10-K 1 v038902_10k.txt UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) |X| Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2005. |_| Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Commission file number: 0-17371 ---------------------- QUEST RESOURCE CORPORATION (Exact Name of Registrant as Specified in Its Charter) ---------------------- Nevada 90-0196936 (State or Other Jurisdiction of (I.R.S. Employer Incorporation or Organization) Identification No.) 9520 N. May, Suite 300, Oklahoma City, Oklahoma 73120 (Address of Principal Executive Offices) (Zip Code) Registrant's Telephone Number: 405-488-1304 Securities Registered Pursuant to Section 12(b) of the Exchange Act: None Securities Registered Pursuant to Section 12(g) of the Exchange Act: Common Stock, $0.001 Par Value ------------------------------ (Title of Class) Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes |_| No |X| Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes |_| No |X| Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes |X| No |_| Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (ss.229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one): Large accelerated filer |_| Accelerated filer |_| Non-accelerated filer |X| Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes |_| No |X| 1 The aggregate market value of the voting stock held by non-affiliates computed by reference to the last reported sale of the registrant's common stock on June 30, 2005, the last business day of the registrant's most recently completed second fiscal quarter, at $7.50 per share was $22,139,373. This figure assumes that only the directors and officers of the registrant, their spouses and controlled corporations were affiliates. There were 22,072,383 shares outstanding of the registrant's common stock as of March 31, 2006. 2 TABLE OF CONTENTS PART I ITEMS 1. AND 2. BUSINESS AND PROPERTIES....................................4 ITEM 1A. RISK FACTORS..............................................22 ITEM 1B. UNRESOLVED STAFF COMMENTS.................................32 ITEM 3. LEGAL PROCEEDINGS.........................................32 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.......32 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES................................................32 ITEM 6. SELECTED FINANCIAL DATA...................................33 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.......................35 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK...............................................48 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA..............F-1 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE....................51 ITEM 9A. CONTROLS AND PROCEDURES...................................51 ITEM 9B. OTHER INFORMATION.........................................51 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT........51 ITEM 11. EXECUTIVE COMPENSATION....................................56 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS............58 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS............65 ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES....................65 PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENTS SCHEDULES..................66 SIGNATURES................................................67 INDEX TO EXHIBITS.........................................68 3 PART I ITEMS 1. AND 2. DESCRIPTION OF BUSINESS AND PROPERTIES. The Company and Subsidiaries Quest Resource Corporation. Quest Resource Corporation is a Nevada corporation and was incorporated on July 12, 1982. Its principal executive offices are located at 9520 N. May Avenue, Suite 300, Oklahoma City, OK 73120 and its telephone number is (405) 488-1304. Quest Resource Corporation is referred to in this report as the "Company," "Quest," "we," "us" and "our." The Company is a holding company that conducts its operations primarily through its wholly-owned subsidiaries. Unless otherwise indicated, references to the Company include the Company's operating subsidiaries. Quest Cherokee, LLC. Our principal operating subsidiary is Quest Cherokee, LLC, a Delaware limited liability company ("Quest Cherokee"), which owns all of our natural gas and oil leases in the Cherokee Basin in southeastern Kansas and northeastern Oklahoma. Bluestem Pipeline, LLC. Our natural gas gathering pipeline network is owned by Bluestem Pipeline, LLC, a Delaware limited liability company ("Bluestem"). Bluestem is a wholly-owned subsidiary of Quest Cherokee. Quest Cherokee Oilfield Services, LLC. Our field equipment is owned by Quest Cherokee Oilfield Service, LLC, a Delaware limited liability company ("QCOS"). QCOS also employees all of our field level employees and first line supervisors. QCOS is a wholly-owned subsidiary of Quest Cherokee. Other Subsidiaries. Our remaining subsidiaries are: o STP Cherokee, Inc., an Oklahoma corporation ("STP"), o Quest Energy Service, Inc., a Kansas corporation ("QES"), o Quest Oil & Gas Corporation, a Kansas corporation ("QOG"), o Producers Service, Incorporated, a Kansas corporation ("PSI"), o Ponderosa Gas Pipeline Company, a Kansas corporation ("PGPC"), and o J-W Gas Gathering, L.L.C., a Kansas limited liability company ("J-W Gas"). QES, QOG, PGPC and STP are wholly-owned by Quest. PGPC owns all of the outstanding capital stock of PSI and PSI is the sole member of J-W Gas. Together these subsidiaries own all of the membership interests in Quest Cherokee. Our executive officers and administrative employees are employed by QES. Change in Fiscal Year. We elected to change our year-end from May 31 to December 31, effective January 1, 2005. Accordingly, our financial statements included in this report consist of the financial statements for the fiscal year ended May 31, 2004, the seven-month transition period ended December 31, 2004 and the calendar year ended December 31, 2005. General A Glossary of Oil and Gas Terms is found at the end of this Item 1 on page 20. We are an independent energy company engaged in the exploration, development and production of natural gas. Our operations are currently focused on the development of coal bed methane or CBM in a ten county region in southeastern Kansas and northeastern Oklahoma known as the Cherokee Basin. As of December 31, 2005, we had 134.5 Bcfe of net proved reserves with a PV-10 value of $482.5 million. Our reserves are approximately 99% CBM and 54% proved developed. We believe we are the largest producer of natural gas in the Cherokee Basin with an average net daily production of 26.2 mmcfe for the year ended December 31, 2005. Our reserves are long-lived with a reserve life index of 16.3 years. 4 As of December 31, 2005, we owned the development rights to 494,985 net CBM acres throughout the Cherokee Basin and had developed approximately 40% of our acreage. We presently operate approximately 1,055 producing gas and oil wells. Our undeveloped acreage contains approximately 1,800 CBM drilling locations. Of the over 1,000 CBM wells that have been drilled on our acreage to date, over 98% have been successful. None of our acreage or producing wells is associated with coal mining operations. In addition to our CBM reserves and acreage, we own and operate a gas gathering pipeline network of approximately 1,100 miles that serves our acreage position. Presently, this system has a maximum daily throughput of 70 mmcf/d and is operating at about 54% capacity. We transport 100% of our production through our gas gathering pipeline network to interstate pipeline delivery points. Approximately 10% of the current volumes transported on our pipeline system are for third parties. As of December 31, 2005, we had an inventory of 228 drilled CBM wells awaiting connection to our gas gathering system. It is our intention to focus on the development of CBM reserves that can be immediately served by our gathering system. In addition, we plan to continue to expand our gathering system to serve other areas of the Cherokee Basin where we intend to acquire additional CBM acreage for development. Summary of Cherokee Basin Properties as of December 31, 2005 Estimated Net Proved Reserves (Bcfe) 134.5 Percent Proved Developed (1) 53.4% Producing Gas and Oil Wells 1,055 Approximate No. of Drill Sites Available 1,800 Net Developed Acres (2) 211,182 Net Undeveloped Acres (2) 283,803 ------- Total Net Acres 494,985 ======= ------------- (1) We estimate the cost as of December 31, 2005 to fully develop our proved undeveloped and proved developed non-producing reserves excluding abandonment is $122.4 million, including pipeline expansion. (2) Represents acreage with wells drilled on 160 acre spacing locations. Recent Drilling and Completion Activity and Pipeline Miles 12 Months Ended December 31, ---------------------------- 2005 2004 ---- ---- Wells Drilled 99 466 Wells Recompleted 205 18 Wells Connected 233 164 Pipeline Miles 120 141 Well Completion % 98% 98% Total Capital Expenditures - (in thousands) $41,442(1) $53,600 --------------- (1) Capital expenditures represent cash transactions - excludes $6.0 million for other assets and $26.1 million for the purchase of Class A units from ArcLight Energy Partners Fund I, L.P., through its wholly-owned subsidiary, Cherokee Energy Partners, LLC (collectively, "ArcLight"), in November 2005. 5 Recent Developments Default Under UBS Credit Agreement and Additional ArcLight Financing In January 2005, Quest Cherokee determined that it was not in compliance with the leverage and interest coverage ratios in its secured credit facility arranged and syndicated by UBS Securities LLC, with UBS AG, Stamford Branch as administrative agent (the "UBS Credit Agreement") for the quarter ended November 30, 2004. Despite the fact that we drilled 330 wells during the seven month transition period ended December 31, 2004, we were only able to complete and connect a total of 117 wells during that same period. We were delayed in connecting additional wells to our system due to construction delays in the expansion of our pipeline network that were largely caused by wet ground conditions from a significantly above average amount of rainfall during that period. On February 11, 2005, Quest Cherokee and ArcLight amended and restated the note purchase agreement entered into between them in December 2003 to provide for the issuance to ArcLight of up to $15 million of additional 15% junior subordinated promissory notes (the "Additional Notes") pursuant to the terms of an amended and restated note purchase agreement. Also on February 11, 2005, Quest Cherokee issued $5 million of Additional Notes to ArcLight. The February 11, 2005 amended and restated note purchase agreement also provided for Quest Cherokee to issue to ArcLight Additional Notes in the principal amount of $7 million upon Quest Cherokee obtaining a waiver from the lenders under the UBS Credit Agreement with respect to Quest Cherokee's default under the credit agreement and an amendment to the credit agreement to permit the issuance of Additional Notes to ArcLight. On February 22, 2005, Quest Cherokee obtained the necessary waivers and amendments to the UBS Credit Agreement and issued the $7 million of Additional Notes. At the same time, Quest Cherokee borrowed $5 million of additional term loans under the UBS Credit Agreement, $2 million of which was used to repay amounts owing under the revolving credit facility portion of the UBS Credit Agreement. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations--Capital Resources and Liquidity--Default Under UBS Credit Agreement and Additional ArcLight Financing" for additional information regarding the above matters. Recapitalization Due to restrictions put in place in connection with the amendment to the UBS Credit Agreement, we were unable to drill any additional wells until our gross daily production was at least 43 mmcf/d for 20 of the last 30 days prior to the date of drilling, after which time we could 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 did not exceed 250. We were unable to obtain these production goals without the drilling of additional wells, so our management team began exploring various strategic and refinancing alternatives. As a result of these efforts, in the fourth quarter of 2005, we completed a significant recapitalization of our capital structure. The recapitalization consisted of the following items: Reverse Stock Split. A 2.5 to 1 reverse stock split and a reduction in the number of Quest's authorized shares of common stock to 380 million became effective on October 31, 2005. The number of outstanding shares, per share data and common stock prices contained in this Form 10-K have been adjusted to take into account the effects of the reverse stock split. Private Placement of Common Stock. On November 14, 2005, Quest issued 15,258,144 shares of its common stock in a private placement. Quest's gross proceeds in the private placement were approximately $198.4 million. After deducting the initial purchaser's/placement agent's discount and placement fees and commissions of approximately $13.5 million and paying other expenses of approximately $1.0 million associated with the transaction, Quest's net proceeds were approximately $183.3 million. The following table represents the sources and uses of funds from the private placement and the New Credit Facilities: 6

Sources Uses ---------------------------------------------- -------------------------------------- Private equity, net of expenses $183,272,000 Payoff bank debt $138,088,000 Term loan 100,000,000 Payoff subordinated notes 83,911,000 Purchase Class A units 26,088,000 Cash to collateralize letters of credit 17,068,000 Cash to Quest 12,331,000 New credit facility fees 4,250,000 Legal/other fees 1,536,000 ------------ ------------ Total sources $283,272,000 Total uses $283,272,000 ============ ============

Buy-Out of ArcLight Investment in Quest Cherokee. We used a portion of the net proceeds from the sale of Quest's common stock to buy-out the investment of ArcLight in Quest Cherokee. The buy-out was completed pursuant to the terms of an Agreement for Purchase and Sale of Units (the "ArcLight Purchase Agreement"), dated as of November 7, 2005, by and among Cherokee Energy Partners, LLC ("Cherokee Energy Partners") and our wholly-owned subsidiaries that owned the Class B equity interests in Quest Cherokee (the "Subsidiaries"). The closing of this transaction occurred simultaneously with the closing of the private placement of common stock. At the closing, a portion of the proceeds from the private placement were used to loan approximately $110 million to the Subsidiaries in order to provide them with sufficient funds to complete the buy-out of the ArcLight investment. The Subsidiaries then paid approximately $26.1 million of this amount to purchase all of the Class A units in Quest Cherokee from ArcLight of which $2.1 million was allocated by the Company to non-producing leasehold and the remainder was allocated to the Company's wells and pipeline assets. After giving effect to these purchases, Quest Cherokee became an indirect wholly-owned subsidiary of our company. The Subsidiaries then loaned the remaining $83.9 million to Quest Cherokee, which used such funds to repay in full the principal and interest owed to ArcLight pursuant to certain promissory notes previously issued by Quest Cherokee to ArcLight. The $26.1 million purchase price for the Class A units was arrived at through negotiations between the Company and ArcLight. The $83.9 million amount for the payoff of promissory notes held by ArcLight was calculated as the amount necessary for full payment and satisfaction of the principal balance of the promissory notes and accrued but unpaid interest. As a result of the completion of the transactions set forth in the ArcLight Purchase Agreement, ArcLight does not have any continuing right or interest as an owner or member of or lender to Quest Cherokee. At closing, we (and our Subsidiaries) executed mutual releases with Cherokee Energy Partners which waived and released any rights or obligations that Cherokee Energy Partners had at any time as a result of being an owner, member or lender of or to Quest Cherokee. In connection with the buy-out of the ArcLight investment, the parties also terminated a Guaranty, which we previously gave to Cherokee Energy Partners, which guaranteed the performance by the Subsidiaries of their indemnification obligations in connection with ArcLight's original investment in Quest Cherokee. The parties also terminated the Pledge Agreement that provided collateral security to Cherokee Energy Partners for the performance by the Subsidiaries of their indemnification obligations in connection with ArcLight's original investment in Quest Cherokee. The mutual release executed by the parties did not release Cherokee Energy Partners, and it has agreed to continue to be bound by, certain obligations of confidentiality contained in the Limited Liability Company Agreement of Quest Cherokee for a period of five years; and Cherokee Energy Partners has agreed that it and certain of its affiliates continue to be bound by the terms of a Non-Competition Agreement for a period of two years following the closing. Since Quest Cherokee is now a wholly-owned indirect subsidiary, the management and operating agreement that was entered into between Quest Energy Service and Quest Cherokee on December 22, 2003 in connection with ArcLight's investment in Quest Cherokee was terminated on November 14, 2005. New Credit Facilities. Simultaneously with the closing of the private placement of common stock, we replaced the existing UBS credit facility with new credit facilities. The new credit facilities consist of a $50 million syndicated five year senior secured first lien revolving credit facility that initially has $50 million of availability (the "New Revolving Loan"); a $50 million syndicated five year senior secured first lien term loan facility that was fully drawn as of February 14, 2006 (the "New First Lien Term Loan"); and a syndicated six year $100 million senior secured second lien term loan facility (the "New Second Lien Term Loan") that was fully drawn at the November 14, 2005 closing of the private placement (collectively, the "New Credit Facilities"). Guggenheim Corporate Funding, LLC ("Guggenheim") is the administrative agent under the New Credit Facilities. See Note 3 "Long-Term Debt--New Credit Facilities - Guggenheim" to our consolidated financial statements contained elsewhere in this report for a more detailed description of the material terms of the New Credit Facilities. 7 Benefits of the Recapitalization. Management believes that the recapitalization has had the following positive effects: o the recapitalization has significantly improved our chances to access the equity capital markets and pursue our growth strategy; o we have been able to recommence our drilling program by eliminating the restrictions in our prior credit agreement and by obtaining additional liquidity; o our board of directors now has complete control of Quest Cherokee's operations, which were previously shared with ArcLight; and o the buy-out of ArcLight's investment in Quest Cherokee and the elimination of ArcLight's preferred return on its Class A equity interest in Quest Cherokee has significantly reduced our cost of capital and increased the value of Quest's common stock. Recent Acquisitions Quest Cherokee acquired certain assets from Faith Well Service on November 30, 2005 in the amount of $1.5 million. The assets consisted of service rigs and related equipment. The acquisition was funded with a portion of the net proceeds from the private placement of common stock that closed on November 14, 2005. The Company acquired approximately 10 miles of pipeline and 2,340 acres of leasehold from Venture Independent Petroleum during 2005 for $365,000. Business Strategy Our goal is to create stockholder value by investing capital to increase reserves, production and cash flow. We intend to accomplish this goal by focusing on the following key strategies: o Accelerate the drilling and development of our acreage position in the Cherokee Basin; o Accumulate additional acreage in the Cherokee Basin in areas where management believes the most attractive development opportunities exist; o Pursue selected strategic acquisitions in the Cherokee Basin that would add attractive development opportunities and critical gas gathering infrastructure; o Expand our gas gathering system throughout the Cherokee Basin in order to accommodate the development of a wider acreage footprint; o Maintain operational control over our assets whenever possible; o Limit our reliance on third party contractors with respect to the completion, stimulation and connection of our wells; o Maintain a low cost and efficient operating environment through the use of remote data monitoring technology; and o Seek out opportunities to apply our expertise with unconventional resource development in other basins. Competitive Strengths o Experienced management. Key members of our executive management and technical team have been developing CBM in the Cherokee Basin since 1995. 8 o Low geological risk. The coal seams from which we produce CBM are notable for their consistent thickness and gas content. In addition, extensive drilling dating back 60 to 80 years for the development of oil reserves in the Cherokee Basin gives us access to substantial information related to the coal seams we target. Over 100,000 wellbores have penetrated the Cherokee Basin since the 1920s. Data available from the drilling records of these wells allows us to determine the aerial extent, thickness and relative permeability of the coal seams we target for development, which greatly reduces our dry hole risk. o High rate of drilling success. Over 98% of the approximately 1,100 CBM wells that have been drilled on our acreage have been completed as economic producers. o Expertise in Cherokee Basin geology. We have spent several years conducting technical research on historical data related to the development of the Cherokee Basin. From this analysis, we believe we have determined where the most attractive opportunities for CBM development exist within the basin. o Large acreage position and inventory of drilling sites. We have the right to develop 494,985 CBM acres in the Cherokee Basin. As of December 31, 2005, our acreage was approximately 40% developed and offered approximately 1,800 potential CBM drilling locations. o Availability of significant quantities of low cost acreage. Presently, several hundred thousand acres of unleased CBM acreage are available in the Cherokee Basin. Generally, this acreage can be leased for an amount far less than acreage in other basins. These circumstances afford us the opportunity to pursue significant organic growth by adding large amounts of undeveloped acreage and CBM drilling locations at a reasonable cost. o Competitive advantage of our gas gathering system. Our gas gathering system provides us with a competitive advantage with respect to third parties seeking to lease acreage that is readily served by our system. The volume take allowance for gas gathering systems in the Cherokee Basin has historically been 30% before royalties. This not only makes development economics less attractive for third party operators to lease land served by our system, it also makes us the most attractive lessee for landowners. The vast geographic extent of our gas gathering system together with our large land position makes it unattractive for third parties to lease proximate acreage and build duplicate gas gathering facilities. o Attractive geological characteristics of Cherokee Basin CBM. Compared to other basins in the United States where CBM is produced, CBM production in the Cherokee Basin has distinct economic advantages. First, the coal seams in the Cherokee Basin are relatively more permeable and thus tend to produce at a faster rate. This results in a shorter reserve life, the need to drill fewer wells, a faster payout period and a higher present value of reserves. Second, Cherokee Basin coal seams produce relatively less water than coal seams in other basins. Cherokee Basin CBM wells produce gas immediately, have a shorter dewatering period, and produce less water overall than CBM wells in other basins. This results in lower operating costs and more attractive rates of return. o Predictable results of our CBM wells. Our CBM wells have highly consistent behavior in terms of recoverable reserves, production rates and decline curves, which results in lower development risk. o Concentrated ownership and operational control. We own 100% of the working interest in over 95% of the wells in which we have ownership. As a result of our ownership position we operate substantially all of the wells in which we own an economic interest. o Long-lived reserves. We believe our reserve life index of 16.3 years is higher than the exploration and production industry average. We believe this long reserve life reduces the reinvestment risk associated with our asset base. o Marketing Flexibility. Our gas gathering system is able to access several interstate pipelines, providing access to major gas demand centers in the central United States. Cherokee Basin CBM Production The Cherokee Basin is located in southeastern Kansas and northeastern Oklahoma. Geologically, it is situated between the Forest City Basin to the north, the Arkoma Basin to the south, the Ozark Dome to the east and the Nemaha Ridge to the west. Structurally, the Cherokee Basin is separated from the Forest City Basin by the Bourbon Arch. The Cherokee Basin is a mature producing area with respect to conventional reservoirs such as the Bartlesville sandstones and the Mississippian limestones, which were developed beginning in the early 1900s. 9 The Cherokee Basin is part of the Western Interior Coal Region of the central United States. The coal seams we target for development are Pennsylvanian (Desmoinesian-Cherokee Group) in age and are found at depths of 300 to 1,400 feet. The principal formations we target include the Mulky, Weir-Pittsburgh and the Riverton. These coal seams are blanket type deposits, which extend across large areas of the basin. Each of these seams generally range from two to five feet thick. Additional minor coal seams such as the Summit, Bevier, Fleming and Rowe are found at varying locations throughout the basin. These seams range in thickness from one to two feet. The coal seams found in the Cherokee Basin are primarily high-volatile A and B bituminous grade with excellent permeability and gas saturations ranging from 150 to 380 scf/ton. We develop our CBM reserves in the Cherokee Basin on 160 acre spacing. Our wells generally reach total depth in 1.5 days and our historical cost was approximately $150,000 to drill and complete a well and to build the related pipeline infrastructure. The increase in various materials due to the hurricanes and the tightness in the oil and gas industry have increased our current costs to drill and complete a well and to build the related pipeline infrastructure to approximately $160,000. We perforate and frac the multiple coal seams present in each well. Our typical Cherokee Basin multi-seam CBM well has gross reserves of 160 mmcf. Our general production profile for a CBM well averages an initial 15-20 mcf/d (net), steadily rising for the first 8 months while water is pumped off and the formation pressure is lowered. A period of relatively flat production of 55-60 mcf/d (net) follows the initial de-watering period for a period of 8-10 months. After 16 to 18 months, production begins to decline at an annual rate of 12-14%. The standard economic life is about 14 years. Our completed wells rely on very basic industry technology and are mechanically unchallenging. Our development activities in the Cherokee Basin also include an active program to recomplete CBM wells that produce from a single coal seam to wells that produce from multiple coal seams. We began our well recompletions in November 2004. As of December 31, 2005, we had recompleted approximately 169 wellbores in Kansas and an additional 36 in Oklahoma and we had an additional 112 wells awaiting recompletion to multi-seam producers. The recompletion strategy is to add 4-5 additional pay zones to each wellbore, in a two-stage process at an average cost of $15,000 per well. Adding new zones to a well has a brief negative effect on production by first taking the well offline to perform the work and then by introducing a second de-watering phase of the newly completed formations. However, in the long term, the impact of the multi-seam recompletions will be positive as a result of an increase in the rate of production and the ultimate recoverable reserves available per well. Wells are equipped with small pumping units to facilitate the de-watering of the producing coal seams. Generally, upon initial production, a single coal seam will produce 50-60 bbls of water per day. A multi-seam completion produces about 150 bbls of water per day. Eventually, water production subsides to 30-50 bbls per day. Produced water is disposed through injection wells we drill into the underlying Arbuckle formation. One disposal well will generally handle the water produced from 25 producing wells. Exploration & Production Activities As of December 31, 2005, we controlled approximately 533,000 gross acres. The petroleum engineering firm of Cawley, Gillespie & Associates, Inc., of Ft. Worth, Texas, estimated our proved oil and natural gas reserves to be as follows as of December 31, 2005: estimated gross natural gas proved reserves of 217.1 Bcf, of which 134.3 Bcf is net to the Company, and estimated net proved oil reserves of 32,269 barrels. The present value of these reserve assets, discounted at 10% of the future net cash flow from the net natural gas and oil reserves, is $482.5 million, before the effect of income taxes. As of December 31, 2005, we were producing natural gas from approximately 1,026 wells (gross). Our total daily natural gas sales (including pipeline-earned volume) as of December 31, 2005 were approximately 28.0 mcf/d net (37.7 mcf/d gross). We have a significant amount of acreage available for development. As of December 31, 2005, we had leases with respect to approximately 283,803 net undeveloped acres. For the year ended December 31, 2005, we drilled approximately 99 wells and connected 233 wells to our pipeline systems. We intend to drill approximately 600 wells during 2006 and to drill approximately 1,200 wells over the two-year period subsequent to calendar year 2006. We have identified approximately 600 proved undeveloped drilling locations and many more probable and possible drilling locations. Management believes that the Company has the necessary expertise, manpower and equipment capabilities required to carry out these development plans. Management believes that significant additional value will be created for the Company if the drilling program continues to be successful in creating new natural gas wells that convert raw acreage into proven natural gas reserves. However, there can be no assurance that we will have the funding required to be able to drill and develop that number of wells during such time frame or as to the number of new wells that will be producing wells. 10 Most of this development type of drilling is in areas of known natural gas reserves that involve much lower risk than the exploratory type of drilling that is required when searching for new natural gas reserves. We have enjoyed a new well success rate of over 98% and the typical new well has been adding value to the Company amounting to several times the Company's approximate $150,000 historical cost for drilling and completing a well and to build the related pipeline infrastructure in the Cherokee Basin. Producing Wells and Acreage The following table sets forth certain information regarding the ownership by the Company of productive wells and total acreage, as of December 31, 2005 and 2004 and May 31, 2004. For purposes of this table, productive wells are: wells currently in production, wells capable of production, and new wells in the process of completion.

PRODUCTIVE WELLS LEASEHOLD ACREAGE (1) ---------------------------------------------- --------------------------------------------------------- Natural Gas(2) Oil Total Producing Non-Producing Total Leased As of ------------- ------------ --------------- ----------------- ----------------- ----------------- May 31 Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net ------- ----- ----- ----- ---- ----- ------- ------- ------- ------- ------- ------- ------- 2004 678 660.4 29 27.9 707 688.3 229,080 214,145 436,079 333,993 665,159 548,138 As of Dec. 31 2004 795 774.3 29 27.9 824 802.2 311,941 291,318 205,230 187,884 517,171 479,202 2005 1,026 999.3 29 27.9 1,055 1,027.2 334,676 310,663 198,569 184,322 533,245 494,985

(1) The leasehold acreage data as of May 31, 2004, includes non-producing leasehold acreage in the State of Kentucky. This lease expired in 2004 and the Company did not renew this lease. (2) At December 31, 2005, the Company had approximately 900 wells that have multiple producing completions. During the year ended December 31, 2005, we drilled 99 gross (96.4 net) new wells on our properties, the majority of which were natural gas wells. The wells drilled have been evaluated and were included in the year-end reserve report. The oil well count remains constant as we are focusing on adding natural gas reserves. (See "--Summary of New and Abandoned Well Activity"). During the year ended December 31, 2005, we continued to lease additional acreage in certain core development areas of the Cherokee Basin. Natural Gas and Oil Reserves The following table summarizes the reserve estimate and analysis of net proved reserves of natural gas and oil as of December 31, 2005 and 2004 and May 31, 2004, in accordance with Securities and Exchange Commission ("SEC") guidelines. The data was prepared by the petroleum engineering firm Cawley, Gillespie & Associates, Inc. in Ft. Worth, Texas. The present value of estimated future net revenues from these reserves was calculated on a non-escalated price basis discounted at 10% per year. In December of 2003, the Company acquired certain natural gas properties from Devon Energy Production Company, L.P. and Tall Grass Gas Services, LLC (the "Devon Asset Acquisition"; see Note 2 "Acquisitions" in notes to consolidated financial statements). The Devon Asset Acquisition during the fiscal year ended May 31, 2004 more than tripled the estimated proved reserves over the previous year. During 2005, we filed estimates of our natural gas and oil reserves for the year 2004 with the Energy Information Administration of the U. S. Department of Energy on Form EIA-23. The data on Form EIA-23 was presented on a different basis, and included 100% of the natural gas and oil volumes from our operated properties only, regardless of our net interest. The difference between the natural gas and oil reserves reported on Form EIA-23 and those reported in this report exceeds 5%.

December 31, May 31, --------------------------------- ---------------- 2005 2004 2004 ------------- ---------------- ---------------- Proved Developed Gas Reserves (mcf) 71,638,000 81,467,300 62,558,900 Proved Undeveloped Gas Reserves (mcf) 62,681,000 68,376,600 71,017,300 Total Proved Gas Reserves (mcf) 134,319,000 149,843,900 133,576,200 Proved Developed Oil Reserves (bbl)(1) 32,269 47,834 57,105 Future Cash Flows Before Income Taxes $769,677,000 $611,106,300 $482,745,600

------------ 11 (1) Although we have proved undeveloped oil reserves, they are insignificant, so no effort was made to calculate such reserves. The Company's total proved reserves declined from 150.1 bcfe to 134.5 bcfe. This decrease is comprised of 9.6 bcfe of production for calendar year 2005 and 6.0 bcfe of revisions. The revision resulted from the Company's independent reserve engineer reducing all proved reserve categories in one small area that is performing below expectations. The Company plans to complete the remaining multi seam re-completions for this area in the future and believes that all of this reduction may be recovered if the multi seam re-completions perform as expected. There are numerous uncertainties inherent in estimating natural gas and oil reserves and their values. The reserve data set forth in this report is only an estimate. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Furthermore, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing natural gas and oil prices, operating costs and other factors, and such revisions can be substantial. Accordingly, reserve estimates often differ from the quantities of natural gas and oil that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. The future net cash flow and present value of future net cash flow amounts are estimates based upon current prices at the time the reports were prepared and do not take into account the effects of our natural gas hedging program. The proved reserves of the Company will generally decline as they are produced, except to the extent that the Company conducts revitalization activities, or acquires properties containing proved reserves, or both. To increase reserves and production, we intend to continue our development drilling and re-completion programs, to identify and produce previously overlooked or bypassed zones in shut-in wells, and to a lesser extent, acquire additional properties or undertake other replacement activities. Our current strategy is to increase our reserve base, production and cash flow through the development of our existing natural gas fields and subject to available capital, through the selective acquisition of other promising properties where we can utilize its existing technology and infrastructure. We can give no assurance that our planned development activities will result in significant additional reserves or that we will have success in discovering and producing reserves at economical exploration and development costs. The drilling of new wells and conversion of existing oil wells for natural gas production is a speculative activity and the possibility always exists that newly drilled or converted natural gas wells will be non-productive or fail to produce enough revenue to be commercially worthwhile. Production Volumes, Sales Prices, and Production Costs The following tables set forth certain information regarding the natural gas and oil properties owned by the Company through its subsidiaries. The natural gas and oil production figures reflect the net production attributable to our revenue interest and are not indicative of the total volumes produced by the wells.

Year Ended 7 Month Transition Year Ended December 31, Period Ended December May 31, Gas Production Statistics 2005 31, 2004 2004 ------------ --------------------- ---------- Net gas sales (mcf) 9,565,000 5,013,911 5,530,208 Avg wellhead gas price, (per mcf) $7.44 $5.74 $5.19 Avg wellhead gas price, net (per mcf) (1) $4.61 $4.83 $5.04 Average production cost (per mcf) $0.99 $0.72 $0.92 Average production and ad valorem taxes (per mcf) $0.58 $0.35 $0.33 Net revenue (per mcf) $3.04 $3.76 $3.79

------------ (1) Includes hedging gains and losses. The natural gas production volumes for the year ended December 31, 2005 and for the transition period ended December 31, 2004 and for the 2004 fiscal year include the Devon Asset Acquisition beginning December 22, 2003 and the Perkins/Willhite acquisition beginning June 1, 2003.

