10-Q 1 qr-form10q_1119598.txt FORM 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-QSB (Mark One) [X] Quarterly report under Section 13 or 15(d) of the Securities Exchange Act of 1934 for the quarterly period ended November 30, 2004. [ ] Transition report under Section 13 or 15(d) of the Securities Exchange Act of 1934 (No fee required) for the transition period from ____________________ to _____________________. Commission file number: 0-17371 QUEST RESOURCE CORPORATION ---------------------- (Name of Small Business Issuer in Its Charter) Nevada 90-0196936 -------- ------------ (State or Other Jurisdiction of (I.R.S. Employer Incorporation or Organization) Identification No.) 9520 N. May Avenue, Suite 300, Oklahoma City, OK 73120 ------------------------------------------------------- (Address of Principal Executive Offices)(Zip Code) Issuer's Telephone Number: 405-488-1304 Check whether the issuer: (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act 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 [X] No [] As of February 18, 2005, the issuer had 14,249,694 shares of common stock outstanding. Transitioned Small Business Disclosure Format (check one): Yes [] No [X] QUEST RESOURCE CORPORATION FORM 10-QSB FOR THE QUARTER ENDED NOVEMBER 30, 2004 TABLE OF CONTENTS PART I - FINANCIAL INFORMATION.................................................3 Item 1. Financial Statements...........................................3 Condensed Consolidated Balance Sheets: November 30, 2004 and May 31, 2004.......................F-1 Condensed Consolidated Statements of Operations and Comprehensive Income: Three months and Six months ended November 30, 2004 and 2003..............................F-3 Condensed Consolidated Statements of Cash Flows: Six months ended November 30, 2004 and 2003..............F-5 Condensed Notes to Consolidated Financial Statements.......F-6 Item 2. Management's Discussion and Analysis or Plan of Operation.............................................4 Forward-looking Information....................................4 Business of Issuer.............................................4 Significant Developments during the three months ended November 30, 2004...............4 Results of Operations..........................................5 Capital Resources and Liquidity................................7 Item 3. Controls and Procedures.......................................11 PART II - OTHER INFORMATION...................................................11 Item 1. Legal Proceedings.............................................11 Item 2. Unregistered Sales of Equity Securities and Use of Proceeds...12 Item 3. Defaults Upon Senior Securities...............................12 Item 4. Submission of Matters to a Vote of Security Holders...........12 Item 5. Other Information.............................................12 Item 6. Exhibits......................................................12 SIGNATURES....................................................................14 -2- PART I - FINANCIAL INFORMATION Item 1. Financial Statements Except as otherwise required by the context, references in this quarterly report to "we," "our," "us," "Quest" or "the Company" refer to Quest Resource Corporation and its subsidiaries, Quest Cherokee, LLC; Quest Cherokee Oilfield Service, LLC; Bluestem Pipeline, LLC; Quest Oil & Gas Corporation; Ponderosa Gas Pipeline Company, Inc.; Quest Energy Service, Inc.; STP Cherokee, Inc.; Producers Service, Incorporated; and J-W Gas Gathering, L.L.C. Our operations are primarily conducted through Quest Cherokee, LLC, Bluestem Pipeline, LLC and Quest Energy Service, Inc. Our unaudited interim financial statements, including a balance sheet as of the fiscal quarter ended November 30, 2004, 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-16 and are incorporated herein by this reference. The financial statements included herein have been prepared internally, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission and the Public Company Accounting Oversight Board. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been omitted. However, in our opinion, all adjustments (which include only normal recurring accruals) necessary to fairly present the financial position and results of operations have been made for the periods presented. The 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 for the fiscal year ended May 31, 2004. Change in Fiscal Year End The Company has elected to change its fiscal year end to December 31 from May 31. The Company anticipates filing a transition report on Form 10-KSB covering the period from June 1, 2004 to December 31, 2004. -3- QUEST RESOURCE CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS November 30, May 31, 2004 2004 ------------ ------------ A S S E T S (unaudited) Current assets: Cash $ 5,739,000 $ 3,508,000 Accounts receivable, trade 6,833,000 7,097,000 Other receivables 797,000 609,000 Deposits on acquisition -- 216,000 Other current assets 386,000 257,000 Short-term derivative assets 178,000 -- Inventory 250,000 492,000 ------------- ------------- Total current assets 14,183,000 12,179,000 Property and equipment, net of accumulated depreciation of $1,330,000 and $832,000, respectively 7,725,000 2,570,000 Pipeline assets, net of accumulated depreciation of $2,110,000 and $1,774,000, respectively 39,771,000 36,488,000 Pipelines under construction 12,537,000 -- ------------- ------------- 52,308,000 36,488,000 Oil and gas properties: Properties being amortized 139,522,000 123,161,000 Properties not being amortized 25,667,000 24,662,000 ------------- ------------- 165,189,000 147,823,000 Less: Accumulated depreciation, depletion and amortization (14,417,000) (8,881,000) ------------- ------------- Net oil and gas properties 150,772,000 138,942,000 ------------- ------------- Long-term derivative assets 394,000 -- Other assets, net 5,151,000 196,000 ------------- ------------- Total assets $230,533,000 $190,375,000 ============= ============= 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 Current liabilities: Accounts payable $ 11,720,000 $ 3,714,000 Oil and gas payable 2,973,000 3,285,000 Accrued expenses 473,000 462,000 Current portion of notes payable 1,600,000 336,000 Short-term derivative liability 13,259,000 10,087,000 ------------- ------------- Total current liabilities 30,025,000 17,884,000 Non-current liabilities: Long-term derivative liability 20,983,000 9,701,000 Asset retirement obligation 849,000 717,000 Convertible debentures 50,000 50,000 Acquisition holdback payable -- 638,000 Notes payable, net of current portion shown above 132,789,000 104,691,000 ------------- ------------- Non-current liabilities 154,671,000 115,797,000 Subordinated debt (including accrued interest) 58,619,000 54,459,000 ------------- ------------- Total liabilities 243,315,000 188,140,000 ------------- ------------- Commitments and contingencies -- -- The accompanying notes are an integral part of these condensed consolidated financial statements. F-1 Stockholders' equity: 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 14,112,694 shares issued and outstanding 14,000 14,000 Additional paid-in capital 17,184,000 16,642,000 Less: Stock subscriptions receivable (340,000) -- Accumulated other comprehensive loss (19,970,000) (10,629,000) Accumulated deficit (9,670,000) (3,792,000) ------------- ------------- Total stockholders' equity (12,782,000) 2,235,000 ------------- ------------- Total liabilities and stockholders' equity $230,533,000 $190,375,000 ============= ============= The accompanying notes are an integral part of these condensed consolidated financial statements. F-2 QUEST RESOURCE CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (UNAUDITED)

