10-Q 1 qr-form10q_6635044v2.txt SEPTEMBER 30, 2005 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (Mark One) [X] Quarterly report under Section 13 or 15(d) of the Securities Exchange Act of 1934 For the quarterly period ended September 30, 2005. [ ] Transition report under Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from ____________________ to _____________________. Commission file number: 0-17371 QUEST RESOURCE CORPORATION -------------------------- (Exact name of registrant specified in its charter) Nevada 90-0196936 ------ ---------- (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 9520 N. May Avenue, Suite 300, Oklahoma City, OK 73120 ------------------------------------------------- ----- (Address of principal executive offices) (Zip Code) 405-488-1304 ------------ Registrant's telephone number, including area code Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [XX] No [ ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [XX] Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [XX] As of November 10, 2005, the issuer had 6,798,219 shares of common stock outstanding. -1- QUEST RESOURCE CORPORATION FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2005 TABLE OF CONTENTS

PART I - FINANCIAL INFORMATION.....................................................................3 Item 1. Financial Statements.............................................................3 Consolidated Balance Sheets: September 30, 2005 and December 31, 2004.....................................F-1 Consolidated Statements of Operations and Comprehensive Income: Three months and Nine months ended September 30, 2005 and 2004..............F-3 Consolidated Statements of Cash Flows: Nine months ended September 30, 2005 and 2004...............................F-4 Condensed Notes to Consolidated Financial Statements..........................F-5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations........................................................4 Forward-looking Information...................................................4 Business of Issuer............................................................4 Significant Developments during the three months ended September 30, 2005...........................4 Results of Operations.........................................................4 Liquidity and Capital Resources...............................................6 Critical Accounting Policies.................................................11 Off-Balance Sheet Arrangements...............................................12 Risk Factors.................................................................12 Item 3. Quantitative and Qualitative Disclosures About Market Risk......................22 Item 4. Controls and Procedures.........................................................25 PART II - OTHER INFORMATION.......................................................................25 Item 1. Legal Proceedings...............................................................25 Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.....................26 Item 3. Defaults Upon Senior Securities.................................................26 Item 4. Submission of Matters to a Vote of Security Holders.............................26 Item 5. Other Information...............................................................26 Item 6. Exhibits........................................................................26 SIGNATURES........................................................................................27

-2- PART I - FINANCIAL INFORMATION Item 1. Financial Statements Except as otherwise required by the context, references in this quarterly report to "we," "our," "us," "Quest" or "the Company" refer to Quest Resource Corporation and its subsidiaries, Quest Cherokee, LLC; Quest Cherokee Oilfield Service, LLC; Bluestem Pipeline, LLC; Quest Oil & Gas Corporation; Ponderosa Gas Pipeline Company, Inc.; Quest Energy Service, Inc.; STP Cherokee, Inc.; Producers Service, Incorporated; and J-W Gas Gathering, L.L.C. Our operations are primarily conducted through Quest Cherokee, LLC, Quest Cherokee Oilfield Service, LLC, Bluestem Pipeline, LLC and Quest Energy Service, Inc. Our unaudited interim financial statements, including a balance sheet as of the quarter ended September 30, 2005, a statement of operations, and a statement of cash flows for the three month and nine month periods ended September 30, 2005 and the comparable periods of 2004, are attached hereto as Pages F-1 through F-24 and are incorporated herein by this reference. The financial statements included herein have been prepared internally, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission and the Public Company Accounting Oversight Board. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been omitted. However, in our opinion, all adjustments (which include only normal recurring accruals) necessary to fairly present the financial position and results of operations have been made for the periods presented. The financial statements included herein should be read in conjunction with the financial statements and notes thereto included in the Company's annual report on Form 10-KSB/A (Amendment No. 2) for the transition period ended December 31, 2004 and for the fiscal year ended May 31, 2004. Change in Fiscal Year End ------------------------- The Company elected to change its fiscal year end to December 31 from May 31, beginning January 1, 2005. The Company filed a transition report on Form 10-KSB/A (Amendment No. 2) covering the period from June 1, 2004 to December 31, 2004. Reverse Stock Split ------------------- In October 2005, the Company's board of directors approved a 2.5 to 1 reverse stock split, and a proportionate reduction of the authorized number of shares, of the Company's common stock. In addition, the reverse stock split resulted in a reclassification from common stock to additional paid-in capital to reflect the adjusted share amount as the par value of the Company's common stock remained at $0.001. On October 31, 2005, the reverse stock split became effective. All share and per share data information in this Form 10-Q, and the financial statements included herein, for all periods have been retroactively restated to reflect the reverse stock split. -3- QUEST RESOURCE CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS

September 30, December 31, 2005 2004 ----------------------------- A S S E T S (unaudited) Current assets: Cash $ 4,979,000 $ 6,458,000 Accounts receivable, trade 310,000 6,204,000 Other receivables 708,000 524,000 Other current assets 580,000 241,000 Short-term derivative asset 440,000 202,000 Inventory 1,208,000 284,000 ------------ ------------ Total current assets 8,225,000 13,913,000 Property and equipment, net of accumulated depreciation of $1,912,000 and $1,245,000, respectively 8,608,000 8,433,000 Pipeline assets, net of accumulated depreciation of $3,205,000 and $2,207,000, respectively 60,314,000 42,552,000 Pipeline assets under construction - 12,537,000 Oil and gas properties: Properties being amortized 173,218,000 154,427,000 Properties not being amortized 17,682,000 16,707,000 ------------ ------------ 190,900,000 171,134,000 Less: Accumulated depreciation, depletion and amortization (26,244,000) (16,069,000) ------------ ------------ Net oil and gas properties 164,656,000 155,065,000 Other assets, net 4,861,000 5,141,000 Long-term derivative asset 136,000 321,000 ------------ ------------ Total assets $246,800,000 $237,962,000 ============ ============ L I A B I L I T I E S A N D S T O C K H O L D E R S' E Q U I T Y (DEFICIT) Current liabilities: Accounts payable $ 6,471,000 $ 17,337,000 Oil and gas payable 4,536,000 3,507,000 Accrued expenses 1,440,000 588,000 Current portion of notes payable 1,789,000 1,804,000 Short-term derivative liability 55,295,000 9,513,000 ------------ ------------ Total current liabilities 69,531,000 32,749,000 Non-current liabilities: Long-term derivative liability 31,289,000 12,964,000 Asset retirement obligation 1,085,000 871,000 Convertible debentures 50,000 50,000 Notes payable 137,170,000 136,413,000 Less current maturities (1,789,000) (1,804,000) ------------ ------------ Non-current liabilities 167,805,000 148,494,000 Subordinated debt (including accrued interest) 82,441,000 59,325,000 ------------ ------------ Total liabilities 319,777,000 240,568,000 Commitments and contingencies -- -- Stockholders' equity (deficit): Preferred stock, $.001 par value, 50,000,000 shares authorized 10,000 shares issued and outstanding -- -- Common Stock, $.001 par value, 380,000,000 shares authorized 6,798,219 and 5,699,877 shares issued and outstanding 7,000 6,000

The accompanying notes are an integral part of these consolidated statements. F-1 Additional paid in capital 19,751,000 17,192,000 Accumulated other comprehensive loss (76,809,000) (11,143,000) Accumulated deficit (15,926,000) (8,661,000) ------------ ------------ Total stockholders' equity (deficit) (72,977,000) (2,606,000) ------------ ------------ Total liabilities and stockholders' equity (deficit) $246,800,000 $237,962,000 ============ ============ The accompanying notes are an integral part of these consolicated statements. F-2 QUEST RESOURCE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (UNAUDITED)

For the Three Months Ended For the Nine Months Ended September 30, September 30, ------------------------------- -------------------------- 2005 2004 2005 2004 -------------- ------------ ------------ ------------ Revenue: Oil and gas sales $ 12,263,000 $ 10,805,000 $ 35,629,000 $ 32,657,000 Gas pipeline revenue 1,091,000 820,000 2,798,000 2,375,000 Other revenue and expense 152,000 (105,000) 133,000 (625,000) -------------- ------------ ------------ ------------ Total revenues 13,506,000 11,520,000 38,560,000 34,407,000 Costs and expenses: Oil and gas production 4,231,000 2,329,000 9,524,000 7,124,000 Pipeline operating 2,144,000 1,511,000 5,920,000 4,119,000 General and administrative expenses 1,025,000 1,054,000 3,001,000 2,891,000 Depreciation, depletion and amortization 4,066,000 3,259,000 11,294,000 9,812,000 -------------- ------------ ------------ ------------ Total costs and expenses 11,466,000 8,153,000 29,739,000 23,946,000 -------------- ------------ ------------ ------------ Operating income 2,040,000 3,367,000 8,821,000 10,461,000 -------------- ------------ ------------ ------------ Other income (expense): Sale of assets (5,000) -- (5,000) -- Change in derivative fair value (103,000) 932,000 1,215,000 (4,188,000) Interest income 5,000 -- 11,000 -- Interest expense (6,190,000) (4,490,000) (17,300,000) (11,427,000) ------------- ------------ ------------ ------------ Total other income (expense) (6,293,000) (3,558,000) (16,079,000) (15,615,000) ------------- ------------ ------------ ------------ Income (loss) before income taxes (4,253,000) (191,000) (7,258,000) (5,154,000) Income tax expense - deferred -- -- -- -- ------------- ------------ ------------ ------------ Net income (loss) (4,253,000) (191,000) (7,258,000) (5,154,000) Other comprehensive (loss), net of tax: Change in fixed-price contract and other derivative fair value, net of tax of $0, ($132,000), $0, and $1,153,000 (50,219,000) (10,328,000) (77,358,000) (22,878,000) Reclassification adjustments - contract settlements, net of income taxes of $0, $14,000, $0, and ($119,000) 6,297,000 1,068,000 11,692,000 2,924,000 ------------- ------------ ------------ ------------ Other comprehensive (loss) (43,922,000) (9,260,000) (65,666,000) (19,954,000) ------------- ------------ ------------ ------------ Comprehensive (loss) $ (48,175,000) $ (9,451,000) $(72,924,000) $(25,108,000) ============= ============ ============ ============ Net income (loss) $ (4,253,000) $ (191,000) $ (7,258,000) $ (5,154,000) Preferred stock dividends (2,000) (2,000) (7,000) (7,000) ------------- ------------ ------------ ------------ Net income (loss) available to common stockholders $ (4,255,000) $ (193,000) $ (7,265,000) $ (5,161,000) ============= ============ ============ ============ Earnings (loss) per common share - basic $ (0.64) $ (0.03) $ (1.16) $ (0.92) ============= ============ ============ ============ Earnings (loss) per common share - diluted $ (0.64) $ (0.03) $ (1.16) $ (0.92) ============= ============ ============ ============ Weighted average common and common equivalent shares outstanding: Basic 6,679,089 5,647,960 6,243,093 5,629,902 Diluted 6,679,089 5,647,960 6,243,093 5,629,902

The accompanying notes are an integral part of these consolicated statements. F-3 QUEST RESOURCE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Nine Months Ended September 30, 2005 2004 ---- ---- Cash flows from operating activities: Net (loss) $ (7,258,000) $ (5,154,000) Adjustments to reconcile net income (loss) to cash provided by operations: Depreciation and depletion 11,908,000 10,262,000 Change in derivative fair value (1,215,000) 4,188,000 Accrued interest on subordinated note 8,116,000 5,989,000 Stock issued for audit committee fees 19,000 62,000 Stock issued for services -- 31,000 Stock issued for retirement plan 266,000 121,000 Amortization of loan origination fees 662,000 324,000 Amortization of deferred hedging gains (396,000) (1,491,000) (Gain) loss on sale of assets 5,000 -- Change in assets and liabilities: Accounts receivable 5,710,000 (6,511,000) Other current assets (339,000) (359,000) Inventory (925,000) (1,008,000) Accounts payable (10,867,000) 6,116,000 Oil and gas payable 1,029,000 7,090,000 Hedge settlements payable -- 673,000 Accrued expenses 852,000 1,438,000 --------------- ------------ Net cash provided by operating activities 7,567,000 21,771,000 Cash flows from investing activities: Purchase of equipment, development and leasehold costs (25,548,000) (24,610,000) Other property and equipment additions (880,000) (5,950,000) --------------- ------------ Net cash used in investing activities (26,428,000) (30,560,000) Cash flows from financing activities: Proceeds from bank borrowings 4,207,000 123,715,000 Repayments of note borrowings (3,438,000) (105,480,000) Proceeds from issuance of subordinated notes 15,000,000 -- Proceeds from issuance of common stock 2,000,000 -- Accounts payable holdback -- (218,000) Dividends paid (7,000) (7,000) Refinancing costs - UBS (380,000) (4,887,000) --------------- ------------ Net cash provided by financing activities 17,382,000 13,123,000 Net increase (decrease) in cash (1,479,000) 4,334,000 Cash, beginning of period 6,458,000 225,000 --------------- ------------ Cash, end of period $ 4,979,000 $ 4,559,000 =============== ============ Supplemental disclosure of cash flow information Cash paid during the period for: Interest expense $ 7,635,000 $ 3,489,000

