008 to as low as $5.29 per Mmbtu in December 2008. In light of the historical volatility of these commodities, we periodically have entered into, and expect in the future to enter into, derivative arrangements aimed at reducing the variability of oil and natural gas prices we receive for our production. From time to time, we enter into commodity pricing derivative contracts for a portion of our anticipated production volumes to provide certainty on future sales price and reduce revenue volatility.

We use, and may continue to use, a variety of commodity-based derivative financial instruments, including collars, fixed-price swaps and basis protection swaps. Our fixed price swap and collar transactions are settled based upon either NYMEX prices or index prices at our main delivery points, and our basis protection swap transactions are settled based upon the index price of natural gas at our main delivery points. Settlement for our natural gas derivative contracts typically occurs in advance of our purchaser receipts.

While we believe that the oil and natural gas price derivative arrangements we enter into are important to our program to manage price variability for our production, we have not designated any of our derivative contracts as hedges for accounting purposes. We record all derivative contracts on the balance sheet at fair value, which reflects changes in oil and natural gas prices. We establish fair value of our derivative contracts by price quotations obtained from counterparties to the derivative contracts. Changes in fair values of our derivative contracts are recognized in current period earnings. As a result, our current period earnings may be significantly affected by changes in fair

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value of our commodities derivative contracts. Changes in fair value are principally measured based on period-end prices compared to the contract price.

At December 31, 2008, 2007 and 2006, QELP was party to derivative financial instruments in order to manage commodity price risk associated with a portion of its expected future sales of its oil and gas production. None of these 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.

Gains and losses associated with derivative financial instruments related to gas and oil production were as follows for the years ended December 31, 2008, 2007 and 2006 (in thousands):


	2008		2007			2006

Realized gains (losses)	$	8,174	$	7,279		$	(17,712	)
Unrealized gains (losses)		72,533		(5,318	)		70,402

Total	$	80,707	$	1,961		$	52,690

The following table summarizes the estimated volumes, fixed prices and fair value attributable to oil and gas derivative contracts as of December 31, 2008:


	Year Ending December 31,
	2009		2010		2011		Thereafter		Total
	($ in thousands, except Mmbtu and per Mmbtu data)

Natural Gas Swaps:
Contract volumes (Mmbtu)		14,629,200		12,499,060		2,000,004		2,000,004		31,128,268
Weighted-average fixed price per Mmbtu(1)	$	7.78	$	7.42	$	8.00	$	8.11	$	7.67
Fair value, net	$	38,107	$	14,071	$	2,441	$	2,335	$	56,954
Natural Gas Collars:
Contract volumes (Mmbtu):
Floor		750,000		630,000		3,549,996		3,000,000		7,929,996
Ceiling		750,000		630,000		3,549,996		3,000,000		7,929,996
Weighted-average fixed price per Mmbtu(1):
Floor	$	11.00	$	10.00	$	7.39	$	7.03	$	7.79
Ceiling	$	15.00	$	13.11	$	9.88	$	7.39	$	9.52
Fair value, net	$	3,630	$	1,875	$	3,144	$	2,074	$	10,723
Total Natural Gas Contracts:
Contract volumes (Mmbtu)		15,379,200		13,129,060		5,550,000		5,000,004		39,058,264
Weighted-average fixed price per Mmbtu(1)	$	7.94	$	7.55	$	7.61		7.44	$	7.70
Fair value, net	$	41,737	$	15,946	$	5,585		4,409	$	67,677
Crude Oil Swaps:
Contract volumes (Bbl)		36,000		30,000		—		—		66,000
Weighted-average fixed per Bbl(1)	$	90.07	$	87.50		—		—	$	88.90
Fair value, net	$	1,246	$	666		—		—	$	1,912

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Interest Rate Risk

The Company has entered into interest rate derivatives to mitigate its exposure to fluctuations in interest rates on variable rate debt. These instruments have not been designated as hedges and, therefore are recorded in the consolidated balance sheet at fair value with changes in fair value recognized in earnings as they occur.

As of December 31, 2008, we had outstanding $388.1 million of variable-rate debt. A 1% increase in our interest rates would increase gross interest expense approximately $3.9 million per year. As of December 31, 2008, we did not have any interest hedging activities. The last of our interest rate cap agreements expired September 2007.

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ITEM 8.	*FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.*

Please see the accompanying consolidated financial statements attached hereto beginning on page F-1.


ITEM 9.	*CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.*

None.


ITEM 9A.	*CONTROLS AND PROCEDURES*

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms and that such information is accumulated and communicated to management, including the principal executive officer and the principal financial officer, to allow timely decisions regarding required disclosures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of the achieving their control objectives.

In connection with the preparation of this Annual Report on Form 10-K, our management, under the supervision and with the participation of the current principal executive officer and current principal financial officer, conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2008. Based on that evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective as of December 31, 2008. Notwithstanding this determination, our management believes that the consolidated financial statements in this Annual Report on Form 10-K fairly present, in all material respects, our financial position and results of operations and cash flows as of the dates and for the periods presented, in conformity with GAAP.

Management’s Annual Report on Internal Control Over Financial Reporting

Management, under the supervision of the principal executive officer and the principal financial officer, is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Internal control over financial reporting includes those policies and procedures which (a) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of assets, (b) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, (c) provide reasonable assurance that receipts and expenditures are being made only in accordance with appropriate authorization of management and the board of directors, and (d) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the financial statements. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

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evaluation, management identified the following control deficiencies that constituted material weaknesses as of December 31, 2008:


	(1)	Control environment — We did not maintain an effective control environment. The control environment, which is the responsibility of senior management, sets the tone of the organization, influences the control consciousness of its people, and is the foundation for all other components of internal control over financial reporting. Each of these control environment material weaknesses contributed to the material weaknesses discussed in items (2) through (8) below. We did not maintain an effective control environment because of the following material weaknesses:


	(a)	We did not maintain a tone and control consciousness that consistently emphasized adherence to accurate financial reporting and enforcement of Company policies and procedures. This control deficiency fostered a lack of sufficient appreciation for internal controls over financial reporting, allowed for management override of internal controls in certain circumstances and resulted in an ineffective process for monitoring the adherence of the Company’s policies and procedures.


	(b)	In addition, we did not maintain a sufficient complement of personnel with an appropriate level of accounting knowledge, experience, and training in the application of GAAP commensurate with our financial reporting requirements and business environment.


	(c)	We did not maintain an effective anti-fraud program designed to detect and prevent fraud relating to (i) an effective whistle-blower program, (ii) consistent background checks of personnel in positions of responsibility, and (iii) an ongoing program to manage identified fraud risks.

The control environment material weaknesses described above contributed to the material weaknesses related to the transfers that were the subject of the internal investigation and to our internal control over financial reporting, period end financial close and reporting, accounting for derivative instruments, stock compensation costs, depreciation, depletion and amortization, impairment of oil and gas properties and cash management described in items (2) to (8) below.


	(2)	Internal control over financial reporting — We did not maintain effective monitoring controls to determine the adequacy of our internal control over financial reporting and related policies and procedures because of the following material weaknesses:


	(a)	Our policies and procedures with respect to the review, supervision and monitoring of our accounting operations throughout the organization were either not designed and in place or not operating effectively.


	(b)	We did not maintain an effective internal control monitoring function. Specifically, there were insufficient policies and procedures to effectively determine the adequacy of our internal control over financial reporting and monitoring the ongoing effectiveness thereof.

Each of these material weaknesses relating to the monitoring of our internal control over financial reporting contributed to the material weaknesses described in items (3) through (8) below.


	(3)	Period end financial close and reporting — We did not establish and maintain effective controls over certain of our period-end financial close and reporting processes because of the following material weaknesses:


	(a)	We did not maintain effective controls over the preparation and review of the interim and annual consolidated financial statements and to ensure that we identified and accumulated all required supporting information to ensure the completeness and accuracy of the consolidated financial statements and that balances and disclosures reported in the consolidated financial statements reconciled to the underlying supporting schedules and accounting records.


	(b)	We did not maintain effective controls to ensure that we identified and accumulated all required supporting information to ensure the completeness and accuracy of the accounting records.

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	(c)	We did not maintain effective controls over the preparation, review and approval of account reconciliations. Specifically, we did not have effective controls over the completeness and accuracy of supporting schedules for substantially all financial statement account reconciliations.


	(d)	We did not maintain effective controls over the complete and accurate recording and monitoring of intercompany accounts. Specifically, effective controls were not designed and in place to ensure that intercompany balances were completely and accurately classified and reported in our underlying accounting records and to ensure proper elimination as part of the consolidation process.


	(e)	We did not maintain effective controls over the recording of journal entries, both recurring and non-recurring. Specifically, effective controls were not designed and in place to ensure that journal entries were properly prepared with sufficient support or documentation or were reviewed and approved to ensure the accuracy and completeness of the journal entries recorded.


	(4)	Derivative instruments — We did not establish and maintain effective controls to ensure the correct application of GAAP related to derivative instruments. Specifically, we did not adequately document the criteria for measuring hedge effectiveness at the inception of certain derivative transactions and did not subsequently value those derivatives appropriately.

	(5)	Stock compensation cost — We did not establish and maintain effective controls to ensure completeness and accuracy of stock compensation costs. Specifically, effective controls were not designed and in place to ensure that documentation of the terms of the awards were reviewed in order to be recorded accurately.

	(6)	Depreciation, depletion and amortization — We did not establish and maintain effective controls to ensure completeness and accuracy of depreciation, depletion and amortization expense. Specifically, effective controls were not designed and in place to calculate and review the depletion of oil and gas properties.

	(7)	Impairment of oil and gas properties — We did not establish and maintain effective controls to ensure the accuracy and application of GAAP related to the capitalization of costs related to oil and gas properties and the required evaluation of impairment of such costs. Specifically, effective controls were not designed and in place to determine, review and record the nature of items recorded to oil and gas properties and the calculation of oil and gas property impairments.

	(8)	Cash management — We did not establish and maintain effective controls to adequately segregate the duties over cash management. Specifically, effective controls were not designed to prevent the misappropriation of cash.

Additionally, each of the control deficiencies described in items (1) through (8) above could result in a misstatement of the aforementioned account balances or disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. These material weaknesses resulted in the misstatement of our annual and interim consolidated financial statements as of and for the years ended December 31, 2007, 2006 and 2005 (including the interim periods within those years) and 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.

Based on management’s evaluation, because of the material weaknesses described above, management has concluded that our internal control over financial reporting was not effective as of December 31, 2008. Our independent registered public accounting firm, UHY LLP, has audited the effectiveness of our internal control over financial reporting as of December 31, 2008, and that report appears in this Annual Report on Form 10-K.

Remediation Plan

Our management, under new leadership as described below, has been actively engaged in the planning for, and implementation of, remediation efforts to address the material weaknesses, as well as other identified areas of risk. These remediation efforts, outlined below, are intended both to address the identified material weaknesses and to enhance our overall financial control environment. In August 2008, Mr. David Lawler was appointed President (and

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in May 2009 was appointed as our Chief Executive Officer) (our principal executive officer) and in September 2008, Mr. Jack Collins was appointed Chief Compliance Officer. In January 2009, Mr. Eddie LeBlanc was appointed Chief Financial Officer (our principal financial and accounting officer). The design and implementation of these and other remediation efforts are the commitment and responsibility of this new leadership team.

In addition, Mr. Rateau, one of our independent directors, was elected as Chairman of the Board, and Mr. McMichael, who has significant prior public company audit committee experience, was added to our Board of Directors and Audit Committee.

Our new leadership team, together with other senior executives, is committed to achieving and maintaining a strong control environment, high ethical standards, and financial reporting integrity. This commitment will be communicated to and reinforced with every employee and to external stakeholders. This commitment is accompanied by a renewed management focus on processes that are intended to achieve accurate and reliable financial reporting.

As a result of the initiatives already underway to address the control deficiencies described above, we have effected personnel changes in our accounting and financial reporting functions. We have taken remedial actions, which included termination, with respect to all employees who were identified as being involved with the inappropriate transfers of funds. In addition, we have implemented additional training and/or increased supervision and established segregation of duties regarding the initiation, approval and reconciliation of cash transactions, including wire transfers.

The Board of Directors has directed management to develop a detailed plan and timetable for the implementation of the foregoing remedial measures (to the extent not already completed) and will monitor their implementation. In addition, under the direction of the Board of Directors, management will continue to review and make necessary changes to the overall design of our internal control environment, as well as policies and procedures to improve the overall effectiveness of internal control over financial reporting.

We believe the measures described above will enhance the remediation of the control deficiencies we have identified and strengthen our internal control over financial reporting. We are committed to continuing to improve our internal control processes and will continue to diligently and vigorously review our financial reporting controls and procedures. As we continue to evaluate and work to improve our internal control over financial reporting, we may determine to take additional measures to address control deficiencies or determine to modify, or in appropriate circumstances not to complete, certain of the remediation measures described above.

Changes in Internal Control Over Financial Reporting

During the fourth quarter, and subsequent to December 31, 2008, we have begun the implementation of some of the remedial measures described above, including communication, both internally and externally, of our commitment to a strong control environment, high ethical standards, and financial reporting integrity and certain personnel actions.

ITEM 9B. OTHER INFORMATION.

None.

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PART III


ITEM 10.	*DIRECTORS, EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE GOVERNANCE.*

Directors and Executive Officers

Our Directors and Executive Officers are as follows:


Name	Age		Positions Held	Term of Office Since

David C. Lawler		41	Chief Executive Officer, President and Director		2007

Eddie M. LeBlanc, III		60	Chief Financial Officer		2009
James B. Kite, Jr.		57	Director		2002
William H. Damon III		56	Director		2007
John C. Garrison		57	Director		1998
Jon H. Rateau		53	Chairman of the Board and Director		2005
Greg L. McMichael		60	Director		2008
Richard Marlin		56	Executive Vice President, Engineering		2004
David W. Bolton		40	Executive Vice President, Land		2006
Jack Collins		33	Executive Vice President, Finance/Corporate Development		2007
Thomas A. Lopus		50	Executive Vice President, Appalachia		2008

Mr. Lawler joined us in May 2007 as our Chief Operating Officer and served as Chief Operating Officer until May 2009, then became our President in August 2008 and our Chief Executive Officer in May 2009. He has worked in the oil and gas industry for more than 18 years in various management and engineering positions. Prior to joining us, Mr. Lawler was employed by Shell Exploration & Production Company from May 1997 to May 2007 in roles of increasing responsibility most recently as Engineering and Operations Manager for multiple assets along the U.S. Gulf Coast. Mr. Lawler graduated from the Colorado School of Mines in 1990 with a bachelor’s of science degree in petroleum engineering and earned his Masters in Business Administration from Tulane University in 2003.

Mr. LeBlanc joined us in January 2009 as our Chief Financial Officer. He served as Executive Vice President and Chief Financial Officer of Ascent Energy Company, an independent, private oil and gas company, from July 2003 until it was sold to RAM Energy Resources in November 2007, after which time, Mr. LeBlanc went into retirement. Prior to that, Mr. LeBlanc was Senior Vice President and Chief Financial Officer of Range Resources Corporation, an NYSE-listed independent oil and gas company, from January 2000 to July 2003. Previously, Mr. LeBlanc was a founder of Interstate Natural Gas Company, which merged into Coho Energy in 1994. At Coho, he served as Senior Vice President and Chief Financial Officer until 1999. Mr. LeBlanc’s 35 years of experience include assignments in Celeron Corporation and the energy related subsidiaries of Goodyear Tire and Rubber. Prior to entering the oil and gas industry, Mr. LeBlanc was with a national accounting firm. He is a certified public accountant and a chartered financial analyst, and he received a B.S. in Business Administration from University of Southwestern Louisiana.

Mr. Kite is the Chief Executive Officer of Boothbay Royalty Company, an independent investment company with its primary concentration in the field of oil and gas exploration and production based in Oklahoma City, Oklahoma, which he founded in 1977. He has served as its Chief Executive Officer, President and Treasurer since its inception. Mr. Kite spent several years in the commercial banking industry with an emphasis in credit and loan review prior to his involvement in the oil and gas industry. Mr. Kite presently is a director of The All Souls’ Anglican Foundation. Mr. Kite earned a bachelor’s of business administration in finance from the University of Oklahoma.

Mr. Damon has over 30 years of professional experience specializing in engineering design and development of power generation projects and consulting services. Since January 2008, he has served as Senior Vice President and National Director of Power Consulting for HDR, Inc., which recently purchased the engineering-consulting

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firm, Cummins & Barnard, Inc., which was focused on power generation development and engineering projects for electric utilities, independent power producers, large industrial and institutional clients throughout the United States. Mr. Damon served as the Chief Executive Officer of Cummins & Barnard and had been its principal and co-owner from 1990 to January 2008. He currently leads HDR’s project development and strategic consulting business for coal, natural gas and renewable energy projects. He previously worked for Consumers Power Company, Gilbert-Commonwealth, Inc. and Alternative Energy Ventures. He also held board seats on a minerals and wind turbine company, MKBY, and a start-up construction company that was recently sold to Aker Kvaerner Songer in which he was also a founding member. Mr. Damon graduated from Michigan State University with a B.S. in Mechanical Engineering and continued graduate studies at both Michigan State University and the University of Michigan.

Mr. Garrison brings expertise in public company activities and issues. Mr. Garrison served as our Treasurer from 1998 to September 2001. Mr. Garrison has been a self-employed Certified Public Accountant in public practice providing financial management and accounting services to a variety of businesses for over thirty years. From August 2007 to March 2008, and again from August 2008 to the present, he has served as the Chief Financial Officer of Empire Energy Corporation International. From July 2004 to June 2007, Mr. Garrison was the Chief Financial Officer of ICOP Digital, Inc. He has also been a director of Empire Energy since 1999. Mr. Garrison holds a bachelor’s degree in Accounting from Kansas State University.

Mr. Rateau is currently the Vice President of New Energy, Global Primary Products Growth, Alcoa, Inc., where he is responsible for developing and acquiring energy positions/assets worldwide in support of Alcoa’s smelting and refining activities, and has been at Alcoa, Inc. since 1996. Mr. Rateau has served in his present capacity at Alcoa since September 2007. Prior to that, he was Vice President of Business Development, Primary Metals from March 2001 to September 2007 and Vice President of Energy Management & Services, Primary Metals from November 1997 to March 2001. Before joining Alcoa, Mr. Rateau held a number of managerial positions with National Steel Corporation from 1981 to 1996. He brings expertise in business acquisitions and divestitures, capital budgets and project management, energy contracting, and applied research of complex technology and processes. Mr. Rateau holds an M.B.A. from Michigan State University and received a B.S. in Industrial Engineering from West Virginia University.

Mr. McMichael has over 30 years of oil and gas experience, including 13 years working directly in the exploration and production (E&P) sector, 16 years as an equity analyst following the E&P sector and over four years as a director of both private and public oil and gas companies. Mr. McMichael has served as a Director of Denbury Resources, Inc. since 2004, a publicly held E&P company based in Plano, Texas, where he currently chairs Denbury’s Compensation Committee. Concurrent with being a director at Denbury, he served for four years as a director of Matador Resources Company, a privately held E&P company where he served on the Audit Committee. Mr. McMichael was employed by A.G. Edwards Inc. for eight years (1998 — 2004) as Vice President and Group Leader of Energy Research, where he managed that firm’s global energy equity research effort. He earned a Bachelor’s degree in Political Science and Economics from Schiller International University in London, England in 1973.

Mr. Marlin has served as Executive Vice President — Engineering since September 2004. He also was our Chief Operations Officer from February 2005 through July 2006. He was our engineering manager from November 2002 to September 2004. Prior to that, he was the engineering manager for STP from 1999 until our acquisition of STP in November 2002. Prior to that, he was employed by Parker and Parsley Petroleum as the Mid-Continent Operations Manager for 12 years. Mr. Marlin has more than 32 years industry experience involving all phases of drilling and production in more than 14 states. His experience also involved primary and secondary operations along with the design and oversight of gathering systems that move as much as 175 Mmcf/d. He is a registered Professional Engineer holding licenses in Oklahoma and Colorado. Mr. Marlin earned a B.S. in Industrial Engineering and Management from Oklahoma State University in 1974. Mr. Marlin was a Director of the Mid-Continent Coal Bed Methane Forum from 2003 to 2005.

Mr. Bolton has served as Executive Vice President — Land since May 2006. Prior to that, he was a Land Manager for Continental Land Resources, LLC, an Oklahoma based oil and gas lease broker from May 2004 to May 2006. Prior to that, Mr. Bolton was a landman for Continental Land Resources from April 2001 to May 2004. He was an independent landman from 1995 to April 2001. Mr. Bolton is a Certified Professional Landman with over

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18 years of experience in various aspects of the oil and gas industry, and has worked extensively throughout Oklahoma, Texas, and Kansas. Mr. Bolton holds a Bachelor of Liberal Studies degree from the University of Oklahoma, attended the Oklahoma City University School of Law, and is a member of American Association of Petroleum Landmen, Oklahoma City Association of Petroleum Landmen, the American Bar Association, and the Energy Bar Association.

Mr. Collins joined the Company in December 2007 as Executive Vice President — Investor Relations. From September 2008 to January 2009, he served as the Company’s Interim Chief Financial Officer, and since January 2009, he has served as the Company’s Executive Vice President — Finance/Corporate Development. Mr. Collins has more than 11 years of experience providing analysis and advice to oil and gas industry investors. Prior to joining us, he worked for A.G. Edwards & Sons, Inc., a national, full-service brokerage firm, from 1999 to 2007 in various positions, most recently as a Securities Analyst, where he was responsible for initiating the firm’s coverage of the high yield U.S. energy stock sector (E&P partnerships and U.S. royalty trusts). As an Associate Analyst (2001 to 2005) and Research Associate (1999 to 2001) at A.G. Edwards, he assisted senior analysts in coverage of the independent E&P and oilfield service sectors of the energy industry. Mr. Collins holds a Bachelors degree in Economics with a Business Emphasis from the University of Colorado at Boulder.

Mr. Lopus has served as Executive Vice President — Appalachia since July 2008. Mr. Lopus has more than 27 years of experience in the oil and gas industry. Prior to joining us, Mr. Lopus served as Senior Vice President of Eastern Operations for Linn Energy, LLC from April 2006 to July 2008 where he was responsible for all Eastern United States oil and natural gas activity. From April 2005 to March 2006, he was an independent consultant for a variety of oil and gas related businesses. From February 2002 to March 2005, Mr. Lopus held senior management positions at Equitable Resources, Inc., where he was responsible for all oil and natural gas operations. Prior to that, he worked at FINA, Inc. for 20 years, where he was in charge of all oil and natural gas operations in the United States. Mr. Lopus is a registered petroleum engineer and received a Bachelor of Science degree from The Pennsylvania State University in Petroleum and Natural Gas Engineering. He has held leadership positions with numerous industry and civic organizations, including the Independent Petroleum Association of America, Society of Petroleum Engineers, American Petroleum Institute, United Way, and March of Dimes.

Board of Directors

Our Board of Directors is currently divided among three classes as follows:

Class I — John C. Garrison and Jon H. Rateau;

Class II — David C. Lawler and William H. Damon III; and

Class III — Greg L. McMichael and James B. Kite, Jr.

The term of each class of directors expires at each annual meeting of stockholders, with the terms of Messrs. McMichael and Kite expiring in 2009, the terms of Messrs. Garrison and Rateau expiring in 2010 and the terms of Messrs. Lawler and Damon expiring in 2011.

Corporate Governance

Audit Committee

The Board of Directors has established a separately designated standing Audit Committee in accordance with Section 3(a)(58)(A) of the Exchange Act. The purposes of the Audit Committee are to oversee and review (i) the integrity of all financial information provided to any governmental body or the public and (ii) the integrity and adequacy of the our auditing, accounting and financial reporting processes and systems of internal control for financial reporting and disclosure controls and procedures.

The following three directors are members of the Audit Committee: John Garrison, Chair, Greg McMichael and William H. Damon III. The Board of Directors has determined that each of the Audit Committee members are independent, as that term is defined under the enhanced independence standards for audit committee members in the Securities Exchange Act of 1934 and rules thereunder, as amended, as incorporated into the listing standards of the

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NASDAQ Global Market. The Board of Directors has determined that Mr. Garrison is an “audit committee financial expert,” as that term is defined in the rules promulgated by the SEC pursuant to the Sarbanes-Oxley Act of 2002.

The Audit Committee performs its functions and responsibilities pursuant to a written charter adopted by our Board of Directors, which is published on our Internet website at www.questresourcecorp.com under the heading Corporate Governance.

Code of Ethics

We have adopted a Code of Business Conduct and Ethics for Directors, Officers and Employees (“Code of Ethics”), which addresses conflicts of interests, that is applicable to our principal executive officer, principal financial officer and principal accounting officer. The Code of Ethics describes the types of transactions that may be subject to the review, approval or ratification of the Audit Committee or the chief compliance officer. Any waiver of any provision of our Code of Ethics for a member of our Board of Directors, an executive officer, or a senior financial or accounting officer must be approved by our Audit Committee, and any such waiver will be promptly disclosed as required by law or NASDAQ rule.

A copy of our Code of Ethics is available on our internet website at www.questresourcecorp.com under the heading Corporate Governance. We will also provide a copy of the Code of Ethics, without charge, to any stockholder who requests it. Requests should be addressed in writing to: Corporate Secretary at Quest Resource Corporation, 210 Park Avenue, Suite 2750, Oklahoma City, OK 73102. We intend to post any amendment to or waiver from the Code of Ethics that applies to executive officers or directors on our website.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our directors and executive officers, and persons who own more than 10% of a registered class of our equity securities (“Section 16 Insiders”), to file with the SEC initial reports of ownership and reports of changes in ownership of our equity securities. Directors, executive officers and greater than 10% stockholders are required by SEC regulations to furnish us with copies of all Section 16(a) forms they file.

To our knowledge, based solely on a review of Forms 3, 4, 5 and amendments thereto furnished to us and written representations that no other reports were required, during and for the fiscal year ended December 31, 2008, all Section 16(a) filing requirements applicable to our directors, executive officers and greater than 10% beneficial owners were complied with in a timely manner, except for the following:


	•	Messrs. Rateau, Garrison, Damon and Kite each did not timely report his acquisition of 5,000 shares of common stock pursuant to a bonus shares award agreement.

	•	Richard Marlin did not timely report his disposition of 8,434 shares held in Mr. Marlin’s retirement account.

	•	Bob Alexander, a former director of the Company who resigned on August 22, 2008, did not timely report his achievement of the status of Section 16 Insider. In addition, Mr. Alexander did not timely report his acquisition of a pecuniary interest in 10,000 shares pursuant to a bonus shares award agreement. These shares were not issued to Mr. Alexander and he relinquished any right to receive these shares as part of his resignation from our Board of Directors.

ITEM 11. EXECUTIVE COMPENSATION.

Compensation Discussion and Analysis

Compensation Philosophy

Our compensation philosophy is to manage Named Executive Officer (defined below) total compensation at the median level (50th percentile) relative to companies with which we compete for talent (which are primarily peer group companies). The Compensation Committee of our Board of Directors (the “Committee”) compares compensation levels with a selected cross-industry group of other oil and natural gas exploration and production companies of similar size to establish a competitive compensation package.

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Role of the Compensation Committee

The Committee is responsible for reviewing and approving all aspects of compensation for the “Named Executive Officers” listed in the Summary Compensation Table (the “Named Executive Officers”). The Committee is also responsible for approving the compensation policies of Quest Energy GP, some of whose officers are our Named Executive Officers.

In meeting these responsibilities, the Committee’s policy is to ensure that Named Executive Officer compensation is designed to achieve three primary objectives:


	•	attract and retain well-qualified executives who will lead us and achieve superior performance;

	•	tie annual incentives to achievement of specific, measurable short-term corporate goals; and

	•	align the interests of management with those of the stockholders to encourage achievement of increases in stockholder value.

The Committee retained the independent compensation consulting firm of Towers Perrin (“T-P”) in February 2008 to: (i) assist the Committee in formulating our compensation policies for 2008 and future years; (ii) provide advice to the Committee concerning specific compensation packages and appropriate levels of Named Executive Officers’ compensation; (iii) provide advice about competitive levels of compensation and marketplace trends in the oil and gas industry; and (iv) review and recommend changes in our compensation system and programs. As described below, T-P compiled competitive salary data for seven of our peer group companies and eight of Quest Energy’s peer group companies and assisted the Committee in its benchmarking efforts, among other things. T-P had a conference call with the Committee in order to gather information about us and our business.

Additionally, in September 2008, the Committee subscribed to a service provided by Equilar, Inc. (“Equilar”) to create reports concerning compensation data (including base salary, bonus compensation and equity awards) to assist the Committee in analyzing the compensation received by our Named Executive Officers and directors in comparison to publicly-traded benchmarked companies as described below.

In connection with the adoption of a Long Term Incentive Plan (“LTIP”) and amendments made to our 2005 Omnibus Stock Award Plan (the “Omnibus Plan”) and Management Annual Incentive Plan (the “QRC Bonus Plan”) in May 2008, the Committee retained RiskMetrics Group, formerly Institutional Shareholder Services (“RiskMetrics”), to advise it with respect to corporate governance matters.

The Committee separately considered the elements of (i) base salary, (ii) base salary plus target bonus, and (iii) long-term equity incentive value, comparing our compensation for such elements to the median level (50th percentile) of our peer group for 2008. The Committee believed the metric of actual total cash compensation (base salary, as well as base salary plus bonus) was key to retaining well-qualified executives and to providing annual incentives and therefore gave it a heavier weighting than our peer group. The Committee made adjustments to attempt to align the actual total annual cash compensation between the 50th to 75th percentiles of our market peer group, while taking into account differences in job titles and duties, as well as individual performance. The Committee believes that total compensation packages (taking into account long term equity compensation) were between the 25th and 50th percentiles of our market peer group. Initially, equity awards were granted as part of the Named Executive Officers’ employment agreements in a lump sum that vested over a three-year period. As discussed below, the Committee adopted the LTIP in 2008 in order to provide the Named Executive Officers with annual grants of equity incentive compensation. However, this program was cancelled at the end of 2008 due to our low stock price.

Role of Management in Compensation Process

Each year the Committee asks our principal executive officer (which prior to August 22, 2008, was Jerry Cash, our Chief Executive Officer, and after that date was David Lawler, our President) and principal financial officer to present a proposed compensation plan for the fiscal year beginning January 1 and ending December 31 (each, a “Plan Year”), along with supporting and competitive market data. For 2008, T-P assisted our management in providing this competitive market data, primarily through published and private salary surveys. The compensation amounts presented to the Committee for the 2008 Plan Year were determined based upon Mr. Cash’s negotiations

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with the Named Executive Officers (taking into account the T-P competitive data). The Committee then met with Mr. Cash to review the proposal and establish the compensation plan, with members of T-P participating by telephone.

The Committee monitors the performance of our Named Executive Officers throughout the Plan Year against the targets set for each performance measure. At the end of the Plan Year, the Committee meets with the principal executive officer and principal financial officer to review the final results compared to the established performance goals before determining the Named Executive Officers’ compensation levels for the Plan Year. During these meetings, the Committee also establishes the Named Executive Officer compensation plan for the upcoming Plan Year, based on the principal executive officer’s recommendations. In general, the plan must be established within the first 90 days of a Plan Year.

During 2008, we hired Thomas Lopus, who was one of the Named Executive Officers for 2008. The compensation package for Mr. Lopus was negotiated between Mr. Cash and Mr. Lopus (taking into account the T-P competitive data). The Committee then met with Mr. Cash to review and approve the proposed compensation package.

In connection with David Lawler’s change of executive officer position in October 2008, Mr. Lawler and the Committee renegotiated his compensation package after taking into account the T-P and Equilar competitive data.

Mr. Lawler was actively involved in the renegotiation of Mr. Collins’ employment agreement in October 2008 and made the determination of the amount of the discretionary bonuses awarded to the other Named Executive Officers in January 2009 under the Supplemental Bonus Program discussed below.

Performance Peer Groups

In 2008, the Committee retained T-P as its independent compensation consultant to advise the Committee on matters related to the Named Executive Officers’ compensation program. To assist the Committee in its benchmarking efforts, T-P provided a compensation analysis and survey data for peer groups of companies that are similar in scale and scope to us and Quest Energy. With the assistance of T-P, the Committee selected (i) a peer group for us consisting of the following seven publicly traded U.S. exploration and production companies which had annual revenues ranging from $4 million to $106 million: American Oil & Gas Inc., Aurora Oil & Gas Corp., Brigham Exploration Co., Double Eagle Petroleum Co., Kodiak Oil & Gas Corp., Rex Energy Corp. and Warren Resources Inc.; and (ii) a peer group for Quest Energy consisting of the following eight publicly traded U.S. limited partnerships and limited liability companies: Atlas Energy Resources, LLC, Linn Energy, LLC, BreitBurn Energy Partners, L.P., Legacy Reserves, L.P. , EV Energy Partners, L.P., Constellation Energy Partners, LLC, Encore Energy Partners, L.P. and Vanguard Natural Resources, LLC.

Additionally, the Committee utilized Equilar in 2008 to collect market data concerning total compensation for director and Named Executive Officer positions at comparable peer group companies. The peer group used for the Equilar benchmarking service includes: ATP Oil & Gas Corporation, Brigham Exploration Co., Carrizo Oil & Gas, Inc., Edge Petroleum Corporation, Gastar Exploration Ltd., GMX Resources Inc., Goodrich Petroleum Corporation, Linn Energy, LLC, McMoRan Exploration Co., Parallel Petroleum Corporation, Toreador Resources Corporation, and Warren Resources Inc.

Elements of Executive Compensation Program

Our compensation program for Named Executive Officers consists of the following components:

Base Salary: The base salary element of our compensation program serves as the foundation for other compensation components and addresses the first compensation objective stated above, which is to attract and retain well-qualified executives. Base salaries for all Named Executive Officers are established based on their scope of responsibilities, taking into account competitive market compensation paid by other companies in our peer group. The Committee considers the median salary range for each Named Executive Officer’s counterpart, but makes adjustments to reflect differences in job descriptions and scope of responsibilities for each Named Executive Officer and to reflect the Committee’s philosophy that each Named Executive Officer’s total compensation should be at the median level (50th percentile) relative to our peer group. The Committee annually reviews base salaries for Named

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Executive Officers and makes adjustments from time to time to realign their salaries, after taking into account individual performance, responsibilities, experience, autonomy, strategic perspectives and marketability, as well as the recommendations of the principal executive officer.

In August 2008, David Lawler’s and Jack Collins’s executive officer positions changed and their duties and responsibilities increased. Accordingly, in October 2008, their base salaries were increased and they were granted stock options after the Committee took into account their individual performance, increased responsibilities and experience and competitive data provided by T-P and Equilar.

The Committee allocated approximately 4% of all base salaries of the Named Executive Officers to a pool to be used as a cost of living adjustment. The Committee approved a 4% increase for Mr. Cash and gave Mr. Cash the authority to divide the remaining pool among the Named Executive Officers (other than Mr. Cash).

Management Annual Incentive Plan: In 2006, the Committee established the QRC Bonus Plan. The QRC Bonus Plan is intended to recognize value creation by providing competitive incentives for meeting and exceeding annual financial and operating performance measurement targets related to our exploration and production operations.

By providing market-competitive bonus awards, the Committee believes the QRC Bonus Plan supports the compensation objective of attracting and retaining Named Executive Officer talent critical to achieving superior performance and support the compensation objective of tying annual incentives to the achievement of specific short-term performance goals during the year, which creates a direct connection between the executive’s pay and our financial performance.

For 2008, awards under the QRC Bonus Plan were paid solely in cash. The Committee anticipates that future annual bonus awards will also be paid only in the form of cash awards, except that a portion of Mr. Lawler’s award may be paid in the form of QRCP common stock.

Each year the Committee establishes goals during the first quarter of the calendar year. The 2008 performance goals for the QRC Bonus Plan are described below. The amount of the bonus payable to each participant varies based on the percentage of the performance goals achieved and the employee’s position with us. More senior ranking management personnel are entitled to bonuses that are potentially a higher percentage of their base salaries, reflecting the Committee’s philosophy that higher ranking employees should have a greater percentage of their overall compensation at risk.

Each executive officer and key employee that participates in the QRC Bonus Plan has a target bonus percentage expressed as a percentage of base salary based on his or her level of responsibility. The performance criteria for 2008 includes minimum performance thresholds required to earn any incentive compensation, as well as maximum payouts geared towards rewarding extraordinary performance, thus, actual awards can range from 0% (if performance is below 60% of target) to 99% of base salary for our most senior executives (if performance is 150% of target). For 2008, the potential bonus amounts for each of Messrs. Cash, Grose, Lawler, and Collins were as follows: If we achieved an average of our financial goals of 60%, their incentive awards would be 22% of base salary. If we achieved an average of our financial goals of 100%, their incentive awards would be 42% of base salary. If we achieved an average of our financial goals of 150%, their incentive awards would be 99% of base salary. For 2008, the potential bonus amounts for each of the other Named Executive Officers were as follows: If we achieved an average of our financial goals of 60%, their incentive awards would be 7% of base salary. If we achieved an average of our financial goals of 100%, their incentive awards would be 27% of base salary. If we achieved an average of our financial goals of 150%, their incentive awards would be 73.5% of base salary.

