10-Q/A 1 qr-form10qa_6540562v4.txt FORM 10-Q/A MARCH 31, 2005 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q/A (Amendment No. 1) (Mark One) [X] Quarterly report under Section 13 or 15(d) of the Securities Exchange Act of 1934 For the quarterly period ended March 31, 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] As of May 13, 2005, the issuer had 14,249,694 shares of common stock outstanding. -1- This Form 10-Q/A (Amendment No. 1) is being filed by Quest Resource Corporation to amend its Form 10-Q for the fiscal quarter ended March 31, 2005, filed with the Securities and Exchange Commission (the "SEC") on May 17, 2005. This Amendment No. 1 reflects certain revisions in response to comments received from the SEC. The following items in Part I of this Amendment No. 1 have been modified: 1. Item 1 - Financial Statements - Footnotes 2 and 5; 2. Item 2 - Management's Discussion and Analysis of Financial Condition and Results of Operations; and 3. Item 4 - Controls and Procedures. This Amendment No. 1 also contains updated certifications from our Chief Executive Officer and Chief Financial Officer, as required by Sections 302 and 906 of the Sarbanes-Oxley Act of 2002. -2- QUEST RESOURCE CORPORATION FORM 10-Q/A (Amendment No. 1) FOR THE QUARTER ENDED MARCH 31, 2005 TABLE OF CONTENTS PART I - FINANCIAL INFORMATION.................................................4 Item 1. Financial Statements...........................................4 Consolidated Balance Sheets: March 31, 2005 and December 31, 2004.....................F-1 Consolidated Statements of Operations and Comprehensive Income: Three months ended March 31, 2005 and 2004...............F-3 Consolidated Statements of Cash Flows: Three months ended March 31, 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.....................................5 Forward-looking Information....................................5 Business of Issuer.............................................5 Significant Developments during the three months ended March 31, 2005................5 Results of Operations..........................................5 Liquidity and Capital Resources................................6 Item 3. Quantitative and Qualitative Disclosures About Market Risk....12 Item 4. Controls and Procedures.......................................15 PART II - OTHER INFORMATION...................................................15 Item 1. Legal Proceedings.............................................15 Item 2. Unregistered Sales of Equity Securities and Use of Proceeds...15 Item 3. Defaults Upon Senior Securities...............................15 Item 4. Submission of Matters to a Vote of Security Holders...........16 Item 5. Other Information.............................................16 Item 6. Exhibits......................................................16 SIGNATURES....................................................................17 -3- 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 fiscal quarter ended March 31, 2005, a statement of operations, and a statement of cash flows for the interim period up to the date of such balance sheet and the comparable period of the preceding fiscal year, are attached hereto as Pages F-1 through F-17 and are incorporated herein by this reference. The financial statements included herein have been prepared internally, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission and the Public Company Accounting Oversight Board. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been omitted. However, in our opinion, all adjustments (which include only normal recurring accruals) necessary to fairly present the financial position and results of operations have been made for the periods presented. The 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. 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. -4-

QUEST RESOURCE CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS March 31, December 31, 2005 2004 -------------- ------------- A S S E T S (unaudited) Current assets: Cash $ 4,448,000 $ 6,458,000 Accounts receivable, trade 6,053,000 6,204,000 Other receivables 525,000 524,000 Other current assets 665,000 241,000 Short-term derivative asset 502,000 202,000 Inventory 379,000 284,000 -------------- -------------- Total current assets 12,572,000 13,913,000 Property and equipment, net of accumulated depreciation of $1,470,000 and $1,245,000, respectively 8,734,000 8,433,000 Pipeline assets, net of accumulated depreciation of $2,405,000 and $2,207,000, respectively 43,902,000 42,552,000 Pipeline assets under construction 15,019,000 12,537,000 Oil and gas properties: Properties being amortized 163,568,000 154,427,000 Properties not being amortized 17,221,000 16,707,000 -------------- -------------- 180,789,000 171,134,000 Less: Accumulated depreciation, depletion and amortization (19,192,000) (16,069,000) -------------- -------------- Net property, plant and equipment 161,597,000 155,065,000 Other assets, net 5,292,000 5,141,000 Long-term derivative asset 340,000 321,000 -------------- -------------- Total assets $ 247,456,000 $ 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 $ 12,836,000 $ 17,337,000 Oil and gas payable 3,144,000 3,507,000 Accrued expenses 388,000 588,000 Current portion of notes payable 2,119,000 1,804,000 Short-term derivative liability 22,194,000 9,513,000 -------------- -------------- Total current liabilities 40,681,000 32,749,000 Non-current liabilities: Long-term derivative liability 20,757,000 12,964,000 Asset retirement obligation 938,000 871,000 Convertible debentures 50,000 50,000 Notes payable 138,312,000 136,413,000 Less current maturities (2,119,000) (1,804,000) -------------- -------------- Non-current liabilities 157,938,000 148,494,000 Subordinated debt (including accrued interest) 73,723,000 59,325,000 Deferred income tax payable - -- -------------- -------------- Total liabilities 272,342,000 240,568,000 -------------- -------------- 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, 950,000,000 shares authorized 14,249,694 and 14,021,036 shares issued and outstanding 14,000 14,000 The accompanying notes are an integral part of these consolidated statements. F-1

Additional paid in capital 17,184,000 17,184,000 Accumulated other comprehensive loss (32,323,000) (11,143,000) Accumulated deficit (9,761,000) (8,661,000) -------------- -------------- Total stockholders' equity (deficit) (24,886,000) (2,606,000) -------------- -------------- Total liabilities and stockholders' equity (deficit) $ 247,456,000 $ 237,962,000 ============== ============== The accompanying notes are an integral part of these consolidated statements.