Year Ended 7 Month Transition Year Ended December 31, Period Ended May 31, Oil Production Statistics 2005 December 31, 2004 2004 ------------ ------------------- -------------- Net oil production (bbls) 9,241 5,551 8,549 Average wellhead oil price (per bbl) $53.46 $44.14 $41.06 Average production cost (per bbl) $19.18 $16.90 $16.89 Net revenue (per bbl) $34.28 $27.24 $24.17

12 Summary of New and Abandoned Well Activity Most of the wells expected to be drilled in the next year will be of the development category and in the vicinity of our existing or planned construction pipeline network. However, subsequent to calendar year 2005, we will devote a small part of our drilling effort into exploratory wells in an attempt to discover new natural gas reserves, which is a high-risk endeavor. Our drilling, re-completion, abandonment, and acquisition activities for the periods indicated are shown below:

7 Month Transition Year Ended Period Ended December 31, December 31, 2005(1) 2004(1) Year Ended May 31, 2004 ------------- ------------- --------------------------- Gas Gas Oil Gas ------------- ------------- --------------------------- Gross Net Gross Net Gross Net Gross Net ----- ---- ----- ---- ----- --- ----- --- Exploratory Wells Drilled: Capable of Production -- -- -- -- -- -- -- -- Dry -- -- -- -- -- -- -- -- Development Wells Drilled: Capable of Production 233 233 117 114 -- -- 138 132 Dry -- -- -- -- -- -- 2 2 Re-completion of Old Wells: Capable of Production 205 205 38 38 -- -- -- -- Wells Abandoned (0) (0) (11) (11) (2) (2) -- -- Acquired Devon wells 12/22/03 -- -- -- -- -- -- 337 337 Other Wells Acquired -- -- 11 11 -- -- -- -- ------------- ------------- --------------------------- Net increase in Capable Wells 233 233 117 114 (2) (2) 477 471 ============= ============= ===========================

------------ (1) No change to oil wells for the year ended December 31, 2005 or the seven month transition period ended December 31, 2004. Our coal bed methane gas wells are the most productive and profitable category of wells in our inventory. Our older natural gas wells and oil wells are 10 to 20 years old and are much less profitable than our typical coal bed methane well. By abandoning the marginal or non-commercial wells, we are more focused on our more profitable coal bed methane wells. The 99 new natural gas wells drilled for the year ended December 31, 2005 reflect an average drilling activity level of 8 wells per month. The limited number of wells drilled in the 2005 calendar year was due to our focus on connecting our significant inventory of drilled, but not connected wells, re-completions of existing wells to increase production and certain bank covenant restrictions regarding capital expenditures associated with any drilling activity, which bank covenants were eliminated with the retirement of the UBS Credit Agreement (see Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations--Capital Resources and Liquidity--Credit Facilities"). Subsequent to calendar year 2005, we plan to drill an average of approximately 50 wells per month for at least the next three years, subject to capital being available for such expenditures. During the period from December 31, 2005 through March 23, 2006, we drilled 168 wells and connected 117. As of March 24 2006, we were drilling 3 wells and approximately 45 wells were in the process of being completed over the next thirty-day period. Delivery Commitments Natural Gas We do not have long-term delivery commitments. We market our own natural gas and more than 95% of the natural gas was sold to ONEOK Energy Marketing and Trading Company during 2005 and the seven month transition period ended December 31, 2004. More than 90% of the natural gas was sold to ONEOK Energy Marketing and Trading Company during the fiscal year ended May 31, 2004. No other customer of the Company accounted for more than 10% of the consolidated revenues for the year ended December 31, 2005, the transition period ended December 31, 2004 or the fiscal year ended May 31, 2004. 13 Oil Our oil is currently being sold to Coffeyville Refining. Previously, it had been sold to Plains Marketing, L.P. We do not have a long-term contract for our oil sales. Hedging Activities We seek to reduce our 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 us 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, we 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 prices and floors 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 December 31, 2005. See Note 15 - Derivatives, in notes to consolidated financial statements of this Form 10-K.

Years Ending December 31, ----------------------------------------- 2006 2007 2008 Total ----------- ----------- ----------- ------------ (dollars in thousands, except price data) Natural Gas Swaps: Contract vols (MMBtu) 5,614,000 -- -- 5,614,000 Weighted-avg fixed price per MMBtu (1) $ 4.49 -- -- $ 4.49 Fixed-price sales $ 25,203 -- -- $ 25,203 Fair value, net $ (31,185) -- -- $ (31,185) Natural Gas Collars: Contract vols (MMBtu): Floor 1,825,000 3,650,000 2,928,000 8,403,000 Ceiling 1,825,000 3,650,000 2,928,000 8,403,000 Weighted-avg fixed price per MMBtu (1): Floor $ 5.30 $ 4.83 $ 4.50 $ 4.82 Ceiling $ 6.35 $ 5.83 $ 5.52 $ 5.84 Fixed-price sales (2) $ 11,589 $ 21,279 $ 16,163 $ 49,031 Fair value, net $ (7,010) $ (14,420) $ (9,303) $ (30,733) Total Natural Gas Contracts: Contract vols (MMBtu) 7,439,000 3,650,000 2,928,000 14,017,000 Weighted-avg fixed price per MMBtu (1) $ 4.95 $ 5.83 $ 5.52 $ 5.30 Fixed-price sales (2) $ 36,792 $ 21,279 $ 16,163 $ 74,234 Fair value, net $ (38,195) $ (14,420) $ (9,303) $ (61,918)

(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 Note 14 - Financial Instruments, in notes to consolidated financial statements of this Form 10-K. 14 Our fixed price contracts are tied to commodity prices on the New York Mercantile Exchange ("NYMEX"), that is, we receive the fixed price amount stated in the contract and pay to our counterparty the current market price for gas as listed on the NYMEX. However, due to the geographic location of our natural gas assets and the cost of transporting the natural gas to another market, the amount that we receive when we actually sell our natural gas is based on the Southern Star first of month index. The difference between natural gas prices on the NYMEX and on the Southern Star first of month index is referred to as a basis differential. Typically, the price for natural gas on the Southern Star first of month index is less than the price on the NYMEX due to the more limited demand for natural gas on the Southern Star first of month index. Recently, the basis differential has been increasingly volatile and has on occasion resulted in us receiving a net price for our natural gas that is significantly below the price stated in the fixed price contract. Pipeline Operations We own and operate an approximate 1,100 miles of natural gas gathering pipeline network located throughout ten counties in southeastern Kansas and northeastern Oklahoma. This pipeline network provides a market outlet for natural gas in a region of approximately 1,000 square miles in size and has connections to both intrastate and interstate delivery pipelines. As of December 31, 2005, this pipeline network included 15 natural gas compressors that are owned by Quest and 63 larger compressors that are rented. The pipelines gather all of the natural gas produced by us in addition to some natural gas produced by other companies. The pipeline network is a critical asset for our future growth because natural gas gathering pipelines are a costly component of the infrastructure required for natural gas production and such pipelines are not easily constructed. Much of the undeveloped acreage targeted by us for future development is accessible to our existing pipeline network, which management believes is a significant advantage. We are continuing to expand our pipeline infrastructure through a combination of the development of new pipelines and the acquisition of existing pipelines. During the year ended December 31, 2005, we constructed approximately 120 miles of gas pipeline systems and during the seven month transition period ended December 31, 2004, we constructed approximately 124 miles of gas pipeline systems including gas trunk lines and gas gathering pipelines with diameters ranging in size from 20 inches to 6 inches. In addition, during the year ended December 31, 2005, we acquired approximately 10 miles of pipeline, which was located near our existing pipeline system. The Company's pipeline operations are conducted through Bluestem, which is a wholly-owned subsidiary of the Company. The table below sets forth the natural gas volumes transported by us on our pipeline network during the year ended December 31, 2005, the seven-month transition period ended December 31, 2004 and for the fiscal year ended May 31, 2004.

Year Ended 7 Months Ended Year Ended December 31, 2005 December 31, 2004 May 31, 2004 ----------------- ----------------- ------------ Pipeline Natural Gas Volumes (mcf) 13,257,000 7,004,000 8,157,000

The natural gas volumes for the year ended December 31, 2005; the seven month transition period ended December 31, 2004 and the fiscal year ended May 31, 2004 include the Devon Asset Acquisition beginning December 22, 2003 and the Perkins/Willhite acquisition beginning June 1, 2003. As of December 31, 2005, the total daily capacity was approximately 70 mmcf and the total utilization was approximately 37 mmcf or 54%. Service Operations Field operations conducted by Company personnel include duties performed by "pumpers" or employees whose primary responsibility is to operate the wells and the pipelines. Other field personnel are experienced and involved in the activities of well servicing, pipeline maintenance, the development and completion of new wells and associated infrastructure, new pipeline construction and the construction of supporting infrastructure for new wells (such as electric service, salt water disposal facilities, and natural gas feeder lines). The primary equipment categories owned by us are trucks, well service rigs, stimulation assets and construction equipment. We utilize third party contractors on an "as needed" basis to supplement the Company's field personnel. 15 In August 2004, we acquired various well servicing assets from Consolidated Oil Well Services (the "COWS Acquisition"). These assets consisted of cementing, acidizing, fracturing and well service equipment as well as related office and storage facilities. As a result of the COWS Acquisition, we now are able to provide, on an in-house basis, many of the services required for the completion and maintenance of our CBM wells. Internally sourcing these functions significantly reduces our reliance on third-party contractors, which typically provide these services. This results in reduced delays in executing our plan of development. Also we are able to realize significant cost savings because we can avoid paying price mark-ups and also because we are able to purchase our own supplies at bulk discounts. We rely on third-party contractors to drill our wells. Once a well is drilled, we run our own casing and do our own cementing work. We also perform our own fracturing and stimulation work. Finally, we complete our own well site construction. We have our own fleet of 18 well service units that we use in the process of completing our wells, and also to perform remedial field operations required to maintain production from our existing wells. We do rely on third party contractors to perform gas gathering system construction activities. By retaining operational control of our crucial income producing assets, management believes that we are better able to control costs and minimize downtime of these critical assets. We do not currently provide a material amount of services to unaffiliated companies other than transportation of certain third party production volumes. Regulation The natural gas industry is subject to regulation by federal, state and local authorities on matters such as employee health and safety, permitting, bonding and licensing requirements, air quality standards, water pollution, the treatment, storage and disposal of wastes, plant and wildlife protection, storage tanks, the reclamation of properties and plugging of oil wells after gas operations are completed, the discharge or release of materials into the environment, and the effects of gas well operations on groundwater quality and availability. In addition, the possibility exists that new legislation or regulations may be adopted which would have a significant impact on our operations or our customers' ability to use gas and may require us or our customers to change their operations significantly or incur substantial costs. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of injunctive relief or both. Moreover, changes in any of these laws and regulations could have a material adverse effect on our business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to the Company, management cannot predict the overall effect of such laws and regulations on our future operations. Management believes that our operations comply in all material respects with applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive effect on our method of operations than on other similar companies in the energy industry. We have internal procedures and policies to ensure that our operations are conducted in substantial regulatory compliance. Environmental Regulation of Gas Operations Numerous governmental permits and approvals are required for gas operations. In order to obtain such permits and approvals, we are, or may be, required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of gas may have upon the environment and public and employee health and safety. Compliance with such permits and all other requirements imposed by such authorities may be costly and time-consuming and may delay commencement or continuation of exploration or production operations. Moreover, failure to comply may result in the imposition of significant fines and penalties. Future legislation or regulations may increase and/or change the requirements for the protection of the environment, health and safety and, as a consequence, our activities may be more closely regulated. This type of legislation and regulation, as well as future interpretations of existing laws, may result in substantial increases in equipment and operating costs to us and delays, interruptions or a termination of operations, the extent of which cannot be predicted. Further, the imposition of new environmental regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste. 16 While it is not possible to quantify the costs of compliance with all applicable federal and state environmental laws, those costs have been and are expected to continue to be significant. We did not make any capital expenditures for environmental control facilities during 2005. Any environmental costs are in addition to well closing costs; property restoration costs; and other, significant, non-capital environmental costs, including costs incurred to obtain and maintain permits, to gather and submit required data to regulatory authorities, to characterize and dispose of wastes and effluents, and to maintain management operational practices with regard to potential environmental liabilities. Compliance with these federal and state environmental laws has substantially increased the cost of gas production, but is, in general, a cost common to all domestic gas producers. The magnitude of the liability and the cost of complying with environmental laws cannot be predicted with certainty due to: the lack of specific environmental, geologic, and hydro geologic information available with respect to many sites; the potential for new or changed laws and regulations; the development of new drilling, remediation, and detection technologies and environmental controls; and the uncertainty regarding the timing of work with respect to particular sites. As a result, we may incur material liabilities or costs related to environmental matters in the future and such environmental liabilities or costs could adversely affect its results and financial condition. In addition, there can be no assurance that changes in laws or regulations would not affect the manner in which we are required to conduct our operations. Further, given the retroactive nature of certain environmental laws, we have incurred, and may in the future incur, liabilities associated with: the investigation and remediation of the release of hazardous substances, oil, natural gas, or other petroleum products; environmental conditions; and natural resource damages related to properties and facilities currently or previously owned or operated as well as sites owned by third parties to which we or our subsidiaries sent waste materials for disposal. We are subject to various generally applicable federal environmental laws, including the following: o the Clean Air Act; o the Clean Water Act; o the Toxic Substances Control Act; o the Comprehensive Environmental Response, Compensation and Liability Act (Superfund); o the Resource Conservation and Recovery Act; and o the Emergency Planning and Community Right-to-Know Act; as well as state laws of similar scope and substance in each state in which we operate. These environmental laws require monitoring, reporting, permitting and/or approval of many aspects of gas operations. Both federal and state inspectors regularly inspect facilities during construction and during operations after construction. We have ongoing environmental management, compliance and permitting programs designed to assist in compliance with such environmental laws. Management believes that the Company has obtained or is in the process of obtaining all required permits under federal and state environmental laws for its current gas operations. Further, management believes that the Company is in substantial compliance with such permits. However, violations of permits, failure to obtain permits or other violations of federal or state environmental laws could cause us to incur significant liability: to correct such violations; to provide additional environmental controls; to obtain required permits; and to pay fines which may be imposed by governmental agencies. New permit requirements and other requirements imposed under federal and state environmental laws may cause us to incur significant additional costs that could adversely affect our operating results. Some laws, rules and regulations relating to the protection of the environment may, in certain circumstances, impose "strict liability" for environmental contamination. Such laws render a person or company liable for environmental and natural resource damages, cleanup costs and, in the case of oil spills in certain states, consequential damages without regard to negligence or fault. Other laws, rules and regulations may require the rate of natural gas and oil production to be below the economically optimal rate or may even prohibit exploration or production activities in environmentally sensitive areas. In addition, state laws often require some form of remedial action such as closure of inactive pits and plugging of abandoned wells to prevent pollution from former or suspended operations. Legislation has been proposed and continues to be evaluated in Congress from time to time that would reclassify certain natural gas and oil exploration and production wastes as "hazardous wastes". This reclassification would make such wastes subject to much more stringent and expensive storage, treatment, disposal and clean-up requirements. If such legislation were to be enacted, it could have a significant adverse impact on our operating costs, as well as the natural gas and oil industry in general. Initiatives to regulate further the disposal of natural gas and oil wastes are also proposed in certain states from time to time and may include initiatives at county, municipal and local government levels. These various initiatives could have a similar adverse impact on us. 17 From time to time, we have been the subject of investigations, administrative proceedings, and litigation, by government agencies and third parties, relating to environmental matters. We may become involved in future proceedings, litigation or investigations and incur liabilities that could be materially adverse to us. Federal Regulation of the Sale and Transportation of Gas Various aspects of our operations are regulated by agencies of the federal government. The Federal Energy Regulatory Commission ("FERC") regulates the transportation and sale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. In the past, the federal government has regulated the prices at which gas could be sold. While "first sales" by producers of natural gas, and all sales of condensate and natural gas liquids can be made currently at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead sales in the natural gas industry began with the enactment of the Natural Gas Policy Act in 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993. We own certain natural gas pipeline facilities that we believe meet the traditional tests which the FERC has used to establish a pipeline's status as a gatherer under section 1(b) of the Natural Gas Act, 16 U.S.C. ss. 717(b) and are therefore not subject to FERC jurisdiction. As a condition precedent to Quest's pending purchase of a 12.74 mile pipeline facility ("the Petrolia-Fort Scott pipeline") from Southern Star, Central Gas Pipeline, Inc, Quest plans to elicit from FERC a declaratory order determining that the Petrolia-Fort Scott pipeline, when operated in conjunction with Quest's existing pipeline facilities, falls within the definition of a gathering system outside FERC jurisdiction. We cannot guarantee the outcome of the request for such an order with the FERC. Additional proposals and proceedings that might affect the gas industry are pending before Congress, FERC, the Minerals Management Service, state commissions and the courts. We cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely. Notwithstanding the foregoing, management does not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect upon our or our subsidiaries' capital expenditures, earnings or competitive position. No material portion of our business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the federal government. The courts have largely affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines, although certain appeals remain pending and the FERC continues to review and modify its open access regulations. In particular, the FERC has reviewed its transportation regulations, including how they operate in conjunction with state proposals for retail gas marketing restructuring, whether to eliminate cost-of-service rates for short-term transportation, whether to allocate all short-term capacity on the basis of competitive auctions, and whether changes to its long term transportation policies may also be appropriate to avoid a market bias toward short-term contracts. In February 2000, the FERC issued Order No. 637 amending certain regulations governing interstate natural gas pipeline companies in response to the development of more competitive markets for natural gas and natural gas transportation. The goal of Order No. 637 is to "fine tune" the open access regulations implemented by Order No. 636 to accommodate subsequent changes in the market. Key provisions of Order No. 637 include: (1) waiving the price ceiling for short-term capacity release transactions until September 30, 2002 (which was reversed pursuant to an order on remand issued by the FERC on October 31, 2002); (2) permitting value-oriented peak/off-peak rates to better allocate revenue responsibility between short-term and long-term markets; (3) permitting term-differentiated rates, in order to better allocate risks between shippers and the pipeline; (4) revising the regulations related to scheduling procedures, capacity, segmentation, imbalance management, and penalties; 18 (5) retaining the right of first refusal and the five year matching cap for long-term shippers at maximum rates, but significantly narrowing the right of first refusal for customers that the FERC does not deem to be captive; and (6) adopting new web site reporting requirements that include daily transactional data on all firm and interruptible contracts and daily reporting of scheduled quantities at points or segments. These reporting requirements became effective on September 1, 2000. The FERC has also issued numerous orders confirming the sale and abandonment of natural gas gathering facilities previously owned by interstate pipelines and acknowledging that if the FERC does not have jurisdiction over services provided by these facilities, then such facilities and services may be subject to regulation by state authorities in accordance with state law. A number of states have either enacted new laws or are considering the adequacy of existing laws affecting gathering rates and/or services. Other state regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Thus, natural gas gathering may receive greater regulatory scrutiny of state agencies in the future. Our gathering operations could be adversely affected should they be subject in the future to increased state regulation of rates or services. In addition, the FERC's approval of transfers of previously-regulated gathering systems to independent or pipeline affiliated gathering companies that are not subject to FERC regulation may affect competition for gathering or natural gas marketing services in areas served by those systems and thus may affect both the costs and the nature of gathering services that will be available to interested producers or shippers in the future. State Regulation of Gas Operations Our operations are also subject to regulation at the state and, in some cases, the county, municipal and local governmental levels. Such regulations include requiring permits for the construction, drilling and operation of wells, maintaining bonding requirements in order to drill or operate wells, regulating the surface use and requiring the restoration of properties upon which wells are drilled, requiring the proper plugging and abandonment of wells, and regulating the disposal of fluids used and produced in connection with operations. Our operations are also subject to various state conservation laws and regulations. These include regulations that may affect the size of drilling and spacing units or proration units, the density of wells which may be drilled, and the mandatory unitization or pooling of gas properties. In addition, state conservation regulations may establish the allowable rates of production from gas wells, may prohibit or regulate the venting or flaring of gas, and may impose certain requirements regarding the ratability of gas production. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory and non-preferential purchase and/or transportation requirements, but does not generally entail rate regulation. These regulatory burdens may affect profitability, and management is unable to predict the future cost or impact of complying with such regulations. Competition We operate in the highly competitive areas of acquisition and exploration of natural gas properties in which other competing companies may have substantially larger financial resources, operations, staffs and facilities. In seeking to acquire desirable new properties for future exploration we face competition from other natural gas and oil companies. Such companies may be able to pay more for prospective natural gas properties or prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Since a significant majority of our pipeline and service operations presently support our exploration and development operations, these aspects of our business do not experience any significant competition. Employees At March 31, 2006, the Company had an experienced staff of 332 field employees in offices located in Chanute and Howard, Kansas and Lenapah, Oklahoma. Also, at the headquarters office in Oklahoma City a staff with 27 executive and administrative personnel. None of our employees are covered by a collective bargaining agreement. Management considers its relations with our employees to be satisfactory. Administrative Facilities The office space for the corporate headquarters for the Company and its subsidiaries is leased and is located at 9520 N. May Avenue, Suite 300, Oklahoma City, OK 73120. 19 We also own a building located at 211 West 14th Street in Chanute, Kansas 66720 that is used as an administrative office, an operations terminal and a repair facility. An office building at 127 West Main in Chanute, Kansas is owned and operated by us as a geological laboratory. We also lease an operational office that is located east of Chanute, Kansas. Where To Find Additional Information Additional information about the Company can be found on our website at www.qrcp.net. We also provide free of charge on our website Quest's filings with the SEC, including its annual reports, quarterly reports, and current reports along with any amendments thereto, as soon as reasonably practicable after we have electronically filed such material with, or furnished it to, the SEC. Glossary of Oil and Gas Terms The terms defined in this section are used throughout this Form 10-K. Bcf. Billion cubic feet of natural gas. Bcfe. Billion cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids. Btu or British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. CBM. Coal bed methane. Cherokee Basin. As used in this Form 10-K a ten county region in southeastern Kansas and northeastern Oklahoma. Completion. The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency. Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production. Development well. A well drilled within the proved boundaries of an oil or natural gas reservoir with the intention of completing the stratigraphic horizon known to be productive. Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. Exploitation. Ordinarily considered to be a form of development within a known reservoir. Exploratory well. A well drilled to find and produce oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir. Farm-in or farm-out. An agreement under which the owner of a working interest in an oil or gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a "farm-in" while the interest transferred by the assignor is a "farm-out." Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. Frac/fracturing. The method used to increase the deliverability of a well by pumping a liquid or other substance into a well under pressure to crack and prop open the hydrocarbon formation. 20 Gathering system. Pipelines and other equipment used to move natural gas from the wellhead to the trunk or the main transmission lines of a pipeline system. Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned. Highly volatile bituminous coal. Bituminous coal with a high concentration of methane gas. Horizon or formation. The section of rock, from which gas is expected to be produced in commercial quantities. mcf. Thousand cubic feet of natural gas. mcfe. Thousand cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids. MMBtu. Million British thermal units. mmcf. Million cubic feet of natural gas. mmcfe. Million cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids. Net acres or net wells. The sum of the fractional working interests owned in gross acres or well, as the case may be. NYMEX. The New York Mercantile Exchange. Permeability. The ease of movement of water and/or gases through a soil material. Perforation. The making of holes in casing and cement (if present) to allow formation fluids to enter the well bore. PV-10 or present value of estimated future net revenues. An estimate of the present value of the estimated future net revenues from proved gas reserves at a date indicated after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of federal income taxes. The estimated future net revenues are discounted at an annual rate of 10% in accordance with the SEC's practice, to determine their "present value." The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future net revenues are made using oil and natural gas prices and operating costs at the date indicated and held constant for the life of the reserves. Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. Proved developed non-producing reserves. Proved developed reserves expected to be recovered from zones behind casings in existing wells. Proved developed reserves. Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved undeveloped reserves or PUD. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserve life index. This index is calculated by dividing total proved reserves by the production from the previous year to estimate the number of years of remaining production. 21 Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. scf. Standard cubic feet of natural gas. Shut in. Stopping an oil or gas well from producing. Unconventional resource development. A development in which the targeted reservoirs generally fall into three categories: (1) tight sands, (2) coal beds, and (3) gas shales. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require stimulation treatments or other special recovery processes in order to produce economic flow rate. Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas regardless of whether or not such acreage contains proved reserves. Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production. ITEM 1A. RISK FACTORS. Risks Related to the Company's Business The volatility of natural gas and oil prices could have a material adverse effect on the Company's business. The Company's revenues, profitability and future growth and the carrying value of its natural gas and oil properties depend to a large degree on prevailing natural gas and oil prices. The Company's ability to maintain or increase its borrowing capacity and to obtain additional capital on attractive terms also substantially depends upon natural gas and oil prices. Prices for natural gas and oil are subject to large fluctuations in response to relatively minor changes in the supply and demand for natural gas and oil, uncertainties within the market and a variety of other factors in large part beyond the Company's control, such as: o the domestic and foreign supply of natural gas and oil; o the activities of the Organization of Petroleum Exporting Companies; o overall domestic and global economic condition; o the consumption pattern of industrial consumers, electricity generators and residential users; o weather conditions; o natural disasters; o acts of terrorism; o the political stability in the Middle East and elsewhere; o domestic and foreign governmental regulations; o the price of foreign imports; and o the price and availability of alternative fuels. 22 A sharp decline in the price of natural gas and oil prices would result in a commensurate reduction in the Company's revenues, income and cash flows from the production of natural gas and oil and could have a material adverse effect on the carrying value of the Company's proved reserves and its borrowing base. In the event prices fall substantially, the Company may not be able to realize a profit from its production and would operate at a loss, and even relatively modest drops in prices can significantly affect the Company's financial results and impede its growth. In recent decades, there have been periods of both worldwide overproduction and underproduction of hydrocarbons and periods of both increased and relaxed energy conservation efforts. Such conditions have resulted in periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis. These periods have been followed by periods of short supply of, and increased demand for, crude oil and natural gas. The excess or short supply of natural gas and crude oil has placed pressures on prices and has resulted in dramatic price fluctuations even during relatively short periods of seasonal market demand. Earlier in this decade, natural gas and oil prices were much lower than they are today. Lower natural gas and oil prices may not only decrease the Company's revenues on a per unit basis, but also may reduce the amount of natural gas and oil that the Company can produce economically. This may result in the Company's having to make substantial downward adjustments to its estimated proved reserves. If this occurs or if the Company's estimates of development costs increase, production data factors change or the Company's exploration results deteriorate, accounting rules may require the Company to write down, as a non-cash charge to earnings, the carrying value of its natural gas and oil properties for impairments. The Company is required to perform impairment tests on its assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carry amount may not be recoverable or whenever management's plans change with respect to those assets. The Company may incur impairment charges in the future, which could have a material adverse effect on the Company's results of operations in the period taken. Because the Company faces uncertainties in estimating proven recoverable natural gas reserves, you should not place undue reliance on such reserve information. This Form 10-K contains estimates of natural gas reserves, and the future net cash flows attributable to those reserves, prepared by Cawley, Gillespie & Associates, Inc., the Company's independent petroleum and geological engineers. There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond the Company's control and the control of Cawley, Gillespie & Associates, Inc. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to these reserves, is a function of the available data; assumptions regarding future natural gas and oil prices; expenditures for future development and exploitation activities; and engineering and geological interpretation and judgment. Reserves and future cash flows may also be subject to material downward or upward revisions based upon production history, development and exploitation activities and natural gas and oil prices. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and value of cash flows from those reserves may vary significantly from the assumptions and estimates in this Form 10-K. Any significant variance from these assumptions to actual figures could greatly affect the Company's estimates of reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classification of reserves based on risk of recovery, and estimates of the future net cash flows. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same available data. The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves included in this Form 10-K were prepared by Cawley, Gillespie & Associates, Inc. in accordance with the rules of the SEC, and are not intended to represent the fair market value of such reserves. The Company's total proved reserves declined from 150.1 bcfe to 134.5 bcfe. This decrease is comprised of 9.6 bcfe of production for calendar year 2005 and 6.0 bcfe of revisions. The revision resulted from the Company's independent reserve engineer reducing all proved reserve categories in one small area that is performing below expectations. The present value of future net cash flows from the Company's proved reserves is not necessarily the same as the current market value of its estimated natural gas reserves. The Company bases the estimated discounted future net cash flows from its proved reserves on prices and costs. However, actual future net cash flows from the Company's natural gas and oil properties also will be affected by factors such as: o geological conditions; o changes in governmental regulations and taxation; o assumptions governing future prices; o the amount and timing of actual production; o future operating costs; and o capital costs of drilling new wells. 23 The timing of both the Company's production and its incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor the Company uses when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the natural gas and oil industry in general. In addition, if natural gas prices decline, or our operating expenses increase, by $0.10 per mcf, then the pre-tax PV-10 of the Company's proved reserves as of December 31, 2005 would decrease from $482.5 million to $474.1 million. The SEC permits natural gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. The SEC's guidelines strictly prohibit the Company from including "probable reserves" and "possible reserves" in filings with the SEC. The Company also cautions you that the SEC views such "probable" and "possible" reserve estimates as inherently unreliable and these estimates may be seen as misleading to investors unless the reader is an expert in the natural gas industry. Unless you have such expertise, you should not place undo reliance on these estimates. Potential investors should also be aware that such "probable" and "possible" reserve estimates will not be contained in any "resale" or other registration statement filed by the Company that offers or sells shares on behalf of purchasers of the Company's common stock and may have an impact on the valuation of the resale of the shares. The Company undertakes no duty to update this information and does not intend to update the information. The Company's future success depends upon its ability to find, develop and acquire additional natural gas reserves that are economically recoverable. The rate of production from natural gas and oil properties declines as reserves are depleted. As a result, the Company must locate and develop or acquire new natural gas and oil reserves to replace those being depleted by production. The Company must do this even during periods of low natural gas and oil prices when it is difficult to raise the capital necessary to finance activities. The Company's future natural gas reserves and production and, therefore, the Company's cash flow and income are highly dependent on its success in efficiently developing and exploiting its current reserves and economically finding or acquiring additional recoverable reserves. The Company may not be able to find and develop or acquire additional reserves at an acceptable cost or have necessary financing for these activities in the future. The development of natural gas properties involves substantial risks that may result in a total loss of investment. The business of exploring for and, to a lesser extent, developing and operating natural gas and oil properties involves a high degree of business and financial risks, and thus a substantial risk of investment loss that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The cost of drilling, completing and operating wells is often uncertain, and a number of factors can delay or prevent drilling operations or production, including: o unexpected drilling conditions; o pressure or irregularities in geologic formations; o equipment failures or repairs; o title problems; o fires, explosions, blowouts, cratering, pollution and other environmental risks or other accidents; o adverse weather conditions; o reductions in natural gas and oil prices; o pipeline ruptures; and o unavailability or high cost of drilling rigs, other field services and equipment. 24 A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of natural gas and/or oil from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances. The Company may drill wells that are unproductive or, although productive, do not produce natural gas and/or oil in economic quantities. Unsuccessful drilling activities could result in higher costs without any corresponding revenues. Acquisition and completion decisions generally are based on subjective judgments and assumptions that are speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, a successful completion of a well does not ensure a profitable return on the investment. Currently the vast majority of the Company's producing properties are located in a ten county region in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma, making the Company vulnerable to risks associated with having its production concentrated in one area. The vast majority of the Company's producing properties are geographically concentrated in a ten county region in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma. As a result of this concentration, the Company may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by significant governmental regulation, transportation capacity constraints, curtailment of production, natural disasters, adverse weather conditions or interruption of transportation of natural gas produced from the wells in this basin or other events which impact this area. The Company may suffer losses or incur liability for events for which the Company or the operator of a property has chosen not to obtain insurance. The Company's operations are subject to hazards and risks inherent in producing and transporting natural gas and oil, such as fires, natural disasters, explosions, pipeline ruptures, spills, and acts of terrorism, all of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to the Company's and others' properties. As protection against operating hazards, the Company maintains insurance coverage against some, but not all, potential losses. In addition, pollution and environmental risks generally are not fully insurable. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, the Company may not be able to renew its existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. In addition, the Company believes any operators of its properties or properties in which the Company may acquire an interest will maintain similar insurance coverage. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on the Company's business, financial condition and results of operation. The Company's use of hedging arrangements could result in financial losses or reduce the Company's income. The Company currently engages in hedging arrangements to reduce its exposure to fluctuations in the prices of natural gas for a significant portion of its current natural gas production. These hedging arrangements expose the Company to risk of financial loss in some circumstances, including when production is less than expected; the counter-party to the hedging contract defaults on its contract obligations; or there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received. In addition, these hedging arrangements may limit the benefits the Company would otherwise receive from increases in prices for natural gas. See "Management's Discussion and Analysis of Financial Condition Results of Operations--Quantitative and Qualitative Disclosures About Market Risk" and "Business--Exploration and Production Activities--Hedging Activities." The Company's natural gas sales are dependent on a single customer. The Company markets its own natural gas and more than 95% of its natural gas is sold to ONEOK Energy Marketing and Trading Company ("ONEOK"). In the event that ONEOK were to experience financial difficulties or were to no longer purchase the Company's natural gas, the Company could, in the short term, experience difficulty in its marketing of natural gas, which could adversely affect its results of operations. The Company incurs risks in acquiring producing properties. The Company constantly evaluates opportunities to acquire additional natural gas and oil properties and frequently engage in bidding and negotiation for these acquisitions. If successful in this process, the Company may alter or increase its capitalization through the issuance of additional debt or equity securities, the sale of production payments or other measures. Any change in capitalization affects the Company's risk profile. A change in capitalization, however, is not the only way acquisitions affect the Company's risk profile. Acquisitions may alter the nature of the Company's business. This could occur when the character of acquired properties is substantially different from the Company's existing properties in terms of operating or geologic characteristics. 25 The Company may incur losses as a result of title deficiencies in the properties in which the Company invests. If an examination of the title history of a property that the Company has purchased reveals that a natural gas or oil lease has been purchased in error from a person who is not the owner of the mineral interest desired, the Company's interest would be worthless. In such an instance, the amount paid for such natural gas or oil lease or leases would be lost. It is the Company's practice, in acquiring natural gas and oil leases, or undivided interests in natural gas and oil leases, not to undergo the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease. Rather, the Company will rely upon the judgment of natural gas and oil lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. Prior to the drilling of a natural gas or oil well, however, it is the normal practice in the natural gas and oil industry for the person or Company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed natural gas or oil well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such curative work entails expense. The work might include obtaining affidavits of heirship or causing an estate to be administered. The Company's failure to obtain these rights may adversely impact its ability in the future to increase production and reserves. The Company's ability to market the natural gas that it produces is essential to its business. Several factors beyond the Company's control may materially adversely affect its ability to market the natural gas and oil that it discovers. These factors include the proximity, capacity and availability of natural gas and oil pipelines and processing equipment, the level of domestic production and imports of natural gas and oil, the demand for natural gas and oil by utilities and other end users, the availability of alternative fuel sources, the effect of inclement weather, state and federal regulation of natural gas and oil marketing, market fluctuations of prices, taxes, royalties, land tenure, allowable production and environmental protection. The extent of these factors cannot be accurately predicted, but any one or a combination of these factors may result in the Company's inability to sell its natural gas at prices that would result in an adequate return on its invested capital. The Company is subject to environmental regulation that can materially adversely affect the timing and cost of the Company's operations. The Company's exploration and proposed production activities are subject to certain federal, state and local laws and regulations relating to environmental quality and pollution control. These laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation. Specifically, the Company is subject to legislation regarding the acquisition of permits before drilling, restrictions on drilling activities in restricted areas, emissions into the environment, water discharges, and storage and disposition of hazardous wastes. In addition, legislation has been enacted which requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities. However, such laws and regulations have been frequently changed in the past, and the Company is unable to predict the ultimate cost of compliance as a result of any future changes. The enactment of stricter legislation or the adoption of stricter regulation could have a significant impact on the Company's operating costs, as well as on the natural gas and oil industry in general. The Company's internal procedures and policies exist to ensure that the Company's operations are conducted in substantial compliance with all such environmental laws and regulations. However, while the Company intends to fully comply with all such environmental laws and regulations in the future, such compliance can be very complex, and therefore, no assurances can be given that such environmental laws and regulations will not have a material adverse effect on the Company's business, financial condition and results of operation. The Company's operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. The Company could also be liable for environmental damages caused by previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred which could have a material adverse effect on the Company's financial condition and results of operations. The Company maintains insurance coverage for its operations, but it does not believe that insurance coverage for environmental damages that occur over time, or complete coverage for sudden and accidental environmental damages, is available at a reasonable cost. Accordingly, the Company may be subject to liability or may lose the privilege to continue exploration or production activities upon substantial portions of the Company's properties if certain environmental damages occur. 26 The Company is subject to complex governmental regulations which may materially adversely affect the cost of the Company's business. Natural gas and oil exploration, development and production are subject to various types of regulation by local, state and federal agencies. The Company may be required to make large expenditures to comply with these regulatory requirements. Legislation affecting the natural gas and oil industry is under constant review for amendment and expansion. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Any increases in the regulatory burden on the natural gas and oil industry created by new legislation would increase the Company's cost of doing business and, consequently, adversely affect the Company's profitability. A major risk inherent in drilling is the need to obtain drilling permits from local authorities. Delays in obtaining drilling permits, the failure to obtain a drilling permit for a well or a permit without unreasonable conditions or costs could have a materially adverse effect on the Company's ability to effectively develop its properties. The Company must obtain governmental permits and approvals for drilling operations, which can be a costly and time consuming process and result in restrictions on the Company's operations. Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in the commencement or continuation of the Company's exploration or production operations. For example, the Company is often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that proposed exploration for or production of natural gas and oil may have on the environment. Further, the public may comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits the Company needs may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict the Company's ability to conduct its operations or to do so profitability. The Company operates in a highly competitive environment and its competitors may have greater resources than the Company. The natural gas and oil industry is intensely competitive and the Company competes with other companies from various regions of the United States and may compete with foreign companies for domestic sales, many of whom are larger and have greater financial, technological, human and other resources. Many of these companies not only explore for and produce crude oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. Such companies may be able to pay more for productive natural gas and oil properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than the Company's financial or human resources permit. In addition, such companies may have a greater ability to continue exploration activities during periods of low hydrocarbon market prices. The Company's ability to acquire additional properties and to discover reserves in the future will be dependent upon the Company's ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. If the Company is unable to compete, its operating results and financial position may be adversely affected. The coal beds from which the Company produces methane gas frequently contain water that may hamper the Company's ability to produce gas in commercial quantities. Coal beds frequently contain water that must be removed in order for the gas to detach from the coal and flow to the well bore. The Company's ability to remove and dispose of sufficient quantities of water from the coal seam will determine whether or not the Company can produce gas in commercial quantities. The cost of water disposal may affect the Company's profitability. The Company may have difficulty managing growth in its business. Because of the Company's small size, growth in accordance with its business plans, if achieved, will place a significant strain on the Company's financial, technical, operational and management resources. As the Company expands its activities and increases the number of projects it is evaluating or in which it participates, there will be additional demands on the Company's financial, technical and management resources. The failure to continue to upgrade the Company's technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the recruitment and retention of experienced managers, geoscientists and engineers, could have a material adverse effect on the Company's business, financial condition and results of operations and the Company's ability to timely execute its business plan. 27 The Company's success depends on its key management personnel, the loss of any of whom could disrupt the Company's business. The success of the Company's operations and activities is dependent to a significant extent on the efforts and abilities of the Company's management. The loss of services of any of the Company's key managers could have a material adverse effect on the Company's business. The Company has not obtained "key man" insurance for any of its management. Mr. Jerry D. Cash is the Chief Executive Officer and Mr. David E. Grose is the Chief Financial Officer. The loss of the services of either of these individuals may adversely affect the Company's business and prospects. Acquisition of entire businesses may be a component of the Company's growth strategy in the future and the Company's failure to complete future acquisitions successfully could reduce its earnings and slow its growth. The Company might acquire entire businesses in the future. Potential risks involved in the acquisition of such businesses include the inability to continue to identify business entities for acquisition or the inability to make acquisitions on terms that the Company considers economically acceptable. Furthermore, there is intense competition for acquisition opportunities in the Company's industry. Competition for acquisitions may increase the cost of, or cause the Company to refrain from, completing acquisitions. The Company's strategy of completing acquisitions is dependent upon, among other things, its ability to obtain debt and equity financing and, in some cases, regulatory approvals. The Company's ability to pursue its growth strategy may be hindered if the Company is not able to obtain such financing or regulatory approvals. The Company's ability to grow through acquisitions and manage growth will require the Company to continue to invest in operational, financial and management information systems and to attract, retain, motivate and effectively manage the Company's employees. The inability to effectively manage the integration of acquisitions could reduce the Company's focus on subsequent acquisitions and current operations, which, in turn, could negatively impact the Company's earnings and growth. The Company's financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods. The Company may not be able to replace its reserves or generate cash flows if the Company is unable to raise capital. The Company makes, and will continue to make, substantial capital expenditures for the exploration, acquisition and production of natural gas and oil reserves. Historically, the Company has financed these expenditures primarily with cash generated by operations and proceeds from bank borrowings and equity financings. If the Company's revenues or borrowing base decreases as a result of lower natural gas and oil prices, operating difficulties or declines in reserves, the Company may have limited ability to expend the capital necessary to undertake or complete future drilling programs. Additional debt or equity financing or cash generated by operations may not be available to meet these requirements. If the Company borrows money to expand its business, the Company will face the risks of leverage. As of March 30, 2006 the Company had incurred $150 million of indebtedness for borrowed money. The Company anticipates that it may in the future incur additional debt for financing its growth. The Company's ability to borrow funds will depend upon a number of factors, including the condition of the financial markets. Under certain circumstances, the use of leverage may provide a higher return to you on your investment, but will also create a greater risk of loss to you than if the Company did not borrow. The risk of loss in such circumstances is increased because the Company would be obligated to meet fixed payment obligations on specified dates regardless of the Company's revenue. If the Company does not make its debt service payments when due, the Company may sustain the loss of its equity investment in any of the Company's assets securing such debt, upon the foreclosure on such debt by a secured lender. The interest payable on the Company's debt varies with the movement of interest rates charged by financial institutions. An increase in the Company's borrowing costs due to a rise in interest rates in the market may reduce the amount of income and cash available for the payment of dividends to the holders of the Company's common stock. Because the Company is relatively small, management expects that it will be disproportionately negatively impacted by recently enacted changes in the securities laws and regulations, which are likely to increase the Company's costs and require additional management resources. 28 The Sarbanes-Oxley Act of 2002 (the "Act"), which became law in July 2002, has required changes in some of the Company's corporate governance, securities disclosure and compliance practices. In response to the requirements of that Act, the SEC has promulgated new rules covering a variety of subjects. Compliance with these new rules has significantly increased the Company's legal and financial and accounting costs, and management expects these increased costs to continue. In addition, the requirements have taxed a significant amount of the time and resources of management and the board of directors. Likewise, these developments may make it more difficult for the Company to attract and retain qualified members of the board of directors, particularly independent directors, or qualified executive officers. Because the Company is relatively small, management expects to be disproportionately negatively impacted by these changes in securities laws and regulations which will increase the Company's costs, require additional management resources and may, in the event that the Company receives anything other than an unqualified report on its internal control over financial reporting, result in greater difficulty in raising funding for the Company's operations and negatively impact its stock price. As directed by Section 404 of the Act, the SEC adopted rules requiring public companies to include a report of management on the Company's internal control over financial reporting in their annual reports on Form 10-K that contains an assessment by management of the effectiveness of the Company's internal control over financial reporting. In addition, the public accounting firm auditing the Company's financial statements must attest to and report on management's assessment of the effectiveness of the Company's internal control over financial reporting. This requirement will apply to the Company's annual report on Form 10-K for the fiscal year ended December 31, 2006. If management is unable to conclude that the Company has effective internal control over financial reporting or, if the Company's independent auditors are unable to provide the Company with an unqualified report as to the effectiveness of the Company's internal control over financial reporting as of December 31, 2006 and future year-ends as required by Section 404 of the Act, investors could lose confidence in the reliability of the Company's financial statements, which could result in a decrease in the value of its securities. The Company is a small Company with limited resources. The number and qualifications of the Company's finance and accounting staff are limited, and the Company has limited monetary resources. The Company experiences difficulties in attracting qualified staff with requisite expertise due to the Company's profile and a generally tight market for staff with expertise in these areas. Furthermore, guidance from relevant regulatory bodies and others in the field is evolving and being refined on an ongoing basis, creating difficulties in attempting to assure all matters are addressed in a timely manner. The Company has retained a consultant to assist it in the process of testing and evaluating the internal control over financial reporting. A key risk is that management will not timely remediate any deficiencies that may be identified as part of the review process. Risks Relating to the Company's Common Stock The Company's common stock does not trade in a mature market and therefore has limited liquidity. The Company's common stock trades on the over-the-counter market, and such trading has been sporadic and erratic. Holders of the Company's common stock may not be able to liquidate their investments in a short time period or at the market prices that currently exist at the time a holder decides to sell. Because of this limited liquidity, it is unlikely that shares of the Company's common stock will be accepted by lenders as collateral for loans. In addition, the Company's common stock is subject to restrictions on ownership and transfer described under "--Provisions in Nevada law could delay or prevent a change in control, even if that change would be beneficial to the Company's stockholders." There is no established trading market for the Company's common stock. The Company cannot assure you as to: o the likelihood that an active market will develop for the shares of the Company's common stock; o the liquidity of any such market; o the ability of the Company's stockholders to sell their shares of the Company's common stock; or o the price that the Company's stockholders may obtain for their shares of the Company's common stock. The Company's stock price may be volatile. The Company cannot assure you that an active public market for the Company's common stock will develop in the future. The following factors could affect the Company's stock price: o the Company's operating and financial performance and prospects; 29 o quarterly variations in the rate of growth of the Company's financial indicators, such as net income per share, net income and revenues; o changes in revenue or earnings estimates or publication of research reports by analysts about the Company or the exploration and production industry; o liquidity and registering the Company's common stock for public resale; o actual or anticipated variations in the Company's reserve estimates and quarterly operating results; o changes in natural gas and oil prices; o speculation in the press or investment community; o sales of the Company's common stock by significant stockholders; o actions by institutional investors before disposition of the Company's common stock; o increases in the Company's cost of capital; o changes in applicable laws or regulations, court rulings and enforcement and legal actions; o changes in market valuations of similar companies; o adverse market reaction to any increased indebtedness the Company incurs in the future; o additions or departures of key management personnel; o actions by the Company's stockholders; o general market conditions, including fluctuations in and the occurrence of events or trends affecting the price of natural gas and oil; and o domestic and international economic, legal and regulatory factors unrelated to the Company's performance. It is unlikely that the Company will be able to pay dividends on the common stock. The Company cannot predict with certainty that its operations will result in sufficient revenues to enable it to operate profitably and with sufficient positive cash flow so as to enable the Company to pay dividends to the holders of common stock. In addition, the Company's New Credit Facilities generally prohibit it from paying any dividend to the holders of the Company's common stock without the consent of the lenders under the New Credit Facilities, other than dividends payable solely in equity interests of the Company. The percentage ownership evidenced by the common stock is subject to dilution. The Company is authorized to issue up to 380,000,000 shares of common stock and is not be prohibited from issuing additional shares of such common stock. Moreover, to the extent that the Company issues any additional common stock, a holder of the common stock is not necessarily entitled to purchase any part of such issuance of stock. The holders of the common stock do not have statutory "preemptive rights" and therefore are not entitled to maintain a proportionate share of ownership by buying additional shares of any new issuance of common stock before others are given the opportunity to purchase the same. Accordingly, you must be willing to assume the risk that your percentage ownership, as a holder of the common stock, is subject to change as a result of the sale of any additional common stock, or other equity interests in the Company subsequent to this offering. The common stock is an unsecured equity interest. As an equity interest, the common stock will not be secured by any of the Company's assets. Therefore, in the event of the Company's liquidation, the holders of the common stock will receive a distribution only after all of the Company's secured and unsecured creditors have been paid in full. There can be no assurance that the Company will have sufficient assets after paying its secured and unsecured creditors to make any distribution to the holders of the common stock. 30 The Company's management controls a significant percentage of the Company's outstanding common stock and their interests may conflict with those of the Company's stockholders. The Company's directors and executive officers and their affiliates beneficially own approximately 11.4% of the Company's outstanding common stock. This concentration of ownership could also have the effect of delaying or preventing a change in control of or otherwise discouraging a potential acquirer from attempting to obtain control of the Company. This could have a material adverse effect on the market price of the Company's common stock or prevent the Company's stockholders from realizing a premium over the then prevailing market prices for their shares of common stock. Provisions in Nevada law could delay or prevent a change in control, even if that change would be beneficial to the Company's stockholders. Certain provisions of Nevada law may delay, discourage, prevent or render more difficult an attempt to obtain control of the Company, whether through a tender offer, business combination, proxy contest or otherwise. The provisions of Nevada law are designed to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of the Company to first negotiate with the Company's board of directors. The Nevada Revised Statutes (the "NRS") contain two provisions, described below as "Combination Provisions" and the "Control Share Act," that may make more difficult the accomplishment of unsolicited or hostile attempts to acquire control of the Company through certain types of transactions. Restrictions on Certain Combinations Between Nevada Resident Corporations and Interested Stockholders. The NRS includes the Combination Provisions prohibiting certain "combinations" (generally defined to include certain mergers, disposition of assets transactions, and share issuance or transfer transactions) between a resident domestic corporation and an "interested stockholder" (generally defined to be the beneficial owner of 10% or more of the voting power of the outstanding shares of the corporation), except those combinations which are approved by the board of directors before the interested stockholder first obtained a 10% interest in the corporation's stock. There are additional exceptions to the prohibition, which apply to combinations if they occur more than three years after the interested stockholder's date of acquiring shares. The Combination Provisions apply unless the corporation elects against their application in its original articles of incorporation or an amendment thereto. The Company's restated articles of incorporation do not currently contain a provision rendering the Combination Provisions inapplicable. Nevada Control Share Act. Nevada's Control Share Act imposes procedural hurdles on and curtails greenmail practices of corporate raiders. The Control Share Act temporarily disenfranchises the voting power of "control shares" of a person or group ("Acquiring Person") purchasing a "controlling interest" in an "issuing corporation" (as defined in the NRS) not opting out of the Control Share Act. In this regard, the Control Share Act will apply to an "issuing corporation", unless the articles of incorporation or bylaws in effect on the tenth day following the acquisition of a controlling interest provide that it is inapplicable. The Company's restated articles of incorporation and bylaws do not currently contain a provision rendering the Control Share Act inapplicable. Under the Control Share Act, an "issuing corporation" is a corporation organized in Nevada which has 200 or more stockholders of record, at least 100 of whom have addresses in that state appearing on the company's stock ledger, and which does business in Nevada directly or through an affiliated company. The Company's status at the time of the occurrence of a transaction governed by the Control Share Act (assuming that the Company's articles of incorporation or bylaws have not theretofore been amended to include an opting out provision) would determine whether the Control Share Act is applicable. The Company does not currently conduct any business in Nevada directly or through an affiliated company. The Control Share Act requires an Acquiring Person to take certain procedural steps before he or it can obtain the full voting power of the control shares. "Control shares" are the shares of a corporation (1) acquired or offered to be acquired which will enable the Acquiring Person to own a "controlling interest," and (2) acquired within 90 days immediately preceding that date. A "controlling interest" is defined as the ownership of shares which would enable the Acquiring Person to exercise certain graduated amounts (beginning with one-fifth) of all voting power of the corporation in the election of directors. The Acquiring Person may not vote any control shares without first obtaining approval from the stockholders not characterized as "interested stockholders" (as defined below). 31 To obtain voting rights in control shares, the Acquiring Person must file a statement at the principal office of the issuer ("Offeror's Statement") setting forth certain information about the acquisition or intended acquisition of stock. The Offeror's Statement may also request a special meeting of stockholders to determine the voting rights to be accorded to the Acquiring Person. A special stockholders' meeting must then be held at the Acquiring Person's expense within 30 to 50 days after the Offeror's Statement is filed. If a special meeting is not requested by the Acquiring Person, the matter will be addressed at the next regular or special meeting of stockholders. At the special or annual meeting at which the issue of voting rights of control shares will be addressed, "interested stockholders" may not vote on the question of granting voting rights to control the corporation or its parent unless the articles of incorporation of the issuing corporation provide otherwise. The Company's restated articles of incorporation and bylaws do not currently contain a provision allowing for such voting power. If full voting power is granted to the Acquiring Person by the disinterested stockholders, and the Acquiring Person has acquired control shares with a majority or more of the voting power, then (unless otherwise provided in the articles of incorporation or bylaws in effect on the tenth day following the acquisition of a controlling interest) all stockholders of record, other than the Acquiring Person, who have not voted in favor of authorizing voting rights for the control shares, must be sent a notice advising them of the fact and of their right to receive "fair value" for their shares. The Company's restated articles of incorporation and bylaws do not provide otherwise. By the date set in the dissenter's notice, which may not be less than 30 nor more than 60 days after the dissenter's notice is delivered, any such stockholder may demand to receive from the corporation the "fair value" for all or part of his shares. "Fair value" is defined in the Control Share Act as "not less than the highest price per share paid by the Acquiring Person in an acquisition." The Control Share Act permits a corporation to redeem the control shares in the following two instances, if so provided in the articles of incorporation or bylaws of the corporation in effect on the tenth day following the acquisition of a controlling interest: (1) if the Acquiring Person fails to deliver the Offeror's Statement to the corporation within 10 days after the Acquiring Person's acquisition of the control shares; or (2) an Offeror's Statement is delivered, but the control shares are not accorded full voting rights by the stockholders. The Company's restated articles of incorporation and bylaws do not address this matter. ITEM 1B. UNRESOLVED STAFF COMMENTS. None. ITEM 3. LEGAL PROCEEDINGS. See Note 8 - Contingencies, in notes to consolidated financial statements, which is incorporated herein by reference. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. No matters were submitted to a vote of security holders during the fourth quarter of 2005. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES. Market Information The Company's common stock trades in the over-the-counter market under the symbol "QRES". From June 8, 1999 until February 23, 2004, the Company's common stock traded on the OTC Bulletin Board. From February 23, 2004 until November 15, 2004, the Company's common stock was traded in the "pink sheets". Since November 15, 2004, the Company's common stock has traded on the OTC Bulletin Board. The table set forth below lists the range of high and low bids of the Company's common stock on the OTC Bulletin Board for each quarter of the Company's last two fiscal years: the transition period ended December 31, 2004 and the year ended December 31, 2005. The prices in the table reflect inter-dealer prices, without retail markup, markdown or commission and may not represent actual transactions. Prices have been adjusted to give effect to the 2.5 to 1.0 reverse stock split that was effective October 31, 2005. 32 Fiscal Quarter and Period Ended ------------------------------- High Price Low Price ---------- --------- December 31, 2005 $ 13.88 $ 9.58 September 30, 2005 $ 10.75 $ 6.93 June 30, 2005 $ 10.63 $ 5.28 March 31, 2005 $ 15.63 $ 7.88 December 31, 2004 (month ended) $ 15.63 $ 14.38 November 30, 2004 $ 18.13 $ 10.75 August 31, 2004 $ 12.13 $ 8.75 The closing price for QRES stock on March 24, 2006 was $11.90. Record Holders Common Stock. There are 380,000,000 shares of common stock authorized for issuance. As of March 21, 2006, there were 22,072,383 shares of common stock issued and outstanding, held of record by approximately 820 shareholders. Preferred Stock. There are 50,000,000 shares of preferred stock authorized for issuance. 500,000 shares of the authorized preferred stock have been classed as Series A Convertible Preferred Stock. Holders of Series A Convertible Preferred Stock are entitled to cumulative quarterly dividends at the annual rate of 10% on the liquidation preference of $10.00 per share and to convert each share into 1.6 shares of common stock. As of December 31, 2005, no shares of Series A Convertible Preferred Stock were issued and outstanding. Dividends The payment of dividends on the Company's stock is within the discretion of the board of directors and will depend on the Company's earnings, capital requirements, financial condition and other relevant factors. The Company has not declared any cash dividends on its common stock for the last two fiscal years and does not anticipate paying any dividends on its common stock in the foreseeable future. The ability of the Company to pay dividends on its common stock is subject to restrictions contained in its New Credit Facilities. See Item 7. "Management's Discussion and of Financial Conditions and Results of Operations--Capital Resources and Liquidity" for a discussion of these restrictions. Recent Sales of Unregistered Securities On December 20, 2005, we issued a total of 16,000 shares of common stock upon the conversion of 10,000 shares of Series A preferred stock in accordance with its terms. The Series A Preferred Stock was held by two individuals. Purchases of Equity Securities None. ITEM 6. SELECTED FINANCIAL DATA The following table sets forth selected consolidated financial data of Quest for the year ended December 31, 2005, the seven month transition period ended December 31, 2004 and the fiscal years ended May 31, 2004, 2003, and 2002. The data are derived from our audited consolidated financial statements revised to reflect the reclassification of certain items. In addition to changes in the annual average prices for oil and gas and increased production from drilling activity, significant acquisitions in recent years also impacted comparability between years. The table should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements, including the notes, appearing in Items 7 and 8 of this report. 33