For the Three Months For the Six Months Ended Ended November 30, November 30, ----------------------------- ----------------------------- 2004 2003 2004 2003 ------------- ------------ ------------- ------------ Revenue: Oil and gas sales $ 9,843,000 $ 3,464,000 $ 20,622,000 $ 7,078,000 Gas pipeline revenue 818,000 544,000 1,628,000 1,099,000 Other revenue and expense 30,000 (294,000) 51,000 (1,290,000) ------------- ------------ ------------- ------------ Total revenues 10,691,000 3,714,000 22,301,000 6,887,000 Costs and expenses: Oil and gas production 1,856,000 954,000 4,212,000 1,807,000 Pipeline operating 1,413,000 481,000 2,892,000 947,000 General and administrative expenses 1,385,000 334,000 2,402,000 671,000 Depreciation, depletion and amortization 3,040,000 780,000 6,072,000 1,501,000 ------------- ------------ ------------- ------------ Total costs and expenses 7,694,000 2,549,000 15,578,000 4,926,000 ------------- ------------ ------------- ------------ Operating income 2,997,000 1,165,000 6,723,000 1,961,000 ------------- ------------ ------------- ------------ Other income (expense): Change in derivative fair value (4,670,000) 603,000 (4,007,000) 4,407,000 Interest income 4,000 8,000 Interest expense (4,339,000) (477,000) (8,597,000) (830,000) ------------- ------------ ------------- ------------ Total other income (expense) (9,005,000) 126,000 (12,596,000 3,577,000 ------------- ------------ ------------- ------------ Income (loss) before income taxes (6,008,000) 1,291,000 (5,873,000) 5,538,000 Income tax benefit (expense)-deferred 54,000 (516,000) -- (2,215,000) ------------- ------------ ------------- ------------ Net income (loss) before cumulative effect of accounting change (5,954,000) 775,000 (5,873,000) 3,323,000 Cumulative effect of accounting change, net of income taxes of -- -- -- (28,000) ------------- ------------ ------------- ------------ Net income (loss) (5,954,000) 775,000 (5,873,000) 3,295,000 Other comprehensive income (loss), net of income taxes: Change in fixed-price contract and other derivative fair value, net of income taxes of ($594,000), $0, $0, and $0 (11,762,000) -- (12,653,000) -- Reclassification adjustments-contract settlements, net of income taxes of $712,000, $0, $0, and $0 2,244,000 -- 3,312,000 -- ------------- ------------ ------------- ------------ Other comprehensive income (loss) (9,518,000) -- (9,341,000) -- ------------- ------------ ------------- ------------ Comprehensive income (loss) (15,472,000) 775,000 (15,214,000) 3,295,000 ============= ============ ============= ============ Net income (loss) (5,954,000) 775 000 (5,873,000) 3,295,000 Preferred stock dividends (2,000) (2,000) (5,000) (5,000) ------------- ------------ ------------- ------------ Net income (loss) available to common stockholders $ (5,956,000) $ 773,000 $ (5,878,000) $ 3,290,000 ============= ============ ============= ============ Earnings (loss) per share - basic: Income (loss) before cumulative effect of accounting change $ (0.42) $ 0.06 $ (0.42) $ 0.24 Cumulative effect of accounting change -- -- -- -- ------------- ------------ ------------- ------------ $ (0.42) $ 0.06 $ (0.42) $ 0.24 ============= ============ ============= ============ The accompanying notes are an integral part of these condensed consolidated financial statements. F-3

Earnings (loss) per share - diluted Income (loss) before cumulative effect of accounting change $ (0.42) $ 0.05 $ (0.42) $ .21 Cumulative effect of accounting change -- -- -- -- ------------- ------------ ------------- ------------ $ (0.42) $ 0.05 $ (0.42) $ .21 ============= ============ ============= ============ Weighted average common and equivalent shares outstanding: Basic 14,160,024 14,008,352 14,137,066 13,904,974 Diluted 14,160,024 15,607,955 14,137,066 15,554,699