The accompanying notes are an integral part of these consolidated statements. F-4 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2005 (UNAUDITED) 1. BASIS OF PRESENTATION The unaudited financial statements included herein have been prepared in accordance with generally accepted accounting principles for interim financial statements and with Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and nine months ended September 30, 2005 are not necessarily indicative of the results that may be expected for the year ended December 31, 2005. The financial statements should be read in conjunction with the financial statements and notes thereto included in the Company's Form 10-KSB/A (Amendment No. 2) for the transition period ended December 31, 2004. Shares of common stock issued by the Company for other than cash have been assigned amounts equivalent to the fair value of the service or assets received in exchange. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation and Subsidiaries Ownership of Subsidiaries; Formation of Quest Cherokee. ------------------------------------------------------ The Company's subsidiaries consist of: o Quest Cherokee, LLC, a Delaware limited liability company ("Quest Cherokee"), o Bluestem Pipeline, LLC, a Delaware limited liability company ("Bluestem"), o Quest Cherokee Oilfield Service, LLC, a Delaware limited liability company ("QCOS"), o Quest Energy Service, Inc., a Kansas corporation ("QES"), o Quest Oil & Gas Corporation, a Kansas corporation ("QOG"), o Ponderosa Gas Pipeline Company, Inc., a Kansas corporation ("PGPC"), o Producers Service, Incorporated, a Kansas corporation ("PSI"), o J-W Gas Gathering, L.L.C., a Kansas limited liability ("J-W Gas"), and o STP Cherokee, Inc., an Oklahoma corporation ("STP"). QES, QOG, PGPC and STP are wholly-owned by the Company. PGPC owns all of the outstanding capital stock of PSI and PSI is the sole member of J-W Gas. Quest Cherokee was formed on December 22, 2003 to own and operate the Company's oil and gas properties in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma. Upon its formation, QES, QOG, PGPC, STP, PSI and J-W Gas contributed all of their natural gas and oil properties in the Cherokee Basin with an agreed upon value of $51 million in exchange for all of the membership interests in Quest Cherokee. The transfer of these properties was treated as a corporate restructuring. For financial reporting purposes, the properties transferred to Quest Cherokee by the Company and its subsidiaries, were transferred at historical cost. Subsequent to the formation of Quest Cherokee, Cherokee Energy Partners, LLC, a wholly owned subsidiary of ArcLight Energy Partners Fund I, L.P. ("ArcLight"), purchased $51 million of 15% junior subordinated promissory notes of Quest Cherokee at par. In connection with the purchase of the subordinated promissory notes, 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 the Company's subsidiaries were converted into all of the Class B units. Quest Cherokee is the sole member of Bluestem and QCOS. Since the Company is anticipated to ultimately control 65% of the cash flows of Quest Cherokee (See "--Distributions of Net Cash Flow of Quest Cherokee" below), the results of operation of Quest Cherokee have been included in these consolidated financial statements. For the period from inception through December 31, 2004, Quest Cherokee incurred operating losses. F-5 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2005 (UNAUDITED) Operating losses are allocated 30% to the holders of the Class A units until their membership interest of $100 is reduced to zero; thereafter all losses are allocated 100% to the Company. Financial reporting by the Company's subsidiaries is consolidated into one set of financial statements for QRC. Ownership of Company Assets. --------------------------- Quest Cherokee owns and operates all of the Company's Cherokee Basin natural gas and oil properties. Quest Cherokee Oilfield Service owns and operates all of the Company's vehicles and equipment and Bluestem owns all of the Company's gas gathering pipeline assets in the Cherokee Basin. QES employs all of the Company's non-field employees and has entered into an operating and management agreement with Quest Cherokee to manage the day-to-day operations of Quest Cherokee in exchange for a monthly manager's fee of $345,000 (the "Management Agreement"). The costs associated with field employees, first level supervisors, exploration, development and operation of the properties and certain other direct charges are borne by QCOS. STP owns properties located in Texas and Oklahoma outside of the Cherokee Basin, and QES and STP own certain equipment used at the corporate headquarters offices. Distributions of Net Cash Flow of Quest Cherokee. ------------------------------------------------ Under the terms of the limited liability company agreement for Quest Cherokee, the net cash flow (as defined therein) of Quest Cherokee was initially to be distributed generally 85% to the holders of the subordinated promissory notes and 15% to the holders of the Class B units until the subordinated promissory notes had been repaid. Thereafter, the net cash flow of Quest Cherokee was generally to be distributed 60% to the holders of the Class A units and 40% to the holders of the Class B units, until the holders of the subordinated notes and the Class A units had received a combined internal rate of return of 30% on their cash invested. Thereafter, the net cash flow of Quest Cherokee was generally to be distributed 30% to the holders of the Class A units and 70% to the holders of the Class B units. In February 2005, ArcLight purchased an additional $12 million of 15% junior subordinated promissory notes. As a condition to the purchase of these additional subordinated promissory notes: o the portion of Quest Cherokee's net cash flow that is required to be used to repay the subordinated promissory notes was increased from 85% to 90%, and the portion of the net cash flow distributable to the Company's subsidiaries, as the holders of all of Quest Cherokee's Class B units, was decreased from 15% to 10%, until the subordinated promissory notes have been repaid; and o after the subordinated promissory notes have been repaid and ArcLight has received a 30% internal rate of return on its investment in Quest Cherokee, Quest Cherokee's net cash flow will be distributed 35% to ArcLight (as the holder of the Class A units) and 65% to the Company's subsidiaries (as the holders of the Class B units); previously such net cash flow would have been distributed 30% to ArcLight and 70% to the Company's subsidiaries. Quest Cherokee has the option to issue to ArcLight an additional $3 million of 15% junior subordinated promissory notes. In the event that the Company exercises this option: o the interest rate on the subordinated promissory notes would increase from 15% to 20%; o the portion of Quest Cherokee's net cash flow that is required to be used to repay the subordinated promissory notes would be further increased from 90% to 95%, and the portion of the net cash flow distributable to the Company's subsidiaries, as the holders of all of Quest Cherokee's Class B units, would be further decreased from 10% to 5%, until the subordinated promissory notes have been repaid; and o after the subordinated promissory notes have been repaid and ArcLight, as the holder of the Class A units, has received a 30% internal rate of return on its investment in Quest Cherokee, Quest Cherokee's net cash flow would be distributed 40% to ArcLight (as the holder of the Class A units) and 60% to the Company's subsidiaries (as the holders of the Class B units). F-6 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2005 (UNAUDITED) These percentages may be altered on a temporary basis as a result of certain permitted tax distributions to the holders of the Class B units; however, future distributions will be shifted from the Class B unit holders to the Class A unit holders until the total distributions are in line with the above percentages. Mangement of Quest Cherokee. --------------------------- Quest Cherokee is managed by a board of four managers. The holders of the Class A units (as a class) and the Class B units (as a class) are each entitled to appoint two managers. In general, the vote of all the managers is required to approve any matter voted on by the managers. If there is a conflict of interest, then the managers that have the conflict of interest will not be entitled to vote on the matter. The vote of a majority of each of the Class A units and Class B units is required to approve any matter submitted to a vote of the members. Effect of a Change of Control. ----------------------------- Under the limited liability company agreement of Quest Cherokee, if a change of control or involuntary transfer occurs with respect to (1) either the Class B members or the Company or (2) the Class A members prior to the third anniversary date, then in either case the Quest Cherokee Board representatives of the class of members that has not undergone a change of control or involuntary transfer will have the right to take all actions on the part of Quest Cherokee in pursuing an exit transaction. An exit transaction will generally consist of a sale of all or substantially all of the assets of Quest Cherokee, a merger or consolidation, interest exchange or similar transaction with an unaffiliated party. "Change of Control" is defined under the limited liability company agreement as follows: For public companies, a "Change of Control" is deemed to have occurred under the limited liability company agreement at such time as any of the following occur: o with respect to the Company only, on or after the date that Douglas L. Lamb, Jerry D. Cash or any immediate family member of either of them sells or transfers 20% or more of the number of shares of the Company's common stock owned or held by any of them as of December 22, 2003, o a tender offer or exchange offer is made and consummated for the ownership of 33.33% or more of the outstanding voting securities of the public company, o the public company is merged or consolidated with another corporation (an "Other Entity") and as a result of such merger or consolidation less than 40% of the outstanding voting securities of the surviving or resulting corporation are owned directly or indirectly in the aggregate by the former stockholders of the public company other than the Other Entity or its affiliates, as the same shall have existed immediately prior to such merger or consolidation, o the public company sells or otherwise transfers substantially all of its assets to another entity which is not wholly-owned directly or indirectly by the public company or one of its subsidiaries, o a person, within the meaning of section 3(a)(9) or section 13(d)(3) of the Securities Exchange Act of 1934, acquires 33.33% or more of the outstanding voting securities of the public company (whether directly, indirectly, beneficially or of record), or o individuals who, as of December 22, 2003, constitute the board of directors of the public company (the "Incumbent Board") cease for any reason to constitute a majority of the board of directors of the public company, provided, that any individual becoming a director subsequent to December 22, 2003 whose election, or nomination for election by the public company's shareholders, was approved by a vote of at least a majority of directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office is in connection with an actual or threatened election contest relating to the election of the directors of the public company. For private companies, a "Change of Control" is deemed to have occurred under the limited liability company agreement at such time as any of the following occur: o a tender offer or exchange offer is made and consummated for the ownership of 50% or more of the outstanding voting securities of the private company, F-7 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2005 (UNAUDITED) o the private company is merged or consolidated with another entity ("Constituent Party") and as a result of such merger or consolidation 50% or less of the outstanding voting securities of the surviving or resulting entity is owned directly or indirectly in the aggregate by the former stockholder(s) of the private company or their affiliates, other than affiliates of the Constituent Party, as the same existed immediately prior to such merger or consolidation, o the private company sells or otherwise transfers substantially all of its assets to another entity which is not wholly-owned, directly or indirectly, by the private company, one of its subsidiaries or its parent company, o a person (which is not wholly-owned, directly or indirectly, by such person or one of its subsidiaries or its parent company), within the meaning of section 3(a)(9) or section 13(d)(3) of the Securities Exchange Act of 1934, acquires 50% or more of the outstanding voting securities of the private company (whether directly, indirectly, beneficially or of record), or o a distribution or sale of voting securities of the private company is consummated and as a result of such distribution 80% or less of the outstanding voting securities of the private company is owned directly or indirectly in the aggregate by the former stockholder(s) of the private company or their affiliates. In addition, with respect to the Company and the Class B members, a Change of Control will also be deemed to have occurred if a "change of control" occurs under the documents related to the subordinated promissory notes or Quest Cherokee's bank credit facilities. A Change of Control of an entity will also be deemed to have occurred if any person that controls such entity experiences a "Change of Control"; provided, however, that this provision only applies with respect to Cherokee Energy Partners to the extent that any of the change of control events for a private company occurs with respect to Cherokee Energy Partners' sole member, ArcLight Energy Partners Fund I, L.P. Terms of Subordinated Promissory Notes. -------------------------------------- The subordinated promissory notes accrue interest at the rate of 15% per annum and have a maturity date of October 22, 2010. Quest Cherokee has the option to extend the maturity of the subordinated promissory notes until December 22, 2010. Interest on the subordinated promissory notes is payable on January 31, April 30, July 31 and October 31 of each year. Quest Cherokee has the option to pay accrued interest on the subordinated promissory notes by issuing additional subordinated promissory notes as payment for the accrued interest. The entire principal amount is due at the maturity date. See Note 3 "Long-Term Debt--Subordinated Promissory Notes" for a description of provisions in the Company's credit agreement that limit Quest Cherokee's ability to repay the subordinated promissory notes. Effect of Early Termination of Quest Cherokee. --------------------------------------------- In the event that Quest Cherokee is dissolved on or before February 11, 2008 (an "Early Liquidation Event"), the holders of the subordinated promissory notes will be entitled to a make-whole payment. The make-whole payment is equal to the difference between the amount the holders of the subordinated promissory notes have received on account of principal and interest on the subordinated promissory notes and 140% of the funded principal amount of the subordinated promissory notes ($88.2 million). In the event of an Early Liquidation Event, the holders of the subordinated promissory notes are entitled to 100% of the net cash flow until they have received the make-whole payment. Provisions relating to the transfer of Quest Cherokee Units. ----------------------------------------------------------- At any time following the point in time at which net cash flow will be distributed 35% to the Class A members and 65% to the Class B members, either the Class A members or the Class B members may deliver a notice to the other class of members offering to sell all of the offeror's units to the offeree, or to buy all of the offeree's units, at a specified price and any other terms of transfer, based upon an assumed value of Quest Cherokee and with the price being tied to 65% of such assumed value with respect to Class B units and 35% of such assumed value with respect to Class A units. The offeree may subsequently notify the offeror whether the offeree elects to buy all of the offeror's units or sell all of the offeree's units at the applicable price and terms. The purchasing member would also be required to pay to the selling member the amount of any outstanding loans held by the selling member to Quest Cherokee or the other member. F-8 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2005 (UNAUDITED) Subject to various requirements, in the event that a Class B member desires to transfer its units to a party other than a Class A member or an affiliate of such Class B member, then a Class A member has certain rights to require that an equivalent number of its units be included in the proposed transfer upon the same terms and conditions, other than price, which must be not less than a specified price per Class A unit based generally upon a hypothetical distribution if all assets of Quest Cherokee were sold for cash at fair market value and its liabilities were satisfied. Subject to various requirements, if the Class A member desires to transfer any of its units, the Class A member must first notify the Class B members of the desire to sell such units and request the Class B members to make an offer to purchase the units. If the Class B members are interested in purchasing the units, the Class B members must make a binding offer to purchase the units for cash at a specified price. If the Class A member accepts the offer, then the Class B members will be obligated to purchase the units. Any loans owing by Quest Cherokee or any of the Class B members to the Class A member (including, without limitation, the subordinated promissory note) must also be repaid in connection with such purchase (or a proportionate amount repaid in the case of a transfer of less than all of the Class A member's units). If the Class A member does not accept the offer, then the Class A member may transfer the units to a third party, but only if the price received by the Class A member for the units exceeds the price offered by the Class B members. Minority Investments; Other. --------------------------- Investments in which the Company does not have a majority voting or financial controlling interest are accounted for under the equity method of accounting unless its ownership constitutes less than a 20% interest in such entity for which such investment would then be included in the consolidated financial statements on the cost method. All significant inter-company transactions and balances have been eliminated in consolidation. EARNINGS PER COMMON SHARE Statement of Financial Accounting Standards ("SFAS") 128, Earnings Per Share, requires presentation of "basic" and "diluted" earnings per share on the face of the statements of operations for all entities with complex capital structures. Basic earnings per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted during the period. Dilutive securities having an antidilutive effect on diluted earnings per share are excluded from the calculation. See Note 6 - Earnings Per Share for a reconciliation of the numerator and denominator of the basic and diluted earnings per share computations. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES The Company seeks to reduce its exposure to unfavorable changes in natural gas prices by utilizing energy swaps and collars (collectively "fixed-price contracts"). The Company has adopted SFAS 133, as amended by SFAS 138, Accounting for Derivative Instruments and Hedging Activities. It requires that all derivative instruments be recognized as assets or liabilities in the statement of financial position, measured at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Designation is established at the inception of a derivative, but redesignation is permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS 133, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Pursuant to the provisions of SFAS 133, all hedging designations and the methodology for determining hedge ineffectiveness must be documented at the inception of the hedge, and, upon the initial adoption of the standard, hedging relationships must be designated anew. Although our fixed-price contracts may not qualify for special hedge accounting treatment from time to time under the specific guidelines of SFAS 133, the Company has continued to refer to these contracts in this document as hedges inasmuch as this was the intent when such contracts were executed, the characterization is consistent with the actual economic performance of the contracts, and the Company expects the contracts to continue to mitigate its commodity price risk in the future. The specific F-9 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2005 (UNAUDITED) accounting for these contracts, however, is consistent with the requirements of SFAS 133. See Note 5 - Financial Instruments and Hedging Activities. The Company has established the fair value of all derivative instruments using estimates determined by our counterparties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, futures prices, volatility, and time to maturity and credit risk. The values reported in the financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors. RECENTLY ISSUED ACCOUNTING STANDARDS Inventory Costs - an amendment of ARB No. 43 In November 2004, the FASB issued SFAS No. 151, Inventory Costs - an amendment of ARB No. 43, Chapter 4. Statement No. 151 requires that certain abnormal costs associated with the manufacturing, freight, and handling costs associated with inventory be charged to current operations in the period in which they are incurred. The financial statements are unaffected by implementation of this new standard. Revision of SFAS No. 123, Share-Based Payment In December 2004, the FASB issued a revision of SFAS No. 123, Share-Based Payment. The statement establishes standards for the accounting for transactions in which an entity exchanges its equity investments for goods and services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity's equity instruments or that may be settled by the issuance of those equity instruments. The statement does not change the accounting guidance for share-based payments with parties other than employees. The statement is effective for the quarter beginning January 1, 2006. The Company does not expect this statement to have a material effect on its reporting. Accounting for Exchanges of Non-monetary Assets-amendment of APB Opinion No. 29 In December 2004, the FASB issued SFAS No. 153, Exchanges of Non-monetary Assets-amendment of APB Opinion No. 29. Statement 153 eliminates the exception to fair value for exchanges of similar productive assets and replaces it with a general exception for exchanged transactions that do not have a commercial substance, defined as transactions that are not expected to result in significant changes in the cash flows of the reporting entity. This statement is effective for exchanges of non-monetary assets occurring after September 15, 2005. The Company does not expect this statement to have a material effect on its reporting. Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3 In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3. Statement 154 requires retrospective application to prior periods' financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. The statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company does not expect this statement to have a material effect on its reporting. 3. LONG-TERM DEBT

Long-term debt consists of the following: September 30, 2005 --------------- Senior credit facility: Term loan $ 123,800,000 Revolving loan 12,000,000 Notes payable to banks, finance companies and related parties, secured by equipment and vehicles, due in installments through February 2008 with interest rates ranging from 5.5% to 11.5% per annum 1,370,000

F-10 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2005 (UNAUDITED)

Long-term debt consists of the following: September 30, 2005 --------------- Convertible debentures - unsecured; interest accrues at 8% per annum. 50,000 --------------- Total long-term debt 137,220,000 Less - current maturities 1,789,000 --------------- Total long-term debt, net of current maturities $ 135,431,000 =============== Subordinated debt (inclusive of accrued interest) $ 82,441,000 ===============