After the end of the Plan Year, the Committee determines to what extent we and the participants have achieved the performance measurement goals. The Committee calculates and certifies in writing the amount of each participant’s bonus based upon the actual achievements and computation formula set forth in the QRC Bonus Plan. The Committee has no discretion to increase the amount of any Named Executive Officer’s bonus as so determined, but may reduce the amount of or totally eliminate such bonus, if it determines, in its absolute and sole discretion that such reduction or elimination is appropriate in order to reflect the Named Executive Officer’s performance or unanticipated factors. The performance period (“Incentive Period”) with respect to which target awards and

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bonuses may be payable under the QRC Bonus Plan will generally be the fiscal year beginning on January 1 and ending on December 31, but the Committee has the authority to designate different Incentive Periods.

The Committee increased certain 2008 performance targets for the QRC Bonus Plan from the 2007 levels. Since our drilling program for 2008 concentrated mainly on drilling new wells located on our proved undeveloped reserves, the Committee eliminated the increase in year end proved reserves as a performance measure in 2008. The Committee added a “health, safety and environment” target in order to reflect our commitment to improving the environment, increasing worker safety and reducing costs. The Committee established the 2008 performance targets and percentages of goals achieved for each of the five corporate goals described below:


	Percentage of Goal Achieved
	50%		100%		150%

Performance Measure and % Weight

Cost reduction in savings — health, safety and environment (20% in the aggregate)
Number of OSHA recordable injuries (5%)		33		30		26
Number of vehicle incidents > $1,000 (5%)		20		18		15
Salt water spills (Bbls) (5%)		14,760		13,120		11,480
Number of spills (5%)		338		301		263
EBITDA (earnings before interest, taxes, depreciation and amortization) (20%)	$	69,300,000	$	72,400,000	$	78,800,000
Lease operating expense (excluding gross production taxes and ad valorem taxes) (20%)	$	28,246,660	$	25,700,000	$	23,153,000
Finding and development cost (20%)	$	1.52/Mcf	$	1.39/Mcf	$	1.25/Mcf
Production (20%)		22.5 Bcfe		23.1 Bcfe		24.5 Bcfe

Each of the five corporate goals were equally weighted. The amount of the incentive bonus varies depending upon the average percentage of the goals achieved. For amounts between 50% and 100% and between 100% and 150%, linear interpolation is used to determine the “Percentage of Goal Achieved.” For amounts below 50%, the “Percentage of Goal Achieved” is determined using the same scale as between 50% and 100%. For amounts in excess of 150%, the “Percentage of Goal Achieved” is determined using the same scale as between 100% and 150%. For 2008, no incentive awards would have been payable under the QRC Bonus Plan if the average percentage of the goals achieved was less than 60%. Additionally, no additional incentive awards were payable if the average percentage of the goals achieved exceeded 150%. For 2008, the average percentage of the goals achieved under the QRC Bonus Plan was 60.9%. We made a dramatic improvement in our health, safety and environment performance for 2008 compared to 2007. Without this strong health, safety and environment performance our average percentage of goals achieved would have been below 60% and no bonuses would have been payable under the QRC Bonus Plan. We believe that we realized a number of benefits from improving our health, safety and environment performance, including improving the environment where our wells are located, reducing worker injuries and reducing costs. In addition, we should be able to significantly lower our insurance costs if we are able to maintain our 2008 level of performance.

Additionally, with respect to the 2008 awards, and any future awards under the QRC Bonus Plan, if our overall performance under the QRC Bonus Plan equals or exceeds 100%, Mr. Lawler will be granted a number of performance shares and restricted shares (valued based on the closing price of the Company’s common stock at year end) under the Company’s Omnibus Plan, each having a value equal to 50% of the payment Mr. Lawler would have been paid under the QRC Bonus Plan if our overall performance under the QRC Bonus Plan was 100%. The performance shares will be immediately vested and the restricted shares will vest on the first anniversary of the date of grant. The Company’s overall performance under the QRC Bonus Plan for 2008 was less than 100%, so no additional equity award was payable to Mr. Lawler for 2008.

Mr. Lopus commenced employment as our EVP — Appalachia in July 2008, and Mr. Lopus received a pro rata portion of the bonus for 2008 under the QRC Bonus Plan.

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Discretionary Bonuses: In October 2008, our Board of Directors adopted a 2008 Supplemental Bonus Plan (the “Supplemental Bonus Plan”) for certain key employees, excluding Mr. Lawler. The Supplemental Bonus Plan provided additional incentive and bonus opportunities to supplement the bonus opportunities available to employees under the QRC Bonus Plan for 2008 and additional key employees. The determination as to whether a bonus payment was made under the Supplemental Bonus Plan and the amount of that payment was solely within the discretion of Mr. Lawler, who took into account both our performance during 2008 and the respective employee’s individual performance during 2008. The maximum amount that an employee was eligible to receive under the Supplemental Bonus Plan was dependent upon the employee’s classification under the QRC Bonus Plan less the actual amount such individual received under the QRC Bonus Plan, if any, for 2008. The maximum aggregate amount of bonuses available under the Supplemental Bonus Plan was capped at $2 million. Employees were to receive their supplemental bonuses in quarterly payments in 2009. To the extent an employee’s payment under the QRC Bonus Plan, if any, was greater than or less than originally anticipated at the time the amount of the employee’s supplemental bonus was established, any quarterly payment made after the payment under the QRC Bonus Plan were to be appropriately adjusted. Mr. Lawler awarded quarterly discretionary bonuses in January 2009, which were related to 2008 performance. The Compensation Committee subsequently terminated the Supplemental Bonus Program.

In connection with the amendment to Mr. Lawler’s employment agreement in October 2008 and in lieu of participating in the Supplemental Bonus Plan, the Committee authorized the payment of a $232,000 bonus to Mr. Lawler in November 2008 and payment of an amount equal to $164,000 minus the amount, if any, Mr. Lawler is paid under the QRC Bonus Plan in 2009 for his 2008 performance, which was payable at the same time as the awards under the QRC Bonus Plan for 2008 were payable in March 2009.

Certain of our executive officers had entered into 10b(5)-1(c) trading plans with the company and a designated broker that provided that upon vesting of restricted stock our chief financial officer would notify the designated broker of the number of shares that needed to be sold in order to generate sufficient funds to satisfy the executive officers’ tax withholding obligations (which would have been about 30% of the shares that vested). During 2008, several of the executive officers had restricted shares that vested in March and April at a time when QRCP’s stock price was generally between $6.50 and $7.00 per share. Our former chief financial officer did not perform his obligations under the trading plans, but the executive officers still incurred a tax liability based on the stock price on the date of vesting. Subsequent to the disclosure of the Transfers, our stock price dropped significantly to under one dollar. At that time, it came to the attention of our Board of Directors that our former chief financial officer had not complied with the trading plans. The Board of Directors decided to make the executive officers whole due to our former chief financial officer’s inaction. The Board of Directors agreed to pay the affected executive officers a bonus equal to the value of approximately 30% of each executive officer’s stock on the date of vesting in exchange for approximately 30% of the vested shares (the approximate number of shares that would have been sold under the trading plans). The Board of Directors also agreed to pay the affected executive officers a tax gross-up payment on this bonus, since the bonus was additional taxable income that the executive officers would not have had if our former chief financial officer had complied with the trading plans.

Productivity Gain Sharing Payments: For part of 2008, we made productivity sharing payments, which were comprised of a one-time cash payment equal to 10% of an individual’s monthly base salary earned during each month that our CBM production rate increased by 1,000 Mcf/day over the prior record. All of our employees were eligible to receive productivity gain sharing payments. The purpose of these payments was to incentivize all employees, including Named Executive Officers, to continually and immediately focus on production. The Named Executive Officers received payments equal to less than one month of base salary as a result of this plan.

Equity Awards: The Committee believes that the long-term performance of our executive officers is enhanced through ownership of stock-based awards, such as stock options and restricted stock, which expose executive officers to the risks of downside stock prices and provide an incentive for executive officers to build shareholder value.

Omnibus Stock Award Plan. Our Omnibus Plan provides for grants of non-qualified stock options, restricted shares, bonus shares, deferred shares, stock appreciation rights, performance units and performance shares. Currently, the total number of shares that may be issued under the Omnibus Plan is 2,700,000. The Omnibus

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Plan also permits the grant of incentive stock options. The objectives of the Omnibus Plan are to strengthen key employees’ and non-employee directors’ commitment to our success, to stimulate key employees’ and non-employee directors’ efforts on our behalf and to help us attract new employees with the education, skills and experience we need and retain existing key employees. All of our equity awards consisting of our common stock are issued under the Omnibus Plan.

In connection with the adoption of the LTIP and amendments made to the Omnibus Plan and QRC Bonus Plan in May 2008, the Committee received guidance from RiskMetrics with respect to corporate governance matters. As a result of the Committee’s discussions with RiskMetrics, the Committee adopted a “burn rate” policy. This policy provides that for the years ended December 31, 2008, 2009 and 2010, our prospective three-year average burn rate with respect to our equity awards will not exceed the mean and one standard deviation of our Global Industry Classification Standards Peer Group (1010 — Energy) of 4.43%. For purposes of calculating the three-year average burn rate under this burn rate policy, each restricted stock (unit), bonus share or stock award or any forms of full-value awards granted under our equity plans will be counted as 1.5 award shares and will be calculated as (i) the number of equity awards granted in each fiscal year by the Committee to employees and directors, excluding awards granted to replace securities assumed in connection with a business combination transaction, divided by (ii) the weighted average basic shares outstanding.

As a result of the termination of Messrs. Cash and Grose and other employees related to the internal investigation and related matters, a significant percentage of our prior unvested equity awards were forfeited during 2008. However, under the burn rate policy, awards that are forfeited during the year are not taken into account in calculating the burn rate.

In order to attract a new chief financial officer and to compensate Messrs. Lawler and Collins for their increased roles at the Company, the Committee determined that it was necessary under the circumstances to grant new equity awards during 2008 that exceeded the burn rate policy. However, we are significantly below the burn rate policy if the forfeiture of previously granted awards is taken into consideration.

Long-Term Incentive Plan. In May 2008, the Committee adopted the LTIP. Under the LTIP, our principal executive officer would have received awards of restricted stock under the Omnibus Plan if the adjusted average share price for a calendar year exceeded both the “initial value” ($9.74 for 2007) and the “adjusted average share price” for the prior year. The “adjusted average share price” is the adjusted average of the fair market values for each trading day during a calendar year, taking into account the trading volume of our shares on each day. Any restricted stock awards granted to our principal executive officer under the LTIP would have vested ratably over a three-year period. The LTIP also provided for awards of restricted stock to the other participants (including the Named Executive Officers) based upon (1) a pool of 3% of our consolidated income before depreciation, depletion, amortization and taxes and ignoring changes in income attributable to non-cash changes in derivative fair value and (2) the stock price as of the day awards were made under the Omnibus Plan. Any restricted stock awards under the LTIP to the other participants would have vested over a two-year period.

The LTIP was intended to encourage participants to focus on our long-term performance, align the interests of management with those of our stockholders, and provide an opportunity for our executive officers to increase their stake in us through grants of restricted stock pursuant to the terms of the Omnibus Plan. The Committee designed the long-term incentive plan to:


	•	enhance the link between the creation of stockholder value and long-term incentive compensation;

	•	provide an opportunity for increased equity ownership by executive officers; and

	•	maintain a competitive level of total compensation.

However, for 2008, the Committee elected to not make any awards, and effective January 1, 2009, the LTIP was terminated due to (1) the large number of shares that would have been required to be issued due to our low stock price and (2) the establishment of the Supplemental Bonus Plan discussed above.

Quest Energy Partners Long Term Incentive Plan. In July 2007, we formed Quest Energy to own and operate our Cherokee Basin assets and to acquire, exploit and develop oil and natural gas properties in the Cherokee Basin. On November 14, 2007, Quest Energy’s general partner, Quest Energy GP adopted the Quest Energy Partners, L.P.

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Long-Term Incentive Plan for employees, consultants and directors of Quest Energy GP and any of its affiliates who perform services for Quest Energy. The long-term incentive plan consists of the following securities of Quest Energy: options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The purpose of awards under the long-term incentive plan is to provide additional incentive compensation to employees providing services to Quest Energy, and to align the economic interests of such employees with the interests of Quest Energy’s unitholders. The total number of common units available to be awarded under the long-term incentive plan is 2,115,950. Common units cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The plan is administered by the Committee, provided that administration may be delegated to such other committee as appointed by Quest Energy GP’s board of directors. To date, no awards have been made under this plan other than to the independent directors of Quest Energy GP.

Benefits

Our employees, including the Named Executive Officers, who meet minimum service requirements are entitled to receive medical, dental, life and disability insurance benefits for themselves (and beginning the first of the following month after 90 days of employment, 50% coverage for their dependents). Our Named Executive Officers also participate along with other employees in our 401(k) plan and other standard benefits. Our 401(k) plan provides for matching contributions by us and permits discretionary contributions by us of up to 10% of a participant’s eligible compensation. Such benefits are provided equally to all employees, other than where benefits are provided pro rata based on the respective Named Executive Officer’s salary (such as the level of disability insurance coverage).

Perquisites

We believe our executive compensation program described above is generally sufficient for attracting talented executives and that providing large perquisites is neither necessary nor in the stockholders’ best interests. Certain perquisites are provided to provide job satisfaction and enhance productivity. For example, we provide an automobile for Messrs. Lawler, Marlin and Lopus and provided an automobile for Mr. Cash. On occasion, family members and acquaintances accompanied Mr. Cash on business trips made on private charter flights. The Named Executive Officers also are eligible to receive gym and social club memberships and subsidized parking. Messrs. Lawler and Collins received reimbursements of certain relocation and temporary living expenses in connection with their move to Oklahoma City, Oklahoma in 2007 and 2008, respectively.

Ownership Guidelines (Stock Ownership Policy)

Our Board of Directors, upon the Committee’s recommendation, adopted a Stock Ownership Policy for our corporate officers and directors (“Guideline Owners”) to ensure that they have a meaningful economic stake in us. The guidelines are designed to satisfy an individual Guideline Owner’s need for portfolio diversification, while maintaining management stock ownership at levels high enough to assure our stockholders of management’s commitment to value creation.

The Committee annually reviews each Guideline Owner’s compensation and stock ownership levels to confirm if appropriate or make adjustments. The Committee requires that the Guideline Owners have direct ownership of our common stock in at least the following amounts:


	•	*CEO* — five times base salary

	•	*Directors* — four times cash compensation (including committee fees)

	•	*Direct CEO Reports* — two and one-half times base salary

	•	*Corporate Officers (vice president or higher and controller)* — one and one-half times base salary.

A corporate officer has five years to comply with the ownership requirement from the later of: (a) February 1, 2007 or (b) the date the individual was appointed to a position noted above. A director has five years to comply with the ownership requirement from the later of: (a) January 1, 2008 or (b) the date the individual was appointed to be a

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director. If a corporate officer is promoted to a position with a higher stock ownership salary multiple, the corporate officer will have five years from the date of the change in position to reach the higher expected stock ownership salary multiple, but still must meet the prior expected stock ownership salary multiple within the original five years of the date first appointed to such prior position or February 1, 2007, whichever is later.

Until a Guideline Owner achieves the applicable stock ownership salary multiple, the following applies:


	•	Restricted Stock/Bonus Share Awards. Upon vesting of a restricted stock or bonus share award, the Guideline Owner is required to hold the net profit shares until the applicable Stock Ownership Guideline is met.

	•	Exercise of Options. Upon exercise of a stock option, the Guideline Owner is required to hold net profit shares (less any shares used to pay the exercise price for the shares) until the applicable Stock Ownership Guideline is met.

	•	Reporting of Taxes upon Vesting/Exercise. The Guideline Owner must report to the Corporate Secretary the number of shares required by such Guideline Owner to pay the applicable taxes upon the vesting of restricted stock or bonus share awards or exercise of stock options in excess of the minimum statutory taxes and any shares used to pay the exercise price of any options.

Notwithstanding the foregoing, corporate officers are not required to hold bonus shares that were originally granted prior to January 1, 2007 or any bonus shares awarded pursuant to the 2006 management annual incentive plan.

Required Ownership Shares. Upon reaching the required stock ownership salary multiple, the Guideline Owner must certify to the Corporate Secretary that the ownership requirements have been met and the Corporate Secretary must confirm such representation and record the number of shares required to be held by the Guideline Owner based on the closing price of the shares and the corporate officer’s current salary level or the director’s current compensation level on the day prior to certification by the Guideline Owner (the “Required Ownership Shares”).

The Guideline Owner is not be required to accumulate any shares in excess of the Required Ownership Shares so long as the Required Ownership Shares are held by the Guideline Owner, regardless of changes in the price of the shares. However, the Guideline Owner may only sell shares held prior to certification if, after the sale of shares, the Guideline Owner will (a) still own a number of shares equal to at least the Required Ownership Shares or (b) still be in compliance with the stock ownership salary multiple as of the day the shares are sold based on current share price and salary level.

Annual Review. The Committee reviews all Required Ownership Shares levels of the Guideline Owners covered by the Policy on an annual basis. Deviations from the Stock Ownership Policy can only be approved the Committee and then only because of a “personal hardship”.

Policy Regarding Hedging Stock Ownership

In April 2007, the Board of Directors, upon the Committee’s recommendation, adopted a policy to prohibit directors, executive officers and employees from speculating in our stock, including, but not limited to, the following: short selling (profiting if the market price of the stock decreases); buying or selling publicly traded options, including writing covered calls; taking out margin loans against stock options; and hedging or any other type of derivative arrangement that has a similar economic effect without the full risk or benefit of ownership. In March 2009, the Board of Directors amended the policy to also prohibit directors, executive officers and employees from pledging any of our stock and taking out margin loans against shares of our stock.

Compensation Recovery Policies

The Board maintains a policy that it will evaluate in appropriate circumstances whether to seek recovery of certain compensation awards paid to our executive officers and any profits realized from their sale of our securities if we are required to prepare an accounting restatement due to our material noncompliance, as a result of misconduct, with any financial reporting requirement under the securities laws. This policy ensures that if

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circumstances warrant, we may seek to claw back appropriate portions of our executive officer’s compensation for the relevant period, as provided by law. This supplements the SEC’s ability, under Section 304 of the Sarbanes-Oxley Act of 2002, to claw back appropriate portions of the Chief Executive Officer’s and Chief Financial Officer’s compensation under the same circumstances.

Tax and Accounting Considerations

U.S. federal tax laws (Section 162(m) of the Internal Revenue Code of 1986, as amended) impose a limitation on our U.S. income tax deductibility of Named Executive Officer compensation, unless it is “performance-based” under the tax rules. The Committee is concerned about the tax aspects of restricted stock and bonus share grants because they are not currently performance-based awards. The Committee will evaluate and consider possible performance elements for future awards. The Committee, however, does not believe the failure of Named Executive Officers equity awards to qualify as performance based awards to have a material impact on the Company at this time.

Executive Compensation and Other Information

The table below sets forth information concerning the annual and long-term compensation paid to or earned by Jerry Cash and David Lawler, who each served as our principal executive officer during 2008; David Grose and Jack Collins, who each served as our principal financial officer during 2008; and the three other most highly compensated executive officers who were serving as executive officers as of December 31, 2008 (the “Named Executive Officers”). The positions of the Named Executive Officers listed in the table below are those positions held in 2008.

Summary Compensation Table


												Non-Equity		All
							Stock			Option		Incentive Plan		Other
Name and Principal Position	Year		Salary		Bonus (1)		Awards (2)			Awards (3)		Compensation (4)		Compensation (5)			Total

Jerry D. Cash		2008	$	349,731	$	100	$	(637,113	)		—	$	22,225	$	11,534		$	(253,523	)
Chairman of the Board,		2007	$	491,346	$	1,200	$	2,048,169			—	$	289,667	$	11,300		$	2,841,682
President and Chief		2006	$	400,000	$	1,300	$	14,000			—	$	165,333	$	11,054		$	591,687
Executive Officer

David Lawler(6)		2008	$	344,616	$	390,244	$	280,735		$	48,000	$	104,917	$	50,205		$	1,218,717
President, Chief Operating Officer and Director		2007	$	180,692	$	1,200	$	515,264			—	$	107,672	$	96,040		$	900,868

David E. Grose		2008	$	275,154	$	100	$	(140,993	)		—	$	17,850	$	11,538		$	163,649
Chief Financial Officer		2007	$	329,808	$	1,200	$	1,129,900			—	$	193,458	$	11,300		$	1,665,666
		2006	$	270,240	$	1,200	$	203,890			—	$	113,667	$	11,054		$	600,051

Jack Collins(7)		2008	$	152,500	$	28,600	$	289,363		$	19,619	$	52,042	$	49,994	(8)	$	592,118
Interim Chief Financial
Officer and Executive VP
Finance/Corporate
Development

Richard Marlin		2008	$	254,486	$	17,990	$	154,302			—	$	32,851	$	11,550		$	471,179
Executive VP Engineering		2007	$	247,865	$	1,500	$	270,421			—	$	102,073	$	11,300		$	633,159
		2006	$	247,500	$	1,000	$	195,066			—	$	77,550	$	11,054		$	532,170

David Bolton		2008	$	230,885	$	57,848	$	196,108			—	$	29,805	$	24,542		$	539,188
Executive VP Land		2007	$	228,461	$	1,200	$	414,205			—	$	92,625	$	11,300		$	747,791
		2006	$	100,961	$	1,000	$	65,856			—	$	39,588	$	2,746		$	210,151

Thomas Lopus (9)		2008	$	95,192	$	26,156	$	126,131			—	$	10,313	$	8		$	257,800
Executive Vice President
Appalachia

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(1)		See “Compensation Discussion and Analysis — Elements of Executive Compensation Program — Discretionary Bonuses,” exclusive of the portion constituting a tax gross-up. Also includes other miscellaneous bonuses available to all employees totaling less than $1,500 per named executive officer.

(2)		Includes expense related to bonus shares and restricted stock granted under employment agreements. Expense for the bonus shares and restricted stock is computed in accordance with the provisions of Statement of Financial Accounting Standards No. 123 (Revised) (“SFAS No. 123R”) and represents the grant date fair value, which for our common stock was determined by utilizing the closing stock price on the date of grant, with expense being recognized ratably over the requisite service period. Also includes equity portion of the QRC Bonus Plan award earned for 2006. Twenty-five percent of the bonus shares vested in March 2007 at the time the Committee determined the amount of the awards based upon 2006 performance, twenty-five percent of the bonus shares vested in March 2008 and the remaining portion vests and will be paid in March of each of the next two years. Amounts for Messrs. Cash and Grose in 2008 are negative due to forfeiture of unvested equity awards in connection with the termination of their employment during the year.

(3)		Includes expense related to stock options granted to Mr. Lawler and Mr. Collins during 2008. Expense for the stock options is computed in accordance with the provisions of Statement of Financial Accounting Standards No. 123 (Revised) (“SFAS No. 123R”) and represents the grant date fair value, which is calculated using the Black-Scholes Option Pricing Model, with expense being recognized ratably over the requisite service period. For a discussion of valuation assumptions, see Note 10 — Stockholders’ Equity — Stock Awards of the notes to the consolidated financial statements included in this Form 10-K.

(4)		Represents the QRC Bonus Plan awards earned for 2007 and 2008 and paid in 2008 and 2009, as applicable, the cash portion of the QRC Bonus Plan awards earned for 2006 and paid in 2007 and productivity gain sharing bonus payments earned and paid in 2006, 2007 and 2008.

(5)		Company matching contribution under the 401(k) savings plan, life insurance premiums, perquisites and personal benefits if $10,000 or more for the year and, for Messrs. Lawler and Bolton, tax withholding gross-ups related to discretionary bonuses paid in 2008 relating to the failure of our former chief financial officer to execute on 10b-5(1)(c) trading plans. See “Compensation Discussion and Analysis — Elements of Executive Compensation Program — Discretionary Bonuses.” Salary shown above has not been reduced by pre-tax contributions to the company-sponsored 401(k) savings plan. For 2008, Company matching contributions were as follows: Mr. Cash — $11,500, Mr. Lawler — $10,193, Mr. Grose — $11,500, Mr. Collins — $6,245, Mr. Marlin — $11,500, Mr. Bolton — $9,437 and Mr. Lopus — $0. Tax withholding gross-up in 2008 for Mr. Lawler was $39,962 and for Mr. Bolton was $15,055.

(6)		Mr. Lawler’s employment as our chief operating officer commenced on April 10, 2007 and as our president effective as of August 23, 2008.

(7)		Mr. Collins’s employment as our executive vice president of investor relations commenced on December 3, 2007 and as our interim chief financial officer and executive vice president of finance/corporate development effective as of August 23, 2008.

(8)		Perquisites and personal benefits for 2008 consist of expenses related to relocation expenses ($40,782), benefits for gym services, parking and social club membership.

(9)		Mr. Lopus’s employment as our Executive Vice President Appalachia commenced on July 16, 2008.

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Grants of Plan-Based Awards in 2008

This table discloses the actual number of stock options and restricted stock awards granted during the last fiscal year, the grant date fair value of these awards and the estimated payouts under non-equity incentive plan awards.

Grants of Plan-Based Awards in 2008


												Estimated
												future
												payouts			All other		All other
												under			stock		option					Grant date
												equity			awards:		awards:			Exercise		fair value
						Estimated future payouts under						incentive			Number of		Number of			or base		of stock
						non-equity incentive plan awards						plan awards			shares of		securities			price of		and
	Approval		Grant			Threshold		Target		Maximum		Target			stock or		underlying			option		option
Name	Date		Date			($)		($)		($)		($)			units (#)		options (#)			awards ($/Sh)		awards(1)

Jerry Cash				(2	)	$	115,500	$	220,500	$	519,750
				5/19/08	(3)								(3	)
				(4	)			$	22,225
David Lawler				(2	)	$	75,816	$	144,739	$	341,170
				5/19/08	(3)							$	24,166
				(4	)			$	16,917
		10/20/08		10/20/08														200,000	(5)	$	0.71	$	122,000
David Grose				(2	)	$	77,000	$	147,000	$	346,500
				5/19/08	(3)							$	25,133
				(4	)			$	17,850
Jack Collins				(2	)
				5/19/08	(3)							$	8,976
				(4	)			$	8,042
		10/20/08		10/23/08														100,000	(6)	$	0.48	$	41,000
Richard Marlin				(2	)	$	17,814	$	68,711	$	187,047
				5/19/08	(3)							$	17,808
				(4	)			$	14,797
David Bolton				(2	)	$	16,162	$	62,339	$	169,700
				5/19/08	(3)							$	16,517
				(4	)			$	13,425
Thomas Lopus				(2	)	$	6,663	$	25,696	$	69,937
				(4	)			$	3,750
		6/30/08		7/14/08	(7)											45,000						$	441,450


(1)		The amounts included in the “Grant date fair value of stock and option awards” column represents the grant date fair value of the awards made to Named Executive Officers in 2008 computed in accordance with SFAS No. 123(R). The value ultimately realized by the executive upon the actual vesting of the award(s) or the exercise of the stock option(s) may or may not be equal to the SFAS No. 123(R) determined value. For a discussion of valuation assumptions, see Note 10 — Stockholders’ Equity — Stock Awards of the notes to the consolidated financial statements included in this Form 10-K.

(2)		Represents an award under the QRC Bonus Plan for 2008. On March 26, 2009, the Committee determined the amount of the award payable for 2008 based upon 2008 performance. The amounts for Messrs. Lawler, Collins, Marlin, Bolton and Lopus are based upon their actual base salary paid during the year. The amounts for Messrs. Cash and Grose represents the amounts they would have been entitled to receive if they had remained employed with the Company for the entire year at the salaries provided for in their employment agreements. See “Compensation Discussion and Analysis — Elements of Executive Compensation Program — Management Annual Incentive Plan” for a discussion of the performance criteria applicable to these awards.

(3)		Represents amounts payable under the LTIP adopted by the Board of Directors on May 19, 2008. The award for Mr. Cash was an indeterminate number of shares based on the increase in our adjusted average share price for 2008 over $9.74. As such, a target amount for the award was not determinable. The amount of Mr. Cash’s award was capped at $3.0 million. For the other Named Executive Officers, a bonus pool equal to three percent of our consolidated income before income taxes, adjusted to (1) add back depreciation, depletion and amortization expenses and (2) exclude the effect of non-cash derivative fair value gains or losses, for the applicable calendar year or period (“Measured Income”) was to be divided among plan participants based on their relative base

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		salaries. Each individual would then be issued that number of shares equal to the dollar amount of their award divided by the stock price as of the day the Compensation Committee finalized the awards. For purposes of this table, the target amount is based on the base salaries of all participants as of May 19, 2008 and assumes QRCP’s Measured Income was equal to the budgeted amount. The LTIP program for 2008 was terminated in January 2009 and no awards were paid to the Named Executive Officers for 2008.

(4)		Represents amount payable under our productivity gain sharing bonus program.

(5)		100,000 shares subject to the stock option were immediately vested.

(6)		50,000 shares subject to the stock option were immediately vested.

(7)		Represents an equity award granted in connection with the execution of Mr. Lopus’s employment agreement in 2008. Grant date is the date the employment agreement was executed. One-third of the award vests on July 16, 2009, 2010 and 2011.

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Equity Awards Outstanding at Fiscal Year-End 2008

The following table shows unvested stock awards and stock options outstanding for the Named Executive Officers as of December 31, 2008. Market value is based on the closing market price of our common stock on December 31, 2008 ($0.44 a share).


	Option Awards									Stock Awards
	Number of		Number of										Market value
	Securities		Securities							Number of			of shares or
	Underlying		Underlying							shares or			units of stock
	Unexercised		Unexercised			Option		Option		units that			that
	Options		Options (#)			Exercise		Expiration		have not			have not
	(#) Exercisable		Unexercisable			Price ($)		Date		vested			vested

Jerry Cash(1)		—		—			—		—		—			—
David Lawler		100,000		100,000	(2)	$	0.71		10/20/18		60,000	(3)	$	26,400
David Grose(4)		—		—			—		—		—			—
Jack Collins		50,000		50,000	(5)	$	0.48		10/23/18		40,000	(6)	$	17,600
Richard Marlin		—		—			—		—		31,376	(7)	$	13,805
Dave Bolton		—		—			—		—		30,740	(8)	$	13,526
Thomas Lopus		—		—			—		—		45,000	(9)	$	19,800


(1)		Mr. Cash forfeited all of his unvested stock awards when he resigned all of his positions with us on August 23, 2008.

(2)		Option vests on October 20, 2009.

(3)		30,000 shares vest on each of May 1, 2009 and 2010.

(4)		All of Mr. Grose’s unvested stock awards were forfeited in connection with the termination of his employment on September 13, 2008.

(5)		Option vests on October 23, 2009.

(6)		20,000 shares vest on each of December 3, 2009 and 2010.

(7)		15,688 shares vest on each of March 16, 2009 and 2010.

(8)		15,370 shares vest on each of March 16, 2009 and 2010.

(9)		15,000 shares vest on each of July 16, 2009, 2010 and 2011.

Stock Vested in 2008

The following table sets forth certain information regarding stock awards vested during 2008 for the Named Executive Officers.


	Stock Awards
	Number of shares of
	common stock acquired		Value realized on
Name	on vesting (#)		vesting ($)

Jerry Cash		166,088	$	1,077,625
David Lawler		30,000	$	266,400
David Grose		36,188	$	231,544
Jack Collins		20,000	$	7,200
Richard Marlin		27,688	$	129,924
David Bolton		35,370	$	149,282
Thomas Lopus		—		—

For purposes of the above table, the amount realized upon vesting is determined by multiplying the number of shares of stock or units by the market value of the shares or units on the date the shares vested.

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Director Compensation for 2008

The following table discloses the cash, equity awards and other compensation earned, paid or awarded, as the case may be, to each of our directors during the fiscal year ended December 31, 2008.


	Fees earned or		Stock Awards
Name	paid in cash ($)		($)(1)			Total ($)

James Kite	$	44,434	$	113,012(2	)	$	157,446
Jon Rateau	$	63,125	$	113,012(2	)	$	176,137
John Garrison	$	57,500	$	113,012(2	)	$	170,512
Malone Mitchell	$	13,750		—(3	)	$	13,750
William Damon	$	51,585	$	192,372(4	)	$	243,957
Bob Alexander	$	21,586		—		$	21,586
Greg McMichael	$	444		—		$	444


(1)		Represents the dollar amount recognized for financial statement reporting purposes for 2008 in accordance with FAS 123R.

(2)		In October 2005, Messrs. Kite, Rateau, and Garrison each received a grant of an option for 50,000 shares of common stock. Each option has a term of 10 years and an exercise price of $10.00 per share. The FAS 123R grant date fair value of each option award was $370,000. Options for 10,000 shares were immediately vested and the options for the remaining 40,000 shares were to vest 10,000 per year over the next four years; provided that the director was still serving on the board of directors at the time of the vesting of the stock options. However, as described below, in March 2008, Messrs. Kite, Rateau, and Garrison each exchanged their 20,000 unvested stock options for 10,000 bonus shares of common stock of the Company; 5,000 of these shares vested in October 2008 and 5,000 of these shares will vest in October 2009. The incremental fair value of this exchange, computed in accordance with FAS 123R, as of the exchange date was $51,600. On June 19, 2008, Messrs. Kite, Rateau, and Garrison each received a grant of 5,000 shares of common stock. The FAS 123R grant date fair value of these shares was $36,000.

(3)		In August 2007, Mr. Mitchell received a grant of an option for 50,000 shares of common stock. The option had a term of 10 years and an exercise price of $10.05 per share. The FAS 123R grant date fair value of the option award was $398,000. Options for 10,000 shares were immediately vested and the options for the remaining 40,000 shares were to vest 10,000 per year over the next four years; provided that Mr. Mitchell was still serving on the board of directors at the time of the vesting of the stock options. However, as described below, in March 2008, Mr. Mitchell exchanged his 40,000 unvested stock options for 20,000 bonus shares of common stock of the Company. The incremental fair value of this exchange, computed in accordance with FAS 123R, as of the exchange date was $38,400. Mr. Mitchell resigned from the board of directors on May 7, 2008, and forfeited all 20,000 bonus shares, so no compensation cost was recorded in 2008.

(4)		In August 2007, Mr. Damon received a grant of an option for 50,000 shares of common stock. The option had a term of 10 years and an exercise price of $10.05 per share. The FAS 123R grant date fair value of the option award was $398,000. Options for 10,000 shares were immediately vested and the options for the remaining 40,000 shares were to vest 10,000 per year over the next four years; provided that Mr. Damon was still serving on the board of directors at the time of the vesting of the stock options. However, as described below, in March 2008, Mr. Damon exchanged his 40,000 unvested stock options for 20,000 bonus shares of common stock of the Company; 5,000 of these shares vested in August 2008 and 5,000 of these shares will vest in August of 2009, 2010 and 2011. The incremental fair value of this exchange, computed in accordance with FAS 123R, as of the exchange date was $38,400. On June 19, 2008, Mr. Damon received a grant of 5,000 shares of common stock. The FAS 123R grant date fair value of these shares was $36,000.

In addition to the stock and option awards described above, for the fiscal year ended December 31, 2008, all of our non-employee directors received an annual director fee of $50,000 (the fees for Messrs. Mitchell, Alexander and McMichael were pro rated for 2008 based on their length of service). The chairman of the Audit Committee received an additional $7,500 and the chairmen of the Compensation and Nominating Committees each received an

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additional $5,000. Additionally, Mr. Rateau was appointed Chairman of the Board in September 2008 and received a $30,000 pro rated fee based on his length of service.

In March 2008, the Board of Directors approved the exchange of each unvested stock option for one-half of a bonus share of common stock of the Company, with the same vesting schedule as their unvested options. The directors made the decision to exchange the stock options for bonus shares in order to more closely align the interests of the directors with those of the stockholders. The directors also believed that the recent trend in director compensation was to grant awards of bonus shares rather than stock options. The exchange ratio was determined based on market data provided by T-P. As a result of the exchange, Messrs. Kite, Rateau and Garrison each received 10,000 bonus shares of our common stock and Messrs. Damon and Mitchell each received 20,000 bonus shares of our common stock. 5,000 of these shares vested in 2008 and 5,000 will vest in 2009 for Messrs. Kite, Rateau and Garrison. 5,000 of these shares will vest over each of the next three years for Mr. Damon. Mr. Mitchell forfeited his shares when he resigned in May 2008. Additionally, each of Messrs. Kite, Rateau, Garrison and Damon was awarded 5,000 shares of common stock following the 2008 annual meeting of our stockholders. Mr. Mitchell resigned as a director in May 2008 and therefore did not receive an equity grant for 2008. Mr. Alexander resigned in August 2008 before the shares were issued to him and he relinquished any right to the shares at that time.