The accompanying notes are an integral part of these condensed consolidated financial statements. F-4 QUEST RESOURCE CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended November 30, -------------------------- 2004 2003 ------------ ------------ Cash flows from operating activities: Net income (loss) $(5,873,000) $ 3,295,000 Adjustments to reconcile net income (loss) to cash provided by operations: Depreciation and depletion 6,394,000 1,501,000 Change in derivative fair value 4,007,000 (4,407,000) Accrued interest on subordinated note 4,160,000 -- Cumulative effect of accounting change -- 47,000 Deferred income taxes -- 2,196,000 Accretion of line of credit -- 185,000 Stock issued for audit committee fees 62,000 -- Stock issued for services -- 62,000 Amortization of loan origination fees 460,000 26,000 Amortization of deferred hedging gains 534,000 -- Change in assets and liabilities: Accounts receivable 75,000 (430,000) Other current assets (129,000) (400,000) Inventory 242,000 (32,000) Accounts payable 8,009,000 (281,000) Oil and gas payable (312,000) 623,000 Accrued expenses 10,000 -- ------------ ------------ Net cash provided by operating activities 17,639,000 2,385,000 Cash flows from investing activities: Purchase of equipment, development and leaseholdcosts (38,859,000) (6,714,000) Change in other assets (527,000) (166,000) ------------ ------------ Net cash used in investing activities (39,386,000) (6,880,000) Cash flows from financing activities: Proceeds from bank borrowings 133,742,000 2,776,000 Repayments of note borrowings (104,380,000) -- Proceeds from issuance of common stock 140,000 500,000 Dividends paid (5,000) (5,000) Refinancing costs - UBS (4,881,000) -- Change in other long-term liabilities (638,000) -- ------------ ------------ Net cash provided by financing activities 23,978,000 3,271,000 Net increase (decrease) in cash 2,231,000 (1,224,000) Cash, beginning of period 3,508,000 2,689,000 ------------ ------------ Cash, end of period $ 5,739,000 $ 1,465,000 ============ ============ The accompanying notes are an integral part of these condensed consolidated financial statements. F-5 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS NOVEMBER 30, 2004 (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 the instructions to Form 10-QSB and Item 310(b) of Regulation S-B. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and six months ended November 30, 2004 are not necessarily indicative of the results that may be expected for the transitional period ended December 31, 2004. The financial statements should be read in conjunction with the financial statements and notes thereto included in the Company's Form 10-KSB for the fiscal year ended May 31, 2004. Shares of common stock issued by the Company for other than cash have been assigned amounts equivalent to the fair value of the service or assets received in exchange. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation and Subsidiaries The Company's subsidiaries consist of: o Quest Cherokee, LLC, a Delaware limited liability company ("Quest Cherokee"), o Bluestem Pipeline, LLC, a Delaware limited liability company ("Bluestem"), o Quest 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 ("J-W Gas"), o STP Cherokee, Inc., an Oklahoma corporation ("STP"), and o Quest Cherokee Oilfield Service, LLC, a Delaware limited liability company ("QCOS"). 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. QES, QOG, PGPC, STP, PSI and J-W Gas collectively own all of the outstanding Class B Units of Quest Cherokee. Cherokee Energy Partners, LLC, a wholly owned subsidiary of ArcLight Energy Partners Fund I, L.P. ("ArcLight"), owns all of the Class A Units of Quest Cherokee. Quest Cherokee is the sole member of Bluestem and QCOS. 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 $292,000 (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. Quest Cherokee, has two classes of membership units, Class A that is owned and controlled by ArcLight, and Class B that is owned and controlled by Quest Resource Corporation though several of its wholly owned subsidiaries. The Class A acquired the Class A units for $100 in connection with its purchase of $51 million of subordinated notes of Quest Cherokee. The Class B members contributed natural gas and oil properties with an agreed upon value of $51 million. For financial reporting purposes, the properties transferred to Quest Cherokee by the Company and its subsidiaries, were transferred at historical cost. Under the terms of the amended and restated limited liability company agreement for Quest Cherokee, the net cash flow of Quest Cherokee will generally be distributed 90% to the holders of the subordinated promissory notes and 10% to the holders of Class B units until the subordinated promissory notes have been repaid. Thereafter, the net cash flow of Quest Cherokee will F-6 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS NOVEMBER 30, 2004 (UNAUDITED) generally be distributed 65% to the holders of the Class A units and 35% to the holders of the Class B units, until the holders of the subordinated notes and the Class A units have received a combined internal rate of return of 30% on their cash invested. Thereafter, the net cash flow of Quest Cherokee will generally be distributed 35% to the holders of the Class A units and 65% to the holders of the Class B units. Since the Company is anticipated to ultimately control 65% of the cash flows, the results of operation of Quest Cherokee have been included in these consolidated financial statements. For the period from inception through November 30, 2004, Quest Cherokee incurred operating losses. Operating losses are allocated 30% to the minority members until their membership interest of $100 is reduced to zero; thereafter all losses are allocated 100% to the Company. Financial reporting by the Company's subsidiaries is consolidated into one set of financial statements for QRC. 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 are computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflect the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted during the period. Dilutive securities having an anti-dilutive effect on diluted earnings per share are excluded from the calculation. See Note 7 - Earnings Per Share for a reconciliation of the numerator and denominator of the basic and diluted earnings per share computations. Common Stock During the six months ended November 30, 2004, the Company granted a total of 25,000 shares of its common stock to Mr. Garrison as compensation for services on the Company's audit committee during the period from June 6, 2003 to May 31, 2005. Of the shares granted, 17,000 shares were issued with a value of $62,000 for financial reporting purposes. The remaining 8,000 shares are restricted and subject to forfeiture in the event that Mr. Garrison resigns from the Company's audit committee before May 31, 2005 and will be issued when the restrictions have lapsed. Also during the six months ended November 30, 2004, 120,000 shares of common stock sold for cash with a value of $480,000 were issued to the following accredited investors: Fred B. Oates, Theodore Wannamaker Gage, Jr., Kate O. Dargan, Frank A. Jones, Larry Joe Vin Zant, Kenneth A. and Victoria M. Hull, Whitney and Elizabeth Vin Zant and Mark N. Vin Zant. 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 also enters into interest rate swaps and caps to reduce its exposure to adverse interest rate fluctuations. In the first quarter of fiscal 2001, the Company adopted SFAS 133, as amended by SFAS 138, Accounting for Derivative Instruments and Hedging Activities, which established new accounting and reporting guidelines 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. F-7 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS NOVEMBER 30, 2004 (UNAUDITED) 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. Based on the interpretation of these guidelines by the Company, the changes in fair value of all of its derivatives during the period from June 1, 2003 to December 22, 2003 required reporting in results of operations, rather than in other comprehensive income. Also, 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. 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 6 - Financial Instruments and Hedging Activities. The Company has established the fair value of all derivative instruments using estimates determined by our counterparties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, futures prices, volatility, and time to maturity and credit risk. The values reported in the financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors. Recently Issued Accounting Standards 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. 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 an effect on its reporting. 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 an effect on its reporting. 3. ACQUISITIONS The Company acquired certain assets from Consolidated Oil Well Services on September 15, 2004 in the amount of $4.1 million. The assets consist of cementing, acidizing and fracturing equipment and a related office building and storage facility in Chanute, Kansas. The acquisition was funded with a portion of the remaining net proceeds from the $120 million term loan under the UBS Credit Agreement. The Company formed Quest Cherokee Oilfield Service, LLC ("QCOS") to acquire the Consolidated vehicles and equipment and transferred all existing field assets (vehicles and equipment) and field personnel to QCOS. Under the terms of the UBS Credit Agreement, QCOS was required to become a guarantor of the UBS Credit Agreement and has pledged its assets as security for its guarantee. F-8 QUEST RESOURCE CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) The Company acquired approximately 80 miles of an inactive oil pipeline for approximately $1.0 million on August 10, 2004. The Company intends to convert this former oil pipeline into a natural gas pipeline. The acquisition was funded with a portion of the remaining net proceeds from the $120 million term loan under the new credit facility with UBS. Additionally, the Company acquired 8 wells and approximately 8,000 acres in the Cherokee Basin on August 6, 2004 for $750,000. 4. LONG-TERM DEBT Long-term debt consists of the following: November 30, 2004 ----------------- Senior credit facility: Term loan $120,000,000 Revolving loan 13,000,000 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 1,389,000 Convertible debentures - unsecured; interest accrues at 8% per annum. 50,000 ------------ Total long-term debt 134,439,000 Less - current maturities 1,600,000 ------------ Total long-term debt, net of current maturities $132,839,000 ============ Subordinated debt (inclusive of accrued interest) $ 58,619,000 ============ UBS Credit Facility On July 22, 2004, Quest Cherokee entered into a syndicated credit facility arranged and syndicated by UBS Securities LLC, with UBS AG, Stamford Branch as administrative agent (the "UBS Credit Agreement"). The UBS Credit Agreement originally provided for a $120.0 million six year term loan that was fully funded at closing (the "UBS Term Loan") and a $20.0 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 November 30, 2004, Quest Cherokee had approximately $13.0 million of loans and approximately $5.0 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 $15.0 million "synthetic" letter of credit facility that matures in December 2008, which provides credit support for Quest Cherokee's natural gas hedging program. See the Company's Form 10-QSB for the quarter ended August 31, 2004 for additional information regarding 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. 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 $12.0 million of subordinated notes to Cherokee Energy Partners, LLC ("Cherokee Partners") was permitted; o the UBS Term Loan was increased by an additional $5.0 million to a total of $125 million; F-9 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS NOVEMBER 30, 2004 (UNAUDITED) o 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; 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 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 2007; and 1.50 to 1.0 thereafter; o capital expenditures for any test period may not exceed: $15.0 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 $10.0 million for 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. A copy of the amendment and waiver to the UBS Credit Agreement is filed as Exhibit 4.1 to this Form 10-QSB and is incorporated herein by reference. F-10 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS NOVEMBER 30, 2004 (UNAUDITED) Subordinated Promissory Notes On February 11 and February 22, 2005, Quest Cherokee issued and sold to Cherokee Partners $5.0 million and $7.0 million, respectively, of additional subordinated promissory notes. See our Form 8-K filed February 17, 2005 for additional information with respect to the terms of this investment. Other Long-Term Indebtedness QES has one promissory note with an authorized credit limit of $440,000. The note matures on February 19, 2008, bears interest at the annual rate of 7% per annum, requires monthly payments based upon a 60-month amortization, is secured by equipment and rolling stock, and had a principal balance outstanding on November 30, 2004 of $229,000. The obligation under this note was assumed by Quest Cherokee as part of the restructuring of the Company's operations in connection with the acquisition of natural gas leases and related pipelines and equipment from Devon Energy Production Company, L.P. and Tall Grass Gas Services, LLC in December 2003. Approximately $1.1 million of notes with various financial lenders for equipment and vehicle purchases comprise the remainder. 5. 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 our preliminary investigation, the Company believes that the claims against it are without merit and intends to defend against them vigorously. STP was named as Defendant in a lawsuit (Case #CJ-2003-137) filed by Plaintiff Davis Operating Company on October 14, 2003 in the District Court of Craig County, Oklahoma. Plaintiff was alleging improper operation of a gas gathering system. The plaintiff was seeking unspecified actual and punitive damages as a result of the alleged improper operations by STP. The case was heard by jury trial in September 2004 and the Plaintiff was awarded a judgment of approximately $178,000 that has been paid by the Company. 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. 6. FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES Natural Gas Hedging Activities The Company seeks to reduce its exposure to unfavorable changes in natural gas prices, which are subject to significant and often volatile fluctuation, through the use of fixed-price contracts. The fixed-price contracts are comprised of energy swaps and collars. These contracts allow the Company to predict with greater certainty the effective natural gas prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. Collar structures provide for participation in price increases and decreases to the extent of the ceiling and floor prices provided in those contracts. For the six months ended November 30, 2004, fixed-price contracts hedged 85.0% of the Company's natural gas production. As of November 30, 2004, fixed-price contracts are in place to hedge 23.0 Bcf of estimated future natural gas production. Of this total volume, 4.0 Bcf are hedged for fiscal 2005 and 19.0 Bcf thereafter. Reference is made to the Annual Report on Form 10-KSB for the year ended May 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 November 30, 2004. F-11 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS NOVEMBER 30, 2004 (UNAUDITED)