F-2 QUEST RESOURCE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (UNAUDITED)

Three months ended March 31, ------------------------------- 2005 2004 -------------- -------------- Revenue: Oil and gas sales $ 11,266,000 $ 10,782,000 Gas pipeline revenue 806,000 760,000 Other revenue and (expense) (21,000) 6,000 -------------- -------------- Total revenues 12,051,000 11,548,000 Costs and expenses: Oil and gas production 2,309,000 2,439,000 Pipeline operating 1,770,000 1,202,000 General and administrative 971,000 983,000 Depreciation, depletion and amortization 3,354,000 3,277,000 -------------- -------------- Total costs and expenses 8,404,000 7,901,000 -------------- -------------- Operating income 3,647,000 3,647,000 -------------- -------------- Other income (expense): Change in derivative fair value 444,000 (5,913,000) Interest income 4,000 -- Interest expense (5,193,000) (3,380,000) ---------------- -------------- Total other expense (4,745,000) (9,293,000) ---------------- -------------- Loss before income taxes (1,098,000) (5,646,000) Income tax expense - deferred - - -------------- -------------- Net loss (1,098,000) (5,646,000) -------------- -------------- Other comprehensive loss, net of tax: Change in fixed-price contract and other derivative fair value, net of tax of $0 and $0 (23,410,000) (1,027,000) Reclassification adjustments - contract settlements, net of tax of $0 and $0 2,230,000 692,000 -------------- -------------- Other comprehensive loss (21,180,000) (335,000) -------------- -------------- Comprehensive loss (22,278,000) (5,981,000) -------------- -------------- Net loss (1,098,000) (5,646,000) Preferred stock dividends (2,000) (2,000) -------------- -------------- Net loss available to common shareholders $ (1,100,000) $ (5,648,000) ============== ============== Earnings (loss) per common share - basic: Loss $ (0.08) $ (0.40) ============== ============== Earnings (loss) per common share - diluted: Loss $ (0.08) $ (0.40) ============== ============== Weighted average common and common equivalent shares outstanding: Basic 14,249,694 14,021,306 Diluted 14,249,694 14,021,306

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

Three Months Ended ------------------------------- March 31, March 31, 2005 2004 -------------- -------------- Cash flows from operating activities: Net (loss) $ (1,098,000) $ (5,646,000) Adjustments to reconcile net income (loss) to cash provided by operations: Depreciation and depletion 3,559,000 3,277,000 Change in derivative fair value (444,000) 5,913,000 Accrued interest on subordinated note 2,399,000 1,929,000 Amortization of loan origination fees 214,000 14,000 Amortization of deferred hedging gains (581,000) -- Change in assets and liabilities: Accounts receivable 149,000 (4,273,000) Other current assets (424,000) (226,000) Inventory (96,000) (81,000) Accounts payable (4,501,000) 2,839,000 Oil and gas payable (363,000) 2,549,000 Accrued expenses (200,000) 175,000 -------------- -------------- Net cash (used) provided by operating activities (1,386,000) 6,470,000 Cash flows from investing activities: Purchase of equipment, development and leasehold costs (14,158,000) (4,111,000) -------------- -------------- Net cash used in investing activities (14,158,000) (4,111,000) Cash flows from financing activities: Proceeds from bank borrowings 5,358,000 2,921,000 Proceeds from subordinated notes 12,000,000 -- Repayments of note borrowings (3,458,000) (1,227,000) Dividends paid (2,000) -- Refinancing costs - UBS (364,000) -- -------------- -------------- Net cash provided by financing activities 13,534,000 1,694,000 Net increase (decrease) in cash (2,010,000) 4,053,000 Cash, beginning of period 6,458,000 225,000 -------------- -------------- Cash, end of period $ 4,448,000 $ 4,278,000 ============== ============== Supplemental disclosure of cash flow information Cash paid during the period for: Interest expense $ 2,789,000 $ 1,451,000 Income taxes $ -- $ --