In March 2009, the Board of Directors approved a change to the structure of the non-employee directors’ fees, based on the recommendation of the Committee. Under the new fee structure, the annual retainer was increased to $125,000 effective as of January 1, 2009. The Chairman of the Board will receive an additional $30,000 per year, the chair of the Audit Committee will receive an additional $10,000 per year and the chairs of the other committees will receive $5,000 per year. No equity awards will be paid to the non-employee directors for 2009 due to the current low stock price and the large number of shares that would need to be issued in connection with any significant equity component.

Employment Contracts

Each of the Named Executive Officers has or had an employment agreement with us. Mr. Cash resigned all of his positions with us in August 2008 and the employment agreement of Mr. Grose was terminated in September 2008. Except as described below, the employment agreements for each of the Named Executive Officers are substantially similar.

Each of these agreements has an initial term of three years (the “Initial Term”). In October 2008, the Initial Term of the employment agreements for Messrs. Lawler and Collins were extended until August 2011. Upon expiration of the Initial Term, each agreement will automatically continue for successive one-year terms, unless earlier terminated in accordance with the terms of the agreement. The positions, base salary, number of restricted

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shares of our common stock, and shares for purchase pursuant to stock options granted under each of the employment agreements is as follows:


					Number of			Number of Shares
		Expiration of			Shares of			for Purchase
		Initial			Restricted			Pursuant to
Name	Position	Term	Base Salary		Stock			Stock Options

Jerry Cash	Chief Executive Officer	(1)	$	525,000		493,080	(2)		—
David Lawler	Chief Operating Officer and	August 2011	$	400,000		90,000			200,000
	President
David Grose	Chief Financial Officer	(1)	$	350,000		105,000	(3)		—
Jack Collins	Interim Chief Financial	August 2011	$	200,000		60,000			100,000
	Officer and Executive Vice President — Finance/ Corporate Development
David Bolton	Executive Vice President —	March 2010	$	225,000		45,000			—
	Land
Richard Marlin	Executive Vice	March 2010	$	248,000		45,000			—
	President — Engineering
Thomas Lopus	Executive Vice President —	July 2011	$	225,000		45,000			—
	Appalachia


(1)		Agreement has been terminated.

(2)		328,720 of these shares were forfeited at the time the agreement was terminated.

(3)		All of these shares were cancelled at the time the agreement was terminated.

One-third of the restricted shares vest on each of the first three anniversary dates of each employment agreement. In addition, Mr. Grose and Mr. Lawler received 70,000 and 15,000 unrestricted shares, respectively, of our common stock in connection with the execution of their employment agreements.

In connection with the amendments to the employment agreements of Messrs. Lawler and Collins in October 2008, Mr. Lawler received a nonqualified stock option to purchase 200,000 shares of the Company’s common stock at an exercise price of $0.71 per share and Mr. Collins received a non-qualified stock option to purchase 100,000 shares of the Company’s common stock at an exercise price of $0.48 per share. One-half of these options were immediately vested and the other half will vest on the first anniversary date of the applicable amendment. These options are included in the table above.

Each executive is eligible to participate in all of our incentive bonus plans that are established for our executive officers. If we terminate an executive’s employment without “cause” (as defined below) or if an executive terminates his employment agreement for Good Reason (as defined below), in each case after notice and cure periods —


	•	the executive will receive his base salary for the remainder of the term,

	•	we will pay the executive’s health insurance premium payments for the duration of the COBRA continuation period (18 months) or until he becomes eligible for health insurance with a different employer,

	•	the executive will receive his pro rata portion of any annual bonus and other incentive compensation to which he would have been entitled; and

	•	his unvested shares of restricted stock will vest (which vesting may be deferred for six months if necessary to comply with Section 409A of the Internal Revenue Code).

Under each of the employment agreements, Good Reason means:


	•	our failure to pay the executive’s salary or annual bonus in accordance with the terms of the agreement (unless the payment is not material and is being contested by us in good faith);

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	•	if we require the executive to be based anywhere other than Oklahoma City, Oklahoma (or, in the case of Mr. Lopus, Pittsburgh, Pennsylvania);

	•	a substantial or material reduction in the executive’s duties or responsibilities; or

	•	the executive no longer has the title specified above (though this does not apply to Mr. Lopus and in the case of Mr. Collins, Good Reason does not apply in the situation where he no longer holds the interim chief financial officer position as long as he continues to have a title, position and duties not materially less than those of executive vice president finance/corporate development).

For purposes of the employment agreements, “cause” includes the following:


	•	any act or omission by the executive that constitutes gross negligence or willful misconduct;

	•	theft, dishonest acts or breach of fiduciary duty that materially enrich the executive or materially damage us or conviction of a felony,

	•	any conflict of interest, except those consented to in writing by us;

	•	any material failure by the executive to observe our work rules, policies or procedures;

	•	failure or refusal by the executive to perform his duties and responsibilities required under the employment agreements, or to carry out reasonable instruction, to our satisfaction;

	•	any conduct that is materially detrimental to our operations, financial condition or reputation; or

	•	any material breach of the employment agreement by the executive.

The following summarizes potential maximum payments that an executive could receive upon a termination of employment without cause or for Good Reason, actual amounts are likely to be less.


			Unvested Equity
Name	Base Salary(1)		Compensation(2)		Bonus(3)		Benefits(4)		Total

David Lawler	$	1,057,534	$	53,400	$	336,000	$	21,522	$	1,468,456
Jack Collins	$	528,767	$	19,600	$	84,000	$	25,461	$	657,828
Richard Marlin	$	302,356	$	13,805	$	66,960	$	9,703	$	392,824
David Bolton	$	265,685	$	13,526	$	60,750	$	17,582	$	357,543
Thomas Lopus	$	570,205	$	19,800	$	60,750	$	17,582	$	668,337


(1)		Assumes full amount of remaining base salary payable under the agreement as of December 31, 2008 is paid (with no renewal of the term of the agreement). Actual amounts may be less.

(2)		For purposes of this table, we have used the number of unvested stock awards and stock options as of December 31, 2008 and the closing price of our common stock on that date ($0.44). Assumes all such equity awards remain unvested on the date of termination. No value was assigned to unvested stock options since the exercise price exceeded the stock price on December 31, 2008.

(3)		Represents target amounts payable under the QRC Bonus Plan for 2009. Assumes a full year’s bonus (i.e., if employment were terminated on December 31 of a year). Actual payment would be pro-rated based on the number of days in the year during which the executive was employed. For Mr. Lawler, also assumes he will be granted (i) a number of performance shares under the Omnibus Plan having a value equal to 50% of the payment he would have been paid under the QRC Bonus Plan and (ii) a number of restricted shares under the Omnibus Plan having a value equal to 50% of the payment he would have been paid under the QRC Bonus Plan.

(4)		Represents 18 months of insurance premiums at current rates.

On August 23, 2008, Jerry Cash resigned as our Chairman of the Board, Chief Executive Officer and President. He was paid his base salary through his last day of work, was not entitled to receive any additional compensation pursuant to his employment agreement and forfeited his rights in his unvested equity awards. On September 13, 2008, David Grose’s employment was terminated, and he was paid his base salary through his last day of work, was

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not entitled to receive any additional compensation pursuant to his employment agreement and all of his equity awards granted under his employment agreement were cancelled.

In general, base salary payments will be paid to the executive in equal installments on our regular payroll dates, with the installments commencing six months after the executive’s termination of employment (at which time the executive will receive a lump sum amount equal to the monthly payments that would have been paid during such six month period). However, the payments may be commenced immediately if an exemption under Internal Revenue Code § 409A is available.

If the executive’s employment is terminated without cause within two years after a change in control (as defined below), then the base salary payments will be paid in a lump sum six months after termination of employment.

Under the employment agreements, a “change in control” is generally defined as:


	•	the acquisition by any person or group of our common stock that, together with shares of common stock held by such person or group, constitutes more than 50% of the total voting power of our common stock;

	•	any person or group acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such person or group) ownership of our common stock possessing 35% or more of the total voting power of our common stock;

	•	a majority of members of our board of directors being replaced during any 12-month period by directors whose appointment or election is not endorsed by a majority of the members of our board of directors prior to the date of the appointment or election; or

	•	any person or group acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such person or group) assets from us that have a total gross fair market value equal to or more than 40% of the total gross fair market value of all of our assets immediately prior to the acquisition or acquisitions.

The pro rata portion of any annual bonus or other compensation to which the executive would have been entitled for the year during which the termination occurred will generally be paid at the time bonuses are paid to all employees, but in no event later than March 15th of the calendar year following the calendar year the executive separates from service. However, unless no exception to Internal Revenue Code § 409A applies, payment will be made six months after the executive’s termination of employment, if later.

If the executive is unable to render services as a result of physical or mental disability, we may terminate his employment, and he will receive a lump-sum payment equal to one year’s base salary and all compensation and benefits that were accrued and vested as of the date of termination. If necessary to comply with Internal Revenue Code § 409A, the payment may be deferred for six months.

Each of the employment agreements also provides for one-year restrictive covenants of non-solicitation in the event the executive terminates his own employment or is terminated by us for cause. Our obligation to make severance payments is conditioned upon the executive not competing with us during the term that severance payments are being made.

Compensation Committee Interlocks and Insider Participation

None of the persons who served on our Compensation Committee during the last completed fiscal year (Jon H. Rateau, John C. Garrison, James B. Kite, Jr., William H. Damon III and Greg McMichael) (i) was an officer or employee of the Company during the last fiscal year or (ii) had any relationship requiring disclosure under Item 404 of Regulation S-K. Except for Mr. Garrison, who previously served as our Treasurer from 1998 to 2001, none of the persons who served on our Compensation Committee during the last completed fiscal year was formerly an officer of the Company.

None of our executive officers, during the last completed fiscal year, served as a (i) member of the compensation committee of another entity, one of whose executive officers served on our Compensation Committee; (ii) director of another entity, one of whose executive officers served on our Compensation Committee; or (iii) member of the compensation committee of another entity, one of whose executive officers served as our director.

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Compensation Committee Report

The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis set forth above with management, and based on such review and discussions, the Compensation Committee has recommended to the Board of Directors of the Company that such Compensation Discussion and Analysis be included in the Company’s Annual Report on Form 10-K and the Company’s Proxy Statement.

Greg McMichael, Chairman
William H. Damon III
James B. Kite, Jr.
Jon H. Rateau
John C. Garrison

Note: Mr. Rateau served on the Compensation Committee and was its chairman until September 4, 2008. Mr. Damon served on the Compensation Committee for all of 2008 and was its chairman from September 4, 2008 until December 29, 2008. Mr. Garrison served on the Compensation Committee from September 4, 2008 until December 29, 2008. Mr. McMichael joined the board of directors on December 29, 2008, at which time he was appointed chairman of the Compensation Committee. As such, Messrs. McMichael and Garrison had only limited involvement in the compensation decisions related to 2008.


ITEM 12.	*SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.*

The following table sets forth information as of May 15, 2009 concerning the shares of our common stock beneficially owned by (i) each person known by us, solely by reason of our examination of Schedule 13D and 13G filings made with the SEC and by information voluntarily provided to us by certain stockholders, to be the beneficial owner of 5% or more of our outstanding common stock, (ii) each of our directors, (iii) each of the executive officers named in the summary compensation table and (iv) all current directors and executive officers as a group. If a person or entity listed in the following table is the beneficial owner of less than one percent of the securities outstanding, this fact is indicated by an asterisk in the table.


	Number of Shares of
	Quest Resource
	Corporation Common		Percent
	Stock		of Class of Quest
	Beneficially		Resource Corporation
Name and Address of Beneficial Owner	Owned(1)		Common Stock

Advisory Research, Inc.(2) 180 North Stetson, Suite 5500 Chicago, IL 60601		2,889,400		9.1	%
Jerry D. Cash(3)		1,463,270		4.6	%
James B. Kite, Jr.(4)(5)		956,157		3.0	%
David C. Lawler(6)		183,415			*
Jack T. Collins(7)		113,000			*
John C. Garrison(4)(8)		106,053			*
Richard Marlin(9)		61,012			*
David Grose(10)		56,080			*
David W. Bolton(11)		47,776			*
Thomas A. Lopus(12)		45,000			*
Jon H. Rateau(4)(13)		40,000			*
William H. Damon III(14)		20,000			*
Greg McMichael		—		—
All Current Directors and Executive Officers as a Group (11 Persons)		1,572,413		4.9	%

141


(1)		The number of securities beneficially owned by the persons or entities above is determined under rules promulgated by the SEC and the information is not necessarily indicative of beneficial ownership for any other purpose. Under such rules, beneficial ownership includes any securities as to which the person or entity has sole or shared voting power or investment power and also any securities that the person or entity has the right to acquire within 60 days through the exercise of any option or other right. The inclusion herein of such securities, however, does not constitute an admission that the named equityholder is a direct or indirect beneficial owner of such securities. Unless otherwise indicated, each person or entity named in the table has sole voting power and investment power (or shares such power with his or her spouse) with respect to all securities listed as owned by such person or entity.

(2)		Advisory Research, Inc. (“ARI”) is the general partner and investment manager of Advisory Research Micro Cap Value Fund, L.P. (“Advisory Micro Cap”) (which owns 1,503,421 shares of our common stock) and Advisory Research Energy Fund, L.P. (“Advisory Energy”) (which owns 533,874 shares of our common stock) and is registered under the Investment Advisers Act of 1940. By virtue of investment management agreements with each of Advisory Micro Cap, Advisory Energy, and other discretionary client funds, ARI is deemed to have beneficial ownership over the 2,889,400 shares.

(3)		Includes (i) 1,200 shares of our common stock owned by Mr. Cash’s wife, Sherry J. Cash and (ii) 7,678 shares held in Mr. Cash’s retirement account (Mr. Cash does not have voting rights with respect to the shares held in his profit sharing retirement account). Mr. Cash disclaims beneficial ownership of the shares owned by Sherry J. Cash. Mr. Cash did not respond to our request to confirm the exact beneficial ownership information and, as a result, it is based on his most recent Form 4 adjusted for forfeitures; however, he has advised us that all of the shares of our common stock beneficially owned by him have been pledged to secure a personal loan.

(4)		Includes options to acquire 30,000 shares of our common stock that are immediately exercisable.

(5)		Includes 916,157 shares of our common stock owned by McKown Point LP, a Texas Limited Partnership. Easterly Family Investments LLC is the sole general partner of McKown Point LP. Easterly Family Investments LLC is wholly owned by the Virginia V. Kite GST Exempt Trust for James B. Kite, Jr. Mr. Kite and Bank of Texas, N.A. are the trustees of the Virginia V. Kite GST Exempt Trust for James B. Kite, Jr. Easterly Family Investments LLC, the Virginia V. Kite GST Exempt Trust for James B. Kite, Jr. and James B. Kite, Jr. may be deemed to have beneficial ownership of the shares owned by McKown Point LP. In addition, Mr. Kite is entitled to receive 5,000 bonus shares upon satisfaction of certain vesting requirements. Mr. Kite does not have the ability to vote these bonus shares.

(6)		Includes 30,000 restricted shares, which are subject to vesting, and options to acquire 100,000 shares of our common stock that are immediately exercisable.

(7)		Includes 40,000 restricted shares, which are subject to vesting, and options to acquire 50,000 shares of our common stock that are immediately exercisable.

(8)		Mr. Garrison is also entitled to receive 5,000 bonus shares upon satisfaction of certain vesting requirements. Mr. Garrison does not have the ability to vote these bonus shares.

(9)		Includes 15,000 restricted shares, which are subject to vesting. In addition, Mr. Marlin is entitled to receive 688 bonus shares upon satisfaction of certain vesting requirements. Mr. Marlin does not have the ability to vote these bonus shares.

(10)		Includes 3,281 shares of our common stock held in Mr. Grose’s retirement account (Mr. Grose does not have voting rights with respect to these shares). Mr. Grose did not respond to our request to confirm the exact beneficial ownership information and, as a result it is based on his most recent Form 4 adjusted for shares cancelled in connection with the termination of his employment.

(11)		Includes 15,000 restricted shares, which are subject to vesting. In addition, Mr. Bolton is entitled to receive 370 bonus shares upon satisfaction of certain vesting requirements. Mr. Bolton does not have the ability to vote these bonus shares.

(12)		Consists of 45,000 restricted shares, which are subject to vesting.

(13)		Mr. Rateau is also entitled to receive 5,000 bonus shares upon satisfaction of certain vesting requirements. Mr. Rateau does not have the ability to vote these bonus shares.

142


(14)		Includes options to acquire 10,000 shares of our common stock that are immediately exercisable. In addition, Mr. Damon is entitled to receive 5,000 bonus shares upon satisfaction of certain vesting requirements. Mr. Damon does not have the ability to vote these bonus shares.

Equity Compensation Plans

The table below sets forth information concerning compensation plans under which equity securities are authorized for issuance as of the fiscal year ended December 31, 2008.

Equity Compensation Plan Information


					Number of securities
	Number of securities to		Weighted-average		remaining available for
	be issued upon exercise		exercise price of		future issuance under
	of outstanding options,		outstanding options,		equity compensation
Plan category	warrants and rights		warrants and rights		plans

Equity compensation plans approved by security holders(1)		310,000	$	0.94		1,349,859(3	)
Equity compensation plans not approved by security holders(2)		90,000	$	10.00		—

Total		400,000	$	2.98		1,349,859


(1)		Consists of (a) 10,000 immediately vested 10-year options issued to one of our non-employee directors (Mr. Damon) in August 2007 with an exercise price of $10.05 per share; (b) 200,000 10-year options issued to Mr. Lawler in October 2008, one-half of which were immediately vested and one-half of which will vest on the first anniversary of the date of grant, with an exercise price of $0.71; and (c) 100,000 10-year options issued to Mr. Collins in October 2008, one-half of which were immediately vested and one-half of which will vest on the first anniversary of the date of grant, with an exercise price of $0.48.

(2)		Consists of 30,000 options issued to each of our non-employee directors (Messrs. Kite, Garrison and Rateau) in October 2005. For each director, 10,000 of the options were immediately vested and 10,000 of the remaining options vested on the first two anniversaries of the date of grant. The options have a term of 10 years and an exercise price of $10.00 per share.

(3)		Excludes securities to be issued upon exercise of outstanding options, warrants and rights. Amount includes 78,669 unvested and unissued shares awarded under our management incentive plan that are subject to forfeiture.


ITEM 13.	*CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.*

Related Transactions

No director, executive officer or stockholder who is known to us to own of record or beneficially own more than five percent of our common stock, or any member of the immediate family of such director, executive officer or stockholder, had a direct or indirect material interest in any transaction since the beginning of the year ended December 31, 2008, or any currently proposed transaction, in which we or one of our subsidiaries is a party and the amount involved exceeds $120,000.

See Note 15 — Related Party Transactions to the accompanying consolidated financial statements for descriptions of certain unauthorized transactions made by our former chief executive officer and two former officers.

Policy Regarding Transactions with Related Persons

We do not have a formal, written policy for the review, approval or ratification of transactions between us and any director or executive officer, nominee for director, 5% stockholder or member of the immediate family of any

143

such person that are required to be disclosed under Item 404(a) of Regulation S-K. However, our policy is that any activities, investments or associations of a director or officer that create, or would appear to create, a conflict between the personal interests of such person and our interests must be assessed by our Chief Financial Officer or the Audit Committee.

Director Independence

Our Board of Directors has determined that each of our directors, except Mr. Lawler, is an independent director, as defined in the applicable rules and regulations of The NASDAQ Global Market, including Rule 5605(a)(2) of the Marketplace Rules of the NASDAQ Stock Market LLC.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.

Audit and Non-Audit Fees

On August 1, 2008, MHM resigned as our independent registered public accounting firm as a result of its operations having been acquired by Eide Bailly. We engaged Eide Bailly on that date as our independent registered public accounting firm. On September 25, 2008, Eide Bailly notified us that it was resigning as our independent registered accounting firm effective upon the earlier of the date of the filing of the Company’s Form 10-Q for the period ended September 30, 2008, or November 10, 2008. On October 23, 2008, our Board of Directors approved the recommendation of the Audit Committee to appoint UHY as our independent registered public accounting firm.

The following table lists fees billed by MHM, Eide Bailly and UHY for services rendered during the years ended December 31, 2007 and 2008.


	Year Ended		Year Ended
	December 31,		December 31,
	2008		2007

Audit Fees(1)	$	514,593	$	354,738
Audit-Related Fees(2)		316,561		3,100
Tax Fees(3)		174,195		117,891
All Other Fees		—		—

Total Fees	$	1,005,349	$	475,729


	1.	Audit Fees include fees billed for services performed to comply with Generally Accepted Auditing Standards (GAAS), including the recurring audit of our consolidated financial statements for such period included in the Annual Report on Form 10-K and for the reviews of the consolidated quarterly financial statements included in the Quarterly Reports on Form 10-Q filed with the SEC. This category also includes fees for audits provided in connection with statutory filings or procedures related to the audit of income tax provisions and related reserves, consents and assistance with and review of documents filed with the SEC. During 2008, UHY billed us $215,327 for audit fees.

	2.	Audit-Related Fees include fees for services associated with assurance and reasonably related to the performance of the audit or review of our financial statements. This category includes fees related to assistance in financial due diligence related to mergers and acquisitions, consultations regarding GAAP, reviews and evaluations of the impact of new regulatory pronouncements, general assistance with implementation of Sarbanes-Oxley Act of 2002 requirements and audit services not required by statute or regulation. This category also includes audits of pension and other employee benefit plans, as well as the review of information systems and general internal controls unrelated to the audit of the financial statements. During 2008, UHY did not bill us any amount for audit-related fees.

	3.	Tax fees consist of fees related to the preparation and review of our federal and state income tax returns and tax consulting services. During 2008, UHY did not bill us any amount for tax fees.

The Audit Committee has concluded the provision of the non-audit services listed above as “Audit-Related Fees” and “Tax Fees” is compatible with maintaining the auditors’ independence and has approved all of the fees discussed above.

144

All services to be performed by the independent public accountants must be pre-approved by the Audit Committee, which has chosen not to adopt any pre-approval policies for enumerated services and situations, but instead has retained the sole authority for such approvals.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

(a)(1) and (2) Financial Statements. See “Index to Financial Statements” set forth on page F-1 of this Form 10-K.

(a)(3) Index to Exhibits. Exhibits requiring attachment pursuant to Item 601 of Regulation S-K are listed in the Index to Exhibits beginning on page 147 of this Form 10-K that is incorporated herein by reference.

145

QUEST RESOURCE CORPORATION
Index To Financial Statements


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM			F-2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM			F-3
CONSOLIDATED BALANCE SHEETS			F-6
CONSOLIDATED STATEMENTS OF OPERATIONS			F-7
CONSOLIDATED STATEMENTS OF CASH FLOWS			F-8
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ (DEFICIT) EQUITY			F-9
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS			F-10

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Quest Resource Corporation:

We have audited the accompanying consolidated balance sheets of Quest Resource Corporation and subsidiaries (the Company) as of December 31, 2008, 2007 and 2006, and the related consolidated statements of operations, cash flows and stockholders’ (deficit) equity for each of the four years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Quest Resource Corporation and subsidiaries at December 31, 2008, 2007 and 2006, and the results of their operations and their cash flows for each of the four years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements for the year ended December 31, 2008, have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company’s recurring losses from operations, accumulated deficit, and inability to generate sufficient cash flow to meet its obligations and sustain its operations raise substantial doubt about its ability to continue as a going concern. Management’s plans concerning these matters are also discussed in Note 1 to the consolidated financial statements. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

As discussed in Notes 1 and 18 to the consolidated financial statements, the Company has restated its previously issued consolidated financial statements as of December 31, 2007, 2006 and for the years ended December 31, 2007, 2006 and 2005, which were audited by other auditors.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated June 2, 2009 expressed an adverse opinion on the Company’s internal control over financial reporting.

/s/ UHY LLP

Houston, Texas

June 2, 2009

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Quest Resource Corporation:

We have audited Quest Resource Corporation and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2008, based on criteria established by the Committee of Sponsoring Organizations of the Treadway Commission. Quest Resource Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on that risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles (GAAP). A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Material weaknesses related to ineffective controls over the period-end financial reporting process have been identified and included in management’s assessment. These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the consolidated financial statements as of and for the year ended December 31, 2008. This report does not affect our report on such financial statements. A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The following material weaknesses have been identified and included in management’s assessment as of December 31, 2008:

(1) Control environment — The Company did not maintain an effective control environment. The control environment which is the responsibility of senior management, sets the tone of the organization, influences the control consciousness of its people, and is the foundation for all other components of internal control over financial reporting. Each of these control environment material weaknesses contributed to the material weaknesses discussed in items (2) through (8) below. The Company did not maintain an effective control environment because of the following material weaknesses:

(a) The Company did not maintain a tone and control consciousness that consistently emphasized adherence to accurate financial reporting and enforcement of Company policies and procedures. This

F-3

control deficiency fostered a lack of sufficient appreciation for internal controls over financial reporting, allowed for management override of internal controls in certain circumstances and resulted in an ineffective process for monitoring the adherence of the Company’s policies and procedures.

(b) The Company did not maintain a sufficient complement of personnel with an appropriate level of accounting knowledge, experience, and training in the application of GAAP commensurate with its financial reporting requirements and business environment.

(c) The Company did not maintain an effective anti-fraud program designed to detect and prevent fraud relating to (i) an effective whistle-blower program, (ii) consistent background checks of personnel in positions of responsibility, and (iii) an ongoing program to manage identified fraud risks.

The control environment material weaknesses described above contributed to the material weaknesses related to the transfers that were the subject of the internal investigation and to its internal control over financial reporting, period end financial close and reporting, accounting for derivative instruments, stock compensation costs, depreciation, depletion and amortization, impairment of oil and gas properties and cash management described in items (2) to (8) below.

(2) Internal control over financial reporting — The Company did not maintain effective monitoring controls to determine the adequacy of its internal control over financial reporting and related policies and procedures because of the following material weaknesses:

(a) The Company’s policies and procedures with respect to the review, supervision and monitoring of its accounting operations throughout the organization were either not designed and in place or not operating effectively.

(b) The Company did not maintain an effective internal control monitoring function. Specifically, there were insufficient policies and procedures to effectively determine the adequacy of the Company’s internal control over financial reporting and monitoring the ongoing effectiveness thereof.

Each of these material weaknesses relating to the monitoring of the Company’s internal control over financial reporting contributed to the material weaknesses described in items (3) through (8) below.

(3) Period end financial close and reporting — The Company did not establish and maintain effective controls over certain of its period-end financial close and reporting processes because of the following material weaknesses:

(a) The Company did not maintain effective controls over the preparation and review of the interim and annual consolidated financial statements and to ensure that it identified and accumulated all required supporting information to ensure the completeness and accuracy of the consolidated financial statements and that balances and disclosures reported in the consolidated financial statements reconciled to the underlying supporting schedules and accounting records.

(b) Company did not maintain effective controls to ensure that it identified and accumulated all required supporting information to ensure the completeness and accuracy of the accounting records.

(c) The Company did not maintain effective controls over the preparation, review and approval of account reconciliations. Specifically, the Company did not have effective controls over the completeness and accuracy of supporting schedules for substantially all financial statement account reconciliations.

(d) The Company did not maintain effective controls over the complete and accurate recording and monitoring of intercompany accounts. Specifically, effective controls were not designed and in place to ensure that intercompany balances were completely and accurately classified and reported in the Company’s underlying accounting records and to ensure proper elimination as part of the consolidation process.

(e) The Company did not maintain effective controls over the recording of journal entries, both recurring and non-recurring. Specifically, effective controls were not designed and in place to ensure that

F-4

journal entries were properly prepared with sufficient support or documentation or were reviewed and approved to ensure the accuracy and completeness of the journal entries recorded.

(4) Derivative instruments — The Company did not establish and maintain effective controls to ensure the correct application of GAAP related to derivative instruments. Specifically, the Company did not adequately document the criteria for measuring hedge effectiveness at the inception of certain derivative transactions and did not subsequently value those derivatives appropriately.

(5) Stock compensation cost — The Company did not establish and maintain effective controls to ensure completeness and accuracy of stock compensation costs. Specifically, effective controls were not designed and in place to ensure that documentation of the terms of the awards were reviewed in order to be recorded accurately.

(6) Depreciation, depletion and amortization — The Company did not establish and maintain effective controls to ensure completeness and accuracy of depreciation, depletion and amortization expense. Specifically, effective controls were not designed and in place to calculate and review the depletion of oil and gas properties.

(7) Impairment of oil and gas properties — The Company did not establish and maintain effective controls to ensure the accuracy and application of GAAP related to the capitalization of costs related to oil and gas properties and the required evaluation of impairment of such costs. Specifically, effective controls were not designed and in place to determine, review and record the nature of items recorded to oil and gas properties and the calculation of oil and gas property impairments.

(8) Cash management — The Company did not establish and maintain effective controls to adequately segregate the duties over cash management. Specifically, effective controls were not designed to prevent the misappropriation of cash.

Additionally, each of the control deficiencies described in items (1) through (8) above could result in a misstatement of the aforementioned account balances or disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Management has determined that each of the control deficiencies in items (1) through (8) above constitutes a material weakness. These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2008 consolidated financial statements, and our opinion regarding the effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those consolidated financial statements.

In our opinion, because of the effect of the material weaknesses identified above on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets and the related consolidated statements of operations, cash flows, and stockholders’ (deficit) equity of the Company as of December 31, 2006, 2007 and 2008 and for the years ended December 31, 2008. Our report dated June 2, 2009 expressed an unqualified opinion on those financial statements and included (1) an explanatory paragraph expressing substantial doubt about the Company’s ability to continue as a going concern and (2) an explanatory paragraph related to the Company’s restatement of the 2007, 2006, and 2005 financial statements.

/s/ UHY LLP

Houston, Texas

June 2, 2009

F-5

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

($ in thousands, except share and per share data)


	December 31,
	2008			2007			2006
				(Restated)			(Restated)

ASSETS
Current assets:
Cash and cash equivalents	$	13,785		$	6,680		$	33,820
Restricted cash		559			1,236			1,150
Accounts receivable — trade, net		16,715			15,557			9,651
Other receivables		9,434			1,480			235
Other current assets		2,858			3,962			1,076
Inventory		11,420			6,622			5,632
Current derivative financial instrument assets		42,995			8,008			14,109

Total current assets		97,766			43,545			65,673
Oil and gas properties under full cost method of accounting, net		172,537			300,953			241,278
Pipeline assets, net		310,439			294,526			126,654
Other property and equipment, net		23,863			21,505			16,680
Other assets, net		14,735			8,541			9,629
Long-term derivative financial instrument assets		30,836			3,467			8,022

Total assets	$	650,176		$	672,537		$	467,936


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	35,804		$	31,202		$	16,411
Revenue payable		8,309			7,725			4,989
Accrued expenses		7,138			8,387			786
Current portion of notes payable		45,013			666			324
Current derivative financial instrument liabilities		12			8,108			8,879

Total current liabilities		96,276			56,088			31,389
Non-current liabilities:
Long-term derivative financial instrument liabilities		4,230			6,311			10,878
Asset retirement obligations		5,922			2,938			1,410
Notes payable		343,094			233,046			225,245

Total long-term liabilities		353,246			242,295			237,533

Minority interests		204,536			297,385			84,173
Commitments and contingencies
Stockholders’ equity:
Preferred stock, $0.001 par value; authorized shares — 50,000,000; none issued and outstanding		—			—			—
Common stock, $0.001 par value; authorized shares — 200,000,000; issued — 32,224,643, 23,553,230 and 22,365,883 at December 31, 2008, 2007 and 2006; outstanding — 31,720,312, 22,471,355, and 22,248,883 at December 31, 2008, 2007 and 2006, respectively		33			24			22
Additional paid-in capital		298,583			211,852			205,772
Treasury stock at cost		(7	)		—			—
Accumulated deficit		(302,491	)		(135,107	)		(90,953	)

Total stockholders’ (deficit) equity		(3,882	)		76,769			114,841

Total liabilities and stockholders’ (deficit) equity	$	650,176		$	672,537		$	467,936

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

F-6

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

($ in thousands, except share and per share data)


	Years ended December 31,
	2008			2007			2006			2005
				(Restated)			(Restated)			(Restated)

Revenue:
Oil and gas sales	$	147,937		$	105,285		$	72,410		$	70,628
Gas pipeline revenue		28,176			9,853			5,014			3,939

Total revenues		176,113			115,138			77,424			74,567
Costs and expenses:
Oil and gas production		44,111			36,295			25,338			18,532
Pipeline operating		29,742			21,098			13,151			7,703
General and administrative expenses		28,269			21,023			8,655			6,218
Depreciation, depletion and amortization		70,445			39,782			27,011			22,244
Impairment of oil and gas properties		298,861			—			—			—
Misappropriation of funds		—			2,000			6,000			2,000

Total costs and expenses		471,428			120,198			80,155			56,697

Operating income (loss)		(295,315	)		(5,060	)		(2,731	)		17,870
Other income (expense):
Gain (loss) from derivative financial instruments		80,707			1,961			52,690			(73,566	)
Gain (loss) on sale of assets		24			(322	)		3			12
Loss on early extinguishment of debt		—			—			—			(12,355	)
Other income (expense)		305			(9	)		99			389
Interest expense		(25,609	)		(44,044	)		(20,957	)		(28,271	)
Interest income		236			416			390			46

Total other income (expense)		55,663			(41,998	)		32,225			(113,745	)

Loss before income taxes and minority interests		(239,652	)		(47,058	)		29,494			(95,875	)
Income tax benefit (expense)		—			—			—			—

Net loss before minority interest		(239,652	)		(47,058	)		29,494			(95,875	)
Minority interest		72,268			2,904			14			—

Net income (loss)		(167,384	)		(44,154	)		29,508			(95,875	)
Preferred stock dividends		—			—			—			(10	)

Net income (loss) available to common shareholders	$	(167,384	)	$	(44,154	)	$	29,508		$	(95,885	)

Net income (loss) available to common shareholders per share:
Basic	$	(6.20	)	$	(1.97	)	$	1.33		$	(11.48	)
Diluted	$	(6.20	)	$	(1.97	)	$	1.33		$	(11.48	)
Weighted average common and common equivalent shares outstanding:
Basic		27,010,690			22,379,479			22,119,497			8,351,945

Diluted		27,010,690			22,379,479			22,129,607			8,351,945

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

F-7

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

($ in thousands)


	Years Ended December 31,
	2008			2007			2006			2005
				(Restated)			(Restated)			(Restated)

Cash flows from operating activities:
Net income (loss)	$	(167,384	)	$	(44,154	)	$	29,508		$	(95,875	)
Adjustments to reconcile net income (loss) to cash provided by (used in) operations:
Depreciation, depletion and amortization		70,445			39,782			27,011			22,244
Impairment of oil and gas properties		298,861			—			—			—
Accretion of debt discount		—			—			—			11,478
Stock-based compensation		1,939			6,081			1,037			1,217
Stock-based compensation — minority interests		486			1,137			—			—
Stock issued for services and retirement plan		—			—			904			559
Amortization of deferred loan costs		2,100			11,220			2,069			4,497
Change in fair value of derivative financial instruments		(72,533	)		5,318			(70,402	)		46,602
Bad debt expense		—			22			85			302
Minority interest		(72,268	)		(2,904	)		(14	)		—
Loss on early extinguishment of debt		—			—			—			12,355
Loss on disposal of property and equipment		—			1,363			—			—
Change in assets and liabilities:
Accounts receivable		(1,158	)		(5,928	)		604			(4,469	)
Other receivables		(7,954	)		(1,245	)		108			181
Other current assets		4,173			(2,827	)		860			(1,693	)
Other assets		318			15			(819	)		788
Accounts payable		5,233			14,347			2,550			(14,867	)
Revenue payable		584			2,736			(256	)		1,518
Accrued expenses		(1,187	)		4,001			137			61
Other long-term liabilities		404			220			167			210
Other		(159	)		(388	)		1,053			116

Net cash provided by (used in) operating activities		61,900			28,796			(5,398	)		(14,776	)

Cash flows from investing activities:
Restricted cash		677			(86	)		3,168			(4,318	)
Acquisition of business — PetroEdge		(141,777	)		—			—			—
Acquisition of business — KPC		—			(133,725	)		—			—
Acquisition of minority interest — ArcLight		—			—			—			(26,100	)
Equipment, development, leasehold and pipeline		(141,553	)		(138,657	)		(168,315	)		(35,312	)
Proceeds from sale of oil and gas properties		16,100			—			—			—

Net cash used in investing activities		(266,553	)		(272,468	)		(165,147	)		(65,730	)

Cash flows from financing activities:
Proceeds from bank borrowings		86,195			44,580			125,170			100,103
Repayments of note borrowings		(59,800	)		(225,441	)		(589	)		(135,565	)
Proceeds from revolver note		128,000			224,000			75,000			—
Repayment of revolver note		—			(35,000	)		(75,000	)		—
Proceeds from Quest Energy		—			163,800			—			—
Proceeds from Quest Midstream		—			75,230			84,187			—
Syndication costs		—			(14,618	)		—			—
Distributions to unitholders		(24,413	)		(5,872	)		—			—
Proceeds from subordinated debt		—			—			—			15,000
Repayment of subordinated debt		—			—			—			(83,912	)
Refinancing costs		(3,018	)		(10,147	)		(4,569	)		(6,281	)
Equity offering costs		—			—			(393	)		—
Dividends paid		—			—			—			(10	)
Repurchase of restricted stock		(7	)		—			—			—
Proceeds from issuance of common stock		84,801			—			—			185,272

Net cash provided by financing activities		211,758			216,532			203,806			74,607

Net increase (decrease) in cash		7,105			(27,140	)		33,261			(5,899	)
Cash and cash equivalents beginning of period		6,680			33,820			559			6,458

Cash and cash equivalents end of period	$	13,785		$	6,680		$	33,820		$	559

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

F-8

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ (DEFICIT) EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2008, 2007, 2006, and 2005
(amounts as of and prior to December 31, 2007 are restated)
($ in thousands, except share amounts)


				Preferred		Common			Common		Additional			Shares of
	Preferred			Stock		Shares			Stock		Paid-in			Treasury			Treasury			Accumulated
	Shares			Par Value		Issued			Par Value		Capital			Stock			Stock			Deficit			Total

Balance, December 31, 2004		10,000		$	—		5,699,877		$	6	$	17,192		$	—		$	—		$	(24,576	)	$	(7,378	)
Proceeds from stock offering		—			—		15,258,164			15		183,257			—			—			—			183,272
Conversion of preferred stock		(10,000	)		—		16,000			—		—			—			—			—			—
Dividends on preferred stock		—			—		—			—		—			—			—			(10	)		(10	)
Stock issued for warrants exercised		—			—		639,840			1		(1	)		—			—			—			—
Stock issued for services		—			—		8,660			—		64			—			—			—			64
Stock sold for cash		—			—		400,000			—		2,000			—			—			—			2,000
Stock issued to retirement plan		—			—		49,842			—		495			—			—			—			495
Stock based compensation		—			—		—			—		1,217			—			—			—			1,217
Restricted stock grants, net of forfeitures		—			—		140,000			—		—			—			—			—			—
Net loss		—			—		—			—		—			—			—			(95,875	)		(95,875	)

Balance, December 31, 2005		—			—		22,212,383			22		204,224			—			—			(120,461	)		83,785
Equity offering costs		—			—		—			—		(393	)		—			—			—			(393	)
Stock issued to refinance debt		—			—		82,500			—		904			—			—			—			904
Stock based compensation		—			—		—			—		1,037			—			—			—			1,037
Restricted stock grants, net of forfeitures		—			—		71,000			—		—			—			—			—			—
Net income		—			—		—			—		—			—			—			29,508			29,508

Balance, December 31, 2006		—			—		22,365,883			22		205,772			—			—			(90,953	)		114,841
Stock based compensation		—			—		—			—		6,081			—			—			—			6,081
Restricted stock grants, net of forfeitures		—			—		1,187,347			2		(1	)		—			—			—			1
Net loss		—			—		—			—		—			—			—			(44,154	)		(44,154	)

Balance, December 31, 2007		—			—		23,553,230			24		211,852			—			—			(135,107	)		76,769
Proceeds from stock offering		—			—		8,800,000			9		84,692			—			—			—			84,701
Stock based compensation		—			—		—			—		1,939			—			—			—			1,939
Restricted stock grants, net of forfeitures		—			—		(138,587	)		—		—			—			—			—			—
Exercise of stock options		—			—		10,000			—		100			—			—			—			100
Repurchase of common stock		—			—		—			—		—			(21,955	)		(7	)		—			(7	)
Net loss		—			—		—			—		—			—			—			(167,384	)		(167,384	)

Balance, December 31, 2008		—		$	—		32,224,643		$	33	$	298,583			(21,955	)	$	(7	)	$	(302,491	)	$	(3,882	)

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

F-9

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization, Going Concern, Misappropriation, Reaudit and Restatement and Business

Organization

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

We are an integrated independent energy company involved in the acquisition, development, gathering, transportation, exploration, and production of oil and natural gas. Our principal operations and producing properties are located in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma and the Appalachian Basin in West Virginia and New York. We conduct substantially all of our production operations through Quest Energy Partners, L.P. (Nasdaq: QELP) (“Quest Energy” or “QELP”) and our natural gas transportation and gathering operations through Quest Midstream Partners, L.P. (“Quest Midstream” or “QMLP”). Our Appalachian Basin operations are primarily focused on the development of the Marcellus Shale through Quest Eastern Resource LLC (“Quest Eastern”) and Quest Energy. Our Cherokee Basin operations are currently focused on developing CBM gas production through Quest Energy, which is served by a gas gathering pipeline network owned through Quest Midstream. Quest Midstream also owns an interstate natural gas transmission pipeline.