Six Months Ending Years Ending May 31, May 31, ---------------------------------------------------------------- 2005 2006 2007 2008 2009 Total ---- ---- ---- ---- ---- ----- (dollars in thousands, except price data) Natural Gas Swaps: Contract vols (MMBtu) 2,659,000 5,633,000 3,292,000 - - 11,584,000 Weighted-avg fixed price per MMBtu (1) $ 4.80 $ 4.62 $ 4.53 - - $ 4.64 Fixed-price sales $ 12,773 $ 26,030 $ 14,912 - - $ 53,715 Fair value, net $ (6,885) $ (12,669) $ (5,869) - - $ (25,423) Natural Gas Collars: Contract vols (MMBtu): Floor 1,483,000 2,437,000 2,580,000 3,356,000 1,712,000 11,568,000 Ceiling 1,483,000 2,437,000 2,580,000 3,356,000 1,712,000 11,568,000 Weighted-avg fixed price per MMBtu (1): Floor $ 5.04 $ 5.26 $ 5.03 $ 4.71 $ 4.50 $ 4.91 Ceiling $ 6.09 $ 6.31 $ 6.05 $ 5.72 $ 5.52 $ 5.93 Fixed-price sales (2) $ 9,030 $ 15,367 $ 15,598 $ 19,189 $ 9,450 $ 68,634 Fair value, net $ (1,681) $ (2,060) $ (2,092) $ (2,238) $ (748) $ (8,819) Total Natural Gas Contracts: Contract vols (MMBtu) 4,142,000 8,070,000 5,872,000 3,356,000 1,712,000 23,152,000 Weighted-avg fixed price per MMBtu (1) $ 5.26 $ 5.13 $ 5.20 $ 5.72 $ 5.52 $ 5.28 Fixed-price sales (2) $ 21,803 $ 41,397 $ 30,510 $ 19,189 $ 9,450 $ 122,349 Fair value, net $ (8,566) $ (14,729) $ (7,961) $ (2,238) $ (748) $ (34,242)

(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 November 30, 2004 and 2003, oil and gas sales included $1,532,000 and $0, respectively, of losses associated with realized losses under fixed-price contracts. For the six months ended November 30, 2004 and 2003, oil and gas sales included $3,312,000 and $0, 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 November 30, 2004 and 2003, other revenue and expense included $0 and $192,000, respectively, of losses associated with realized losses under fixed-price contracts. For the six months ended November 30, 2004 and 2003, other revenue and expense included $105,000 and $1,010,000, respectively, of losses associated with realized losses under fixed-price contracts. For fixed-price contracts qualifying as cash flow hedges, changes in fair value for volumes not yet settled are shown as adjustments to other comprehensive income. For those contracts not qualifying as cash flow hedges, changes in fair value for F-12 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS NOVEMBER 30, 2004 (UNAUDITED) volumes not yet settled are recognized in change in derivative fair value in the statement of operations. The fair value of all fixed-price contracts are recorded as assets or liabilities in the balance sheet. 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. In the current quarter, the Company entered into the following interest rate swaps and caps:

Fixed Rate / of November Instrument Type Term Notional Amount Cap Rate Floating Rate 30, 2004 ------------------------------------------------------------------------------------------------------------------------------------ $58,250,000 Interest Rate Swap March 2005 - March 2006 $53,875,000 2.795% 3-month LIBOR $251,000 $98,705,000 Interest Rate Cap March 2006 - Sept. 2007 $70,174,600 5.000% 3-month LIBOR $321,000

Change in Derivative Fair Value Change in derivative fair value in the statements of operations for the three months and six months ended November 30, 2004 and 2003 is comprised of the following:

Three Months Ended Six Months Ended November 30, November 30, ------------------------------------------------------------- 2004 2003 2004 2003 ------------------------------------------------------------- Change in fair value of derivatives not qualifying as cash flow hedges $ (4,215,000) $ 603,000 $ (3,503,000) $ 4,407,000 Amortization of derivative fair value gains and losses recognized in earnings prior to actual cash settlements 232,000 -- 507,000 -- Ineffective portion of derivatives qualifying as cash flow hedges (687,000) -- (1,011,000) -- ------------------------------------------------------------- $ (4,670,000) $ 603,000 $ (4,007,000) $ 4,407,000 =============================================================

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. F-13 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS NOVEMBER 30, 2004 (UNAUDITED) The change in carrying value of fixed-price contracts and interest rate swaps and caps in the balance sheet since May 31, 2004 resulted from an increase in market prices for natural gas and a decrease in interest rates. Derivative assets and liabilities reflected as current in the November 30, 2004 balance sheet represent the estimated fair value of fixed-price contract settlements scheduled to occur over the subsequent twelve-month period based on market prices for natural gas as of the balance sheet date. 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 November 30, 2004 and May 31, 2004 and the methods and assumptions used to estimate their fair value: November 30, 2004 May 31, 2004 -------------------- ------------------ Derivative assets: Interest rate swaps and caps $ 572,000 $ -- Derivative liabilities: Fixed-price natural gas collars $ (8,819,000) $ (1,644,000) Fixed-price natural gas swaps $ (25,423,000) $ (18,144,000) Bank debt $ (133,000,000) $ (103,700,000) Other financing agreements $ (1,439,000) $ (1,377,000) Subordinated debt (inclusive of accrued interest) $ (58,619,000) $ (54,459,000) 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 November 30, 2004 and May 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 November 30, 2004 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. 7. EARNINGS PER SHARE SFAS 128 requires a reconciliation of the numerator and denominator of the basic and diluted earnings per share (EPS) computations. The following securities were not included in the calculation of diluted earnings per share because their effect was anti-dilutive. o For the three months and six months ended November 30, 2004 and the three months ended November 30, 2003, 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. F-14 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS NOVEMBER 30, 2004 (UNAUDITED) o For the three months and six months ended November 30, 2004, dilutive shares do not include the assumed conversion of convertible debt (convertible into 4,000 and 8,000 shares, respectively) because the effects were antidilutive. o For the three months ended November 30, 2003, dilutive shares do not include the assumed conversion of convertible debt (convertible into 5,000 common shares) because the effects were anti-dilutive. o For the three months and six months ended November 30, 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 November 30, 2004: Net loss $ (5,954,000) Preferred stock dividends (2,000) --------------- Basic EPS loss available to common shareholders $ (5,956,000) 14,160,024 $ (0.42) Effect of dilutive securities: -------- None -- -- --------------- ------------ Diluted EPS loss available to common shareholders $ (5,956,000) 14,160,024 $ (0.42) =============== ============ ========= For the three months ended November 30, 2003: Income before cumulative effect of accounting change, net of tax $ 775,000 Preferred stock dividends (2,000) --------------- Basic EPS income available to common shareholders before cumulative effect of accounting change, net of tax $ 773,000 14,008,352 $ 0.06 Effect of dilutive securities: -------- Warrant issued to Wells Fargo -- 1,599,603 --------------- ------------ Diluted EPS income available to common shareholders $ 773,000 15,607,955 $ 0.05 =============== ============ ========= For the six months ended November 30, 2004: Net loss $ (5,873,000) Preferred stock dividends (5,000) --------------- Basic EPS loss available to common shareholders $ (5,878,000) 14,137,066 $ (0.42) Effect of dilutive securities: --------- None -- -- --------------- ------------ Diluted EPS loss available to common shareholders $ (5,878,000) 14,137,066 $ (0.42) =============== ============ ========= For the six months ended November 30, 2003: Income before cumulative effect of accounting change, net of tax $ 3,323,000 Preferred stock dividends (5,000) --------------- Basic EPS income available to common shareholders before cumulative effect of accounting change, net of tax $ 3,318,000 13,904,974 $ 0.24 Effect of dilutive securities: --------- Assumed conversion as of the beginning of the period of preferred shares outstanding during the period: Preferred stock dividends 5,000 Common shares assumed issued for 10% convertible preferred stock -- 40,000 F-15