Year 7 Mos Ended Ended -------- -------- December 31, Year Ended May 31, -------------------- ------------------------------ 2005 2004 2004 2003 2002 -------- -------- -------- ------- ------- ($ in thousands, except per share data) Statement of Operations Data: Revenues: Oil and gas sales $ 44,565 $ 24,201 $ 28,147 $ 8,345 $ 1,699 Gas pipeline revenue 3,939 1,918 2,707 632 433 Other revenue/expense 389 37 (843) (879) 303 -------- -------- -------- ------- ------- Total revenues 48,893 26,156 30,011 8,098 2,435 Costs and expenses: Oil and gas production 14,388 5,389 6,835 1,979 593 Pipeline operating 8,470 3,653 3,506 912 662 General and administrative 4,802 2,681 2,555 977 370 Depreciation and amortization 22,199 7,671 7,650 1,822 401 -------- -------- -------- ------- ------- Total costs and expenses 49,859 19,394 20,546 5,690 2,026 -------- -------- -------- ------- ------- Operating income (loss) (966) 6,762 9,465 2,408 409 -------- -------- -------- ------- ------- Other income (expense): Change in derivative fair value (4,668) (1,487) (2,013) (4,867) -- Sale of assets 12 -- (6) (3) -- Interest expense, net (26,319) (10,138) (8,056) (727) (213) -------- -------- -------- ------- ------- Total other expense (30,975) (11,625) (10,075) (5,597) (213) -------- -------- -------- ------- ------- Income (loss) before income taxes (31,941) (4,863) (610) (3,189) 196 Deferred income tax benefit (expense) -- -- 245 (374) (72) -------- -------- -------- ------- ------- Net income (loss) before cumulative effect of accounting change (31,941) (4,863) (365) (3,563) 124 Cumulative effect of accounting change, net of tax -- -- (28) -- -- -------- -------- -------- ------- ------- Net income (loss) (31,941) (4,863) (393) (3,563) 124 Preferred stock dividends (10) (6) (10) (10) (10) -------- -------- -------- ------- ------- Net income (loss) available to common shareholders $(31,951) $ (4,869) $ (403) $(3,573) $ 114 ======== ======== ======== ======= ======= Income (loss) per common share-basic: Income (loss) before cumulative effect of accounting change $ (3.81) $ (0.86) $ (0.07) $ (0.87) $ 0.04 Cumulative effect of accounting change -- -- -- -- -- -------- -------- -------- ------- ------- $ (3.81) $ (0.86) $ (0.07) $ (0.87) $ 0.04 ======== ======== ======== ======= ======= Income (loss) per common share-diluted: Income (loss) before cumulative effect of accounting change $ (3.81) $ (0.86) $ (0.07) $ (0.87) $ 0.04 Cumulative effect of accounting change -- -- -- -- -- -------- -------- -------- ------- ------- $ (3.81) $ (0.86) $ (0.07) $ (0.87) $ 0.04 ======== ======== ======== ======= =======

34

Year 7 Mos Ended Ended --------- --------- December 31, Year Ended May 31, ---------------------- --------------------------- 2005 2004 2004 2003 2002 --------- --------- -------- ------- ------ ($ in thousands, except per share data) Cash Flow Data: Cash provided (used) by operating activities $ (4,914) $ 25,484 $ 12,197 $ 4,211 $1,306 Cash used in investing activities 73,601 48,814 146,834 8,804 3,494 Cash provided by financing activities 74,616 26,280 135,456 7,205 2,077 Balance Sheet Data: Total assets $ 297,803 $ 237,962 $190,375 $36,533 $9,671 Long-term debt, net of current maturities 100,581 193,984 159,290 16,081 2,167 Stockholders' equity (deficit) 115,673 (2,606) 2,235 11,142 4,612

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. Financial Data The following table sets forth certain information regarding the production volumes, oil and gas sales, average sales prices received and expenses for the periods indicated:

Year Ended 7 Mos Ended ---------- ---------- December 31, Year Ended ------------------------ May 31, 2005 2004 2004 ---------- ---------- ----------- Net Production: Gas (bcf) 9.57 5.01 5.53 Oil (bbls) 9,241 5,551 8,549 Gas equivalent (bcfe) 9.62 5.05 5.58 Gas and Oil Sales ($ in thousands): Gas sales $ 71,137 $ 28,864 $ 27,694 Gas derivatives - gains (loss) $ (27,066) $ (4,908) $ 102 ---------- ---------- ----------- Total gas sales $ 44,071 $ 23,956 $ 27,796 Oil sales $ 494 $ 245 $ 351 ---------- ---------- ----------- Total gas and oil sales $ 44,565 $ 24,201 $ 28,147 Average Sales Price (excluding effects of hedging): Gas ($ per mcf) $ 7.44 $ 5.74 $ 5.19 Oil ($ per bbl) $ 53.46 $ 44.14 $ 41.06 Gas equivalent ($ per mcfe) $ 7.45 $ 5.77 $ 5.02 Average Sales Price (including effects of hedging): Gas ($ per mcf) $ 4.61 $ 4.83 $ 5.04 Oil ($ per bbl) $ 53.46 $ 44.14 $ 41.06 Gas equivalent ($ per mcfe) $ 4.63 $ 4.79 $ 5.04 Expenses ($ per mcfe): Lifting $ 0.98 $ 0.72 $ 0.91 Production and property tax $ 0.58 $ 0.37 $ 0.34 Pipeline operating $ 0.82 $ 0.70 $ 0.61 General and administrative $ 0.50 $ 0.53 $ 0.46 Depreciation and amortization $ 2.31 $ 1.52 $ 1.37 Interest expense $ 2.74 $ 2.01 $ 1.44 Capital expenditures $ 73,601A $ 48,814 $ 146,834B Miles of Pipeline Constructed 120 124 20 Net Wells Drilled 99 330 153 Producing Gas & Oil Wells as of the End of Period 1,055 824 707