UBS Credit Facility On July 22, 2004, Quest Cherokee entered into a syndicated credit facility arranged and syndicated by UBS Securities LLC, with UBS AG, Stamford Branch as administrative agent (the "UBS Credit Agreement"). The UBS Credit Agreement originally provided for a $120 million nine year term loan that was fully funded at closing (the "UBS Term Loan") and a $20 million five year revolving credit facility that could be used to issue letters of credit and fund future working capital needs and general corporate purposes (the "UBS Revolving Loan"). As of September 30, 2005, Quest Cherokee had approximately $12 million of loans and approximately $2 million in letters of credit issued under the UBS Revolving Loan. Letters of credit issued under the UBS Revolving Loan reduce the amount that can be borrowed there under. The UBS Credit Agreement also contains a $15 million "synthetic" letter of credit facility that matures in December 2008, which provides credit support for Quest Cherokee's natural gas hedging program. A portion of the proceeds from the UBS Term Loan were used to repay the Bank One credit facilities. After the repayment of the Bank One credit facilities and payment of fees and other obligations related to this transaction, Quest Cherokee had approximately $9 million of cash at closing from the proceeds of the UBS Term Loan and $15 million of availability under the UBS Revolving Loan. Interest initially accrued under both the UBS Term Loan and the UBS Revolving Loan, at Quest Cherokee's option, at either (i) a rate equal to the greater of the corporate "base rate" established by UBS AG, Stamford Branch, or the federal funds effective rate plus 0.50% (the "Alternative Base Rate"), plus the applicable margin (3.50% for revolving loans and 4.50% for term loans), or (ii) LIBOR, as adjusted to reflect the maximum rate at which any reserves are required to be maintained against Eurodollar liabilities (the "Adjusted LIBOR Rate"), plus the applicable margin (3.75% for revolving loans and 4.75% for term loans). In connection with the amendment to the UBS Credit Agreement in February 2005 discussed below, the applicable margin on borrowings under the UBS Credit Agreement was increased by 1% until Quest Cherokee's total leverage ratio is less than 4.0 to 1.0. In the event of a default under either the UBS Term Loan or the UBS Revolving Loan, interest will accrue at the applicable rate, plus an additional 2% per annum. Quest Cherokee pays an annual fee on the synthetic letter of credit facility equal to 4.75% of the amount of the facility. The UBS Credit Agreement may be repaid at any time without any premium or prepayment penalty. An amount equal to $300,000 (0.25% of the original principal balance of the UBS Term Loan) is required to be repaid each quarter, commencing December 31, 2004. In addition, Quest Cherokee is required to semi-annually apply 50% of Excess Cash Flow (or 25% of Excess Cash Flow, if the ratio of the present value (discounted at 10%) of the future cash flows from Quest Cherokee's proved mineral interest to Total Net Debt is greater than or equal to 2.25:1.0) to repay the UBS Term Loan. "Excess Cash Flow" for any semi- annual period is generally defined as net cash flow from operations for that period less (1) principal payments of the UBS Term Loan made during the period, (2) the lower of actual capital expenditures or budgeted capital expenditures during the period and (3) permitted tax distributions made during the period or that will be paid within nine months after the period. "Total Net Debt" is generally defined as funded indebtedness (other than the Subordinated Notes) less up to $10 million of unrestricted cash. For the nine month period ended September 30, 2005, the Company did not have any "Excess Cash Flow". The UBS Credit Agreement is secured by a lien on substantially all of the consolidated assets of Quest Cherokee (other than the pipeline assets owned by Bluestem) and a pledge of the membership interests in Bluestem and Quest Cherokee Oilfield Service, LLC ("QCOS"). The UBS Credit Agreement contains affirmative and negative covenants that are typical for credit agreements of this type. The covenants in the UBS Credit Agreement include provisions requiring the maintenance of and furnishing of financial and other F-11 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2005 (UNAUDITED) information; the maintenance of insurance, the payment of taxes and compliance with the law; the maintenance of collateral and security interests and the creation of additional collateral and security interests; the maintenance of certain financial ratios (which are described below); restrictions on the incurrence of additional debt or the issuance of convertible or redeemable equity securities; restrictions on the granting of liens; restrictions on making acquisitions and other investments; restrictions on disposing of assets and merging or consolidating with a third party where Quest Cherokee is not the surviving entity; restrictions on the payment of dividends and the repayment of other indebtedness; restrictions on transactions with affiliates that are not on an arms length basis; and restrictions on changing the nature of Quest Cherokee's business. The UBS Credit Agreement provides that it is an event of default if a "change of control" occurs. A "change of control" is defined to include Bluestem, or any other wholly owned subsidiary of Quest Cherokee no longer being wholly owned by Quest Cherokee; ArcLight and the Company collectively ceasing to own at least 51% of the equity interests and voting stock of Quest Cherokee; or Mr. Cash ceasing to be an executive officer of Quest Cherokee, unless a successor reasonably acceptable to UBS AG, Stamford Branch is appointed within 60 days. In January 2005, Quest Cherokee determined that it was not in compliance with the leverage and interest coverage ratios in the UBS Credit Agreement for the quarter ended November 30, 2004. On February 22, 2005, Quest Cherokee and the lenders under the UBS Credit Agreement entered into an amendment and waiver pursuant to which the lenders waived all of the existing defaults under the UBS Credit Agreement and the UBS Credit Agreement was amended, among other things, as follows: o an additional $12 million of Subordinated Notes to ArcLight was permitted; o the UBS Term Loan was increased by an additional $5 million to a total of $125 million; o the Company cannot drill any new wells until not less than 200 wells have been connected to the Company's gathering system since January 1, 2005 and gross daily production is at least 43 mmcfe/d for 20 of the last 30 days prior to the date of drilling, after which time the Company may drill up to 150 new wells prior to December 31, 2005 as long as the ending inventory of wells-in-progress as of the end of any month does not exceed 250; o the total leverage ratio for any test period may not exceed: 5.50 to 1.0 for the first quarter of 2005; 5.00 to 1.0 for the second quarter of 2005; 4.50 to 1.0 for the third quarter of 2005; 3.80 to 1.0 for the fourth quarter of 2005; 3.30 to 1.0 for the first quarter of 2006; 2.90 to 1.0 for the second quarter of 2006; 2.50 to 1.0 for the third quarter of 2006; and 2.50 to 1.0 for the fourth quarter of 2006 and thereafter; o the minimum asset coverage ratio for any test period may not be less than 1.25 to 1.0; o the minimum interest coverage ratio for any test period may not be less than: 2.70 to 1.0 for each quarter for the year ended December 31, 2005; and 3.50 to 1.0 for each quarter for the year ended December 31, 2006 and thereafter; o the minimum fixed charge coverage ratio for any test period (starting March 2006) may not be less than: 1.00 to 1.0 for each of the first three quarters of 2006; 1.10 to 1.0 for the fourth quarter of 2006; 1.25 to 1.0 for each quarter for the year ended December 31, 2007; and 1.50 to 1.0 thereafter; F-12 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2005 (UNAUDITED) o capital expenditures for any test period may not exceed: $15 million for the first quarter 2005 $7.25 million for the second quarter 2005 $9.5 million for the third quarter 2005 $13.25 million for the fourth quarter 2005 $10 million for each quarter for the year ended December 31, 2006; and the amount of budgeted capital expenditures for 2007 and thereafter; and o until the later of December 31, 2005 and the date on which Quest Cherokee's total leverage ratio is less than 3.5 to 1.0, the UBS Revolving Loan may only be used for working capital purposes. Subordinated Promissory Notes In connection with the Devon asset acquisition, the Company issued a $51 million junior subordinated promissory note to ArcLight (the "Original Note") pursuant to the terms of a note purchase agreement. The Original Note was purchased at par. The Original Note bears interest at 15% per annum and is subordinate and junior in right of payment to the prior payment in full of superior debts. Interest is payable quarterly in arrears; provided, however, that if Quest Cherokee is not permitted to pay cash interest on the Original Note under the terms of its senior debt facilities, then interest will be paid in the form of additional subordinated notes. Quest Cherokee paid a commitment fee of $1,020,000 to obtain this loan. This loan fee has been capitalized as part of the acquisition of assets from Devon. In February 2005, Quest Cherokee issued an additional $12 million of 15% junior subordinated promissory notes (the "Additional Notes" and together with the Original Note, the "Subordinated Notes"). The Additional Notes have the same terms and conditions as the Original Note. The Subordinated Notes, together with all accrued and unpaid interest, are due on the later of October 22, 2010 and the maturity date of the UBS Term Loan, subject to extension until December 22, 2010. In the event that Quest Cherokee is dissolved on or before February 11, 2008 (an "Early Liquidation Event"), the holders of the Subordinated Notes will be entitled to a make-whole payment equal to the difference between the amount they have received on account of principal and interest on the Subordinated Notes and $88.2 million (140% of the funded principal amount of the Subordinated Notes). In the event of an Early Liquidation Event, the holders of the Subordinated Notes are entitled to 100% of the net cash flow until they have received the make-whole payment. Under the UBS Credit Agreement, payments may be made on the Subordinated Notes only if all of the following conditions have been met: o no default exists on the date any such payment is made, and no default or event of default would result from the payment, under the UBS Credit Agreement. o for the most recent four consecutive quarters, the ratio of the present value (discounted at 10%) of the future cash flows from Quest Cherokee's proved mineral interest to Total Net Debt is at least 1.75:1.0 and the ratio of Total Net Debt to Consolidated EBITDA does not exceed 3.00:1.0, in each case, after giving effect to such payment. "Consolidated EBITDA" is generally defined as consolidated net income, plus interest expense, amortization, depreciation, taxes and non-cash items deducted in computing consolidated net income and minus non-cash items added in computing consolidated net income. o The amount of such semi-annual payments do not exceed Quest Cherokee's Excess Cash Flow during the preceding half of the fiscal year less (1) the amount of Excess Cash Flow required to be applied to repay the UBS Term Loan, and (2) any portion of the Excess Cash Flow that is used to fund capital expenditures. F-13 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2005 (UNAUDITED) Under the terms of the amended and restated limited liability company agreement for Quest Cherokee, the net cash flow of Quest Cherokee will be distributed generally 90% to the holders of the Subordinated Notes and 10% to the holders of the Class B units until the Subordinated Notes have been repaid. These percentages may be altered on a temporary basis as a result of certain permitted tax distributions to the holders of the Class B units; however, future distributions will be shifted from the Class B unit holders to the holders of the Subordinated Notes until the total distributions are in line with the above percentages. Quest Cherokee has the option to issue to ArcLight Additional Notes in the principal amount of $3 million. In the event this option is exercised: o the interest rate on the Subordinated Notes would increase from 15% to 20%; o the portion of Quest Cherokee's net cash flow that is required to be used to repay the Subordinated Notes would be further increased from 90% to 95%, and the portion of the net cash flow distributable to the Company's subsidiaries, as the holders of all of Quest Cherokee's Class B units, would be further decreased from 10% to 5%, until the Subordinated Notes have been repaid; and o after the Subordinated Notes have been repaid and ArcLight as the holder of the Class A units has received a 30% internal rate of return on its total investment in Quest Cherokee (including amounts received on the Subordinated Notes), Quest Cherokee's net cash flow would be distributed 40% to ArcLight (as the holder of the Class A units) and 60% to the Company's subsidiaries (as the holders of the Class B units). Other Between July 20, 2005 and August 10, 2005, the Company sold 400,000 shares of its restricted common stock, par value $0.001 per share, to individual investors in exchange for $2 million cash. The sale of restricted common stock concludes the Company's goal of selling a total of 400,000 shares of restricted common stock. Following the issuance of the 400,000 shares of restricted common stock in the private offering described above, the Company loaned the $2 million in proceeds from the sales to its subsidiary, Quest Cherokee. Quest Cherokee's obligation to repay the Company the $2 million is represented by a promissory note (the "Quest Note") that provides for interest to accrue on the unpaid principal amount of the promissory note at a rate of 15% per annum. The Quest Note's maturity date is October 10, 2010. On August 8, 2005, Quest Cherokee also received a $3.0 million loan from Cherokee Energy Partners LLC ("Cherokee Energy Partners"). Quest Cherokee's obligation to repay the $3.0 million is represented by a promissory note (the "Cherokee Note") that provides for interest to accrue on the unpaid principal at a rate of 15% per annum. The Cherokee Note's maturity date is October 22, 2010. Additionally, on August 8, 2005, the Company and Cherokee Energy Partners entered into an Intercreditor Agreement. Under the agreement, the Company and Cherokee Energy Partners will share pro-rata any amount that Quest Cherokee pays on either the Quest Note or the Cherokee Note, with the Company receiving 40% of any payments and Cherokee Energy Partners receiving 60% of any payments. Wells Fargo Energy Capital Warrant On November 7, 2002, the Company entered into a credit agreement with Wells Fargo Energy Capital, Inc. ("WFEC"), as lender. In connection with the transaction, the Company issued a warrant to WFEC to acquire up to 640,000 shares of the Company's common stock at a purchase price of $0.001 per share at any time on or before November 7, 2007 (the "Warrant"). On April 6, 2005, WFEC exercised the Warrant with respect to all 640,000 shares of common stock for which the Warrant was exercisable. WFEC elected to do a "cashless exercise" of the Warrant such that the purchase price of $0.001 per share for the 640,000 shares of common stock was paid by WFEC by reducing the number of shares of common stock issuable to WFEC upon such exercise by a number which, when multiplied by the market price of the Company's common stock on the exercise date ($10.00 after giving effect to the reverse stock split) equaled the purchase price. As a result of WFEC's "cashless exercise" of the Warrant, the Company issued to WFEC 639,840 shares of its common stock. F-14 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2005 (UNAUDITED) 4. COMMITMENTS AND CONTINGENCIES The Company and STP have been named defendants in a lawsuit (Case #CJ-2003-30) filed by plaintiffs Eddie R. Hill et al on March 27, 2003 in the District Court for Craig County, Oklahoma. Plaintiffs are royalty owners who are alleging underpayment of royalties owed them by STP and the Company. The plaintiffs also allege, among other things, that STP and the Company have engaged in self-dealing, have breached their fiduciary duties to the plaintiffs and have acted fraudulently towards the plaintiffs. The plaintiffs are seeking unspecified actual and punitive damages as a result of the alleged conduct by STP and the Company. Based on the information available to date and the Company's preliminary investigation, the Company believes that the claims against it are without merit and intends to defend against them vigorously. Quest Cherokee, LLC was named as a defendant in a lawsuit (Case No. 04-CV-156-I) filed by plaintiffs Wilbur A. Schwatken, Trustee of the Wilbur A. Schwatken Revocable Trust, and Vera D. Schwatken, Trustee of the Vera D. Schwatken Revocable Trust, on November 23, 2004 in the District Court of Montgomery County, Kansas. Plaintiffs allege that an oil and gas lease covering approximately 2,245 net acres executed by plaintiffs on July 18, 2001 has terminated due to no production being established prior to the expiration date of the primary term of the lease. Plaintiff is seeking a judicial declaration of lease termination, damages for costs to restore land and unspecified punitive damages. On March 16, 2005, the court granted Quest Cherokee's motion for summary judgment holding that Quest Cherokee's oil and gas lease is valid and in effect. Plaintiffs have appealed the district court's ruling and that appeal is pending. Based on information available to date and the Company's investigation into the matter, the Company believes that the claims are without merit and intends to continue to defend against them vigorously. Quest Cherokee, LLC was named as a defendant in a lawsuit (Case No. 04-C-100-PA) filed by plaintiff Central Natural Resources, Inc. on September 1, 2004 in the District Court of Labette County, Kansas. Central Natural Resources owns the coal underlying several 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 those lands and has drilled four wells that produce coal bed methane gas on that land. Plaintiff alleges that it owns the coal bed methane gas produced and is entitled to the revenues from those leases. Plaintiff is seeking quiet title and an equitable accounting on the revenues for the coal bed methane gas produced. The Company contends it has valid leases with the owners of the coal bed methane gas rights. The issue is whether the coal bed methane gas is owned by the owner of the coal rights or by the owners of the gas rights. Quest Cherokee has asserted third party claims against the persons who entered into the gas leases with Quest Cherokee for breach of the warranty of title contained in their leases in the event that the court finds that plaintiff owns the coal bed methane gas. 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 have been filed by Quest and the plaintiff, but have not been decided by the court. Based on information available to date and the Company's investigation into the matter, the Company believes that the plaintiff's claims are without merit and intends to defend against them vigorously. On November 9, 2005, Quest Cherokee received a written notice from Central Natural Resources, Inc. stating that it owns the coal under lands that are leased by Quest Cherokee in Craig County, Oklahoma and alleging that it has rights to the coalbed methane gas from such lands. Based upon a preliminary review, Quest Cherokee owns approximately 2,250 net acres of oil and gas leases on that land, and has drilled and completed 20 producing gas wells on those leases. Quest Cherokee believes that it has valid oil and gas lesases on those lands from the owners of the coalbed methane gas. Central Natural Resources has threatened to file a lawsuit against Quest Cherokee to quiet its alleged title to the coalbed methane gas, and to recover the value of the coalbed methane gas produced to date from those wells. Although the Company has only had a limited time to evaluate Central Natural Resources claims, based on information available to date and the Company's investigation into the matter, the Company believes Central Natural Resources' demands are without merit and intends to defend against them vigorously in the event that a lawsuit is filed. Quest Cherokee, LLC, STP Cherokee, Inc. and Bluestem Pipeline, LLC were named as defendants in a lawsuit (Case No. CJ-05-23) filed by plaintiff Davis Operating Company on February 9, 2005 in the District Court of Craig County, Oklahoma. Plaintiff is alleging a breach of contract. Plaintiff is seeking $373,704 as a result of the breach of the contract. The case is in the early stages of discovery. The Company believes that the contract in question expired pursuant to its own terms. Therefore, based on information available to date and the Company's investigation into the matter, the Company believes that the claims are without merit and intends to defend against them vigorously. Quest Resource Corporation, E. Wayne Willhite, and James R. Perkins were named as defendants in a lawsuit (Case No. 04-CV-14) filed by plaintiffs Bill Sweaney and Charles Roye on August 9, 2004 in the district court of Elk County, Kansas. F-15 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2005 (UNAUDITED) Plaintiffs claim to own a short gas gathering line in Elk County, Kansas. Plaintiffs claim that the Company has used their gas gathering pipeline to transport gas and, as a result, they are owed compensation for that use. Plaintiffs have not quantified the amount of their alleged damages. Discovery in the case is ongoing. Based on information available to date and the Company's investigation into the matter, the Company believes that the claims are without merit and intends to defend against them vigorously. Quest Cherokee, G. N. Resources, Inc., Alan B. and Sharon L. Hougardy, Gerald L. and Debra A. Callarman, and Tammy L. and Kenneth Allen were named as defendants in a lawsuit (Case No. 2003-CV-8) filed by plaintiff Union Central Life Insurance Company in the district court of Neosho County, Kansas on January 30, 2003. Plaintiff claims to own one-half of the oil, gas, and minerals underlying three tracts of land in Neosho County, Kansas. Quest Cherokee obtained oil and gas leases from the owners of that land and has drilled and completed four wells on that land. Quest Cherokee and the landowner defendants deny plaintiff's claim of ownership to one-half of the oil and gas. All parties have agreed to settle and dismiss all claims in this matter. The settlement does not require Quest Cherokee to expend any monies that will not be reimbursed to Quest Cherokee. We anticipate that the settlement will be approved by the court. Upon approval by the court, all claims will be dismissed with prejudice. That motion has been fully briefed and is pending decision by the Court. Some discovery has been conducted in the case and is ongoing. Based on information available to date and the Company's investigation into the matter, the Company believes that the claims are without merit and intends to defend against them vigorously. Quest Cherokee was named as a defendant in a Third Party Petition filed by Union Central Life Insurance Company ("Union Central") in a lawsuit (Case No. 05-CV-14) filed by Quest Cherokee in the district court of Neosho County, Kansas. Union Central seeks a declaration that an oil and gas lease executed by plaintiff and owned by Quest Cherokee was forfeited and is void and as a result, that Union Central is entitled to one-half of the oil and gas produced from wells drilled by others on the land covered by that lease. Quest Cherokee denies those third party claims and contends that, during the period of time that the lease executed by Union Central was in effect and owned by Quest Cherokee, Quest Cherokee was entitled to one-half of the working interest share of the production from those wells. Discovery in the matter is ongoing. Based on information available to date and the Company's investigation into this matter, the Company believes that the third party claims are without merit and intends to defend against them vigorously. Quest Cherokee and STP Cherokee, Inc. ("STP Cherokee") were named as defendants in a lawsuit (Case No. 05 CV 41 PA) filed by Labette Energy, LLC in the district court of Labette County, Kansas. Plaintiff claims to own a 3.2 mile gas gathering pipeline in Labette County, Kansas, and that the defendants have used that pipeline without plaintiff's consent. Plaintiff also contends that the defendants slandered plaintiff's title to that pipeline. Quest Cherokee has filed a counterclaim seeking to quiet its title to the gas gathering pipeline in question. Discovery in the case is ongoing. Based on information available to date and the Company's investigation into the matter, the Company believes that the claims are without merit and intends to defend against them vigorously. Quest Cherokee was named as a defendant in a lawsuit (Case No. 05-CV-39-C) filed by Endeavor Energy Resources, L.P. in the district court of Montgomery County, Kansas. Plaintiff seeks a declaration that five oil and gas leases owned by Quest Cherokee have expired and are void, and damages arising from Quest's continued ownership and operation of those leases. There are no wells located on the oil and gas leases in issue, but those leases have been unitized with other oil and gas leases owned by Quest Cherokee on which producing wells are located. Quest Cherokee has answered the petition and filed a motion to dismiss all claims. Discovery in this matter is ongoing and Plaintiff has not yet quantified the amount of its claimed damages. Based on information available to date and the Company's investigation into the matter, the Company believes that the claims are without merit and intends to defend against them vigorously. Quest Cherokee was named as a defendant in a lawsuit (Case No. 2005-CV-64) filed by John C. and Juanita E. Mears in the District Court of Wilson County, Kansas. Quest removed the case to the U. S. District Court for the District of Kansas (Case No. 05-04123-JAR). Plaintiffs assert several claims against Quest Cherokee arisng from the ownership and operation of an oil and gas lease on land owned by the plaintiffs, and plaintiffs seek to cancel that lease. Quest Cherokee has filed an answer denying the plaintiffs' claims, and discovery has not yet commenced. Plaintiffs have not yet quantified the amount of damages that they are seeking. Based on information available to date and the Company's investigation into the matter, the Company believes that the claims are without merit and intends to defend against them vigorously. F-16 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2005 (UNAUDITED) Bluestem Pipeline has been named as a respondent in four complaints filed before the Kansas Corporation Commission (the "KCC") and two complaints before the Oklahoma Corporation Commission (the "OCC"). Each of the complaints request that the applicable Commission review and determine whether rates charged by Bluestem Pipeline for gas gathering services on its gas gathering system in Labette, Chautauqua and Montgomery counties in Kansas and Craig County in Oklahoma, as applicable, are just, reasonable, and non-discriminatory. The parties have agreed that the resolution of the complaint filed by Davis Operating that is pending before the KCC will be governed by the decision of the OCC in the Oklahoma proceedings. The matters pending before the OCC were heard by a hearing examiner, and the hearing examiner has issued his decision. Both parties appealed that decision, and those appeals are pending. Based on information available to date and the Company's investigation into the matters, the Company believes that the claims are without merit and intends to defend against them vigorously. Quest Cherokee has received three Notices of Violations from the Kansas Corporation Commission demanding that Quest Cherokee plug a total of 21 abandoned wells on properties leased by Quest Cherokee in Wilson, Neosho and Labette counties in Kansas. Failure to plug those abandoned wells could result in a recommendation of a fine of $1,000 per well. Based upon information available to date and the Company's investigation into the matter, the Company intends to plug three of those abandoned wells. The Company believes that the Kansas Corporation Commission's claims regarding the remaining abandoned wells on these leases are without merit and intends to defend against them vigorously. Quest Cherokee has received a Notice of Violation from the Kansas Corporation Commission demanding that Quest Cherokee obtain a permit to operate the Longton Gas Storage area. Failure to obtain that permit could result in a fine of $1,000 per day. Quest Cherokee is working with the KCC to obtain a permit for that facility. The Company believes that it will be successful in obtaining the required permit for that facility and that no fine will be imposed by the Kansas Corporation Commission. Quest Cherokee has received three Notices of Violation from the Oklahoma Department of Environmental Quality ("ODEQ") arising from the alleged failure to obtain the necessary permits to construct and operate three natural gas compressors. The potential fines for the alleged violations are $10,000 per day for each day that the sites were not in compliance. Quest is working with the ODEQ to resolve these issues and believes that it will be able to resolve these matters for an amount significantly less than this amount. The Company, from time to time, may be subject to legal proceedings and claims that arise in the ordinary course of its business. Although no assurance can be given, management believes, based on its experiences to date, that the ultimate resolution of such items will not have a material adverse impact on the Company's business, financial position or results of operations. Like other natural gas and oil producers and marketers, the Company's operations are subject to extensive and rapidly changing federal and state environmental regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. Therefore it is extremely difficult to reasonably quantify future environmental related expenditures. 5. FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES Natural Gas Hedging Activities The Company seeks to reduce its exposure to unfavorable changes in natural gas prices, which are subject to significant and often volatile fluctuation, through the use of fixed-price contracts. The fixed-price contracts are comprised of energy swaps and collars. These contracts allow the Company to predict with greater certainty the effective natural gas prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. Collar structures provide for participation in price increases and decreases to the extent of the ceiling and floor prices provided in those contracts. For the nine months ended September 30, 2005, fixed-price contracts hedged 90.0% of the Company's natural gas production. As of September 30, 2005, fixed-price contracts are in place to hedge 16.2 Bcf of estimated future natural gas production. Of this total volume, 2.2 Bcf are hedged for 2005 and 14.0 Bcf thereafter. Reference is made to the Annual Report on Form 10-KSB/A (Amendment No. 2) for the seven-month transition period ended December 31, 2004 for a more detailed discussion of the fixed-price contracts. The Company's fixed price contracts are tied to commodity prices on the New York Mercantile Exchange ("NYMEX"), that is, the Company receives the fixed price amount stated in the contract and pays to its counterparty the current market price for natural gas as listed on the NYMEX. However, due to the geographic location of the Company's natural gas assets and the cost of transporting the natural gas to another market, the amount that the Company receives when it actually sells its natural gas is based on the Southern Star first of month index. The difference between natural gas prices on the NYMEX and on the Southern Star first of month index is referred to as a basis differential. Typically, the price for natural gas on the Southern Star first of month index is less than the price on the NYMEX due to the more limited demand for natural gas on the Southern Star first of month index. Recently, the basis differential has been increasingly volatile and has on occasion resulted in the Company receiving a net price for its natural gas that is significantly below the price stated in the fixed price contract. F-17 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2005 (UNAUDITED) The following table summarizes the estimated volumes, fixed prices, fixed-price sales and fair value attributable to the fixed-price contracts as of September 30, 2005.