The accompanying notes are an integral part of these consolidated statements. F-4 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 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 information 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 months ended March 31, 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 Ownership of Subsidiaries; Formation of Quest Cherokee. ------------------------------------------------------ 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, a Kansas corporation ("PGPC"), o Producers Service, Incorporated, a Kansas corporation ("PSI"), o J-W Gas Gathering, L.L.C., a Kansas limited liability company ("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 a $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. 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. F-5 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2005 (UNAUDITED) 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). 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. F-6 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2005 (UNAUDITED) 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, 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 F-7 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2005 (UNAUDITED) 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 note 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 MARCH 31, 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 anti-dilutive 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 accounting for these contracts, however, is consistent with the requirements of SFAS 133. See Note 5 - Financial Instruments and Hedging Activities. F-9 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 June 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: March 31, 2005 -------------- Senior credit facility : Term loan $ 124,400,000 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 1,912,000 Convertible debentures - unsecured; interest accrues at 8% per annum. 50,000 -------------- Total long-term debt 138,362,000 Less - current maturities 2,119,000 -------------- Total long term debt, net of current maturities $ 136,243,000 ============== Subordinated debt (inclusive of accrued interest) $ 73,723,000 ============== F-10 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2005 (UNAUDITED) 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 six 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 March 31, 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 six 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. The UBS Credit Agreement was initially secured by a lien on substantially all of the assets of Quest Cherokee (other than the pipeline assets owned by Bluestem) and a pledge of the membership interest in Bluestem. Bluestem also guaranteed Quest Cherokee's obligations under the UBS Credit Agreement. In connection with the formation of Quest Cherokee Oilfield Service, LLC ("QCOS") on August 16, 2004, QCOS became a guarantor of the UBS Credit Agreement and pledged its assets as security for its guarantee. 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 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 F-11 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2005 (UNAUDITED) 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; 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 F-12 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2005 (UNAUDITED) 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 from 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. On February 11, 2005, Quest Cherokee and ArcLight amended and restated the note purchase agreement to provide for the issuance to ArcLight of up to $15 million of additional 15% junior subordinated promissory notes (the "Additional Notes" and together with the Original Notes, the "Subordinated Notes") pursuant to the terms of an amended and restated note purchase agreement. Also on February 11, 2005, Quest Cherokee issued $5 million of Additional Notes to ArcLight (the "Second Issuance"). The Subordinated Notes, together with all accrued and unpaid interest, were originally due on December 22, 2008. In connection with the UBS Credit Agreement, the maturity date of the Subordinated Notes was extended to 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 original 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, no payments may be made on the Subordinated Notes nor may any distributions be made to the members of Quest Cherokee until after the December 31, 2004 reserve report has been delivered to the lenders. After that date, payments may be made with respect to the Subordinated Notes and distributions made to the members of Quest Cherokee semi-annually, but 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. 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, F-13 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2005 (UNAUDITED) 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 was initially to be distributed generally 85% to the holders of the Subordinated Notes and 15% to the holders of the Class B units until the Subordinated Notes have been repaid. Thereafter, the net cash flow of Quest Cherokee was to 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 was to be distributed generally 30% to the holders of the Class A units and 70% to the holders of the Class B units. As a condition to the Second Issuance, the amended and restated limited liability company agreement was amended to provided that (1) the portion of Quest Cherokee's net cash flow that is required to be used to repay the Subordinated 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 Notes have been repaid and (2) 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 will be distributed generally 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). 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. In addition, if the defect value attributable to the properties contributed by the Company's subsidiaries to Quest Cherokee exceed $2.5 million, then any distribution of net cash flow otherwise distributable to the Class B members will, instead, be distributed to the Class A member until these distributions equal such excess amount. The February 11, 2005 amended and restated note purchase agreement also provided for Quest Cherokee to issue to ArcLight Additional Notes in the principal amount of $7 million (the "Third Issuance") upon Quest Cherokee obtaining a waiver from the lenders under the UBS Credit Agreement with respect to Quest Cherokee's default under the credit agreement and an amendment to the credit agreement to permit the issuance of Additional Notes to ArcLight. On February 22, 2005, Quest Cherokee obtained the necessary waivers and amendments to the UBS Credit Agreement and closed on the Third Issuance. At the same time, Quest Cherokee borrowed $5 million of additional term loans under the UBS Credit Agreement. Finally, the amended and restated note purchase agreement provides Quest Cherokee with the option to issue to ArcLight Additional Notes in the principal amount of $3 million (the "Fourth Issuance"). In the event of the Fourth Issuance: 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 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). 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 1.6 million 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"). F-14 On April 6, 2005, WFEC exercised the Warrant with respect to all 1.6 million 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 1.6 million shares of common stock, or $1,600.00, 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 ($4.00) equaled the purchase price. As a result of WFEC's "cashless exercise" of the Warrant, the Company issued to WFEC 1,599,600 shares of its common stock. 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-156-1) 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. Plaintiff is alleging an oil and gas lease covering approximately 2,245 net acres executed by plaintiff on July 18, 2001 is terminated due to no production being established prior to the expiration date of the primary term of the lease. Plaintiff is seeking actual damages for cost to restore land and unspecified punitive damages. On March 16, 2005, the court granted Quest Cherokee's motion for summary judgment and held that Quest Cherokee's oil and gas lease is valid. 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 is alleging it is entitled to the coal bed methane gas produced and revenues from these leases and that Quest Cherokee is a trespasser. Plaintiff is seeking quiet title and an equitable accounting 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 are due on July 1, 2005. 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. 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. Motions for Summary Judgment have been filed by the parties and are currently set for hearing on May 25, 2005. 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. Plaintiffs claim to own a short gas gathering line in Elk County, Kansas. Plaintiffs claim that the Company has used their pipeline to transport gas and, as a result, they are owed compensation for that use. Plaintiffs have not quantified the amount of their alleged F-15 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 1/2 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 4 wells on that land. Quest Cherokee and the landowner defendants deny plaintiff's claim of ownership to 1/2 of the oil and gas. Plaintiff has filed a motion for summary judgment on the issue of its ownership of the 1/2 mineral interest. 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 in a lawsuit (Case No. 05-CV-14) filed by Quest Cherokee in the district court of Neosho County, Kansas. Plaintiff 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 plaintiff is entitled to one-half of the oil and gas produced from wells drilled by others on the land covered by that lease. Quest denies those third party claims and contends that, during the period of time that the lease executed by plaintiff was in effect and owned by Quest, Quest 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. Bluestem Pipeline has been named as a respondent in four complaints filed before the Kansas Corporation Commission and one complaint before the Oklahoma Corporation Commission. 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 systems in Labette, Chautauqua and Montgomery counties in Kansas or Craig County in Oklahoma, as applicable, are just, reasonable, and non-discriminatory. Discovery is on-going with respect to three of these complaints. The complaint filed by Davis Operating Company was heard by the Oklahoma Corporation Commission on April 13 - 14, 2005 and taken under advisement, but no order has been issued in that matter. 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. 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 F-16 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 three months ended March 31, 2005, fixed-price contracts hedged 96.0% of the Company's natural gas production. As of March 31, 2005, fixed-price contracts are in place to hedge 20.0 Bcf of estimated future natural gas production. Of this total volume, 6.0 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 following table summarizes the estimated volumes, fixed prices, fixed-price sales and fair value attributable to the fixed-price contracts as of March 31, 2005.