A-includes approximately $26.1 million for Class A Units acquired B-includes approximately $126 million for assets acquired from Devon Energy Production Company, L.P. and Tall Grass Gas Services, L.L.C. The following discussion of financial condition and results of operations should be read in conjunction with the consolidated financial statements and the notes to the consolidated financial statements, which are included elsewhere in this report. 35 Cautionary Statements for Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995 We are including the following discussion to inform you of some of the risks and uncertainties that can affect our company and to take advantage of the "safe harbor" protection for forward-looking statements that applicable federal securities law affords. Various statements this report contains, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements. These include such matters as: o projections and estimates concerning the timing and success of specific projects; o financial position; o business strategy; o budgets; o amount, nature and timing of capital expenditures; o drilling of wells; o acquisition and development of natural gas and oil properties; o timing and amount of future production of natural gas and oil; o operating costs and other expenses; o estimated future net revenues from natural gas and oil reserves and the present value thereof; o cash flow and anticipated liquidity; and o other plans and objectives for future operations. When we use the words "believe," "intend," "expect," "may," "will," "should," "anticipate," "could," "estimate," "plan," "predict," "project," or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this report speak only as of the date of this report; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. All subsequent oral and written forward looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these factors. These risks, contingencies and uncertainties relate to, among other matters, the following: o our ability to implement our business strategy; o the extent of our success in discovering, developing and producing reserves, including the risks inherent in exploration and development drilling, well completion and other development activities; o fluctuations in the commodity prices for natural gas and crude oil; o engineering and mechanical or technological difficulties with operational equipment, in well completions and workovers, and in drilling new wells; o land issues; o the effects of government regulation and permitting and other legal requirements; o labor problems; o environmental related problems; o the uncertainty inherent in estimating future natural gas and oil production or reserves; o production variances from expectations; o the substantial capital expenditures required for construction of pipelines and the drilling of wells and the related need to fund such capital requirements through commercial banks and/or public securities markets; o disruptions, capacity constraints in or other limitations on our pipeline systems; o costs associated with perfecting title for natural gas rights in some of our properties; o the need to develop and replace reserves; o competition; o dependence upon key personnel; o the lack of liquidity of our equity securities; o operating hazards attendant to the natural gas and oil business; o down-hole drilling and completion risks that are generally not recoverable from third parties or insurance; o potential mechanical failure or under-performance of significant wells; o climatic conditions; o natural disasters; 36 o acts of terrorism; o availability and cost of material and equipment; o delays in anticipated start-up dates; o our ability to find and retain skilled personnel; o availability of capital; o the strength and financial resources of our competitors; and o general economic conditions. When you consider these forward-looking statements, you should keep in mind these risk factors and the other factors discussed under Item 1A.--"Risk Factors." Overview of Company Status The successful integration of the three major acquisitions that have occurred during the last two fiscal years (Devon, Perkins/Willhite and STP); the stimulation asset acquisition (Consolidated) during the transition period ended December 31, 2004 and the service units acquired during the fourth quarter of 2005 (Faith) into one new organization, has allowed us to support new levels of development and operational activities. This integration has been accomplished with all of our personnel now comprising an effective new team. Our strategic positioning in the southeastern Kansas and northeastern Oklahoma natural gas industry has contributed to increases in total revenues and has resulted in a solid foundation for future growth. The increase in total revenues in 2005 as compared to the unaudited calendar year 2004, resulted from higher product prices (before hedge settlements) for natural gas and an increase in production volumes. At December 31, 2005, Quest had an interest in 1,055 natural gas and oil wells (gross) and natural gas and oil leases on approximately 533,000 gross acres. Management believes that the proximity of the 1,100 miles of company-owned pipeline network to these natural gas and oil leases will enable the Company to develop new producing wells on many of its un-developed properties. The current inventory of undeveloped acreage is expected to yield more than 1,800 additional natural gas well drilling sites. With approximately 600 wells planned to be drilled during each of 2006, 2007 and 2008, we are positioned for significant growth in natural gas production, revenues, and net income. However, no assurance can be given that we will be able to achieve our anticipated rate of growth or that adequate sources of capital will be available. Significant Developments During the Year Ended December 31, 2005 Due to restrictions on drilling new wells in our prior credit facility, during most of 2005, we focused our efforts primarily on completing and connecting wells that had been drilled in 2004, expanding our pipeline network to support our existing wells and re-completing existing single seam wells into multi-seam wells. Prior to the recapitalization of the Company that occurred in November 2005, we drilled 26 new gas wells (gross), connected 207 new gas wells (gross) into our gas gathering pipeline network, constructed approximately 83 miles of pipeline and re-completed 141 wells. On November 14, 2005, we completed a recapitalization of the company that included, among other things, a private placement of 15,258,144 shares of our common stock, which resulted in our receiving gross proceeds of $198,355,872, and the replacement of our existing credit facility with a new syndicated credit facility arranged and syndicated by Guggenheim Corporate Funding, LLC ("Guggenheim"), with Guggenheim as administrative agent (the "New Credit Facilities"). The New Credit Facilities consist of a $50 million syndicated five year senior secured first lien revolving credit facility that will initially have $50 million of availability (the "New Revolving Loan"); a $50 million syndicated five year senior secured first lien term loan facility that was fully drawn as of February 14, 2006 (the "New First Lien Term Loan"); and a syndicated six year $100 million senior secured second lien term loan facility (the "New Second Lien Term Loan") that was fully drawn at November 14, 2005. For more information with respect to the recapitalization, see Items 1 and 2--"Business and Properties--Recent Developments--Recapitalization." Since the closing of the recapitalization, we have recommenced our drilling and development program. For the four month period from November 2005 through February 2006, we drilled 178 new gas wells (gross), connected 114 new gas wells (gross) into our gas gathering pipeline network, constructed approximately 108 miles of pipeline and recompleted 44 wells. 37 Results of Operations Year ended December 31, 2005 compared to the Year ended December 31, 2004 Effective January 1, 2005, we changed our fiscal year-end from May 31 to December 31. As a result of this change, we prepared audited financial statements for the seven-month transition period ended December 31, 2004. Accordingly, the following discussion of results of operations will compare audited balances for the year ended December 31, 2005 to the unaudited balances for the year ended December 31, 2004, as follows: Years ended December 31, ---------------------------- 2005 2004 ------------ ------------ (unaudited) Oil and gas sales $ 44,565,000 $ 42,409,000 Gas pipeline revenue 3,939,000 3,290,000 Other revenue and expense 389,000 632,000 ------------ ------------ Total revenues 48,893,000 46,331,000 Oil and gas production 14,388,000 9,526,000 Pipeline operating 8,470,000 5,702,000 General & administrative expense 4,802,000 4,424,000 Depreciation, depletion & amortization 22,199,000 13,935,000 ------------ ------------ Total costs and expenses 49,859,000 33,587,000 ------------ ------------ Operating income (loss) (966,000) 12,744,000 Change in derivative fair value (4,668,000) (6,812,000) Interest expense (26,365,000) (15,885,000) Interest income/other 58,000 8,000 ------------ ------------ Income (loss) before income taxes (31,941,000) (9,945,000) Income tax (expense) -- -- ------------ ------------ Net income (loss) $(31,941,000) $ (9,945,000) ============ ============ Total revenues of $48.9 million for the year ended December 31, 2005 represents an increase of 6% when compared to total revenues of $46.3 million for the year ended December 31, 2004. The increase in natural gas and oil sales from $42.4 million for the year ended December 31, 2004 to $44.6 million for the year ended December 31, 2005 and the increase in natural gas pipeline revenue from $3.3 million to $3.9 million resulted from the additional wells and pipelines acquired or completed during the past twelve months. The additional wells acquired or completed contributed to the production of 9,565,000 mcf of net gas for the year ended December 31, 2005, as compared to 8,607,000 net mcf produced for the year ended December 31, 2004. Our product prices before hedge settlements on an equivalent basis (mcfe) increased from $5.63 mcfe average for the 2004 period to $7.45 mcfe average for the 2005 period. Accounting for hedge settlements, the product prices decreased from $4.93 mcfe average for the 2004 period to $4.63 mcfe average for the 2005 period, due to the significant basis differential that occurred in the market during our fourth quarter, resulting from the hurricanes in the United States. Since new well development is once again an ongoing program, management expects the production and pipeline volumes to continue growing in the foreseeable future. We seek to reduce natural gas price volatility through the use of derivative financial instruments or hedges. As of January 1, 2006, we had entered into hedging transactions covering a total of approximately 14 Bcf of natural gas production through December 2008. See Items 1 and 2 "Description of Business and Properties--Company Operations--Exploration & Production Activities-Hedging Activities" and Notes 14 and 15 to the consolidated financial statements included in this report. Other revenue for the year ended December 31, 2005 was $389,000 as compared to other revenue of $632,000 for the year ended December 31, 2004, resulting from recording the gain or loss on hedge settlements for the two comparative periods. 38 The operating costs for the year ended December 31, 2005 totaled approximately $14.4 million as compared to operating costs of approximately $9.5 million incurred for the year ended December 31, 2004. Operating costs, excluding gross production and ad valorem taxes, were $0.99 per mcf for 2005 compared to $0.78 for the year ended December 31, 2004. Operating costs, inclusive of gross production and ad valorem taxes, were $1.57 per mcf for the 2005 period as compared to $1.11 per mcf for the year ended December 31, 2004 period, representing a 35% increase. Approximately 30% of this increase resulted from increased property taxes on wells and pipelines in the State of Kansas, due to an increase in tax valuations; approximately 25% of the increase was due to increased gross production taxes from product price increases and approximately 30% was due to a decrease in the amount of field payroll allocated to capital expenditures due to the limited amount of capital expenditures that we could incur under our prior credit facility during the last half of year 2005. Additionally, approximately 3% relates to workers compensation payments made in August 2005 as a result of an audit of our 2004 payroll and approximately 12% is due to an increase in the Company's treating program to reduce pump failures. Pipeline operating costs for the year ended December 31, 2005 totaled approximately $8.5 million ($0.89 per mcf) as compared to pipeline operating costs of $5.7 million ($0.66 per mcf) for the year ended December 31, 2004. Pipeline operating costs, excluding ad valorem taxes, were $0.82 per mcf for 2005 as compared to $0.64 per mcf for 2004. This increase in operating costs was due to the delivery of additional compressors in anticipation of increased pipeline volumes, the number of wells acquired, completed and operated during the year and the increased miles of pipeline in service. The increase in depreciation, depletion and amortization to approximately $22.2 million in 2005 from approximately $13.9 million in 2004 is a result of the increased number of producing wells and miles of pipeline acquired and developed, the higher volumes of natural gas and oil produced and the resulting increased depletion rate and development costs. In 2006, we anticipate these operating costs to decrease on a per mcf basis due to the increased volumes forecasted from our aggressive development program. General and administrative expenses increased to approximately $4.8 million for the year ended December 31, 2005 from $4.4 million in the year ended December 31, 2004 due primarily to the increased staffing in the fourth quarter to support the higher levels of development and operational activity and the added resources to enhance the Company's internal controls and financial reporting in anticipation of the Company having to comply with the requirement for an audit of our internal control over financial reporting for the year ended December 31, 2006 required under the Sarbanes-Oxley Act of 2002. See Item 1A. "Risk Factors--Risks Related to the Company's Business." Interest expense increased to approximately $26.4 million (inclusive of a $4.3 million write off of amortizing bank fees realized in connection with the refinancing of our credit facilities) for the year ended December 31, 2005 from $15.9 million for the year ended December 31, 2004, due to an increase in interest rates and due to the increase in the Company's outstanding borrowings related to the compounding of interest under the subordinated notes and equipment, development and leasehold expenditures from the Company's drilling and development program and the associated build out of pipeline systems. Change in derivative fair value was a non-cash net loss of $4.7 million for the year ended December 31, 2005, which included a $879,000 net gain attributable to the change in fair value for certain cash flow hedges that did not meet the effectiveness guidelines of SFAS 133 for the period, a $103,000 net gain attributable to the reversal of contract fair value gains and losses recognized in earnings prior to actual settlement, and a loss of $5.7 million relating to hedge ineffectiveness. Change in derivative fair value was a non-cash net loss of $6.8 million for the year ended December 31, 2004, which included a $5.0 million net loss attributable to the change in fair value for certain cash flow hedges that did not meet the effectiveness guidelines of SFAS 133 for the period, a $1.4 million net gain attributable to the reversal of contract fair value gains and losses recognized in earnings prior to actual settlement, and a loss of $3.2 million relating to hedge ineffectiveness. Amounts recorded in this caption represent non-cash gains and losses created by valuation changes in derivatives that are not entitled to receive hedge accounting. All amounts recorded in this caption are ultimately reversed in this caption over the respective contract term. We generated a net loss of $27.3 million (including $26.4 million of interest expense) before income taxes and before the change in derivative fair value of $4.7 million for the year ended December 31, 2005, compared to a net loss of $3.1 million (including $15.9 million of interest expense) before income taxes and before the change in derivative fair value of $6.8 million in the year ended December 31, 2004. No income tax expense or benefit resulted for the years ended December 31, 2005 or 2004. We recorded a net loss of $31.9 million for the year ended December 31, 2005 as compared to a net loss of $9.9 million for the year ended December 31, 2004. Seven months ended December 31, 2004 compared to the seven months ended December 31, 2003 39 As a result of the change in our fiscal year effective January 1, 2005, we have prepared financial statements for the seven-month transition period ended December 31, 2004. Accordingly, the following discussion of results of operations will compare audited balances for the seven months ended December 31, 2004 to the unaudited balances for the seven months ended December 31, 2003, as follows: Seven months ended December 31, ------------------------------- 2004 2003 ------------ ------------ (unaudited) Oil and gas sales $ 24,201,000 $ 8,755,000 Gas pipeline revenue 1,918,000 1,289,000 Other revenue and expense 37,000 (1,356,000) ------------ ------------ Total revenues 26,156,000 8,688,000 Oil and gas production 5,389,000 2,267,000 Pipeline operating 3,653,000 1,140,000 General & administrative expense 2,681,000 831,000 Depreciation, depletion & amortization 7,671,000 2,235,000 Other costs of revenues -- (8,000) ------------ ------------ Total costs and expenses 19,394,000 6,465,000 ------------ ------------ Operating income 6,762,000 2,223,000 Change in derivative fair value (1,487,000) 3,312,000 Interest expense (10,147,000) (2,377,000) Interest income 9,000 -- ------------ ------------ Income (loss) before income taxes (4,863,000) 3,158,000 Income tax (expense) -- (1,263,000) ------------ ------------ Net income (loss) $ (4,863,000) $ 1,895,000 ============ ============ Total revenues of $26.2 million for the seven months ended December 31, 2004 represents an increase of 201% when compared to total revenues of $8.7 million for the seven months ended December 31, 2003. This increase was achieved by a combination of the additional producing wells from the Devon acquisition in December 2003 and the Company's aggressive new well development program that was in effect during the 2003 and 2004 fiscal years. The increase in natural gas and oil sales from $8.8 million for the seven months ended December 31, 2003 to $24.2 million for the seven months ended December 31, 2004 and the increase in natural gas pipeline revenue from $1.3 million to $1.9 million resulted from the Devon asset acquisition and the additional wells and pipelines acquired or completed during the twelve month period ended December 31, 2004. The Devon asset acquisition and the additional wells acquired or completed contributed to the production of 5,014,000 mcf of net gas for the seven months ended December 31, 2004, as compared to 1,815,000 net mcf produced for the seven months ended December 31, 2003. Our product prices before hedge settlements on an equivalent basis (mcfe) increased from $4.82 mcfe average for the 2003 period to $5.74 mcfe average for the 2004 period. Accounting for hedge settlements, the product prices increased from $4.08 mcfe average for the 2003 period to $4.83 mcfe average for the 2004 period. Since new well development is once again an ongoing program, management expects the production and pipeline volumes to continue growing in the foreseeable future. We seek to reduce natural gas price volatility through the use of derivative financial instruments or hedges. As of January 1, 2005, we had entered into hedging transactions covering a total of approximately 22.5 Bcf of natural gas production through December 2008. See Items 1 and 2 "Description of Business and Properties--Company Operations--Exploration & Production Activities-Hedging Activities" and Notes 14 and 15 to the consolidated financial statements included in this report. Other revenue for the seven months ended December 31, 2004 was $37,000 as compared to other expense of $1.4 million for the seven months ended December 31, 2003, resulting from recording the gain or loss on hedge settlements for the two comparative periods. The operating costs for the seven months ended December 31, 2004 totaled approximately $5.4 million as compared to operating costs of approximately $2.3 million incurred for the seven months ended December 31, 2003. Operating costs per mcf for the 2004 period were $1.07 per mcf as compared to $1.25 per mcf for the 2003 period, representing a 14% decrease. Pipeline operating costs for the seven months ended December 31, 2004 totaled approximately $3.7 million as compared to pipeline operating costs of $1.1 million incurred for the seven months ended December 31, 2003. The increase in operating costs are due to the Devon asset acquisition and the number of wells acquired, completed and operated during the year and the increased miles of pipeline in service. The increase in depreciation, depletion and amortization to approximately $7.7 million from approximately $2 million is a result of the increased number of producing wells and miles of pipeline acquired and developed, the higher volumes of natural 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. 40 General and administrative expenses increased to approximately $2.7 million for the seven months ended December 31, 2004 from $831,000 in the prior seven month period due primarily 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 in anticipation of the Company having to comply with the requirement for an audit of our internal control over financial reporting for the year ended December 31, 2006 required under the Sarbanes-Oxley Act of 2002. See Item 1A. "Risk Factors--Risks Related to the Company's Business". Interest expense increased to approximately $10.1 million for the seven months ended December 31, 2004 from $2.4 million for the seven months ended December 31, 2003, due to the increase in our outstanding borrowings related to the Devon acquisition and equipment, development and leasehold expenditures from our aggressive drilling and development program during the transition period. Change in derivative fair value was a non-cash net loss of $1.5 million for the seven months ended December 31, 2004, which included a $269,000 net loss attributable to the change in fair value for certain cash flow hedges which did not meet the effectiveness guidelines of SFAS 133 for the period, a $565,000 net gain attributable to the reversal of contract fair value gains and losses recognized in earnings prior to actual settlement, and a loss of $1.8 million relating to hedge ineffectiveness. Change in derivative fair value was a non-cash net gain of $3.3 million for the seven months ended December 31, 2003, which was attributable to the change in fair value of cash flow hedges that did not meet the effectiveness guidelines of SFAS 133 for the period. 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. We generated a net loss of $3.4 million before income taxes and before the change in derivative fair value of $1.5 million for the seven months ended December 31, 2004, compared to a net loss of $154,000 before income taxes and before the change in derivative fair value of $3.3 million in the previous seven month period. No income tax expense or benefit resulted for the seven months ended December 31, 2004 compared to income tax expense of $1.3 million for the seven months ended December 31, 2003, inclusive of a tax benefit of approximately $620,000 and the resulting limitation of net operating loss carry forwards, both resulting from the acquisition of STP Cherokee, Inc. in November 2002. We recorded a net loss of $4.9 million for the seven months ended December 31, 2004 as compared to net income of $1.9 million for the seven months ended December 31, 2003. Fiscal year ended May 31, 2004 compared to fiscal year ended May 31, 2003 Total revenues of $30 million for the year ended May 31, 2004 represents an increase of 271% when compared to total revenues of $8.1 million for the fiscal year ended May 31, 2003. This increase was achieved by a combination of the additional producing wells from the Devon acquisition in December 2003, the Perkins/Willhite acquisition in June 2003, the STP Cherokee acquisition in November 2002 and the Company's aggressive new well development program during both periods. The increase in natural gas and oil sales from $8.3 million in fiscal year 2003 to $28.1 million in fiscal year 2004 and the increase in natural gas pipeline revenue from $632,000 to $2.7 million resulted from the Devon, STP Cherokee and the Perkins/Willhite acquisitions and the additional wells and pipelines acquired or completed during the 2004 fiscal year. The Devon, STP Cherokee and Perkins/Willhite acquisitions and the additional wells acquired or completed contributed to the production of 5,530,208 mcf of net gas in fiscal year 2004, as compared to 1,488,679 net mcf produced in the prior fiscal year. Our product prices on an equivalent basis (mcfe) decreased from $5.30 mcfe average for 2003 to $5.04 average for 2004. Since new well development is once again an ongoing program, management expects the production and pipeline volumes to continue growing in the foreseeable future. We seek to reduce natural gas price volatility through the use of derivative financial instruments or hedges. As of June 1, 2004, we had entered into hedging transactions covering a total of approximately 16.6 Bcf of natural gas production through December 2006. Subsequent to May 31, 2004, in connection with the establishment of new credit facilities with UBS in July 2004, we entered into additional hedging transactions covering approximately 10.2 Bcf of natural gas production through December 2008. See Items 1 and 2 "Description of Business and Properties--Company Operations--Exploration & Production Activities-Hedging Activities" and Notes 14 and 15 to the consolidated financial statements included in this report. 41 Other expense for the fiscal year ended May 31, 2004 was $843,000 as compared to other expense of $879,000 for the fiscal year ended May 31, 2003, resulting from recording the loss on hedge settlements for the two comparative periods. The operating costs for fiscal year ended May 31, 2004 totaled approximately $6.8 million as compared to operating costs of approximately $1.9 million incurred for fiscal year ended May 31, 2003. Operating costs per mcf for fiscal year May 31, 2004 were $1.24 per mcf as compared to $1.29 per mcf for fiscal year ended May 31, 2003, representing a 4% decrease. Pipeline operating costs for fiscal year ended May 31, 2004 totaled approximately $3.5 million as compared to pipeline operating costs of $912,000 incurred for fiscal year ended May 31, 2003. The increase in operating costs are due to the Devon, STP Cherokee and Perkins/Willhite acquisitions and the number of wells acquired, completed and operated during the year and the increased miles of pipeline in service. The increase in depreciation, depletion and amortization to approximately $7.7 million from approximately $1.8 million is a result of the increased number of producing wells and miles of pipelines acquired and developed, the higher volumes of natural gas and oil produced and the higher cost of properties recorded by application of the purchase method of accounting to record the Devon, STP Cherokee and Perkins/Willhite acquisitions. General and administrative expenses increased to approximately $2.6 million in fiscal year 2004 from $977,000 in the prior year due primarily to the Devon, STP and Perkins/Willhite acquisitions, 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. Interest expense increased to approximately $8.1 million for fiscal year 2004 from $727,000 for fiscal year 2003, due to the increase in the Company's outstanding borrowings related to the Devon, STP and Perkins/Willhite acquisitions and equipment, development and leasehold expenditures and the expense of $1 million related to the refinancing of the Company's credit facilities that were in place at the time of the Devon acquisition. Change in derivative fair value was a non-cash net loss of $2 million for the fiscal year ended May 31, 2004, which included a $1.7 million net loss attributable to the change in fair value for certain cash flow hedges that did not meet the effectiveness guidelines of SFAS 133 for the fiscal year, a $888,000 net gain attributable to the reversal of contract fair value gains and losses recognized in earnings prior to actual settlement, and a loss of $1.2 million relating to hedge ineffectiveness. Change in derivative fair value was a non-cash net loss of $4.9 million for the year ended May 31, 2003, which was attributable to the change in fair value of cash flow hedges that did not meet the effectiveness guidelines of SFAS 133 for the year. Amounts recorded in this caption represent non-cash gains and losses created by valuation changes in derivatives which are not entitled to receive hedge accounting. All amounts recorded in this caption are ultimately reversed in this caption over the respective contract term. We generated income of $1.4 million before income taxes and before the change in derivative fair value of $2 million for fiscal year 2004, compared to income of approximately $1.7 million before income taxes and before the change in derivative fair value of $4.9 million in the previous fiscal year. The income tax benefit for the fiscal year ended May 31, 2004 was $245,000 compared to the income tax expense of $374,000 for the fiscal year ended May 31, 2003, inclusive of a tax benefit of approximately $620,000 and the resulting limitation of net operating loss carry forwards, both resulting from the STP Cherokee acquisition. We recorded a net loss of $393,000 for fiscal year 2004 as compared to a net loss of approximately $3.6 million for fiscal year 2003. Capital Resources and Liquidity Analysis of cash flows. As a result of the change to calendar fiscal year effective January 1, 2005, we prepared audited financial statements for the seven-month transition period ended December 31, 2004. Accordingly, the following analysis of cash flows will compare audited balances for the year ended December 31, 2005 to the unaudited balances for the year ended December 31, 2004, as follows: 42

Year Ended December 31, ------------------------------ 2005 2004 ------------- ------------- (unaudited) Cash flows from operating activities: Net income (loss) $ (31,941,000) $ (9,945,000) Adjustments to reconcile net income (loss) to cash Provided by operations: Depreciation and depletion 22,949,000 14,373,000 Accrued interest subordinated note 9,586,000 8,144,000 Change in derivative fair value 4,668,000 6,812,000 Stock issued for retirement plan 266,000 121,000 Stock issued for audit committee fees 19,000 -- Stock awards granted to employees 352,000 -- Stock issued for services -- 32,000 Amortization of loan origination fees 5,106,000 540,000 Amortization of deferred hedging gains (831,000) -- Bad debt expense 192,000 -- Other 56,000 21,000 Change in assets and liabilities: Restricted cash (4,318,000) -- Accounts receivable (3,646,000) (3,857,000) Other receivables 181,000 (1,347,000) Other current assets (1,695,000) 85,000 Inventory (2,499,000) (233,000) Accounts payable (4,957,000) 16,146,000 Revenue payable 1,537,000 2,092,000 Accrued expenses 61,000 247,000 ------------- ------------- Net cash provided by (used in) operating activities (4,914,000) 33,231,000 Cash flows from investing activities: Other assets (6,071,000) (7,197,000) Equipment, development and leasehold costs (67,530,000) (48,538,000) ------------- ------------- Net cash used in investing activities (73,601,000) (55,735,000) Cash flows from financing activities: Proceeds from bank borrowings 100,103,000 139,198,000 Repayments of note borrowings (135,565,000) (105,346,000) Proceeds from subordinated debt 15,000,000 -- Repayment of subordinated debt (83,912,000) -- Refinancing costs - Guggenheim (5,892,000) -- Refinancing costs - UBS (380,000) (4,942,000) Dividends paid (10,000) (5,000) Change in other long-term liabilities -- (3,112,000) Proceeds from issuance of common stock 185,272,000 480,000 ------------- ------------- Net cash provided by financing activities 74,616,000 26,273,000 ------------- ------------- Net increase (decrease) in cash (3,899,000) 3,769,000 Cash, beginning of period 6,458,000 2,689,000 ------------- ------------- Cash, end of period $ 2,559,000 $ 6,458,000 ============= =============

At December 31, 2005, we had current assets of $21.7 million, working capital (current assets minus current liabilities, excluding the short-term derivative asset and liability of $95,000 and $38.2 million, respectively) of $3.1 million and had used $4.9 million net cash from operations during the year ended December 31, 2005. During the year ended December 31, 2005, a total of approximately $73.6 million was invested in new natural gas wells and properties, new pipeline facilities, and other additional capital items, including approximately $26.1 million to acquire the Class A Units of Quest Cherokee from ArcLight in November 2005. This investment was funded through the issuance of $12 million of additional notes to ArcLight and $3 million of additional bank borrowings during February 2005, the issuance of $3 million of additional notes to ArcLight and $2 million from the sale of common stock in July 2005 and the private placement of 15,258,144 shares of common stock in November 2005, which generated net proceeds of $183.3 million. The remainder of the net proceeds from the November 2005 private placement of common stock and the net proceeds of approximately $93.7 million from the New Second Lien Term Loan Facility were used to repay $135.6 million of bank debt and $83.9 million of subordinated notes. 43 Net cash provided by operating activities decreased substantially from $33.2 million for the year ended December 31, 2004 to $4.9 million of net cash used for the year ended December 31, 2005 due primarily to increased interest expense, an increase in operating costs, the fact that accounts payable increased substantially during 2004 due to our expanded operations and our limited liquidity at the end of 2004 and the reduction in accounts payable at the end of 2005 due to our improved liquidity as a result of the recapitalization in November 2005. Our working capital (current assets minus current liabilities, excluding the short-term derivative asset and liability of $95,000 and $38.2 million, respectively) was $3.1 million at December 31, 2005, compared to a working capital deficit of $9.5 million, (excluding the short-term derivative asset and liability of $202,000 and $9.5 million, respectively) at December 31, 2004. The change in working capital is due to the completion of the recapitalization in November 2005. Additionally, accounts receivable, inventory, oil and gas payable and accrued expenses balances increased as we expanded our operations. A significant portion of the decrease in accounts payable as of December 31, 2005 was funded with the proceeds from the November 2005 recapitalization. See Items 1 and 2 "Business and Properties--Recent Developments--Recapitalization." During 2006, we intend to focus on developing up to 600 additional new wells to be drilled and completed using resources generated by our operations, remaining cash from the equity offering and available borrowings under the New Credit Facilities. We also currently intend to drill approximately 600 wells per year for each of 2007 and 2008. Management currently estimates that it will require over the next three years a capital investment of approximately $100 million per year to drill and develop these wells and for the pipeline expansion to connect the new wells to our existing gas gathering pipeline network. Management currently estimates that it will be able to drill and develop the approximately 600 new wells planned for 2006 utilizing cash flow from operations, remaining cash from the equity offering and available borrowings under the New Credit Facilities. The Company intends to finance capital expenditures during 2007 and 2008 utilizing a combination of cash flow from operations, additional borrowings and/or the sale of equity. However, no assurances can be given that such sources will be sufficient to fund the proposed capital expenditures. We acquired certain assets from Faith Well Service on November 30, 2005 in the amount of $1.5 million. The assets consisted of service rigs and related equipment. The acquisition was funded with a portion of the net proceeds from the recapitalization. Additionally, we acquired approximately 10 miles of pipeline and 2,340 acres of leasehold from Venture Independent Petroleum during 2005 for $365,000. Default Under UBS Credit Agreement and Additional ArcLight Financing In January 2005, Quest Cherokee determined that it was not in compliance with the leverage and interest coverage ratios in its secured credit facility arranged and syndicated by UBS Securities LLC, with UBS AG, Stamford Branch as administrative agent (the "UBS Credit Agreement") for the quarter ended November 30, 2004. Despite the fact that we drilled 330 wells during the seven month transition period ended December 31, 2004, we were only able to complete and connect a total of 117 wells during that same period. We were delayed in connecting additional wells to our system due to construction delays in the expansion of our pipeline network that were largely caused by wet ground conditions from a significantly above average amount of rainfall during that period. On February 11, 2005, Quest Cherokee and ArcLight amended and restated the note purchase agreement entered into between them in December 2003 to provide for the issuance to ArcLight of up to $15 million of additional 15% junior subordinated promissory notes (the "Additional Notes") pursuant to the terms of an amended and restated note purchase agreement. Also on February 11, 2005, Quest Cherokee issued $5 million of Additional Notes to ArcLight. The February 11, 2005 amended and restated note purchase agreement also provided for Quest Cherokee to issue to ArcLight Additional Notes in the principal amount of $7 million upon Quest Cherokee obtaining a waiver from the lenders under the UBS Credit Agreement with respect to Quest Cherokee's default under the credit agreement and an amendment to the credit agreement to permit the issuance of Additional Notes to ArcLight. On February 22, 2005, Quest Cherokee obtained the necessary waivers and amendments to the UBS Credit Agreement and issued the $7 million of Additional Notes. At the same time, Quest Cherokee borrowed $5 million of additional term loans under the UBS Credit Agreement, $2 million of which was used to repay amounts owing under the revolving credit facility portion of the UBS Credit Agreement. 44 In July 2005, Quest Cherokee issued an additional $3 million of promissory notes to ArcLight and, in July and August 2005, we received a total of $2 million from the sale of 400,000 shares of our common stock to two individuals. Recapitalization Due to restrictions put in place in connection with the February 2005 amendment to the UBS Credit Agreement, we were unable to drill any additional wells until our gross daily production was at least 43 mmcf/d for 20 of the last 30 days prior to the date of drilling, after which time we could 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 did not exceed 250. We were unable to obtain these production goals without the drilling of additional wells, so our management team began exploring various strategic and refinancing alternatives. As a result of these efforts, in the fourth quarter of 2005, we completed a significant recapitalization of our capital structure. The recapitalization consisted of-- o a 2.5 to 1 reverse stock split; o a private placement of 15,258,144 shares of our common stock; o the buy-out of the investment of ArcLight in Quest Cherokee; and o the refinancing of our credit facilities. See Items 1 and 2 "Business and Properties--Recent Developments--Recapitalization" for more information with respect to the recapitalization and Note 3 "Long Term Debt" to our consolidated financial statements contained elsewhere in this report for a more detailed description of the terms of our long term debt. Management Agreement Between QES and Quest Cherokee This agreement was terminated on November 14, 2005 in connection with the recapitalization. Previously, as part of the Devon acquisition, Quest Energy Service entered into an operating and management agreement with Quest Cherokee to manage the day to day operations of Quest Cherokee in exchange for a monthly manager's fee of $292,000 plus the reimbursement of costs associated with field employees, first level supervisors, exploration, development and operation of the properties and certain other direct charges. At the time of the Devon acquisition, we consolidated all of our employees into Quest Energy Service. In September 2004, Quest Cherokee Oilfield Services was formed to acquire the stimulation assets from Consolidated. At that time, our vehicles and equipment were transferred to Quest Cherokee Oilfield Service and the costs associated with field employees, first level supervisors, exploration, development and operation of our properties and certain other direct charges began to be paid directly by Quest Cherokee Oilfield Services while Quest Energy Service continues to employ all of our non-field employees (other than first level supervisors). Due to restrictions in the UBS credit facility, prior to the recapitalization, our only source of cash flow to pay for our general and administrative expenses was the management fee paid by Quest Cherokee. As a result of the recapitalization and Quest Cherokee becoming a wholly-owned subsidiary, these restrictions have been eliminated. Wells Fargo Energy Capital Warrant In connection with entering into a credit agreement with Wells Fargo Energy Capital on November 7, 2002, we issued a warrant to Wells Fargo Energy Capital for 640,000 shares of common stock with an exercise price of $0.0025 per share. During 2005, Wells Fargo Energy Capital exercised the warrant on a "net exercise" basis and we issued 639,840 shares of our common stock to Wells Fargo Energy Capital. Other Long-Term Indebtedness The proceeds of the recapitalization were also used to payoff $373,000 of outstanding indebtedness of Quest Energy Service under a $440,000 revolving credit note. The note had a maturity date of February 19, 2008, bore interest at an annual rate of 7% per annum, required a monthly payment based upon a 60 month amortization and was secured by equipment and rolling stock. Also, $988,000 of notes payable to banks and finance companies were outstanding at December 31, 2005 and are secured by equipment and vehicles, with payments due in monthly installments through October 2013 with interest ranging from 5.5% to 11.5% per annum. Contractual Obligations Future payments due on our contractual obligations as of December 31, 2005 are as follows: 45

Total 2006 2007-2008 2009-2010 thereafter ------------ ----------- ----------- ----------- ------------ Second Lien Term Note $100,000,000 $ -- $ -- $ -- $100,000,000 Notes payable 988,000 407,000 448,000 35,000 98,000 Lease obligations 422,000 118,000 251,000 53,000 -- Derivatives 61,918,000 38,195,000 23,723,000 -- -- ------------ ----------- ----------- ----------- ------------ Total $163,328,000 $38,720,000 $24,422,000 $ 88,000 $100,098,000 ============ =========== =========== =========== ============

In November 2005, we borrowed $100 million of Second Lien Term Notes that will be due in 2011 in connection with the closing of the private placement. In November 2005, we entered into a $50 million five year First Lien Term Loan. No amounts were outstanding under the First Lien Term Loan as of December 31, 2005, but we were required to borrow the full amount by February 14, 2006. Critical Accounting Policies Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of our financial statements. We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. In preparing our consolidated financial statements and related disclosures, we must use estimates in determining the economic useful lives of our assets, the fair values used to determine possible asset impairment charges, provisions for uncollectible accounts receivable, exposures under contractual indemnifications and various other recorded or disclosed amounts. However, we believe that certain accounting policies are of more significance in our consolidated financial statement preparation process than others, which policies are discussed following. See also Note 1 to the consolidated financial statements for a summary of our significant accounting policies. Estimated Net Recoverable Quantities of Natural Gas and Oil. We use the full cost method of accounting for our natural gas and oil producing activities. The full cost method inherently relies on the estimation of proved reserves, both developed and undeveloped. The existence and the estimated amount of proved reserves affect, among other things, the amount and timing of costs depleted or amortized into income and the presentation of supplemental information on oil and gas producing activities. The expected future cash flows to be generated by natural gas and oil producing properties used in testing for impairment of such properties also rely in part on estimates of net recoverable quantities of natural gas and oil. Our estimation of net recoverable quantities of natural gas and oil is a highly technical process. Independent natural gas and oil consultants have reviewed the estimates of proved reserves of natural gas and crude oil that we have attributed to our net interest in natural gas and oil properties as of December 31, 2005. Proved reserves are the estimated quantities of natural gas and oil that geologic and engineering data demonstrates with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves may change, either positively and negatively, as additional information becomes available and as contractual, economic and political conditions change. Hedging Activities. We engage in a hedging program to mitigate our exposure to fluctuations in commodity prices and to balance our exposure to fixed and floating interest rates, and we believe that these hedges are generally effective in realizing these objectives. However, the accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. Generally, the financial statement volatility arises from an accounting requirement to recognize changes in values of financial instruments while not concurrently recognizing the values of the underlying transactions being hedged. In addition, it is not always possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. For example, when we purchase a commodity at one location and sell it at another, we may be unable to hedge completely our exposure to a differential in the price of the product between these two locations. Even when we cannot enter into a completely effective hedge, we often enter into hedges that are not completely effective in those instances where we believe to do so would be better than not hedging at all. Our financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge. 46 Legal Matters. We are subject to litigation and regulatory proceedings as a result of our business operations and transactions. We utilize internal personnel and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. We expense legal costs as incurred, and all recorded legal liabilities are revised as better information becomes available. Environmental Matters. With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable. Certain Capital Transactions During the year ended December 31, 2005, the seven months ended December 31, 2004 and the fiscal year ended May 31, 2004, we engaged in the following capital transactions: On December 20, 2005, we issued 16,000 shares of common stock upon the conversion of 10,000 shares of Series A preferred stock. On November 14, 2005, we issued 15,258,144 shares of common stock in private placement for gross proceeds of $198.4 million. On August 10, 2005, 160,000 shares of common stock sold for cash with a value of $800,000 were issued to Hartwig Investments. The securities were issued with a legend restricting resale. On July 27, 2005, 100,000 shares of common stock sold for cash with a value of $500,000 were issued to E. Peter Hoffman Jr. The securities were issued with a legend restricting resale. On July 15, 2005, 140,000 shares of common stock sold for cash with a value of $700,000 were issued to E. Peter Hoffman Jr. The securities were issued with a legend restricting resale. On June 24, 2005 and April 1, 2005, we issued 20,936 and 28,906 shares of common stock, respectively, to our 401(k) plan at a value totaling $495,000 as an employer contribution. On June 1, 2005, we issued 3,200 shares of our common stock to Mr. John Garrison as compensation for services on our audit committee valued at $19,000. On May 5, 2005, we issued 5,460 shares of our common stock to one individual as payment for approximately $45,000 worth of services rendered to the Company. On April 6, 2005, we issued 639,840 shares of common stock upon the exercise of the Wells Fargo warrant (no cash was received by the Company in connection with this exercise). On November 8, 2004, 48,000 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. The securities were issued with a legend restricting resale. On August 23, 2004, we granted a total of 10,000 shares of our common stock to Mr. John Garrison as compensation for services on our audit committee during the period from June 6, 2003 to May 31, 2005. Of the shares granted, 6,800 shares were issued with a value of $62,000 for financial reporting purposes. The remaining 3,200 shares were issued June 1, 2005. 47 On May 1, 2004, we issued 32,355 shares of common stock to our 401(k) plan valued at $121,000 as an employer contribution. On May 1, 2004, we issued 4,200 shares of common stock to one individual as payment for approximately $31,000 worth of services rendered to the Company. On September 8, 2003, we issued 58,823 shares of common stock for $500,000 in order to satisfy working capital needs. On September 1, 2003, we issued 9,060 shares of common stock to four individuals as payment for approximately $62,000 worth of services rendered to the Company. Effective June 1, 2003, we consummated the Perkins/Willhite acquisition. A portion of the purchase price for this acquisition was paid through the issuance of 200,000 shares of common stock. During fiscal year 2004, $180,000 of existing debentures were converted into 28,404 shares of common stock. Although the conversion of these debentures did not result in any additional capital being available to the Company, it did cease the accrual of additional interest under the debentures. Off-balance Sheet Arrangements At December 31, 2005, we did not have any relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. In addition, we do not engage in trading activities involving non-exchange traded contracts. As such, we are not exposed to any financing, liquidity, market, or credit risk that could arise if we had engaged in such activities. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. See Notes 14 and 15 to our consolidated financial statements which are included elsewhere in this report and incorporated herein by reference. ITEM 8. FINANCIAL STATEMENTS. Please see the accompanying financial statements attached hereto beginning on page F-1. 48 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholders Quest Resource Corporation We have audited the accompanying consolidated balance sheets of QUEST RESOURCE CORPORATION and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations, stockholders' equity, and cash flows for the year ended December 31, 2005, the seven months ended December 31, 2004 and the year ended May 31, 2004. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Quest Resource Corporation and subsidiaries as of December 31, 2005 and 2004, and the consolidated results of their operations and cash flows for the year ended December 31, 2005, the seven months ended December 31, 2004 and the year ended May 31, 2004, in conformity with accounting principles generally accepted in the United States of America. /S/ MURRELL, HALL, MCINTOSH & CO., PLLP Oklahoma City, Oklahoma March 1, 2006 F-1 QUEST RESOURCE CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS

ASSETS December 31, 2005 December 31, 2004 ----------------- ----------------- Current assets: Cash $ 2,559,000 $ 6,458,000 Restricted cash 4,318,000 -- Accounts receivable, trade 9,658,000 6,204,000 Other receivables 343,000 524,000 Other current assets 1,936,000 241,000 Inventory 2,782,000 284,000 Short-term derivative asset 95,000 202,000 ----------------- ----------------- Total current assets 21,691,000 13,913,000 Property and equipment, net of accumulated depreciation of $2,114,000 and $1,245,000 13,490,000 8,433,000 Pipeline assets, net of accumulated depreciation of $3,598,000 and $2,207,000 60,150,000 42,552,000 Pipeline assets under construction 12,699,000 12,537,000 Oil and gas properties: Properties being amortized 201,788,000 154,427,000 Properties not being amortized 18,285,000 16,707,000 ----------------- ----------------- 220,073,000 171,134,000 Less: Accumulated depreciation, depletion and amortization (36,703,000) (16,069,000) ----------------- ----------------- Net property, plant and equipment 183,370,000 155,065,000 Other assets, net 6,310,000 5,141,000 Long-term derivative asset 93,000 321,000 ----------------- ----------------- Total assets $ 297,803,000 $ 237,962,000 ================= ================= LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable $ 12,381,000 $ 17,337,000 Revenue payable 5,044,000 3,507,000 Accrued expenses 649,000 588,000 Current portion of notes payable 407,000 1,804,000 Short-term derivative liability 38,195,000 9,513,000 ----------------- ----------------- Total current liabilities 56,676,000 32,749,000 Non-current liabilities: Long-term derivative liability 23,723,000 12,964,000 Asset retirement obligation 1,150,000 871,000 Convertible debentures -- 50,000 Notes payable 100,988,000 136,413,000 Less current maturities (407,000) (1,804,000) ----------------- ----------------- Non-current liabilities 125,454,000 148,494,000 Subordinated debt (including accrued interest) -- 59,325,000 ----------------- ----------------- Total liabilities 182,130,000 240,568,000 Commitments and contingencies -- -- Stockholders' equity: 10% convertible preferred stock, $.001 par value, 50,000,000 shares authorized, 0 and 10,000 shares issued and outstanding at December 31, 2005 and 2004 -- -- Common stock, $.001 par value, 380,000,000 shares authorized, 22,072,383 and 5,699,877 shares issued and outstanding at December 31, 2005 and 2004 22,000 6,000 Additional paid-in capital 203,434,000 17,192,000 Accumulated other comprehensive income (47,171,000) (11,143,000) Accumulated deficit (40,612,000) (8,661,000) ----------------- ----------------- Total stockholders' equity (deficit) 115,673,000 (2,606,000) ----------------- ----------------- Total liabilities and stockholders' equity $ 297,803,000 $ 237,962,000 ================= =================

The accompanying notes are an integral part of these consolidated financial statements F-2 QUEST RESOURCE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS

Seven Months Year Ended Ended Year Ended December 31, December 31, May 31, 2005 2004 2004 ------------ ------------ ------------ Revenue: Oil and gas sales $ 44,565,000 $ 24,201,000 $ 28,147,000 Gas pipeline revenue 3,939,000 1,918,000 2,707,000 Other revenue and expense 389,000 37,000 (843,000) ------------ ------------ ------------ Total revenues 48,893,000 26,156,000 30,011,000 Costs and expenses: Oil and gas production 14,388,000 5,389,000 6,835,000 Pipeline operating 8,470,000 3,653,000 3,506,000 General and administrative expenses 4,802,000 2,681,000 2,555,000 Depreciation, depletion and amortization 22,199,000 7,671,000 7,650,000 ------------ ------------ ------------ Total costs and expenses 49,859,000 19,394,000 20,546,000 ------------ ------------ ------------ Operating income (loss) (966,000) 6,762,000 9,465,000 ------------ ------------ ------------ Other income (expense): Change in derivative fair value (4,668,000) (1,487,000) (2,013,000) Sale of assets 12,000 -- (6,000) Interest expense (26,365,000) (10,147,000) (8,057,000) Interest income 46,000 9,000 1,000 ------------ ------------ ------------ Total other income and expense (30,975,000) (11,625,000) (10,075,000) ------------ ------------ ------------ Loss before income taxes (31,941,000) (4,863,000) (610,000) Deferred income tax benefit (expense) -- -- 245,000 ------------ ------------ ------------ Net loss before cumulative effect of accounting change (31,941,000) (4,863,000) (365,000) Cumulative effect of accounting change, net of income tax of $19,000 -- -- (28,000) ------------ ------------ ------------ Net loss (31,941,000) (4,863,000) (393,000) Preferred stock dividends (10,000) (6,000) (10,000) ------------ ------------ ------------ Net loss available to common shareholders $(31,951,000) $ (4,869,000) $ (403,000) ============ ============ ============ Loss per common share - basic: Loss before cumulative effect of accounting change $ (3.81) $ (0.86) $ (0.07) Cumulative effect of accounting change -- -- -- ------------ ------------ ------------ $ (3.81) $ (0.86) $ (0.07) ============ ============ ============ Loss per common share - diluted: Loss before cumulative effect of accounting change $ (3.81) $ (0.86) $ (0.07) Cumulative effect of accounting change -- -- -- ------------ ------------ ------------ $ (3.81) $ (0.86) $ (0.07) ============ ============ ============ Weighted average common and common equivalent shares outstanding: Basic 8,390,092 5,661,352 5,558,352 ============ ============ ============ Diluted 8,390,092 5,661,352 5,588,352 ============ ============ ============

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

Year Ended Seven Months Year Ended December 31, Ended December 31, May 31, 2005 2004 2004 ------------- ------------------ ------------- Cash flows from operating activities: Net income (loss) $ (31,941,000) $ (4,863,000) $ (393,000) Adjustments to reconcile net income (loss) to cash provided by operations: Depreciation 2,315,000 846,000 835,000 Depletion 20,634,000 7,187,000 6,802,000 Accrued interest subordinated note 9,586,000 4,866,000 3,459,000 Change in derivative fair value 4,668,000 1,487,000 2,013,000 Cumulative effect of accounting change -- -- 47,000 Deferred income taxes -- -- (263,000) Accretion of line of credit -- -- 1,204,000 Stock issued for retirement plan 266,000 -- 121,000 Stock issued for audit committee fees 19,000 62,000 -- Stock awards granted to employees 352,000 -- -- Stock issued for services -- -- 94,000 Amortization of loan origination fees 5,106,000 530,000 172,000 Amortization of deferred hedging gains (831,000) 163,000 -- Bad debt expense 192,000 -- -- Other 56,000 28,000 44,000 Change in assets and liabilities: Restricted cash (4,318,000) -- -- Accounts receivable (3,646,000) 893,000 (4,751,000) Other receivables 181,000 85,000 (1,432,000) Other current assets (1,695,000) 16,000 (257,000) Inventory (2,499,000) 208,000 (244,000) Accounts payable (4,957,000) 13,628,000 2,302,000 Revenue payable 1,537,000 222,000 2,221,000 Accrued expenses 61,000 126,000 223,000 ------------- ------------------ ------------- Net cash provided by (used in) operating activities (4,914,000) 25,484,000 12,197,000 Cash flows from investing activities: Acquisition of proved oil and gas properties-Devon -- -- (111,849,000) Acquisition of gas gathering pipeline - Devon -- -- (21,964,000) Other assets (6,071,000) (527,000) (393,000) Equipment, development and leasehold costs (67,530,000) (48,287,000) (12,628,000) ------------- ------------------ ------------- Net cash used in investing activities (73,601,000) (48,814,000) (146,834,000) Cash flows from financing activities: Proceeds from bank borrowings 100,103,000 136,118,000 105,000,000 Repayments of note borrowings (135,565,000) (104,732,000) (21,682,000) Proceeds from subordinated debt 15,000,000 -- 51,000,000 Repayment of subordinated debt (83,912,000) -- -- Refinancing costs - Guggenheim (5,892,000) -- -- Refinancing costs - UBS (380,000) (4,942,000) -- Dividends paid (10,000) (6,000) -- Change in other long-term liabilities -- (638,000) 638,000 Proceeds from issuance of common stock 185,272,000 480,000 500,000 ------------- ------------------ ------------- Net cash provided by financing activities 74,616,000 26,280,000 135,456,000 ------------- ------------------ ------------- Net increase (decrease) in cash (3,899,000) 2,950,000 819,000 Cash, beginning of period 6,458,000 3,508,000 2,689,000 ------------- ------------------ ------------- Cash, end of period $ 2,559,000 $ 6,458,000 $ 3,508,000 ============= ================== =============

The accompanying notes are an integral part of these consolidated financial statements F-4 QUEST RESOURCE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FOR THE YEAR ENDED DECEMBER 31, 2005, THE SEVEN MONTHS ENDED DECEMBER 31, 2004 AND THE YEAR ENDED MAY 31, 2004

Preferred Common Additional Preferred Common Stock Stock Paid-In Shares Shares Par Value Par Value Capital --------- ---------- ---------- ---------- --------------- Balance, May 31, 2003 10,000 5,312,235 $ -- $ 5,000 $ 14,536,000 Comprehensive income: Net loss Other comprehensive loss, net of tax: Change in fixed-price contract and other derivative fair value Reclassification adjustments-contract settlements Total comprehensive loss Stock sales for cash 58,823 500,000 Stock issued for acquisition 200,000 1,000 1,219,000 Stock issued for services 13,260 94,000 Stock issued for convertible debt 28,404 180,000 Stock issued employees 401(k) plan 32,355 121,000 --------- ---------- ---------- ---------- --------------- Balance, May 31, 2004 10,000 5,645,077 $ -- $ 6,000 $ 16,650,000 --------- ---------- ---------- ---------- --------------- Comprehensive income: Net loss Other comprehensive loss, net of tax: Change in fixed-price contract and other derivative fair value Reclassification adjustments-contract settlements Total comprehensive loss Dividends on preferred stock Stock sales for cash 48,000 480,000 Stock issued for services 6,800 62,000 --------- ---------- ---------- ---------- --------------- Balance, December 31, 2004 10,000 5,699,877 $ -- $ 6,000 $ 17,192,000 --------- ---------- ---------- ---------- --------------- Comprehensive income: Net loss Other comprehensive loss, net of tax: Change in fixed-price contract and other derivative fair value Reclassification adjustments-contract settlements Total comprehensive loss Dividends on preferred stock Equity offering 15,258,164 15,000 183,257,000 Conversion of preferred stock (10,000) 16,000 Stock sales for cash 400,000 2,000,000 Stock issued for exercise of warrant 639,840 1,000 (1,000) Stock issued to employees 401(k) plan 49,842 495,000 Stock awards granted to employees 427,000 Stock issued for services 8,660 64,000 --------- ---------- ---------- ---------- --------------- Balance, December 31, 2005 -- 22,072,383 $ -- $ 22,000 $ 203,434,000 ========= ========== ========== ========== ===============

Accumulated Other Comprehensive Accumulated Income (Loss) Deficit Total -------------- ---------------- ------------- Balance, May 31, 2003 $ -- $ (3,399,000) $ 11,142,000 Comprehensive income: Net loss (393,000) (393,000) Other comprehensive loss, net of tax: Change in fixed-price contract and other derivative fair value (10,044,000) (10,044,000) Reclassification adjustments-contract settlements (585,000) (585,000) ------------- Total comprehensive loss (11,022,000) ------------- Stock sales for cash 500,000 Stock issued for acquisition 1,220,000 Stock issued for services 94,000 Stock issued for convertible debt 180,000 Stock issued employees 401(k) plan 121,000 -------------- ---------------- ------------- Balance, May 31, 2004 $ (10,629,000) $ (3,792,000) $ 2,235,000 -------------- ---------------- ------------- Comprehensive income: Net loss (4,863,000) (4,863,000) Other comprehensive loss, net of tax: Change in fixed-price contract and other derivative fair value (5,258,000) (5,258,000) Reclassification adjustments-contract settlements 4,744,000 4,744,000 ------------- Total comprehensive loss (5,377,000) ------------- Dividends on preferred stock (6,000) (6,000) Stock sales for cash 480,000 Stock issued for services 62,000 -------------- ---------------- ------------- Balance, December 31, 2004 $ (11,143,000) $ (8,661,000) $ (2,606,000) -------------- ---------------- ------------- Comprehensive income: Net loss (31,941,000) (31,941,000) Other comprehensive loss, net of tax: Change in fixed-price contract and other derivative fair value (63,924,000) (63,924,000) Reclassification adjustments-contract settlements 27,896,000 27,896,000 ------------- Total comprehensive loss (67,969,000) ------------- Dividends on preferred stock (10,000) (10,000) Equity offering 183,272,000 Conversion of preferred stock -- Stock sales for cash 2,000,000 Stock issued for exercise of warrant -- Stock issued to employees 401(k) plan 495,000 Stock awards granted to employees 427,000 Stock issued for services 64,000 -------------- ---------------- ------------- Balance, December 31, 2005 $ (47,171,000) $ (40,612,000) $ 115,673,000 ============== ================ =============

F-5 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Basis of Presentation and Summary of Significant Accounting Policies Nature of Business Quest Resource Corporation (the "Company") is an independent energy company with an emphasis on the acquisition, production, transportation, exploration, and development of natural gas (coal bed methane) in southeastern Kansas and northeastern Oklahoma. Quest operations are currently focused on developing coal bed methane gas production in a ten county region that is served by a Company-owned pipeline network. Principles of Consolidation and Subsidiaries Ownership of Subsidiaries; Formation of Quest Cherokee. The Company's subsidiaries consist of: o STP Cherokee, Inc., an Oklahoma corporation ("STP"), o Quest Energy Service, Inc., a Kansas corporation ("QES"), o Quest Oil & Gas Corporation, a Kansas corporation ("QOG"), o Producers Service, Incorporated, a Kansas corporation ("PSI"), o Ponderosa Gas Pipeline Company, a Kansas corporation ("PGPC"), o Bluestem Pipeline, LLC, a Delaware limited liability company ("Bluestem"), o J-W Gas Gathering, L.L.C., a Kansas limited liability Company ("J-W Gas"), o Quest Cherokee, LLC, a Delaware limited liability company ("Quest Cherokee"), 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. Quest Cherokee was formed on December 22, 2003 to own and operate the Company's oil and gas properties in the Cherokee Basin of southeastern Kansas and northeastern Oklahoma. Upon its formation, QES, QOG, PGPC, STP, PSI and J-W Gas contributed all of their natural gas and oil properties in the Cherokee Basin with an agreed upon value of $51 million in exchange for all of the membership interests in Quest Cherokee. The transfer of these properties was treated as a corporate restructuring. For financial reporting purposes, the properties transferred to Quest Cherokee by the Company and its subsidiaries, were transferred at historical cost. Subsequent to the formation of Quest Cherokee, Cherokee Energy Partners, LLC, a wholly owned subsidiary of ArcLight Energy Partners Fund I, L.P. ("ArcLight"), purchased a $51 million of 15% junior subordinated promissory notes of Quest Cherokee at par. In connection with the purchase of the subordinated promissory notes, the original limited liability company agreement for Quest Cherokee was amended and restated to, among other things, provide for Class A units and Class B units of membership interest, and ArcLight acquired all of the Class A units of Quest Cherokee in exchange for $100. The existing membership interests in Quest Cherokee owned by the Company's subsidiaries were converted into all of the Class B units. Effective November 14, 2005, the Company affected a buy out of the ArcLight investment that included the purchase of the Class A units held by ArcLight and Quest Cherokee is now a wholly-owned subsidiary of the Company. Quest Cherokee is the sole member of Bluestem and QCOS. Financial reporting by the Company's subsidiaries is consolidated into one set of financial statements with the Company. Ownership of Company Assets. Quest Cherokee owns and operates all of the Company's Cherokee Basin natural gas and oil properties. Quest Cherokee Oilfield Service owns and operates all of the Company's vehicles and equipment and Bluestem owns all of the Company's gas gathering pipeline assets in the Cherokee Basin. QES employs all of the Company's non-field employees and had 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"). This Management Agreement was terminated with the buy out of the ArcLight investment on November 14, 2005. 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. F-6 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Terms of Subordinated Promissory Notes. Prior to November 14, 2005, the subordinated promissory notes accrued interest at the rate of 15% per annum and had a maturity date of October 22, 2010. Interest on the subordinated promissory notes was payable on January 31, April 30, July 31 and October 31 of each year. Quest Cherokee had the option to pay accrued interest on the subordinated promissory notes by issuing additional subordinated promissory notes as payment for the accrued interest. The subordinated promissory notes were paid in full on November 14, 2005. Minority Investments; Other. Investments in which the Company does not have a majority voting or financial controlling interest are accounted for under the equity method of accounting unless its ownership constitutes less than a 20% interest in such entity for which such investment would then be included in the consolidated financial statements on the cost method. All significant inter-company transactions and balances have been eliminated in consolidation. Financial reporting by the Company's subsidiaries is consolidated into one set of financial statements for QRC. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Basis of Accounting The Company's financial statements are prepared using the accrual method of accounting. Revenues are recognized when earned and expenses when incurred. Cash Equivalents For purposes of the consolidated financial statements, the Company considers investments in all highly liquid instruments with original maturities of three months or less at date of purchase to be cash equivalents. Uninsured Cash Balances The Company maintains its cash balances at several financial institutions. Accounts at the institutions are insured by the Federal Deposit Insurance Corporation up to $100,000. Periodically, the Company's cash balances are in excess of this amount. Accounts Receivable The Company conducts the majority of its operations in the States of Kansas and Oklahoma and operates exclusively in the natural gas and oil industry. The Company's joint interest and natural gas and oil sales receivables are generally unsecured; however, the Company has not experienced any significant losses to date. Receivables are recorded at the estimate of amounts due based upon the terms of the related agreements. Management periodically assesses the Company's accounts receivable and establishes an allowance for estimated uncollectible amounts. Accounts determined to be uncollectible are charged to operations when that determination is made. Inventory Inventory, which is included in current assets, includes tubular goods and other lease and well equipment which we plan to utilize in our ongoing exploration and development activities and is carried at the lower of cost or market using the specific identification method. F-7 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Concentration of Credit Risk A significant portion of the Company's liquidity is concentrated in cash and derivative instruments that enable the Company to hedge a portion of its exposure to price volatility from producing natural gas and oil. These arrangements expose the Company to credit risk from its counterparties. The Company's accounts receivable are primarily from purchasers of natural gas and oil products. Natural gas sales to one purchaser (ONEOK) accounted for more than 95% of total natural gas and oil revenues for the year ended December 31, 2005 and for the seven months ended December 31, 2004 and 90% for the fiscal year ended May 31, 2004. The industry concentration has the potential to impact the Company's overall exposure to credit risk, either positively or negatively, in that the Company's customers may be similarly affected by changes in economic, industry or other conditions. Natural Gas and Oil Properties The Company follows the full cost method of accounting for natural gas and oil properties, prescribed by the Securities and Exchange Commission ("SEC"). Under the full cost method, all acquisition, exploration, and development costs are capitalized. The Company capitalizes internal costs including: salaries and related fringe benefits of employees directly engaged in the acquisition, exploration and development of natural gas and oil properties, as well as other directly identifiable general and administrative costs associated with such activities. All capitalized costs of natural gas and oil properties, including the estimated future costs to develop proved reserves, are amortized on the units-of-production method using estimates of proved reserves. Investments in unproved reserves and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Abandonment's of natural gas and oil properties are accounted for as adjustments of capitalized costs; that is, the cost of abandoned properties is charged to the full cost pool and amortized. Under the full cost method, the net book value of natural gas and oil properties, less related deferred income taxes, may not exceed a calculated "ceiling". The ceiling is the estimated after-tax future net revenue from proved natural gas and oil properties, discounted at 10% per annum plus the lower of cost or fair market value of unproved properties adjusted for the present value of all future oil and gas hedges. In calculating future net revenues, prices and costs in effect at the time of the calculation are held constant indefinitely, except for changes that are fixed and determinable by existing contracts. The net book value is compared to the ceiling on a quarterly basis. The excess, if any, of the net book value above the ceiling is required to be written off as an expense. Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between the capitalized costs and proved reserves of natural gas and oil, in which case the gain or loss is recognized in income. Other Property and Equipment Other property and equipment is reviewed on an annual basis for impairment and as of December 31, 2005, the Company had not identified any such impairment. Repairs and maintenance are charged to operations when incurred and improvements and renewals are capitalized. Other property and equipment are stated at cost. Depreciation is calculated using the straight-line method for financial reporting purposes and accelerated methods for income tax purposes. The estimated useful lives are as follows: Pipeline 40 years Buildings 25 years Equipment 10 years Vehicles 7 years F-8 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Debt Issue Costs Included in other assets are costs associated with bank credit facilities. The remaining unamortized debt issue costs at December 31, 2005 and 2004 totaled $5.8 million and $4.6 million, respectively, and are being amortized over the life of the credit facilities. Other Dispositions Upon disposition or retirement of property and equipment other than natural gas and oil properties, the cost and related accumulated depreciation are removed from the accounts and the gain or loss thereon, if any, is credited or charged to income. Marketable Securities In accordance with Statement of Financial Accounting Standards ("SFAS") 115, Accounting for Certain Investments in Debt and Equity Securities, the Company classifies its investment portfolio according to the provisions of SFAS 115 as either held to maturity, trading, or available for sale. At December 31, 2005 and 2004, the Company did not have any investments in its investment portfolio classified as available for sale and held to maturity. Income Taxes The Company accounts for income taxes pursuant to the provisions of the SFAS 109, Accounting for Income Taxes, which requires an asset and liability approach to calculating deferred income taxes. The asset and liability approach requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the carrying amounts and the tax basis of assets and liabilities. The provision for income taxes differ from the amounts currently payable because of temporary differences (primarily intangible drilling costs and the net operating loss carry forward) in the recognition of certain income and expense items for financial reporting and tax reporting purposes. Earnings Per Common Share SFAS 128, Earnings Per Share, requires presentation of "basic" and "diluted" earnings per share on the face of the statements of operations for all entities with complex capital structures. Basic earnings per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted during the period. Dilutive securities having an anti-dilutive effect on diluted earnings per share are excluded from the calculation. See Note 9 - Earnings Per Share, for a reconciliation of the numerator and denominator of the basic and diluted earnings per share computations. Reverse Stock Split In October 2005, the Company's board of directors approved a 2.5 to 1 reverse stock split, and a proportionate reduction of the authorized number of shares, of the Company's common stock. In addition, the reverse stock split resulted in a reclassification from common stock to additional paid-in capital to reflect the adjusted share amount as the par value of the Company's common stock remained at $0.001. On October 31, 2005, the reverse stock split became effective. All share and per share data information in this Form 10-K, and the financial statements included herein, for all periods have been retroactively restated to reflect the reverse stock split. Fair Value of Financial Instruments The Company's financial instruments consist of cash, receivables, deposits, hedging contracts, accounts payable, accrued expenses, convertible debentures and notes payable. The carrying amount of cash, receivables, deposits, accounts payable and accrued expenses approximates fair value because of the short-term nature of those instruments. The hedging contracts are recorded in accordance with the provisions of SFAS 133, Accounting for Derivative Instruments and Hedging Activities. 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. F-9 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Stock-Based Compensation Stock Options. The Company applies the intrinsic value-based method of accounting prescribed by Accounting Principles Board Opinion ("APB") 25, Accounting for Stock Issued to Employees, and related interpretations including Financial Accounting Standards Board Interpretation ("FIN") 44, Accounting for Certain Transactions Involving Stock Compensation, an interpretation of APB 25, to account for non-plan stock options granted to employees and non-employee directors. Under this method, compensation expense is recorded on the date of grant only if the fair value of the underlying stock exceeded the exercise price, and is amortized ratably over the service period. As required by FIN 44, the Company uses a fair value-based method to account for stock options granted to service providers. SFAS 123, Accounting for Stock-Based Compensation, and SFAS 148, Accounting for Stock-Based Compensation-Transition and Disclosure, established accounting and disclosure requirements using a fair value-based method of accounting for stock-based employee compensation plans. As allowed by SFAS 123, the Company has elected to apply the intrinsic value-based method of accounting described above, and has adopted the disclosure requirements of SFAS 148. Pro forma information regarding net income and earnings per share is required by SFAS 123 and has been determined as if we had accounted for our non-employee director stock options under the fair value method of the statement. The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for 2005: interest rate (zero-coupon U.S. government issues with a remaining life equal to the expected term of the options) of 4.34%, no dividends over the option term, and a volatility factor of the expected market price of our common stock of 0.30. We used a weighted-average expected life of the options of 8.3 years. Pro forma financial information assuming the Company had applied the fair value method under SFAS No. 123 is as follows:

Year Ended Seven Months Ended Year Ended December 31, 2005 December 31, 2004 May 31, 2004 ----------------- ------------------ ------------ Net loss, as reported $ (31,941,000) $ (4,863,000) $ (393,000) Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects (328,000) -- -- ----------------- ------------------ ------------ Pro forma net loss $ (32,269,000) $ (4,863,000) $ (393,000) ================= ================== ============ Loss per share: Basic - as reported $ (3.81) $ (0.86) $ (0.07) ================= ================== ============ Basic - pro forma $ (3.85) $ (0.86) $ (0.07) ================= ================== ============ Diluted - as reported $ (3.81) $ (0.86) $ (0.07) ================= ================== ============ Diluted - pro forma $ (3.85) $ (0.86) $ (0.07) ================= ================== ============

For purposes of the pro forma disclosures, the estimated fair value of the options is amortized to expense over the option vesting period, which is four years for non-employee director options. F-10 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS In December 2004, the Financial Accounting Standards Board issued SFAS 123(R), Share-Based Payment, a revision of SFAS 123, accounting for stock-based compensation. This statement establishes standards for the accounting of transactions in which an entity exchanges its equity instruments for goods or services by requiring a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. That cost will be recognized over the period during which an employee is required to provide services in exchange for the award. The fair value of employee stock options will be estimated using option-pricing models. Excess tax benefits will be recognized as an addition to paid-in capital. Cash retained as a result of those excess tax benefits will be presented in the statement of cash flows as financing cash inflows. The write-off of deferred tax assets relating to unrealized tax benefits associated with recognized compensation cost will be recognized as income tax expense unless there are excess tax benefits from previous awards remaining in paid-in capital to which it can be offset. This statement was initially effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. However, in April 2005, the Securities and Exchange Commission adopted a new rule that amends the compliance dates for SFAS 123(R). The new rule allows the implementation of SFAS 123(R) at the beginning of the annual reporting period that begins after June 13, 2005, instead of the next reporting period. The SEC's new rule only changes the date for compliance with the standard. The Company will implement SFAS 123(R) in the first quarter of 2006 and the Black-Scholes option pricing model will be used to value the stock options as of the grant date. Based on the stock options outstanding and unvested at December 31, 2005, we do not believe the new accounting requirement will have a significant impact on future results of operations. Stock Awards. The Company granted shares of common stock to certain employees in October 2005. The shares are subject to pro rata vesting which ranges from 0 to 2.5 years. During this vesting period, the fair value of the stock awards granted is recognized pro rata as compensation expense. To the extent the compensation expense relates to employees directly involved in acquisition, exploration and development activities, such amounts are capitalized to oil and gas properties. Amounts not capitalized to oil and gas properties are recognized in general and administrative expenses. Accounting for Derivative Instruments and Hedging Activities The Company 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 re-designation is permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS 133, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Pursuant to the provisions of SFAS 133, all hedging designations and the methodology for determining hedge ineffectiveness must be documented at the inception of the hedge, and, upon the initial adoption of the standard, hedging relationships must be designated anew. 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 were required to be reported 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. F-11 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Although the Company's fixed-price contracts and interest rate swaps and caps 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 and interest rate risks in the future. The specific accounting for these contracts, however, is consistent with the requirements of SFAS 133. See Note 15 - Derivatives. The Company has established the fair value of all derivative instruments using estimates determined by its 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. Asset Retirement Obligations Effective June 1, 2003, the Company adopted SFAS 143, Accounting for Asset Retirement Obligations. SFAS 143 requires companies to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Company's asset retirement obligations relate to the plugging and abandonment of natural gas and oil properties. The Company is unable to predict if and when its pipelines would become completely obsolete and require decommissioning. Accordingly, the Company has recorded no liability or corresponding asset for the pipelines in conjunction with the adoption of SFAS 143 because the future dismantlement and removal dates of the Company's assets and the amount of any associated costs are indeterminable. Reclassification Certain reclassifications have been made to the prior year's financial statements in order to conform to the current presentation. The effect of the 2.5 to 1 reverse stock split was rolled back to all prior periods included in these adjusted financial statements. 2. Acquisitions Quest Cherokee acquired certain assets from Faith Well Service on November 30, 2005 in the amount of $1.5 million. The assets consisted of service rigs and related equipment. The acquisition was funded with a portion of the net proceeds from the private placement of common stock that closed on November 14, 2005. The Company purchased all of the Class A units in Quest Cherokee from ArcLight for approximately $26.1 million of which $2.1 million was allocated to non-producing leasehold, $17.0 million was allocated to wells and $7.0 million was allocated to pipeline assets. The $26.1 million purchase price for the Class A units was arrived at through negotiations between the Company and ArcLight. The Company acquired approximately 10 miles of pipeline and 2,340 acres of leasehold from Venture Independent Petroleum during 2005 for $365,000. The Company acquired certain assets from Consolidated Oil Well Services on September 15, 2004 in the amount of $4.1 million. The assets consisted 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. F-12 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The Company acquired approximately 80 miles of an inactive oil pipeline for approximately $1 million on August 10, 2004. The acquisition was funded with a portion of the remaining net proceeds from the $120 million term loan under the 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. On December 10, 2003, the Company entered into an asset purchase agreement with Devon Energy Production Company, L.P. and Tall Grass Gas Services, LLC (collectively, "Devon") to acquire certain natural gas properties located in Kansas and Oklahoma for a total consideration of $126 million, subject to certain purchase price adjustments. The acquisition was finalized on December 22, 2003. At the closing, the Company transferred all of its rights and obligations under the asset purchase agreement to Quest Cherokee. At the time of closing, Devon had not received consents to the assignment of certain of the leases from the lessors on natural gas leases with an allocated value of approximately $12.3 million. As a result, Quest Cherokee and Devon entered into a Holdback Agreement pursuant to the terms of which Quest Cherokee paid approximately $113.4 million of the purchase price at the closing and agreed to pay the allocated value of the remaining properties at such time as Devon received the consents to assignment for those leases. Subsequent to closing, Quest Cherokee paid approximately $9.6 million in February 2004, $2.6 million in May 2004 and $0.6 million in September 2004. At the time of acquisition, the acquired assets had approximately 95.9 Bcfe of estimated proved reserves, 91.7 Bcfe of estimated probable reserves and 72.2 Bcfe of estimated possible reserves. The assets included approximately 372,000 gross (366,000 net) acres of natural gas leases, 418 gross (325 net) natural gas wells and 207 miles of natural gas gathering pipelines. At the time of acquisition, the Devon assets were producing an average of approximately 19,600 mcf per day. In accordance with the terms of the asset purchase agreement, the purchase price, including approximately $7.7 million of transaction fees and $1.7 million of assumed hedging liabilities was allocated as follows: Proved producing properties $54,528,000 Proved undeveloped properties 38,649,000 Undeveloped properties 20,422,000 Pipelines 21,964,000 Other 9,000 ------------ Total $135,572,000 ============ Effective June 1, 2003, PGPC and the Company consummated a Stock Purchase Agreement with Perkins Oil Enterprises, Inc. and E. Wayne Willhite Energy, L.L.C. pursuant to the terms of which the Company and PGPC acquired from Perkins Oil Enterprises and E. Wayne Willhite Energy all of the capital stock of PSI in exchange for 200,000 shares of the common stock of the Company which was valued at $1.2 million. At the time of the acquisition, PSI owned all of the issued and outstanding membership interests of J-W Gas and a 5-year contract right to operate a lease on a 78-mile natural gas pipeline and J-W Gas owned approximately 200 miles of natural gas gathering lines in southeast Kansas. These assets were subsequently transferred to Quest Cherokee as part of the restructuring of the Company's operations in anticipation of the Devon asset acquisition. Also effective June 1, 2003, QOG closed on a Purchase and Sale Agreement with James R. Perkins Energy, L.L.C. and E. Wayne Willhite Energy, L.L.C. and J-W Gas pursuant to the terms of which QOG acquired 53 natural gas and oil leases and related assets in Chautauqua, Elk, and Montgomery Counties, Kansas for $2,000,000. Both of these June 6, 2003 transactions were completed effective as of June 1, 2003. The cash portion of the purchase price was funded with borrowings under the Company's two credit facilities with Wells Fargo Bank Texas, N.A. and Wells Fargo Energy Capital, Inc. These assets were also subsequently transferred to Quest Cherokee as part of the restructuring of the Company's operations in anticipation of the Devon asset acquisition. In accordance with the terms of the asset purchase agreement, the purchase price, current assets and certain assumed liabilities were allocated as follows: F-13 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Current assets $ 604,000 Property and equipment 1,177,000 Natural gas and oil properties 2,040,000 Current liabilities (669,000) Long-term debt (112,000) ------------- Net assets acquired $ 3,040,000 ============= Pro Forma Summary Data (unaudited) The following pro forma summary data for the transition period ended December 31, 2004 and the fiscal year ending May 31, 2004 presents the consolidated results of operations as if the Devon asset acquisition made on December 22, 2003 and the Perkins/Willhite acquisition made on June 1, 2003 had occurred on June 1, 2003. These pro forma results have been prepared for comparative purposes only and do not purport to be indicative of what would have occurred had the acquisitions been made at June 1, 2003 or of results that may occur in the future. Seven Months Ended Year Ended December 31, May 31, ------------ ------------ 2004 2004 ------------ ------------ Proforma revenue $ 26,156,000 $ 45,241,000 Proforma net income (loss) $ (4,863,000) $ 2,311,000 Proforma net income (loss) per share $ (.34) $ .17 3. Long-Term Debt Long-term debt consists of the following:

December 31, 2005 December 31, 2004 ----------------- ----------------- Senior credit facilities $ 100,000,000 $ 134,700,000 Notes payable to banks and finance companies, secured by equipment and vehicles, due in installments through October 2013 with interest ranging from 5.5% to 11.5% per annum 988,000 1,713,000 Convertible debentures - unsecured; interest accrues at 8% per annum -- 50,000 ----------------- ----------------- Total long-term debt 100,988,000 136,463,000 Less - current maturities 407,000 1,804,000 ----------------- ----------------- Total long term debt, net of current maturities $ 100,581,000 $ 134,659,000 ================= ================= Subordinated debt (inclusive of accrued interest) $ -- $ 59,325,000 ================= =================

The aggregate scheduled maturities of notes payable and long-term debt for the five years ending December 31, 2010 and thereafter were as follows as of December 31, 2005: 2006 $ 407,000 2007 338,000 2008 110,000 2009 28,000 2010 7,000 Thereafter 100,098,000 ------------ $100,988,000 ============ F-14 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS New Credit Facilities - Guggenheim Simultaneously with the closing of the private placement of common stock on November 14, 2005, the Company and its subsidiary, Quest Cherokee, LLC entered into two new credit agreements totaling $200 million. The new credit agreements consist of a $100 million Senior Credit Agreement between the Company and Quest Cherokee, Guggenheim Corporate Funding, LLC ("Guggenheim"), as administrative agent and syndication agent, and the lenders party thereto and a $100 million Second Lien Term Loan Agreement between the Company, Quest Cherokee, Guggenheim, as Administrative Agent, and the lenders party thereto. The Senior Credit Agreement consists of a five year $50 million revolving credit facility and a five year $50 million first lien term loan. The first lien term loan was fully drawn as of February 14, 2006. The Second Lien Term Loan Agreement consists of a six year $100 million second lien term loan that was fully funded at the closing. Availability under the revolving credit facility is tied to a borrowing base that will be redetermined by the lenders every six months taking into account the value of the Company's reserves and such other information (including, without limitation, the status of title information with respect to the Company's natural gas and oil properties and the existence of any other indebtedness) as the administrative agent deems appropriate and consistent with its normal oil and gas lending criteria as it exists at the particular time. The unanimous consent of the lenders is required to increase the borrowing base and the consent of 66 2/3% of the lenders is required to decrease or maintain the borrowing base. In addition, the Company or the lenders may each request a special redetermination of the borrowing base once every 12 months. The outstanding principal balance of the first lien term loan and any outstanding letters of credit will be reserved against the borrowing base in determining availability under the revolving credit facility. The initial borrowing base under the revolving credit facility is $100 million. The Company will pay a commitment fee equal to 0.75% on the difference between $50 million and the outstanding balance of borrowings and letters of credit under the revolving credit facility. On the first lien term loan, the Company will pay a commitment fee equal to 0.75% on the difference between $50 million and the outstanding balance of borrowings under the first lien term loan. Interest will accrue on the revolving credit facility at either LIBOR plus 1.75% or the base rate plus 0.75%, at our option. Interest will accrue on the first lien term loan at either LIBOR plus 3.25% or the base rate plus 2.50%, at our option. Interest will accrue on the second lien term loan at LIBOR plus 6.00%. The second lien term loan may not be repaid prior to November 14, 2006. Thereafter, if the Company prepays second lien term loan, the Company will pay a 3% premium in year 2 following the closing, a 2% premium in year 3 following the closing, and a 1% premium in year 4 following the closing. Thereafter, the Company may repay the second lien term loan at any time without any premium or prepayment penalty. The revolving credit facility and the first lien term loan may be prepaid, without any premium or penalty, at any time. Each of the Company's subsidiaries has guaranteed all obligations under these credit agreements. The revolving credit facility and the first lien term loan are secured by a first priority lien on substantially all of the assets of the Company and its subsidiaries. The second lien term loan is secured by a second priority lien on substantially all of the assets of the Company and its subsidiaries. The credit agreements also secure on a pari passu basis hedging agreements entered into with lenders, their affiliates and other approved counterparties if the hedging agreements state that they are secured by the credit facilities. Approved counterparties are generally entities that have an A rating from Standard & Poor's or an A2 rating from Moody's. In connection with the closing of the credit agreements, the Company's existing natural gas swap and collar hedging agreements were amended to provide that they are secured on a pari passu basis with the revolving credit facility. F-15 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The Company and Quest Cherokee are required to make certain representations and warranties that are customary for credit agreements of this type. The credit agreements also contain affirmative and negative covenants that are customary for credit agreements of this type. The covenants in the credit agreements include, without limitation, performance of obligations; delivery of financial statements, other financial information, production reports and information regarding swap agreements; delivery of notices of default and other material developments; operation of properties in accordance with prudent industry practice and in compliance with applicable laws; maintenance of satisfactory insurance; compliance with laws; inspection of books and properties; continued perfection of security interests in existing and subsequently acquired collateral; further assurances; payment of taxes and other preferred claims; compliance with environmental laws and delivery of notices related thereto; delivery of reserve reports; limitations on dividends and other distributions on, and redemptions and repurchases of, capital stock and other equity interests; limitations on liens; limitations on loans and investments; limitations on debt, guarantees and hedging arrangements; limitations on mergers, acquisitions and asset sales; limitations on transactions with affiliates; limitations on dissolution; limitations on changes in business conducted by us and our subsidiaries; limitations on the right to enter into hedging arrangements; and prohibitions against agreements limiting any subsidiaries' right to pay dividends or make distributions; as well as certain financial covenants. The financial covenants applicable to the credit agreements require that: o the Company's minimum net sales volumes will not be less than: 1,890 mmcf for the quarter ended March 31, 2006; 2,380 mmcf for the quarter ended June 30, 2006; 3,080 mmcf for the quarter ended September 30, 2006; and 3,430 mmcf for the quarter ended December 31, 2006. o the Company's ratio of total net debt to EBITDA for each quarter ending on the dates set forth below will not be more than: 4.5 to 1.0 for the quarter ended March 31, 2007; 4.25 to 1.0 for the quarter ended June 30, 2007; 4.00 to 1.0 for the quarter ended September 30, 2007; 3.75 to 1.0 for the quarter ended December 31, 2007; 3.50 to 1.0 for the quarter ended March 31, 2008; 3.25 to 1.0 for the quarter ended June 30, 2008; and 3.00 to 1.0 for any quarter ended on or after September 31, 2008. o for the Senior Credit Agreement, the Company is required to maintain a ratio of PV-10 value for all of its proved reserves to indebtedness under the Senior Credit Agreement (excluding obligations under hedging agreements secured by the Senior Credit Agreement) of not less than 2.0 to 1.0. o for the Second Lien Term Loan Agreement, the Company's ratio of PV-10 value for all of its proved reserves to total net debt must not be less than 1.5 to 1. Under both credit agreements "PV-10 value" is generally defined as the future cash flows from the Company's proved reserves (based on the NYMEX three-year pricing strip and taking into account the effects of its hedge agreements) discounted at 10%. EBITDA is generally defined in both of the credit agreements as consolidated net income plus interest, income taxes, depreciation, depletion, amortization and other non-cash charges (including unrealized losses on hedging agreements), plus costs and expenses directly incurred in connection with the credit agreements, the private equity transaction and the buy-out of ArcLight's investment in Quest Cherokee and any write-off of prior debt issue costs, minus all non-cash income (including unrealized gains on hedging agreements). The EBITDA for each quarter will be multiplied by four in calculating the above ratios. Total net debt is generally defined as funded debt, less cash and cash equivalents, reimbursement obligations under letters of credit and certain surety bonds. Events of default under the credit agreements are customary for transactions of this type and include, without limitation, non-payment of principal when due, non-payment of interest, fees and other amounts for a period of three business days after the due date, representations and warranties not being correct in any material respect when made, non-performance of covenants after any applicable grace period, certain acts of bankruptcy or insolvency, cross defaults to other material indebtedness and change in control. Under both credit agreements, a change in control will generally be deemed to have occurred if any person or group acquires more than 35% of the Company's outstanding common stock or a majority of the Company's directors have either not been nominated or appointed by its board of directors. If an event of default has occurred and is continuing, the interest rate on the credit agreements will increase by 2.5%. F-16 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 was paid in full on November 14, 2005 (see New Credit Facilities-Guggenheim). The UBS Credit Agreement originally provided for a $120 million six year term loan that was fully funded at closing (the "UBS Term Loan") and a $20 million five year revolving credit facility that could be used to issue letters of credit and fund future working capital needs and general corporate purposes (the "UBS Revolving Loan"). As of December 31, 2004, Quest Cherokee had approximately $15 million of loans and approximately $5 million in letters of credit issued under the UBS Revolving Loan. Letters of credit issued under the UBS Revolving Loan reduced the amount that could be borrowed thereunder. The UBS Credit Agreement also contained a $15 million "synthetic" letter of credit facility with a maturity date in December 2008, which provided credit support for Quest Cherokee's natural gas hedging program. A portion of the proceeds from the UBS Term Loan were used to repay the Company's prior credit facilities. After the repayment of the prior credit facilities and payment of fees and other obligations related to this transaction, Quest Cherokee had approximately $9 million of cash at closing from the proceeds of the UBS Term Loan and $15 million of availability under the UBS Revolving Loan. Interest initially accrued under both the UBS Term Loan and the UBS Revolving Loan, at Quest Cherokee's option, at either (i) a rate equal to the greater of the corporate "base rate" established by UBS AG, Stamford Branch, or the federal funds effective rate plus 0.50% (the "Alternative Base Rate"), plus the applicable margin (3.50% for revolving loans and 4.50% for term loans), or (ii) LIBOR, as adjusted to reflect the maximum rate at which any reserves are required to be maintained against Eurodollar liabilities (the "Adjusted LIBOR Rate"), plus the applicable margin (3.75% for revolving loans and 4.75% for term loans). In connection with the amendment to the UBS Credit Agreement in February 2005 discussed below, the applicable margin on borrowings under the UBS Credit Agreement was increased by 1% until Quest Cherokee's total leverage ratio is less than 4.0 to 1.0. In the event of a default under either the UBS Term Loan or the UBS Revolving Loan, interest accrued at the applicable rate, plus an additional 2% per annum. Quest Cherokee paid an annual fee on the synthetic letter of credit facility equal to 4.75% of the amount of the facility. The UBS Credit Agreement contained affirmative and negative covenants that are typical for credit agreements of this type. The covenants in the UBS Credit Agreement included provisions requiring the maintenance of and furnishing of financial and other information; the maintenance of insurance, the payment of taxes and compliance with the law; the maintenance of collateral and security interests and the creation of additional collateral and security interests; the maintenance of certain financial ratios; restrictions on the incurrence of additional debt or the issuance of convertible or redeemable equity securities; restrictions on the granting of liens; restrictions on making acquisitions and other investments; restrictions on disposing of assets and merging or consolidating with a third party where Quest Cherokee was not the surviving entity; restrictions on the payment of dividends and the repayment of other indebtedness; restrictions on transactions with affiliates that are not on an arms length basis; and restrictions on changing the nature of Quest Cherokee's business. Subordinated Promissory Notes In connection with the Devon asset acquisition, the Company issued a $51 million junior subordinated promissory note from ArcLight (the "Original Note") pursuant to the terms of a note purchase agreement. The Original Note was purchased at par. The Original Note bore interest at 15% per annum and was subordinate and junior in right of payment to the prior payment in full of superior debts. Interest was payable quarterly in arrears; provided, however, that if Quest Cherokee was not permitted to pay cash interest on the Original Note under the terms of its senior debt facilities, then interest was to be paid in the form of additional subordinated notes. Quest Cherokee paid a commitment fee of $1,020,000 to obtain this loan. This loan fee was capitalized as part of the acquisition of assets from Devon. F-17 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS In connection with the purchase of the Original Note, the original limited liability company agreement for Quest Cherokee was amended and restated to, among other things, provide for Class A units and Class B units of membership interest, and ArcLight acquired all of the Class A units of Quest Cherokee in exchange for $100. The existing membership interests in Quest Cherokee owned by the Company's subsidiaries were converted into all of the Class B units. On February 11, 2005, Quest Cherokee and ArcLight amended and restated the note purchase agreement to provide for the issuance to ArcLight of up to $15 million of additional 15% junior subordinated promissory notes (the "Additional Notes" and together with the Original Notes, the "Subordinated Notes") pursuant to the terms of an amended and restated note purchase agreement. Also on February 11, 2005, Quest Cherokee issued $5 million of Additional Notes to ArcLight (the "Second Issuance"). The February 11, 2005 amended and restated note purchase agreement also provided for Quest Cherokee to issue to ArcLight Additional Notes in the principal amount of $7 million (the "Third Issuance") upon Quest Cherokee obtaining a waiver from the lenders under the UBS Credit Agreement with respect to Quest Cherokee's default under the credit agreement and an amendment to the credit agreement to permit the issuance of Additional Notes to ArcLight. On February 22, 2005, Quest Cherokee obtained the necessary waivers and amendments to the UBS Credit Agreement and closed on the Third Issuance. At the same time, Quest Cherokee borrowed $5 million of additional term loans under the UBS Credit Agreement. The Subordinated Promissory Notes were retired on November 14, 2005. Other Long-Term Indebtedness The proceeds of the recapitalization were also used to payoff $373,000 of outstanding indebtedness of Quest Energy Service under a $440,000 revolving credit note. The note had a maturity date of February 19, 2008, bore interest at an annual rate of 7% per annum, required a monthly payment based upon a 60 month amortization and was secured by equipment and rolling stock. Also, $988,000 of notes payable to banks and finance companies were outstanding at December 31, 2005 and are secured by equipment and vehicles, with payments due in monthly installments through October 2013 with interest ranging from 5.5% to 11.5% per annum. Wells Fargo Energy Capital Warrant In connection with entering into a credit agreement with Wells Fargo Energy Capital on November 7, 2002, we issued a warrant to Wells Fargo Energy Capital for 640,000 shares of common stock with an exercise price of $0.0025 per share. During 2005, Wells Fargo Energy Capital exercised the warrant on a "net exercise" basis and we issued 639,840 shares of our common stock to Wells Fargo Energy Capital. Convertible Debentures During the year ended May 31, 2004, the Company converted $180,000 of debentures into 28,404 shares of common stock. No debentures were converted during the seven-month transition period ended December 31, 2004. During 2005, the last convertible debenture matured without being converted and no debentures were outstanding at December 31, 2005. The debenture retired in 2005 had an interest rate of 8% and required interest to be paid quarterly. The debenture had a conversion feature that allowed the debenture holder to convert to common stock after one year from the date of the debenture but prior to the maturity date. The conversion price was 75% of the daily average trading price of the Company's common stock for the 30 days prior to the conversion with the conversion price limited to a maximum of $7.50 per share and a minimum of $3.125 per share. F-18 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 4. Stockholders' Equity Common Stock Transactions The Company has authorized 380,000,000 shares of common stock and 50,000,000 shares of preferred stock. As of December 31, 2005, there were 22,072,383 shares of common stock outstanding and no shares of preferred stock outstanding. The following transactions were recorded in the Company's financial statements during the year ended December 31, 2005. 1) Issued 639,840 shares of common stock upon the exercise of the Wells Fargo warrant (no cash was received by the Company in connection with this exercise). 2) Issued 3,200 shares of common stock to compensate director for audit committee service valued at $19,000. 3) Issued 5,460 shares of common stock to one individual for services rendered valued at $45,000. 4) Issued 400,000 shares of common stock for $2.0 million in cash. 5) Issued 15,258,144 shares of common stock in the November 14, 2005 private placement for gross proceeds of $198.4 million. 6) Issued 16,000 shares of common stock upon the conversion of 10,000 shares of Series A preferred stock. 7) Issued 49,842 shares of common stock valued at $495,000 as an employer contribution to the Company's 401(k) plan. The following transactions were recorded in the Company's financial statements during the seven-month transition period ended December 31, 2004. 1) Issued 6,800 shares of common stock to compensate director for audit committee service valued at $62,000. 2) Issued 48,000 shares of common stock for $480,000 in cash. The following transactions were recorded in the Company's financial statements during the fiscal year ended May 31, 2004. 1) Issued 200,000 shares of common stock in connection with the Perkins/Willhite acquisition. 2) Issued 28,404 shares of common stock upon the conversion of $180,000 in convertible debentures. 3) Issued 13,260 shares of common stock to four individuals for services rendered valued at $94,000. 4) Issued 58,823 shares of common stock for $500,000 in cash. 5) Issued 32,355 shares of common stock valued at $121,000 as an employer contribution to the Company's 401(k) plan. Stock Awards. The Company granted shares of common stock to certain employees in October 2005. The shares are subject to pro rata vesting which ranges from 0 to 2.5 years. During this vesting period, the fair value of the stock awards granted is recognized pro rata as compensation expense. To the extent the compensation expense relates to employees directly involved in acquisition, exploration and development activities, such amounts are capitalized to oil and gas properties. Amounts not capitalized to oil and gas properties are recognized in general and administrative expenses. At December 31, 2005, the Company recognized $427,000 of total compensation expense related to stock awards. Of this amount, $352,000 was reflected in general and administrative expenses as compensation expense with the remaining $75,000 capitalized to oil and gas properties. Stock Options. On October 14, 2005, the Company granted stock options in the amount of 250,000 shares of its common stock to its five non-employee directors. Each non-employee director received a grant of 50,000 shares of common stock, of which 10,000 shares were immediately vested and the remaining 40,000 shares will vest 10,000 shares per year over the next four years, provided that the director is still serving on the Board of Directors at the time of the vesting of the remaining stock options. The exercise price of the grants equaled the closing stock price on October 14, 2005. F-19 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS A summary of the status of the Company's stock options as of December 31, 2005, and changes during the year then ended is presented below. Year Ended December 31, 2005 ----------------------------------- Weighted-Average Shares Exercise Price ------------- ---------------- Outstanding at beginning of year -- $ -- Granted 250,000 10.00 Exercised -- -- Canceled -- -- ------------- ---------------- Outstanding at end of year 250,000 $ 10.00 ============= ================ Exercisable at end of year 50,000 $ 10.00 ============= ================ Weighted-average fair value of options granted during year $ 4.58 ============= Outstanding options to acquire 250,000 shares of common stock at December 31, 2005 had an exercise price of $10.00, a weighted-average exercise price of $10.00, and had a weighted-average remaining contractual life of 9.9 years. Series A Preferred Stock The Company has authorized 50,000,000 preferred shares of stock. During the year ended May 31, 2000, the Company issued a total of 10,000 shares of Series A Preferred Stock to two individuals for a total of $100,000. Each share of Series A Preferred Stock is convertible into 1.6 shares of common stock. The Series A Preferred Stock has an annual cash dividend of $1.00 per share. During December 2005, all 10,000 shares of Series A Preferred Stock were converted to 16,000 shares of common stock. Other Comprehensive Income The components of other comprehensive loss and related tax effects for the year ended December 31, 2005 and the seven-month transition period ended December 31, 2004 are shown as follows:

Gross Tax Effect Net of Tax ----------------- ------------------ ------------------ Year Ended December 31, 2005: Change in fixed-price contract and other derivative fair value $ (63,924,000) $ -- $ (63,924,000) Reclassification adjustments - contract settlements 27,896,000 -- 27,896,000 ----------------- ------------------ ------------------ $ (36,028,000) $ -- $ (36,028,000) ================= ================== ================== Seven Months Ended December 31, 2004: Change in fixed-price contract and other derivative fair value $ (5,258,000) $ -- $ (5,258,000) Reclassification adjustments - contract settlements 4,744,000 -- 4,744,000 ----------------- ------------------ ------------------ $ (514,000) $ -- $ (514,000) ================= ================== ==================

F-20 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 5. Income Taxes The components of income tax expense for the year ended December 31, 2005, for the seven-month transition period ended December 31, 2004 and for the fiscal year ended May 31, 2004 are as follows: Year Ended Seven Months Ended Year Ended December 31, 2005 December 31, 2004 May 31, 2004 ---------------- ------------------ -------------- Current tax expense: Federal $ -- $ -- $ -- State -- -- -- ---------------- ------------------ -------------- -- -- -- ---------------- ------------------ -------------- Deferred tax expense: Federal -- -- (208,000) State -- -- (37,000) ---------------- ------------------ -------------- -- -- (245,000) ---------------- ------------------ -------------- $ -- $ -- $ (245,000) ================ ================== ============== A reconciliation of income tax at the statutory rate to the Company's effective rate for the year ended December 31, 2005, for the seven-month transition period ended December 31, 2004 and for the fiscal year ended May 31, 2004 is as follows:

Year Ended Seven Months Ended Year Ended December 31, 2005 December 31, 2004 May 31, 2004 ----------------- ------------------ ------------ Computation of deferred income tax expense (benefit) at statutory rate $ (11,093,000) $ (1,872,000) $ (245,000) Tax effect of other comprehensive loss (9,581,000) (4,290,000) -- Derivative losses not deductible 15,314,000 5,700,000 2,752,000 Book depreciation and depletion in excess of tax (3,302,000) (456,000) (2,686,000) Carryover depletion (170,000) (608,000) -- ----------------- ------------------ ------------ Tax Benefit (8,832,000) (1,526,000) (179,000) Less: Valuation allowance 8,832,000 1,526,000 179,000 ----------------- ------------------ ------------ $ -- $ -- $ -- ================= ================== ============

The following temporary differences gave rise to the net deferred tax liabilities at December 31, 2005 and 2004 and at May 31, 2004: F-21 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Year Ended Seven Months Ended Year Ended December 31, 2005 December 31, 2004 May 31, 2004 ----------------- ------------------ ------------ Deferred tax liabilities, non-current: Book basis in property and equipment in excess of tax basis, net of accumulated depreciation, depletion and amortization $ (12,405,000) $ (7,424,000) $ (2,686,000) ----------------- ------------------ ------------ Deferred tax assets, current: Hedging contracts expenses per books but deferred for income tax reporting purposes 23,766,000 8,452,000 2,752,000 Net operating loss carryforwards 16,849,000 8,961,000 4,715,000 Percentage depletion carryforwards 800,000 608,000 -- Derivative losses deferred for book purposes (13,871,000) (4,290,000) -- ----------------- ------------------ ------------ Deferred tax assets 27,544,000 13,731,000 7,467,000 ----------------- ------------------ ------------ Net deferred tax (liability) asset 15,139,000 6,307,000 4,781,000 Less: Valuation allowance (15,139,000) (6,307,000) (4,781,000) ----------------- ------------------ ------------ Total deferred tax (liability) asset $ -- $ -- $ -- ================= ================== ============

At December 31, 2005, the Company had federal income tax net operating loss (NOL) carryforwards of approximately $43,800,000. The NOL carryforwards expire from 2021 through 2025. The value of these carryforwards depends on the ability of the Company to generate taxable income. The ability of the Company to utilize NOL carryforwards to reduce future federal taxable income and federal income tax of the Company is subject to various limitations under the Internal Revenue Code of 1986, as amended. The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the issuance or exercise of rights to acquire stock, the purchase or sale of stock by 5% stockholders, as defined in the Treasury regulations, and the offering of stock by the Company during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of the Company. The Company completed a private placement of its common stock on November 14, 2005. In connection with this offering, 15,258,144 shares of common stock were issued. This issuance may constitute an "owner shift" as defined in the Regulations under 1.382-2T. This event will subject approximately $40,000,000 of NOL's to limitations under Section 382. The current annual limitation on NOL's incurred prior the owner shift is expected to be $8,000,000. NOL's incurred after November 14, 2005 will not be limited. 6. Related Party Transactions The corporate headquarters for the Company and its subsidiaries is located in Suite 300 at 9520 N. May Avenue in Oklahoma City, OK 73120. Prior to July 2004, the offices were located in Suite 200 at 5901 N. Western in Oklahoma City, Oklahoma 73118 and the space was rented from Mr. Cash, who is the Chairman, Chief Executive Officer and a director of the Company for the amount of $3,050 monthly. The Company also owns a building located at 211 West 14th Street in Chanute, Kansas 66720 that is used as an administrative office. Prior to November 2004, an administrative office for the Company and its subsidiaries was located at 701 East Main Street in Benedict, Kansas 66714. It was leased from Crown Properties, LC for $400 per month. Crown Properties, LC is owned by Marsha K. Lamb who is the wife of Douglas Lamb, who was the president and a director of the Company until October 7, 2005. F-22 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 7. Supplemental Cash Flow Information

Year Ended Seven Months Ended Year Ended December 31, 2005 December 31, 2004 May 31, 2004 ---------------------- ----------------------- ------------------ Cash paid for interest $ 10,315,000 $ 4,760,000 $ 3,354,000 Cash paid for income taxes $ -- $ -- $ --

Supplementary Information: During the year ended December 31, 2005, non-cash investing and financing activities were as follows: 1) Issued 3,200 shares of common stock to compensate director for audit committee service valued at $19,000. 2) Issued stock for services rendered valued at $45,000. 3) Issued stock to the Company's 401(k) plan valued at $495,000 as an employer contribution. 4) Recorded non-cash additions to net natural gas and oil properties of $211,000 pursuant to SFAS 143. During the seven-month transition period ended December 31, 2004, non-cash investing and financing activities are as follows: 1) Issued 6,800 common stock shares to compensate director for audit committee service valued at $62,000. 2) Recorded non-cash additions to net natural gas and oil properties of $126,000 pursuant to SFAS 143. During the fiscal year ended May 31, 2004, non-cash investing and financing activities are as follows: 1) Issued stock upon conversion of $180,000 of convertible debentures. 2) Issued stock to acquire assets valued at $1,200,000. 3) Issued stock for services rendered valued at $94,000. 4) Issued stock to the Company's 401(k) plan valued at $121,000 as an employer contribution. 5) Recorded non-cash additions to net natural gas and oil properties of $624,000 pursuant to SFAS 143. 8. Contingencies The Company and STP Cherokee, Inc. ("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. The Company intends to defend vigorously against these claims. Quest Cherokee was named as a defendant in a lawsuit (Case No. 04-C-100-PA) filed by plaintiff Central Natural Resources, Inc. on September 1, 2004 in the District Court of Labette County, Kansas. Central Natural Resources owns the coal underlying numerous tracts of land in Labette County, Kansas. Quest Cherokee has obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying some of that land and has drilled wells that produce coal bed methane gas on that land. Plaintiff alleges that it is entitled to the coal bed methane gas produced and revenues from these leases and that Quest Cherokee is a trespasser. Plaintiff is seeking quiet title and an equitable accounting for the revenues from the coal bed methane gas produced. The Company contends it has valid leases with the owners of the coal bed methane gas rights. The issue is whether the coal bed methane gas is owned by the owner of the coal rights or by the owners of the gas rights. Quest Cherokee has asserted third party claims against the persons who entered into the gas leases with Quest Cherokee for breach of the warranty of title contained in their leases in the event that the court finds that plaintiff owns the coal bed methane gas. All issues relating to ownership of the coal bed methane gas and damages have been bifurcated. Cross motions for summary judgment on the ownership of the coal bed methane have been filed by Quest Cherokee and the plaintiff, but have not been decided by the court. The Company intends to defend vigorously against these claims. F-23 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Quest Cherokee was named as a defendant in a lawsuit (Case No. CJ-06-07) filed by plaintiff Central Natural Resources, Inc. on January 17, 2006, in the District Court of Craig County, Oklahoma. Central Natural Resources owns the coal underlying approximately 2,250 acres of land in Craig County, Oklahoma. Quest Cherokee has obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying those lands, and has drilled and completed 20 wells that produce coal bed methane gas on those lands. Plaintiff alleges that it is entitled to the coal bed methane gas produced and revenues from these leases and that Quest Cherokee is a trespasser. Plaintiff seeks to quiet its alleged title to the coal bed methane and an accounting of the revenues from the coal bed methane gas produced by Quest Cherokee. The Company contends it has valid leases from the owners of the coal bed methane gas rights. The issue is whether the coal bed methane gas is owned by the owner of the coal rights or by the owners of the gas rights. Quest Cherokee has answered the petition and discovery is ongoing. The Company intends to defend vigorously against these claims. Quest Cherokee, STP and Bluestem Pipeline, LLC ("Bluestem") were named as defendants in a lawsuit (Case No. CJ-05-23) filed by plaintiff Davis Operating Company on February 9, 2005 in the District Court of Craig County, Oklahoma. Plaintiff is alleging a breach of contract. Plaintiff is seeking $373,704 as a result of the breach of the contract. The case is in the early stages of discovery. The Company believes that the contract in question expired pursuant to its own terms. The Company intends to defend vigorously against these claims. The Company, from time to time, may be subject to legal proceedings and claims that arise in the ordinary course of its business. Although no assurance can be given, management believes, based on its experiences to date, that the ultimate resolution of such items will not have a material adverse impact on the Company's business, financial position or results of operations. Like other natural gas and oil producers and marketers, the Company's operations are subject to extensive and rapidly changing federal and state environmental regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. Therefore it is extremely difficult to reasonably quantify future environmental related expenditures. 9. 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 year ended December 31, 2005, dilutive shares do not include stock awards of 1,000 shares of common stock because the effects were antidilutive. o For the year ended December 31, 2005, dilutive shares do not include options to purchase 12,000 shares of common stock because the effects were antidilutive. o For the seven-month transition period ended December 31, 2004 and for the fiscal year ended May 31, 2004, dilutive shares do not include outstanding warrants to purchase 640,000 shares of common stock at an exercise price of $0.0025 because the effects were antidilutive. o For the seven-month transition period ended December 31, 2004 and for the fiscal year ended May 31, 2004, dilutive shares do not include the assumed conversion of the outstanding 10% preferred stock (convertible into 16,000 common shares) because the effects were antidilutive. o For the seven-month transition period ended December 31, 2004 and for the fiscal year ended May 31, 2004, dilutive shares do not include the assumed conversion of convertible debt (convertible into 4,000 common shares in the transition period ended December 31, 2004 and 8,000 common shares in fiscal 2004) because the effects were antidilutive. F-24 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following reconciles the components of the EPS computation:

Income Shares Per Share (Numerator) (Denominator) Amount ------------ ------------- ---------- For the year ended December 31, 2005: Net loss $(31,941,000) Preferred stock dividends (10,000) ------------ Basic EPS income available to common shareholders $(31,951,000) 8,390,092 $ (3.81) ---------- Effect of dilutive securities: None -- -- ------------ ------------- ---------- Diluted EPS income available to common shareholders $(31,951,000) 8,390,092 $ (3.81) ============ ============= ========== For the seven months ended December 31, 2004: Net loss $ (4,863,000) Preferred stock dividends (6,000) ------------ Basic EPS income available to common shareholders $ (4,869,000) 5,661,352 $ (0.86) ---------- Effect of dilutive securities: None -- -- ------------ ------------- ---------- Diluted EPS income available to common shareholders $ (4,869,000) 5,661,352 $ (0.86) ============ ============= ========== For the fiscal year ended May 31, 2004: Income (loss) before cumulative effect of accounting change, net of tax $ (365,000) Preferred stock dividends (10,000) ------------ Basic EPS income (loss) available to common shareholders before cumulative effect of accounting change, net of tax $ (375,000) 5,588,352 $ (0.07) ---------- Effect of dilutive securities: None -- -- ------------ ------------- ---------- Diluted EPS income available to common shareholders $ (375,000) 5,588,352 $ (0.07) ============ ============= ==========

10. Asset Retirement Obligation As described in Note 1, effective June 1, 2003, the Company adopted SFAS 143, Accounting for Asset Retirement Obligations. Upon adoption of SFAS 143, the Company recorded a cumulative effect to net income of ($28,000) net of tax, or ($0.00) 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 year ended December 31, 2005 and for the seven-month transition period ended December 31, 2004:

Year Ended Seven Months Ended December 31, 2005 December 31, 2004 -------------------- --------------------- Asset retirement obligation beginning balance $ 871,000 $ 717,000 Liabilities incurred 217,000 129,000 Liabilities settled (6,000) (3,000) Accretion expense 68,000 28,000 Revisions in estimated cash flows -- -- -------------------- --------------------- Asset retirement obligation ending balance $ 1,150,000 $ 871,000 ==================== =====================

F-25 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 11. Company Benefit Plan The Company has adopted a 401(K) profit sharing plan with an effective date of June 1, 2001. The plan covers all eligible employees. During the year ended December 31, 2005, employees contributed $298,937 to the plan and the Company contributed 49,842 shares of its common stock to the plan. The Company valued the 2005 common stock contribution at $495,000, of which the intrinsic value of $266,000 was included as an expense in the statement of operations. During the seven-month transition period ended December 31, 2004 and the fiscal year ended May 31, 2004, the employee contributions to the plan were $115,231 and $97,631, respectively, and the Company contributed 32,355 shares of its common stock to the plan. The Company valued the 2004 common stock contribution at $121,000 and included this amount as an expense in the statement of operations. There is a graduated vesting schedule with the employee becoming fully vested after six years of service. 12. Operating Leases The Company leases natural gas compressors. Terms of these leases call for a minimum obligation of six months and are month to month thereafter. As of December 31, 2005, December 31, 2004, and May 31, 2004, the Company's monthly obligation under these leases totaled $490,000, $408,000 and $284,000, respectively. Additionally, the minimum annual rental commitments as of December 31, 2005 under non-cancellable office space leases are as follows: 2006 - $117,720; 2007 - $123,443; 2008 - $127,530 and 2009 - $53,138. 13. Major Purchasers The Company's natural gas and oil production is sold under contracts with various purchasers. Natural gas sales to one purchaser approximated 95% of total natural gas and oil revenues for the year ended December 31, 2005 and for the seven-month transition period ended December 31, 2004 and 90% for the fiscal year ended May 31, 2004. 14. 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 December 31, 2005 and 2004 and the methods and assumptions used to estimate their fair value:

December 31, 2005 December 31, 2004 -------------------------------- -------------------------------- Carrying Amount Fair Value Carrying Amount Fair Value --------------- ------------- --------------- ------------- Derivative assets: Interest rate swaps and caps $ 188,000 $ 188,000 $ 523,000 $ 523,000 Derivative liabilities: Fixed-price natural gas swaps $ (31,185,000) $ (31,185,000) $ (17,675,000) $ (17,675,000) Fixed-price natural gas collars $ (30,733,000) $ (30,733,000) $ (4,802,000) $ (4,802,000) Bank debt $ (100,000,000) $(100,000,000) $ (134,700,000) $(134,700,000) Subordinated debt (inclusive of accrued interest) $ -- $ -- $ (59,325,000) $ (59,325,000) Other financing agreements $ (988,000) $ (988,000) $ (1,763,000) $ (1,763,000)

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 December 31, 2005 and 2004 was based upon estimates determined by the Company's 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. See Note 15--Derivatives. F-26 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Derivative assets and liabilities reflected as current in the December 31, 2005 and 2004 balance sheets represent the estimated fair value of fixed-price contract and interest rate 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, creating the appearance of a working capital deficit from these contracts. 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 and interest rates 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. 15. Derivatives 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 year ended December 31, 2005, the seven months ended December 31, 2004 and the fiscal year ended May 31, 2004, fixed-price contracts hedged approximately 89.0%, 85.0% and 83.0%, respectively, of the Company's natural gas production. As of December 31, 2005, fixed-price contracts are in place to hedge 14.0 Bcf of estimated future natural gas production. Of this total volume, 7.4 Bcf are hedged for 2006 and 6.6 Bcf thereafter. For energy swap contracts, the Company receives a fixed price for the respective commodity and pays a floating market price, as defined in each contract (generally NYMEX futures prices or a regional spot market index), to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. Natural gas collars contain a fixed floor price (put) and ceiling price (call). If the market price of natural gas exceeds the call strike price or falls below the put strike price, then the Company receives the fixed price and pays the market price. If the market price of natural gas is between the call and the put strike price, then no payments are due from either party. The following table summarizes the estimated volumes, fixed prices, fixed-price sales and fair value attributable to the fixed-price contracts as of December 31, 2005. See "--Market Risk." F-27 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ending December 31, -------------------------------------------- 2006 2007 2008 Total ------------ ------------ ------------ ------------ (dollars in thousands, except price data) Natural Gas Swaps: Contract vols (MMBtu) 5,614,000 -- -- 5,614,000 Weighted-avg fixed price per MMBtu (1) $ 4.49 -- -- $ 4.49 Fixed-price sales $ 25,203 -- -- $ 25,203 Fair value, net $ (31,185) -- -- $ (31,185) Natural Gas Collars: Contract vols (MMBtu): Floor 1,825,000 3,650,000 2,928,000 8,403,000 Ceiling 1,825,000 3,650,000 2,928,000 8,403,000 Weighted-avg fixed price per MMBtu (1): Floor $ 5.30 $ 4.83 $ 4.50 $ 4.82 Ceiling $ 6.35 $ 5.83 $ 5.52 $ 5.84 Fixed-price sales (2) $ 11,589 $ 21,279 $ 16,163 $ 49,031 Fair value, net $ (7,010) $ (14,420) $ (9,303) $ (30,733) Total Natural Gas Contracts: Contract vols (MMBtu) 7,439,000 3,650,000 2,928,000 14,017,000 Weighted-avg fixed price per MMBtu (1) $ 4.95 $ 5.83 $ 5.52 $ 5.30 Fixed-price sales (2) $ 36,792 $ 21,279 $ 16,163 $ 74,234 Fair value, net $ (38,195) $ (14,420) $ (9,303) $ (61,918)

(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 Note 14--Financial Instruments. All fixed-price contracts have been approved by the Company's board of directors. 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 year ended December 31, 2005, the seven-month transition period ended December 31, 2004 and for the fiscal year ended May 31, 2004, oil and gas sales included $27.9 million, $4.7 million and $649,000, respectively, of net 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 year ended December 31, 2005, the seven months ended December 31, 2004 and for the year ended May 31, 2004, other revenue and expense included $0, $105,000 and $1.5 million, respectively, of net losses associated with realized losses under fixed-price contracts. For fixed-price contracts qualifying as cash flow hedges, changes in fair value for volumes not yet settled are shown as adjustments to other comprehensive income. For those contracts not qualifying as cash flow hedges, changes in fair value for volumes not yet settled are recognized in change in derivative fair value in the statement of operations. The fair value of all fixed-price contracts are recorded as assets or liabilities in the balance sheet. Based upon market prices at December 31, 2005, the estimated amount of unrealized losses for fixed-price contracts shown as adjustments to other comprehensive income that are expected to be reclassified into earnings as actual contract cash settlements are realized within the next 12 months is $38.2 million. F-28 QUEST RESOURCE CORPORATION AND SUBSIDIARIES 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 its credit facilities. All interest rate swaps and caps have been approved by the Company's board of directors. The differential between the fixed rate and the floating rate multiplied by the notional amount is the swap gain or loss. This gain or loss is included in interest expense in the period for which the interest rate exposure was hedged. For interest rate swaps and caps qualifying as cash flow hedges, changes in fair value of the derivative instruments are shown as adjustments to other comprehensive income. For those interest rate swaps and caps not qualifying as cash flow hedges, changes in fair value of the derivative instruments are recognized in change in derivative fair value in the statement of operations. All changes in fair value of the Company's interest rate swaps and caps are reported in results of operations rather than in other comprehensive income because the critical terms of the interest rate swaps and caps do not comply with certain requirements set forth in SFAS 133. The fair value of all interest rate swaps and caps are recorded as assets or liabilities in the balance sheet. Based upon market prices at December 31, 2005, the estimated amount of unrealized gains for interest rate caps shown as adjustments to change in derivative fair value in the statement of operations that are expected to be reclassified into earnings as actual contract cash settlements are realized within the next 12 months is $95,000. The following table summarizes the notional amounts, interest rates and the fair value attributable to the interest rate swaps and caps as of December 31, 2005.

Fair Value as Fixed Rate Floating of December Instrument Type Term Notional Amount(1) / Cap Rate Rate 31, 2005 ------------------- ----------------------- ------------------ ---------- ----------- ------------- $ 98,705,000 3-month Interest Rate Cap March 2006 - Sept. 2007 $ 70,174,600 5.000% LIBOR $ 188,000

------------ (1) Represents the maximum and minimum notional amounts that are hedged during the period. In connection with entering into the New Credit Facilities on November 14, 2005, the Company terminated an interest rate swap with a notional amount ranging from $53.9 million to $58.3 million in exchange for a termination payment of $379,000. The proceeds were booked as an increase to other revenue and expense in the fourth quarter of 2005. Change in Derivative Fair Value Change in derivative fair value in the statements of operations for the year ended December 31, 2005, the seven-month transition period ended December 31, 2004 and for the fiscal year ended May 31, 2004 is comprised of the following:

Year Ended Seven Months Ended Year Ended December 31, December 31, May 31, 2005 2004 2004 ------------ ------------------ ----------- Change in fair value of derivatives not qualifying as $ 879,000 $ (269,000) $(1,740,000) cash flow hedges Amortization of derivative fair value gains and losses recognized in earnings prior to actual cash settlements 103,000 565,000 888,000 Ineffective portion of derivatives qualifying as cash flow hedges (5,650,000) (1,783,000) (1,161,000) ------------ ------------------ ----------- $ (4,668,000) $ (1,487,000) $(2,013,000) ============ ================== ===========

F-29 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. Credit Risk Energy swaps and collars and interest rate swaps and caps provide for a net settlement due to or from the respective party as discussed previously. The counterparties to the derivative contracts are a financial institution and a major energy corporation. Should a counterparty default on a contract, there can be no assurance that we would be able to enter into a new contract with a third party on terms comparable to the original contract. The Company has not experienced non-performance by its counterparties. Cancellation or termination of a fixed-price contract would subject a greater portion of our natural gas production to market prices, which, in a low price environment, could have an adverse effect on its future operating results. Cancellation or termination of an interest rate swap or cap would subject a greater portion of the Company's long-term debt to market interest rates, which, in an inflationary environment, could have an adverse effect on its future net income. In addition, the associated carrying value of the derivative contract would be removed from the balance sheet. Market Risk The differential between the floating price paid under each energy swap contract and the price received at the wellhead for our production is termed "basis" and is the result of differences in location, quality, contract terms, timing and other variables. For instance, the Company's fixed price contracts are tied to commodity prices on the New York Mercantile Exchange ("NYMEX"), that is, the Company receives the fixed price amount stated in the contract and pays to its counterparty the current market price for gas as listed on the NYMEX. However, due to the geographic location of the Company's natural gas assets and the cost of transporting the natural gas to another market, the amount that it receives when it actually sells its natural gas is based on the Southern Star first of month index. Typically, the price for natural gas on the Southern Star first of month index is less than the price on the NYMEX due to the more limited demand for natural gas on the Southern Star first of month index. The difference between natural gas prices on the NYMEX and on the Southern Star first of month index is the basis differential. The effective price realizations that result from the fixed-price contracts are affected by movements in this basis differential. Basis movements can result from a number of variables, including regional supply and demand factors, changes in the portfolio of the Company's fixed-price contracts and the composition of its producing property base. Basis movements are generally considerably less than the price movements affecting the underlying commodity, but their effect can be significant. Recently, the basis differential has been increasingly volatile and has on occasion resulted in the Company receiving a net price for its natural gas that is significantly below the price stated in the fixed price contract. Changes in future gains and losses to be realized in natural gas and oil sales upon cash settlements of fixed-price contracts as a result of changes in market prices for natural gas are expected to be offset by changes in the price received for hedged natural gas production. 16. SFAS 69 SUPPLEMENTAL DISCLOSURES (UNAUDITED) Net Capitalized Costs The Company's aggregate capitalized costs related to natural gas and oil producing activities are summarized as follows: F-30 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, ----------------------------------- Natural gas and oil properties and related lease equipment: 2005 2004 --------------- ---------------- Proved $ 201,788,000 $ 154,427,000 Unproved 18,285,000 16,707,000 --------------- ---------------- 220,073,000 171,134,000 Accumulated depreciation and depletion (36,703,000) (16,069,000) --------------- ---------------- Net capitalized costs $ 183,370,000 $ 155,065,000 =============== ================

Unproved properties not subject to amortization consisted mainly of leasehold acquired through acquisitions. The Company will continue to evaluate its unproved properties; however, the timing of the ultimate evaluation and disposition of the properties has not been determined. Costs Incurred Costs incurred in natural gas and oil property acquisition, exploration and development activities that have been capitalized are summarized as follows:

Year Ended Seven Months Year Ended December 31, Ended December 31, May 31, 2005 2004 2004 -------------- --------------------- ----------------- Acquisition of properties proved and unproved $ -- $ -- $115,069,000 Development costs 29,283,000(1) 23,192,000 11,621,000 -------------- --------------------- ----------------- $29,283,000 $23,192,000 $126,690,000 ============== ===================== =================

(1) Development costs for the year ended December 31, 2005 do not include the buy out of the ArcLight units of $19.1 million. Results of Operations for Natural Gas and Oil Producing Activities The Company's results of operations from natural gas and oil producing activities are presented below for the year ended December 31, 2005, the transition period ended December 31, 2004 and the fiscal year ended May 31, 2004. The following table includes revenues and expenses associated directly with the Company's natural gas and oil producing activities. It does not include any interest costs and general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of the Company's natural gas and oil operations.

Year Ended Seven Months Year Ended December 31, Ended December 31, May 31, 2005 2004 2004 --------------- ------------------ ------------ Production revenues $44,565,000 $24,201,000 $28,147,000 Production costs (14,388,000) (5,389,000) (6,835,000) Depreciation and depletion (20,634,000) (7,187,000) (6,802,000) --------------- ------------------ ------------ 9,543,000 11,625,000 14,510,000 Imputed income tax provision (1) (3,817,000) (4,650,000) (5,804,000) --------------- ------------------ ------------ Results of operation for natural gas/oil producing activity $ 5,726,000 $ 6,975,000 $ 8,706,000 =============== ================== ============

(1) The imputed income tax provision is hypothetical (at the statutory rate) and determined without regard to the Company's deduction for general and administrative expenses, interest costs and other income tax credits and deductions, nor whether the hypothetical tax provision will be payable. F-31 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Natural Gas and Oil Reserve Quantities The following schedule contains estimates of proved natural gas and oil reserves attributable to the Company. Proved reserves are estimated quantities of natural gas and oil that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those that are expected to be recovered through existing wells with existing equipment and operating methods. Reserves are stated in thousand cubic feet (mcf) of natural gas and barrels (bbl) of oil. Geological and engineering estimates of proved natural gas and oil reserves at one point in time are highly interpretive, inherently imprecise and subject to ongoing revisions that may be substantial in amount. Although every reasonable effort is made to ensure that the reserve estimates are accurate, by their nature reserve estimates are generally less precise than other estimates presented in connection with financial statement disclosures. Gas - mcf Oil - bbls -------------- ------------- Proved reserves: Balance, May 31, 2003 28,270,634 43,083 Purchase of reserves-in-place 99,700,000 -- Extensions and discoveries 11,219,900 22,571 Revisions of previous estimates (84,126) -- Production (5,530,208) (8,549) -------------- ------------- Balance, May 31, 2004 133,576,200 57,105 Purchase of reserves-in-place -- -- Extensions and discoveries 21,281,611 -- Revisions of previous estimates -- (3,720) Production (5,013,911) (5,551) -------------- ------------- Balance, December 31, 2004 149,843,900 47,834 Purchase of reserves-in-place -- -- Extensions and discoveries -- -- Revisions of previous estimates (5,959,600) (6,324) Production (9,565,000) (9,241) -------------- ------------- Balance, December 31, 2005 134,319,300 32,269 ============== ============= Proved developed reserves: Balance, May 31, 2004 62,558,920 57,105 Balance, December 31, 2004 81,467,220 47,834 Balance, December 31, 2005 71,638,250 32,269 Standardized Measure of Discounted Future Net Cash Flows The following schedule presents the standardized measure of estimated discounted future net cash flows from the Company's proved reserves for the year ended December 31, 2005, for the seven-month transition period ended December 31, 2004 and for the fiscal year ended May 31, 2004. Estimated future cash flows are based on independent reserve data. Because the standardized measure of future net cash flows was prepared using the prevailing economic conditions existing at December 31, 2005 and 2004 and May 31, 2004, it should be emphasized that such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of the Company's recoverable reserves or in estimating future results of operations. F-32 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Year Ended Seven Months Year Ended December 31, Ended December 31, May 31, 2005 2004 2004 ------------------ ------------------ ------------------ Future production revenues (1) $ 1,258,579,000 $ 959,591,000 $ 796,329,000 Future production costs (366,474,000) (274,015,000) (264,810,000) Future development costs (122,428,000) (74,470,000) (48,773,000) ------------------ ------------------ ------------------ Future cash flows before income taxes 769,677,000 611,106,000 482,746,000 Future income tax (205,561,000) (160,734,000) (128,000,000) ------------------ ------------------ ------------------ Future net cash flows 564,116,000 450,372,000 354,746,000 Effect of discounting future annual cash flows at 10% (210,446,000) (154,769,000) (120,802,000) ------------------ ------------------ ------------------ Standardized measure of discounted net 353,670,000 295,603,000 233,944,000 cash flows before hedges Future hedge settlements (61,918,000) (22,477,000) (19,788,000) ------------------ ------------------ ------------------ Standardized measure of discounted net cash flows after hedges $ 291,752,000 $ 273,126,000 $ 214,156,000 ================== ================== ==================

(1) The weighted average natural gas and oil wellhead prices used in computing the Company's reserves were $9.22 per mcf and $55.69 per bbl at December 31, 2005, $6.30 per mcf and $41.07 per bbl at December 31, 2004, and $5.95 per mcf and $35.25 per bbl at May 31, 2004. The principal changes in the standardized measure of discounted future net cash flows relating to proven natural gas and oil properties were as follows:

Year Ended Seven Months Year Ended December 31, Ended December 31, May 31, 2005 2004 2004 ------------------ ------------------ ------------------ Sales and transfers of natural gas and $ (25,646,000) $ (18,419,000) $ (21,312,000) oil, net of production costs Net changes in prices and production costs 171,468,000 45,264,000 7,461,000 Acquisitions of natural gas and oil in place - less related production costs -- -- 217,924,000 Extensions and discoveries, less related production costs -- 46,686,000 19,956,000 Revisions of previous quantity estimates less related production costs (51,760,000)(1) 5,004,000 22,722,000 Accretion of discount 8,832,000 4,609,000 3,917,000 Net change in income taxes (44,827,000) (21,485,000) (63,792,000) ------------------ ------------------ ------------------ Total change in standardized measure of discounted future net cash flows $ 58,067,000 $ 61,659,000 $ 186,876,000 ================== ================== ==================

(1) - includes $30.1 million related to increase in future development costs. The following schedule contains a comparison of the standardized measure of discounted future net cash flows to the net carrying value of proved natural gas and oil properties at December 31, 2005 and 2004 and May 31, 2004: F-33 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Year Ended Seven Months Year Ended December 31, Ended December 31, May 31, 2005 2004 2004 ----------------- --------------------- -------------- Standardized measure of discounted future net cash flows $ 353,670,000 $ 295,603,000 $ 233,944,000 Proved natural gas & oil property, net of accumulated depletion 165,085,000 138,358,000 114,280,000 ----------------- --------------------- -------------- Standardized measure of discounted future net cash flows in excess of net carrying value of proved natural gas & oil properties $ 188,585,000 $ 157,245,000 $ 119,664,000 ================= ===================== ==============

17. Comparison of Certain Financial Data Due To Change in Fiscal Year End Seven months ended December 31, 2004 compared to the seven months ended December 31, 2003 The Company changed its fiscal year-end from May 31 to December 31, effective January 1, 2005. As a result of this change, the Company has prepared financial statements for the seven-month transition period ended December 31, 2004. Accordingly, the following results of operations compares audited balances for the seven months ended December 31, 2004 to the unaudited balances for the seven months ended December 31, 2003.

Seven months ended December 31, ---------------------------------- 2004 2003 -------------- -------------- (unaudited) Oil and gas sales $ 24,201,000 $ 8,755,000 Gas pipeline revenue 1,918,000 1,289,000 Other revenue and expense 37,000 (1,356,000) -------------- -------------- Total revenues 26,156,000 8,688,000 Oil and gas production 5,389,000 2,267,000 Pipeline operating 3,653,000 1,140,000 General & administrative expense 2,681,000 831,000 Depreciation, depletion & amortization 7,671,000 2,235,000 Other costs of revenues -- (8,000) -------------- -------------- Total costs and expenses 19,394,000 6,465,000 -------------- -------------- Operating income 6,762,000 2,223,000 Change in derivative fair value (1,487,000) 3,312,000 Interest expense (10,147,000) (2,377,000) Interest income 9,000 -- -------------- -------------- Income (loss) before income taxes (4,863,000) 3,158,000 Deferred income tax (expense) -- (1,263,000) -------------- -------------- Net income (loss) before cumulative effect of accounting (4,863,000) 1,895,000 change Cumulative effect of accounting change, net of income tax of $19,000 -- (28,000) -------------- -------------- Net loss (4,863,000) 1,867,000 Preferred stock dividends (6,000) (6,000) -------------- -------------- Net loss available to common shareholders $ (4,869,000) $ 1,861,000 ============== ============== Loss per common share - basic: Loss before cumulative effect of accounting change $ (0.86) $ 0.34 Cumulative effect of accounting change -- (0.01) -------------- -------------- $ (0.86) $ 0.33 ============== ============== Loss per common share - diluted: Loss before cumulative effect of accounting change $ (0.86) $ 0.30 Cumulative effect of accounting change -- -- -------------- -------------- $ (0.86) $ 0.30 ============== ============== Weighted average common and common equivalent shares outstanding: Basic 5,661,352 5,568,730 ============== ============== Diluted 5,661,352 6,229,315 ============== ==============

F-34 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following analysis of cash flows compares the audited seven months ended December 31, 2004 to the seven months ended December 31, 2003.

Seven months ended December 31, ------------------------------ 2004 2003 ------------- ------------- (unaudited) Cash flows from operating activities: Net income (loss) $ (4,863,000) $ 1,895,000 Adjustments to reconcile net income (loss) to cash provided by operations: Depreciation & depletion 8,033,000 2,235,000 Accrued interest subordinated notes 4,866,000 210,000 Change in derivative fair value 1,487,000 (3,312,000) Cumulative effect of accounting change -- 47,000 Deferred income taxes -- 1,263,000 Accretion of line of credit -- 1,204,000 Stock issued for services -- 62,000 Stock issued for director fees 62,000 -- Amortization of loan origination fees 530,000 172,000 Other 191,000 -- Change in assets and liabilities: Accounts receivable 893,000 (2,397,000) Other receivables 85,000 -- Other current assets 16,000 -- Inventory 208,000 130,000 Accounts payable 13,628,000 1,201,000 Revenue payable 222,000 836,000 Accrued expenses 126,000 -- ------------- ------------- Net cash provided by operating activities 25,484,000 3,546,000 Cash flows from investing activities: Acquisition of proved gas & oil properties-Devon -- (111,220,000) Acquisition of gas gathering pipelines-Devon -- (21,864,000) Equipment, development & leasehold costs (48,287,000) (6,425,000) Other assets (527,000) (188,000) ------------- ------------- Net cash used in investing activities (48,814,000) (139,697,000) Cash flows from investing activities: Long-term debt 136,118,000 89,450,000 Repayments of note borrowings (104,732,000) (19,500,000) Proceeds from subordinated debt -- 51,000,000 Refinancing costs-UBS (4,942,000) -- Accounts payable-Devon holdback -- 12,417,000 Dividends paid (6,000) (5,000) Proceeds from the issuance of common stock 480,000 500,000 Change in other long-term liabilities (638,000) -- ------------- ------------- Net cash provided by financing activities 26,280,000 133,862,000 ------------- ------------- Net increase in cash 2,950,000 (2,289,000) Cash, beginning of period 3,508,000 2,689,000 ------------- ------------- Cash, end of period $ 6,458,000 $ 400,000 ============= =============

F-35 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 18. Quarterly Financial Data (unaudited) Summarized unaudited quarterly financial data for 2005 and 2004 are as follows:

Quarters Ended ------------------------------------------------------------ December 31, September 30, June 30, March 31, 2005 2005 2005 2005 ------------ ------------- ------------ ------------ Total revenues $ 10,333,000 $ 13,506,000 $ 13,003,000 $ 12,051,000 Gross profit (1) (2) (9,787,000) 2,040,000 3,134,000 3,647,000 Net loss (3) (24,683,000) (4,253,000) (1,907,000) (1,098,000) Net loss per common share: Basic $ (1.67) $ (0.64) $ (0.30) $ (0.19) Diluted $ (1.67) $ (0.64) $ (0.30) $ (0.19)

Quarters Ended ------------------------------------------------------------ December 31, September 30, June 30, March 31, 2004 2004 2004 2004 ------------ ------------- ------------ ------------ Total revenues $ 11,924,000 $ 11,520,000 $ 11,339,000 $ 11,548,000 Gross profit (1) 2,283,000 3,367,000 3,447,000 3,647,000 Net income (loss)(4) (4,791,000) (191,000) 683,000 (5,646,000) Net earnings (loss) per common share: Basic $ (0.84) $ (0.03) $ 0.12 $ (1.01) Diluted $ (0.84) $ (0.03) $ 0.09 $ (1.01)