Three Months Ending Years Ending December 31, December 31, --------------- ---------------- ---------------- 2005 2006 2007 2008 Total ---- ---- ---- ---- ----- (dollars in thousands, except price data) Natural Gas Swaps: Contract vols (MMBtu) 1,562,000 5,615,000 - - 7,177,000 Weighted-avg fixed price per MMBtu (1) $ 4.64 $ 4.49 - - $ 4.52 Fixed-price sales $ 7,255 $ 25,203 - - $ 32,458 Fair value, net $ (14,720) $ (39,320) - - $ (54,040) Natural Gas Collars: Contract vols (MMBtu): Floor 584,000 1,825,000 3,650,000 2,928,000 8,987,000 Ceiling 584,000 1,825,000 3,650,000 2,928,000 8,987,000 Weighted-avg fixed price per MMBtu (1): Floor $ 5.47 $ 5.30 $ 4.83 $ 4.50 $ 4.86 Ceiling $ 6.52 $ 6.35 $ 5.83 $ 5.52 $ 5.88 Fixed-price sales (2) $ 3,808 $ 11,589 $ 21,279 $ 16,163 $ 52,839 Fair value, net $ (2,797) $ (9,303) $ (12,861) $ (7,583) $ (32,544) Total Natural Gas Contracts: Contract vols (MMBtu) 2,146,000 7,440,000 3,650,000 2,928,000 16,164,000 Weighted-avg fixed price per MMBtu (1) $ 5.15 $ 4.95 $ 5.83 $ 5.52 $ 5.28 Fixed-price sales (2) $ 11,063 $ 36,792 $ 21,279 $ 16,163 $ 85,297 Fair value, net $ (17,517) $ (48,623) $ (12,861) $ (7,583) $ (86,584)

(1) The prices to be realized for hedged production are expected to vary from the prices shown due to basis. (2) Assumes ceiling prices for natural gas collar volumes. The estimates of fair value of the fixed-price contracts are computed based on the difference between the prices provided by the fixed-price contracts and forward market prices as of the specified date, as adjusted for basis. Forward market prices for natural gas are dependent upon supply and demand factors in such forward market and are subject to significant volatility. The fair value estimates shown above are subject to change as forward market prices and basis change. See "-Fair Value of Financial Instruments". All fixed-price contracts have been executed in connection with the Company's natural gas hedging program. The differential between the fixed price and the floating price for each contract settlement period multiplied by the associated contract volume is the contract profit or loss. For fixed-price contracts qualifying as cash flow hedges pursuant to SFAS 133, the realized contract profit or loss is included in oil and gas sales in the period for which the underlying production was hedged. For the three months ended September 30, 2005 and 2004, oil and gas sales included $6.3 million and $949,000, respectively, of losses associated with realized losses under fixed-price contracts. For the nine months ended September 30, 2005 and 2004, oil and gas sales included $11.7 million and $2.4 million, respectively, of losses associated with realized losses under fixed-price contracts. For contracts that did not qualify as cash flow hedges, the realized contract profit and loss is included in other revenue and expense in the period for which the underlying production was hedged. For the three months ended September 30, 2005 and 2004, other revenue and expense included $0 and $105,000, respectively, of losses associated with realized losses under fixed-price contracts. For the nine months ended September 30, 2005 and 2004, other revenue and expense included $0 and $632,000, respectively, of losses associated with realized losses under fixed-price contracts. For fixed-price contracts qualifying as cash flow hedges, changes in fair value for volumes not yet settled are shown as adjustments to other comprehensive income. For those contracts not qualifying as cash flow hedges, changes in fair value for F-18 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2005 (UNAUDITED) volumes not yet settled are recognized in change in derivative fair value in the statement of operations. The fair value of all fixed-price contracts are recorded as assets or liabilities in the balance sheet. Based upon market prices at September 30, 2005, the estimated amount of unrealized losses for fixed-price contracts shown as adjustments to other comprehensive income that are expected to be reclassified into earnings as actual contract cash settlements are realized within the next 12 months is $55.3 million. INTEREST RATE HEDGING ACTIVITIES The Company has entered into interest rate swaps and caps designed to hedge the interest rate exposure associated with borrowings under the UBS Credit Agreement. All interest rate swaps and caps have been executed in connection with the Company's interest rate hedging program. The differential between the fixed rate and the floating rate multiplied by the notional amount is the swap gain or loss. This gain or loss is included in interest expense in the period for which the interest rate exposure was hedged. For interest rate swaps and caps qualifying as cash flow hedges, changes in fair value of the derivative instruments are shown as adjustments to other comprehensive income. For those interest rate swaps and caps not qualifying as cash flow hedges, changes in fair value of the derivative instruments are recognized in change in derivative fair value in the statement of operations. All changes in fair value of the Company's interest rate swaps and caps are reported in results of operations rather than in other comprehensive income because the critical terms of the interest rate swaps and caps do not comply with certain requirements set forth in SFAS 133. The fair value of all interest rate swaps and caps are recorded as assets or liabilities in the balance sheet. Based upon market prices at September 30, 2005, the estimated amount of unrealized gains for interest rate swaps and caps shown as adjustments to change in derivative fair value in the statement of operations that are expected to be reclassified into earnings as actual contract cash settlements are realized within the next 12 months is $440,000. At September 30, 2005, the Company had outstanding the following interest rate swaps and caps:

Notional Fixed Rate Floating Fair Value as of Instrument Type Term Amount (1) / Cap Rate Rate September 30, 2005 ------------------------ ----------------------------- -------------------- ------------- ------------- ---------------------- $58,250,000 3-month Interest Rate Swap March 2005 - March 2006 $53,875,000 2.795% LIBOR $ 368,000 $98,705,000 3-month Interest Rate Cap March 2006 - Sept. 2007 $70,174,600 5.000% LIBOR $ 208,000

(1) Represents the maximum and minimum notional amounts that are hedged during the period. CHANGE IN DERIVATIVE FAIR VALUE Change in derivative fair value in the statements of operations for the three months and nine months ended September 30, 2005 and 2004 is comprised of the following:

Three Months Ended Nine Months Ended September 30, September 30, -------------------------------------------------------------- 2005 2004 2005 2004 -------------------------------------------------------------- Change in fair value of derivatives not qualifying as cash flow hedges $ 739,000 $ 972,000 $ 557,000 $(3,954,000) Amortization of derivative fair value gains and losses recognized in earnings prior to actual cash settlements (36,000) 284,000 111,000 1,257,000 Ineffective portion of derivatives qualifying as cash flow hedges (806,000) (324,000) 547,000 (1,491,000) -------------------------------------------------------------- $ (103,000) $ 932,000 $ 1,215,000 $(4,188,000) ==============================================================

F-19 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2005 (UNAUDITED) The amounts recorded in change in derivative fair value do not represent cash gains or losses. Rather, they are temporary valuation swings in the fair value of the contracts. All amounts initially recorded in this caption are ultimately reversed within this same caption over the respective contract terms. The change in carrying value of fixed-price contracts and interest rate swaps and caps in the balance sheet since December 31, 2004 resulted from an increase in market prices for natural gas and interest rates. FAIR VALUE OF FINANCIAL INSTRUMENTS The following information is provided regarding the estimated fair value of the financial instruments, including derivative assets and liabilities as defined by SFAS 133 that the Company held as of September 30, 2005 and December 31, 2004 and the methods and assumptions used to estimate their fair value:

September 30, 2005 December 31, 2004 ------------------ ------------------ Derivative assets: Interest rate swaps and caps $ 576,000 $ 523,000 Derivative liabilities: Fixed-price natural gas collars $ (32,544,000) $ (4,802,000) Fixed-price natural gas swaps $ (54,040,000) $ (17,675,000) Bank debt $ (135,800,000) $ (134,700,000) Other financing agreements $ (1,420,000) $ (1,763,000) Subordinated debt (inclusive of accrued interest) $ (82,441,000) $ (59,325,000)

The carrying amount of cash, receivables, deposits, accounts payable and accrued expenses approximates fair value due to the short maturity of those instruments. The carrying amounts for convertible debentures and notes payable approximate fair value because the interest rates have remained generally unchanged since the issuance of the convertible debentures and due to the variable nature of the interest rates of the notes payable. The fair value of all derivative instruments as of September 30, 2005 and December 31, 2004 was based upon estimates determined by our counter-parties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, futures prices, volatility, and time to maturity and credit risk. The values reported in the financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors. Derivative assets and liabilities reflected as current in the September 30, 2005 balance sheet represent the estimated fair value of fixed-price contract and interest rate swap and cap settlements scheduled to occur over the subsequent twelve-month period based on market prices for natural gas and fluctuations in interest rates as of the balance sheet date. The offsetting increase in value of the hedged future production has not been accrued in the accompanying balance sheet. The contract settlement amounts are not due and payable until the monthly period that the related underlying hedged transaction occurs. In some cases the recorded liability for certain contracts significantly exceeds the total settlement amounts that would be paid to a counterparty based on prices in effect at the balance sheet date due to option time value. Since the Company expects to hold these contracts to maturity, this time value component has no direct relationship to actual future contract settlements and consequently does not represent a liability that will be settled in cash or realized in any way. The Company has terminated the interest rate swaps and has agreed to receive as settlement for the instrument, an amount of approximately $378,000. The interest rate caps will continue to remain in effect. 6. EARNINGS PER SHARE SFAS 128 requires a reconciliation of the numerator and denominator of the basic and diluted earnings per share (EPS) computations. The following securities were not included in the calculation of diluted earnings per share because their effect was antidilutive. o For the three and nine months ended September 30, 2005 and 2004, dilutive shares do not include the assumed conversion of the outstanding 10% Series A preferred stock (convertible into 16,000 common shares) because the effects were antidilutive. F-20 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2005 (UNAUDITED) o For the three and nine months ended September 30, 2005 and 2004, dilutive shares do not include the assumed conversion of convertible debt (convertible into 2,000, 2,000, 5,000 and 5,000 shares, respectively) because the effects were antidilutive. o For the three and nine months ended September 30, 2004, dilutive shares do not include outstanding warrants to purchase 640,000 shares of common stock at an exercise price of $0.001 because the effects were antidilutive. The following reconciles the components of the EPS computation:

Income Shares Per Share (Numerator) (Denominator) Amount ----------- ------------ ------ FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2005: Net loss $ (4,253,000) Preferred stock dividends (2,000) ---------------- Basic EPS loss available to common shareholders $ (4,255,000) 6,679,089 $ (0.64) -------- Effect of dilutive securities: None -- -- ---------------- --------- Diluted EPS loss available to common shareholders $ (4,255,000) 6,679,089 $ (0.64) ================ ========= ======== FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2004: Net loss $ (191,000) Preferred stock dividends (2,000) ---------------- Basic EPS loss available to common shareholders $ (193,000) 5,647,960 $ (0.03) -------- Effect of dilutive securities: None -- -- ---------------- --------- Diluted EPS loss available to common shareholders $ (193,000) 5,647,960 $ (0.03) ================ ========= ======== FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2005: Net loss $ (7,258,000) Preferred stock dividends (7,000) ---------------- Basic EPS loss available to common shareholders $ (7,265,000) 6,243,093 $ (1.16) -------- Effect of dilutive securities: None -- -- ---------------- --------- Diluted EPS loss available to common shareholders $ (7,265,000) 6,243,093 $ (1.16) ================ ========= ======== FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2004: Net loss $ (5,154,000) Preferred stock dividends (7,000) ----------------- Basic EPS loss available to common shareholders $ (5,161,000) 5,629,902 $ (0.92) -------- Effect of dilutive securities: None -- -- ---------------- --------- Diluted EPS loss available to common shareholders $ (5,161,000) 5,629,902 $ (0.92) ================= ========= ========

7. ASSET RETIREMENT OBLIGATIONS Effective September 1, 2003, the Company adopted SFAS 143, Accounting for Asset Retirement Obligations. Upon adoption of SFAS 143, the Company recorded a cumulative effect to net income of ($28,000) net of tax, or ($.00) per share. Additionally, the Company recorded an asset retirement obligation liability of $254,000 and an increase to net properties and equipment of $207,000. F-21 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2005 (UNAUDITED) The following table provides a roll forward of the asset retirement obligations for the three months and nine months ended September 30, 2005 and 2004:

Three Months Ended Nine Months Ended September 30, September 30, ------------------------------------------------------------ 2005 2004 2005 2004 ------------------------------------------------------------ Asset retirement obligation beginning balance $ 1,011,000 $ 739,000 $ 871,000 $ 631,000 Liabilities incurred 58,000 55,000 170,000 166,000 Liabilities settled (2,000) (1,000) (5,000) (5,000) Accretion expense 18,000 12,000 49,000 13,000 Revisions in estimated cash flows -- -- -- -- ------------------------------------------------------------ Asset retirement obligation ending balance $ 1,085,000 $ 805,000 $ 1,085,000 $ 805,000 ============================================================