Misappropriation, Reaudit and Restatement

These consolidated financial statements include restated and reaudited financial statements for QRCP as of December 31, 2007 and 2006 and for the periods ended December 31, 2007, 2006 and 2005 and are included in our Form 10-K for the year ended December 31, 2008. QRCP will subsequently file (i) an amended Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 including restated unaudited condensed financial statements as of March 31, 2008 and for the three month periods ended March 31, 2008 and 2007; (ii) an amended Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 including restated unaudited condensed financial statements as of June 30, 2008 and for the three and six month periods ended June 30, 2008 and 2007; and (iii) a Quarterly Report on Form 10-Q including restated unaudited condensed financial statements as of September 30, 2008 and for the three and nine month periods ended September 30, 2008 and 2007.

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 QELP, and Quest Midstream GP, LLC (“Quest Midstream GP”), the general partner of QMLP, 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 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 2007 and as of and for the three and six months ended June 30, 2008 and 2007 should no longer be relied upon.

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

F-10

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 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 18 — Restatement.

Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates the realization of assets and the liquidation of liabilities in the normal course of business, though such an assumption may not be true. The Company has incurred significant losses from 2003 through 2008, mainly attributable to operations, legal restructurings, financings, the current legal and operational structure and, to a lesser degree, the cash expenditures resulting from the investigation related to the Transfers. We have determined that there is substantial doubt about our ability to continue as a going concern.

QRCP is almost exclusively dependent upon distributions from its partnership interests in Quest Energy and Quest Midstream for revenue and cash flow. Quest Midstream did not pay any distributions on any of its units for the third or fourth quarters of 2008, and Quest Energy suspended its distributions on its subordinated units for the third quarter of 2008 and all units starting with the fourth quarter of 2008. QRCP does not expect to receive any distributions from Quest Energy or Quest Midstream in 2009 and is unable to estimate at this time when such distributions may be resumed.

Although QRCP is not currently receiving distributions from Quest Energy or Quest Midstream, it continues to require cash to fund general and administrative expenses, debt service requirements, capital expenditures to develop and maintain its undeveloped acreage, drilling commitments and payments to landowners necessary to maintain its oil and gas leases.

Given the liquidity challenges facing the Company, Quest Midstream and Quest Energy, each entity has undertaken a strategic review of its assets and is currently evaluating one or more transactions to dispose of assets in order to raise additional funds for operations and/or to repay indebtedness. On April 28, 2009, QRCP, Quest Midstream and Quest Energy entered into a non-binding letter of intent which contemplates a transaction in which all three companies would form a new publicly traded holding company that would wholly-own all three entities (the “Recombination”). The closing of the Recombination is subject to the satisfaction of a number of conditions, including the entry into a definitive merger agreement, the negotiation of a new credit facility for the new company, regulatory approval and the approval of the transaction by the stockholders of QRCP and the common unit holders of Quest Energy and Quest Midstream.

As of December 31, 2008, QRCP, excluding QELP and QMLP, had cash and cash equivalents of $4.0 million and no ability to borrow under the terms of its existing credit agreement. QRCP currently estimates that it will not have enough cash to pay its expenses, including capital expenditures and debt service requirements, after August 31, 2009. This date could be extended if QRCP is able to restructure its debt obligations, issue equity securities and/or sell additional assets. The accompanying financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Business

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:


	•	Oil and gas production, and

	•	Natural gas pipelines, including transporting, gathering, treating and processing natural gas.

F-11

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Oil and Gas Production Operations

On November 15, 2007, Quest Energy completed an initial public offering of 9,100,000 common units at $18.00 per unit, or $16.83 per unit after payment of the underwriting discount (excluding a structuring fee). On November 9, 2007, Quest Energy’s common units began trading on the NASDAQ Global Market under the symbol “QELP.” Total proceeds from the sale of the common units in the initial public offering were $163.8 million, before underwriting discounts, a structuring fee and offering costs, of approximately $10.6 million, $0.4 million and $1.5 million, respectively. Quest Energy used the net proceeds of $151.3 million to repay a portion of the indebtedness of the Company.

Additionally, on November 15, 2007:

(a) Quest Energy, Quest Energy GP, the Company and certain of the Company’s subsidiaries entered into a Contribution, Conveyance and Assumption Agreement (the “Contribution Agreement”). At the closing of the offering, the following transactions, among others, occurred pursuant to the Contribution Agreement:


	•	the contribution of Quest Cherokee, LLC (“Quest Cherokee”) and its subsidiary, Quest Oilfield Service, LLC (“QCOS”), to Quest Energy. Quest Cherokee owns all of the Company’s oil and gas leases in the Cherokee Basin;

	•	the issuance of 431,827 General Partner Units and the incentive distribution rights to Quest Energy GP, LLC (“Quest Energy GP”) and the continuation of its 2.0% general partner interest in Quest Energy;

	•	the issuance of 3,201,521 common units and 8,857,981 subordinated units to the Company; and

	•	the Company and its affiliates on the one hand, and Quest Cherokee and Quest Energy on the other, agreed to indemnify the other parties from and against all losses suffered or incurred by reason of or arising out of certain existing legal proceedings.

(b) Quest Energy, Quest Energy GP and the Company entered into an Omnibus Agreement, which governs Quest Energy’s relationship with the Company and its affiliates regarding the following matters:


	•	reimbursement of certain insurance, operating and general and administrative expenses incurred on behalf of Quest Energy;

	•	indemnification for certain environmental liabilities, tax liabilities, title defects and other losses in connection with assets;

	•	a license for the use of the Quest name and mark; and

	•	Quest Energy’s right to purchase from the Company and its affiliates certain assets that the Company and its affiliates acquire within the Cherokee Basin.

(c) Quest Energy, Quest Energy GP and Quest Energy Service, LLC (“QES”) entered into a Management Services Agreement, under which QES will perform acquisition services and general and administrative services, such as accounting, finance, tax, property management, risk management, land, marketing, legal and engineering to Quest Energy, as directed by Quest Energy GP, for which Quest Energy will reimburse QES on a monthly basis for the reasonable costs of the services provided.

(d) Quest Energy entered into an Assignment and Assumption Agreement (the “Assignment”) with Bluestem Pipeline, LLC (“Bluestem”) and the Company, whereby the Company assigned all of its rights in that certain Midstream Services and Gas Dedication Agreement, dated as of December 22, 2006, but effective as of December 1, 2006, as amended (the “Midstream Services Agreement”), to Quest Energy, and Quest Energy assumed all of the Company’s liabilities and obligations arising under the Midstream Services Agreement from and after the assignment. Bluestem will gather and provide certain midstream services, including

F-12

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

dehydration, treating and compression, to Quest Energy for all gas produced from Quest Energy’s wells in the Cherokee Basin that are connected to Bluestem’s gathering system.

(e) Quest Energy signed an Acknowledgement and Consent and therefore became subject to that certain Omnibus Agreement (the “Midstream Omnibus Agreement”), dated December 22, 2006, among the Company, Quest Midstream GP, LLC, Bluestem and Quest Midstream. As long as Quest Energy is an affiliate of the Company and the Company or any of its affiliates control Quest Midstream, Quest Energy will be bound by the Midstream Omnibus Agreement. The Quest Midstream Agreement restricts Quest Energy from engaging in the following businesses, subject to certain exceptions:


	•	the gathering, treating, processing and transporting of gas in North America;

	•	the transporting and fractionating of gas liquids in North America;

	•	any other midstream activities, including but not limited to crude oil storage, transportation, gathering and terminaling;

	•	constructing, buying or selling any assets related to the foregoing businesses; and

	•	any line of business other than those described in the preceding bullet points that generates “qualifying income”, within the meaning of Section 7704(d) of the Internal Revenue Code of 1986, as amended, other than any business that is primarily engaged in the exploration for and production of oil or gas and the sale and marketing of gas and oil derived from such exploration and production activities.

(f) Quest Energy GP adopted the Quest Energy Partners, L.P. Long-Term Incentive Plan (the “Plan”) for employees, consultants and directors of Quest Energy GP and its affiliates, including Quest Energy, who perform services for Quest Energy. The Plan provides for the grant of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights and other unit-based awards. Subject to adjustment for certain events, an aggregate of 2,115,950 common units may be delivered pursuant to awards under the Plan.

Natural Gas Pipeline Operations

Our natural gas gathering pipeline network is owned by Bluestem. Bluestem was a wholly-owned subsidiary of Quest Cherokee until the formation and contribution of our midstream assets to Quest Midstream on December 22, 2006. On this date, we contributed Bluestem assets to Quest Midstream in exchange for 4.9 million class B subordinated units, 35,134 class A subordinated units and an 85% interest in the general partner of Quest Midstream (see discussion below). Also on December 22, 2006, Quest Midstream sold 4,864,866 common units, representing an approximate 48.64% limited partner interest in Quest Midstream, for $18.50 per common unit, or approximately $90 million ($84.2 million after offering costs), pursuant to a purchase agreement dated December 22, 2006, to a group of institutional investors led by Alerian Capital Management, LLC (“Alerian”), and co-led by Swank Capital, LLC (“Swank”).

Quest Midstream GP, LLC (“Quest Midstream GP”), the sole general partner of Quest Midstream, was formed on December 13, 2006 by the Company. As of December 31, 2008, Quest Midstream GP owns 276,531 general partner units representing a 2% general partner interest in Quest Midstream. The Company owns 850 member interests representing an 85% ownership interest in Quest Midstream GP, Alerian owns 75 member interests representing a 7.5% ownership interest in Quest Midstream GP and Swank owns 75 member interests representing a 7.5% ownership interest in Quest Midstream GP. Quest Midstream GP’s sole business activity is to act as the general partner of Quest Midstream.

On November 1, 2007, Quest Midstream completed the purchase of an interstate gas pipeline running from Oklahoma to Missouri (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.,

F-13

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

whereby Quest Midstream purchased all of the membership interests in the two general partners of Enbridge Pipelines (KPC), the owner of the KPC Pipeline, for a purchase price of approximately $134 million including transaction costs and assumed liabilities of approximately $1.2 million. In connection with this acquisition, Quest Midstream issued 3,750,000 common units for $20.00 per common unit, or approximately $75 million of gross proceeds ($73.6 million after offering costs) to fund a portion of the purchase price and borrowed the remainder of the purchase price under its credit facility.

Note 2 — Summary of Significant Accounting Policies

Principles of Consolidation — These consolidated financial statements include the accounts of the Company and its subsidiaries. Subsidiaries 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, a subsidiaries’ balance sheet and results of operations are reflected within the Company’s consolidated financial statements. The equity of the minority interests in its majority-owned or effectively controlled subsidiaries are shown in the consolidated financial statements as “minority interest”. 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 subsidiary company. Upon dilution of control below 50% or the loss of effective control, the accounting method is adjusted to the equity or cost method of accounting, as appropriate, for subsequent periods. All significant intercompany accounts and transactions have been eliminated.

Use of Estimates in the Preparation of Financial Statements — The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Our most significant estimates are based on remaining proved oil and gas reserves. Estimates of proved reserves are key components of our depletion rate for oil and natural gas properties and our full cost ceiling test limitation. In addition, estimates are used in computing taxes, asset retirement obligations, fair value of derivative contracts and other items. Actual results could differ from these estimates.

Revenue Recognition — We derive revenue from our oil and gas operations from the sale of produced oil and natural gas. We use the sales method of accounting for the recognition of oil and gas revenue. Because there is a ready market for oil and natural gas, we sell our oil and natural gas shortly after production at various pipeline receipt points at which time title and risk of loss transfers to the buyer. Revenue is recorded when title and risk of loss is transferred based on our net revenue interests.

Gathering revenue from our pipeline operations is recognized at the time the natural gas is gathered or transported through the system and delivered to a third party. Transportation revenue from our interstate pipeline operations is primarily from services pursuant to firm transportation agreements. These agreements provide for a demand charge based on the volume of contracted capacity and a commodity charge based on the volume of gas delivered, both at rates specified in our FERC tariffs. We recognize revenues from demand charges ratably over the contract period regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges are recognized when natural gas is scheduled to be delivered at the agreed upon delivery point.

Cash and Cash Equivalents — The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company maintains its cash balances at several financial institutions that are insured by the Federal Deposit Insurance Corporation. The Company’s cash balances typically are in excess of the insured amount; however no losses have been recognized as a result of this circumstance. Restricted Cash represents cash pledged to support reimbursement obligations under outstanding letters of credit.

F-14

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Accounts Receivable — The Company conducts the majority of its operations in the States of Kansas and Oklahoma and operates exclusively in the oil and gas industry. The Company’s receivables are generally unsecured; however, the Company has not experienced any significant losses to date. Receivables are recorded at the estimate of amounts due based upon the terms of the related agreements. Management periodically assesses the Company’s accounts receivable and establishes an allowance for estimated uncollectible amounts. Accounts determined to be uncollectible are charged to operations in the period determined to be uncollectible. The allowance for doubtful accounts was approximately $0.2 million as of December 31, 2008, 2007 and 2006.

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

Oil and Gas Properties — We use the full cost method of accounting for oil and gas properties. Under the full cost method, all direct costs and certain indirect costs associated with the acquisition, exploration, and development of our oil and gas properties are capitalized.

Oil and gas properties are depleted using the units-of-production method. The depletion expense is significantly affected by the unamortized historical and future development costs and the estimated proved oil and gas reserves. Estimation of proved oil and gas reserves relies on professional judgment and use of factors that cannot be precisely determined. Holding all other factors constant, if proved oil and gas reserve quantities were revised upward or downward, earnings would increase or decrease, respectively. Subsequent proved reserve estimates materially different from those reported would change the depletion expense recognized during the future reporting period. No gains or losses are recognized upon the sale or disposition of oil and gas properties unless the sale or disposition represents a significant quantity of proved reserves, which would have a significant impact on the depreciation, depletion, and amortization rate.

Under the full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of future net revenues, discounted at 10% per annum, plus the lower of cost or fair value of unevaluated properties less income tax effects (the “ceiling limitation”). We perform a quarterly ceiling test to evaluate whether the net book value of our full cost pool exceeds the ceiling limitation. If capitalized costs (net of accumulated depreciation, depletion, and amortization) less related deferred taxes are greater than the discounted future net revenues or ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of our full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ (deficit) equity in the period of occurrence and typically results in lower depreciation, depletion, and amortization expense in future periods. Once incurred, a write-down is not reversible at a later date. The risk that we will be required to write down the carrying value of our oil and gas properties increases when oil and gas prices are depressed, even if low prices are temporary. In addition, a write-down may occur if estimates of proved reserves are substantially reduced or estimates of future development costs increase significantly. See Note 5 — Property.

Unevaluated Properties — The costs directly associated with unevaluated oil and gas properties and properties under development are not initially included in the amortization base and relate to unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination together with interest costs capitalized for these projects. Unevaluated leasehold costs are transferred to the amortization base once determination has been made or upon expiration of a lease. Geological and geophysical costs associated with a specific unevaluated property are transferred to the amortization base with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. All items included in our unevaluated property balance are assessed on a quarterly basis for possible impairment or reduction in value. Any impairments to unevaluated properties are transferred to the amortization base.

Capitalized General and Administrative Expenses — Under the full cost method of accounting, a portion of general and administrative expenses that are directly attributable to our acquisition, exploration, and development

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

activities are capitalized to our full cost pool. The capitalized costs include salaries, related fringe benefits, cost of consulting services and other costs directly associated with those activities. We capitalized general and administrative costs related to our acquisition, exploration and development activities, during the years ended December 31, 2008, 2007, 2006 and 2005 of $3.0 million, $2.3 million, $1.4 million and $0.8 million, respectively.

Capitalized Interest Costs — The Company capitalizes interest based on the cost of major development projects. For the years ended December 31, 2008, 2007, 2006 and 2005, the Company capitalized $0.6 million, $0.4 million, $1.1 million and $0.2 million of interest, respectively.

Other Property and Equipment — The cost of other property and equipment is depreciated over the estimated useful lives of the related assets. The cost of leasehold improvements is depreciated over the lesser of the length of the related leases or the estimated useful lives of the assets.

Upon disposition or retirement of property and equipment, other than oil and gas properties, the cost and related accumulated depreciation are removed from the accounts and the gain or loss thereon, if any, is recognized in the income statement in the period of sale or disposition.

Impairment — Long-lived assets, such as property, and equipment, and finite-lived intangibles subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. If the carrying amount of such assets exceeds their undiscounted estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of such assets exceeds the fair value of the assets.

Other Assets — Other assets include deferred financing costs associated with bank credit facilities and are amortized over the term of the credit facility into interest expense. Also included in other assets are contractual rights obtained in connection with the KPC Pipeline acquisition. These intangible assets are amortized over their estimated useful lives and are reviewed for impairment whenever impairment indicators are present.

Asset Retirement Obligations — Asset retirement obligations associated with the retirement of a tangible long-lived asset are recognized as a liability in the period incurred or when it becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.

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.

Derivative Instruments — We utilize derivative instruments in conjunction with our marketing and trading activities and to manage price risk attributable to our forecasted sales of oil and gas production.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

We elect “Normal Purchases Normal Sales” (“NPNS”) accounting for derivative contracts that provide for the purchase or sale of a physical commodity that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. Derivatives that are designated as NPNS are accounted for under the accrual method accounting.

Under accrual accounting, we record revenues in the period when we deliver energy commodities or products, render services, or settle contracts. Once we elect NPNS classification for a given contract, we do not subsequently change the election and treat the contract as a derivative using mark-to-market or hedge accounting. However, if we were to determine that a transaction designated as NPNS no longer qualified for the NPNS election, we would have to record the fair value of that contract on the balance sheet at that time and immediately recognize that amount in earnings.

For those derivatives that do not meet the requirements for NPNS designation nor qualify for hedge accounting, we believe that they are still effective as economic hedges of our commodity price exposure. These contracts are accounted for using the mark-to-market accounting method. Using this method, the contracts are carried at their fair value on our consolidated balance sheets under the captions “Derivative financial instrument assets” and “Derivative financial instrument liabilities.” We recognize all unrealized and realized gains and losses related to these contracts on our consolidated statements of operations under the caption “Gain (loss) from derivative financial instruments,” which is a component of other income (expense).

We have exposure to credit risk to the extent a counterparty to a derivative instrument is unable to meet its settlement commitment. We actively monitor the creditworthiness of each counterparty and assesses the impact, if any, on our derivative positions. We do not apply hedge accounting to our derivative instruments. As a result, both realized and unrealized gains and losses on derivative instruments are recognized in the income statement as they occur.

Legal — We are subject to legal proceedings, claims and liabilities which arise in the ordinary course of our business. We accrue for losses associated with legal claims when such losses are probable and can be reasonably estimated. These estimates are adjusted as additional information becomes available or circumstances change. See Note 12 — Commitments and Contingencies.

Environmental Costs — Environmental expenditures are expensed or capitalized, as appropriate, depending on future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and costs can be reasonably estimated. We have no environmental costs accrued for all periods presented.

Stock-Based Compensation — The Company grants various types of stock-based awards (including stock options and restricted stock) and accounts for stock-based compensation at fair value. The fair value of stock option awards is determined using a Black-Scholes pricing model. The fair value of restricted stock awards are valued using the market price of the Company’s common stock on the grant date. Stock-based compensation expense is recognized over the requisite service period net of estimated forfeitures.

The Company accounts for stock-based compensation in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 123(R), Share-Based Payment (“SFAS 123(R)”), 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 utilized the modified retrospective method of adopting SFAS 123(R), whereby compensation cost and the related tax effect have been recognized in the consolidated financial statements for all relevant periods.

Income Taxes — We record our income taxes using an asset and liability approach in accordance with the provisions of the SFAS No. 109, Accounting for Income Taxes (“SFAS 109”). This results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences (primarily

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

intangible drilling costs and the net operating loss carry forward) between the book carrying amounts and the tax bases of assets and liabilities using enacted tax rates at the end of the period. Under SFAS 109, the effect of a change in tax rates of deferred tax assets and liabilities is recognized in the year of the enacted change. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. As of December 31, 2008, 2007 and 2006, a full valuation allowance was recorded against our deferred tax assets.

On January 1, 2007, the Company adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”), which defines the criteria an individual tax position must meet in order to be recognized in the financial statements. FIN 48 also provides guidance on the measurement of the income tax benefit associated with uncertain tax positions, derecognition, classification, interest and penalties and financial statement disclosure. We regularly analyze tax positions taken or expected to be taken in a tax return based on the threshold condition prescribed under FIN 48. Tax positions that do not meet or exceed this threshold condition are considered uncertain tax positions. We accrue interest related to these uncertain tax positions which is recognized in interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other expenses. The adoption of FIN 48 did not have a material impact on our financial position or results of operations.

Net Income (Loss) per Common Share — Basic earnings (loss) per share is calculated by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the period. Diluted earnings (loss) per share assumes the conversion of all potentially dilutive securities (stock options and restricted stock awards) and is calculated by dividing net income (loss) by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities under the treasury stock method. See Note 10 — Stockholders’ Equity — Earnings (Loss) Per Share.

Concentrations of Market Risk — Our future results will be affected by the market price of oil and natural gas. The availability of a ready market for oil and gas will depend on numerous factors beyond our control, including weather, production of oil and gas, imports, marketing, competitive fuels, proximity of oil and gas pipelines and other transportation facilities, any oversupply or undersupply of oil and gas, the regulatory environment, and other regional and political events, none of which can be predicted with certainty.

Concentration of Credit Risk — Financial instruments, which subject us to concentrations of credit risk, consist primarily of cash and accounts receivable. We place our cash investments with highly qualified financial institutions. Risk with respect to receivables as of December 31, 2008, 2007 and 2006 arise substantially from the sales of oil and gas and transportation revenue from our pipeline system.

ONEOK Energy Marketing and Trading Company (“ONEOK”), accounted for substantially all of our oil and gas revenue for the year ended December 31, 2008. Natural gas sales to ONEOK accounted for more than 71% of total revenue for the year ended December 31, 2007, and more than 91% for the years ended December 31, 2006 and 2005.

Fair Value — Effective January 1, 2008, we adopted SFAS 157, Fair Value Measurements (“SFAS 157”), for financial assets and liabilities measured on a recurring basis. SFAS 157 defines fair value, establishes a framework for measuring fair value and requires certain disclosures about fair value measurements for assets and liabilities measured on a recurring basis. In February 2008, the FASB issued FSP 157-2, which delayed the effective date of SFAS 157 by one year for non-financial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). We have elected to utilize this deferral and have only partially applied SFAS 157 (to financial assets and liabilities measured at fair value on a recurring basis, as described above). Accordingly, we will apply SFAS 157 to our nonfinancial assets and liabilities for which we disclose or recognize at fair value on a nonrecurring basis, such as asset retirement obligations and other assets and liabilities in the first quarter of 2009. Fair value is the exit price that we would receive to sell an asset or pay to transfer a liability in an orderly transaction between market participants at the measurement date.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

SFAS 157 also establishes a hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy are as follows:


	•	Level 1 — Quoted prices available in active markets for identical assets or liabilities as of the reporting date.

	•	Level 2 — Pricing inputs other than quoted prices in active markets included in Level 1 which are either directly or indirectly observable as of the reporting date. Level 2 consists primarily of non-exchange traded commodity derivatives.

	•	Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources.

We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. Certain of our derivatives are classified as Level 3 because observable market data is not available for all of the time periods for which we have derivative instruments. As observable market data becomes available for all of the time periods, these derivative positions will be reclassified as Level 2. The income valuation approach, which involves discounting estimated cash flows, is primarily used to determine recurring fair value measurements of our derivative instruments classified as Level 2 or Level 3. We prioritize the use of the highest level inputs available in determining fair value.

The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy. Because of the long-term nature of certain assets and liabilities measured at fair value as well as differences in the availability of market prices and market liquidity over their terms, inputs for some assets and liabilities may fall into any one of the three levels in the fair value hierarchy. While SFAS 157 requires us to classify these assets and liabilities in the lowest level in the hierarchy for which inputs are significant to the fair value measurement, a portion of that measurement may be determined using inputs from a higher level in the hierarchy.

Recently Adopted Accounting Principles

We adopted SFAS 157 as of January 1, 2008. SFAS 157 does not require any additional fair value measurements. Rather, the pronouncement defines fair value, establishes a framework for measuring fair value under existing accounting pronouncements that require fair value measurements, and expands disclosures about fair value measurements. We elected to implement SFAS 157 with the one-year deferral FASB Staff Position (“FSP”) FAS No. 157-2 for nonfinancial assets and nonfinancial liabilities, except those nonfinancial items recognized or disclosed at fair value on a recurring basis (at least annually). Effective upon issuance, the FASB issued FSP FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active (“FSP FAS 157-3”), in October 2008. FSP FAS 157-3 clarifies the application of SFAS 157 in determining the fair value of a financial asset when the market for that financial asset is not active. As of December 31, 2008, we had no financial assets with a market that was not active.

In September 2006, the SEC issued Staff Accounting Bulletin (“SAB”) No. 108 (“SAB 108”). SAB 108 addresses how the effects of prior year uncorrected misstatements should be considered when quantifying misstatements in current year financial statements. SAB 108 requires companies to quantify misstatements using a balance sheet and income statement approach and to evaluate whether either approach results in quantifying an error that is material in light of relevant quantitative and qualitative factors. When the effect of initial adoption is material, companies will record the effect as a cumulative effect adjustment to beginning of year retained earnings and disclose the nature and amount of each individual error being corrected in the cumulative adjustment. SAB 108 became effective beginning January 1, 2007 and applies to our restatement adjustments recorded in the restated financial statements presented herein.

In December 2004, the FASB issued SFAS 153, Exchanges of Nonmonetary Assets (“SFAS 153”). SFAS 153 requires the use of fair value measurement for exchanges of nonmonetary assets. Because SFAS 153 is applied

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

retrospectively, the statement was effective for us in 2005. The adoption of SFAS 153 did not have a material impact on our financial statements.

In September 2005, the Emerging Issues Task Force (“EITF”) concluded in Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty (“EITF 04-13”), that purchases and sales of inventory with the same party in the same line of business should be accounted for as nonmonetary exchanges, if entered into in contemplation of one another. We present purchase and sale activities related to our marketing and trading activities on a net basis in the income statement. The conclusion reached on EITF 04-13 did not have an impact on our consolidated financial statements.

Recent Accounting Pronouncements

In April 2007, the FASB issued FSP FIN 39-1, Amendment of FASB Interpretation No. 39 (“FSP FIN 39-1”), which amends FIN 39, Offsetting of Amounts Related to Certain Contracts. FSP FIN 39-1 permits netting fair values of derivative assets and liabilities for financial reporting purposes, if such assets and liabilities are with the same counterparty and subject to a master netting arrangement. FSP FIN 39-1 also requires that the net presentation of derivative assets and liabilities include amounts attributable to the fair value of the right to reclaim collateral assets held by counterparties or the obligation to return cash collateral received from counterparties. We did not elect to adopt FSP FIN 39-1.

In December 2007, the FASB issued SFAS No. 141(R), Business Combinations (“SFAS 141(R)”), which replaces SFAS 141. SFAS 141(R) establishes principles and requirements for how the acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree. In addition, SFAS 141(R) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase. SFAS 141(R) also establishes disclosure requirements to enable users to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective as of the beginning of an entity’s fiscal year that begins after December 15, 2008, with early adoption prohibited. Effective January 1, 2009, we will apply this statement to any business combinations, including the contemplated Recombination previously discussed. The adoption of SFAS 141(R) did not have a material effect on our results of operations, cash flows and financial position as of January 1, 2009, the date of adoption.

In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS 159”), including an amendment to SFAS 115. Under SFAS 159, entities may elect to measure specified financial instruments and warranty and insurance contracts at fair value on a contract-by-contract basis, with changes in fair value recognized in earnings each reporting period. The election, called the fair value option, enables entities to achieve an offset accounting effect for changes in fair value of certain related assets and liabilities without having to apply complex hedge accounting provisions. SFAS 159 is expected to expand the use of fair value measurement consistent with the FASB’s long-term objectives for financial instruments. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We have assessed the provisions of SFAS 159 and we have elected not to apply fair value accounting to our existing eligible financial instruments. As a result, the adoption of SFAS 159 did not have an impact on our financial statements.

In December 2007, the FASB issued SFAS No. 160, Non-controlling Interests in Consolidated Financial Statements — An Amendment of ARB No. 51 (“SFAS 160”). SFAS 160 establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the non-controlling interest, and changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary. In addition, SFAS 160 establishes principles for valuation of retained non-controlling equity investments and measurement of gain or loss when a subsidiary is deconsolidated. SFAS 160 also establishes disclosure requirements to clearly identify and distinguish between interests of the parent and the interests of the non-controlling owners. SFAS 160 is effective for fiscal years and interim periods beginning after December 15, 2008, with early adoption prohibited. After adopting SFAS 160 in

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

2009, we will apply provisions of this standard to noncontrolling interests created or acquired in future periods. Upon adoption, we will reclassify our minority interests to stockholders’ equity.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133 (“SFAS 161”). SFAS 161 does not change the accounting for derivatives, but requires enhanced disclosures about how and why we use derivative instruments, how derivative instruments and related hedged items (if any) are accounted for, and how they affect our financial position, financial performance and cash flows. SFAS 161 is effective for us beginning with the first quarter of 2009.

In June 2008, the FASB issued FSP EITF No. 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (“FSP EITF 03-6-1”). FSP EITF 03-6-1 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and are therefore required to be included in the earnings allocation in calculating earnings per share under the two-class method described in SFAS No. 128, Earnings per Share. FSP EITF 03-6-1 requires companies to treat unvested share-based payment awards that have non-forfeitable rights to dividend or dividend equivalents as a separate class of securities in calculating earnings per share. FSP EITF 03-6-1 is effective for fiscal years beginning after December 15, 2008. We adopted FSP EITF 03-6-1 effective January 1, 2009. FSP EITF 03-6-1 did not have an effect on the presentation of earnings per share.

On December 31, 2008, the SEC issued Release No. 33-8995, Modernization of Oil and Gas Reporting, which revises disclosure requirements for oil and gas companies. In addition to changing the definition and disclosure requirements for oil and gas reserves, the new rules change the requirements for determining oil and gas reserve quantities. These rules permit the use of new technologies to determine proved reserves under certain criteria and allow companies to disclose their probable and possible reserves. The new rules also require companies to report the independence and qualifications of their reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit. The new rules also require that oil and gas reserves be reported and the full cost ceiling limitation be calculated using a twelve-month average price rather than period-end prices. The use of a twelve-month average price may have had an effect on our 2008 depletion rates for our oil and gas properties and the amount of impairment recognized as of December 31, 2008 had the new rules been effective for the period. The new rules are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, pending the potential alignment of certain accounting standards by the FASB with the new rule. We plan to implement the new requirements in our Annual Report on Form 10-K for the year ended December 31, 2009. We are currently assessing the impact the rules will have on our consolidated financial statements.

Note 3 — Acquisitions and Divestitures

Acquisitions

PetroEdge — On July 11, 2008, QRCP completed the acquisition of privately held PetroEdge Resources (WV) LLC (“PetroEdge”) in an all cash purchase for approximately $142 million in cash including transaction costs, subject to certain adjustments for working capital and certain other activity between May 1, 2008 and the closing date. The assets acquired were approximately 78,000 net acres of oil and natural gas producing properties in the Appalachian Basin with estimated net proved reserves of 99.6 Bcfe as of May 1, 2008 and net production of approximately 3.3 million cubic feet equivalent per day (“Mmcfe/d”). The transaction was recorded within the Company’s oil and gas production segment and was funded using the proceeds from the sale of the PetroEdge producing wellbores to Quest Cherokee discussed below and the proceeds of its July 8, 2008 public offering of 8,800,000 shares of common stock.