Nine 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) 4,184,000 5,614,000 - - 9,798,000 Weighted-avg fixed price per MMBtu (1) $ 4.69 $ 4.53 - - $ 4.61 Fixed-price sales $ 19,603 $ 25,433 - - $ 45,036 Fair value, net $ (12,435) $ (17,159) - - $ (29,594) Natural Gas Collars: Contract vols (MMBtu): Floor 2,231,000 1,825,000 3,650,000 2,928,000 10,634,000 Ceiling 2,231,000 1,825,000 3,650,000 2,928,000 10,634,000 Weighted-avg fixed price per MMBtu (1): Floor $ 5.21 $ 5.30 $ 4.83 $ 4.50 $ 4.90 Ceiling $ 6.26 $ 6.35 $ 5.83 $ 5.52 $ 5.92 Fixed-price sales (2) $ 13,956 $ 11,589 $ 21,279 $ 16,163 $ 62,987 Fair value, net $ (3,020) $ (2,628) $ (4,643) $ (3,066) $ (13,357) Total Natural Gas Contracts: Contract vols (MMBtu) 6,415,000 7,439,000 3,650,000 2,928,000 20,432,000 Weighted-avg fixed price per MMBtu (1) $ 5.23 $ 4.98 $ 5.83 $ 5.52 $ 5.29 Fixed-price sales (2) $ 33,559 $ 37,022 $ 21,279 $ 16,163 $ 108,023 Fair value, net $ (15,455) $ (19,787) $ (4,643) $ (3,066) $ (42,951)

(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 March 31, 2005 and 2004, oil and gas sales included $2,230,000 and $692,000, respectively, of losses associated with realized losses under fixed-price contracts. F-17 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2005 (UNAUDITED) 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 March 31, 2005 and 2004, other revenue and expense included $0 and $0, 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 March 31, 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 $22.2 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 March 31, 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 $502,000. At March 31, 2005, the Company had outstanding the following interest rate swaps and caps:

Fair Value as Notional Fixed Rate Floating of March 31, Instrument Type Term Amount (1) / Cap Rate Rate 2005 --------------------------------------------------------------------------------------------------------------------- $58,250,000 3-month Interest Rate Swap March 2005 - March 2006 $53,875,000 2.795% LIBOR $ 492,000 $98,705,000 3-month Interest Rate Cap March 2006 - Sept. 2007 $70,174,600 5.000% LIBOR $ 350,000

(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 ended March 31, 2005 and 2004 is comprised of the following:

Three Months Ended March 31, ------------------------------- 2005 2004 ------------------------------- Change in fair value of derivatives not qualifying as cash flow hedges $ (538,000) $ (5,182,000) F-18 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2005 (UNAUDITED)

Three Months Ended March 31, ------------------------------- 2005 2004 ------------------------------- Amortization of derivative fair value gains and losses recognized in earnings prior to actual cash settlements 186,000 (648,000) Ineffective portion of derivatives qualifying as cash flow hedges 796,000 (83,000) ------------------------------- $ 444,000 $ (5,913,000) ===============================

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 March 31, 2005 and December 31, 2004 and the methods and assumptions used to estimate their fair value:

March 31, 2005 December 31, 2004 ---------------- ----------------- Derivative assets: Interest rate swaps and caps $ 842,000 $ 523,000 Derivative liabilities: Fixed-price natural gas collars $ (13,357,000) $ (4,802,000) Fixed-price natural gas swaps $ (29,594,000) $ (17,675,000) Bank debt $ (136,400,000) $ (134,700,000) Other financing agreements $ (1,962,000) $ (1,763,000) Subordinated debt (inclusive of accrued interest) $ (73,723,000) $ (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 March 31, 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 March 31, 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. F-19 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2005 (UNAUDITED) 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 anti-dilutive. o For the three months ended March 31, 2005 and 2004, dilutive shares do not include the assumed conversion of the outstanding 10% Series A preferred stock (convertible into 40,000 common shares) because the effects were antidilutive. o For the three months ended March 31, 2005 and 2004, dilutive shares do not include the assumed conversion of convertible debt (convertible into 4,000 and 4,000 shares, respectively) because the effects were antidilutive. o For the three months ended March 31, 2005 and 2004, dilutive shares do not include outstanding warrants to purchase 1,600,000 shares of common stock at an exercise price of $.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 March 31, 2005: Net loss $ (1,098,000) Preferred stock dividends (2,000) -------------- Basic EPS loss available to common shareholders $ (1,100,000) 14,249,694 $ (0.08) -------- Effect of dilutive securities: None -- -- -------------- ---------- Diluted EPS loss available to common shareholders $ (1,100,000) 14,249,694 $ (0.08) ============== ========== ======== For the three months ended March 31, 2004: Net loss $ (5,646,000) Preferred stock dividends (2,000) -------------- Basic EPS loss available to common shareholders $ (5,648,000) 14,021,306 $ (0.40) -------- Effect of dilutive securities: None -- -- -------------- ---------- Diluted EPS loss available to common shareholders $ (5,648,000) 14,021,306 $ (0.40) =============== ========== =======