Assumed conversion as of the beginning of the period of convertible debt outstanding during the period: Interest expense 1,000 Common shares assumed issued of 8% convertible debt -- 10,158 Warrant issued to Wells Fargo -- 1,599,567 --------------- ------------ Diluted EPS income available to common shareholders $ 3,324,000 15,554,699 $ 0.21 =============== ============ =========

QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS NOVEMBER 30, 2004 (UNAUDITED) 8. ASSET RETIREMENT OBLIGATIONS 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 and six months ended November 30, 2004 and 2003: Three Months Ended Six Months Ended November 30, November 30, -------------------------------------------- 2004 2003 2004 2003 -------------------------------------------- Asset retirement obligation beginning balance $ 783,000 $ 337,000 $ 717,000 $ 254,000 Liabilities incurred 56,000 7,000 111,000 86,000 Liabilities settled (2,000) (1,000) (3,000) (3,000) Accretion expense 12,000 6,000 24,000 12,000 Revisions in estimated cash flows -- -- -- -- -------------------------------------------- Asset retirement obligation ending balance $ 849,000 $ 349,000 $ 849,000 $ 349,000 ============================================ 9. SUBSEQUENT EVENTS No material subsequent events have occurred that warrant disclosure since the balance sheet date, other than as disclosed above in Note 4--Long Term Debt. F-16 Item 2. Management's Discussion and Analysis or Plan of Operation 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 for the fiscal year ended May 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 coalbed 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 Six Months Ended November 30, 2004 The Company has continued its development of new wells and the construction of supporting pipeline infrastructure. On June 1, 2004, the Company had 678 gas wells (gross) that it was operating and 179 gas wells (gross) that it was in the process of completing and connecting to its gas gathering pipeline system. During the six months ended November 30, 2004, the Company drilled 294 new gas wells (gross). The Company also connected 111 new gas wells (gross) into its gas gathering pipeline network during the same six-month period. This required the construction of approximately 80 miles of pipelines to gather gas and water from the new wells before they could become operational. As of November 30, 2004, the Company had 787 gas wells (gross) that it was operating and 344 gas wells (gross) that it was in the process of completing and connecting to its gas gathering pipeline system. Significant developments accomplished during the six months ended November 30, 2004 are described below: 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 $120.0 million six year term loan that was fully funded at closing and a $20.0 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 $5.0 million of the UBS Revolving Loan was utilized for the issuance of letters of credit. The UBS Amended Credit Agreement also contains a $15.0 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. See "--Liquidity and Capital Resources". The Company entered into an asset purchase agreement and a real estate purchase agreement on August 19, 2004 to acquire certain assets from Consolidated Oil Well Services in the amount of $4.1 million. The assets consist of cementing, acidizing and fracturing equipment and a related office building and storage facility in Chanute, Kansas. The acquisition closed on September 15, 2004 and was funded with a portion of the remaining net proceeds from the $120 million term loan under the UBS Credit Agreement. -4- Additionally, the Company acquired 8 wells and approximately 8,000 acres in the Cherokee Basin on August 6, 2004 for $750,000. 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 report on Form 10-KSB for the fiscal year ended May 31, 2004. Comparisons made between reporting periods herein are for the three and six months period ended November 30, 2004 as compared to the same period in 2003. In making comparisons to the year-earlier period, it is important to note that the three and six months ended November 30, 2004 includes results from the December 22, 2003 Devon asset acquisition. Therefore, caution should be exercised in making comparisons between the three and six months period ended November 30, 2004, and November 30, 2003. Three Months Ended November 30, 2004 Compared to Three Months Ended November 30, 2003 Total revenues of $10.7 million for the fiscal quarter ended November 30, 2004 represents an increase of 188% when compared to total revenues of $3.7 million for the fiscal quarter ended November 30, 2003. This increase was achieved by a combination of the addition of more producing wells, the Devon asset acquisition in December 2003, and the Company's aggressive new well development program. The increase in oil and gas sales from $3.5 million for the fiscal quarter ended November 30, 2003 to $9.8 million for the fiscal quarter ended November 30, 2004 and the increase in gas pipeline revenue from $544,000 to $818,000 resulted from the Devon asset acquisition, and the additional wells and pipelines acquired or completed during the past 12 months. The Devon asset acquisition and the additional wells acquired or completed contributed to the production of 2,114,000 mcf of net gas for the fiscal quarter ended November 30, 2004, as compared to 761,000 net mcf of gas produced in the prior fiscal quarter. The Company's product prices on an equivalent basis (mcfe) increased from $4.83 mcfe average for the fiscal quarter ended November 30, 2003 to $5.42 mcfe average for the fiscal quarter ended November 30, 2004. For the quarter ended November 30, 2004, the net product price, after accounting for hedge settlements of $1.5 million during the quarter, averaged $4.72 mcfe. For the quarter ended November 30, 2003, the net product price, after accounting for hedging settlements of $192,000 during the quarter, averaged $4.45 mcfe. Since new well development is an ongoing program, management expects most of the above revenue categories to continue growing in the foreseeable future. Other expense for the three months ended November 30, 2003 was $294,000 resulting from recording the loss on hedge settlements as compared to other revenue of $30,000 for the three-month period ended November 30, 2004. The operating costs for the quarter ended November 30, 2004 totaled $1.9 million, which is a 99% increase over the operating costs of $954,000 incurred for the quarter ended November 30, 2003. Lease operating costs per mcf for the fiscal quarter ended November 30, 2004 were $.90 per mcf as compared to $1.25 per mcf for the fiscal quarter ended November 30, 2003, representing a 28% decrease. Pipeline operating costs increased by 191% from $481,000 for the fiscal quarter ended November 30, 2003 to $1.4 million for the fiscal quarter ended November 30, 2004. 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 and a decrease in the amount of time spent servicing the wells. The substantial cost increases incurred in the oil and gas production costs categories and pipeline operating costs are due to the Devon asset acquisition, the number of wells acquired, completed and operated during the quarter and the increased miles of pipeline in service. The 284% increase in depreciation, depletion and amortization to $3.0 million from $780,000 is a result of the increased number of producing wells and miles of pipelines acquired and developed, the higher volumes of gas and oil produced and the higher cost of properties recorded by application of the purchase method of accounting to record the Devon asset acquisition. General and administrative expenses increased by 319% to $1.4 million for the quarter ended November 30, 2004 from $334,000 for the same period in the prior fiscal year, due to the Devon asset acquisition, the increased staffing to support the higher levels of development and operational activity and the added resources to enhance the Company's internal controls and financial reporting. Additionally, $291,000 is included as bad debt expense for the quarter ended November 30, 2004. Interest expense increased to $4.3 million for the fiscal quarter ended November 30, 2004 from $477,000 for the fiscal quarter ended November 30, 2003, due to the increase in the Company's outstanding borrowings related to the Devon asset acquisition and equipment, development and leasehold expenditures. Change in derivative fair value was a non-cash loss of $ 4.7 million for the three months ended November 30, 2004, which included a $4.2 million loss attributable to the change in fair value for certain derivatives that did not qualify as cash flow -5- hedges pursuant to SFAS 133, and a $232,000 net gain attributable to the reversal of contract fair value gains and losses recognized in earnings prior to actual settlement, partially offset by a loss of $687,000 relating to hedge ineffectiveness. Change in derivative fair value was a non-cash net gain of $603,000 for the three months ended November 30, 2003, which was attributable to the change in fair value for derivatives that did not qualify as cash flow hedges pursuant to SFAS 133. 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 generated a net loss before income taxes of $6.0 million, compared to income before income taxes and cumulative effect of accounting change of $1.3 million for the quarter ended November 30, 2003. The income tax benefit for the November 30, 2004 quarter was $54,000 compared to income tax expense of $516,000 being recorded for the November 30, 2003 quarter. The Company recorded a net loss of $1.3 million for the quarter ended November 30, 2004 as compared to net income of $413,000 for the quarter ended November 30, 2003, each period exclusive of the non-cash net gain or loss derived from the change in derivative fair value as stated above. Six Months Ended November 30, 2004 Compared to Six Months Ended November 30, 2003 Total revenues of $22.3 million for the six months ended November 30, 2004 represents an increase of 223% when compared to total revenues of $6.9 million for the six months ended November 30, 2003. This increase was achieved by a combination of the addition of more producing wells, the Devon asset acquisition in December 2003, and the Company's aggressive new well development program. The increase in oil and gas sales from $7.1 million for the six months ended November 30, 2003 to $20.6 million for the six months ended November 30, 2004 and the increase in gas pipeline revenue from $1.1 million to $1.6 million resulted from the Devon asset acquisition, and the additional wells and pipelines acquired or completed during the past 12 months. The Devon asset acquisition and the additional wells acquired or completed contributed to the production of 4,313,000 mcf of net gas for the six months ended November 30, 2004, as compared to 1,453,000 net mcf of gas produced in the prior six months period. The Company's product prices on an equivalent basis (mcfe) increased from $5.62 mcfe average for the six months ended November 30, 2003 to $5.65 mcfe average for the six months ended November 30, 2004. For the six months ended November 30, 2004, the net product price, after accounting for hedge settlements of $3.4 million during the quarter, averaged $4.87 mcfe. For the six months ended November 30, 2003, the net product price, after accounting for hedging settlement of $1.0 million during the quarter, averaged $4.73 mcfe. Since new well development is an ongoing program, management expects most of the above revenue categories to continue growing in the foreseeable future. Other expense for the six months ended November 30, 2003 was $1.3 million resulting from recording the loss on hedge settlements as compared to other revenue of $51,000 for the six-month period ended November 30, 2004. The operating costs for the six months ended November 30, 2004 totaled $4.2 million, which is a 133% increase over the operating costs of $1.8 million incurred for the six months ended November 30, 2003. Lease operating costs per mcf for the six months ended November 30, 2004 were $.99 per mcf as compared to $1.24 per mcf for the six months ended November 30, 2003, representing a 20% decrease. Pipeline operating costs increased by 206% from $947,000 for the six months November 30, 2003 to $2.9 million for the six months ended November 30, 2004. 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 and a decrease in the amount of time spent servicing the wells. The substantial cost increases incurred in the oil and gas production costs categories and pipeline operating costs are due to the Devon asset acquisition, the number of wells acquired, completed and operated during the six months and the increased miles of pipeline in service. The increase in depreciation, depletion and amortization by 307% to $6.1 million from $1.5 million is a result of the increased number of producing wells and miles of pipelines acquired and developed, the higher volumes of gas and oil produced and the higher cost of properties recorded by application of the purchase method of accounting to record the Devon asset acquisition. General and administrative expenses increased by 258% to $2.4 million for the six months ended November 30, 2004 from $671,000 for the same period in the prior fiscal year, due to the Devon asset acquisition, the increased staffing to support the higher levels of development and operational activity and the added resources to enhance the Company's internal controls and financial reporting. Additionally, $291,000 is included as bad debt expense for the six months ended November 30, 2004. -6- Interest expense increased to $8.6 million for the six months ended November 30, 2004 from $830,000 for the six months ended November 30, 2003, due to the increase in the Company's outstanding borrowings related to the Devon asset acquisition and equipment, development and leasehold expenditures. Change in derivative fair value was a non-cash loss of $ 4.0 million for the six months ended November 30, 2004, which included a $3.5 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 $507,000 net gain attributable to the reversal of contract fair value gains and losses recognized in earnings prior to actual settlement, partially offset by a loss of $1.0 million relating to hedge ineffectiveness. Change in derivative fair value was a non-cash net gain of $4.4 million for the six months ended November 30, 2003, which was attributable to the change in fair value for derivatives that did not qualify as cash flow hedges pursuant to SFAS 133. 