At closing, QRCP sold the producing well bores to Quest Cherokee for approximately $71.2 million. The proved undeveloped reserves, unproved and undrilled acreage related to the wellbores (generally all acreage other than established spacing related to the producing well bores) and a gathering system were retained by PetroEdge

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

and its name was changed to Quest Eastern Resource LLC. Quest Eastern is designated as operator of the wellbores purchased by Quest Cherokee and conducts drilling and other operations for our affiliates and third parties on the PetroEdge acreage. Quest Cherokee funded its purchase of the PetroEdge wellbores with borrowings under its revolving credit facility and the proceeds of a $45 million, six-month term loan. See Note 4 — Long-Term Debt.

We accounted for this acquisition in accordance with SFAS 141, “Business Combinations.” The purchase price was allocated to assets acquired and liabilities assumed based on estimated fair values of the respective assets and liabilities at the time of closing. The following table summarizes the allocation of the purchase price (in thousands):


Current assets	$	3,069
Oil and gas properties		142,618	(a)
Gathering facilities		1,820
Current liabilities		(3,537	)
Asset retirement obligations		(2,193	)(a)

Purchase price	$	141,777


(a)		Net assets acquired by Quest Cherokee consisted of $73.4 million of proved oil and gas properties and $2.2 million of asset retirement obligations.

KPC Pipeline — On November 1, 2007, Quest Midstream completed the purchase of the KPC Pipeline for approximately $133.7 million, including transaction costs. The acquisition expanded Quest Midstream’s pipeline operations and was recorded in the Company’s natural gas pipelines segment. The KPC Pipeline is a 1,120 mile interstate gas pipeline, which transports natural gas from Oklahoma and western Kansas to the metropolitan Wichita and Kansas City markets and is one of only three pipeline systems capable of delivering gas into the Kansas City metropolitan market. The KPC system includes three compressor stations with a total of 14,680 horsepower and has a capacity of approximately 160 MMcf/d. The KPC Pipeline has supply interconnections with pipelines owned and/or operated by Enogex, Inc., Panhandle Eastern Pipeline Company and ANR Pipeline Company, allowing Quest Midstream to transport natural gas sourced from the Anadarko and Arkoma basins, as well as the western Kansas and Oklahoma panhandle producing regions. The acquisition was funded through the issuance of 3,750,000 common units of Quest Midstream for $20.00 per common unit and borrowings of $58 million under Quest Midstream’s credit facility.

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 (See Note 13)		9,934
Liabilities assumed		(1,145	)

Purchase price	$	133,725

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QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Pro Forma Summary Data related to acquisitions (unaudited)

The following unaudited pro forma information summarizes the results of operations for the years ended December 31, 2008, 2007 and 2006 as if the PetroEdge acquisition had occurred on January 1, 2008 and 2007 and as if the KPC Pipeline acquisition had occurred on January 1, 2007 and 2006 (in thousands):


	2008			2007			2006

Pro forma revenue	$	182,813		$	143,913		$	96,200
Pro forma net income (loss)	$	(246,175	)	$	(60,677	)	$	30,768
Pro forma net income (loss) per share — basic	$	(7.79	)	$	(1.95	)	$	1.39
Pro forma net income (loss) per share — diluted	$	(7.79	)	$	(1.95	)	$	1.39

The pro forma information is presented for illustration purposes only, in accordance with the assumptions set forth below. The pro forma information does not reflect any cost savings or other synergies anticipated as a result of the acquisitions or any future acquisition-related expenses. The pro forma adjustments are based on estimates and assumptions. Management believes the estimates and assumptions are reasonable, and that the significant effects of the transactions are properly reflected.

The pro forma information is a result of combining the income statement of the Company with the pre-acquisition results of KPC and PetroEdge adjusted for 1) recording pro forma interest expense on debt incurred to acquire KPC and PetroEdge; 2) DD&A expense calculated based on the adjusted basis of the properties and intangibles acquired using the purchase method of accounting; and 3) any related income tax effects of these adjustments based on the applicable statutory tax rates.

Other Transactions — On October 15, 2007, QRCP, Quest MergerSub, Inc., QRCP’s wholly-owned subsidiary (“MergerSub”), and Pinnacle Gas Resources, Inc. (“Pinnacle”) entered into an Agreement and Plan of Merger, pursuant to which MergerSub would merge (the “Merger”) with and into Pinnacle, with Pinnacle continuing as the surviving corporation and as QRCP’s wholly-owned subsidiary. On May 16, 2008, the Merger Agreement was terminated. Pursuant to the terms of the Merger Agreement, either QRCP or Pinnacle had the right to terminate the Merger Agreement if the proposed Merger was not completed by May 16, 2008. No termination fee was payable by QRCP or Pinnacle as a result of the termination of the Merger Agreement.

Divestitures

On June 4, 2008, we acquired the right to develop, and the option to purchase, certain drilling and other rights in and below the Marcellus Shale covering approximately 28,700 net acres in Potter County, Pennsylvania for $4.0 million. On November 26, 2008, we divested of these rights to a private party for approximately $3.2 million.

On October 30, 2008, we divested of approximately 22,600 net undeveloped acres and one well in Somerset County, Pennsylvania to a private party for approximately $6.8 million.

On November 5, 2008, we divested of 50% of our interest in approximately 4,500 net undeveloped acres in Wetzel County, West Virginia to a private party for $6.1 million. Included in the sale were three wells in various stages of completion and existing pipelines and facilities. QRCP will continue to operate the property included in this joint venture. All future development costs will be split equally between us and the private party.

On February 13, 2009, we divested of approximately 23,000 net undeveloped acres and one well in Lycoming County, Pennsylvania to a private party for approximately $8.7 million.

The proceeds from these divestitures were credited to the full cost pool.

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QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 4 — Long-Term Debt

The following is a summary of the Company’s long-term debt at December 31, 2008, 2007 and 2006 (in thousands):


	2008		2007		2006

Borrowings under bank senior credit facilities
Quest	$	29,000	$	44,000	$	225,000
Quest Energy:						—
Revolving credit facility		189,000		94,000		—
Term loan		41,200		—		—
Quest Midstream		128,000		95,000		—
Notes payable to banks and finance companies, secured by equipment and vehicles, due in installments through October 2013 with interest ranging from 2.9% to 9.8% per annum		907		712		569

Total debt		388,107		233,712		225,569
Less current maturities included in current liabilities		45,013		666		324

Total long-term debt	$	343,094	$	233,046	$	225,245

Aggregate maturities of long-term debt during the next five years at December 31, 2008 are as follows (in thousands):


2009	$	45,013
2010		215,053
2011		26
2012		128,007
2013 and thereafter		8

Total	$	388,107

Other Long-Term Indebtedness

Approximately $0.9 million of notes payable to banks and finance companies were outstanding at December 31, 2008 and are secured by equipment and vehicles, with payments due in monthly installments through October 2013 with interest ranging from 2.9% to 9.8% per annum.

Credit Facilities

Quest. On July 11, 2008, QRCP and Royal Bank of Canada (“RBC”) entered into an Amended and Restated Credit Agreement (the “Credit Agreement”) to convert QRCP’s then-existing $50 million revolving credit facility to a $35 million term loan, due and maturing on July 11, 2010 (the “Original Term Loan”). On October 24, 2008, QRCP and RBC entered into a First Amendment to Amended and Restated Credit Agreement, which, among other things, added a $6 million term loan (the “Additional Term Loan”) to the $35 million term loan under the Credit Agreement. The maturity date for the Additional Term Loan was November 30, 2008. On October 24, 2008, QRCP borrowed $2 million of the $6 million available under the Additional Term Loan. On November 4, 2008, QRCP entered into a Second Amendment to Amended and Restated Credit Agreement (the “Second Amendment to Credit Agreement”) which clarified that the $6 million commitment under the Additional Term Loan would be reduced dollar for dollar to the extent QRCP retained net cash proceeds from dispositions in accordance with the terms of the Credit Agreement. On January 30, 2009, QRCP entered into a Third Amendment to Amended and Restated Credit

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QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Agreement (the “Third Amendment to Credit Agreement”) and on May 29, 2009, QRCP entered into a Fourth Amendment to Amended and Restated Credit Agreement (the “Fourth Amendment to Credit Agreement”).

The Original Term Loan is payable in quarterly installments of $1.5 million on the last business day of each March, June, September and December commencing on September 30, 2008, with the remaining principal amount being payable in full on July 11, 2010. As discussed in the next paragraph, QRCP has prepaid all of the quarterly principal payment requirements of $1.5 million through June 30, 2009 and therefore has no quarterly principal payments due until September 30, 2009. If the outstanding amount of the Original Term Loan is at any time more than 50% of the market value of QRCP’s partnership interests in Quest Midstream and Quest Energy pledged to secure the loan plus the value of QRCP’s oil and gas properties (as defined in the Credit Agreement) pledged to secure the loan, QRCP will be required to either repay the term loan by the amount of such excess or pledge additional assets to secure the term loan.

As part of the Second Amendment to Credit Agreement, QRCP agreed to apply any net cash proceeds from a sale of assets or a sale of equity interests in certain subsidiaries as follows: first, to repay any amounts borrowed under the Additional Term Loan (this was done on October 30, 2008); second, to prepay the next three quarterly principal payments due on the Original Term Loan on the last business day of December 2008, March 2009 and June 2009 (this was done in October and November 2008); third, subject to certain conditions being met and the net cash proceeds being received by January 31, 2009, up to $20 million for QRCP’s own use for working capital and to make capital expenditures for the development of its oil and gas properties; and fourth, any excess net cash proceeds to repay the Original Term Loan. The Third Amendment to Credit Agreement provided that in connection with the sale of QRCP’s Lycoming County, Pennsylvania acreage in February 2009, QRCP could retain all of the net proceeds from such sale in excess of $750,000. QRCP will be required to apply all of the net cash proceeds from the issuance of any debt and 50% of the net cash proceeds from the sale of any equity securities to first repay the Original Term Loan and then to QRCP.

Quest Oil & Gas, LLC (“QOG”), Quest Energy Service, LLC (“QES”), Quest Mergersub and Quest Eastern guarantee all of QRCP’s obligations under the Credit Agreement. The Credit Agreement is secured by a first priority lien on QRCP’s ownership interests in Quest Energy and Quest Midstream and their general partners and the oil and gas properties owned by Quest Eastern in the Appalachian Basin, which are substantially all of QRCP’s assets. The assets of each of Quest Midstream GP, Quest Midstream and each of their subsidiaries and Quest Energy GP, Quest Energy and each of their subsidiaries (collectively the “Excluded MLP Entities”) are not pledged to secure the Credit Agreement.

At December 31, 2008, $29 million was outstanding under the Original Term Loan. The Additional Term Loan was repaid on October 30, 2008.

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QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The Credit Agreement’s financial covenants prohibit QRCP and any of its subsidiaries (excluding the Excluded MLP Entities) from:


	•	permitting the interest coverage ratio (ratio of consolidated EBITDA (or consolidated annualized EBITDA for periods ending on or before December 31, 2008) to consolidated interest charges (or consolidated annualized interest charges for periods ending on or before December 31, 2008)) at any fiscal quarter-end, commencing with the quarter-ended September 30, 2008, to be less than 2.5 to 1.0 (calculated based on the most recently delivered compliance certificate); and

	•	permitting the leverage ratio (ratio of consolidated funded debt to consolidated EBITDA (or consolidated annualized EBITDA for periods ending on or before December 31, 2008)) at any fiscal quarter-end, commencing with the quarter-ended September 30, 2008, to be greater than 2.0 to 1.0 (calculated based on the most recently delivered compliance certificate).

Consolidated EBITDA is defined in the Credit Agreement to mean for QRCP and its subsidiaries (excluding the Excluded MLP Entities) on a consolidated basis, an amount equal to the sum of (i) consolidated net income, (ii) consolidated interest charges, (iii) the amount of taxes, based on or measured by income, used or included in the determination of such consolidated net income, (iv) the amount of depreciation, depletion and amortization expense deducted in determining such consolidated net income, (v) merger and acquisition costs incurred by QRCP that are required to be expensed as a result of the termination of the merger agreement with Pinnacle Gas Resources, Inc., (vi) merger and acquisition costs required to be expensed under FAS 141(R), (vii) fees and expenses of the internal investigation relating to the Misappropriation Transaction (as defined in the First Amendment to Credit Agreement) and the related restructuring which were capped at $1,500,000 for purposes of this definition and (viii) other non-cash charges and expenses deducted in the determination of such consolidated net income, including, without limitation, non-cash charges and expenses relating to swap contracts or resulting from accounting convention changes, of QRCP and its subsidiaries (excluding the Excluded MLP Entities) on a consolidated basis, all determined in accordance with GAAP.

Consolidated annualized EBITDA means, for QRCP and its subsidiaries (excluding the Excluded MLP Entities) on a consolidated basis, (i) for the fiscal quarter ended September 30, 2008, consolidated EBITDA for the nine month period ended September 30, 2008 multiplied by 1.33, and (ii) for the fiscal quarter ended December 31, 2008, consolidated EBITDA for the twelve month period ended December 31, 2008.

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

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QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Consolidated annualized interest charges means, for QRCP and its subsidiaries (excluding the Excluded MLP Entities) on a consolidated basis, (i) for the fiscal quarter ended September 30, 2008, consolidated interest charges for the nine month period ended September 30, 2008 multiplied by 1.33, and (ii) for the fiscal quarter ended December 31, 2008, consolidated interest charges for the twelve month period ended December 31, 2008.

Consolidated funded debt means, for QRCP and its subsidiaries (excluding the Excluded MLP Entities) on a consolidated basis, the sum of (i) the outstanding principal amount of all obligations and liabilities, whether current or long-term, for borrowed money (including obligations under the Credit Agreement), (ii) all reimbursement obligations relating to letters of credit that have been drawn and remain unreimbursed, (iii) attributable indebtedness pertaining to capital leases, (iv) attributable indebtedness pertaining to synthetic lease obligations, and (v) without duplication, all guaranty obligations with respect to indebtedness of the type specified in subsections (i) through (iv) above.

Events of default under the Credit Agreement are customary for transactions of this type and include, without limitation, non-payment of principal when due, non-payment of interest, fees and other amounts for a period of three business days after the due date, failure to perform or observe covenants and agreements (subject to a 30-day cure period in certain cases), representations and warranties not being correct in any material respect when made, cross-defaults to other material indebtedness, certain acts of bankruptcy or insolvency, and change of control. Under the Credit Agreement, a change of control means the acquisition by any person, or two or more persons acting in concert, of beneficial ownership (within the meaning of Rule 13d-3 of the SEC under the Securities Exchange Act of 1934) of 50% or more of QRCP’s outstanding shares of voting stock; provided, however, that a merger of QRCP into another entity in which the other entity is the survivor will not be deemed a change of control if QRCP’s stockholders of record as constituted immediately prior to such acquisition hold more than 50% of the outstanding shares of voting stock of the surviving entity.

QRCP was not in compliance with all of its financial covenants as of December 31, 2008 and March 31, 2009 and QRCP does not anticipate that it will be in compliance at any time in the foreseeable future. On May 29, 2009, QRCP obtained a waiver of these defaults from its lenders for the quarters ended December 31, 2008 and March 31, 2009 and is negotiating with its lender to obtain a waiver of these requirements for future periods.

Quest Energy. On November 15, 2007, Quest Energy, as a guarantor, entered into an Amended and Restated Credit Agreement (the “Quest Cherokee Credit Agreement”) with QRCP, as the initial co-borrower, Quest Cherokee, as the borrower, RBC, as administrative agent and collateral agent, KeyBank National Association, as documentation agent and the lenders party thereto. Quest Cherokee and QRCP had previously been parties to the following credit agreements with Guggenheim Corporate Funding, LLC (“Guggenheim”): (i) Amended and Restated Senior Credit Agreement, dated February 7, 2006, as amended; (ii) Amended and Restated Second Lien Term Loan Agreement, dated June 9, 2006, as amended; and (iii) Third Lien Term Loan Agreement, dated June 9, 2006, as amended (collectively, the “Prior Credit Agreements”). Guggenheim and the lenders under the Prior Credit Agreements assigned all of their interests and rights (other than certain excepted interests and rights) in the Prior Credit Agreements to RBC and the new lenders under the Quest Cherokee Credit Agreement pursuant to a Loan Transfer Agreement, dated November 15, 2007, by and among QRCP, Quest Cherokee, QOG, QES, Quest Cherokee Oilfield Service, LLC (“QCOS”), Guggenheim, Wells Fargo Foothill, Inc., the lenders under the Prior Credit Agreements and RBC. The Quest Cherokee Credit Agreement amended and restated the Prior Credit Agreements in their entirety. In connection with the closing of the initial public offering and the application of the net proceeds thereof, QRCP was released as a borrower under the Quest Cherokee Credit Agreement. On April 15, 2008, Quest Energy and Quest Cherokee entered into a First Amendment to Amended and Restated Credit Agreement that, among other things, amended the interest rate and maturity date pursuant to the “market flex” rights contained in the commitment papers related to the Quest Cherokee Credit Agreement.

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QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Cherokee’s proved reserves. In addition, Quest Cherokee and RBC each have the right to initiate a redetermination of the borrowing base between each six-month redetermination. As of December 31, 2008, the borrowing base was $190 million, and the amount borrowed under the Quest Cherokee Credit Agreement was $189 million. No amounts were available for borrowing because the remaining $1.0 million was supporting letters of credit issued under the Quest Cherokee Credit Agreement.

On July 11, 2008, concurrent with Quest Energy’s acquisition of 32.9 Bcfe of proved developed reserves in the Appalachian Basin from QRCP, Quest Energy and Quest Cherokee entered into a Second Lien Senior Term Loan Agreement (the “Second Lien Loan Agreement,” together with the Quest Cherokee Credit Agreement, as amended, the “Quest Cherokee Agreements”) for a six-month, $45 million term loan.

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. On October 28, 2008, Quest Energy and Quest Cherokee entered into a First Amendment to Second Lien Loan Agreement (the “First Amendment to Second Lien Loan Agreement”) to, among other things, extend the maturity date to September 30, 2009 and to amend and/or waive certain of the representations and covenants contained in the Second Lien Loan Agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result or (1) the Transfers and (2) not timely settling certain intercompany accounts among QRCP, Quest Energy and Quest Midstream. At the same time, a Second Amendment to the Quest Cherokee Credit Agreement was entered into to amend and/or waive certain of the representations and covenants contained in the Second Lien Loan Agreement in order to rectify any possible covenant violations or non-compliance with the representations and warranties as a result of (1) the Transfers and (2) not timely settling certain intercompany accounts among QRCP, Quest Energy and Quest Midstream.

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QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

September 30, 2009) or (iii) engage RBC Capital Markets to arrange financing to refinance the term loan under the Second Lien Loan Agreement on the prevailing terms in the credit market.

The Quest Cherokee Agreements’ financial covenants prohibit Quest Cherokee, Quest Energy and any of their subsidiaries from:


	•	permitting the ratio (calculated based on the most recently delivered compliance certificate) of Quest Energy’s consolidated current assets (including the unused availability under the revolving credit facility, but excluding non-cash assets under FAS 133) to consolidated current liabilities (excluding non-cash obligations under FAS 133, asset and asset retirement obligations and current maturities of indebtedness under the Quest Cherokee Credit Agreement) at any fiscal quarter-end to be less than 1.0 to 1.0; provided, however, that current assets and current liabilities will exclude mark-to-market values of swap contracts, to the extent such values are included in current assets and current liabilities;

	•	permitting the interest coverage ratio (calculated on the most recently delivered compliance certificate) of adjusted consolidated EBITDA to consolidated interest charges at any fiscal quarter-end to be less than 2.5 to 1.0 measured on a rolling four quarter basis; and

	•	permitting the leverage ratio (calculated based on the most recently delivered compliance certificate) of consolidated funded debt to adjusted consolidated EBITDA at any fiscal quarter-end to be greater than 3.5 to 1.0 measured on a rolling four quarter basis.

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QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Events of default under the Quest Cherokee Agreements are customary for transactions of this type and include, without limitation, non-payment of principal when due, non-payment of interest, fees and other amounts for a period of three business days after the due date, failure to perform or observe covenants and agreements (subject to a 30-day cure period in certain cases), representations and warranties not being correct in any material respect when made, certain acts of bankruptcy or insolvency, cross defaults to other material indebtedness, borrowing base deficiencies, and change of control. Under the Quest Cherokee Agreements, a change of control means (i) QRCP fails to own or to have voting control over at least 51% of the equity interest of Quest Energy GP, (ii) any person acquires beneficial ownership of 51% or more of the equity interest in Quest Energy; (iii) Quest Energy fails to own 100% of the equity interests in Quest Cherokee, or (iv) QRCP undergoes a change in control (the acquisition by a person, or two or more persons acting in concert, of beneficial ownership of 50% or more of QRCP’s outstanding shares of voting stock, except for a merger with and into another entity where the other entity is the survivor if QRCP’s stockholders of record immediately preceding the merger hold more than 50% of the outstanding shares of the surviving entity).

Quest Energy was in compliance with all of its covenants as of December 31, 2008.

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QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

During the Transition Period (as defined in the Amended Quest Midstream Credit Agreement), interest will accrue on the revolving credit facility at either LIBOR plus 4% or the base rate plus 3.0%. After the Transition Period ends, interest will accrue at either LIBOR plus a margin ranging from 2.0% to 3.50% (depending on the total leverage ratio) or the base rate plus a margin ranging from 1.0% to 2.5% (depending on the total leverage ratio), at our option. The base rate is generally the higher of the federal funds rate plus 0.50%, RBC’s prime rate or LIBOR plus 1.25%. The Transition Period ended on March 31, 2009 when Quest Midstream’s audited financial statements for 2008 were delivered to RBC.

Quest Kansas General Partner, Quest Kansas Pipeline, and KPC guarantee all of Quest Midstream’s and Bluestem’s obligations under the Amended Quest Midstream Credit Agreement. The revolving credit facility is secured by a first priority lien on substantially all of the assets of Quest Midstream and Bluestem and their subsidiaries (including the KPC Pipeline).

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QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Amended Quest Midstream Credit Agreement’s financial covenants prohibit Bluestem, Quest Midstream and any of their subsidiaries from:


	•	permitting the interest coverage ratio (ratio of adjusted consolidated EBITDA to consolidated interest charges) on a rolling four quarter basis (calculated based on the most recently delivered compliance certificate), commencing with the fiscal quarter ending December 31, 2007, to be less than 2.50 to 1.00 for any fiscal quarter ending on or prior to December 31, 2008, increasing to 2.75 to 1.00 for each fiscal quarter end thereafter; and

	•	permitting the total leverage ratio (ratio of adjusted consolidated funded debt to adjusted consolidated EBITDA) on a rolling four quarter basis (calculated based on the most recently delivered compliance certificate), commencing with the fiscal quarter ending December 31, 2007 and ending December 31, 2008, to be greater than 5.00 to 1.00, decreasing to 4.50 to 1.00 for each fiscal quarter end thereafter.

F-32

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Events of default under the Amended Quest Midstream Credit Agreement are customary for transactions of this type and include, without limitation, non-payment of principal when due, non-payment of interest, fees and other amounts for a period of three business days after the due date, failure to perform or observe covenants and agreements (subject to a 30-day cure period in certain cases), representations and warranties not being correct in any material respect when made, certain acts of bankruptcy or insolvency, cross defaults to other material indebtedness, and change of control. Under the Quest Midstream Credit Agreement a change of control means (i) QRCP fails to own or to have voting control over, at least 51% of the equity interest of Quest Midstream GP; (ii) any person acquires beneficial ownership of 51% or more of the equity interest in Quest Midstream; (iii) Quest Midstream fails to own 100% of the equity interests in Bluestem or (iv) QRCP undergoes a change in control (the acquisition by a person, or two or more persons acting in concert, of beneficial ownership of 50% or more of QRCP’s outstanding shares of voting stock, except for a merger with and into another entity where the other entity is the survivor if QRCP’s stockholders of record immediately preceding the merger hold more than 50% of the outstanding shares of the surviving entity).

Quest Midstream was in compliance with all of its covenants as of December 31, 2008.

Subordinated Notes — In December 2003, we issued a five-year $51 million junior subordinated promissory note (the “Original Note”) to ArcLight Energy Partners Fund I, L.P. (“ArcLight”) pursuant to the terms of a note purchase agreement. The Original Note bore interest at 15% per annum and was subordinate and junior in right of payment to the prior payment in full of superior debts. In connection with the purchase of the Original Note, the original limited liability company agreement for Quest Cherokee was amended and restated to, among other things, provide for Class A units and Class B units of membership interest, and ArcLight acquired all of the Class A units of Quest Cherokee in exchange for $100. The existing membership interests in Quest Cherokee owned by our subsidiaries were converted into all of the Class B units. To appropriately determine the fair value of the Class A units, we imputed a discount on the Original Note of approximately $15.4 million. Accordingly, the initial carrying value of the Original Note was $35.6 million. The $15.4 million value allocated to the Class A units was recorded as minority interest in Quest Cherokee in our consolidated financial statements.

During 2005, Quest Cherokee and ArcLight amended and restated the note purchase agreement to provide for the issuance to ArcLight of up to $15 million of additional 15% junior subordinated promissory notes (the “Additional Notes” and together with the Original Notes, the “Subordinated Notes”) pursuant to the terms of an amended and restated note purchase agreement and issued $15 million of Additional Notes to ArcLight.

In November 2005, we paid approximately $84 million to repurchase the Subordinated Notes and accrued interest and $26.1 million to repurchase the Class A units of Quest Cherokee. In connection with this transaction, a loss on extinguishment of debt of approximately $12.4 million was recognized representing the remaining debt discount on the Subordinated Notes as of the date of the repurchase. The excess of the amount paid to repurchase the Class A units of Quest Cherokee over the minority interest (approximately $10.7 million) was allocated to oil and

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QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

gas properties and pipeline assets under the provisions of SFAS 141. Additionally, the Company wrote-off $0.8 million in deferred loan costs related to the Original Note.

Note 5 — Property

Oil and gas properties, pipeline assets and other property and equipment were comprised of the following as of December 31, 2008, 2007 and 2006 (in thousands):


	2008			2007			2006

Oil and gas properties under the full cost method of accounting:
Properties being amortized	$	299,629		$	380,033		$	288,646
Properties not being amortized		10,108			7,986			8,108

Total oil and gas properties, at cost		309,737			388,019			296,754
Less: accumulated depletion, depreciation and amortization		(137,200	)		(87,066	)		(55,476	)

Oil and gas properties, net	$	172,537		$	300,953		$	241,278

Pipeline assets, at cost	$	333,966		$	306,317		$	132,715
Less: accumulated depreciation		(23,527	)		(11,791	)		(6,061	)

Pipeline assets, net	$	310,439		$	294,526		$	126,654

Other property and equipment at cost	$	33,994		$	27,712		$	21,115
Less: accumulated depreciation		(10,131	)		(6,207	)		(4,435	)

Other property and equipment, net	$	23,863		$	21,505		$	16,680

As of December 31, 2008, the Company’s net book value of oil and gas properties exceeded the full cost ceiling. Accordingly, a provision for impairment was recognized in the fourth quarter of 2008 of $298.9 million. The provision for impairment was primarily attributable to declines in the prevailing market prices of oil and gas at the measurement date and revisions of reserves due to further technical analysis and production of gas during 2008. See Note 21 — Supplemental Information on Oil and Gas Producing Activities (Unaudited).

Depreciation on pipeline assets and other property and equipment is computed on the straight-line basis over the following estimated useful lives:


Pipelines			15 to 40 years
Buildings			25 years
Machinery and equipment			10 years
Software and computer equipment			3 to 5 years
Furniture and fixtures			10 years
Vehicles			7 years

For the years ended December 31, 2008, 2007, 2006 and 2005, depletion, depreciation and amortization expense (excluding impairment amounts discussed above) on oil and gas properties amounted to $50.4 million, $31.7 million, $22.4 million and $19.4 million, respectively; depreciation expense on pipeline assets amounted to $16.2 million, $5.8 million, $2.5 million and $1.4 million, respectively; and depreciation expense on other property and equipment amounted to $3.8 million, $2.3 million, $2.1 million and $1.4 million, respectively.

F-34

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 6 — Minority Interests

A rollforward of minority interest balances related to QRCP’s investments in Quest Energy and Quest Midstream for the periods indicated is as follows (in thousands):


	Year Ended December 31,
	2008			2007			2006

Quest Energy:
Beginning of year	$	145,364		$	—		$	—
Contributions, net		—			151,025			—
Distributions		(13,438	)		—			—
Minority interest in earnings (loss)		(73,295	)		(5,661	)		—
Stock compensation expense related to QELP unit-based awards		35			—			—

End of year	$	58,666		$	145,364		$	—

Quest Midstream:
Beginning of year	$	152,021		$	84,173		$	—
Contributions, net		—			73,424			84,187
Distributions		(7,629	)		(9,470	)		—
Minority interest in earnings (loss)		1,027			2,757			(14	)
Stock compensation expense related to QMLP unit-based awards		451			1,137			—

End of year	$	145,870		$	152,021		$	84,173

Total minority interest liability at end of year	$	204,536		$	297,385		$	84,173

Quest Energy

During November 2007, QELP completed its initial public offering of 9,100,000 common units (representing a 42.1% limited partner interest) for net proceeds of $151.3 million ($163.8 million less $12.5 million for underwriting discounts, structuring fees and offering costs). QELP was formed by Quest to own, operate, acquire and develop Quest’s oil and gas production operations in the Cherokee Basin. Quest contributed assets to QELP in exchange for an aggregate 55.9% limited partner interest (consisting of common and subordinated limited partner units) in QELP, a 2% general partner interest and incentive distribution rights (IDRs). IDRs entitle the holder to specified increasing percentages of cash distributions as QELP’s per-unit cash distributions increase. In addition, Quest maintains control over the assets owned by QELP through sole indirect ownership of the general partner interests. Net proceeds from the offering were used to refinance a portion of the existing debt secured by the assets contributed to QELP.

The QELP common units have preference over the subordinated units with respect to cash distributions. Accordingly, all proceeds from the sale of the common units were recorded as minority interest on the consolidated balance sheet. The subordinated units will convert into an equal number of common units upon termination of the subordination period. Generally, the subordination period will end when either:

(i) QELP has paid at least $0.40 per quarter on each outstanding common unit, subordinated unit and general partner unit for any three consecutive non-overlapping four-quarter periods ending on or after December 31, 2012; or

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QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(ii) QELP has paid at least $0.50 per quarter on each outstanding common unit, subordinated unit and general partner unit for any two consecutive non-overlapping four-quarter periods ending on or after December 31, 2010; or

(iii) if the unitholders remove QELP’s general partner other than for cause and units held by its general partner and its affiliates are not voted in favor of such removal.

The results of operations and financial position of QELP are included in our consolidated financial statements. The portion of QELP’s results of operations that is attributable to common units held by the public (units not held by Quest) is recorded as minority interests.

Pursuant to the terms of its partnership agreement, QELP is required to pay a minimum quarterly distribution of $0.40 per unit to the extent it has sufficient cash available for distribution. During 2008, QELP paid the following distributions:


First Quarter	—	$0.41	per unit on all outstanding units
Second Quarter	—	$0.43	per unit on all outstanding units
Third Quarter	—	$0.40	per unit on only the common units and a proportionate distribution on the general partner units
Fourth Quarter	—	$0

No distributions may be made to the subordinated unitholders until minimum quarterly distributions to the common unitholders, plus any arrearages, have been made.

Quest Midstream

During 2006, QMLP was formed by Quest to own, operate, acquire and develop midstream assets. Quest transferred pipeline assets and certain associated liabilities to QMLP as a capital contribution in exchange for 4,900,000 Class B subordinated units and 35,134 Class A subordinated units, which currently represents an aggregate 35.69% limited partner interest in QMLP, as well as an 85% interest in the general partner of QMLP, which owns a 2% general partner interest and incentive distribution rights. The IDRs entitle the holder to specified increasing percentages of cash distributions as QMLP’s per-unit cash distributions increase. At the same time, QMLP issued 4,864,866 common units to private investors for net proceeds of $84.2 million ($90 million less $5.8 million for placement fees and offering costs).

In November 2007, QMLP completed the purchase of the KPC Pipeline for a purchase price of approximately $133 million in cash, subject to adjustment for working capital at closing, and assumed liabilities of approximately $1.2 million. In connection with this acquisition, QMLP issued 3,750,000 common units to private investors for approximately $75 million of gross proceeds ($73.6 million after offering costs). As a result of these two issuances, private investors currently own an approximate 62.31% limited partner interest in QMLP. Quest maintains control over the assets owned by QMLP through its majority ownership interest in QMLP’s general partner.

The QMLP common units have preference over the subordinated units with respect to cash distributions. Accordingly, all proceeds from the sale of the common units were recorded as minority interest on the consolidated balance sheet. The subordinated units will convert into an equal number of common units upon termination of the subordination period. Generally, the subordination period will end when either:

(i) QMLP has paid at least $0.425 per quarter on each outstanding common unit, subordinated unit and general partner unit for any three consecutive non-overlapping four quarter periods ending on or after December 22, 2013; or

(ii) if the QMLP unitholders remove its general partner other than for cause and units held by the general partner and its affiliates are not voted in favor of such removal.

F-36

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The results of operations and financial position of QMLP are included in our consolidated financial statements. The portion of QMLP’s results of operations that is attributable to common units held by the private investors (units we do not hold) is recorded as minority interests.

Pursuant to the terms of its partnership agreement, QMLP is required to pay a minimum quarterly distribution to the common unitholders of $0.425 per unit to the extent it has sufficient cash available for distribution. During 2008, QMLP paid the following distributions:


First Quarter	—	$0.425	per unit on only the common units and a proportionate distribution on the general partner units
Second Quarter	—	$0.425	per unit on only the common units and a proportionate distribution on the general partner units
Third Quarter	—	$0
Fourth Quarter	—	$0

No distribution may be made to the subordinated unitholders until minimum quarterly distributions to the common unitholders, plus any arrearages, have been made.

Note 7 — Derivative Financial Instruments

We are exposed to commodity price and interest rate risk, and management believes it prudent to periodically reduce our exposure to cash-flow variability resulting from this volatility. Accordingly, we enter into certain derivative financial instruments in order to manage exposure to commodity price risk inherent in the Company’s oil and gas production operations. Specifically, we utilize futures, swaps and options. Futures contracts and commodity swap agreements are used to fix the price of expected future oil and gas sales at major industry trading locations, such as Henry Hub, Louisiana for gas and Cushing, Oklahoma for oil. Basis swaps are used to fix or float the price differential between the price of gas at Henry Hub and various other market locations. Options are used to fix a floor and a ceiling price (collar) for expected future oil and gas sales. Derivative financial instruments are also used to manage commodity price risk inherent in customer pricing requirements and to fix margins on the future sale of natural gas. Interest rate swaps are used to fix or float interest rates attributable to the Company’s existing or anticipated indebtedness.

Settlements of any exchange-traded contracts are guaranteed by the New York Mercantile Exchange (NYMEX) or the Intercontinental Exchange and are subject to nominal credit risk. Over-the-counter traded swaps, options and physical delivery contracts expose us to credit risk to the extent the counterparty is unable to satisfy its settlement commitment. We monitor the creditworthiness of each counterparty and assess the impact, if any, on fair value. In addition, we routinely exercise our contractual right to net realized gains against realized losses when settling with our swap and option counterparties.

Interest Rate Derivatives In the past, the Company has entered into interest rate derivatives to mitigate its exposure to fluctuations in interest rates on variable rate debt. These instruments were not designated as hedges and, therefore, were recorded in the consolidated balance sheet at fair value with changes in fair value recognized in earnings as they occurred.

Commodity Derivatives At December 31, 2008, 2007 and 2006, QELP was a party to derivative financial instruments in order to manage commodity price risk associated with a portion of our expected future sales of our oil and gas production. None of these 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.