8. SUBSEQUENT EVENTS On November 7, 2005, the Company entered into a Purchase/Placement Agreement (the "Purchase/Placement Agreement") pursuant to which we agreed to sell 14,650,000 shares of our common stock in a previously announced private transaction. We have also granted an option to purchase an additional 1,465,000 shares within 30 days. The option with respect to 608,144 of these shares was exercised on November 9, 2005. In connection with the Purchase/Placement Agreement, we have agreed to register the resale of the shares of common stock sold in the private transaction. The sale of the common stock is expected to close on November 14, 2005, subject to the closing of new credit facilities in the aggregate amount of $200 million (discussed below), the closing of the ArcLight Purchase Agreement (discussed below) and other customary closing conditions. We expect our gross proceeds in the transaction to be approximately $198,355,872 and our net proceeds to be approximately $184,470,961 assuming the remainder of the option is not exercised. Following the consummation of the transaction and the issuance of the common stock sold in the transaction, we will have approximately 22,056,363 shares of common stock outstanding assuming the remainder of the option is not exercised. We will use the proceeds of the transaction to, among other things, buy-out the investment of ArcLight Energy Partners Fund I, L.P., made through its wholly owned subsidiary Cherokee Energy Partners, LLC (collectively, "ArcLight"), in our principal operating subsidiary, Quest Cherokee, pursuant to the terms of the Agreement for Purchase and Sale of Units (the "ArcLight Purchase Agreement"), dated as of November 7, 2005, by and among Cherokee Energy Partners, LLC and our wholly-owned subsidiaries that own the Class B units in Quest Cherokee (the "Subsidiaries"). Simultaneously with the closing of the private transaction described above, and pursuant to the terms of the ArcLight Purchase Agreement, we will use the proceeds of the private transaction to loan approximately $110 million to Subsidiaries. The Subsidiaries will then use approximately $26.1 million of this amount to purchase all of the Class A units from ArcLight in the same percentages in which they own the Class B units. After giving effect to these purchases, Quest Cherokee will be an indirect wholly-owned subsidiary of the Company. These subsidiaries will then loan the remaining $83.9 million to Quest Cherokee, which will use such funds to repay in full the principal and interest owed to ArcLight pursuant to certain promissory notes previously issued by Quest Cherokee to ArcLight. The closing of the ArcLight Purchase Agreement is conditioned on the closing of the private transaction described above and other customary closing conditions. Also, On October 31, 2005, we entered into a commitment letter with Guggenheim Corporate Funding, LLC ("Guggenheim") for new secured credit facilities with an aggregate principal amount of $200 million to be arranged and syndicated by Guggenheim as agent for the lenders thereunder (collectively, the "New Credit Facility"). The New Credit Facility will consist of a $50 million syndicated five year senior secured first lien revolving credit facility, the entire amount of which will be available after the closing of the recapitalization transactions and after the $50 million senior secured first lien term loan has been fully drawn (the "New Revolving Loan"), a $50 million syndicated senior secured first lien term loan that will be fully drawn within 90 days after closing (the "First Lien Term Loan") and a $100 million syndicated six year senior secured second lien term loan facility that will be fully drawn at the closing of the recapitalization transactions (the "Second Lien Term Loan"). We and Quest Cherokee will be co-borrowers under the New Credit Facility. F-22 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2005 (UNAUDITED) We currently anticipate that the material terms of the New Credit Facility will be as follows; however, the actual terms may differ from those described herein. The borrowing base under the New Revolving Loan will be redetermined by the lenders under the New Revolving Loan every 6 months, with the unanimous consent of the lenders required to increase the borrowing base and 66 2/3% of the lenders required to decrease or maintain the borrowing base. We will pay a commitment fee equal to 75 basis points times the amount of the unused borrowing base. The weighted average interest rate on the New Credit Facility will not exceed LIBOR plus 4.25%. It is currently anticipated that interest will accrue under the New Revolving Loan at LIBOR plus 1.75%; under the New First Lien Term Loan at LIBOR plus 3.25% and under the New Second Lien Term Loan at LIBOR plus 6.00% . We anticipate that we will also have the option under the New Revolving Facility to designate borrowings as "base rate loans" at a rate equal to the prime rate plus 2.50%. The New Second Lien Term Loan may not be repaid for one year from the closing of the New Second Lien Term Loan. Thereafter, if we repay the New Second Lien Term Loan prior to the expiration of its term, we will pay a 3% premium in year 2 following the closing, a 2% premium in year 3 following the closing, and a 1% premium in year 4 following the closing. Thereafter, we may repay the New Second Lien Term Loan at any time without any premium or prepayment penalty. The New Revolving Loan and the First Lien Term Loan may be repaid prior to the expiration of their terms, without any premium or penalty, at any time. The New Revolving Loan and First Lien Term Loan will be secured by a first priority lien on substantially all of our assets other than our pipelines. The New Second Lien Term Loan will be secured by a second priority lien on substantially all of our assets other than our pipelines. However, Quest Cherokee will pledge the membership interests of Bluestem Pipeline, LLC, our subsidiary that owns our pipelines, to secure the New Credit Facility. Each of our subsidiaries will also guarantee the New Credit Facility. We and Quest Cherokee will be required to make certain representations and warranties that are typical for credit agreements of this type. The New Credit Facility will also contain affirmative and negative covenants that are typical for credit agreements of this type. The covenants in the New Credit Facility are expected to include, without limitation, performance of obligations under loan documentation; delivery of financial statements, other financial information and information required under the Patriot Act; delivery of notices of default, material litigation, certain dispositions and material adverse effect; operation of properties in accordance with diligent and prudent industry practice and in compliance with applicable laws; maintenance of satisfactory insurance; compliance with laws; inspection of books and properties; continued perfection of security interests in existing and subsequently acquired collateral; further assurances; payment of taxes and other preferred claims; compliance with environmental laws and delivery of notices related thereto; delivery of reserve reports; limitations on dividends and other distributions on, and redemptions and repurchases of, capital stock and other equity interests; limitations on liens; limitations on loans and investments; limitations on debt, guarantees and hedging arrangements; limitations on mergers, acquisitions and asset sales; limitations on transactions with affiliates; limitations on dissolution; limitations on changes in business conducted by us and our subsidiaries; and limitations on restrictions of subsidiaries to pay dividends or make distributions. The financial covenants under the New Credit Facility will require that: o our minimum net sales volumes will not be less than: 1,890 mmcf for the quarter ended March 31, 2006; 2,380 mmcf for the quarter ended June 30, 2006; 3,080 mmcf for the quarter ended September 30, 2006; and 3,430 mmcf for the quarter ended December 31, 2006. o our ratio of total net debt/EBITDA for each quarterly test period shall be calculated using EBITDA for such quarter multiplied by four and will not be less than: F-23 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2005 (UNAUDITED) 4.5 to 1.0 for the quarter ended March 31, 2007; 4.25 to 1.0 for the quarter ended June 30, 2007; 4.00 to 1.0 for the quarter ended September 30, 2007; 3.75 to 1.0 for the quarter ended December 31, 2007; 3.50 to 1.0 for the quarter ended March 31, 2008; 3.25 to 1.0 for the quarter ended June 30, 2008; and 3.00 to 1.0 for any quarter ended on or after September 30, 2008. o for the New Second Lien Term Loan, our total net secured debt will not exceed 65% of our proved PV-10 based on the three year NYMEX Pricing Strip. o for the New Revolving Loan and the New First Lien Term Loan, our net senior secured debt will not exceed 50% of our proved PV-10 based on the three year NYMEX Pricing Strip. We and Guggenheim will mutually agree upon the treatment of our hedging obligations in calculating these covenants. The closing of the New Credit Facility, which closing is a condition to the sale of our common equity in a private transaction, is subject to the satisfaction of a number of conditions precedent that are typical for credit agreements of this type, including but not limited to, the completion of the lenders' due diligence, the receipt of at least $175 million of proceeds from the sale of our common equity in a private transaction, the closing of the ArcLight Purchase Agreement and our having $25 million in liquidity at the closing. F-24 Item 2. Management's Discussion And Analysis Of Financial Condition and Results of Operations Forward-looking information This quarterly report contains forward-looking statements. For this purpose, any statements contained herein that are not statements of historical fact may be deemed to be forward-looking statements. These statements relate to future events or to our future financial performance. In some cases, you can identify forward-looking statements by terminology such as "may," "will," "should," "expects," "plans," "anticipates," "believes," "estimates," "predicts," "potential" or "continue" or the negative of such terms or other comparable terminology. These statements are only predictions. Actual events or results may differ materially. There are a number of factors that could cause our actual results to differ materially from those indicated by such forward-looking statements. See our report on Form 10-KSB/A (Amendment No. 2) for the transition period ended December 31, 2004 and "--Risk Factors" below for a listing of some of these factors. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance, or achievements. Moreover, we do not assume responsibility for the accuracy and completeness of such forward-looking statements. We are under no duty to update any of the forward-looking statements after the date of this report to conform such statements to actual results. BUSINESS OF ISSUER The Company is an independent energy company with an emphasis on the acquisition, exploration, development, production, and transportation of natural gas (coal bed methane) in a ten county region in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma. The Company also owns and operates a gas gathering pipeline network of approximately 1,000 miles in length within this basin. Quest's main focus is upon the development of the Company's coal bed methane gas reserves in the Company's pipeline network region and upon the continued enhancement of the pipeline system and supporting infrastructure. Unless otherwise indicated, references to the Company or Quest include the Company's operating subsidiaries. SIGNIFICANT DEVELOPMENTS DURING THE THREE MONTHS ENDED SEPTEMBER 30, 2005 The Company has been focused on re-completions of existing wells (that is, opening up production of additional gas from different depths), which management anticipates will in the long term increase overall natural gas production. However, the re-completion program may in the short term negatively affect natural gas production as natural gas wells are taken off line for the re-completions and then undergo a period of "dewatering" after they are re-connected. During the third quarter, the Company completed 40 re-completions that have increased the production from those wells by approximately 29% during the third quarter and the Company anticipates additional volumes from these wells after dewatering of the newly opened producing zones is completed. The Company has also been completing the connection of wells that were previously drilled. During the three months ended September 30, 2005, the Company completed the connection of 6 gross wells and as of that date had 7 additional gas wells (gross) that it was in the process of completing and connecting to its gas gathering pipeline system. The Company is also evaluating the operation of its natural gas gathering system to determine whether changes in compression or other alterations in the operation of the pipeline system might improve production. Due to restrictions in Quest Cherokee's credit agreement, the Company is unable to drill any additional wells until gross daily production is at least 43mmcfe/d for 20 of the last 30 days prior to the date of drilling, after which time the Company may drill up to 150 new wells prior to December 31, 2005 as long as the ending inventory of wells-in-progress as of the end of any month does not exceed 250. As of November 10, 2005, the Company's average gross daily production for the 20 highest days out of the last 30 days was 37.6mmcfe/d. At this time the Company is not able to predict when its production will increase sufficiently to allow it to recommence drilling operations under Quest Cherokee's credit agreement. RESULTS OF OPERATIONS The following discussion is based on the consolidated operations of all our subsidiaries and should be read in conjunction with the financial statements included in this report; and should further be read in conjunction with the audited financial statements and notes thereto included in our annual reports on Form 10-KSB/A (Amendment No. 2) for the transition period ended December 31, 2004 and for the fiscal year ended May 31, 2004. Comparisons made between reporting periods herein are for the three and nine month periods ended September 30, 2005 as compared to the same periods in 2004. Three Months Ended September 30, 2005 Compared to Three Months Ended September 30, 2004 Total revenues of $13.5 million for the quarter ended September 30, 2005 represents an increase of 17% when compared to total revenues of $11.5 million for the quarter ended September 30, 2004. This increase was achieved by a combination of the addition of more producing wells and higher natural gas prices, which was partially offset by the natural decline in production from some of the Company's older gas wells. -4- The increase in oil and gas sales from $10.8 million for the quarter ended September 30, 2004 to $12.3 million for the quarter ended September 30, 2005 and the increase in gas pipeline revenue from $820,000 to $1.1 million resulted from the additional wells and pipelines acquired or completed during the past 12 months and higher natural gas prices, which was partially offset by the natural decline in production from some of the Company's older gas wells. The additional wells acquired or completed contributed to the production of 2,532,000 mcf of net gas for the quarter ended September 30, 2005, as compared to 2,155,000 net mcf produced in the same quarter last year. The Company's product prices on an equivalent basis (mcfe) increased from $5.50 mcfe average for the quarter ended September 30, 2004 to $7.31 mcfe average for the quarter ended September 30, 2005. For the quarter ended September 30, 2005, the net product price, after accounting for hedge settlements of $6.3 million during the quarter, averaged $4.80 mcfe. For the quarter ended September 30, 2004, the net product price, after accounting for hedging settlement of $1.1 million during the quarter, averaged $5.01 mcfe. Other expense for the three months ended September 30, 2004 was $105,000 as compared to other income of $152,000 for the three-month period ended September 30, 2005. Other expense for the three months ended September 30, 2004 was the result of a reclassification from gas sales of cash settlements for contracts that did not qualify as cash flow hedges for the quarter. Other income for the three months ended September 30, 2005 was primarily the result of overhead fees. The oil and gas production costs increased to $4.2 million for the quarter ended September 30, 2005 as compared to the operating costs of $2.3 million incurred for the quarter ended September 30, 2004. Lease operating costs per mcf for the quarter ended September 30, 2005 increased to $1.33 per mcf as compared to $.81 per mcf for the quarter ended September 30, 2004. Pipeline operating costs increased by approximately 40% from $1.5 million for the quarter September 30, 2004 to $2.1 million for the quarter ended September 30, 2005. The lease operating cost per mcf increased due to a decrease in the amount of field payroll allocated to capital expenditures as the amount of capital expenditures is currently limited pursuant to certain bank covenants. Additionally, workers compensation payments were made in August 2005 of approximately $145,000. The cost increases incurred for pipeline operations are due to the number of wells acquired, completed and operated during the quarter and the increased miles of pipeline in service. For the quarter ended September 30, 2005, depreciation, depletion and amortization increased to $4.1 million as compared to $3.3 million for the quarter ended September 30, 2004. The increase in depreciation, depletion and amortization is a result of the increased number of producing wells and miles of pipelines acquired and developed and the higher volumes of gas and oil produced. General and administrative expenses remained relatively flat at $1.0 million for the quarter ended September 30, 2005 compared to $1.1 million for the same period in the prior year. Interest expense increased to $6.2 million for the quarter ended September 30, 2005 from $4.5 million for the quarter ended September 30, 2004, due to the increase in the Company's outstanding borrowings related to equipment, development and leasehold expenditures and higher average interest rates. Change in derivative fair value was a non-cash loss of $103,000 for the three months ended September 30, 2005, which included a $739,000 gain attributable to the change in fair value for certain derivatives that did not qualify as cash flow hedges pursuant to SFAS 133, a $36,000 net loss attributable to the reversal of contract fair value gains and losses recognized in earnings prior to actual settlement, and a loss of $806,000 relating to hedge ineffectiveness. Change in derivative fair value was a non-cash gain of $932,000 for the three months ended September 30, 2004, which included a $972,000 gain attributable to the change in fair value for certain derivatives that did not qualify as cash flow hedges pursuant to SFAS 133, a $284,000 net gain attributable to the reversal of contract fair value gains and losses recognized in earnings prior to actual settlement, and a loss of $324,000 relating to hedge ineffectiveness. Amounts recorded in this caption represent non-cash gains and losses created by valuation changes in derivatives that are not entitled to receive hedge accounting. All amounts recorded in this caption are ultimately reversed in this caption over the respective contract term. The Company recorded a net loss of $4.3 million for the quarter ended September 30, 2005 as compared to a net loss of $191,000 for the quarter ended September 30, 2004, each period inclusive of the non-cash net gain or loss derived from the change in derivative fair value as stated above. Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004 Total revenues of $38.6 million for the nine months ended September 30, 2005 represents an increase of approximately 12% when compared to total revenues of $34.4 million for the nine months ended September 30, 2004. This increase was achieved by a combination of the addition of more producing wells and higher natural gas prices, which was partially offset by the natural decline in production from some of the Company's older gas wells. -5- The increase in oil and gas sales from $32.7 million for the nine months ended September 30, 2004 to $35.6 million for the nine months ended September 30, 2005 and the increase in gas pipeline revenue from $2.4 million to $2.8 million resulted from the additional wells and pipelines acquired or completed during the past 12 months and higher natural gas prices, which was partially offset by the natural decline in production from some of the Company's older gas wells. The additional wells acquired or completed contributed to the production of 7,106,000 mcf of net gas for the nine months ended September 30, 2005, as compared to 6,464,000 net mcf produced for the nine months ended September 30, 2004. The Company's product prices on an equivalent basis (mcfe) increased from $5.52 mcfe average for the nine months ended September 30, 2004 to $6.60 mcfe average for the nine months ended September 30, 2005. For the nine months ended September 30, 2005, the net product price, after accounting for hedge settlements of $10.7 million during the nine months, averaged $5.10 mcfe. For the nine months ended September 30, 2004, the net product price, after accounting for hedging settlement of $3.0 million during the nine months, averaged $5.05 mcfe. Other expense for the nine months ended September 30, 2004 was $625,000 as compared to other revenue of $133,000 for the nine month period ended September 30, 2005. Other expense for the nine months ended September 30, 2004 was the result of a reclassification from gas sales of cash settlements for contracts that did not qualify as cash flow hedges in the second and third quarters of 2004. Other income for the nine months ended September 30, 2005 was primarily the result of an adjustment to overhead fees. The oil and gas production costs increased to $9.5 million for the nine months ended September 30, 2005 as compared to the operating costs of $7.1 million incurred for the nine months ended September 30, 2004. Lease operating costs per mcf for the nine months ended September 30, 2005 were $1.03 per mcf as compared to $1.10 per mcf for the nine months ended September 30, 2004, representing a 6% decrease. Pipeline operating costs increased by 44% from $4.1 million for the nine months September 30, 2004 to $5.9 million for the nine months ended September 30, 2005. The decrease in lease operating cost per mcf is due primarily to a decrease in the amount of time spent servicing the wells resulting from gains in operational efficiency. The cost increases incurred for pipeline operations are due to the number of wells acquired, completed and operated during the nine months and the increased miles of pipeline in service. For the nine months ended September 30, 2005, depreciation, depletion and amortization increased to $11.3 million as compared to $9.8 million for the nine months ended September 30, 2004. The increase in depreciation, depletion and amortization is a result of the increased number of producing wells and miles of pipelines acquired and developed and the higher volumes of gas and oil produced. General and administrative expenses increased slightly to $3.0 million for the nine months ended September 30, 2005 compared to $2.9 million for the same period in the prior year, due to increased staffing to support the higher levels of development and operational activity and the added resources to enhance the Company's internal controls and financial reporting. Interest expense increased to $17.3 million for the nine months ended September 30, 2005 from $11.4 million for the nine months ended September 30, 2004, due to the increase in the Company's outstanding borrowings related to equipment, development and leasehold expenditures and higher average interest rates. Change in derivative fair value was a non-cash gain of $1.2 million for the nine months ended September 30, 2005, which included a $557,000 gain attributable to the change in fair value for certain