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 generated a net loss before income taxes of $5.9 million for the six months ended November 30, 2004, compared to income before income taxes and cumulative effect of accounting change of $5.5 million for the six months ended November 30, 2003. No income tax effect was recorded for the six months ended November 30, 2004 compared to income tax expense of $2.2 million being recorded for the six months ended November 30, 2003. The Company recorded a net loss of $1.9 million for the six months ended November 30, 2004 as compared to net income of $679,000 for the six months ended November 30, 2003, each period exclusive of the non-cash net loss and gain derived from the change in derivative fair value as stated above, for the respective period. Capital Resources and Liquidity At November 30, 2004, the Company had current assets of $14.2 million, a working capital deficit (current assets minus current liabilities, excluding the short-term derivative assets and liabilities) of $2.7 million and had generated $17.6 million net cash from operations during the six months ended November 30, 2004. During the six months ended November 30, 2004, a total of approximately $38.9 million was invested in new natural gas wells and properties, new pipeline facilities, and other additional capital items. This investment was funded by operational cash flow and additional borrowings under the Company's credit facilities. Net cash provided from operating activities increased from $2.4 million for the six months ended November 30, 2003 to $17.6 million for the six months ended November 30, 2004 due primarily to the expanded operations of the Company as discussed above. The Company had a working capital deficit (current assets minus current liabilities, excluding the short-term derivative assets and liabilities) of $2.7 million at November 30, 2004, compared to working capital of $4.4 million at May 31, 2004, excluding net short-term derivative liabilities of $13.1 million at November 30, 2004 and $10.1 million at May 31, 2004. The decrease results from the significant capital expenditures related to the expanded operations, including the completion of the Devon asset acquisition. Additionally, inventory, accounts payable, oil and gas payable and accrued expenses balances increased as the Company continues to expand its operations. There is a substantial increase in payables on the balance sheet for November 30, 2004 as compared to May 31, 2004. This increase is due to the substantial increase in operating activity being conducted by the Company. Management anticipates that after the quarter ended March 31, 2005, capital expenditures will decrease as the Company intends to fund capital expenditures from cash flows for the remainder of calendar year 2005. The Company intends to continue developing additional wells. For calendar year 2005, the Company currently intends to connect 310 gas wells that had been drilled, but not connected to the Company's gas gathering pipeline systems as of December 31, 2004 and intends to drill and complete approximately 159 gas wells during calendar year 2005. Approximately, 300 re-completions are scheduled for calendar year 2005. The Company currently estimates that this development program will require approximately $36.6 million, including approximately $7.0 million of pipeline capital expenditures. Management anticipates funding the majority of this well and pipeline development with internally generated cash flow and the remainder from funds from the financing received from the issuance of the additional subordinated notes and from the additional funds provided from the credit facilities with UBS discussed below. However, no assurances are given that such sources will be sufficient to fund the Company's anticipated level of well and pipeline development. In the event that additional financing is required, the Company could seek to borrow additional funds or -7- sell equity securities. However, no assurances are given that the Company would be able to obtain such financing on terms favorable to Quest, if at all. The Company determined that it is not feasible to develop the property in western Kentucky and elected to not extend the lease, as the Company would have been required to obtain significant additional capital resources to drill and complete wells on this property. As this property was outside of Quest Cherokee, the assets and financial resources of Quest Cherokee were not available to support the development of this property. The Company acquired certain assets from Consolidated Oil Well Services on September 15, 2004 in the amount of $4.1 million. The assets consist of cementing, acidizing and fracturing equipment and a related office building and storage facility in Chanute, Kansas. The Company acquired approximately 80 miles of an inactive oil pipeline for approximately $1.0 million on August 10, 2004. The Company intends to convert this former oil pipeline into a natural gas pipeline. Additionally, the Company acquired 8 wells and approximately 8,000 acres in the Cherokee Basin on August 6, 2004 for $750,000. All of these acquisitions were funded with a portion of the remaining net proceeds from the $120.0 million term loan under the credit facility with UBS in July 2004. Credit Agreement and Subordinated Notes As previously disclosed, in December 2003, the direct subsidiary companies of Quest Resource Corporation (the "Company") formed a subsidiary company, Quest Cherokee, LLC, a Delaware limited liability company ("Quest Cherokee") to acquire certain oil and gas assets of Devon Energy Corporation located in the Cherokee Basin area of northeastern Oklahoma and southeastern Kansas (the "Devon Acquisition"). Concurrent with the Devon Acquisition, the Company contributed its other Cherokee Basin oil and gas assets to Quest Cherokee and it became the Company's primary operating subsidiary. The Devon Acquisition was financed with the proceeds of a credit facility and the issuance of $51.0 million of Quest Cherokee's 15% Junior Subordinated Promissory Notes (the "Original Notes") to Cherokee Energy Partners, LLC ("Cherokee Partners"), which is wholly-owned by ArcLight Energy Partners Fund I, L.P. ("ArcLight"), pursuant to the terms of a Note Purchase Agreement (the "Note Purchase Agreement") dated as of December 22, 2003 between Quest Cherokee and Cherokee Partners. In connection with Cherokee Partners' purchase of the Original Notes, Quest Cherokee's original limited liability company agreement was amended and restated (as amended and restated, the "LLC Agreement") to, among other things, provide for Class A units and Class B units of membership interest, with all of the Class A units being issued to Cherokee Partners, and all of the Class B units being issued to the Company's direct subsidiaries. See the Company's Form 8-K filed on January 6, 2004 for additional information related to the terms of Cherokee Partners' investment. On July 22, 2004, Quest Cherokee refinanced the credit facility entered into in connection with the Devon Acquisition with its current $155.0 million credit facility. Between July 22, 2004 and November 30, 2004, Quest Cherokee drilled 225 new wells of which 97 wells were in excess of the budgeted number of wells to be drilled during that period. Quest Cherokee drilled the additional wells in order to maximize efficiencies as it expanded its pipeline system to new regions. During the same period, Quest Cherokee only connected 86 new wells to its pipeline gathering system, which was 117 wells less than the budgeted number of wells to be connected during that period. The decrease in the number of new wells connected was due to unseasonable weather and labor delays that significantly slowed the pace of connections. In addition, the connection of new wells was also slowed by Quest Cherokee's decision to expand its trunk line system to increase its long-term capacity. As a result, Quest Cherokee's average daily gross production for the month of November was 32,453 mmcfe/day as compared to an average daily gross production for the month of July of 32,548 mmcfe/day. As a result of the foregoing, in January 2005, Quest Cherokee determined that it was not in compliance with the leverage and interest coverage ratios in the credit facility for the quarter ended November 30, 2004. During the period from November 30, 2004 through February 16, 2004, Quest Cherokee has connected an additional 92 new wells and has increased its average daily gross production to 34,494 mmcfe/day for the first 14 days of February. In addition, management began working with ArcLight and its lenders in early January 2005 to provide additional funds to Quest Cherokee and to waive the defaults under the credit facility. On February 11, 2005, Quest Cherokee and Cherokee Partners amended and restated the Note Purchase Agreement to provide for the issuance to Cherokee Partners of up to $15.0 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 (the "Amended Note Purchase Agreement"). Also on February 11, 2005, Quest Cherokee issued $5.0 million of Additional Notes to Cherokee Partners (the "Second Issuance"). As a condition to the Second Issuance, the following changes were made to the terms of Cherokee Partners' original investment in Quest Cherokee: -8- (i) the make-whole payment due to Cherokee Partners in the event that Quest Cherokee is dissolved was changed from (a) the difference between the amount Cherokee Partners has received on account of principal and interest on the Original Notes and 150% of the original principal amount of the Original Notes, to (b) the difference between the amount Cherokee Partners has received on account of principal and interest on the Subordinated Notes and 140% of the original principal amount of the Subordinated Notes--this change effectively removed any make-whole premium with respect to the Additional Notes in the event of an early liquidation of Quest Cherokee; (ii) 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 (iii)after the Subordinated Notes have been repaid and Cherokee Partners 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 Cherokee Partners (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 Cherokee Partners and 70% to the Company's subsidiaries. The Amended Note Purchase Agreement also provided for Quest Cherokee to issue to Cherokee Partners Additional Notes in the principal amount of $7.0 million (the "Third Issuance"). The Third Issuance was conditioned on, among other things, Quest Cherokee obtaining a waiver from the lenders under the 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 Cherokee Partners. On February 22, 2005, Quest Cherokee received the necessary waivers and amendments to the credit agreement to permit the Third Issuance and the $7.0 million of Additional Notes were issued to Cherokee Partners. The amendment and waiver to the credit agreement also provided for $5.0 million of additional term loans from the lenders under the credit agreement - "See Note 4, Long-Term Debt - UBS Credit Facility" for more information relating to the terms of the amendment to the credit agreement. Finally, the Amended Note Purchase Agreement provides Quest Cherokee with the option to issue to Cherokee Partners Additional Notes in the principal amount of $3.0 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 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 Cherokee Partners 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 Cherokee Partners (as the holder of the Class A Units) and 60% to the Company's subsidiaries (as the holders of the Class B Units). It is not currently anticipated that Quest Cherokee will exercise its option to issue any Additional Notes in a Fourth Issuance. Other Long-Term Indebtedness QES has one promissory note with an authorized credit limit of $440,000. The note matures on February 19, 2008, bears interest at the annual rate of 7% per annum, requires monthly payments based upon a 60-month amortization, is secured by equipment and rolling stock, and had a principal balance outstanding on November 30, 2004 of $229,000. The obligation under this note was assumed by Quest Cherokee as part of the restructuring of the Company's operations in connection with the acquisition of natural gas leases and related pipelines and equipment from Devon Energy Production Company, L.P. and Tall Grass Gas Services, LLC in December 2003. Approximately $1.1 million of notes with various financial lenders for equipment and vehicle purchases comprise the remainder. -9- Wells Fargo Energy Capital Warrant In connection with the entering into the credit agreement with Wells Fargo Energy Capital on November 7, 2002, the Company issued a warrant to Wells Fargo Energy Capital for 1,600,000 shares of common stock with an exercise price of $0.001 per share. Under the terms of the warrant, the repayment of the Wells Fargo Energy Capital credit agreement on December 22, 2003 in connection with the Devon asset acquisition triggered a put option under the warrant in favor of Wells Fargo Energy Capital. Under the terms of the put option, Wells Fargo Energy Capital may require the Company to purchase the warrant at any time prior to November 7, 2007 for an amount equal to approximately $950,000 (which amount is calculated as if interest was borne at the rate of 18% on the amounts outstanding under the Wells Fargo Energy Capital credit agreement during its term less any cash interest actually paid to Wells Fargo Energy Capital). In the event that Wells Fargo Energy Capital were to exercise the put option in the near future, the Company may have difficulty satisfying its obligations under the warrant since it does not have any readily available sources of liquidity, as this is a Company obligation and not an obligation of Quest Cherokee, LLC. Natural Gas Hedging Activities The Company seeks to reduce its exposure to unfavorable changes in natural gas prices, which are subject to significant and often volatile fluctuation, through the use of fixed-price contracts. The fixed-price contracts are comprised of energy swaps and collars. These contracts allow the Company to predict with greater certainty the effective natural gas prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. Collar structures provide for participation in price increases and decreases to the extent of the ceiling and floor prices provided in those contracts. The following table summarizes the estimated volumes, fixed prices, fixed-price sales and fair value attributable to the fixed-price contracts as of November 30, 2004.