F-37

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Gains and losses associated with derivative financial instruments related to gas and oil production were as follows for the years ended December 31, 2008, 2007, 2006 and 2005 (in thousands):


	2008		2007			2006			2005

Realized gains (losses)	$	8,174	$	7,279		$	(17,712	)	$	(26,964	)
Unrealized gains (losses)		72,533		(5,318	)		70,402			(46,602	)

Total	$	80,707	$	1,961		$	52,690		$	(73,566	)

The following tables summarize the estimated volumes, fixed prices and fair value attributable to oil and gas derivative contracts as of December 31, 2008:


	Year Ending December 31,
	2009		2010		2011		Thereafter		Total
	($ in thousands, except volumes and per unit data)

Natural Gas Swaps:
Contract volumes (Mmbtu)		14,629,200		12,499,060		2,000,004		2,000,004		31,128,268
Weighted-average fixed price per Mmbtu	$	7.78	$	7.42	$	8.00	$	8.11	$	7.67
Fair value, net	$	38,107	$	14,071	$	2,441	$	2,335	$	56,954
Natural Gas Collars:
Contract volumes (Mmbtu):
Floor		750,000		630,000		3,549,996		3,000,000		7,929,996
Ceiling		750,000		630,000		3,549,996		3,000,000		7,929,996
Weighted-average fixed price per Mmbtu:
Floor	$	11.00	$	10.00	$	7.39	$	7.03	$	7.79
Ceiling	$	15.00	$	13.11	$	9.88	$	7.39	$	9.52
Fair value, net	$	3,630	$	1,875	$	3,144	$	2,074	$	10,723
Total Natural Gas Contracts:
Contract volumes (Mmbtu)		15,379,200		13,129,060		5,550,000		5,000,004		39,058,264
Weighted-average fixed price per Mmbtu	$	7.94	$	7.55	$	7.61	$	7.44	$	7.70
Fair value, net	$	41,737	$	15,946	$	5,585	$	4,409	$	67,677

Crude Oil Swaps:
Contract volumes (Bbl)		36,000		30,000		—		—		66,000
Weighted-average fixed per Bbl	$	90.07	$	87.50	$	—	$	—	$	88.90
Fair value, net	$	1,246	$	666	$	—	$	—	$	1,912

F-38

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following tables summarize the estimated volumes, fixed prices and fair value attributable to gas derivative contracts as of December 31, 2007:


	Year Ending
	December 31,
	2008			2009		2010			Thereafter		Total
	($ in thousands, except volumes and per unit data)

Natural Gas Swaps:
Contract volumes (Mmbtu)		8,595,876			12,629,365		10,499,225			—		31,724,466
Weighted-average fixed price per Mmbtu	$	6.39		$	7.70	$	7.31		$	—	$	7.22
Fair value, net	$	1,517		$	1,721	$	(4,565	)	$	—	$	(1,327	)
Natural Gas Collars:
Contract volumes (Mmbtu):
Floor		7,027,566			—		—			—		7,027,566
Ceiling		7,027,566			—		—			—		7,027,566
Weighted-average fixed price per Mmbtu:
Floor	$	6.54		$	—	$	—		$	—	$	6.54
Ceiling	$	7.53		$	—	$	—		$	—	$	7.53
Fair value, net	$	(1,617	)	$	—	$	—		$	—	$	(1,617	)
Total Natural Gas Contracts:
Contract volumes (Mmbtu)		15,623,442			12,629,365		10,499,225			—		38,752,032
Weighted-average fixed price per Mmbtu	$	6.46		$	7.70	$	7.31		$	—	$	7.09
Fair value, net	$	(100	)	$	1,721	$	(4,565	)	$	—	$	(2,944	)

F-39

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following tables summarize the estimated volumes, fixed prices and fair value attributable to natural gas derivative contracts as of December 31, 2006:


	Year Ending
	December 31,
	2007			2008			2009		Thereafter		Total
	($ in thousands, except volumes and per unit data)

Natural Gas Swaps:
Contract volumes (Mmbtu)		2,353,885			—			—		—		2,353,885
Weighted-average fixed price per Mmbtu	$	7.20		$	—		$	—	$	—	$	7.20
Fair value, net	$	2,107		$	—		$	—	$	—	$	2,107
Natural Gas Collars:
Contract volumes (Mmbtu):
Floor		8,432,595			7,027,566			—		—		15,460,161
Ceiling		8,432,595			7,027,566			—		—		15,460,161
Weighted-average fixed price per Mmbtu:
Floor	$	6.63		$	6.54		$	—	$	—	$	6.59
Ceiling	$	7.54		$	7.53		$	—	$	—	$	7.54
Fair value, net	$	3,512		$	(2,856	)	$	—	$	—	$	656
Natural Gas Basis Swaps:
Contract volumes (Mmbtu)		1,825,000			1,464,000			—		—		3,289,000
Weighted-average fixed price	$	(1.15	)	$	(1.03	)	$	—	$	—	$	(1.10	)
Fair value, net	$	(389	)	$	—		$	—	$	—	$	(389	)
Total Natural Gas Contracts:
Contract volumes (Mmbtu)		10,786,480			7,027,566			—		—		17,814,046
Weighted-average fixed price per Mmbtu	$	6.75		$	6.54		$	—	$	—	$	6.67
Fair value, net	$	5,230		$	(2,856	)	$	—	$	—	$	2,374

Note 8 — Financial Instruments

The Company’s financial instruments include commodity derivatives, debt, cash, receivables and payables. The carrying value of the Company’s debt approximates fair value as of December 31, 2008, 2007 and 2006. The carrying amount of cash, receivables and accounts payable approximates fair value because of the short-term nature of those instruments.

Fair Value — 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 December 31, 2008 (in thousands):


									Netting and
	Level		Level			Level			Cash			Total Net Fair
At December 31, 2008	1		2			3			Collateral*			Value

Derivative financial instruments — assets	$	—	$	8,866		$	64,883		$	(4,160	)	$	69,589
Derivative financial instruments — liabilities	$	—	$	(224	)	$	(3,936	)	$	4,160		$	—

Total	$	—	$	8,642		$	60,947		$	—		$	69,589


*		Amounts represent the effect of legally enforceable master netting agreements between the Company and its counterparties and the payable or receivable for cash collateral held or placed with the same counterparties.

F-40

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Risk management assets and liabilities in the table above represent the current fair value of all open derivative positions, excluding those derivatives designated as NPNS. 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):


	Year Ended
	December 31,
	2008

Balance at beginning of year	$	3,444
Realized and unrealized gains included in earnings		68,038
Purchases, sales, issuances, and settlements		(10,535	)
Transfers into and out of Level 3		—

Balance as of December 31, 2008	$	60,947

Note 9 — Asset Retirement Obligations

The following table describes the changes to the Company’s assets retirement liability for the years ending December 31, 2008, 2007 and 2006 (in thousands):


	2008			2007			2006

Asset retirement obligations at beginning of year	$	2,938		$	1,410		$	1,150
Liabilities incurred		134			178			175
Liabilities settled		(22	)		(7	)		(7	)
Acquisition of KPC pipeline		—			1,194			—
Acquisition of PetroEdge		2,193			—			—
Accretion		388			163			92
Revisions in estimated cash flows		291			—			—

Asset retirement obligations at end of year	$	5,922		$	2,938		$	1,410

F-41

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 10 — Stockholders’ Equity

Stockholders’ Rights Plan — On May 31, 2006, the board of directors of QRCP declared a dividend distribution of one right for each share of common stock of QRCP, and the dividend was distributed on June 15, 2006. The rights are governed by a Rights Agreement, dated as of May 31, 2006, between QRCP and Computershare (formerly UMB Bank, n.a.). Pursuant to the Rights Agreement, each right entitles the registered holder to purchase from QRCP one one-thousandth of a share (“Unit”) of Series B Junior Participating Preferred Stock, $0.001 par value per share, at a purchase price of $75.00 per Unit. The rights, however, will not become exercisable unless and until, among other things, any person acquires 15% or more of the outstanding shares of common stock of QRCP. If a person acquires 15% or more of the outstanding stock of QRCP (subject to certain exceptions more fully described in the Rights Agreement), each right will entitle the holder (other than the person who acquired 15% or more of the outstanding common stock) to purchase common stock of QRCP having a value equal to twice the exercise price of a right. The rights are redeemable under certain circumstances at $0.001 per right and will expire, unless earlier redeemed, on May 31, 2016.

Stock Awards — Under the 2005 Omnibus Stock Award Plan (as amended) (the “Plan”) there are available for issuance 2,700,000 shares of QRCP’s Common Stock. The Shares that have been granted are subject to pro rata vesting which ranges from 0 to 4 years. During this vesting period, the fair value of the stock awards granted is recognized pro rata as compensation expense in general and administrative expenses. For the years ended December 31, 2008, 2007, 2006 and 2005, QRCP recognized $1.9 million, $6.1 million, $1.0 million and $1.2 million, of compensation expense related to stock awards. A summary of changes in the non-vested restricted shares for the years ending December 31, 2008, 2007 and 2006 is presented below:


				Weighted
	Number of			average
	non-vested			grant-date
	restricted shares			fair value

Non-vested restricted shares at December 31, 2005		108,000		$	10.00
Granted		75,000			8.95
Vested		(62,000	)		11.73
Forfeited		(4,000	)		10.00

Non-vested restricted shares at December 31, 2006		117,000		$	9.43
Granted		1,192,968			8.71
Vested		(222,472	)		9.21
Forfeited		(5,621	)		8.67

Non-vested restricted shares at December 31, 2007		1,081,875		$	8.69
Granted(a)		405,362	(a)		7.50
Vested		(470,912	)		8.28
Forfeited		(533,949	)		8.75

Non-vested restricted shares at December 31, 2008		482,376		$	8.01


(a)	Includes 140,000 stock options converted to 70,000 restricted shares during the year.

As of December 31, 2008, total unrecognized stock-based compensation expense related to non-vested restricted shares was $1.6 million, which is expected to be recognized over a weighted average period of approximately 1.28 years.

Stock Options — The Plan also provides for the granting of options to purchase shares of QRCP’s common stock. QRCP has granted stock options to employees and non-employees under the Plan. The options expire 10 years following the date of grant and have a weighted average remaining life of 8.78 years.

F-42

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A summary of changes in stock options outstanding during the years ending December 31, 2008, 2007, and 2006 is presented below:


				Weighted average
	Stock			exercise price per
	options			share

Options outstanding at December 31, 2004		—		$	—
Granted		250,000			10.00
Exercised		—			—
Forfeited		—			—

Options outstanding at December 31, 2005		250,000			10.00

Granted		—			—
Exercised		—			—
Forfeited		(100,000	)		10.00

Options outstanding at December 31, 2006		150,000			10.00

Granted		100,000			10.05
Exercised		—			—
Forfeited		—			—

Options outstanding at December 31, 2007		250,000			10.00

Granted		300,000			0.63
Exercised		(10,000	)		10.05
Converted		(140,000	)		10.03

Options outstanding at December 31, 2008		400,000			2.98

Options exercisable at December 31, 2008		250,000		$	4.38

The weighted average grant date fair value of stock options granted during 2008, 2007 and 2005 were $0.54, $7.96, and $7.40, respectively.

The weighted average remaining term of options outstanding and options exercisable at December 31, 2008 was 9.10 and 8.68 years, respectively. Options outstanding and options exercisable at December 31, 2008 had no aggregate intrinsic value.

QRCP determines the fair value of stock option awards using the Black-Scholes option pricing model. The expected life of the option is estimated based upon historical exercise behavior. The expected forfeiture rate was estimated based upon historical forfeiture experience. The volatility assumption was estimated based upon expectations of volatility over the life of the option as measured by historical and implied volatility. The risk-free interest rate was based on the U.S. Treasury rate for a term commensurate with the expected life of the option. The dividend yield was based upon a 12-month average dividend yield. QRCP used the following weighted-average

F-43

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

assumptions to estimate the fair value of stock options granted during the years ending December 31, 2008, 2007 and 2005:


	2008	2007	2005

Expected option life — years	10	10	10
Volatility	69.8%	61.1%	59.6%
Risk-free interest rate	5.42%	5.35%	5.32%
Dividend yield	—	—	—
Fair value	$0.41-$0.61	$7.96	$7.40

For the years ended December 31, 2008, 2007, 2006 and 2005, we recognized $0.2 million, $0.5 million, $0.2 million and $0.5 million of compensation expense related to stock options. As of December 31, 2008, there was $0.2 million of total unrecognized compensation cost related to stock options, which is expected to be recognized over a weighted average period of 1.38 years.

During 2008, we converted 140,000 stock options held by certain directors into 70,000 shares of unvested restricted stock. As a result, we recognized additional compensation expense of $0.1 million for the year ended December 31, 2008.

Earnings (Loss) per Share — A reconciliation of the numerator and denominator used in the basic and diluted per share calculations for the years ending December 31, 2008, 2007, 2006 and 2005, is as follows (in thousands):


	2008			2007			2006		2005

Basic earnings per share:
Net income (loss) available to common shareholders	$	(167,384	)	$	(44,154	)	$	29,508	$	(95,885	)
Shares:
Weighted average number of common shares outstanding		27,011			22,379			22,119		8,352

Basic earnings (loss) per share:
Total basic earnings (loss) per share	$	(6.20	)	$	(1.97	)	$	1.33	$	(11.48	)

Diluted earnings per share:
Net income (loss) available to common shareholders	$	(167,384	)	$	(44,154	)	$	29,508	$	(95,885	)
Shares:
Weighted average common shares and common stock equivalents		27,011			22,379			22,130		8,352

Diluted earnings (loss) per share:
Total diluted earnings (loss) per share	$	(6.20	)	$	(1.97	)	$	1.33	$	(11.48	)

Because we have reported a net loss in the years ended December 31, 2008, 2007 and 2005, restricted stock awards covering 871,344; 781,540; and 25,545 common shares, respectively, and the effect of outstanding options to purchase 193,288; 188,082; and 54,110 common shares, respectively, were excluded from the computation of net loss per share because their effect would have been antidilutive.

F-44

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 11 — Income Taxes

Because we have recorded a full valuation allowance against our net deferred tax assets, federal and state income tax expense, both current and deferred, was zero for the years ended December 31, 2008, 2007, 2006 and 2005.

A reconciliation of federal income taxes at the statutory federal rates to our actual provision for income taxes for the years ended December 31, 2008, 2007, 2006 and 2005 are as follows (in thousands):


	2008			2007			2006			2005

Income tax expense (benefit) at statutory rate	$	(58,584	)	$	(15,454	)	$	10,328		$	(33,556	)
State income tax expense (benefit), net of federal		(3,789	)		(956	)		620			(2,341	)
Carryover depletion in excess of cost		—			—			(736	)		(525	)
Other		300			752			(51	)		(1,941	)
Change in valuation allowance		62,073			15,658			(10,161	)		38,363

Total tax expense (benefit)	$	—		$	—		$	—		$	—

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax reporting. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred assets will not be realized based on the weight of all available evidence. Based on the negative evidence that existed as of each reporting period, we recorded a full valuation allowance against our net deferred tax asset as of December 31, 2008, 2007, 2006 and 2005.

Deferred tax assets and liabilities as of December 31, 2008, 2007, 2006 and 2005 were as follows (in thousands):


	2008		2007		2006		2005

Current deferred income tax assets:
Commodity derivative expense recorded for book, not for tax	$	—	$	—	$	3,310	$	15,765
Accrued liabilities		219		749				117
Allowance for bad debts		78		79		70		53
Unearned revenue		236		111		167		75

Total current deferred income tax assets		533		939		3,547		16,010

Noncurrent deferred income tax assets:
Commodity derivative expense recorded for books, not for tax		—		—		4,055		9,809
Accrued liabilities		—		—		526		429
Partnership basis differences		7,401		—		—		—
Property and equipment basis differences		18,434		—		—		—
Net operating loss carryforwards		72,635		61,577		38,239		22,314
Other tax credit carryforwards		4,352		2,164		2,164		1,379
Misappropriation of assets		3,728		3,728		2,982		746
Other expense recorded for books, not for tax		1,320		1,997		494		334

Total noncurrent deferred income tax assets		107,870		69,466		48,460		35,011

Total deferred income tax assets		108,403		70,405		52,007		51,021

F-45

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	2008			2007			2006			2005

Current deferred income tax liabilities:
Commodity derivative income recorded for books, not for tax		—			—			(5,259	)		(18	)
Other		—			—			(539	)

Total current deferred income tax liabilities		—			—			(5,798	)		(18	)

Noncurrent deferred income tax liabilities:
Commodity derivative income recorded for books, not for tax		—			—			(2,990	)		(198	)
Partnership basis differences		—			(21,542	)		(4,790	)		—
Property and equipment basis differences		—			(2,533	)		(7,757	)		(9,973	)

Total noncurrent deferred income tax liabilities		—			(24,075	)		(15,537	)		(10,171	)

Total deferred income tax liabilities		—			(24,075	)		(21,335	)		(10,189	)

Net deferred income tax assets		108,403			46,330			30,672			40,832
Valuation allowance		(108,403	)		(46,330	)		(30,672	)		(40,832	)

Total deferred tax asset (liability)	$	—		$	—		$	—		$	—

We have net operating loss (“NOL”) carryforwards of approximately $195 million at December 31, 2008 that are available to reduce future U.S. taxable income. If not utilized, such carryforwards will expire from 2021 through 2026.

Our ability to utilize NOL carryforwards to reduce future federal taxable income and federal income tax of the Company is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the issuance or exercise of rights to acquire stock, the purchase or sale of stock by 5% stockholders, as defined in the Treasury regulations, and the offering of stock of the QRCP during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of QRCP.

QRCP completed a private placement of its common stock on November 14, 2005. In connection with this offering, 15,258,144 shares of common stock were issued. This issuance may constitute an “owner shift” as defined in the Regulations under 1.382-2T. This event will subject approximately $40 million of NOL’s to limitations under Section 382 of the Code. The current annual limitation on NOL’s incurred prior to the owner shift is expected to be approximately $4 million. NOL’s incurred after November 14, 2005 through December 31, 2008 are not currently limited.

FIN 48 provides guidance for recognizing and measuring uncertain tax positions. We file income tax returns in the U.S. federal jurisdiction and various state and local jurisdictions. Tax years 2001 to present remain open for the majority of taxing authorities due to NOL utilization. Our policy is to recognize interest and penalties, if any, related to unrecognized tax benefits as income tax expense. We have no amounts recorded for unrecognized tax benefits.

Note 12 — Commitments and Contingencies

Litigation — We are subject, from time to time, to certain legal proceedings and claims in the ordinary course of conducting our business. We record a liability related to our legal proceedings and claims when we have determined that it is probable that we will be obligated to pay and the related amount can be reasonably estimated. Except for those legal proceedings listed below, we believe there are no pending legal proceedings in which we are currently involved which, if adversely determined, could have a material adverse effect on our financial position,

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QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

results of operations or cash flow. We intend to defend vigorously against the claims described below. We are unable to predict the outcome of these proceedings or reasonably estimate a range of possible loss that may result.

Federal Securities Class Actions

Federal Derivative Case

F-47

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

of corporate assets, and unjust enrichment. The complaint seeks disgorgement, costs, expenses, and equitable and/or injunctive relief. On October 16, 2008, the court stayed this case pending the court’s ruling on any motions to dismiss the class action claims. The Company intends to defend vigorously against these claims.

State Court Derivative Cases

Royalty Owner Class Action

Hugo Spieker, et al. v. Quest Cherokee, LLC Case No. 07-1225-MLB in the U.S. District Court, District of Kansas, filed August 6, 2007

F-48

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Personal Injury Litigation

Segundo Francisco Trigoso and Dana Jara De Trigoso v. Quest Cherokee Oilfield Service, LLC, CJ-2007-11079, in the District Court of Oklahoma County, State of Oklahoma, filed December 27, 2007

St. Paul Surplus Lines Insurance Company v. Quest Cherokee Oilfield Service, LLC, et al, CJ-2009-1078, in the District Court of Tulsa County, State of Oklahoma, filed February 11, 2009

Environmental Matters — As of December 31, 2008, there were no known environmental or regulatory matters related to our operations which are reasonably expected to result in a material liability to us. Like other oil and gas producers and marketers, our 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.

Operating Lease Commitments — We have a leasing agreement for pipeline capacity that includes renewal options and options to increase capacity, which would also increase rentals. The initial term of this lease began June 1, 1992 and ends October 31, 2009.

We have lease agreements to obtain natural gas compressors as and when required. Terms of the leases on the gas compressors call for a minimum obligation of one year and are month to month thereafter.

In addition, we have operating leases for office space, warehouse facilities and office equipment expiring in various years through 2017.

Future minimum rental payments under all non-cancelable operating leases as of December 31, 2008, were as follows (in thousands):


Year ending December 31,
2009	$	4,050
2010		1,553
2011		1,524
2012		1,240
2013		1,085
Thereafter		2,690

Total minimum lease obligations	$	12,142

Total rental expense under operating leases was approximately $17.2 million, $10.3 million, $7.4 million, and $5.6 million for the years ended December 31, 2008, 2007, 2006 and 2005, respectively. Included in 2008 are $3.1 million of expenses for the pipeline capacity lease discussed above.

F-49

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Financial Advisor Contracts — In October 2008, Quest Midstream GP engaged a financial advisor in connection with the review of Quest Midstream’s strategic alternatives. Under the terms of the agreement, the financial advisor received an advisory fee of $250,000 in October 2008 and is entitled to additional monthly advisory fees of $75,000 from December 2008 through September 2009, that is due ($750 thousand in arrearages) on October 1, 2009. In addition, the financial advisor is entitled to fees ranging from $2.0 million to $4.0 million, reduced by 50% of the advisory fees previously paid by Quest Midstream, depending on whether or not certain transactions occur. During 2008, the Company recorded $0.3 million of expense relating to this agreement.

In October 2008, QRCP engaged a financial advisor with respect to a review of it’s strategic alternatives. Under the terms of the agreement, the financial advisor receives a monthly retention fee of $150,000 per month. In addition, the financial advisor is entitled to fees, which are not currently estimable, if certain transactions occur. During 2008, QRCP recorded $0.3 million of expense relating to this agreement.

In January 2009, Quest Energy GP engaged a financial advisor to QELP in connection with the review of QELP’s strategic alternatives. Under the terms of the agreement, the financial advisor received a one-time advisory fee of $50,000 in January 2009 and is entitled to additional monthly advisory fees of $25,000 for a minimum period of six months payable on the last day of the month beginning January 31, 2009. In addition, the financial advisor is entitled to fees, which are not currently estimable, if certain transactions occur.

Note 13 — Other Assets

Intangible Assets — Balances for the contract-related intangibles acquired in the KPC Pipeline acquisition were as follows as of December 31, 2008 (in thousands):


Gross carrying amount	$	9,934
Accumulated amortization		4,340

Net carrying amount	$	5,594

These intangibles are recorded in Other Assets and are being amortized over the term of the related contracts, which range from one to ten years. Amortization expense in 2008 amounted to $4.3 million. Projected amortization expense over the next five years is expected to be $3.8 million, $0.5 million, $0.5 million, $0.5 million and $0.5 million. The weighted average amortization period is 2.4 years.

Deferred Financing Costs — The remaining unamortized deferred financing costs at December 31, 2008, 2007 and 2006 were $8.1 million, $8.5 million and $9.5 million, respectively, and are being amortized over the life of the related credit facilities. In November 2007, the credit facilities with Guggenheim Corporate Funding, LLC were repaid, resulting in a charge of $9.0 million in unamortized loan fees and $4.1 million in prepayment penalties which are included with interest expense in 2007.

Deposits — The balance of long-term deposits at December 31, 2008 and 2006 was $1.3 million and $0.2 million, respectively. There were no long-term deposits at December 31, 2007.

Note 14 — Supplemental Cash Flow Information


	Year Ended December 31,
	2008		2007		2006		2005
	(in thousands)

Cash paid for interest	$	21,813	$	32,884	$	20,940	$	10,315
Cash paid for income taxes	$	—	$	—	$	—	$	—

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QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	As of December 31,
	2008		2007		2006		2005
	(in thousands)

Accrued purchases of property and equipment	$	1,492	$	861	$	1,305	$	328
Accrued distributions — QMP	$	—	$	3,600	$	—	$	—
Accrued distributions — QEP	$	—	$	—	$	—	$	—

Note 15 — Related Party Transactions

During the years ended December 31, 2005, 2006 and 2007, our former chief executive officer, Mr. Jerry D. Cash made certain unauthorized transfers, repayments and re-transfers of funds totaling $2.0 million, $6.0 million and $2.0 million, respectively, to entities that he controlled.

The Oklahoma Department of Securities has filed a lawsuit alleging that our former chief financial officer, Mr. David Grose, and our former purchasing manager, Mr. Brent Mueller, stole approximately $1.0 million. In addition to this theft, the Oklahoma Department of Securities has also filed a lawsuit alleging that our former chief financial officer and former purchasing manager received kickbacks totaling approximately $1.8 million ($0.9 million each) from several related suppliers beginning in 2005.

Note 16 — Operating Segments

We divide our operations into two reportable business segments:


	•	Oil and gas production; and

	•	Natural gas pipelines, including transporting, selling, gathering, treating and processing natural gas.

Both of these segments are exclusively located in the continental United States, and each segment uses the same accounting policies as those described in the summary of significant accounting policies (see Note 2 — Summary of Significant Accounting Policies). 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. We do not allocate income taxes to our operating segments.

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QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Operating segment data for the periods indicated is as follows (in thousands):


	Years Ended December 31,
	2008			2007			2006			2005

Revenues:
Oil and gas production	$	147,937		$	105,285		$	72,410		$	70,628
Natural gas pipelines		63,722			39,032			25,833			11,732
Elimination of inter-segment revenue		(35,546	)		(29,179	)		(20,819	)		(7,793	)

Natural gas pipelines, net of inter-segment revenue		28,176			9,853			5,014			3,939

Total segment revenues	$	176,113		$	115,138		$	77,424		$	74,567

Operating profit (loss):
Oil and gas production	$	(284,244	)	$	5,999		$	1,861		$	23,508
Natural gas pipelines		17,198			11,964			10,063			2,580

Total segment operating profit		(267,046	)		17,963			11,924			26,088
General and administrative expenses		(28,269	)		(21,023	)		(8,655	)		(6,218	)
Loss on misappropriation of funds		—			(2,000	)		(6,000	)		(2,000	)

Total operating income (loss)	$	(295,315	)	$	(5,060	)	$	(2,731	)	$	17,870

Interest expense, net		(25,373	)		(43,628	)		(20,567	)		(28,225	)
Gain (loss) from derivative financial instruments		80,707			1,961			52,690			(73,566	)
Loss on early extinguishment of debt		—			—			—			(12,355	)
Other income (expense) and sale of assets		329			(331	)		102			401

Income (loss) before income taxes and minority interests	$	(239,652	)	$	(47,058	)	$	29,494		$	(95,875	)

Capital expenditures:
Oil and gas production	$	239,467		$	91,265		$	98,591		$	32,636
Natural gas pipelines		27,649			173,604			60,080			9,279

Total capital expenditures	$	267,116		$	264,869		$	158,671		$	41,915

Depreciation, depletion and amortization
Oil and gas production	$	53,663		$	33,812		$	24,392		$	20,795
Natural gas pipelines		16,782			5,970			2,619			1,449

Total depreciation, depletion and amortization	$	70,445		$	39,782		$	27,011		$	22,244


	As of December 31,
	2008		2007		2006

Identifiable assets:
Oil and gas production	$	193,195	$	320,880	$	257,800
Natural gas pipelines		313,644		296,104		126,812

Total identifiable assets	$	506,839	$	616,984	$	384,612

Segment operating profit represents total revenues less costs and expenses attributable thereto, excluding interest and general corporate expenses.

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QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 17 — Profit Sharing Plan

Substantially all of our employees are covered by our profit sharing plan under Section 401(k) of the Internal Revenue Code. Eligible employees may make contributions to the plan by electing to defer some of their compensation. Our match is discretionary; however, historically we have matched 100% of total contributions up to a total of five percent of their annual compensation. Our matching contribution vests using a graduated vesting schedule over six years of service. During the years ended December 31, 2008, 2007, 2006 and 2005, we made cash contributions to the plan of $0.6 million, $0.6 million, $0.4 million and $0.4 million, respectively.

During 2005, we contributed 49,842 shares of Quest common stock to the plan. This profit sharing contribution related to the year ended December 31, 2004 and was valued at $0.5 million. Expense related to this contribution was recorded in general and administrative expenses.

Note 18 — Restatement

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-K for the year ended December 31, 2008, to which these consolidated financial statements form a part, includes restated and reaudited consolidated financial statements for QRCP as of December 31, 2007 and 2006 and for the years ended December 31, 2007, 2006 and 2005. After filing the Form 10-K, QRCP will subsequently file amended Quarterly Reports on Form 10-Q/A including restated quarterly consolidated financial statements for the quarters ended March 31, 2008 and June 30, 2008 and a Quarterly Report on Form 10-Q for the quarter ended September 30, 2008.

As a result of the Transfers, the restated consolidated financial statements show a reduction of $10 million in cash balances of QRCP for periods ended on and after December 31, 2007 and an increase in accumulated deficit for periods ended on and after December 31, 2007 of $10 million. The Transfers began in June of 2004 and continued through July 1, 2008, but as a result of certain repayments and the amounts involved, the cash balance and accumulated deficit as reported on QRCP’s consolidated balance sheet as of December 31, 2004 were not materially inaccurate as a result of the Transfers made prior to that date.

F-53

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Although the items listed below comprise the most significant errors (by dollar amount), numerous other errors were identified and restatement adjustments made. We have recorded restatement adjustments to properly reflect the amounts as of and for the periods affected, including the amounts included in Note 20 — Supplemental Financial Information — Quarterly Financial Data (Unaudited). The tables below present previously reported stockholders’ equity, major restatement adjustments and restated stockholders’ (deficit) equity as well as previously reported net income (loss), major restatement adjustments and restated net income (loss) as of and for the periods indicated (in thousands):


	As of December 31,
	2007			2006			2005

Stockholders’ (deficit) equity as previously reported	$	91,853		$	117,354		$	115,673
A — Effect of the Transfers		(10,000	)		(8,000	)		(2,000	)
B — Reversal of hedge accounting		707			(2,389	)		(8,177	)
C — Accounting for formation of Quest Cherokee		(19,055	)		(19,159	)		(19,185	)
D — Capitalization of costs in full cost pool		(23,936	)		(12,748	)		(5,388	)
E — Recognition of costs in proper periods		(1,987	)		(321	)		(316	)
F — Capitalized interest		1,713			1,367			286
G — Stock-based compensation		—			—			—
H — Depreciation, depletion and amortization		10,450			7,209			3,275
I — Impairment of oil and gas properties		30,719			30,719			—
J — Other errors		(3,695	)		809			(383	)

Stockholders’ (deficit) equity as restated	$	76,769		$	114,841		$	83,785


	Years Ended December 31,
	2007			2006			2005

Net income (loss) as previously reported	$	(30,414	)	$	(48,478	)	$	(31,951	)
A — Effect of the Transfers		(2,000	)		(6,000	)		(2,000	)
B — Reversal of hedge accounting		1,183			53,387			(42,854	)
C — Accounting for formation of Quest Cherokee		104			26			(14,402	)
D — Capitalization of costs in full cost pool		(11,188	)		(7,360	)		(5,388	)
E — Recognition of costs in proper periods		(1,666	)		(5	)		721
F — Capitalized interest		346			1,081			154
G — Stock-based compensation		(702	)		405			(790	)
H — Depreciation, depletion and amortization		3,241			3,934			757
I — Impairment of oil and gas properties		—			30,719			—
J — Other errors		(3,058	)		1,799			(132	)

Net income (loss) as restated	$	(44,154	)	$	29,508		$	(95,885	)

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 December 31, 2007, 2006 and 2005, and loss from misappropriation of funds was understated for the years ended December 31, 2007, 2006 and 2005.

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QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(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 over/(under) stated by $(2.6) million, $0.5 million and $6.3 million as of December 31, 2007, 2006 and 2005, respectively. 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 December 31, 2007, 2006 and 2005, and oil and gas sales and gain (loss) from derivative financial instruments were over/(under)stated for the years ended December 31, 2007, 2006 and 2005.

(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 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 December 31, 2007, 2006 and 2005, and oil and gas production expenses and general and administrative expenses were over/(under)stated for the years ended December 31, 2007, 2006 and 2005.

(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 December 31, 2007, 2006 and 2005, and oil and gas production expenses, pipeline operating expenses and general and administrative expenses were over/(under)stated for the years ended December 31, 2007, 2006 and 2005.

(F) Capitalized interest was not recorded on pipeline construction. As a result of this error, pipeline assets and accumulated deficit were understated as of December 31, 2007, 2006 and 2005, interest expense was overstated for the years ended December 31, 2007, 2006 and 2005.

(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 December 31, 2007, 2006 and 2005, and general and administrative expenses were over/(under)stated for the years ended December 31, 2007, 2006 and 2005.

(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 December 31, 2007, 2006 and 2005 and depreciation, depletion and amortization expense was over/(under)stated for the years ended December 31, 2007, 2006 and 2005.