derivatives that did not qualify as cash flow hedges pursuant to SFAS 133, a $111,000 net gain attributable to the reversal of contract fair value gains and losses recognized in earnings prior to actual settlement, and a gain of $547,000 relating to hedge ineffectiveness. Change in derivative fair value was a non-cash loss of $4.2 million for the nine months ended September 30, 2004, which included a $4.0 million loss attributable to the change in fair value for certain derivatives that did not qualify as cash flow hedges pursuant to SFAS 133, a $1.3 million net gain attributable to the reversal of contract fair value gains and losses recognized in earnings prior to actual settlement, and a loss of $1.5 million relating to hedge ineffectiveness. Amounts recorded in this caption represent non-cash gains and losses created by valuation changes in derivatives that are not entitled to receive hedge accounting. All amounts recorded in this caption are ultimately reversed in this caption over the respective contract term. The Company recorded a net loss of $7.3 million for the nine months ended September 30, 2005 as compared to a net loss of $5.2 million for the nine months ended September 30, 2004, each period inclusive of the non-cash net gain or loss derived from the change in derivative fair value as stated above. Liquidity and Capital Resources At September 30, 2005, the Company had current assets of $8.2 million, a working capital deficit (current assets minus current liabilities, excluding the short-term derivative assets and liabilities) of $6.5 million and had $7.6 million of net cash provided by operations during the nine months ended September 30, 2005. The working capital deficit (including the short-term derivative assets and liabilities) totals $61.3 million. -6- During the nine months ended September 30, 2005 a total of approximately $26.4 million was invested in new natural gas wells and properties, new pipeline facilities, and other additional capital items. This investment was funded by an increase of approximately $15 million of additional notes issued to ArcLight, $2 million of additional borrowings under the term loans from the UBS Credit Agreement, the issuance of $2 million of common stock and cash flow from operations. The Company used an additional $3 million of borrowings under the term loans from the UBS Credit Agreement to reduce the outstanding balance under its revolving credit facility. Net cash provided by operating activities totaled $7.6 million for the nine months ended September 30, 2005 as compared to $21.8 million of net cash provided from operating activities for the nine months ended September 30, 2004 due primarily to the Company's increased amount of debt and overall higher interest rates, the costs associated with the expanded operations of the Company as discussed above and the delay between the time a well is drilled and the Company begins receiving payments for production from the well. The Company's working capital deficit (current assets minus current liabilities, excluding the short-term derivative asset and liability of $440,000 and $55.3 million, respectively) was $6.5 million at September 30, 2005, compared to a working capital deficit (excluding the short-term derivative asset and liability of $202,000 and $9.5 million, respectively) of $9.5 million at December 31, 2004. The change in the working capital deficit is due to the reduction of accounts payable and accrued expenses that were funded with the proceeds of additional term loan borrowings and additional subordinated notes issued in February 2005 (See - "UBS Credit Facility" and "ArcLight Transaction"). The Company's ability to recommence drilling operations is currently limited by the covenants contained in the UBS Credit Agreement which require the Company to achieve gross daily production of at least 43 mmcfe/d for 20 of the last 30 days prior to the date of drilling. The Company's average gross daily production for the nine months ended September 30, 2005 was approximately 35.4 mmcfe/d and as of this filing was approximately 37.1 mmcfe/d. At this time, the Company is unable to predict when it will be able to recommence drilling operations under the UBS Credit Agreement. As previously announced, the Company is currently pursuing a recapitalization transaction that would involve the sale of approximately 15.2 million shares of common stock in a private transaction for approximately $200 million, the purchase of the Class A units in Quest Cherokee and the repayment of the notes owed to Cherokee Energy Partners for $110 million and the financing of Quest Cherokee's existing credit facilities with new credit facilities in the aggregate principal amount of $200 million. The new credit facilities would not have the restrictions on drilling that are contained in the UBS Credit Agreement. These transactions are anticipated to close simultaneously on November 14, 2005. Upon the closing of these transactions, the Company would have over $100 million of cash and borrowing capacity under its new credit facilities that would be available for future development of its oil and gas properties. However, no assurance can be given that these transactions will close on the terms described herein. See Note 8 (Subsequent Events) to the consolidated financial statements included elsewhere in this report. Although the Company believes that it will have adequate additional reserves and other resources to support future development plans, no assurance can be given that the Company will be able to obtain funding sufficient to support all of its development plans or that such funding will be on terms favorable to the Company. UBS Credit Facility On July 22, 2004, Quest Cherokee entered into a syndicated credit facility arranged and syndicated by UBS Securities LLC, with UBS AG, Stamford Branch as administrative agent (the "UBS Credit Agreement"). The UBS Credit Agreement originally provided for a $120 million nine year term loan that was fully funded at closing (the "UBS Term Loan") and a $20 million five year revolving credit facility that could be used to issue letters of credit and fund future working capital needs and general corporate purposes (the "UBS Revolving Loan"). As of September 30, 2005, Quest Cherokee had approximately $12 million of loans and approximately $2 million in letters of credit issued under the UBS Revolving Loan. Letters of credit issued under the UBS Revolving Loan reduce the amount that can be borrowed there under. The UBS Credit Agreement also contains a $15 million "synthetic" letter of credit facility that matures in December 2008, which provides credit support for Quest Cherokee's natural gas hedging program. A portion of the proceeds from the UBS Term Loan were used to repay the Bank One credit facilities. After the repayment of the Bank One credit facilities and payment of fees and other obligations related to this transaction, Quest Cherokee had approximately $9 million of cash at closing from the proceeds of the UBS Term Loan and $15 million of availability under the UBS Revolving Loan. Interest initially accrued under both the UBS Term Loan and the UBS Revolving Loan, at Quest Cherokee's option, at either (i) a rate equal to the greater of the corporate "base rate" established by UBS AG, Stamford Branch, or the federal funds effective rate plus 0.50% (the "Alternative Base Rate"), plus the applicable margin (3.50% for revolving loans and 4.50% for term loans), or (ii) LIBOR, as adjusted to reflect the maximum rate at which any reserves are required to be maintained against Eurodollar liabilities (the "Adjusted LIBOR Rate"), plus the applicable margin (3.75% for revolving loans and 4.75% for term -7- loans). In connection with the amendment to the UBS Credit Agreement in February 2005 discussed below, the applicable margin on borrowings under the UBS Credit Agreement was increased by 1% until Quest Cherokee's total leverage ratio is less than 4.0 to 1.0. In the event of a default under either the UBS Term Loan or the UBS Revolving Loan, interest will accrue at the applicable rate, plus an additional 2% per annum. Quest Cherokee pays an annual fee on the synthetic letter of credit facility equal to 4.75% of the amount of the facility. The UBS Credit Agreement may be repaid at any time without any premium or prepayment penalty. An amount equal to $300,000 (0.25% of the original principal balance of the UBS Term Loan) is required to be repaid each quarter, commencing December 31, 2004. In addition, Quest Cherokee is required to semi-annually apply 50% of Excess Cash Flow (or 25% of Excess Cash Flow, if the ratio of the present value (discounted at 10%) of the future cash flows from Quest Cherokee's proved mineral interest to Total Net Debt is greater than or equal to 2.25:1.0) to repay the UBS Term Loan. "Excess Cash Flow" for any semi-annual period is generally defined as net cash flow from operations for that period less (1) principal payments of the UBS Term Loan made during the period, (2) the lower of actual capital expenditures or budgeted capital expenditures during the period and (3) permitted tax distributions made during the period or that will be paid within nine months after the period. "Total Net Debt" is generally defined as funded indebtedness (other than the Subordinated Notes) less up to $10 million of unrestricted cash. For the nine month period ended September 30, 2005, the Company did not have any "Excess Cash Flow". The UBS Credit Agreement is secured by a lien on the substantially all of the consolidated assets of Quest Cherokee (other than the pipeline assets owned by Bluestem) and a pledge of the membership interests in Bluestem and Quest Cherokee Oilfield Service, LLC ("QCOS"). The UBS Credit Agreement contains affirmative and negative covenants that are typical for credit agreements of this type. The covenants in the UBS Credit Agreement include provisions requiring the maintenance of and furnishing of financial and other information; the maintenance of insurance, the payment of taxes and compliance with the law; the maintenance of collateral and security interests and the creation of additional collateral and security interests; the maintenance of certain financial ratios (which are described in more detail below); restrictions on the incurrence of additional debt or the issuance of convertible or redeemable equity securities; restrictions on the granting of liens; restrictions on making acquisitions and other investments; restrictions on disposing of assets and merging or consolidating with a third party where Quest Cherokee is not the surviving entity; restrictions on the payment of dividends and the repayment of other indebtedness; restrictions on transactions with affiliates that are not on an arms length basis; and restrictions on changing the nature of Quest Cherokee's business. The UBS Credit Agreement provides that it is an event of default if a "change of control" occurs. A "change of control" is defined to include Bluestem, or any other wholly owned subsidiary of Quest Cherokee no longer being wholly owned by Quest Cherokee; ArcLight and the Company collectively ceasing to own at least 51% of the equity interests and voting stock of Quest Cherokee; or Mr. Cash ceasing to be an executive officer of Quest Cherokee, unless a successor reasonably acceptable to UBS AG, Stamford Branch is appointed within 60 days. In January 2005, Quest Cherokee determined that it was not in compliance with the leverage and interest coverage ratios in the UBS Credit Agreement for the quarter ended November 30, 2004. On February 22, 2005, Quest Cherokee and the lenders under the UBS Credit Agreement entered into an amendment and waiver pursuant to which the lenders waived all of the existing defaults under the UBS Credit Agreement and the UBS Credit Agreement was amended, among other things, as follows: o an additional $12 million of Subordinated Notes to ArcLight was permitted; o the UBS Term Loan was increased by an additional $5 million to a total of $125 million, $3 million of which was used to reduce outstanding borrowings under the revolving credit facility; o the Company cannot drill any new wells until not less than 200 wells have been connected to the Company's gathering system since January 1, 2005 and gross daily production is at least 43 mmcfe/d for 20 of the last 30 days prior to the date of drilling, after which time the Company may drill up to 150 new wells prior to December 31, 2005 as long as the ending inventory of wells-in-progress as of the end of any month does not exceed 250 (as of August 10 , 2005, the Company had connected 207 wells since January 1, 2005 and its average gross daily production for the 20 highest days out of the last 30 days was 37.5 mmcfe/d; o the total leverage ratio for any test period may not exceed: 5.50 to 1.0 for the first quarter of 2005 5.00 to 1.0 for the second quarter of 2005 4.50 to 1.0 for the third quarter of 2005 3.80 to 1.0 for the fourth quarter of 2005 -8- 3.30 to 1.0 for the first quarter of 2006 2.90 to 1.0 for the second quarter of 2006 2.50 to 1.0 for the third quarter of 2006 2.50 to 1.0 for the fourth quarter of 2006 and thereafter; o the minimum asset coverage ratio for any test period may not be less than 1.25 to 1.0; o the minimum interest coverage ratio for any test period may not be less than: 2.70 to 1.0 for each quarter for the year ended December 31, 2005; and 3.50 to 1.0 for each quarter for the year ended December 31, 2006 and thereafter; o the minimum fixed charge coverage ratio for any test period (starting March 2006) may not be less than: 1.00 to 1.0 for each of the first three quarters of 2006; 1.10 to 1.0 for the fourth quarter of 2006; 1.25 to 1.0 for each quarter for the year ended December 31, 2007; and 1.50 to 1.0 for each quarter thereafter; o capital expenditures for any test period may not exceed: $15 million for the first quarter 2005 $7.25 million for the second quarter 2005 $9.5 million for the third quarter 2005 $13.25 million for the fourth quarter 2005 $10 million for each quarter for the year ended December 31, 2006; and the amount of budgeted capital expenditures for 2007 and thereafter; and o until the later of December 31, 2005 and the date on which Quest Cherokee's total leverage ratio is less than 3.5 to 1.0, the UBS Revolving Loan may only be used for working capital purposes. ArcLight Transaction In connection with the Devon asset acquisition, the Company issued a $51 million junior subordinated promissory note to ArcLight (the "Original Note") pursuant to the terms of a note purchase agreement. The Original Note was purchased at par. Quest Cherokee paid a commitment fee of $1,020,000 to obtain this loan. This loan fee has been capitalized as part of the acquisition of assets from Devon. In February 2005, Quest Cherokee issued an additional $12 million of 15% junior subordinated promissory notes (the "Additional Notes" and together with the Original Note, the "Subordinated Notes") to ArcLight. The Subordinated Notes bear interest at 15% per annum and are subordinate and junior in right of payment to the prior payment in full of superior debts. Interest is payable quarterly in arrears; provided, however, that if Quest Cherokee is not permitted to pay cash interest on the Subordinated Notes under the terms of its senior debt facilities, then interest will be paid in the form of additional subordinated notes. Quest Cherokee is currently paying the interest on the Subordinated Notes by issuing additional subordinated notes and the Company is not able at this time to predict when Quest Cherokee may begin paying interest on the Subordinated Notes in cash. The Subordinated Notes, together with all accrued and unpaid interest, are due on the later of October 22, 2010 and the maturity date of the UBS Term Loan, subject to extension until December 22, 2010. In the event that Quest Cherokee is dissolved on or before February 11, 2008 (an "Early Liquidation Event"), the holders of the Subordinated Notes will be entitled to a make-whole payment equal to the difference between the amount they have received on account of principal and interest on the Subordinated Notes and $88.2 million (140% of the funded principal amount of the Subordinated Notes). In the event of an Early Liquidation Event, the holders of the Subordinated Notes are entitled to 100% of the net cash flow until they have received the make-whole payment. Under the UBS Credit Agreement, payments may be made on the Subordinated Notes and distributions may be made to the members of Quest Cherokee only if all of the following conditions have been met: -9- o no default exists on the date any such payment is made, and no default or event of default would result from the payment, under the UBS Credit Agreement. o or the most recent four consecutive quarters, the ratio of the present value (discounted at 10%) of the future cash flows from Quest Cherokee's proved mineral interest to Total Net Debt is at least 1.75:1.0 and the ratio of Total Net Debt to Consolidated EBITDA does not exceed 3.00:1.0, in each case, after giving effect to such payment. "Consolidated EBITDA" is generally defined as consolidated net income, plus interest expense, amortization, depreciation, taxes and non-cash items deducted in computing consolidated net income and minus non-cash items added in computing consolidated net income. o The amount of such semi-annual payments do not exceed Quest Cherokee's Excess Cash Flow during the preceding half of the fiscal year less (1) the amount of Excess Cash Flow required to be applied to repay the UBS Term Loan, and (2) any portion of the Excess Cash Flow that is used to fund capital expenditures. In connection with the purchase of the Subordinated Notes, 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 the Company's subsidiaries were converted into all of the Class B units. Under the terms of the amended and restated limited liability company agreement for Quest Cherokee, the net cash flow of Quest Cherokee will be distributed generally 90% to the holders of the Subordinated Notes and 10% to the holders of the Class B units until the Subordinated Notes have been repaid. Thereafter, the net cash flow of Quest Cherokee will be distributed generally 60% to the holders of the Class A units and 40% to the holders of the Class B units, until the holders of the Subordinated Notes and the Class A units have received a combined internal rate of return of 30% on their cash invested. Thereafter, the net cash flow of Quest Cherokee will be distributed generally 35% to the holders of the Class A units and 65% to the holders of the Class B units. At this time, the Company is unable to predict when it may begin making payments of principal on the Subordinated Notes or when the holders of the Subordinated Notes and Class A units will have received distributions from Quest Cherokee equal to a combined 30% internal rate of return on their cash invested. These percentages may be altered on a temporary basis as a result of certain permitted tax distributions to the holders of the Class B units; however, future distributions will be shifted from the Class B unit holders to the Subordinated Notes and/or the Class A unit holders until the total distributions are in line with the above percentages. Quest Cherokee has the option to issue to ArcLight additional Subordinated Notes in the principal amount of $3 million. If this option is exercised: (i) the interest rate on the Subordinated Notes would increase from 15% to 20%; (ii) the portion of Quest Cherokee's net cash flow that is required to be used to repay the Subordinated Notes would be further increased from 90% to 95%, and the portion of the net cash flow distributable to the Company's subsidiaries, as the holders of all of Quest Cherokee's Class B units, would be further decreased from 10% to 5%, until the Subordinated Notes have been repaid; and (iii) after the Subordinated Notes have been repaid and ArcLight has received a 30% internal rate of return on its investment in Quest Cherokee, Quest Cherokee's net cash flow would be distributed 40% to ArcLight (as the holder of the Class A units) and 60% to the Company's subsidiaries (as the holders of the Class B units). OTHER Between July 20, 2005 and August 10, 2005, the Company sold 400,000 shares of its restricted common stock, par value $0.001 per share, to individual investors in exchange for $2 million cash. The sale of restricted common stock concludes the Company's goal of selling a total of 400,000 shares of restricted common stock. Following the issuance of the 400,000 shares of restricted common stock in the private offering described above, the Company loaned the $2 million in proceeds from the sales to its subsidiary, Quest Cherokee. Quest Cherokee's obligation to repay the Company the $2 million is represented by a promissory note (the "Quest Note") that provides for interest to accrue on the unpaid principal amount of the promissory note at a rate of 15% per annum. The Quest Note's maturity date is October 10, 2010. On August 8, 2005, Quest Cherokee also received a $3.0 million loan from Cherokee Energy Partners LLC ("Cherokee Energy Partners"). Quest Cherokee's obligation to repay the $3.0 million is represented by a promissory note (the "Cherokee -10- Note") that provides for interest to accrue on the unpaid principal at a rate of 15% per annum. The Cherokee Note's maturity date is October 22, 2010. Additionally, on August 8, 2005, the Company and Cherokee Energy Partners entered into an Intercreditor Agreement. Under the agreement, the Company and Cherokee Energy Partners will share pro-rata any amount that Quest Cherokee pays on either the Quest Note or the Cherokee Note, with the Company receiving 40% of any payments and Cherokee Energy Partners receiving 60% of any payments. MANAGEMENT AGREEMENT BETWEEN QES AND QUEST CHEROKEE As part of the restructuring, QES entered into an operating and management agreement with Quest Cherokee to manage the day to day operations of Quest Cherokee in exchange for a monthly manager's fee of $292,000 plus the reimbursement of costs associated with field employees, first level supervisors, exploration, development and operation of the properties and certain other direct charges. Initially, the Company consolidated all of its employees into QES. In September 2004, QCOS was formed to acquire the stimulation assets from Consolidated. At that time, the Company's vehicles and equipment were transferred to QCOS and the costs associated with field employees, first level supervisors, exploration, development and operation of the Company's properties and certain other direct charges are now paid directly by QCOS while QES continues to employ all of the Company's non-field employees (other than first level supervisors). Effective April 30, 2005, the manager's fee was increased to $345,000 per month. Until Quest Cherokee begins making distributions to its members, the Company's only source of cash flow to pay for its general and administrative expenses will be the management fee paid by Quest Cherokee. If the private sale of equity and the ArcLight Purchase Agreement discussed above are closed, the operating and management agreement will be terminated. WELLS FARGO ENERGY CAPITAL WARRANT On November 7, 2002, the Company entered into a credit agreement with Wells Fargo Energy Capital, Inc. ("WFEC"), as lender. In connection with the transaction, the Company issued a warrant to WFEC to acquire up to 640,000 shares of the Company's common stock at a purchase price of $0.001 per share at any time on or before November 7, 2007 (the "Warrant"). On April 6, 2005, WFEC exercised the Warrant with respect to all 640,000 shares of common stock for which the Warrant was exercisable. WFEC elected to do a "cashless exercise" of the Warrant such that the purchase price of $0.001 per share for the 640,000 shares of common stock was paid by WFEC by reducing the number of shares of common stock issuable to WFEC upon such exercise by a number which, when multiplied by the market price of the Company's common stock on the exercise date ($10.00 after giving effect to the reverse stock split) equaled the purchase price. As a result of WFEC's "cashless exercise" of the Warrant, the Company issued to WFEC 639,840 shares of its common stock. CONTRACTUAL OBLIGATIONS Future payments due on the Company's contractual obligations as of September 30, 2005 are as follows:

Total 2005 2006-2007 2008-2009 thereafter ------------- ----------- ----------- ------------ ------------- Term B Note $ 123,800,000 $ 1,200,000 $ 2,400,000 $ 2,400,000 $ 117,800,000 Revolving Line of Credit 12,000,000 -- -- 12,000,000 -- Notes payable 1,370,000 539,000 687,000 52,000 92,000 Convertible debentures 50,000 50,000 -- -- -- Subordinated debt (1) 82,441,000 -- -- -- 82,441,000 ------------- ----------- ----------- ------------ ------------- Total $ 219,661,000 $ 1,789,000 $3,087,000 $ 14,452,000 $ 200,333,000 ============= =========== =========== ============ =============

(1) If interest on the subordinated notes is not paid in cash, it will be added to the principle balance of the subordinated notes and if no payments are made on the subordinated notes, the principle amount would be $196.1 million in 2010. At this time, management is unable to predict when Quest Cherokee will be able to begin making cash payments with respect to the subordinated notes, if the ArcLight Purchase Agreement does not close. Critical Accounting Policies The consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States. As such, the Company is required to make certain estimates, judgments and assumptions that it believes are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. A summary of the significant accounting policies is described in Note 2 to the consolidated financial statements. -11- Off-Balance Sheet Arrangements At September 30, 2005 and December 31, 2004, the Company 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, the Company does not engage in trading activities involving non-exchange traded contracts. As such, the Company is not exposed to any financing, liquidity, market, or credit risk that could arise if the Company had engaged in such activities. Risk Factors Risks Related to Our Business The volatility of natural gas and oil prices could have a material adverse effect on our business. Our revenues, profitability and future growth and the carrying value of our natural gas and oil properties depend to a large degree on prevailing natural gas and oil prices. Our ability to maintain or increase our borrowing capacity and to obtain additional capital on attractive terms also substantially depends upon natural gas and oil prices. Prices for natural gas and oil are subject to large fluctuations in response to relatively minor changes in the supply and demand for natural gas and oil, uncertainties within the market and a variety of other factors in large part beyond our control, such as: o the domestic and foreign supply of natural gas and oil; o the activities of the Organization of Petroleum Exporting Companies; o overall domestic and global economic condition; o the consumption pattern of industrial consumers, electricity generators and residential users; o weather conditions; o natural disasters; o acts of terrorism; o the political stability in the Middle East and elsewhere; o domestic and foreign governmental regulations; o the price of foreign imports; and o the price and availability of alternative fuels. A sharp decline in the price of natural gas and oil prices would result in a commensurate reduction in our revenues, income and cash flows from the production of natural gas and oil and could have a material adverse effect on the carrying value of our proved reserves and our borrowing base. In the event prices fall substantially, we may not be able to realize a profit from our production and would operate at a loss, and even relatively modest drops in prices can significantly affect our financial results and impede our growth. In recent decades, there have been periods of both worldwide overproduction and underproduction of hydrocarbons and periods of both increased and relaxed energy conservation efforts. Such conditions have resulted in periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis. These periods have been followed by periods of short supply of, and increased demand for, crude oil and natural gas. The excess or short supply of natural gas and crude oil has placed pressures on prices and has resulted in dramatic price fluctuations even during relatively short periods of seasonal market demand. Earlier in this decade, natural gas and oil prices were much lower than they are today. Lower natural gas and oil prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of natural gas and oil that we can produce economically. This may result in us having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our natural gas and oil properties for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carry amount may not be recoverable or whenever management's plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken. -12- We face uncertainties in estimating proven recoverable natural gas reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to these reserves, is a function of the available data; assumptions regarding future natural gas and oil prices; expenditures for future development and exploitation activities; and engineering and geological interpretation and judgment. Reserves and future cash flows may also be subject to material downward or upward revisions based upon production history, development and exploitation activities and natural gas and oil prices. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and value of cash flows from those reserves may vary significantly from the assumptions and estimates in this report. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classification of reserves based on risk of recovery, and estimates of the future net cash flows. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same available data. The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs. However, actual future net cash flows from our natural gas and oil properties also will be affected by factors such as: o geological conditions; o changes in governmental regulations and taxation; o assumptions governing future prices; o the amount and timing of actual production; o future operating costs; and o capital costs of drilling new wells. The timing of both our production and our incurrence of expenses in connection with the development and production of natural 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 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 natural gas and oil industry in general. In addition, if natural gas prices decline by $0.10 per mcf, then the pre-tax PV-10 of our proved reserves as of June 30, 2005 would decrease from $382.9 million to $374.3 million. Our future success depends upon our ability to find, develop and acquire additional natural gas reserves that are economically recoverable. The rate of production from natural gas and oil properties declines as reserves are depleted. As a result, we must locate and develop or acquire new natural gas and oil reserves to replace those being depleted by production. We must do this even during periods of low natural gas and oil prices when it is difficult to raise the capital necessary to finance activities. Our future natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to find and develop or acquire additional reserves at an acceptable cost or have necessary financing for these activities in the future. The development of natural gas properties involves substantial risks that may result in a total loss of investment. The business of exploring for and, to a lesser extent, developing and operating natural gas and oil properties involves a high degree of business and financial risks, and thus a substantial risk of investment loss that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The cost of drilling, completing and operating wells is often uncertain, and a number of factors can delay or prevent drilling operations or production, including: o unexpected drilling conditions; -13- o pressure or irregularities in geologic formations; o equipment failures or repairs; o title problems; o fires, explosions, blowouts, cratering, pollution and other environmental risks or other accidents; o adverse weather conditions; o reductions in natural gas and oil prices; o pipeline ruptures; and o unavailability or high cost of drilling rigs, other field services and equipment. A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of natural gas and/or oil 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 natural gas and/or oil in economic quantities. Unsuccessful drilling activities could result in higher costs without any corresponding revenues. Acquisition and completion decisions generally are based on subjective judgments and assumptions that are speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, a successful completion of a well does not ensure a profitable return on the investment. Currently the vast majority of our producing properties are located in a ten county region in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma, making us vulnerable to risks associated with having our production concentrated in one area. The vast majority of our producing properties are geographically concentrated in a ten county region in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by significant governmental regulation, transportation capacity constraints, curtailment of production, natural disasters, adverse weather conditions or interruption of transportation of natural gas produced from the wells in this basin or other events which impact this area. We may suffer losses or incur liability for events for which we or the operator of a property have chosen not to obtain insurance. Our operations are subject to hazards and risks inherent in producing and transporting natural gas and oil, such as fires, natural disasters, explosions, pipeline ruptures, spills, and acts of terrorism, all of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our and others' properties. As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. In addition, pollution and environmental risks generally are not fully insurable. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. In addition, we believe any operators of our properties or properties in which we may acquire an interest will maintain similar insurance coverage. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on our business, financial condition and results of operation. Our use of hedging arrangements could result in financial losses or reduce our income. We currently engage in hedging arrangements to reduce our exposure to fluctuations in the prices of natural gas for a significant portion of our current natural gas production. These hedging arrangements expose us to risk of financial loss in some circumstances, including when production is less than expected; the counter-party to the hedging contract defaults on its contract obligations; or there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received. In addition, these hedging arrangements may limit the benefits we would otherwise receive from increases in prices for natural gas. See "Management's Discussion and Analysis and Results of Operations-- Quantitative and Qualitative Disclosures About Market Risk." -14- Our natural gas sales are dependent on a single customer. We market our own natural gas and more than 95% of our natural gas is sold to ONEOK Energy Marketing and Trading Company ("ONEOK"). In the event that ONEOK were to experience financial difficulties or were to no longer purchase our natural gas, we could, in the short term, experience difficulty in our marketing of natural gas, which could adversely affect our results of operations. We incur risks in acquiring producing properties. We constantly evaluate opportunities to acquire additional natural gas and oil properties and frequently engage in bidding and negotiation for these acquisitions. If successful in this process, we may alter or increase our capitalization through the issuance of additional debt or equity securities, the sale of production payments or other measures. Any change in capitalization affects our risk profile. A change in capitalization, however, is not the only way acquisitions affect our risk profile. Acquisitions may alter the nature of our business. This could occur when the character of acquired properties is substantially different from our existing properties in terms of operating or geologic characteristics. 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 that we have purchased reveals that a natural gas or oil lease has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would be worthless. In such an instance, the amount paid for such natural gas or oil lease or leases would be lost. It is our practice, in acquiring natural gas and oil leases, or undivided interests in natural gas and oil leases, not to undergo 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 will rely upon the judgment of natural gas and oil lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. Prior to the drilling of a natural gas or oil well, however, it is the normal practice in the natural gas and oil industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed natural gas or oil well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such curative work entails expense. The work might include obtaining affidavits of heirship or causing an estate to be administered. Our failure to obtain these rights may adversely impact our ability in the future to increase production and reserves. Our ability to market the natural gas that we produce is essential to our business. Several factors beyond our control may materially adversely affect our ability to market the natural gas and oil that we discover. These factors include the proximity, capacity and availability of natural gas and oil pipelines and processing equipment, the level of domestic production and imports of natural gas and oil, the demand for natural gas and oil by utilities and other end users, the availability of alternative fuel sources, the effect of inclement weather, state and federal regulation of natural gas and oil marketing, market fluctuations of prices, taxes, royalties, land tenure, allowable production and environmental protection. The extent of these factors cannot be accurately predicted, but any one or a combination of these factors may result in our inability to sell our natural gas at prices that would result in an adequate return on our invested capital. We are subject to environmental regulation that can materially adversely affect the timing and cost of our operations. Our exploration and proposed production activities are subject to certain federal, state and local laws and regulations relating to environmental quality and pollution control. These laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation. Specifically, we are subject to legislation regarding the acquisition of permits before drilling, restrictions on drilling activities in restricted areas, emissions into the environment, water discharges, and storage and disposition of hazardous wastes. In addition, legislation has been enacted which requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities. However, such laws and regulations have been frequently changed in the past, and we are unable to predict the ultimate cost of compliance as a result of any future changes. The enactment of stricter legislation or the adoption of stricter regulation could have a significant impact on our operating costs, as well as on the natural gas and oil industry in general. Our internal procedures and policies exist to ensure that our operations are conducted in substantial compliance with all such environmental laws and regulations. However, while we intend to fully comply with all such environmental laws and regulations in the future, such compliance can be very complex, and therefore, no assurances can be given that such environmental laws and regulations will not have a material adverse effect on our business, financial condition and results of operation. -15- Our operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. We could also be liable for environmental damages caused by previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred which could have a material adverse effect on our financial condition and results of operations. We maintain insurance coverage for our operations, but we do not believe that insurance coverage for environmental damages that occur over time, or complete coverage for sudden and accidental environmental damages, is available at a reasonable cost. Accordingly, we may be subject to liability or may lose the privilege to continue exploration or production activities upon substantial portions of our properties if certain environmental damages occur. We are subject to complex governmental regulations which may materially adversely affect the cost of our business. Natural gas and oil exploration, development and production are subject to various types of regulation by local, state and federal agencies. We may be required to make large expenditures to comply with these regulatory requirements. Legislation affecting the natural gas and oil industry is under constant review for amendment and expansion. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Any increases in the regulatory burden on the natural gas and oil industry created by new legislation would increase our cost of doing business and, consequently, adversely affect our profitability. A major risk inherent in drilling is the need to obtain drilling permits from local authorities. Delays in obtaining drilling permits, the failure to obtain a drilling permit for a well or a permit without unreasonable conditions or costs could have a materially adverse effect on our ability to effectively develop our properties. We must obtain governmental permits and approvals for drilling operations, which can be a costly and time consuming process and result in restrictions on our operations. Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in the commencement or continuation of our exploration or production operations. For example, we are often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that proposed exploration for or production of natural gas and oil may have on the environment. Further, the public may comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our operations or to do so profitability. We operate in a highly competitive environment and our competitors may have greater resources than us. The natural gas and oil industry is intensely competitive and we compete with other companies from various regions of the United States and may compete with foreign companies for domestic sales, many of whom are larger and have greater financial, technological, human and other resources. Many of these companies not only explore for and produce crude oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. Such companies may be able to pay more for productive natural gas and oil properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may have a greater ability to continue exploration activities during periods of low hydrocarbon market prices. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. If we are unable to compete, our operating results and financial position may be adversely affected. The coal beds from which we produce methane gas frequently contain water that may hamper our ability to produce gas in commercial quantities. Coal beds frequently contain water that must be removed in order for the gas to detach from the coal and flow to the well bore. Our ability to remove and dispose of sufficient quantities of water from the coal seam will determine whether or not we can produce gas in commercial quantities. The cost of water disposal may affect our profitability. We may have difficulty managing growth in our business. Because of our small size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical 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 experienced managers, geoscientists and engineers, -16- 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 success depends on our key management personnel, the loss of any of whom could disrupt our business. The success of our operations and activities is dependent to a significant extent on the efforts and abilities of our management. The loss of services of any of our key managers could have a material adverse effect on our business. We have not obtained "key man" insurance for any of our management. Mr. Jerry D. Cash is the Chief Executive Officer and Mr. David E. Grose is the Chief Financial Officer. The loss of the services of either of these individuals may adversely affect our business and prospects. Acquisition of entire businesses may be a component of our growth strategy in the future and our failure to complete future acquisitions successfully could reduce our earnings and slow our growth. We might acquire entire businesses in the future. Potential risks involved in the acquisition of such businesses include the inability to continue to identify business entities for acquisition or the inability to make acquisitions on terms that we consider economically acceptable. Furthermore, there is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our strategy of completing acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to pursue our growth strategy may be hindered if we are not able to obtain such financing or regulatory approvals. Our ability to grow through acquisitions and manage growth will require us to continue to invest in operational, financial and management information systems and to attract, retain, motivate and effectively manage our employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods. We may not be able to replace our reserves or generate cash flows if we are unable to raise capital. We make, and will continue to make, substantial capital expenditures for the exploration, acquisition and production of natural gas and oil 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 as a result of lower natural gas and oil prices, operating difficulties or declines in reserves, we may have limited ability to expend the capital necessary to undertake or complete future drilling programs. Additional debt or equity financing or cash generated by operations may not be available to meet these requirements. If we borrow money to expand our business, we will face the risks of leverage. As of September 30, 2005, we had incurred $220 million of indebtedness for borrowed money. If the recapitalization closes as described herein, we would have approximately $101 million of indebtedness for borrowed money. We anticipate that we may in the future incur additional debt for financing our growth. Our ability to borrow funds will depend upon a number of factors, including the condition of the financial markets. Under certain circumstances, the use of leverage may provide a higher return to you on your investment, but will also create a greater risk of loss to you than if we did not borrow. The risk of loss in such circumstances is increased because we would be obligated to meet fixed payment obligations on specified dates regardless of our revenue. If we do not make our debt service payments when due, we may sustain the loss of our equity investment in any of our assets securing such debt, upon the foreclosure on such debt by a secured lender. The interest payable on our debt varies with the movement of interest rates charged by financial institutions. An increase in our borrowing costs due to a rise in interest rates in the market may reduce the amount of income and cash available for the payment of dividends to the holders of our common stock. Because we are relatively small, management expects that we will be disproportionately negatively impacted by recently enacted changes in the securities laws and regulations, which are likely to increase our costs and require additional management resources. The Sarbanes-Oxley Act of 2002 (the "Act"), which became law in July 2002, has required changes in some of our corporate governance, securities disclosure and compliance practices. In response to the requirements of that Act, the SEC has promulgated new rules covering a variety of subjects. Compliance with these new rules has significantly increased our legal and financial and accounting costs, and management expects these increased costs to continue. In addition, the requirements have taxed a significant amount of the time and resources of management and the board of directors. Likewise, these developments may make it more difficult for us to attract and retain qualified members of the board of directors, particularly independent directors, or qualified executive officers. Because we are relatively small, management expects to be disproportionately negatively impacted by these changes in securities laws and regulations which will increase our costs, require additional management resources and may, -17- in the event that we receive anything other than an unqualified report on our internal control over financial reporting, result in greater difficulty in raising funding for our operations and negatively impact our stock price. As directed by Section 404 of the Act, the SEC adopted rules requiring public companies to include a report of management on the company's internal control over financial reporting in their annual reports on Form 10-K that contains an assessment by management of the effectiveness of the company's internal control over financial reporting. In addition, the public accounting firm auditing the company's financial statements must attest to and report on management's assessment of the effectiveness of the company's internal control over financial reporting. This requirement will first apply to our annual report on Form 10-K for the fiscal year ended December 31, 2006. If management is unable to conclude that we have effective internal control over financial reporting or, if our independent auditors are unable to provide us with an unqualified report as to the effectiveness of our internal control over financial reporting as of December 31, 2006 and future year-ends as required by Section 404 of the Act, investors could lose confidence in the reliability of our financial statements, which could result in a decrease in the value of our securities. We are a small company with limited resources. The number and qualifications of our finance and accounting staff are limited, and we have limited monetary resources. We experience difficulties in attracting qualified staff with requisite expertise due to our profile and a generally tight market for staff with expertise in these areas. Furthermore, guidance from relevant regulatory bodies and others in the field is evolving and being refined on an ongoing basis, creating difficulties in attempting to assure all matters are addressed in a timely manner. We have retained a consultant to assist us in the process of testing and evaluating the internal control over financial reporting. A key risk is that management will not timely remediate any deficiencies that may be identified as part of the review process. Risks Relating to Our Common Stock Our common stock does not trade in a mature market and therefore has limited liquidity. Our common stock trades on the over-the-counter market, and such trading has been sporadic and erratic. Holders of our common stock may not be able to liquidate their investments in a short time period or at the market prices that currently exist at the time a holder decides to sell. Because of this limited liquidity, it is unlikely that shares of our common stock will be accepted by lenders as collateral for loans. There is no established trading market for our common stock. We cannot assure you as to: o the likelihood that an active market will develop for the shares of our common stock; o the liquidity of any such market; o the ability of our stockholders to sell their shares of our common stock; or o the price that our stockholders may obtain for their shares of our common stock. Our stock price may be volatile. The following factors could affect our stock price: o our operating and financial performance and prospects; o quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues; o changes in revenue or earnings estimates or publication of research reports by analysts about us or the exploration and production industry; o liquidity and registering our common stock for public resale; o actual or anticipated variations in our reserve estimates and quarterly operating results; o changes in natural gas and oil prices; o speculation in the press or investment community; o sales of our common stock by significant stockholders; o actions by institutional investors before disposition of our common stock; -18- o increases in our cost of capital; o changes in applicable laws or regulations, court rulings and enforcement and legal actions; o changes in market valuations of similar companies; o adverse market reaction to any increased indebtedness we incur in the future; o additions or departures of key management personnel; o actions by our stockholders; o general market conditions, including fluctuations in and the occurrence of events or tends affecting the price of natural gas and oil; and o domestic and international economic, legal and regulatory factors unrelated to our performance. It is unlikely that we will be able to pay dividends on the 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, we anticipate that the New Credit Facility will prohibit us from paying any dividend to the holders of our common stock without the consent of the lenders under the New Credit Facility. The percentage ownership evidenced by the common stock is subject to dilution. We are authorized to issue up to 380,000,000 shares of common stock and can issue 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 us subsequent to this report. The common stock is an unsecured equity interest. As an equity interest, the common stock will not be secured by any of our assets. Therefore, in the event of our liquidation, the holders of the common stock will receive a distribution only after all of our secured and unsecured creditors have been paid in full and the holders of the Series A Preferred Stock have been paid their liquidation preference. There can be no assurance that we will have sufficient assets after paying our secured and unsecured creditors and the holders of the Series A Preferred Stock to make any distribution to the holders of the common stock. Provisions in Nevada law and provisions in our articles of incorporation and bylaws could delay or prevent a change in control, even if that change would be beneficial to our stockholders. Certain provisions of Nevada law and certain provisions included in our articles of incorporation and bylaws 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. Nevada Law. The provisions of Nevada law, which are described below, as well as our ability to issue preferred stock, 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. We believe that the benefits of increased protection give us the potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us, and that the benefits of this increased protection outweigh the disadvantages of discouraging those proposals, because negotiation of those proposals could result in an improvement of their terms. The Nevada Revised Statutes (the "NRS") contain two provisions, described below as "Combination Provisions" and the "Control Share Act," that may make more difficult the accomplishment of unsolicited or hostile attempts to acquire control of us through certain types of transactions. -19- Restrictions on Certain Combinations Between Nevada Resident Corporations and Interested Stockholders. The NRS includes certain provisions (the "Combination Provisions") 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. The Combination Provisions apply unless the corporation elects against their application in its original articles of incorporation or an amendment thereto. Our articles of incorporation does not currently contain a provision rendering the Combination Provisions inapplicable. Nevada Control Share Act. Nevada's Acquisition of Controlling Interest statutes (the "Control Share Act") imposes procedural hurdles on and curtails greenmail practices of corporate raiders. The Control Share Act temporarily disenfranchises the voting power of "control shares" of a person or group ("Acquiring Person") purchasing a "controlling interest" in an "issuing corporation" (as defined in the NRS) not opting out of the Control Share Act. In this regard, the Control Share Act will apply to an "issuing corporation", unless the articles of incorporation or bylaws in effect on the tenth day following the acquisition of a controlling interest provide that it is inapplicable. Our articles of incorporation and bylaws do not currently contain a provision rendering the Control Share Act inapplicable. Under the Control Share Act, an "issuing corporation" is a corporation organized in Nevada which has 200 or more stockholders of record, at least 100 of whom have addresses in that state appearing on the company's stock ledger, and which does business in Nevada directly or through an affiliated company. Our status at the time of the occurrence of a transaction governed by the Control Share Act (assuming that our articles of incorporation or bylaws have not theretofore been amended to include an opting out provision) would determine whether the Control Share Act is applicable. We do not currently conduct any business in Nevada directly or through an affiliated company. The Control Share Act requires an Acquiring Person to take certain procedural steps before he or it can obtain the full voting power of the control shares. "Control shares" are the shares of a corporation (1) acquired or offered to be acquired which will enable the Acquiring Person to own a "controlling interest," and (2) acquired within 90 days immediately preceding that date. A "controlling interest" is defined as the ownership of shares which would enable the Acquiring Person to exercise certain graduated amounts (beginning with one-fifth) of all voting power of the corporation in the election of directors. The Acquiring Person may not vote any control shares without first obtaining approval from the stockholders not characterized as "interested stockholders" (as defined below). To obtain voting rights in control shares, the Acquiring Person must file a statement at the principal office of the issuer ("Offeror's Statement") setting forth certain information about the acquisition or intended acquisition of stock. The Offeror's Statement may also request a special meeting of stockholders to determine the voting rights to be accorded to the Acquiring Person. A special stockholders' meeting must then be held at the Acquiring Person's expense within 30 to 50 days after the Offeror's Statement is filed. If a special meeting is not requested by the Acquiring Person, the matter will be addressed at the next regular or special meeting of stockholders. At the special or annual meeting at which the issue of voting rights of control shares will be addressed, "interested stockholders" may not vote on the question of granting voting rights to control the corporation or its parent unless the articles of incorporation of the issuing corporation provide otherwise. Our articles of incorporation and bylaws do not currently contain a provision allowing for such voting power. If full voting power is granted to the Acquiring Person by the disinterested stockholders, and the Acquiring Person has acquired control shares with a majority or more of the voting power, then (unless otherwise provided in the articles of incorporation or bylaws in effect on the tenth day following the acquisition of a controlling interest) all stockholders of record, other than the Acquiring Person, who have not voted in favor of authorizing voting rights for the control shares, must be sent a notice advising them of the fact and of their right to receive "fair value" for their shares. Our articles of incorporation and bylaws do not provide otherwise. By the date set in the dissenter's notice, which may not be less than 30 nor more than 60 days after the dissenter's notice is delivered, any such stockholder may demand to receive from the corporation the "fair value" for all or part of his shares. "Fair value" is defined in the Control Share Act as "not less than the highest price per share paid by the Acquiring Person in an acquisition." The Control Share Act permits a corporation to redeem the control shares in the following two instances, if so provided in the articles of incorporation or bylaws of the corporation in effect on the tenth day following the acquisition of a controlling interest: (1) if the Acquiring Person fails to deliver the Offeror's Statement to the corporation within 10 days after the Acquiring -20- Person's acquisition of the control shares; or (2) an Offeror's Statement is delivered, but the control shares are not accorded full voting rights by the stockholders. Our articles of incorporation and bylaws do not address this matter. Articles of Incorporation Provisions. ------------------------------------ Classified Board. The number of directors on our board of directors was recently increased to six. Under our articles of incorporation, when the board of directors consists of six or more directors, the board shall be classified into three classes. Mr. Garrison and Mr. Rateau have been designated Class 1 directors, Mr. White and Mr. Irani have been designated Class 2 directors and Mr. Clark and Mr. Kite have been designated Class 3 directors. The initial term of office of the Class 1 directors will be for a one-year term, the initial term of the Class 2 directors will be for a two-year term, and the initial term of the Class 3 directors will be for a three-year term. Following each initial term, each class of directors will serve for a term of three years and until their successors are elected and qualified. Because a third party will not be able to gain control of our board of directors through a proxy contest, this provision may have the effect of discouraging or deterring a third party from conducting a solicitation of proxies to elect its own slate of directors, without regard to whether consideration of such nominees might be harmful or beneficial to us or our stockholders. Stockholder Nomination of Directors. Our articles of incorporation require advance notice of all stockholders' nominations for election of directors. Stockholders will be required to deliver prior written notice of any director nomination: o no less than 14 days and no more than 50 days before the meeting date, or o if less than 21 days' notice or public disclosure of the meeting date is given to stockholders, no later than 7 days after the notice of meeting date is mailed or publicly announced, whichever occurs first. Such notice must be accompanied by specific information of the sort needed by us for inclusion in any proxy materials in accordance with the Exchange Act. No nominee will be considered at a meeting of the stockholders unless nominated in accordance with the procedures set forth in the articles of incorporation. Accordingly, this provision may have the effect of precluding or delaying a contest for the election of directors if the designated procedures are not followed. Blank-Check Preferred Stock. Under our articles of incorporation, we are authorized to issue 50 million shares of preferred stock, $0.001 par value. These shares may be divided into any series of preferred stock as our board of directors determines. The preferred stock may be issued from time to time in one or more series, each of which is to have the voting powers, designation, preferences and relative, participating, optional or other special rights and qualifications, limitations or restrictions established by our board of directors. See "--Shareholder Rights Plan." Bylaw Provisions. ---------------- Advance Notice Provision; Stockholder Nomination of Directors. Stockholders are required to deliver prior written notice to us of any proposal that they intend to present at a stockholders' meeting: o no less than 50 days and no more than 75 days before the meeting date, or o if less than 65 days' notice or public disclosure of the meeting date is given to stockholders, no later than 15 days after the notice of meeting date is mailed or publicly announced, which ever occurs first. Our bylaws also contain a stockholder nomination of directors provision which conforms to the notice provisions contained in our articles of incorporation and which is summarized under "--Articles of Incorporation Provisions." These notices must be accompanied by specific information of the sort needed by us for inclusion in any proxy materials prepared in accordance with the Exchange Act. No nominee or shareholder proposal will be considered at a meeting of the stockholders unless nominated or proposed in accordance with the procedures set forth in these provisions. Accordingly, these provisions may have the effect of precluding or delaying a contest for the election of directors or the consideration of stockholder proposals if the designated procedures are not followed. Such provisions may have the effect of discouraging or deterring a third party from conducting a solicitation of proxies to elect its own slate of directors or to approve its own proposal, without regard to whether consideration of such nominees or proposals might be harmful or beneficial to us or our stockholders. Who May Call a Special Meeting of Stockholders. Our bylaws permit only our Chairman of the board of directors, our President and the board of directors to call a special meeting of stockholders. The purpose of this provision is to avoid the time, expense and disruption resulting from holding special meetings of stockholders in addition to annual meetings, unless the special -21- meetings are approved by us or the board of directors. However, this provision may have the effect of delaying a change in control of us or delaying the presentation to the stockholders of a stockholder proposal favored by certain stockholders. Stockholder Action Other Than at a Meeting Requires Unanimous Consent. Our bylaws permit stockholders to take action without a meeting only upon the unanimous consent of all stockholders. Item 3. Quantitative and Qualitative Disclosures About Market Risk Hedging Activities. The Company seeks to reduce its exposure to unfavorable changes in natural gas prices, which are subject to significant and often volatile fluctuation, through the use of fixed-price contracts. The fixed-price contracts are comprised of energy swaps and collars. These contracts allow the Company to predict with greater certainty the effective natural gas prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. Collar structures provide for participation in price increases and decreases to the extent of the ceiling and floor prices provided in those contracts. For the nine months ended September 30, 2005, fixed-price contracts hedged 90.0% of the Company's natural gas production. As of September 30, 2005, fixed-price contracts are in place to hedge 16.2 Bcf of estimated future natural gas production. Of this total volume, 2.2 Bcf are hedged for 2005 and 14.0 Bcf thereafter. Reference is made to the Annual Report on Form 10-KSB/A (Amendment No. 2) for the seven-month transition period ended December 31, 2004 for a more detailed discussion of the fixed-price contracts. The Company's fixed price contracts are tied to commodity prices on the New York Mercantile Exchange ("NYMEX"), that is, the Company receives the fixed price amount stated in the contract and pays to its counterparty the current market price for gas as listed on the NYMEX. However, due to the geographic location of the Company's natural gas assets and the cost of transporting the natural gas to another market, the amount that the Company receives when it actually sells its natural gas is based on the Southern Star first of month index. The difference between natural gas prices on the NYMEX and on the Southern Star first of month index is referred to as a basis differential. Typically, the price for natural gas on the Southern Star first of month index is less than the price on the NYMEX due to the more limited demand for natural gas on the Southern Star first of month index. Recently, the basis differential has been increasingly volatile and has on occasion resulted in the Company receiving a net price for its natural gas that is significantly below the price stated in the fixed price contract. The following table summarizes the estimated volumes, fixed prices, fixed-price sales and fair value attributable to the fixed-price contracts as of September 30, 2005.