Six Months Ending Years Ending May 31, May 31, ---------------------------------------------------------------- 2005 2006 2007 2008 2009 Total ---- ---- ---- ---- ---- ----- (dollars in thousands, except price data) Natural Gas Swaps: Contract vols (MMBtu) 2,659,000 5,633,000 3,292,000 - - 11,584,000 Weighted-avg fixed price per MMBtu (1) $ 4.80 $ 4.62 $ 4.53 - - $ 4.64 Fixed-price sales $ 12,773 $ 26,030 $ 14,912 - - $ 53,715 Fair value, net $ (6,885) $ (12,669) $ (5,869) - - $ (25,423) Natural Gas Collars: Contract vols (MMBtu): Floor 1,483,000 2,437,000 2,580,000 3,356,000 1,712,000 11,568,000 Ceiling 1,483,000 2,437,000 2,580,000 3,356,000 1,712,000 11,568,000 Weighted-avg fixed price per MMBtu (1): Floor $ 5.04 $ 5.26 $ 5.03 $ 4.71 $ 4.50 $ 4.91 Ceiling $ 6.09 $ 6.31 $ 6.05 $ 5.72 $ 5.52 $ 5.93 Fixed-price sales (2) $ 9,030 $ 15,367 $ 15,598 $ 19,189 $ 9,450 $ 68,634 Fair value, net $ (1,681) $ (2,060) $ (2,092) $ (2,238) $ (748) $ (8,819) Total Natural Gas Contracts: Contract vols (MMBtu) 4,142,000 8,070,000 5,872,000 3,356,000 1,712,000 23,152,000 Weighted-avg fixed price per MMBtu (1) $ 5.26 $ 5.13 $ 5.20 $ 5.72 $ 5.52 $ 5.28 Fixed-price sales (2) $ 21,803 $ 41,397 $ 30,510 $ 19,189 $ 9,450 $ 122,349 Fair value, net $ (8,566) $ (14,729) $ (7,961) $ (2,238) $ (748) $ (34,242)