(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,

F-55

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 reaudit and 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 incorrectly 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 amount (in thousands):


	As of December 31,
	2007		2006		2005

Previously reported issued shares		22,701		22,206		22,072
Total restatement adjustments		852		160		140

Restated issued shares		23,553		22,366		22,212


	As of December 31,
	2007			2006		2005

Previously reported outstanding shares		22,701			22,206		22,072
Total restatement adjustments		(230	)		43		32

Restated outstanding shares		22,471			22,249		22,104

F-56

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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):


	Year Ended December 31, 2007
	As Previously			Restatement			As
	Reported			Adjustments			Restated

Revenues:
Oil and gas sales	$	113,035		$	(7,750	)	$	105,285
Gas pipeline revenue		9,853			—			9,853
Other revenue (expense)		(9	)		9			—

Total revenues		122,879			(7,741	)		115,138
Costs and expenses:
Oil and gas production		27,995			8,300			36,295
Pipeline operating		21,079			19			21,098
General and administrative expenses		17,976			3,047			21,023
Depreciation, depletion and amortization		41,401			(1,619	)		39,782
Impairment of oil and gas properties		—			—			—
Loss from misappropriation of funds		—			2,000			2,000

Total costs and expenses		108,451			11,747			120,198

Operating income (loss)		14,428			(19,488	)		(5,060	)
Other income (expense):
Gain (loss) from derivative financial instruments		(6,502	)		8,463			1,961
Gain (loss) on sale of assets		(322	)		—			(322	)
Loss on early extinguishment of debt		—			—			—
Other income		—			(9	)		(9	)
Interest expense		(42,916	)		(1,128	)		(44,044	)
Interest income		416			—			416

Total other income (expense)		(49,324	)		7,326			(41,998	)

Income (loss) before income taxes and minority interests		(34,896	)		(12,162	)		(47,058	)
Income tax benefit (expense)		—			—			—

Net income (loss) before minority interests		(34,896	)		(12,162	)		(47,058	)
Minority interests		4,482			(1,578	)		2,904

Net income (loss)	$	(30,414	)	$	(13,740	)	$	(44,154	)

Income (loss) per common share:
Basic	$	(1.37	)	$	(0.60	)	$	(1.97	)
Diluted	$	(1.37	)	$	(0.60	)	$	(1.97	)
Weighted average common and common equivalent shares outstanding:
Basic		22,240,600			138,879			22,379,479

Diluted		22,240,600			138,879			22,379,479

F-57

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table outlines the effects of the restatement adjustments on our Consolidated Balance Sheet for the period indicated (in thousands):


	As of December 31, 2007
	As Previously			Restatement			As
	Reported			Adjustments			Restated

ASSETS
Current assets:
Cash and cash equivalents	$	16,680		$	(10,000	)	$	6,680
Restricted cash		1,236			—			1,236
Accounts receivable trade, net		15,768			(211	)		15,557
Other receivables		1,632			(152	)		1,480
Other current assets		3,717			245			3,962
Inventory		6,622			—			6,622
Current derivative financial instrument assets		6,729			1,279			8,008

Total current assets		52,384			(8,839	)		43,545
Oil and gas properties under full cost method of accounting, net		300,717			236			300,953
Pipeline assets, net		297,279			(2,753	)		294,526
Other property and equipment, net		21,394			111			21,505
Other assets, net		8,268			273			8,541
Long-term derivative financial instrument assets		1,568			1,899			3,467

Total assets	$	681,610		$	(9,073	)	$	672,537


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	27,911		$	3,291		$	31,202
Revenue payable		6,806			919			7,725
Accrued expenses		9,058			(671	)		8,387
Current portion of notes payable		666			—			666
Current derivative financial instrument liabilities		8,241			(133	)		8,108

Total current liabilities		52,682			3,406			56,088
Long-term liabilities:
Long-term derivative financial instrument liabilities		5,586			725			6,311
Asset retirement obligation		3,813			(875	)		2,938
Long-term portion of notes payable		233,046			—			233,046

Total long-term liabilities		242,445			(150	)		242,295

Minority interests		294,630			2,755			297,385
Commitments and contingencies
Stockholders’ (deficit) equity:
Preferred stock		—			—			—
Common stock		23			1			24
Additional paid-in capital		212,819			(967	)		211,852
Accumulated other comprehensive income (loss)		(1,485	)		1,485			—
Accumulated deficit		(119,504	)		(15,603	)		(135,107	)

Total stockholders’ (deficit) equity		91,853			(15,084	)		76,769

Total liabilities and stockholders’ (deficit) equity	$	681,610		$	(9,073	)	$	672,537

F-58

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table outlines the effects of the restatement adjustments on our Consolidated Statement of Cash Flows for the period indicated (in thousands):


	Years Ended December 31, 2007
	As Previously			Restatement			As
	Reported			Adjustments			Restated

Cash flows from operating activities:
Net income (loss)	$	(30,414	)		(13,740	)	$	(44,154	)
Adjustments to reconcile net income (loss) to cash provided by operations:
Depreciation, depletion and amortization		44,120			(4,338	)		39,782
Stock-based compensation		5,549			532			6,081
Stock-based compensation — Minority interests		—			1,137			1,137
Stock issued for services and retirement plan		1,262			(1,262	)		—
Amortization of deferred loan costs		4,620			6,600			11,220
Change in fair value of derivative financial instruments		6,502			(1,184	)		5,318
Amortization of gas swap fees		187			(187	)		—
Bad debt expense		—			22			22
Minority interest		(4,482	)		1,578			(2,904	)
Loss on disposal of property and equipment		—			1,363			1,363
Other		323			(323	)		—
Change in assets and liabilities:
Restricted cash		(86	)		86			—
Accounts receivable		(5,928	)		—			(5,928	)
Other receivables		(1,260	)		15			(1,245	)
Other current assets		(2,649	)		(178	)		(2,827	)
Inventory		(989	)		989			—
Other assets		—			15			15
Accounts payable		13,129			1,218			14,347
Revenue payable		2,268			468			2,736
Accrued expenses		6,560			(2,559	)		4,001
Other long-term liabilities		—			220			220
Other		—			(388	)		(388	)

Net cash provided by (used in) operating activities		38,712			(9,916	)		28,796

Cash flows from investing activities:
Restricted cash		—			(86	)		(86	)
Other assets		(8,598	)		8,598			—
Acquisition of business — KPC		—			(133,725	)		(133,725	)
Equipment, development, leasehold and pipeline		(272,270	)		133,613			(138,657	)

Net cash used in investing activities		(280,868	)		8,400			(272,468	)

Cash flows from financing activities:
Proceeds from bank borrowings		268,580			(224,000	)		44,580

F-59

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Years Ended December 31, 2007
	As Previously			Restatement			As
	Reported			Adjustments			Restated

Repayments of note borrowings		(225,441	)		—			(225,441	)
Proceeds from revolver note		—			224,000			224,000
Repayment of revolver note		(35,000	)		—			(35,000	)
Proceeds from Quest Energy		163,800			—			163,800
Proceeds from Quest MidStream		75,230			—			75,230
Syndication costs		(14,288	)		(330	)		(14,618	)
Distributions to unit holders		(5,894	)		22			(5,872	)
Proceeds from subordinated debt		—			—			—
Repayment of subordinated debt		—			—			—
Refinancing costs		(10,142	)		(5	)		(10,147	)
Change in other long-term liabilities		171			(171	)		—

Net cash provided by financing activities		217,016			(484	)		216,532

Net increase (decrease) in cash		(25,140	)		(2,000	)		(27,140	)
Cash and cash equivalents, beginning of period		41,820			(8,000	)		33,820

Cash and cash equivalents, end of period	$	16,680		$	(10,000	)	$	6,680

F-60

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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):


	Year Ended December 31, 2006
	As Previously			Restatement			As
	Reported			Adjustments			Restated

Revenues:
Oil and gas sales	$	65,551		$	6,859		$	72,410
Gas pipeline revenue		5,014			—			5,014
Other revenue (expense)		(80	)		80			—

Total revenues		70,485			6,939			77,424
Costs and expenses:
Oil and gas production		21,208			4,130			25,338
Pipeline operating		13,247			(96	)		13,151
General and administrative expenses		8,840			(185	)		8,655
Depreciation, depletion and amortization		28,025			(1,014	)		27,011
Impairment of oil and gas properties		30,719			(30,719	)		—
Loss from misappropriation of funds		—			6,000			6,000

Total costs and expenses		102,039			(21,884	)		80,155

Operating income (loss)		(31,554	)		28,823			(2,731	)
Other income (expense):
Gain (loss) from derivative financial instruments		6,410			46,280			52,690
Gain (loss) on sale of assets		3			—			3
Loss on early extinguishment of debt		—			—			—
Other income		—			99			99
Interest expense		(23,483	)		2,526			(20,957	)
Interest income		390			—			390

Total other income (expense)		(16,680	)		48,905			32,225

Income (loss) before income taxes and minority interests		(48,234	)		77,728			29,494
Income tax benefit (expense)		—			—			—

Net income (loss) before minority interests		(48,234	)		77,728			29,494
Minority interests		(244	)		258			14

Net income (loss)	$	(48,478	)	$	77,986		$	29,508

Income (loss) per common share:
Basic	$	(2.19	)	$	3.52		$	1.33
Diluted	$	(2.19	)	$	3.52		$	1.33
Weighted average common and common equivalent shares outstanding:
Basic		22,100,753			18,744			22,119,497

Diluted		22,100,753			18,744			22,129,607

F-61

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table outlines the effects of the restatement adjustments on our Consolidated Balance Sheet for the period indicated (in thousands):


	As of December 31, 2006
	As Previously			Restatement			As
	Reported			Adjustments			Restated

ASSETS
Current assets:
Cash and cash equivalents	$	41,820		$	(8,000	)	$	33,820
Restricted cash		1,150			—			1,150
Accounts receivable trade, net		9,840			(189	)		9,651
Other receivables		371			(136	)		235
Other current assets		1,068			8			1,076
Inventory		5,632			—			5,632
Current derivative financial instrument assets		10,795			3,314			14,109

Total current assets		70,676			(5,003	)		65,673
Oil and gas properties under full cost method of accounting, net		233,593			7,685			241,278
Pipeline assets, net		128,570			(1,916	)		126,654
Other property and equipment, net		16,212			468			16,680
Other assets, net		9,467			162			9,629
Long-term derivative financial instrument assets		4,782			3,240			8,022

Total assets	$	463,300		$	4,636		$	467,936


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	14,778		$	1,633		$	16,411
Revenue payable		4,540			449			4,989
Accrued expenses		2,525			(1,739	)		786
Current portion of notes payable		324			—			324
Current derivative financial instrument liabilities		5,244			3,635			8,879

Total current liabilities		27,411			3,978			31,389
Long-term liabilities:
Long-term derivative financial instrument liabilities		7,449			3,429			10,878
Asset retirement obligation		1,410			—			1,410
Long-term portion of notes payable		225,245			—			225,245

Total long-term liabilities		234,104			3,429			237,533

Minority interests		84,431			(258	)		84,173
Commitments and contingencies
Stockholders’ (deficit) equity:
Preferred stock		—			—			—
Common stock		22			—			22
Additional paid-in capital		205,994			(222	)		205,772
Accumulated other comprehensive income (loss)		428			(428	)		—
Accumulated deficit		(89,090	)		(1,863	)		(90,953	)

Total stockholders’ (deficit) equity		117,354			(2,513	)		114,841

Total liabilities and stockholders’ (deficit) equity	$	463,300		$	4,636		$	467,936

F-62

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table outlines the effects of the restatement adjustments on our Consolidated Statement of Cash Flows for the period indicated (in thousands):


	Years Ended December 31, 2006
	As Previously			Restatement			As
	Reported			Adjustments			Restated

Cash flows from operating activities:
Net income (loss)	$	(48,478	)		77,986		$	29,508
Adjustments to reconcile net income (loss) to cash provided by operations:
Depreciation, depletion and amortization		30,898			(3,887	)		27,011
Impairment of oil and gas properties		30,719			(30,719	)		—
Stock-based compensation		779			258			1,037
Stock issued for services and retirement plan		857			47			904
Amortization of deferred loan costs		1,204			865			2,069
Change in fair value of derivative financial instruments		(16,644	)		(53,758	)		(70,402	)
Amortization of gas swap fees		208			(208	)		—
Amortization of deferred hedging gains		(328	)		328			—
Bad debt expense		37			48			85
Minority interest		244			(258	)		(14	)
Other		(3	)		3			—
Change in assets and liabilities:
Restricted cash		3,167			(3,167	)		—
Accounts receivable		(219	)		823			604
Other receivables		(29	)		137			108
Other current assets		894			(34	)		860
Inventory		(37	)		37			—
Other assets		—			(819	)		(819	)
Accounts payable		2,400			150			2,550
Revenue payable		(505	)		249			(256	)
Accrued expenses		1,836			(1,699	)		137
Other long-term liabilities		—			167			167
Other		—			1,053			1,053

Net cash provided by (used in) operating activities		7,000			(12,398	)		(5,398	)

Cash flows from investing activities:
Restricted cash		—			3,168			3,168
Other assets		(5,712	)		5,712			—
Equipment, development, leasehold and pipeline		(166,905	)		(1,410	)		(168,315	)
Proceeds from sale of oil and gas properties		—			—			—

Net cash used in investing activities		(172,617	)		7,470			(165,147	)

Cash flows from financing activities:
Proceeds from bank borrowings		200,170			(75,000	)		125,170
Repayments of note borrowings		(31,339	)		30,750			(589	)

F-63

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Years Ended December 31, 2006
	As Previously			Restatement			As
	Reported			Adjustments			Restated

Proceeds from revolver note		—			75,000			75,000
Repayment of revolver note		(44,250	)		(30,750	)		(75,000	)
Proceeds from Quest MidStream		84,187			—			84,187
Refinancing costs		(4,568	)		(1	)		(4,569	)
Change in other long-term liabilities		167			(167	)		—
Equity offering costs		—			(393	)		(393	)
Proceeds from issuance of common stock		511			(511	)		—

Net cash provided by financing activities		204,878			(1,072	)		203,806

Net increase (decrease) in cash		39,261			(6,000	)		33,261
Cash and cash equivalents, beginning of period		2,559			(2,000	)		559

Cash and cash equivalents, end of period	$	41,820		$	(8,000	)	$	33,820

F-64

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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):


	Year Ended December 31, 2005
	As Previously			Restatement			As
	Reported			Adjustments			Restated

Revenue:
Oil and gas sales	$	44,565		$	26,063		$	70,628
Gas pipeline revenue		3,939			—			3,939
Other revenue (expense)		389			(389	)		—

Total revenues		48,893			25,674			74,567
Costs and expenses:
Oil and gas production		14,388			4,144			18,532
Pipeline operating		8,470			(767	)		7,703
General and administrative expenses		4,802			1,416			6,218
Depreciation, depletion and amortization		22,199			45			22,244
Impairment of oil and gas properties		—			—			—
Loss from misappropriation of funds		—			2,000			2,000

Total costs and expenses		49,859			6,838			56,697

Operating income (loss)		(966	)		18,836			17,870
Other income (expense):
Gain (loss) from derivative financial instruments		(4,668	)		(68,898	)		(73,566	)
Gain (loss) on sale of assets		12			—			12
Loss on early extinguishment of debt		—			(12,355	)		(12,355	)
Other income		—			389			389
Interest expense		(26,365	)		(1,906	)		(28,271	)
Interest income		46			—			46

Total other income (expense)		(30,975	)		(82,770	)		(113,745	)

Income (loss) before income taxes and minority interests		(31,941	)		(63,934	)		(95,875	)
Income tax benefit (expense)		—			—			—

Net income (loss) before minority interests		(31,941	)		(63,934	)		(95,875	)
Minority interests		—			—			—

Net income (loss)		(31,941	)		(63,934	)		(95,875	)
Preferred stock dividends		(10	)		—			(10	)

Net loss available to common shareholders	$	(31,951	)	$	(63,934	)	$	(95,885	)

Income (loss) available to common shareholders per common share:
Basic	$	(3.81	)	$	(7.67	)	$	(11.48	)
Diluted	$	(3.81	)	$	(7.67	)	$	(11.48	)
Weighted average common and common equivalent shares outstanding:
Basic		8,390,092			(38,147	)		8,351,945

Diluted		8,390,092			(38,147	)		8,351,945

F-65

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table outlines the effects of the restatement adjustments on our Consolidated Balance Sheet for the period indicated (in thousands):


	As of December 31, 2005
	As Previously			Restatement			As
	Reported			Adjustments			Restated

ASSETS
Current assets:
Cash and cash equivalents	$	2,559		$	(2,000	)	$	559
Restricted cash		4,318			—			4,318
Accounts receivable trade, net		9,658			682			10,340
Other receivables		343			—			343
Other current assets		1,936			—			1,936
Inventory		2,782			—			2,782
Current derivative financial instrument assets		95			(47	)		48

Total current assets		21,691			(1,365	)		20,326
Oil and gas properties under full cost method of accounting, net		183,370			(18,362	)		165,008
Pipeline assets, net		72,849			(3,796	)		69,053
Other property and equipment, net		13,490			49			13,539
Other assets, net		6,310			—			6,310
Long-term derivative financial instrument assets		93			439			532

Total assets	$	297,803		$	(23,035	)	$	274,768


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	12,381		$	1,962		$	14,343
Revenue payable		5,044			201			5,245
Accrued expenses		649			—			649
Current portion of notes payable		407			—			407
Current derivative financial instrument liabilities		38,195			4,098			42,293

Total current liabilities		56,676			6,261			62,937
Long-term liabilities:
Long-term derivative financial instrument liabilities		23,723			2,592			26,315
Asset retirement obligation		1,150			—			1,150
Long-term portion of notes payable		100,581			—			100,581

Total long-term liabilities		125,454			2,592			128,046

Minority interests		—			—			—
Commitments and contingencies Stockholders’ equity:
Preferred stock		—			—			—
Common stock		22			—			22
Additional paid-in capital		203,434			790			204,224
Accumulated other comprehensive income (loss)		(47,171	)		47,171			—
Accumulated deficit		(40,612	)		(79,849	)		(120,461	)

Total stockholders’ equity		115,673			(31,888	)		83,785

Total liabilities and stockholders’ equity	$	297,803		$	(23,035	)	$	274,768

F-66

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table outlines the effects of the restatement adjustments on our Consolidated Statement of Cash Flows for the period indicated (in thousands):


	Years Ended December 31, 2005
	As Previously			Restatement			As
	Reported			Adjustments			Restated

Cash flows from operating activities:
Net income (loss)	$	(31,941	)		(63,934	)	$	(95,875	)
Adjustments to reconcile net income (loss) to cash provided by operations:
Depreciation, depletion and amortization		22,949			(705	)		22,244
Accretion of debt discount		9,586			1,892			11,478
Stock-based compensation		352			865			1,217
Stock issued for services and retirement plan		285			274			559
Amortization of deferred loan costs		5,106			(609	)		4,497
Change in fair value of derivative financial instruments		4,668			41,934			46,602
Amortization of deferred hedging gains		(831	)		831			—
Bad debt expense		192			110			302
Loss on early extinguishment of debt		—			12,355			12,355
Other		56			(56	)		—
Change in assets and liabilities:
Restricted cash		(4,318	)		4,318			—
Accounts receivable		(3,646	)		(823	)		(4,469	)
Other receivables		181			—			181
Other current assets		(1,695	)		2			(1,693	)
Inventory		(2,499	)		2,499			—
Other assets		—			788			788
Accounts payable		(4,957	)		(9,910	)		(14,867	)
Revenue payable		1,537			(19	)		1,518
Accrued expenses		61			—			61
Other long-term liabilities		—			210			210
Other		—			116			116

Net cash provided by (used in) operating activities		(4,914	)		(9,862	)		(14,776	)

Cash flows from investing activities:
Restricted cash		—			(4,318	)		(4,318	)
Other assets		(6,071	)		6,071			—
Acquisition of minority interest — ArcLight		—			(26,100	)		(26,100	)
Equipment, development, leasehold and pipeline		(67,530	)		32,218			(35,312	)
Proceeds from sale of oil and gas properties		—			—			—

Net cash used in investing activities		(73,601	)		7,871			(65,730	)

F-67

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Years Ended December 31, 2005
	As Previously			Restatement			As
	Reported			Adjustments			Restated

Cash flows from financing activities:
Proceeds from bank borrowings		100,103			—			100,103
Repayments of note borrowings		(135,565	)		—			(135,565	)
Proceeds from subordinated debt		15,000			—			15,000
Repayment of subordinated debt		(83,912	)		—			(83,912	)
Refinancing costs		(6,272	)		(9	)		(6,281	)
Dividends paid		(10	)		—			(10	)
Proceeds from issuance of common stock		185,272			—			185,272

Net cash provided by financing activities		74,616			(9	)		74,607

Net increase (decrease) in cash		(3,899	)		(2,000	)		(5,899	)
Cash and cash equivalents, beginning of period		6,458			—			6,458

Cash and cash equivalents, end of period	$	2,559		$	(2,000	)	$	559

Note 19 — Subsequent Events

Impairment of oil and gas properties

Due to a further decline in natural gas prices, subsequent to December 31, 2008 we expect to incur an additional impairment charge on our oil and gas properties of approximately $75 million to $95 million as of March 31, 2009.

Settlement Agreements

We filed lawsuits, related to the Transfers, against Mr. Cash, the entity controlled by Mr. Cash that was used in connection with the Transfers and two former officers, who are the other owners of the controlled-entity, seeking, among other things, to recover the funds that were transferred. On May 19, 2009, we entered into settlement agreements with Mr. Cash, the controlled-entity and the other owners to settle this litigation. Under the terms of the settlement agreements, QRCP received (1) approximately $2.4 million in cash and (2) 60% of the controlled-entity’s interest in a gas well located in Louisiana and a landfill gas development project located in Texas. While QRCP estimates the value of these assets to be less than the amount of the Transfers and cost of the internal investigation, they represent substantially all of Mr. Cash’s net worth and the majority of the value of the controlled-entity. We did not take Mr. Cash’s stock in QRCP, which he had pledged to secure personal loans with a principal balance far in excess of the current market value of the stock. QELP received all of Mr. Cash’s equity interest in STP Newco, Inc. (“STP”), which owns certain oil producing properties in Oklahoma, and other assets as reimbursement for all of the costs of the internal investigation and the costs of the litigation against Mr. Cash that have been paid by QELP.

F-68

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 20 — Supplemental Financial Information — Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data for 2008 and 2007 are as follows (in thousands, except per share data):


	Quarters Ended
	December 31,			September 30,		June 30,			March 31,
	2008			2008		2008			2008
						(Restated)			(Restated)

Total revenues	$	52,819		$	41,993	$	38,510		$	42,791
Operating income (loss)(1)		(296,484	)		1,302		(4,927	)		4,796
Net income (loss)		(172,254	)		87,851		(57,886	)		(25,095	)
Net income (loss) per common share:
Basic	$	(6.38	)	$	5.10	$	(2.53	)	$	(1.11	)
Diluted	$	(6.38	)	$	5.05	$	(2.53	)	$	(1.11	)


	Quarters Ended
	December 31,			September 30,			June 30,			March 31,
	2007			2007			2007			2007
	(Restated)			(Restated)			(Restated)			(Restated)

Total revenues	$	33,620		$	25,640		$	29,362		$	26,516
Operating income (loss)(1)		(262	)		(4,189	)		(1,154	)		545
Net income (loss)		(21,206	)		492			(1,380	)		(22,060	)
Net income (loss) per common share:
Basic	$	(0.94	)	$	0.02		$	(0.06	)	$	(0.99	)
Diluted	$	(0.94	)	$	0.02		$	(0.06	)	$	(0.99	)


(1)		Total revenue less total costs and expenses.

As discussed in Note 18 — Restatement, the Company has restated its consolidated financial statements. Such restatements also impacted the Company’s consolidated financial statements as of and for the quarterly periods ended March 31 and June 30, 2008 and March 31, June 30, September 30 and December 31, 2007. See Note 18 for more detailed descriptions of the adjustments below. The adjustments to the applicable quarterly financial statement line items are presented below for the periods indicated (in thousands):

The following table outlines the effects of the restatement adjustments on our summarized unaudited quarterly financial data for the periods indicated (in thousands, except per share data):


	Quarter Ended March 31, 2008
	As Previously			Restatement			As
	Reported			Adjustments			Restated

Total revenues	$	44,304		$	(1,513	)	$	42,791
Operating income (loss)		11,215			(6,420	)		4,795
Net income (loss)		(11,643	)		(13,452	)		(25,095	)
Net income (loss) per common share:
Basic	$	(0.50	)	$	(0.61	)	$	(1.11	)
Diluted	$	(0.50	)	$	(0.61	)	$	(1.11	)

F-69

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Quarter Ended June 30, 2008
	As Previously		Restatement			As
	Reported		Adjustments			Restated

Total revenues	$	47,123	$	(8,613	)	$	38,510
Operating income (loss)		8,499		(13,426	)		(4,927	)
Net income (loss)		4,965		(62,851	)		(57,886	)
Net income (loss) per common share:
Basic	$	0.22	$	(2.75	)	$	(2.53	)
Diluted	$	0.22	$	(2.75	)	$	(2.53	)


	Quarter Ended March 31, 2007
	As Previously			Restatement			As
	Reported			Adjustments			Restated

Total revenues	$	27,078		$	(562	)	$	26,516
Operating income (loss)		4,416			(3,871	)		545
Net income (loss)		(3,311	)		(18,749	)		(22,060	)
Net income (loss) per common share:
Basic	$	(0.15	)	$	(0.84	)	$	(0.99	)
Diluted	$	(0.15	)	$	(0.84	)	$	(0.99	)


	Quarter Ended June 30, 2007
	As Previously			Restatement			As
	Reported			Adjustments			Restated

Total revenues	$	29,640		$	(278	)	$	29,362
Operating income (loss)		3,689			(4,843	)		(1,154	)
Net income (loss)		(4,487	)		3,107			(1,380	)
Net income (loss) per common share:
Basic	$	(0.20	)	$	0.14		$	(0.06	)
Diluted	$	(0.20	)	$	0.14		$	(0.06	)


	Quarter Ended September 30, 2007
	As Previously		Restatement			As
	Reported		Adjustments			Restated

Total revenues	$	30,277	$	(4,637	)	$	25,640
Operating income (loss)		5,064		(9,253	)		(4,189	)
Net income (loss)		1,974		(1,482	)		492
Net income (loss) per common share:
Basic	$	0.09	$	(0.07	)	$	0.02
Diluted	$	0.09	$	(0.07	)	$	0.02

F-70

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Quarter Ended December 31, 2007
	As Previously			Restatement			As
	Reported			Adjustments			Restated

Total revenues	$	35,884		$	(2,264	)	$	33,620
Operating income (loss)		1,259			(1,521	)		(262	)
Net income (loss)		(24,590	)		3,384			(21,206	)
Net income (loss) per common share:
Basic	$	(1.11	)	$	0.17		$	(0.94	)
Diluted	$	(1.11	)	$	0.17		$	(0.94	)

Note 21 — Supplemental Information on Oil and Gas Producing Activities (Unaudited)

The supplementary, oil and gas data that follows is presented in accordance with SFAS No. 69, Disclosures about Oil and Gas Producing Activities, and includes (1) capitalized costs, costs incurred and results of operations related to oil and gas producing activities, (2) net proved oil and gas reserves, and (3) a standardized measure of discounted future net cash flows relating to proved oil and gas reserves.

Net Capitalized Costs

The Company’s aggregate capitalized costs related to oil and gas producing activities as of the periods indicated are summarized as follows (in thousands):


	As of December 31,
	2008			2007			2006

Oil and gas properties and related leasehold costs:
Proved	$	299,629		$	380,033		$	288,646
Unproved		10,108			7,986			8,108

		309,737			388,019			296,754
Accumulated depreciation, depletion and amortization		(137,200	)		(87,066	)		(55,476	)

Net capitalized costs	$	172,537		$	300,953		$	241,278

Unproved properties not subject to amortization consisted mainly of leaseholds acquired through acquisitions. We will continue to evaluate our unproved properties; however, the timing of the ultimate evaluation and disposition of the properties has not been determined.

Costs Incurred

Costs incurred in oil and gas property acquisition, exploration and development activities that have been capitalized as of the periods indicated are summarized as follows (in thousands):


	Years December 31,
	2008			2007		2006		2005

Acquisition of proved and unproved properties	$	158,294	(a)	$	—	$	—	$	—
Exploration costs		1,273			—		—		—
Development costs		276,265			217,539		143,229		49,833

	$	435,832		$	217,539	$	143,229	$	49,833


(a)		Includes the acquisition of the PetroEdge & Seminole County, Oklahoma properties.

F-71

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Results of Operations for Oil and Gas Producing Activities

The following table includes revenues and expenses associated directly with our oil and natural gas producing activities. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our oil and natural gas operations (in thousands).


	Year Ended December 31,
	2008			2007			2006			2005
	(In thousands)

Production revenues	$	147,937		$	105,285		$	72,410		$	70,628
Production costs		(44,111	)		(36,295	)		(25,338	)		(18,532	)
Depreciation and depletion and amortization		(53,663	)		(33,812	)		(24,392	)		(20,795	)
Impairment of oil and gas properties		(298,861	)		—			—			—

		(248,698	)		35,178			22,680			31,301
Imputed income tax provision(1)		—			(13,368	)		(8,618	)		(11,894	)

Results of operations for oil and natural gas producing activity	$	(256,341	)	$	21,810		$	14,062		$	19,407


(1)		The imputed income tax provision is hypothetical (at the statutory rate) and determined without regard to our deduction for general and administrative expenses, interest costs and other income tax credits and deductions, nor whether the hypothetical tax provision will be payable.

Oil and Gas Reserve Quantities

The following reserve schedule was developed by our reserve engineers and sets forth the changes in estimated quantities for our proved reserves, all of which are located in the United States. We retained Cawley, Gillespie & Associates, Inc., independent third-party reserve engineers, to perform an independent evaluation of proved reserves as of December 31, 2008, 2007, 2006 and 2005.

Users of this information should be aware that the process of estimating quantities of “proved,” “proved developed” and “proved undeveloped” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upwards or downward) to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective

F-72

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.


	Gas — Mcf			Oil — Bbls

Proved reserves:
Balance, December 31, 2004		149,843,900			47,834
Purchase of reserves in place		—			—
Extensions, discoveries, and other additions		390,468			—
Sale of reserves		—			—
Revisions of previous estimates(1)		(6,342,690	)		(6,054	)
Production		(9,572,378	)		(9,480	)

Balance, December 31, 2005		134,319,300			32,300
Purchase of reserves in place		—			—
Extensions, discoveries, and other additions		27,696,254			—
Sale of reserves		—			—
Revisions of previous estimates(2)		48,329,663			9,780
Production		(12,305,217	)		(9,808	)

Balance, December 31, 2006		198,040,000			32,272
Purchase of reserves in place		—			—
Extensions, discoveries, and other additions		26,368,000			—
Sale of reserves		—			—
Revisions of previous estimates(3)		3,490,473			11,354
Production		(16,975,067	)		(7,070	)

Balance, December 31, 2007		210,923,406			36,556
Purchase of reserves in place		94,727,687			1,560,946
Extensions, discoveries, and other additions		13,897,600			—
Sale of reserves		(4,386,200	)		—
Revisions of previous estimates(2)		(123,204,433	)		(833,070	)
Production		(21,328,687	)		(69,812	)

Balance, December 31, 2008		170,629,373			694,620

Proved developed reserves:
Balance, December 31, 2005		71,638,300			32,300
Balance, December 31, 2006		122,390,360			32,272
Balance, December 31, 2007		140,966,295			36,556
Balance, December 31, 2008		136,544,572			682,030


(1)		The downward revision was due to a change in performance of wells on a portion of Quest Cherokee’s acreage.
(2)		Lower prices at December 31, 2008 as compared to December 31, 2007 and December 31, 2006 as compared to December 31, 2005 reduced the economic lives of the underlying oil and gas properties and thereby decreased the estimated future reserves.
(3)		During 2007, higher prices increased the economic lives of the underlying oil and natural gas properties and thereby increased the estimated future reserves.

F-73

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Standardized Measure of Discounted Future Net Cash Flows

The following information is based on our best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of the periods indicated in accordance with SFAS No. 69, Disclosures About Oil and Gas Producing Activities which requires the use of a 10% discount rate. Future income taxes are based on year-end statutory rates. This information is not the fair market value, nor does it represent the expected present value of future cash flows of our proved oil and gas reserves (in thousands).


	As of December 31,
	2008		2007		2006		2005

Future cash inflows	$	898,214	$	1,351,980	$	1,197,198	$	1,258,580
Future production costs		570,142		732,488		638,844		366,475
Future development costs		60,318		119,448		126,272		122,428
Future income tax expense		—		56,371		60,024		230,651

Future net cash flows		267,754		443,673		372,058		539,026
10% annual discount for estimated timing of cash flows		103,660		157,496		141,226		201,087

Standardized measure of discounted future net cash flows related to proved reserves	$	164,094	$	286,177	$	230,832	$	337,939


(1)		Future cash inflows are computed by applying year-end prices, adjusted for location and quality differentials on a property-by-property basis, to year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements at year-end. The discounted future cash flow estimates do not include the effects of our derivative instruments. See the following table for oil and gas prices as of the periods indicated.


	As of December 31,
	2008		2007		2006		2005

Crude oil price per Bbl	$	44.60	$	96.10	$	61.06	$	55.63
Natural gas price per Mcf	$	5.71	$	6.43	$	6.03	$	9.27

F-74

QUEST RESOURCE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The principal changes in the standardized measure of discounted future net cash flows relating to proven oil and natural gas properties were as follows (in thousands):


	As of December 31,
	2008			2007			2006			2005

Present value, beginning of period	$	286,177		$	230,832		$	337,939		$	280,481
Net changes in prices and production costs		(122,702	)		13,716			(289,149	)		181,950
Net changes in future development costs		(4,247	)		(43,530	)		(60,330	)		(46,074	)
Previously estimated development costs incurred		66,060			74,310			93,397			25,532
Sales of oil and gas produced, net		(103,826	)		(68,990	)		(47,072	)		(52,096	)
Extensions and discoveries		15,986			49,901			48,399			1,624
Purchases of reserves in-place		119,733			—			0			0
Sales of reserves in-place		(5,045	)		—			0			0
Revisions of previous quantity estimates		(147,464	)		6,735			84,559			(26,524	)
Net change in income taxes		36,360			880			107,365			(23,979	)
Accretion of discount		31,804			25,264			44,771			37,867
Timing differences and other(a)		(8,742	)		(2,941	)		(89,047	)		(40,842	)

Present value, end of period	$	164,094		$	286,177		$	230,832		$	337,939


(a)		The change in timing differences and other are related to revisions in the Company’s estimated time of production and development

F-75

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized this 2nd day of June, 2009.

Quest Resource Corporation

/s/ David C. Lawler

Chief Executive Officer and President

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature		Title	Date


/s/ David C. Lawler David C. Lawler		Director, Chief Executive Officer and President (principal executive officer)	June 2, 2009

* Jon H. Rateau		Director	June 2, 2009

* John C. Garrison		Director	June 2, 2009

* James B. Kite, Jr.		Director	June 2, 2009

* Gregory McMichael		Director	June 2, 2009

* William H. Damon III		Director	June 2, 2009

/s/ Eddie M. LeBlanc Eddie M. LeBlanc		Chief Financial Officer (principal financial and accounting officer)	June 2, 2009

*By:	/s/ Eddie M. LeBlanc Eddie M. LeBlanc Attorney-in-Fact

146

INDEX TO EXHIBITS


Exhibit
No.			Description

	2	.1*	Amended and Restated Agreement and Plan of Merger, dated as of February 6, 2008, by and among the Company, Pinnacle Gas Resources, Inc., and Quest MergerSub, Inc. (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on February 6, 2008).
	2	.2*	Membership Interest Purchase Agreement, dated as of June 5, 2008, by and between PetroEdge Resources Partners, LLC and the Company (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K/A filed on June 19, 2008).
	2	.3*	Agreement for Purchase and Sale, dated July 11, 2008, by and among the Company, Quest Eastern Resource LLC and Quest Cherokee LLC (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on July 16, 2008).
	3	.1*	The Company’s Restated Articles of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Registration Statement on Form 8-A12/G (Amendment No. 2) filed on December 7, 2005).
	3	.2*	Certificate of Designations for Series B Junior Participating Preferred Stock (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 1, 2006).
	3	.3*	Amendment to the Company’s Restated Articles of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 6, 2006).
	3	.4*	Third Amended and Restated Bylaws of the Company (as adopted on May 7, 2008) (incorporated herein by reference to Exhibit 3.1 to Quest Resource Corporation’s Quarterly Report on Form 10-Q filed on May 12, 2008).
	4	.1*	Specimen of certificate for shares of Common Stock (incorporated herein by reference to Exhibit 4.1 to the Company’s Annual Report on Form 10-K filed on March 10, 2008).
	4	.2*	Rights Agreement dated as of May 31, 2006, between the Company and UMB Bank, n.a., which includes as Exhibit A, the Certificate of Designations, Preferences and Rights of Series B Preferred Stock, as Exhibit B, the Form of Rights Certificate, and as Exhibit C, the Summary of Rights to Purchase Preferred Stock (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on June 1, 2006).
	10	.1*	Non-Competition Agreement by and between the Company, Quest Cherokee, LLC, Cherokee Energy Partners LLC, Quest Oil & Gas Corporation, Quest Energy Service, Inc., STP Cherokee, Inc., Ponderosa Gas Pipeline Company, Inc., Producers Service Incorporated and J-W Gas Gathering, L.L.C., dated as of the 22nd day of December, 2003 (incorporated herein by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed on January 6, 2004).
	10	.2†	Summary of Director Compensation Arrangements.
	10	.3*†	Management Annual Incentive Plan (incorporated herein by reference to Appendix C to the Company’s Proxy Statement filed on May 20, 2008).
	10	.4*†	The Company’s Amended and Restated 2005 Omnibus Stock Award Plan (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on February 6, 2008).
	10	.5*†	Amendments to 2005 Omnibus Stock Award Plan (incorporated herein by reference to Appendix A to the Company’s Proxy Statement filed on May 20, 2008).
	10	.6*†	The Company Bonus Compensation Plan (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 21, 2007).
	10	.7†	Form of the Company’s 2005 Omnibus Stock Award Plan Nonqualified Stock Option Agreement.
	10	.8*†	Form of the Company’s 2005 Omnibus Stock Award Plan Bonus Shares Award Agreement (incorporated herein by reference to Exhibit 10.9 to the Company’s Registration Statement on Form S-1 filed on December 12, 2005).
	10	.9*†	The Company’s 2008 Supplemental Bonus Plan (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 24, 2008).
	10	.10	Form of Indemnification Agreement for Directors.
	10	.11	Form of Indemnification Agreement for Officers.

147


Exhibit
No.			Description

	10	.12*	Purchase Agreement, dated as of October 16, 2007, by and among Quest Midstream Partners, L.P., Quest Midstream GP, LLC, the Company, Alerian Opportunity Partners IX, L.P., Bel Air MLP Energy Infrastructure Fund, LP, Tortoise Capital Resources Corporation, Tortoise Gas and Oil Corporation, Dalea Partners, LP, Hartz Capital MLP, LLC, ZLP Fund, L.P., KED MME Investment Partners, LP, Eagle Income Appreciation Partners, L.P., Eagle Income Appreciation II, L.P., Citigroup Financial Products, Inc., and The Northwestern Mutual Life Insurance Company (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on November 2, 2007).
	10	.13*	Amended and Restated Investors’ Rights Agreement, dated as of November 1, 2007, by and among Quest Midstream Partners, L.P., Quest Midstream GP, LLC, the Company, Alerian Opportunity Partners IV, L.P., Swank MLP Convergence Fund, LP, Swank Investment Partners, LP, The Cushing MLP Opportunity Fund I, LP, The Cushing GP Strategies Fund, LP, Tortoise Capital Resources Corporation, Alerian Opportunity Partners IX, L.P., Bel Air MLP Energy Infrastructure Fund, LP, Tortoise Gas and Oil Corporation, Dalea Partners, LP, Hartz Capital MLP, LLC, ZLP Fund, L.P., KED MME Investment Partners, LP, Eagle Income Appreciation Partners, L.P., Eagle Income Appreciation II, L.P., Citigroup Financial Products, Inc., and The Northwestern Mutual Life Insurance Company (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on November 2, 2007).
	10	.14*	Second Amended and Restated Agreement of Limited Partnership of Quest Midstream Partners, L.P., dated as of November 1, 2007, by and among Quest Midstream GP, LLC, the Company, Alerian Opportunity Partners IV, L.P., Swank MLP Convergence Fund, LP, Swank Investment Partners, LP, The Cushing MLP Opportunity Fund I, LP, The Cushing GP Strategies Fund, LP, Tortoise Capital Resources Corporation, Alerian Opportunity Partners IX, L.P., Bel Air MLP Energy Infrastructure Fund, LP, Tortoise Gas and Oil Corporation, Dalea Partners, LP, Hartz Capital MLP, LLC, ZLP Fund, L.P., KED MME Investment Partners, LP, Eagle Income Appreciation Partners, L.P., Eagle Income Appreciation II, L.P., Citigroup Financial Products, Inc., and The Northwestern Mutual Life Insurance Company (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on November 2, 2007).
	10	.15*	Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Quest Midstream Partners, L.P., adopted effective as of January 1, 2007, by Quest Midstream GP, LLC (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q filed May 12, 2008).
	10	.16*	Omnibus Agreement dated as of December 22, 2006, by and among the Company, Quest Midstream GP, LLC, Bluestem Pipeline, LLC and Quest Midstream Partners, L.P. (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on December 29, 2006).
	10	.17*	Registration Rights Agreement dated as of December 22, 2006, by and among Quest Midstream Partners, L.P., Alerian Opportunity Partners IV, LP, Swank MLP Convergence Fund, LP, Swank Investment Partners, LP, The Cushing MLP Opportunity Fund I, LP, The Cushing GP Strategies Fund, LP, Tortoise Capital Resources Corporation, Huizenga Opportunity Partners, LP and HCM Energy Holdings, LLC (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on December 29, 2006).
	10	.18*	First Amendment to Registration Rights Agreement, dated as of November 1, 2007, by and among Quest Midstream Partners, L.P., the Company, Alerian Opportunity Partners IV, L.P., Swank MLP Convergence Fund, LP, Swank Investment Partners, LP, The Cushing MLP Opportunity Fund I, LP, The Cushing GP Strategies Fund, LP, Tortoise Capital Resources Corporation, Alerian Opportunity Partners IX, L.P., Bel Air MLP Energy Infrastructure Fund, LP, Tortoise Gas and Oil Corporation, Dalea Partners, LP, Hartz Capital MLP, LLC, ZLP Fund, L.P., KED MME Investment Partners, LP, Eagle Income Appreciation Partners, L.P., Eagle Income Appreciation II, L.P., Citigroup Financial Products, Inc., and The Northwestern Mutual Life Insurance Company (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on November 2, 2007).
	10	.19*	Midstream Services and Gas Dedication Agreement between Bluestem Pipeline, LLC and the Company entered into on December 22, 2006, but effective as of December 1, 2006 (incorporated herein by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed on December 29, 2006).