Three Ending Years Ending December 31, December 31, --------------- ---------------- ---------------- 2005 2006 2007 2008 Total ---- ---- ---- ---- ----- (dollars in thousands, except price data) Natural Gas Swaps: Contract vols (MMBtu) 1,562,000 5,615,000 - - 7,177,000 Weighted-avg. fixed price per MMBtu (1) $ 4.64 $ 4.49 - - $ 4.52 Fixed-price sales $ 7,255 $ 25,203 - - $ 32,458 Fair value, net $ (14,720) $ (39,320) - - $ (54,040) Natural Gas Collars: Contract vols (MMBtu): Floor 584,000 1,825,000 3,650,000 2,928,000 8,987,000 Ceiling 584,000 1,825,000 3,650,000 2,928,000 8,987,000 Weighted-avg fixed price per MMBtu (1): Floor $ 5.47 $ 5.30 $ 4.83 $ 4.50 $ 4.86 Ceiling $ 6.52 $ 6.35 $ 5.83 $ 5.52 $ 5.88 Fixed-price sales (2) $ 3,808 $ 11,589 $ 21,279 $ 16,163 $ 52,839 Fair value, net $ (2,797) $ (9,303) $ (12,861) $ (7,583) $ (32,544) Total Natural Gas Contracts: Contract vols (MMBtu) 2,146,000 7,440,000 3,650,000 2,928,000 16,164,000 Weighted-avg fixed price per MMBtu (1) $ 5.15 $ 4.95 $ 5.83 $ 5.52 $ 5.28 Fixed-price sales (2) $ 11,063 $ 36,792 $ 21,279 $ 16,163 $ 85,297 Fair value, net $ (17,517) $ (48,623) $ (12,861) $ (7,583) $ (86,584)

-22- (1) The prices to be realized for hedged production are expected to vary from the prices shown due to basis. (2) Assumes ceiling prices for natural gas collar volumes. The estimates of fair value of the fixed-price contracts are computed based on the difference between the prices provided by the fixed-price contracts and forward market prices as of the specified date, as adjusted for basis. Forward market prices for natural gas are dependent upon supply and demand factors in such forward market and are subject to significant volatility. The fair value estimates shown above are subject to change as forward market prices and basis change. See - "Fair Value of Financial Instruments". All fixed-price contracts have been executed in connection with the Company's natural gas hedging program. The differential between the fixed price and the floating price for each contract settlement period multiplied by the associated contract volume is the contract profit or loss. For fixed-price contracts qualifying as cash flow hedges pursuant to SFAS 133, the realized contract profit or loss is included in oil and gas sales in the period for which the underlying production was hedged. For the three months ended September 30, 2005 and 2004, oil and gas sales included $6.3 million and $949,000, respectively, of losses associated with realized losses under fixed-price contracts. For the nine months ended September 30, 2005 and 2004, oil and gas sales included $11.7 million and $2.4 million, respectively, of losses associated with realized losses under fixed-price contracts. For contracts that did not qualify as cash flow hedges, the realized contract profit and loss is included in other revenue and expense in the period for which the underlying production was hedged. For the three months ended September 30, 2005 and 2004, other revenue and expense included $0 and $105,000, respectively, of losses associated with realized losses under fixed-price contracts. For the nine months ended September 30, 2005 and 2004, other revenue and expense included $0 and $632,000, respectively, of losses associated with realized losses under fixed-price contracts. For fixed-price contracts qualifying as cash flow hedges, changes in fair value for volumes not yet settled are shown as adjustments to other comprehensive income. For those contracts not qualifying as cash flow hedges, changes in fair value for volumes not yet settled are recognized in change in derivative fair value in the statement of operations. The fair value of all fixed-price contracts are recorded as assets or liabilities in the balance sheet. Based upon market prices at September 30, 2005, the estimated amount of unrealized losses for fixed-price contracts shown as adjustments to other comprehensive income that are expected to be reclassified into earnings as actual contract cash settlements are realized within the next 12 months is $55.3 million. Interest Rate Hedging Activities The Company has entered into interest rate swaps and caps designed to hedge the interest rate exposure associated with borrowings under the UBS Credit Agreement. All interest rate swaps and caps have been executed in connection with the Company's interest rate hedging program. The differential between the fixed rate and the floating rate multiplied by the notional amount is the swap gain or loss. This gain or loss is included in interest expense in the period for which the interest rate exposure was hedged. For interest rate swaps and caps qualifying as cash flow hedges, changes in fair value of the derivative instruments are shown as adjustments to other comprehensive income. For those interest rate swaps and caps not qualifying as cash flow hedges, changes in fair value of the derivative instruments are recognized in change in derivative fair value in the statement of operations. All changes in fair value of the Company's interest rate swaps and caps are reported in results of operations rather than in other comprehensive income because the critical terms of the interest rate swaps and caps do not comply with certain requirements set forth in SFAS 133. The fair value of all interest rate swaps and caps are recorded as assets or liabilities in the balance sheet. Based upon market prices at September 30, 2005, the estimated amount of unrealized gains for interest rate swaps and caps shown as adjustments to change in derivative fair value in the statement of operations that are expected to be reclassified into earnings as actual contract cash settlements are realized within the next 12 months is $440,000. At September 30, 2005, the Company had outstanding the following interest rate swaps and caps:

Notional Fixed Rate Floating Fair Value as of Instrument Type Term Amount (1) / Cap Rate Rate September 30, 2005 ------------------------ ----------------------------- -------------------- ------------- ------------- ---------------------- $58,250,000 3-month Interest Rate Swap March 2005 - March 2006 $53,875,000 2.795% LIBOR $ 368,000 $98,705,000 3-month Interest Rate Cap March 2006 - Sept. 2007 $70,174,600 5.000% LIBOR $ 208,000

-23- (1) Represents the maximum and minimum notional amounts that are hedged during the period. Change in Derivative Fair Value Change in derivative fair value in the statements of operations for the three months and nine months ended September 30, 2005 and 2004 is comprised of the following:

Three Months Ended Nine Months Ended September 30, September 30, -------------------------------------------------------------- 2005 2004 2005 2004 -------------------------------------------------------------- Change in fair value of derivatives not qualifying as cash flow hedges $ 739,000 $ 972,000 $ 557,000 $(3,954,000) Amortization of derivative fair value gains and losses recognized in earnings prior to actual cash settlements (36,000) 284,000 111,000 1,257,000 Ineffective portion of derivatives qualifying as cash flow hedges (806,000) (324,000) 547,000 (1,491,000) -------------------------------------------------------------- $ (103,000) $ 932,000 $ 1,215,000 $(4,188,000) ==============================================================

The amounts recorded in change in derivative fair value do not represent cash gains or losses. Rather, they are temporary valuation swings in the fair value of the contracts. All amounts initially recorded in this caption are ultimately reversed within this same caption over the respective contract terms. The change in carrying value of fixed-price contracts and interest rate swaps and caps in the balance sheet since December 31, 2004 resulted from an increase in market prices for natural gas and interest rates. Fair Value of Financial Instruments The following information is provided regarding the estimated fair value of the financial instruments, including derivative assets and liabilities as defined by SFAS 133 that the Company held as of September 30, 2005 and December 31, 2004 and the methods and assumptions used to estimate their fair value:

September 30, 2005 December 31, 2004 ------------------ ------------------ Derivative assets: Interest rate swaps and caps $ 576,000 $ 523,000 Derivative liabilities: Fixed-price natural gas collars $ (32,544,000) $ (4,802,000) Fixed-price natural gas swaps $ (54,040,000) $ (17,675,000) Bank debt $ (135,800,000) $ (134,700,000) Other financing agreements $ (1,420,000) $ (1,763,000) Subordinated debt (inclusive of accrued interest) $ (82,441,000) $ (59,325,000)

The carrying amount of cash, receivables, deposits, accounts payable and accrued expenses approximates fair value due to the short maturity of those instruments. The carrying amounts for convertible debentures and notes payable approximate fair value because the interest rates have remained generally unchanged since the issuance of the convertible debentures and due to the variable nature of the interest rates of the notes payable. The fair value of all derivative instruments as of September 30, 2005 and December 31, 2004 was based upon estimates determined by our counter-parties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, futures prices, volatility, and time to maturity and credit risk. The values reported in the financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors. Derivative assets and liabilities reflected as current in the September 30, 2005 balance sheet represent the estimated fair value of fixed-price contract and interest rate swap and cap settlements scheduled to occur over the subsequent twelve-month period based on market prices for natural gas and fluctuations in interest rates as of the balance sheet date. The offsetting increase in value of the hedged future production has not been accrued in the accompanying balance sheet. The contract settlement amounts are not due and payable until the monthly period that the related underlying hedged transaction occurs. In some cases the recorded liability for certain contracts significantly exceeds the total settlement amounts that would be paid to a counterparty based on prices in effect at the balance sheet date due to option time value. Because the Company expects to hold the remaining contracts to maturity, this time value component with respect to these contracts has no direct relationship to actual future contract settlements and consequently does not represent a liability that will be settled in cash or realized in any way. -24- The Company has terminated the interest rate swaps and has agreed to receive as settlement for the instrument, an amount of approximately $378,000. The interest rate caps will continue to remain in effect. Credit Risk Energy swaps and collars and interest rate swaps and caps provide for a net settlement due to or from the respective party as discussed previously. The counterparties to the derivative contracts are a financial institution and a major energy corporation. Should a counterparty default on a contract, there can be no assurance that the Company would be able to enter into a new contract with a third party on terms comparable to the original contract. The Company has not experienced non-performance by its counterparties. Cancellation or termination of a fixed-price contract would subject a greater portion of the Company's natural gas production to market prices, which, in a low price environment, could have an adverse effect on its future operating results. Cancellation or termination of an interest rate swap or cap would subject a greater portion of the Company's long-term debt to market interest rates, which, in an inflationary environment, could have an adverse effect on its future net income. In addition, the associated carrying value of the derivative contract would be removed from the balance sheet. Market Risk The differential between the floating price paid under each energy swap contract and the price received at the wellhead for the Company's production is termed "basis" and is the result of differences in location, quality, contract terms, timing and other variables. The effective price realizations that result from the fixed-price contracts are affected by movements in basis. Basis movements can result from a number of variables, including regional supply and demand factors, changes in the portfolio of the Company's fixed-price contracts and the composition of its producing property base. Basis movements are generally considerably less than the price movements affecting the underlying commodity, but their effect can be significant. Changes in future gains and losses to be realized in natural gas and oil sales upon cash settlements of fixed-price contracts as a result of changes in market prices for natural gas are expected to be offset by changes in the price received for hedged natural gas production. Item 4. Controls and Procedures. As of September 30, 2005, the Company's management, including the Chief Executive Officer and the Chief Financial Officer, evaluated the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. Based upon and as of the date of the evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the design and operation of the Company's disclosure controls and procedures were effective in all material respects to provide reasonable assurance that information required to be disclosed in the reports that the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and is accumulated and communicated to Quest's management, including Quest's Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. It should be noted, however, that no matter how well designed and operated, a control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events. Because of these and other inherent limitations of control systems (including faulty judgments in decision making or breakdowns resulting from simple errors or mistakes), there can be no assurance that any design will succeed in achieving its stated goals under all potential conditions. Additionally, controls can be circumvented by individual acts, collusion or by management override of the controls in place. There has been no change in the Company's internal control over financial reporting during the quarter ended September 30, 2005 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting. PART II -OTHER INFORMATION Item 1. Legal Proceedings See Part I, Item 1, Note 6 to our consolidated financial statements entitled "Commitments and Contingencies", which is incorporated herein by reference. -25- In addition, the Company, from time to time, may be subject to legal proceedings and claims that arise in the ordinary course of its business. Although no assurance can be given, management believes, based on its experiences to date, that the ultimate resolution of such items will not have a material adverse impact on the Company's business, financial position or results of operations. Item 2. Unregistered Sales of Equity Securities and Use of Proceeds None Item 3. Default Upon Senior Securities None Item 4. Submission of Matters to Vote of Security Holders None Item 5. Other Information None Item 6. Exhibits 10.1 Intercompany Note dated July 20, 2005 of Quest Cherokee in the original principal amount of up to $3,000,000 payable to the order of the Company 10.2 Intercreditor Agreement dated July 20, 2005 among the Company, Cherokee and Cherokee Energy Partners 10.3 Promissory Note dated August 5, 2005 of Quest Cherokee in the original principal amount of up to $3,000,000 payable to the order of Cherokee Energy Partners 10.4 Termination of Intercreditor Agreement dated as of August 5, 2005 between the Company, Quest Cherokee and Cherokee Energy Partners LLC 10.5 Intercreditor Agreement dated as of August 5, 2005 among the Company, Quest Cherokee and Cherokee Energy Partners, LLC 31.1 Certification by Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification by Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1 Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. -26- SIGNATURES In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized this 14th day of November, 2005. QUEST RESOURCE CORPORATION By: /s/ Jerry D. Cash ------------------------------- Jerry D. Cash Chief Executive Officer By: /s/ David E. Grose ------------------------------- David E. Grose Chief Financial Officer -27-