7. ASSET RETIREMENT OBLIGATIONS As described in Note 1, effective June 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. The following table provides a roll forward of the asset retirement obligations for the three months ended March 31, 2005 and 2004: F-20 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2005 (UNAUDITED) Three Months Ended March 31, ---------------------------- 2005 2004 ---------------------------- Asset retirement obligation beginning balance $ 871,000 $ 631,000 Liabilities incurred 56,000 55,000 Liabilities settled (2,000) (2,000) Accretion expense 13,000 4,000 Revisions in estimated cash flows -- -- ---------------------------- Asset retirement obligation $ 938,000 $ 688,000 ending balance ============================ 8. SUBSEQUENT EVENTS No other material subsequent events have occurred that warrants disclosure since the balance sheet date other than the issuance of 1,599,600 shares of common stock in cashless exercise of warrants as described in Note 3 above. F-21 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 Exhibit 99.1 "Risk Factors" to this report 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 Quest Resource Corporation ("Quest" or 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 March 31, 2005 The Company has continued its development of new wells and the construction of supporting pipeline infrastructure. During the three months ended March 31, 2005, the Company drilled 25 new gas wells (gross). The Company also connected 151 new gas wells (gross) into its gas gathering pipeline network during the same three-month period. On March 31, 2005, the Company had 938 gas wells (gross) that it was operating and 55 gas wells (gross) that it was in the process of completing and connecting to its gas gathering pipeline system. In order to connect these new wells to the Company's pipeline network, the Company constructed approximately 124 miles of additional pipeline during the last half of 2004 and the first quarter of 2005 to gather gas and water from the new wells. 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 six year term loan that was fully funded at closing 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. At closing, approximately $5 million of the UBS Revolving Loan was utilized for the issuance of letters of credit. 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 term loan were used to repay Quest Cherokee's existing credit facilities. 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. These defaults have been waived by lenders and Quest Cherokee is currently in compliance under the UBS Credit Agreement as amended on February 22, 2005. See "--Liquidity and Capital Resources". 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, as amended, 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 month period ended March 31, 2005 as compared to the same period in 2004. Three Months Ended March 31, 2005 Compared to Three Months Ended March 31, 2004 Total revenues of $12.1 million for the quarter ended March 31, 2005 represents an increase of 4% when compared to total revenues of $11.5 million for the quarter ended March 31, 2004. This increase was achieved by a combination of the addition -5- 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. The increase in oil and gas sales from $10.8 million for the quarter ended March 31, 2004 to $11.3 million for the quarter ended March 31, 2005 and the increase in gas pipeline revenue from $760,000 to $806,000 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 2,181,000 mcf of net gas for the quarter ended March 31, 2005, as compared to 2,150,000 net mcf produced in the prior quarter. The Company's product prices on an equivalent basis (mcfe) increased from $5.34 mcfe average for the quarter ended March 31, 2004 to $6.19 mcfe average for the quarter ended March 31, 2005. For the quarter ended March 31, 2005, the net product price, after accounting for hedge settlements of $2.2 million during the quarter, averaged $5.22 mcfe. For the quarter ended March 31, 2004, the net product price, after accounting for hedging settlement of $692,000 during the quarter, averaged $4.97 mcfe. Other revenue for the three months ended March 31, 2004 was $6,000 as compared to other expense of $21,000 for the three-month period ended March 31, 2005. The operating costs remained fairly constant for the quarter ended March 31, 2005 totaling $2.3 million, as compared to the operating costs of $2.4 million incurred for the quarter ended March 31, 2004. Lease operating costs per mcf for the quarter ended March 31, 2005 were $.78 per mcf as compared to $.86 per mcf for the quarter ended March 31, 2004, representing an 9% decrease. Pipeline operating costs increased by 47% from $1.2 million for the quarter March 31, 2004 to $1.8 million for the quarter ended March 31, 2005. The decrease in lease operating cost per mcf is due primarily to an increase in the allocation of field employee time spent developing pipeline infrastructure, completing and connecting wells and a decrease in the amount of time spent servicing the wells. 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 March 31, 2005, depreciation, depletion and amortization of $3.4 million remained relatively constant compared to $3.3 million for the quarter ended March 31, 2004. General and administrative expenses remained fairly constant totaling $971,000 for the quarter ended March 31, 2005 compared to $983,000 for the same period in the prior year. Interest expense increased to $5.2 million for the quarter ended March 31, 2005 from $3.4 million for the quarter ended March 31, 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 $444,000 for the three months ended March 31, 2005, which included a $538,000 loss attributable to the change in fair value for certain derivatives that did not qualify as cash flow hedges pursuant to SFAS 133, and a $186,000 net gain attributable to the reversal of contract fair value gains and losses recognized in earnings prior to actual settlement, and a gain of $796,000 relating to hedge ineffectiveness. Change in derivative fair value was a non-cash loss of $5.9 million for the three months ended March 31, 2004, which included a $5.2 million loss attributable to the change in fair value for certain derivatives that did not qualify as cash flow hedges pursuant to SFAS 133, and a $648,000 net loss attributable to the reversal of contract fair value gains and losses recognized in earnings prior to actual settlement, and a loss of $83,000 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 $1.1 million for the quarter ended March 31, 2005 as compared to a net loss of $5.6 million for the quarter ended March 31, 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 ResourcesCapital Resources And Liquidity At March 31, 2005, the Company had current assets of $12.6 million, a working capital deficit (current assets minus current liabilities, excluding the short-term derivative assets and liabilities) of $6.4 million and had $1.4 million of net cash used by operations during the three months ended March 31, 2005. The working capital deficit (including the short-term derivative assets and liabilities) totals $28.1 million. During the three months ended March 31, 2005 a total of approximately $14.2 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 $12 million of additional notes issued to ArcLight and $2 million of additional borrowings under the term loans -6- from the UBS Credit Agreement. An additional $3 million of notes is available for issuance to ArcLight. 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 during the first quarter. Net cash used by operating activities totaled $1.4 million for the three months ended March 31, 2005 as compared to $6.5 million of net cash provided from operating activities for the three months ended March 31, 2004 due primarily to 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 $502,000 and $22.2 million, respectively) was $6.4 million at March 31, 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, oil and gas 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 is focused on re-completions and developing up to 134 additional new wells to be drilled and completed during the remaining nine months of calendar year 2005 using the resources generated by its operations (subject to compliance with the limitations contained in the UBS Credit Agreement - See "UBS Credit Facility" below). The Company can commence drilling of the 134 additional new wells upon achieving gross daily production of 43 mmcfe/d for any 20 of the last 30 days prior to recommencement of drilling. However, no assurances can be given that such sources will be sufficient to fund the proposed capital expenditures for the remainder of calendar year 2005 or that the required gross daily production levels will be achieved early enough in 2005, if at all, to permit the development of all 134 wells. The Company's average gross daily production for the first quarter was approximately 34 mmcfe/d and as of this filing was approximately 36 mmcfe/d. Subsequent to calendar year 2005, the Company intends to drill approximately 380 wells per year, which management currently estimates will require a capital investment of approximately $32 million per year to drill and develop. Management currently estimates that the Company would be able to drill and develop approximately 310 of these new wells during year 2006 utilizing cash flow from operations and that the Company will need to obtain additional funds for any additional wells. The Company could seek to borrow additional funds or sell equity securities. This estimate is based on forecasts of production volumes increasing to approximately 20 bcf for calendar year 2006 production. However, no assurances are given that the Company will be able to achieve this level of production or 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. Although the Company believes that it will have adequate additional reserves and other resources to support the 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 six 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 March 31, 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 -7- 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 six 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. The UBS Credit Agreement was initially secured by a lien on the substantially all of the assets of Quest Cherokee (other than the pipeline assets owned by Bluestem) and a pledge of the membership interest in Bluestem. Bluestem also guaranteed Quest Cherokee's obligations under the UBS Credit Agreement. In connection with the formation of Quest Cherokee Oilfield Service, LLC ("QCOS") on August 16, 2004, QCOS became a guarantor of the UBS Credit Agreement and pledged its assets as security for its guarantee. 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 May 13, 2005, the Company had connected 191 wells since January 1, 2005 and its average gross daily production for the 20 highest days out of the last 30 days was 36,026 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 3.30 to 1.0 for the first quarter of 2006 -8- 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 from 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. On February 11, 2005, Quest Cherokee and ArcLight amended and restated the note purchase agreement to provide for the issuance to ArcLight of up to $15 million of additional 15% junior subordinated promissory notes (the "Additional Notes" and together with the Original Notes, the "Subordinated Notes") pursuant to the terms of an amended and restated note purchase agreement. Also on February 11, 2005, Quest Cherokee issued $5 million of Additional Notes to ArcLight (the "Second Issuance"). The Subordinated Notes, together with all accrued and unpaid interest, were originally due on December 22, 2008. In connection with the UBS Credit Agreement, the maturity date of the Subordinated Notes was extended to 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 original 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, no payments may be made on the Subordinated Notes nor may any distributions be made to the members of Quest Cherokee until after the December 31, 2004 reserve report has been delivered to the lenders. After -9- that date, payments may be made with respect to the Subordinated Notes and distributions made to the members of Quest Cherokee semi-annually, but 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. 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 was initially to be distributed generally 85% to the holders of the Subordinated Notes and 15% to the holders of the Class B units until the Subordinated Notes have been repaid. Thereafter, the net cash flow of Quest Cherokee was to 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 was to be distributed generally 30% to the holders of the Class A units and 70% to the holders of the Class B units. As a condition to the Second Issuance, the amended and restated limited liability company agreement was amended to provided that (1) the portion of Quest Cherokee's net cash flow that is required to be used to repay the Subordinated 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 Notes have been repaid and (2) 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 will be distributed generally 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). 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. In addition, if the defect value attributable to the properties contributed by the Company's subsidiaries to Quest Cherokee exceed $2.5 million, then any distribution of net cash flow otherwise distributable to the Class B members will, instead, be distributed to the Class A member until these distributions equal such excess amount. The February 11, 2005 amended and restated note purchase agreement also provided for Quest Cherokee to issue to ArcLight Additional Notes in the principal amount of $7 million (the "Third Issuance") upon Quest Cherokee obtaining a waiver from the lenders under the UBS Credit Agreement with respect to Quest Cherokee's default under the credit agreement and an amendment to the credit agreement to permit the issuance of Additional Notes to ArcLight. On February 22, 2005, Quest Cherokee obtained the necessary waivers and amendments to the UBS Credit Agreement and closed on the Third Issuance. At the same time, Quest Cherokee borrowed $5 million of additional term loans under the UBS Credit Agreement and paid down $3 million of the outstanding balance under the revolver. Finally, the amended and restated note purchase agreement provides Quest Cherokee with the option to issue to ArcLight Additional Notes in the principal amount of $3 million (the "Fourth Issuance"). In the event of the Fourth Issuance: (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 -10- 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). 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. 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 1.6 million 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 1.6 million 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 1.6 million shares of common stock, or $1,600.00, 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 ($4.00) equaled the purchase price. As a result of WFEC's "cashless exercise" of the Warrant, the Company issued to WFEC 1,599,600 shares of its common stock. Contractual Obligations Future Payments due on the Company's contractual obligations as of March 31, 2005 are as follows:

Total 2005 2006-2007 2008-2009 thereafter ---------------- -------------- ------------- --------------- ---------------- Term B Note $ 124,400,000 $ 1,200,000 $2,400,000 $ 2,400,000 $ 118,400,000 Revolving Line of Credit 12,000,000 -- -- 12,000,000 -- Notes payable 1,912,000 869,000 868,000 82,000 93,000 Convertible debentures 50,000 50,000 -- -- -- Subordinated debt (1) 73,724,000 -- -- -- 73,724,000 ---------------- -------------- ------------- --------------- ---------------- Total $ 212,086,000 $2,119,000 $3,268,000 $ 14,482,000 $192,217,000 ================ ============== ============= =============== ================

(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. 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 March 31, 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. 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 three months ended March 31, 2005, fixed-price contracts hedged 96.0% of the Company's natural gas production. As of March 31, 2005, fixed-price contracts are in place to hedge 20.0 Bcf of estimated future natural gas production. Of this total volume, 6.0 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 following table summarizes the estimated volumes, fixed prices, fixed-price sales and fair value attributable to the fixed-price contracts as of March 31, 2005.

Nine 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) 4,184,000 5,614,000 - - 9,798,000 Weighted-avg fixed price per MMBtu (1) $ 4.69 $ 4.53 - - $ 4.61 Fixed-price sales $ 19,603 $ 25,433 - - $ 45,036 Fair value, net $ (12,435) $ (17,159) - - $ (29,594) Natural Gas Collars: Contract vols (MMBtu): Floor 2,231,000 1,825,000 3,650,000 2,928,000 10,634,000 Ceiling 2,231,000 1,825,000 3,650,000 2,928,000 10,634,000 Weighted-avg fixed price per MMBtu (1): Floor $ 5.21 $ 5.30 $ 4.83 $ 4.50 $ 4.90 Ceiling $ 6.26 $ 6.35 $ 5.83 $ 5.52 $ 5.92 Fixed-price sales (2) $ 13,956 $ 11,589 $ 21,279 $ 16,163 $ 62,987 Fair value, net $ (3,020) $ (2,628) $ (4,643) $ (3,066) $ (13,357) Total Natural Gas Contracts: Contract vols (MMBtu) 6,415,000 7,439,000 3,650,000 2,928,000 20,432,000 Weighted-avg fixed price per MMBtu (1) $ 5.23 $ 4.98 $ 5.83 $ 5.52 $ 5.29 Fixed-price sales (2) $ 33,559 $ 37,022 $ 21,279 $ 16,163 $ 108,023 Fair value, net $ (15,455) $ (19,787) $ (4,643) $ (3,066) $ (42,951)