148


Exhibit
No.			Description

	10	.20*	Amendment No. 1 to the Midstream Services and Gas Dedication Agreement, dated as of August 9, 2007, by and between the Company and Bluestem Pipeline, LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 13, 2007).
	10	.21*	Assignment and Assumption Agreement, dated as of November 15, 2007, by and among the Company, Quest Energy Partners, L.P. and Bluestem Pipeline, LLC (incorporated herein by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on November 21, 2007).
	10	.22	Amendment No. 2 to the Midstream Services and Gas Dedication Agreement, dated as of February 27, 2009, by and between Quest Energy Partners, L.P. and Bluestem Pipeline, LLC.
	10	.23	Second Amended and Restated Limited Liability Company Agreement of Quest Midstream GP, LLC.
	10	.24*†	Employment Agreement dated April 10, 2007 between the Company and David Lawler (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 13, 2007).
	10	.25*†	First Amendment to Employment Agreement, dated October 20, 2008, between the Company and David Lawler (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on October 24, 2008).
	10	.26*†	Nonqualified Stock Option Agreement, dated October 20, 2008, between the Company and David Lawler (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K filed on October 24, 2008).
	10	.27*†	Employment Agreement dated March 7, 2007 between the Company and David Bolton (incorporated herein by reference to Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q filed on May 10, 2007).
	10	.28*†	Employment Agreement dated December 3, 2007 between the Company and Jack T. Collins (incorporated herein by reference to Exhibit 10.28 to the Company’s Annual Report on Form 10-K filed on March 10, 2008).
	10	.29*†	First Amendment to Employment Agreement, dated October 23, 2008, between the Company and Jack Collins (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on October 24, 2008).
	10	.30*†	Nonqualified Stock Option Agreement, dated October 23, 2008, between the Company and Jack Collins (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K filed on October 24, 2008).
	10	.31*†	Employment Agreement dated March 21, 2007 between the Company and Richard Marlin (incorporated herein by reference to Exhibit 10.30 to the Company’s Annual Report on Form 10-K filed on March 10, 2008).
	10	.32†	First Amendment to Employment Agreement, dated December 29, 2008, between the Company and Richard Marlin.
	10	.33*†	Employment Agreement dated July 14, 2008 between the Company and Tom Lopus (incorporated herein by reference to Exhibit 10.15 to the Company’s Quarterly Report on Form 10-Q filed on August 11, 2009).
	10	.34*†	Nonqualified Stock Option Agreement, dated January 12, 2009, between the Company and Eddie LeBlanc (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 14, 2009).
	10	.35*	Office Lease dated May 31, 2007 between the Company and Oklahoma Tower Realty Investors, L.L.C. (incorporated herein by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q filed on June 30, 2007).
	10	.36*	Assignment and Assumptions of Leases, dated as of February 28, 2008, by and between Chesapeake Energy Corporation and the Company (incorporated herein by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q filed on May 12, 2008).
	10	.37*	Amended and Restated Credit Agreement, dated as of November 1, 2007, by and among Quest Midstream Partners, L.P., Bluestem Pipeline, LLC, Royal Bank of Canada, RBC Capital Markets and the Lenders party thereto (incorporated herein by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on November 2, 2007).

149


Exhibit
No.			Description

	10	.38*	First Amendment to the Amended and Restated Credit Agreement, dated as of November 1, 2007 among Quest Midstream Partners, L.P., Bluestem Pipeline, LLC, Royal Bank of Canada and certain guarantors. (incorporated herein by reference to Exhibit 10.29 to the Company’s Registration Statement on Form S-4 filed on February 7, 2008).
	10	.39*	Second Amendment to Amended and Restated Credit Agreement, dated as of October 28, 2008, but effective as of November 5, 2008, by and among Quest Midstream Partners, L.P., Bluestem Pipeline, LLC, Quest Kansas General Partner, L.L.C., Quest Kansas Pipeline, L.L.C., Quest Pipeline (KPC), Royal Bank of Canada and the Lenders party thereto (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on November 7, 2008).
	10	.40*	Guaranty by Quest Kansas General Partner, L.L.C., Quest Kansas Pipeline, L.L.C., and Quest Pipeline (KPC) in favor of Royal Bank of Canada, dated as of November 1, 2007 (incorporated herein by reference to Exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q filed on November 9, 2007).
	10	.41	Guaranty by Quest Transmission Company, LLC in favor of Royal Bank of Canada, dated as of February, 21, 2008.
	10	.42	Pledge and Security Agreement by Quest Transmission Company, LLC in favor of Royal Bank of Canada, dated as of February 21, 2008.
	10	.43*	Pledge and Security Agreement by Quest Kansas General Partner, L.L.C. in favor of Royal Bank of Canada, dated as of November 1, 2007 (incorporated herein by reference to Exhibit 10.10 to the Company’s Quarterly Report on Form 10-Q filed on November 9, 2007).
	10	.44*	Pledge and Security Agreement by Quest Kansas Pipeline, L.L.C. in favor of Royal Bank of Canada, dated as of November 1, 2007 (incorporated herein by reference to Exhibit 10.11 to the Company’s Report on Form 10-Q filed on November 9, 2007).
	10	.45*	Pledge and Security Agreement by Quest Pipelines (KPC) in favor of Royal Bank of Canada, dated as of November 1, 2007 (incorporated herein by reference to Exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q filed on November 9, 2007).
	10	.46*	Amended and Restated Pledge and Security Agreement by Bluestem Pipeline, LLC in favor of Royal Bank of Canada, dated as of November 1, 2007 (incorporated herein by reference to Exhibit 10.13 to the Company’s Quarterly Report on Form 10-Q filed on November 9, 2007).
	10	.47*	Amended and Restated Pledge and Security Agreement by Quest Midstream Partners, L.P. in favor of Royal Bank of Canada, dated as of November 1, 2007 (incorporated herein by reference to Exhibit 10.14 to the Company’s Quarterly Report on Form 10-Q filed on November 9, 2007).
	10	.48	First Amendment to Amended and Restated Pledge and Security Agreement by Quest Midstream Partners, L.P. in favor of Royal Bank of Canada, dated as of February 21, 2008.
	10	.49*	Settlement and Release Agreement dated November 8, 2007 between Quest Midstream GP, LLC, the Company and Richard Andrew Hoover (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on November 15, 2007).
	10	.50*	First Amended and Restated Agreement of Limited Partnership of Quest Energy Partners, L.P., dated November 15, 2007, by and between the Company and Quest Energy GP, LLC (incorporated herein by reference to Exhibit 3.1 to Quest Energy Partners, L.P.’s Current Report on Form 8-K (File No. 001-33787) filed on November 21, 2007).
	10	.51*	Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Quest Energy Partners, L.P., effective as of January 1, 2007, by Quest Energy GP, LLC (incorporated herein by reference to Exhibit 3.1 to Quest Energy Partners, L.P.’s Current Report on Form 8-K filed on April 11, 2008).
	10	.52*	Contribution, Conveyance and Assumption Agreement, dated as of November 15, 2007, by and among Quest Energy Partners, L.P., Quest Energy GP, LLC, the Company, Quest Cherokee, LLC, Quest Oil & Gas, LLC, and Quest Energy Service, LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on November 21, 2007).
	10	.53*	Omnibus Agreement, dated as November 15, 2007, by and among Quest Energy Partners, L.P., Quest Energy GP, LLC and the Company (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on November 21, 2007).

150


Exhibit
No.			Description

	10	.54*	Management Services Agreement, dated as of November 15, 2007, by and among Quest Energy GP, LLC, Quest Energy Partners, L.P. and Quest Energy Service, LLC (incorporated herein by reference to Quest Energy Partners, L.P.’s Current Report on Form 8-K filed on November 21, 2007).
	10	.55*	Amended and Restated Credit Agreement, dated as of November 15, 2007, by and among the Company, as the Initial Co-Borrower, Quest Cherokee, LLC, as the Borrower, Quest Energy Partners, L.P., as a Guarantor, Royal Bank of Canada, as Administration Agent and Collateral Agent, KeyBank National Association, as Documentation Agent, and the lenders from time to time party thereto (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on November 21, 2007).
	10	.56*	First Amendment to Amended and Restated Credit Agreement, dated as of April 15, 2008, by and among Quest Cherokee, LLC, Royal Bank of Canada, KeyBank National Association, and the lenders Party Thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 23, 2008).
	10	.57*	Second Amendment to Amended and Restated Credit Agreement, dated as of October 28, 2008, but effective as of November 5, 2008, by and among Quest Cherokee, LLC, Quest Energy Partners, L.P., Quest Cherokee Oilfield Service, LLC, Royal Bank of Canada, KeyBank National Association and the Lenders party thereto (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on November 7, 2008).
	10	.58*	Amended and Restated Credit Agreement, dated as of July 11, 2008, by and among the Company, as the Borrower, Royal Bank of Canada, as Administrative Agent and Collateral Agent, and the lenders from time to time party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on July 16, 2008).
	10	.59*	First Amendment to Amended and Restated Credit Agreement, dated as of October 24, 2008, by and among the Company, Royal Bank of Canada and the Guarantors party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 31, 2008).
	10	.60*	Second Amendment to Amended and Restated Credit Agreement, dated as of November 4, 2008, by and among the Company, Royal Bank of Canada and the Guarantors party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on November 7, 2008).
	10	.61	Third Amendment to Amended and Restated Credit Agreement, dated as of January 30, 2009, by and among the Company, Royal Bank of Canada and the Guarantors party thereto.
	10	.62	Fourth Amendment to Amended and Restated Credit Agreement, dated as of May 29, 2009, by and among the Company, Royal Bank of Canada and the Guarantors party thereto.
	10	.63*	Loan Transfer Agreement, dated as of November 15, 2007, by and among the Company, Quest Cherokee, LLC, Quest Oil & Gas, LLC, Quest Energy Service, Inc., Quest Cherokee Oilfield Service, LLC, Guggenheim Corporate Funding, LLC, Wells Fargo Foothill, Inc., and Royal Bank of Canada (incorporated herein by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed on November 21, 2007).
	10	.64*	Guaranty for Credit Agreement by Quest Oil & Gas, LLC and Quest Energy Service, LLC in favor of Royal Bank of Canada, dated as of November 15, 2007 (incorporated herein by reference to Exhibit 10.7 to the Company’s Current Report on Form 8-K filed on November 21, 2007).
	10	.65*	Pledge and Security Agreement for Credit Agreement by Quest Energy Service, LLC for the benefit of Royal Bank of Canada, dated as of November 15, 2007 (incorporated herein by reference to Exhibit 10.8 to the Company’s Current Report on Form 8-K filed on November 21, 2007).
	10	.66*	Pledge and Security Agreement for Credit Agreement by Quest Oil & Gas, LLC for the benefit of Royal Bank of Canada, dated as of November 15, 2007 (incorporated herein by reference to Exhibit 10.9 to the Company’s Current Report on Form 8-K filed on November 21, 2007).
	10	.67	First Amendment to Pledge and Security Agreement for Amended and Restated Credit Agreement by Quest Oil & Gas, LLC for the benefit of Royal Bank of Canada, dated May 29, 2009.
	10	.68*	Pledge and Security Agreement for Credit Agreement by the Company for the benefit of Royal Bank of Canada, dated as of November 15, 2007 (incorporated herein by reference to Exhibit 10.10 to the Company’s Current Report on Form 8-K filed on November 21, 2007).

151


Exhibit
No.			Description

	10	.69*	First Amendment to Pledge and Security Agreement for Amended and Restated Credit Agreement by the Company for the benefit of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on July 16, 2008).
	10	.70*	Guaranty for Amended and Restated Credit Agreement by Quest Energy Partners, L.P. in favor of Royal Bank of Canada, dated as of November 15, 2007 (incorporated herein by reference to Exhibit 10.11 to the Company’s Current Report on Form 8-K filed on November 21, 2007).
	10	.71*	Guaranty for Amended and Restated Credit Agreement by Quest Cherokee Oilfield Service, LLC in favor of Royal Bank of Canada, dated as of November 15, 2007 (incorporated herein by reference to Exhibit 10.12 to the Company’s Current Report on Form 8-K filed on November 21, 2007).
	10	.72*	Pledge and Security Agreement for Amended and Restated Credit Agreement by Quest Energy Partners, L.P. for the benefit of Royal Bank of Canada, dated as of November 15, 2007 (incorporated herein by reference to Exhibit 10.13 to the Company’s Current Report on Form 8-K filed on November 21, 2007).
	10	.73*	Pledge and Security Agreement for Amended and Restated Credit Agreement by Quest Cherokee Oilfield Service, LLC for the benefit of Royal Bank of Canada, dated as of November 15, 2007 (incorporated herein by reference to Exhibit 10.14 to the Company’s Current Report on Form 8-K filed on November 21, 2007).
	10	.74*	Pledge and Security Agreement for Amended and Restated Credit Agreement by Quest Cherokee, LLC for the benefit of Royal Bank of Canada, dated as of November 15, 2007 (incorporated herein by reference to Exhibit 10.15 to the Company’s Current Report on Form 8-K filed on November 21, 2007).
	10	.75*	Pledge and Security Agreement for Amended and Restated Credit Agreement by Quest Eastern Resource LLC for the benefit of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on July 16, 2008).
	10	.76*	Pledge and Security Agreement for Amended and Restated Credit Agreement, dated as of July 11, 2008, by Quest Mergersub, Inc., for the benefit of Royal Bank of Canada (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on July 16, 2008).
	10	.77*	Guaranty for Amended and Restated Credit Agreement by Quest Eastern Resource LLC in favor of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on July 16, 2008).
	10	.78*	Guaranty for Amended and Restated Credit Agreement by Quest MergerSub, Inc. in favor of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed on July 16, 2008).
	10	.79*	Second Lien Senior Term Loan Agreement, dated as of July 11, 2008, by and among Quest Cherokee, LLC, Quest Energy Partners, L.P., Royal Bank of Canada, KeyBank National Association, Société Générale, the lenders party thereto and RBC Capital Markets (incorporated herein by reference to Exhibit 10.7 to the Company’s Current Report on Form 8-K filed on July 16, 2008).
	10	.80*	First Amendment to Second Lien Senior Term Loan Agreement, dated as of October 28, 2008, but effective as of November 5, 2008, by and among Quest Cherokee, LLC, Quest Energy Partners, L.P., Quest Cherokee Oilfield Service, LLC, Royal Bank of Canada, Keybank National Association, Société Générale and the Lenders party thereto (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on November 7, 2008).
	10	.81*	Guaranty for Second Lien Term Loan Agreement by Quest Cherokee Oilfield Service, LLC in favor of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.8 to the Company’s Current Report on Form 8-K filed on July 16, 2008).
	10	.82*	Guaranty for Second Lien Term Loan Agreement by Quest Energy Partners, L.P. in favor of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.9 to the Company’s Current Report on Form 8-K filed on July 16, 2008).
	10	.83*	Pledge and Security Agreement for Second Lien Term Loan Agreement by Quest Cherokee Oilfield Service, LLC for the benefit of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.10 to the Company’s Current Report on Form 8-K filed on July 16, 2008).

152


Exhibit
No.			Description

	10	.84*	Pledge and Security Agreement for Second Lien Term Loan Agreement by Quest Energy Partners, L.P. for the benefit of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.11 to the Company’s Current Report on Form 8-K filed on July 16, 2008).
	10	.85*	Pledge and Security Agreement for Second Lien Term Loan Agreement by Quest Cherokee, LLC for the benefit of Royal Bank of Canada, dated as of July 11, 2008 (incorporated herein by reference to Exhibit 10.12 to the Company’s Current Report on Form 8-K filed on July 16, 2008).
	10	.86*	Intercreditor Agreement, dated as of July 11, 2008, by and between Royal Bank of Canada and Quest Cherokee, LLC (incorporated herein by reference to Exhibit 10.13 to the Company’s Current Report on Form 8-K filed on July 16, 2008).
	10	.87*	First Amendment to Office Lease, dated as of February 7, 2008, by and between Cullen Allen Holdings L.P. and Quest Midstream Partners, L.P. (incorporated herein by reference to Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q filed on May 12, 2008).
	10	.88	Settlement Agreement by and among Quest Resource Corporation, Quest Energy Partners, L.P., Quest Midstream Partners, L.P. and Jerry D. Cash, effective March 30, 2009.
	10	.89	Full and Final Settlement Agreement and Mutual Release, by and among Quest Resource Corporation, Quest Energy Partners, L.P., Quest Midstream Partners, L.P., Rockport Energy, LLC, Rockport Georgetown Partners, LLC, Rockport Georgetown Holdings, LP, Jerry D. Cash, Bryan T. Simmons and Steven Hochstein, dated May 19, 2009.
	21	.1	List of Subsidiaries.
	23	.1	Consent of Cawley, Gillespie & Associates, Inc.
	23	.2	Consent of UHY, LLP.
	24	.1	Power of Attorney.
	31	.1	Certification by principal executive officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31	.2	Certification by principal financial officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32	.1	Certification by principal executive officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	32	.2	Certification by principal financial officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		Incorporated by reference.

†		Management contracts and compensatory plans and arrangements required to be filed as Exhibits pursuant to Item 15(a) of this report.

PLEASE NOTE: Pursuant to the rules and regulations of the Securities and Exchange Commission, we have filed or incorporated by reference the agreements referenced above as exhibits to this Annual Report on Form 10-K. The agreements have been filed to provide investors with information regarding their respective terms. The agreements are not intended to provide any other factual information about the Company or its business or operations. In particular, the assertions embodied in any representations, warranties and covenants contained in the agreements may be subject to qualifications with respect to knowledge and materiality different from those applicable to investors and may be qualified by information in confidential disclosure schedules not included with the exhibits. These disclosure schedules may contain information that modifies, qualifies and creates exceptions to the representations, warranties and covenants set forth in the agreements. Moreover, certain representations, warranties and covenants in the agreements may have been used for the purpose of allocating risk between the parties, rather than establishing matters as facts. In addition, information concerning the subject matter of the representations, warranties and covenants may have changed after the date of the respective agreement, which subsequent information may or may not be fully reflected in the Company’s public disclosures. Accordingly, investors should not rely on the representations, warranties and covenants in the agreements as characterizations of the actual state of facts about the Company or its business or operations on the date hereof.

153

	•		annual director fee of $50,000 per year;

	•		annual fee of $7,500 per year for the Audit Committee chairperson;

	•		annual fee of $5,000 per year for any other committee chairperson; and

	•		a grant of 5,000 shares of common stock of the Company immediately following the annual meeting of stockholders.

	•		annual director fee of $125,000 per year;

	•		annual fee of $10,000 per year for the Audit Committee chairperson; and

	•		annual fee of $5,000 per year for any other committee chairperson.



Grant Date:


Total Number of Shares Subject to Option


Option Price per Share ($):		$

Expiration Date:

	(a)		set forth the number of Shares with respect to which the Option is to be exercised (such number must be in a minimum amount of 50 Shares);

	(b)		if the person exercising this Option is not the Grantee, be accompanied by satisfactory evidence of such person’s right to exercise this Option; and

	(c)		be accompanied by payment in full of the Option Price in the form of cash, personal or certified bank check or electronic wire transfer payable to the order of the Company or any other means allowable under the Plan which the Company in its sole discretion determines will provide legal consideration for the Shares.

	(a)		If the Grantee has a Termination of Affiliation within the Option Term due to the Grantee’s ceasing to be employed by the Company, the Option, to the extent exercisable, may be exercised by the Grantee at any time prior to 5:00 P.M., U.S. Central Time, on the ninetieth (90th) calendar day following the Grantee’s Termination of Affiliation (but in no event later than the Expiration Date). In the event that such ninetieth (90th) day shall not be a Business Day, then the Option shall expire at 5:00 P.M., U.S. Central Time, on the first (1st) Business Day immediately following such ninetieth (90th) day. In any such case, the Option may be exercised only as to the Shares as to which the Option had become exercisable on or before the date of the Termination of Affiliation.

	(b)		If the Grantee dies or becomes Disabled within the Option Term (A) while he or she is an employee of the Company, or (B) within the ninety-day period referred to in

	(a)		Except as provided above in Section 6(b) (in the event of the Grantee’s death) or below in Section 8(b), or as otherwise may be provided in the Plan, no portion of the Option granted hereunder may be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated, other than by will, by the laws of descent and distribution. All rights with respect to the Option granted to the Grantee shall be available during his or her lifetime only to the Grantee.

	(b)		Pursuant to conditions and procedures established by the Board from time to time, the Board may permit the Option to be transferred to, exercised by and paid to (a) the Grantee’s child, stepchild, grandchild, parent, stepparent, grandparent, spouse, former spouse, sibling, niece, nephew, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law, or sister-in-law (including adoptive relationships), (b) any person sharing the Grantee’s household (other than a tenant or employee), (c) a trust in which persons described in (a) or (b) have more than 50% of the beneficial interest, (d) a foundation in which persons described in (a) or (b) or the Grantee owns more than 50% of the voting interests; provided such transfer is not for value. Any permitted transfer shall be subject to the condition that the Board receive evidence satisfactory to it that the transfer is being made for estate and/or tax planning purposes on a gratuitous or donative basis and without consideration (other than nominal consideration).

	1.		Paragraph 5.2 (a) of the Agreement is deleted and replaced in its entirely as follows:

			Beginning January 1, 2008, the Compression Fee and the Gathering Fee shall be subject to adjustment on an annual basis. The amount of the adjusted fee shall be determined by multiplying each of the Compression Fee and the Gathering Fee by the sum of (a) 0.25 times the Percentage Change in the Producer Price Index for the prior calendar year and (b) 0.75 times the Percentage Change in the First of Month Index for the prior calendar year. The adjusted Compression Fee and Gathering Fee shall (a) be rounded to the third decimal point and (b) shall be calculated by Gatherer within 60 days after the beginning of each year, but shall be retroactive to the beginning of the year. In no event shall the Compression Fee or the Gathering Fee be reduced below the amount set forth in Paragraph 5.1.

	2.		The following defined term in Section 1.28 of Exhibit B to the Agreement is deleted and replaced in its entirely as follows:

			Producer Price Index — The average annual Producer Price Index for Commodities. All calculations using the Producer Price Index shall be made using (a) the most recently available version of such index, for the latter year in the calculation, as of the date of the calculation (as published by the U.S.


Quest Energy Partners, LP
By:		Quest Energy Partners GP, LLC, its general partner

By:		/s/ DAVID LAWLER

		David Lawler President


Bluestem Pipeline, LLC
	By:	Quest Midstream Partners, LP, its sole member
	By:	Quest Midstream GP, LLC, its general partner

By:	/s/ MICHAEL A. FORBAU

	Michael A. Forbau Chief Operating Officer


ARTICLE I. DEFINITIONS			6

Section 1.01 Definitions			6
Section 1.02 Construction			15

ARTICLE II. ORGANIZATION			16

Section 2.01 Formation			16
Section 2.02 Name			16
Section 2.03 Registered Office; Registered Agent; Principal Office			16
Section 2.04 Purposes			16
Section 2.05 Foreign Qualification			17
Section 2.06 Term			17
Section 2.07 No State Law Partnership			17

ARTICLE III. MEMBERSHIP INTERESTS; UNITS			18

Section 3.01 Membership Interests; Additional Members			18
Section 3.02 Liability			18
Section 3.03 Withdrawal			18

ARTICLE IV. TRANSFER OF UNITS			18

Section 4.01 General			18
Section 4.02 Requirements Applicable to All Transfers and Admissions			18
Section 4.03 Assignees			19
Section 4.04 Prohibition Against Hypothecation			20
Section 4.05 Option to Repurchase Units Assigned by Operation of Law			20
Section 4.06 General Provisions Relating to Transfer of Units			20

ARTICLE V. RIGHTS UPON A DISPOSITION			21

Section 5.01 Right of First Refusal			21
Section 5.02 Notice of Certain Sales			22
Section 5.03 Co-Sale Obligations and Rights			22
Section 5.04 Delivery of Documents to Effectuate Transfer			23
Section 5.05 Consummation of Transfer			23
Section 5.06 Specific Performance			23
Section 5.07 Termination of Rights Conferred in this Article V			23

ARTICLE VI. ISSUANCE OF UNITS; CERTIFICATES			23

Section 6.01 Issuance of Units			23
Section 6.02 Issuance of Additional Units			23
Section 6.03 Grant of Preemptive Rights			24
Section 6.04 Certificates			25
Section 6.05 Transfers			25
Section 6.06 Record Holders			26


ARTICLE VII. CAPITAL CONTRIBUTIONS			26

Section 7.01 Initial Capital Contributions			26
Section 7.02 Additional Contributions			26
Section 7.03 Loans			26
Section 7.04 Return of Contributions			26
Section 7.05 Capital Accounts			26
Section 7.06 Effect of Transfer of Membership Interest			27
Section 7.07 Certain Tax Incidents			27

ARTICLE VIII. DISTRIBUTIONS AND ALLOCATIONS			27

Section 8.01 Distributions			27
Section 8.02 Distributions on Dissolution and Winding Up			27
Section 8.03 Allocations			27
Section 8.04 Varying Interests			29
Section 8.05 Withheld Taxes			30
Section 8.06 Limitations on Distributions			30

ARTICLE IX. MANAGEMENT			30

Section 9.01 Management by Board of Directors and Executive Officers			30
Section 9.02 Number; Qualification; Tenure			30
Section 9.03 Regular Meetings			31
Section 9.04 Special Meetings			31
Section 9.05 Notice			31
Section 9.06 Action by Consent of Board			31
Section 9.07 Conference Telephone Meetings			31
Section 9.08 Quorum			31
Section 9.09 Vacancies; Increases in the Number of Directors			32
Section 9.10 Committees			32
Section 9.11 Removal			33

ARTICLE X. OFFICERS			33

Section 10.01 Elected Officers			33
Section 10.02 Election and Term of Office			33
Section 10.03 Chairman of the Board			33
Section 10.04 President			34
Section 10.05 Vice Presidents			34
Section 10.06 Treasurer			34
Section 10.07 Secretary			34
Section 10.08 Removal			35
Section 10.09 Vacancies			35

ARTICLE XI. MEMBER MEETINGS			35

Section 11.01 Meetings			35
Section 11.02 Notice of a Meeting			35
Section 11.03 Quorum; Voting Requirement			35
Section 11.04 Action by Consent of Members			36


ARTICLE XII. INDEMNIFICATION OF DIRECTORS, OFFICERS, EMPLOYEES AND AGENTS			36

Section 12.01 Indemnification			36
Section 12.02 Liability of Indemnitees			37
Section 12.03 Standards of Conduct and Fiduciary Duties			38

ARTICLE XIII. TAXES			38

Section 13.01 Tax Returns			38
Section 13.02 Tax Elections			38
Section 13.03 Tax Matters Officer			39

ARTICLE XIV. BOOKS, RECORDS, REPORTS, AND BANK ACCOUNTS			40

Section 14.01 Maintenance of Books			40
Section 14.02 Reports			40
Section 14.03 Bank Accounts			40

ARTICLE XV. DISSOLUTION, WINDING-UP, TERMINATION AND CONVERSION			41

Section 15.01 Dissolution			41
Section 15.02 Winding-Up and Termination			41
Section 15.03 Deficit Capital Accounts			42
Section 15.04 Certificate of Cancellation			42

ARTICLE XVI. GENERAL PROVISIONS			43

Section 16.01 Offset			43
Section 16.02 Notices			43
Section 16.03 Entire Agreement; Superseding Effect			44
Section 16.04 Effect of Waiver or Consent			44
Section 16.05 Amendment or Restatement			44
Section 16.06 Binding Effect			44
Section 16.07 Governing Law; Severability			44
Section 16.08 Further Assurances			45
Section 16.09 Waiver of Certain Rights			45
Section 16.10 Counterparts			45
Section 16.11 Jurisdiction			45


	Number
	of Units
Member	Held		Effective Capital Contribution
Quest Resource Corporation		850	$1,000 and a 2.64% member
			interest in Bluestem Pipeline,
			LLC with an agreed value of
			$	3,700,000
Alerian Opportunity Partners IV, LP		75	$	75
Swank MLP Convergence Fund, LP		30	$	30
Swank Investment Partners, LP		5	$	5
The Cushing MLP Opportunity Fund I, LP		10	$	10
The Cushing GP Strategies Fund, LP		30	$	30

Total:		1000	$	3,701,150



“Employee”		“Company”

Richard Marlin		QUEST RESOURCE CORPORATION

By:	/s/ Richard Marlin	By:	/s/ Jack Collins


Dated:	12/29/08	Dated:	12/29/08


		Title:	Interim CFO


	QUEST TRANSMISSION COMPANY, LLC, a Delaware limited liability company, as Guarantor
	By:	Quest Midstream Partners, L.P., a Delaware limited partnership, its Sole Member



	By:	Quest Midstream GP, LLC, a Delaware limited liability company, its General Partner


QUEST TRANSMISSION COMPANY, LLC, a Delaware limited liability company

By:	Quest Midstream Partners, L.P., a Delaware limited partnership, its General Partner

	By:	Quest Midstream GP, LLC, its General Partner

		By:	/s/ Jerry C. Cash

			Jerry C. Cash Chief Executive Officer


A.	Exact Legal Name of Debtor:	Quest Transmission Company, LLC

B.	Mailing Address of Debtor:	210 Park Avenue, Suite 2750
		Oklahoma City, Oklahoma 73102

C.	Type of Entity:	limited liability company

D.	Jurisdiction of Organization:	Delaware

E.	State Issued Organizational
	Identification Number:	4494032

F.	Tax ID Number:	26-1982491

G.	Location of Books and Records:	210 Park Avenue, Suite 2750
		Oklahoma City, Oklahoma 73102
		and
		Three Allen Center
		333 Clay Street, Suite 3300
		Houston, Texas 77002

H.	Location of Collateral:	210 Park Avenue, Suite 2750
		Oklahoma City, Oklahoma 73102
		and
		Three Allen Center
		333 Clay Street, Suite 3300
		Houston, Texas 77002

I.	Location of Real Property:	Kansas: Butler County and Wyandotte County

J.	Jurisdiction(s) for Filing
	Financing Statements:	Delaware

	Fixture filings in the relevant counties in which the properties are located:	Kansas: Butler County and Wyandotte County

		fully entitled to rely upon such instructions from Pledgee even if such instructions are contrary to any instructions or demands that Pledgor may give to the Depository Bank.

7.		Pledgee agrees to indemnify and hold the Depository Bank, its officers and employees, harmless from and against any and all claims, causes of action, liabilities, lawsuits, demands, and/or damages, including, without limitation any and all costs, including court costs and reasonable attorneys’ fees, that may arise or result from the Depository Bank complying with the instructions and orders of Pledgee given in connection with Pledgee’s exercise of its control over and secured rights in the Account and the Collateral except to the extent that such claims, causes of action, liabilities, lawsuits, demands, and/or damages are found in a final, non-appealable judgment by a court of competent jurisdiction to have resulted from the gross negligence or willful misconduct of the Depository Bank.

8.		Pledgor agrees to indemnify and hold the Depository Bank, its officers and employees, harmless from and against any and all claims, causes of action, liabilities, lawsuits, demands, and/or damages, including, without limitation, any and all costs, including court costs and reasonable attorneys’ fees, that may arise or result from the Depository Bank entering into and performing its obligations under this letter agreement except to the extent that such claims, causes of action, liabilities, lawsuits, demands, and/or damages are found in a final, non-appealable judgment by a court of competent jurisdiction to have resulted from the gross negligence or willful misconduct of the Depository Bank.

9.		The Depository Bank represents that it has not received notice regarding any lien, encumbrance, or other claim to the Account or the Collateral from any person other than pursuant to this letter agreement and has not entered into another agreement with any other party to act on such party’s instructions with respect to the Account. The Depository Bank further agrees not to enter into any such agreement with any other party.

10.		The Depository Bank subordinates’ to the security interest of Pledgee any right of recoupment or set-off, or to assert any security interest or other lien, that it may at any time have against or in any of the Collateral on account of any credit or other obligations owed to the Depository Bank by Pledgor or any other person. The Depository Bank may, however, from time to time debit the Account for any of its customary charges in maintaining the Account or for reimbursement for the reversal of any provisional credits granted by the Depository Bank to the Account, to the extent, in each case, that Pledgor has not separately paid or reimbursed Depository Bank therefor.

11.		To the extent a conflict exists between the terms of this letter agreement and any account agreement between Pledgor and the Depository Bank, the terms of this letter agreement will control.

12.		The terms of this letter agreement will in no way be modified except by a writing signed by all parties hereto.

13.		Each of the parties executing this letter agreement represents that he has the proper authority to execute this letter agreement.


	[PARTNERSHIP/LIMITED LIABILITY COMPANY]
	By:
		as [General Partner] [Manager]


DEBTOR:

QUEST MIDSTREAM PARTNERS, L.P., a Delaware limited partnership

By:	Quest Midstream GP, LLC, a Delaware limited liability company, its General Partner

	By:	/s/ Jerry C. Cash

		Jerry C. Cash
		Chief Executive Officer


		SECURED PARTY:

		ROYAL BANK OF CANADA, as Administrative Agent and Collateral Agent

		By:		/s/ Susan Khokher

		Name: Susan Khokher
		Title: Manager, Agency

A.		Collateral Notes and Collateral Note Security:

		None.

B.		Pledged Shares:

		None.

C.		Partnership/Limited Liability Company Interests:

		100% of the limited liability company membership interest in Bluestem Pipeline, LLC, a Delaware limited liability company

		100% of the limited liability company membership interest in Quest Kansas Pipeline, L.L.C., a Delaware limited liability company

		100% of the limited liability company interest in Quest Kansas General Partner, L.L.C., a Delaware limited liability company

		100% of the limited liability company interest in Quest Transmission Company, LLC, a Delaware limited liability company

D.		Agreements:

		Bluestem Partners, LLC Limited Liability Company Agreement

		Quest Kansas Pipeline, L.L.C Limited Liability Company Agreement

		Quest Kansas General Partner, L.L.C. Limited Liability Company Agreement

		Quest Transmission Company, LLC Limited Liability Company Agreement

E.		Commercial Tort Claims: None.

F.		Deposit Accounts (including name of bank address and account number).

		Account No. 805481093 at Bank of Oklahoma


	BORROWER: QUEST RESOURCE CORPORATION, as Borrower
	By:	/s/ David Lawler
		David Lawler,
		President


	GUARANTORS: QUEST OIL & GAS, LLC as a Guarantor
	By:	/s/ David Lawler
		David Lawler,
		President

	QUEST ENERGY SERVICE, LLC, as a Guarantor
	By:	/s/ David Lawler
		David Lawler,
		President


	QUEST EASTERN RESOURCE, LLC as a Guarantor
	By:	/s/ David Lawler
		David Lawler,
		President

	QUEST MERGERSUB, INC., as a Guarantor
	By:	/s/ David Lawler
		David Lawler,
		President


ADMINISTRATIVE AGENT; ROYAL BANK OF CANADA, as Administrative Agent and Collateral Agent
By:	/s/ Susan Khokher
Name:		Susan Khokher
Title:		Manager, Agency


	L/C ISSUER AND LENDER: ROYAL BANK OF CANADA, as a Lender and L/C Issuer
	By:	/s/ Jason York
		Jason York
		Authorized Signatory


BORROWER:

QUEST RESOURCE CORPORATION, as Borrower

By:	/s/	David Lawler

		David Lawler
		President


GUARANTORS:

QUEST OIL & GAS, LLC, as a Guarantor

By:	/s/	David Lawler

		David Lawler,
		President


QUEST ENERGY SERVICE, LLC, as a Guarantor

By:	/s/	David Lawler

		David Lawler,
		President