(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 -10- significant volatility. The fair value estimates shown above are subject to change as forward market prices and basis change. See Note 6 of the Notes to Consolidated Financial Statements. 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 bank credit facility. 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. In the current quarter, the Company entered into the following interest rate swaps and caps:

Fixed Rate / of November Instrument Type Term Notional Amount Cap Rate Floating Rate 30, 2004 ------------------------------------------------------------------------------------------------------------------------------------ $58,250,000 - Interest Rate Swap March 2005 - March 2006 $53,875,000 2.795% 3-month LIBOR $251,000 $98,705,000 - Interest Rate Cap March 2006 - Sept. 2007 $70,174,600 5.000% 3-month LIBOR $321,000

Off-Balance Sheet Arrangements At May 31, 2004 and November 30, 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. Controls and Procedures. As of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures. 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. Based upon and as of the date of the evaluation, our Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective in all material respects to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported as and when required. However, this quarterly filing was delayed due to certain personnel matters, including several personnel departures from the Company. There were no changes in the Company's internal control over financial reporting that occurred during the quarter ended November 30, 2004 that materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting. Subsequent to the quarter end, the Company began implementing a purchase order (PO) system that will be effective March 1, 2005. -11- PART II -OTHER INFORMATION Item 1. Legal Proceedings See Part I, Item 1, Note 5 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. Recent Sales of Unregistered Securities and Use of Proceeds On August 23, 2004, the Company granted a total of 25,000 shares of its common stock to Mr. John Garrison as compensation for services on the Company's audit committee during the period from June 6, 2003 to May 31, 2005. Of the shares granted, 17,000 shares were issued with a value of $62,000 for financial reporting purposes. The remaining 8,000 shares are restricted and subject to forfeiture in the event that Mr. Garrison resigns from the Company's audit committee before May 31, 2005 and will be issued when the restrictions have lapsed. The issuance of the shares is exempt from registration pursuant to Section 4(2) of the Securities Act. On November 8, 2004, 120,000 shares of common stock sold for cash with a value of $480,000 were issued to the following accredited investors: Fred B. Oates, Theodore Wannamaker Gage, Jr., Kate O. Dargan, Frank A. Jones, Larry Joe Vin Zant, Kenneth A. and Victoria M. Hull, Whitney and Elizabeth Vin Zant, Mark N. Vin Zant. These transactions were exempt from registration pursuant to either Section 4(2) of the Securities Act or Regulation D. These securities were sold without a general solicitation, and to accredited investors. The securities were issued with a legend restricting resale. Item 3. Default Upon Senior Securities On September 21, 2004 Quest Cherokee L.L.C. entered into interest rate swap and interest rate cap transactions with UBS AG London branch, which are described in Note 6 to the Condensed Consolidated Financial Statements included in this report. Item 4. Submission of Matters to Vote of Security Holders None Item 5. Other Information On September 21, 2004, Quest Cherokee L.L.C. entered into interest rate swap and interest rate cap transactions with UBS AG London branch, which are described in Note 6 to the Condensed Consolidated Financial Statements included in this report. Item 6. Exhibits **4.1 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. *4.2 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). *10.1 Amendment 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). -12- **10.2 Amendment No. 1 dated as of September 22, 2004 to Employment Agreement between the Company and Jerry Cash **10.3 Amendment No. 1 dated as of September 22, 2004 to Employment Agreement between the Company and Douglas Lamb **10.4 Interest Rate Cap Transaction Agreements between the Quest Cherokee L.L.C. and UBS AG London Branch dated September 21, 2004 **10.5 Interest Rate Swap Transaction Agreements between the Quest Cherokee L.L.C. and UBS AG London Branch dated September 21, 2004 **31.1 Certification of Chief Executive Officer of Quest Resource Corporation pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. **31.2 Certification of Chief Financial Officer of Quest Resource Corporation pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. **32.1 Certification of Chief Executive Officer of Quest Resource Corporation pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. **32.2 Certification of Chief Financial Officer of Quest Resource Corporation 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 herewith -13- SIGNATURES In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned; thereunto duly authorized this 23rd day of February, 2005. QUEST RESOURCE CORPORATION By: /s/ Jerry D. Cash ----------------------------------- Jerry D. Cash Chief Executive Officer By: /s/ David E. Grose ----------------------------------- David E. Grose Chief Financial Officer -14-