(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. -12- 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 March 31, 2005 and 2004, oil and gas sales included $2,230,000 and $692,000, 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 March 31, 2005 and 2004, other revenue and expense included $0 and $0, 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 March 31, 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 $22.2 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 March 31, 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 $502,000. At March 31, 2005, the Company had outstanding the following interest rate swaps and caps:

Fair Value as Notional Fixed Rate Floating of March 31, Instrument Type Term Amount (1) / Cap Rate Rate 2005 --------------------------------------------------------------------------------------------------------------------- $58,250,000 3-month Interest Rate Swap March 2005 - March 2006 $53,875,000 2.795% LIBOR $ 492,000 $98,705,000 3-month Interest Rate Cap March 2006 - Sept. 2007 $70,174,600 5.000% LIBOR $ 350,000

(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 ended March 31, 2005 and 2004 is comprised of the following:

Three Months Ended March 31, ----------------------------------- 2005 2004 ----------------------------------- Change in fair value of derivatives not qualifying as cash flow hedges $ (538,000) $ (5,182,000) -13-

Three Months Ended March 31, ----------------------------------- 2005 2004 ----------------------------------- Amortization of derivative fair value gains and losses recognized in earnings prior to actual cash settlements 186,000 (648,000) Ineffective portion of derivatives qualifying as cash flow hedges 796,000 (83,000) ----------------------------------- $ 444,000 $ (5,913,000) ===================================

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 March 31, 2005 and December 31, 2004 and the methods and assumptions used to estimate their fair value:

December 31, March 31, 2005 2004 ------------------------ ------------------- Derivative assets: Interest rate swaps and caps $ 842,000 $ 523,000 Derivative liabilities: Fixed-price natural gas collars $ (13,357,000) $ (4,802,000) Fixed-price natural gas swaps $ (29,594,000) $ (17,675,000) Bank debt $ (136,400,000) $ (134,700,000) Other financing agreements $ (1,962,000) $ (1,763,000) Subordinated debt (inclusive of accrued interest) $ (73,723,000) $ (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 March 31, 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 March 31, 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. 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. -14- 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 March 31, 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 March 31, 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. 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 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 -15- 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. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources--UBS Credit Facility" for additional information. Item 4. Submission of Matters to Vote of Security Holders None Item 5. Other Information None Item 6. Exhibits 4.1* Amended and Restated Note Purchase Agreement, by and between, Quest Cherokee, LLC and Cherokee Energy Partners, LLC, dated as of the 11th day of February, 2005 (filed as Exhibit 4.1 to Quest Resource Corporation's Form 8-K filed February 17, 2005 and incorporated herein by reference). 4.2* Junior Subordinated Promissory Note made by Quest Cherokee, LLC in favor of and to the order of Cherokee Energy Partners LLC, dated as of the 11th day of February, 2005 (filed as Exhibit 4.8 to Quest Resource Corporation's Form 10-KSB filed March 31, 2005 and incorporated herein by reference). 4.3* Junior Subordinated Promissory Note made by Quest Cherokee, LLC in favor of and to the order of Cherokee Energy Partners LLC, dated as of the 22nd day of February, 2005 (filed as Exhibit 4.9 to Quest Resource Corporation's Form 10-KSB filed March 31, 2005 and incorporated herein by reference). 4.4* Amendment No. 2 and Waiver to Credit Agreement, by and between, Quest Cherokee, LLC, the subsidiary guarantors and the various lenders party to the UBS Amended Credit Agreement, UBS Securities LLC, as the lead arranger, book manager, documentation agent and syndication agent, UBS AG, Stamford Branch, as issuing bank, the L/C Facility issuing bank, the administrative agent for the lenders and collateral agent for the secured parties, and UBS Loan Finance LLC, as swing line lender, dated as of the 22nd day of February, 2005 (incorporated herein by reference to Exhibit 4.1 to the Company's Quarterly Report on Form 10-QSB filed February 23. 2005). 10.1** Consent of Transferee of Shares of Quest Resource Corporation, McKown Point LP, dated as of December 31, 2004, to the Voting Agreement for Shares of Stock of Quest Resource Corporation by and among Quest Resource Corporation, Douglas L. Lamb and Jerry D. Cash, dated as of November 7, 2002. 10.2** Amendment No. 2 dated as of March 1, 2005 to Employment Agreement between the Company and Douglas Lamb. 10.3* Amendment dated February 11, 2005 to the Amended and Restated Limited Liability Company Agreement of Quest Cherokee, LLC, by and among Cherokee Energy Partners LLC, Quest Oil & Gas Corporation, Quest Energy Service, Inc., STP Cherokee, Inc., Ponderosa Gas Pipeline Company, Inc., Producers Service Incorporated and J-W Gas Gathering, L.L.C., dated as of the 22nd day of December, 2003 (Filed as Exhibit 10.1 to Quest Resource Corporation's Form 8-K filed February 17, 2005 and incorporated herein by reference). 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. 99.1** Risk Factors. ----------------------------- * Incorporated by reference ** Filed previously -16- SIGNATURES In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this Amendment No. 1 to report to be signed on its behalf by the undersigned, thereunto duly authorized this 19th day of October, 2005. QUEST RESOURCE CORPORATION By: /s/ David E. Grose ---------------------------------- David E. Grose Chief Financial Officer -17-