F-36 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) Total revenue less operating costs. (2) The decrease in gross profit in the fourth quarter is the result of an increase in depletion expense. (3) The decrease in net income in the third quarter is primarily attributable to change in derivative fair value. The decrease in net income in the fourth quarter is attributable to change in derivative fair value and an increase in depletion expense. (4) The decrease in net income in the first and fourth quarters is primarily attributable to change in derivative fair value. 19. Recent Accounting Pronouncements The Financial Accounting Standards Board recently issued the following standards which the Company reviewed to determine the potential impact on our financial statements upon adoption. In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123(R), Share-Based Payment, which revised SFAS 123, Accounting for Stock-Based Compensation. This statement establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. SFAS 123(R) requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. This statement is effective as of the beginning of the first annual reporting period that begins after June 15, 2005. Since the issuance of SFAS 123(R), three FASB Staff Positions (FSPs) have been issued regarding SFAS 123(R): FSP FAS 123(R)-1--Classification and Measurement of Freestanding Financial Instruments Originally Issued in Exchange for Employee Services under FASB Statement No. 123(R), FSP FAS 123(R)-2--Practical Accommodation to the Application of Grant Date as Defined in FASB Statement No. 123(R), and FSP FAS 123(R)-3--Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards. These FSPs will be applicable upon the initial adoption of FAS 123(R). The effect of SFAS 123(R) is more fully described in Note 1. In March 2005, the FASB issued FASB Interpretation No. (FIN) 47, Accounting for Conditional Asset Retirement Obligations. FIN 47 specifies the accounting treatment for conditional asset retirement obligations under the provisions of SFAS 143. FIN 47 is effective no later than the end of the fiscal year ending after December 15, 2005. The Company adopted this statement effective December 31, 2005. Implementation of FIN 47 did not have a material effect on our financial statements. In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3. SFAS 154 requires retrospective application to prior period financial statements for changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS 154 also requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. SFAS 154 is effective for accounting changes made in fiscal years beginning after December 15, 2005. The impact of SFAS 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but the Company does not currently expect SFAS 154 to have a material impact on our financial statements. In June 2005, the EITF reached a consensus on Issue No. 04-10, Determining Whether to Aggregate Operating Segments That Do Not Meet the Quantitative Thresholds. EITF Issue 04-10 confirmed that operating segments that do not meet the quantitative thresholds can be aggregated only if aggregation is consistent with the objective and basic principles of SFAS 131, Disclosure about Segments of an Enterprise and Related Information. The consensus in this issue should be applied for fiscal years ending after September 30, 2005, and the corresponding information for earlier periods, including interim periods, should be restated unless it is impractical to do so. The adoption of EITF Issue 04-10 is not expected to have a material impact on our disclosures. In September 2005, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty. EITF Issue 04-13 requires that purchases and sales of inventory with the same counterparty in the same line of business should be accounted for as a single non-monetary exchange, if entered into in contemplation of one another. The consensus is effective for inventory arrangements entered into, modified or renewed in interim or annual reporting periods beginning after March 15, 2006. The adoption of EITF Issue 04-13 is not expected to have a material impact on our financial statements. F-37 QUEST RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 20. Subsequent Events No other material subsequent events have occurred that warrants disclosure since the balance sheet date, other than as disclosed above in Note 3--Long-Term Debt. F-38 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None. ITEM 9A. CONTROLS AND PROCEDURES The effectiveness of the Company's or any system of disclosure and procedures, no matter how well designed and operated, 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. The Company's management, including the Chief Executive Officer and the Chief Financial Officer, evaluated the Company's disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of December 31, 2005. Based on that evaluation, the management, the Chief Executive Officer and the Chief Financial Officer concluded that the Company's disclosure controls and procedures are designed, and are effective, in all material respects to provide reasonable assurance that information required to be disclosed in the reports that the Company files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and are effective to ensure that information required to be disclosed by the Company is accumulated and communicated to the Company's management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in the Company's internal control over financial reporting during the fourth quarter of 2005 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting. ITEM 9B. OTHER INFORMATION. Effective March 27, 2006, the board of directors approved a standard form of indemnification agreement for our non-employee directors and executive officers. Under certain circumstances, the agreement will require us to indemnify and to advance certain expenses to each director or executive officer in the event the director or executive officer becomes subject to a lawsuit or liability claim in connection with his or her activities as a director or executive officer of Quest. A copy of the form of indemnification agreement for directors and executive officers has been attached to this Form 10-K as Exhibit 10.11. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. MANAGEMENT Directors and Executives The following is a list of our executive officers and directors, their ages as of March 30, 2006 and their positions and offices. Name Age Position --------------------- --------- -------------------------------------- Jerry D. Cash 44 Chief Executive Officer and Director David E. Grose 53 Chief Financial Officer Richard Marlin 53 VP Engineering Walter Yuras 54 VP Geology Bree Stewart 31 VP Land John C. Garrison 54 Director James B. Kite, Jr. 54 Director Kevin R. White 48 Director Ronnie K. Irani 49 Director Jon H. Rateau 50 Director 51 Jerry D. Cash, Chief Executive Officer and Director. Mr. Cash has been active in the oil and gas exploration and development business for over 20 years. Mr. Cash has been the Chairman of the Board since November 2002, when we acquired STP Cherokee, Inc. Mr. Cash has been Chief Executive Officer since September 2004. From November 2002 until September 2004, he was Co-Chief Executive Officer. From November 2002 until June 2004, he was Chief Financial Officer. From 1980 to 1986, Mr. Cash worked for Bodard & Hale Drilling Company while pursuing a petroleum engineering degree at Oklahoma State University. During this period, Mr. Cash drilled several hundred wells throughout Oklahoma. In 1987, Mr. Cash formed STP Cherokee and directed that company in the identification and realization of numerous oil, gas and CBM exploration projects until its sale to us in November, 2002. A long-time resident of Oklahoma, Mr. Cash maintains an active role in several charitable organizations. David E. Grose, Chief Financial Officer. Mr. Grose has been our Chief Financial Officer since June 2004. Mr. Grose has 25 years of financial experience, primarily in the exploration, production, and drilling sectors of the oil and gas industry. Mr. Grose also has significant knowledge and expertise in capital development and in the acquisition of oil & gas companies. In previous years, Mr. Grose held various positions including Vice-President and/or CFO for Oxley Petroleum Company during 2002 and 2003, a telecommunications company from 2000 to 2001, Bayard Drilling Technologies, Inc. from 1997 to 1999, and Alexander Energy Corporation from 1980 to 1997. Mr. Grose earned a B.A. in Political Science from Oklahoma State University in 1974 and an MBA from the University of Central Oklahoma in 1977. Richard Marlin, Executive VP Engineering. Mr. Marlin has served as our Executive VP Engineering since September 2004. Prior to that, he was our engineering manager from November 2002 to September 2004. Prior to that, he was the engineering manager for STP from 1999 until STP's acquisition by us in November 2004. Prior to that, he was employed by Parker and Parsley Petroleum as the Mid-Continent Operations Manager for 12 years. He has more than 28 years industry experience involving all phases of drilling and production in more than 14 states. His experience also involved primary and secondary operations along with the design and oversight of gathering systems that move as much as 175 MMcf/d. He is a registered Professional Engineer holding licenses in Oklahoma and Colorado. Mr. Marlin earned a B.S. in Industrial Engineering and Management from Oklahoma State University in 1974. Mr. Marlin is a Director of the Mid-Continent Coal Bed Methane Forum. Walter Yuras, Executive VP Geology. Mr. Yuras has been Executive VP Geology since September 2004. Prior to that, he was our geologic manager since November 2002. Mr. Yuras is a Certified Petroleum Geologist with 27 years of oil and gas exploration and development experience in the Mid-Continent region, including subsurface and geophysical prospecting, trend and frontier exploration plays, and production acquisition. His background includes experience with both major and independent companies and since 1993, he has partnered with Mr. Cash, focusing on oil, gas and CBM exploration and acquisition opportunities. Mr. Yuras holds a B.S. - Geology degree from Eastern Illinois University and a M.S. - Geology degree from the New Mexico Institute of Mining and Technology. Bree Stewart, Executive VP Land. Ms. Stewart has served as Executive VP Land since September 2004. Ms. Stewart joined us in May, 2004 with over 8 years of land experience. Prior to that, Ms. Stewart spent 3 years with Devon Energy Corporation in their land department. Prior to Devon, Ms. Stewart spent 3 years with Alliance Resources Oil Company in the land and legal departments. Ms. Stewart holds a Bachelor of Science degree in Biology from the University of Central Oklahoma. Ms. Stewart is a member of the American Association of Professional Landmen and Oklahoma City Association of Petroleum Landmen. John C. Garrison brings expertise in public company activities and issues. Mr. Garrison served as our Treasurer from 1998 to September 2001. Mr. Garrison has been a Certified Public Accountant in public practice providing financial management and accounting services to a variety of businesses for over twenty years. Since July 2004, Mr. Garrison has been the Chief Financial Officer of ICOP Digital, Inc. Mr. Garrison presently is also a director of Empire Energy Corporation. Mr. Garrison holds a bachelor's degree in Accounting from Kansas State University. James B. Kite, Jr. is the Chief Executive Officer of Boothbay Royalty Company, based in Oklahoma City, Oklahoma. Boothbay Royalty Company was founded in 1977 as an independent investment company with its primary concentration in the field of oil & gas exploration and production. Mr. Kite spent several years in the commercial banking industry with an emphasis in credit and loan review prior to his involvement in the oil and gas industry. Mr. Kite presently is a director of The All Souls' Anglican Foundation and Bigelow Laboratory for Ocean Science. Mr. Kite earned a bachelor's of business administration in finance from the University of Oklahoma. 52 Kevin R. White is a Certified Public Accountant and has 19 years of independent exploration experience with expertise in strategic planning, capital formation and investor relations, information technology and risk management. Mr. White served as a consultant for the Company from September 2003 until May 2004. Prior to that time, he was Executive VP Corporate Development/Strategic Planning for Louis Dreyfus Natural Gas from 1990 to 2001 and spent seven years during the 1980's with Bogert Oil Company/Bogert Funds, Inc. as a Manager, Executive VP and Controller. Mr. White received a Master of Science in Accounting in 1980 and a B.S. in Accounting in 1979 from Oklahoma State University. Ronnie K. Irani is the Chief Executive Officer of RKI Exploration & Production, LLC. He has 26 years of extensive oil and gas experience. From 2001 to 2005, Mr. Irani was Senior Vice President and General Manager in charge of Dominion Resources, Inc.'s western U.S. business division. He joined Louis Dreyfus Natural Gas Corporation in 1991 as its Vice President of Engineering and Exploration until the company's 2001 merger with Dominion. Prior to that, he managed and directed Woods Petroleum Corporation's development drilling and acquisition projects. Mr. Irani serves on several oil and gas industry related boards, including the Oklahoma Independent Petroleum Association, the Oklahoma Energy Resources Board, and the Interstate Oil and Gas Compact Commission. Mr. Irani earned a B.S. from the University of Bombay, a bachelors and masters degree in Petroleum Engineering from the University of Oklahoma, and a masters degree in Business Administration from Oklahoma City University. Jay H. Rateau is the Vice President of Business Development and Energy Management & Services of Alcoa Primary Metals, Energy Division and has been at Alcoa Primary Metals since 1996. Before that, Mr. Rateau held a number of managerial positions with National Steel Corporation from 1981 to 1996. He brings expertise in business acquisitions and divestitures, capital budgets and project management, and applied research of complex technology and processes. Mr. Rateau holds an M.B.A. from Michigan State University and received a B.S. in Industrial Engineering from West Virginia University. Audit Committee The Board of Directors has established a separate Audit Committee. The following three directors are members of the Audit Committee: John Garrison, Chair, Ronnie Irani and Jon Rateau. The Board of Directors has determined that each of the Audit Committee members are independent, as that term is defined under the enhanced independence standards for audit committee members in the Securities Exchange Act of 1934 and rules thereunder, as amended, as incorporated into the listing standards of the Nasdaq National Market. The Board of Directors has determined that Mr. Garrison is an "audit committee financial expert", as that term is defined in the rules promulgated by the Securities and Exchange Commission pursuant to the Sarbanes-Oxley Act of 2002. Nomination Process During the period from November 7, 2002 until November 7, 2005, we were subject to the terms of a voting agreement among the Company, Douglas L. Lamb, Jerry D. Cash and certain other shareholders of the Company (the "Voting Agreement"). In the Voting Agreement, we agreed to use our best efforts and to take all action within our power to elect Mr. Lamb, an individual designated by Mr. Lamb, Mr. Cash, and an individual designated by Mr. Cash to the Board. As a result, during prior years, we did not have any formal procedures for stockholders to recommend nominations to the Board of Directors and the policy of the Board of Directors was to not consider candidates recommended by security holders. As a result of the termination of the Voting Agreement and the issuance of additional shares of our common stock in November 2005, which resulted in the members of our Board of Directors no longer controlling the Company, the Board of Directors established a nominating committee and adopted the following procedures for stockholders to recommend nominees to our Board of Directors. Our Nominating Committee's charter describes the committee's responsibilities, including developing corporate governance guidelines and seeking, screening and recommending director candidates for nomination by the Board of Directors. Quest's Corporate Governance Guidelines contain information regarding the selection, qualification and criteria for director nominees and the composition of the Board. Both documents are published on Quest's Internet website at www.qrcp.net under the heading Corporate Governance Policies. The Nominating Committee evaluates all director candidates in accordance with the director qualification standards described in the Corporate Governance Guidelines. 53 The Nominating Committee considers candidates for Board membership suggested by its members and other Board members, as well as management and stockholders. A stockholder who wishes to recommend a prospective nominee for the Board should notify the Company's Secretary in writing with whatever supporting material the stockholder considers appropriate or that is required by the Company's bylaws relating to stockholder nominations as described below. The notice should be sent to Quest Resource Corporation, 9520 N. May Avenue, Suite 300, Oklahoma City, OK 73120, attention: Corporate Secretary. The Company's Secretary will forward the information to the members of the Nominating Committee, who will consider whether to nominate any person nominated by a stockholder pursuant to the provisions of the proxy rules, the Company's bylaws, the Company's Nominating Committee Charter, the Company's Corporate Governance Guidelines and the director selection procedures established by the Nominating Committee. We recommend that any recommendations for nominees be submitted to the Corporate Secretary at least 90 days prior to the date on which last years annual meeting was held, in order to give the Nominating Committee sufficient time to evaluate the recommended nominee. Once the Nominating Committee has identified a prospective nominee candidate, the Committee makes an initial determination as to whether to conduct a full evaluation of the candidate. This initial determination is based on the information provided to the Nominating Committee with the recommendation of the prospective candidate, as well as the Nominating Committee's own knowledge of the candidate. This information may be supplemented by inquiries to the person making the recommendation or others. The preliminary determination is based primarily on the need for additional Board members to fill vacancies or expand the size of the Board and the likelihood that the prospective nominee can satisfy the criteria and qualifications described below. If the Nominating Committee determines, in consultation with the Chairman of the Board and other Board members as appropriate, that additional consideration is warranted, the Nominating Committee then evaluates the prospective nominees against the criteria and qualifications set out in the Nominating Committee's Charter. Such criteria and qualifications include: o a general understanding of management, marketing, accounting, finance and other elements relevant to the Company's success in today's business environment; o an understanding of the principal operational, financial and other plans, strategies and objectives of the Company; o an understanding of the results of operations and the financial condition of the Company and its significant business segments for recent periods; o an understanding of the relative standing of the Company's significant business segments vis-a-vis competitors; o the educational and professional background of the prospective candidate; o the prospective nominee's standards of personal and professional integrity; o the demonstrated ability and judgment necessary to work effectively with other members of the Board to serve the long-term interests of the stockholders; o the prospective nominee's willingness and ability to make a sufficient time commitment to the affairs of the Company in order to effectively perform the duties of a director, including regular attendance at Board and committee meetings; o the prospective nominee's commitment to the long-term growth and profitability of the Company; and o the prospective nominee's ability to qualify as an independent director as defined in the Nasdaq listing standards. However, as determining the specific qualifications or criteria against which to evaluate the fitness or eligibility of potential director candidates is necessarily dynamic and an evolving process, the Board believes that it is not always in the best interests of the Company or its stockholders to attempt to create an exhaustive list of such qualifications or criteria. Appropriate flexibility is needed to evaluate all relevant facts and circumstances in context of the needs of the Board and the Company at a particular point in time. The Nominating Committee also considers such other relevant factors as it deems appropriate, including the current composition of the Board, the balance of management and independent directors, the need for Audit Committee expertise and the evaluations of other prospective nominees. In determining whether to recommend a director for re-election, the Nominating Committee also considers the director's past attendance at meetings and participation in and contributions to the activities of the Board. In connection with this evaluation, the Nominating Committee determines whether to interview the prospective nominee, and if warranted, one or more members of the Nominating Committee, and others as appropriate, interview prospective nominees in person or by telephone. After completing this evaluation and interview, the Nominating Committee makes a recommendation to the full Board as to the persons who should be nominated by the Board, and the Board determines the nominees after considering the recommendation and report of the Nominating Committee. In addition, nominees and new directors who serve as a member of Quest's Audit Committee are not permitted to serve on the audit committee of more than two other boards of public companies. The Board values the contributions of directors whose years of service have given them insight into the Company and its operations and believes term limits are not necessary. Directors shall not be nominated for election to the Board after their 72nd birthday, although the full Board may nominate candidates over the age of 72 for special circumstances. 54 In addition to the ability of stockholders to recommend nominees to the Board of Directors discussed above, in accordance with our Restated Articles of Incorporation and Bylaws, any stockholder of record entitled to vote for the election of directors at the applicable meeting of stockholders may at such meeting nominate persons for election to the Board of Directors if such stockholder complies with the notice procedures set forth in our Restated Articles of Incorporation and Bylaws and summarized below. In order for a stockholder to nominate a candidate for Director at an annual meeting, notice of the nomination must be received by the Secretary of Quest not less than 14 days nor more than 50 days prior to the meeting date; provided, however, that if less than 21days prior notice or public disclosure of the date of the meeting is given or made to stockholders, the notice must be received no later than the close of business on the 7th day following the day on which the notice of the meeting was mailed or public disclosure was made, whichever occurs first. The stockholder's notice must set forth as to each person whom the stockholder proposes to nominate for election or reelection as a director: o the name, age, business address and, if known, residence address of each nominee proposed in such notice, o the principal occupation or employment of such nominee, o the number of shares of stock of the Corporation which are beneficially owned by each such nominee, and o any other information relating to the person that is required to be disclosed in solicitations for proxies for election of Directors pursuant to Regulation 14A under the Securities Exchange Act of 1934; and The stockholder's notice must also set forth the following information about the stockholder giving the notice: o the name and record address of the stockholder, and o the class and number of shares of capital stock of the Corporation which are beneficially owned by the stockholder. We may require any proposed nominee to furnish such other information as may reasonably be required by us to determine the eligibility of the proposed nominee to serve as a director. Section 16(a) Beneficial Ownership Reporting Compliance Section 16(a) of the Exchange Act requires our directors and executive officers, and persons who own more than 10% of a registered class of our equity securities, to file with the SEC initial reports of ownership and reports of changes in ownership of our equity securities. Directors, executive officers and greater than 10% stockholders are required by SEC regulations to furnish us with copies of all Section 16(a) forms they file. To our knowledge, based solely on a review of Forms 3, 4, 5 and amendments thereto furnished to us and written representations that no other reports were required, during and for the fiscal year ended December 31, 2005, all Section 16(a) filing requirements applicable to our directors, executive officers and greater than 10% beneficial owners were complied with, except for the following: o Jerry Cash filed late a Form 4 reporting a transfer of shares. o John Garrison filed late a Form 4 reporting the Company's issuance of shares as compensation for his duties on the Company's Audit Committee. o James Kite, Jr. and Boothbay Royalty Company each filed late a Form 4 reporting a transfer of shares for estate planning purposes from Boothbay Royalty Company, which is wholly owned by Mr. Kite, to McKown Point, LP. McKown Point, LP's sole general partner is Easterly Family Investments, LLC, which is wholly owned by the Virginia V. Kite GST Exempt Trust for James B. Kite, Jr. (the "Trust"). Mr. Kite is a co-trustee of the Trust. McKown Point, LP, Easterly Family Investments, LLC and the Virginia V. Kite GST Exempt Trust each filed late a Form 3 reporting their becoming a 10% beneficial owner of the Company as a result of the transaction. Code of Ethics Our board of directors has adopted a Code of Business Conduct and Ethics that is applicable to all of our directors, officers and employees, including our principal executive officer, our principal financial officer and our principal accounting officer. A copy of our Code of Business Conduct and Ethics is available on our internet website at www.qrcp.net under the heading Corporate Governance Policies. 55 ITEM 11. EXECUTIVE COMPENSATION. The table below sets forth information concerning the annual and long-term compensation paid to or earned by the Chief Executive Officer and each of the other persons who were serving as an executive officer on December 31, 2005 and who earned more than $100,000 in salary and bonus during the 12 month period ended December 31, 2005. Summary Compensation Table

Annual Compensation Long Term Compensation Awards -------------------------------------------------------------------------------------------------- Other Stock Securities 12 months Annual(2) Bonus Underlying LTIP All Other(3) Name and Principal Position ended(1) Salary Bonus Compensation Awards Options/SARS Payouts Compensation --------------------------- --------- -------- --------- ------------ -------- ------------ ------- ------------ Jerry D. Cash 12/31/05 $167,625 $ 4,200 -- -- -- -- $ 9,044 Chairman of the Board, 12/31/04 $120,000 $ 1,000 -- -- -- -- $ 3,512 Chief Executive Officer 5/31/04 $120,000 $ 800 -- -- -- -- $ 3,600 and President David E. Grose (4) 12/31/05 $167,608 $ 5,000 -- $480,000 -- -- $ 9,084 Chief Financial Officer 12/31/04 $ 83,077 $ 1,000 -- -- -- -- -- Richard Marlin (5) 12/31/05 $189,518 $ 6,226 -- $360,000 -- -- $ 11,596 Executive VP Engineering 12/31/04 $132,000 $ 1,000 -- -- -- -- $ 4,165 Walter Yuras (6) 12/31/05 $158,004 -- -- -- -- -- -- Executive VP Geology 12/31/04 $159,600 -- -- -- -- -- --

----------- (1) On December 31, 2004, we changed our fiscal year from a fiscal year ended May 31 to a fiscal year ended December 31. As a result, we are providing information for our fiscal year ended May 31, 2004 and the transitional disclosure for the 12 months ended December 31, 2004. Therefore, there is a five-month overlap in the compensation disclosed for the 12-month periods ended May 31, 2004 and December 31, 2004. (2) Perquisites and other personal benefits, securities or property did not exceed 10% of the total of salary and bonus for each of the named executives during the applicable year. (3) Consists of employer contributions to the executive's profit sharing account. (4) Represent shares of our common stock awarded as a bonus in 2005. Under the terms of the award, Mr. Grose will receive (i) 16,000 bonus shares on January 1, 2007, regardless of whether he is employed by us on such date, (ii) an additional 16,000 bonus shares on January 1, 2007, provided he is employed (and has at all times from the date of the agreement been employed) by us on June 1, 2006, and (iii) 16,000 bonus shares on June 1, 2007, provided he is employed (and has at all times from the date of the agreement been employed) by us on June 1, 2007. Value computed as the number of shares awarded times the closing price on date of grant ($480,000 at October 14, 2005). Mr. Grose is not eligible to vote or to receive dividends declared on such shares until such time as the shares are issued to him. As of December 31, 2005, the 48,000 bonus shares issuable to Mr. Grose had a value of $633,600. The bonus share awards have no value to the recipient until the term of service requirement is met. Mr. Grose became our Chief Financial Officer effective June 1, 2004. (5) Represent shares of our common stock awarded as a bonus in 2005. Richard Marlin, Executive Vice President of Engineering, will receive (i) 12,000 bonus shares on January 1, 2007, provided he is employed (and has at all times from the date of the agreement been employed) by us on April 4, 2006, (ii) 12,000 bonus shares on April 4, 2007, provided he is employed (and has at all times from the date of the agreement been employed) by us on April 4, 2007, and (iii) 12,000 bonus shares on April 4, 2008 provided he is employed (and has at all times from the date of the agreement been employed) by us on April 4, 2008. Value computed as the number of shares awarded times the closing price on date of grant ($360,000 at October 14, 2005). Mr. Marlin is not eligible to vote or to receive dividends declared on such shares until such time as the shares are issued to him. As of December 31, 2005, the 36,000 bonus shares issuable to Mr. Marlin had a value of $475,200. The bonus share awards have no value to the recipient until the term of service requirement is met. Mr. Marlin became our Executive VP Engineering effective September 2004. (6) Mr. Yuras became our Executive VP Geology effective September 2004. Options Granted and Options Exercised in the Last Fiscal Year and Year End Option Values No options were granted by us to executive officers during the year ended December 31, 2005. No options were exercised during the year ended December 31, 2005 by our executive officers named in the Summary Compensation Table. 56 As of December 31, 2005, none of the executive officers named in the Summary Compensation Table had any unexercised options. Employment Contracts As of October 14, 2005, we entered into employment agreements with each of Mr. Cash and Mr. Grose. Under the terms of the agreements, Mr. Cash will receive an annual salary of $400,000 and Mr. Grose will receive an annual salary of $275,000. Mr. Cash and Mr. Grose are each also entitled to participate in any incentive bonus plan or program and/or stock option plan that is established by the Compensation Committee for our senior executive officers. The term of each of the agreements will expire upon notice of termination delivered by either us or Mr. Cash or Mr. Grose, as applicable. Mr. Cash or Mr. Grose must provide us with 30 days prior notice of termination. We may terminate either Mr. Cash or Mr. Grose for cause without prior notice. If we terminate either Mr. Cash or Mr. Grose without cause, we must pay him severance pay equal to 12 months salary (to be paid in equal installments), provided that he does not compete with us during the time that he is receiving severance payments and signs a general release of claims in favor of us. Under the employment agreements, "cause" is defined to include, but is not limited to, the following: (i) any act or omission by Mr. Cash or Mr. Grose that constitutes gross negligence or willful misconduct; (ii) theft, dishonest acts or breach of fiduciary duty that materially enrich Mr. Cash or Mr. Grose or materially damage us or conviction of a felony, (iii) any conflict of interest, except those consented to in writing by us; (iv) any material failure by Mr. Cash or Mr. Grose to observe our work rules, policies or procedures that is not cured after 10 days' written notice; (v) bad faith refusal by Mr. Cash or Mr. Grose to carry out reasonable instruction that is not cured after 10 days' written notice; or (vi) any material breach of their employment agreements. The agreements require Mr. Cash and Mr. Grose to not disclose or use confidential information (except in the ordinary course of performing his duties for us). In cases of termination for cause or voluntary termination, Mr. Cash or Mr. Grose, as appropriate, may not solicit customers, business prospects or employees for a period of one year following his termination of employment. The agreements also prohibit Mr. Cash and Mr. Grose from engaging in any act, which creates a conflict of interest with us. Compensation of Directors Historically, our directors did not receive any compensation for serving as a director, although we did reimburse directors for expenses incurred in connection with attendance at meetings of the board of directors. In connection with the expansion of the size of the board of directors and the appointment of three new non-employee directors in October 2005 as part of the recapitalization, all of our non-employee directors will receive the following compensation: o annual director fee of $20,000 per year; o $2,000 for each board meeting attended in person and $500 for each telephonic board meeting; and o a grant of an option for 50,000 shares of common stock (on a post-reverse stock split basis). Options for 10,000 shares will be immediately vested and the options for the remaining 40,000 shares will vest 10,000 per year over the next four years; provided that the director is still serving on the board of directors at the time of the vesting of the stock options. Mr. Garrison received 10,000 restricted shares of our common stock for serving on the audit committee for the period from June 6, 2003 to May 31, 2005. In connection with the expansion of the board of directors, we intend to increase the size of the existing audit committee from one to three members and to establish compensation and nominating committees consisting solely of independent directors. The board of directors has not yet determined the amount of additional compensation, if any, to be paid to the members of these committees for their service on such committees. Annual Incentive Plan Effective March 31, 2006, our Compensation Committee adopted our Annual Management Incentive Plan (the "Bonus Plan"). Each of our executive officers will be eligible to participate in the Bonus Plan for 2006. Our Bonus Plan puts a significant portion of total compensation at risk by linking potential annual compensation to the Company's achievement of specific performance goals during the year, which creates a direct connection between the executive's pay and the Company's financial performance. These goals will be established by the Compensation Committee at the beginning of each calendar year and for 2006 will include: 57 o Operational goals consisting of finding and development costs per mcf, reserve replacement and revisions and production growth; and o Financial discipline goals consisting of lease operating expense per mcf produced, pipeline operating expenses per mcf transported and EBITDA. Each of these six performance goals are equally weighted for all participants in the Bonus Plan. The Bonus Plan provides for bonuses to be paid in the form of a predetermined mixture of cash and common stock that varies depending upon the level of bonus (with higher bonus awards being paid with a greater percentage of common stock). Each executive officer has a target bonus percentage expressed as a percentage of base salary based on his or her level of responsibility, with bonuses ranging from a low of approximately 15% of base salary to 42% of base salary for the CEO (if performance is 100% of target). The annual incentive program includes minimum performance thresholds required to earn any incentive compensation, as well as maximum payouts geared towards rewarding extraordinary performance; thus, actual awards can range from 0% (if performance is below 60% of target) to 99% of base salary for the CEO (if performance is 150% of target). Any equity paid as part of a bonus would be considered part of the 2005 Omnibus Stock Award Plan and would count against the total number of shares that may be issued pursuant to that plan. In addition, no portion of any bonus will be paid in the form of common stock unless the 2005 Omnibus Stock Award Plan is approved by the shareholders. Omnibus Stock Award Plan On October 14, 2005, the Board of Directors adopted our 2005 Omnibus Stock Award Plan that provides for grants of non-qualified stock options, restricted shares, bonus shares, deferred shares, stock appreciation rights, performance units and performance shares. The Omnibus Plan also permits the grant of incentive stock options ("ISOs"). The objectives of the Omnibus Plan are to strengthen key employees' and non-employee directors' commitment to our success, to stimulate key employees' and non-employee directors' efforts on our behalf and to help us attract new employees with the education, skills and experience we need and retain existing key employees. See Item 12. "Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters--2005 Stock Omnibus Award Plan" for a description of the plan. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS. The following table sets forth information as of March 28, 2006 concerning the shares of common stock beneficially owned by (a) each person known by us, solely by reason of our examination of Schedule 13D and 13G filings made with the SEC and by information voluntarily provided to us by certain stockholders, to be the beneficial owner of 5% or more of our outstanding common stock, (b) each of the directors and nominees for election as a director, (c) each of the executive officers named in the summary compensation table under Item 11. "Executive Compensation" and (d) all current directors and executive officers as a group. If a person or entity listed in the following table is the beneficial owner of less than one percent of our common stock outstanding, this fact is indicated by an asterisk in the table. The percentages of ownership and the number of shares beneficially owned are disproportionate due to joint beneficial ownership making the notes following the table essential for a complete understanding of our ownership structure. 58

Number of Shares of Common Stock Beneficially Percent Owned(1) Of Class ------------------ -------- Name and Address of Beneficial Owner Wellington Management Company, LLP(2) 75 State Street Boston, MA 02109................................................ 2,415,600 10.94% Third Point LLC(3) 390 Park Avenue, 18th Floor New York, NY 10022............................................... 1,973,076 8.9% SAB Capital Advisors, L.L.C.(4) 712 Fifth Avenue, 42nd Floor New York, NY 10019............................................... 1,923,076 8.7% Jerry D. Cash(6) 9520 North May Avenue, Suite 300 Oklahoma City, OK 73120.......................................... 1,269,238 5.75% First Pacific Advisors, Inc.(5) 11400 West Olympic Blvd., Suite 1200 New York, NY 10019............................................... 1,185,000 5.4% James B. Kite, Jr.(7)(8) ........................................ 926,157 4.2% John C. Garrison(7) ............................................. 76,053 * Kevin R. White(7) ............................................... 10,000 * Jon H. Rateau(7) ................................................ 10,000 * Ronnie K. Irani(7) .............................................. 10,000 * David Grose (9) ................................................. 1,537 * Richard Marlin(10) .............................................. 5,363 * Walter Yuras(11)................................................. 207,698 * All Directors and Executive Officers as a Group (10 Persons)..... 2,516,327 11.4%

---------- * Less than 1%. (1) The number of shares beneficially owned by the entities above is determined under rules promulgated by the SEC and the information is not necessarily indicative of beneficial ownership for any other purpose. Under such rules, beneficial ownership includes any shares as to which the individual has sole or shared voting power or investment power and also any shares that the individual has the right to acquire within 60 days through the exercise of any stock option or other right. The inclusion herein of such shares, however, does not constitute an admission that the named stockholder is a direct or indirect beneficial owner of such shares. Unless otherwise indicated, each person or entity named in the table has sole voting power and investment power (or shares such power with his or her spouse) with respect to all shares of capital stock listed as owned by such person or entity. (2) Wellington Management Company, LLP ("Wellington") is the investment manager and adviser to clients that own a total of 2,415,600 shares of our common stock and is registered under the Investment Advisers Act of 1940, as amended. Wellington, in such capacity, is deemed to share beneficial ownership over the shares held by its client accounts. None of Wellington's individual clients owns more than 5% of our outstanding shares of common stock. (3) Third Point LLC ("Third Point") is the investment manager and adviser to hedge funds and other managed accounts that own a total of 1,973,076 shares of our common stock. Except for Third Point Offshore Fund, Ltd., which owns 1,234,076 shares of our common stock, none of the funds or accounts owns more than 5% of our outstanding shares of common stock. Daniel S. Loeb is the Chief Executive Officer of Third Point. Mr. Loeb and Third Point may each be deemed to beneficially own the shares of common stock owned by the hedge funds and managed accounts for which Third Point serves as the investment manager and adviser. (4) SAB Capital Advisors, L.L.C. is the general partner of SAB Capital Partners, L.P. and SAB Overseas Master Fund, L.P. Scott A. Bommer is the managing member of SAB Capital Advisors. SAB Capital Partners owns 944,814 shares of our common stock, and the SAB Overseas Master Fund owns 978,262 shares of our common stock. Mr. Bommer and SAB Capital Advisors, L.L.C. may each be deemed to beneficially own the shares of common stock owned by SAB Capital Partners and SAB Overseas Master Fund. 59 (5) First Pacific Advisors, Inc. ("FPA") is the managing member of two funds that own a total of 1,185,000 shares of our common stock. FPA, in such capacity, has shared dispositive power and is deemed to share beneficial ownership over the shares held by the funds. Neither of the individual funds owns more than 5% of our outstanding shares of common stock. (6) Includes 200 shares owned by Mr. Cash's wife, Sherry J. Cash and 5,108 shares held in Mr. Cash's retirement account. Mr. Cash does not have voting rights with respect to the shares held in his profit sharing retirement account. Jerry D. Cash disclaims beneficial ownership of the shares owned by Sherry J. Cash. (7) Includes options to acquire 10,000 shares of our common stock that are immediately exercisable. (8) Includes 916,517 shares owned by McKown Point LP, a Texas Limited Partnership. Easterly Family Investments LLC is the sole general partner of McKown Point LP. Easterly Family Investments LLC is wholly owned by the Virginia V. Kite GST Exempt Trust for James B. Kite, Jr. Mr. Kite and Bank of Texas, N.A. are the trustees of the Virginia V. Kite GST Exempt Trust for James B. Kite, Jr. Easterly Family Investments LLC, the Virginia V. Kite GST Exempt Trust for James B. Kite, Jr. and James B. Kite, Jr. may be deemed to have beneficial ownership of the shares owned by McKown Point LP. (9) Represents shares held in Mr. Grose's retirement accounts. Mr. Grose does not have voting rights with respect to these shares. (10) Represents shares held in Mr. Marlin's retirement accounts. Mr. Marlin does not have voting rights with respect to these shares. (11) Represents shares owned of record by Southwind Resources, Inc. Mr. Yuras owns 100% of the outstanding capital stock of Southwind Resources and accordingly may be deemed to beneficially own the shares that are owned by Southwind Resources. Equity Compensation Plans The table below sets forth information concerning compensation plans under which equity securities are authorized for issuance as of the fiscal year ended December 31, 2005. Equity Compensation Plan Information

Number of securities remaining available for Number of securities to Weighted-average future issuance under be issued upon exercise exercise price of equity compensation plans of outstanding options, outstanding options, (excluding securities Plan category warrants and rights (a) warrants and rights (b) reflected in column (a)(c) ------------------------------- -------------------------- ------------------------- --------------------------- Equity compensation plans approved by security holders -- -- -- Equity compensation plans not approved by security holders 250,000 $10.00 1,774,000(1) -------------------------- ------------------------- --------------------------- Total 250,000 $10.00 1,774,000(1) ========================== ========================= ===========================

(1) Currently, the only compensation plan under which equity securities of the Company are authorized for issuance is our 2005 Omnibus Stock Award Plan, which was adopted by the Board of Directors in October 2005. This plan provides for the issuance of up to 2,200,000 shares of our common stock. At the time of the adoption of the plan, awards with respect to 426,000 shares were granted, including options to acquire 250,000 shares listed in the above table. The Board of Directors has decided to submit the plan to the stockholders for approval at the next annual meeting and will not issue any additional awards under the plan until stockholder approval has been obtained. 60 2005 Omnibus Stock Award Plan General We believe that equity compensation aligns the interests of management and employees with the interests of other shareholders. Accordingly, our board of directors adopted the "2005 Omnibus Stock Award Plan" (the "Omnibus Plan") on October 14, 2005. The Omnibus Plan provides for grants of non-qualified stock options, restricted shares, bonus shares, deferred shares, stock appreciation rights, performance units and performance shares. The Omnibus Plan also permits the grant of incentive stock options ("ISOs"). The objectives of the Omnibus Plan are to strengthen key employees' and non-employee directors' commitment to our success, to stimulate key employees' and non-employee directors' efforts on our behalf and to help us attract new employees with the education, skills and experience we need and retain existing key employees. We intend to submit the Omnibus Plan to our stockholders for approval. If the Omnibus Plan is not approved, no future awards will be made under the Omnibus Plan. The grant of options to acquire 250,000 shares of common stock to non-employee directors, which is listed in the table above and the October 2005 stock bonus awards described below are not subject to stockholder approval. Eligibility and Limits on Awards Any of our employees or any employee of our majority owned subsidiaries and our non-employee directors will be eligible to receive awards under the Omnibus Plan. Such eligible employees include our officers or officers of any majority owned subsidiary. As of March 31, 2006, there were five executive officers, approximately 300 employees other than executive officers and five non-employee directors who are eligible to receive awards. Except as described below under "--October 2005 Stock Awards Under the 2005 Omnibus Stock Award Plan," no determination has been made as to which of our employees will receive grants under the Omnibus Plan, and, therefore, the benefits to be allocated to any individual or to any group of employees are not otherwise presently determinable. The Omnibus Plan places limits on the maximum amount of awards that may be granted to any employee in any five year period. Under the Omnibus Plan, no employee may receive awards of stock options, stock appreciation rights, restricted stock, bonus shares, performance units, performance shares or deferred shares that cover in the aggregate more than 500,000 shares in any five year period. Non-employee directors may not be granted awards that are incentive stock options. Administration The Omnibus Plan will be administered by the board of directors or the Compensation Committee of the board of directors (the "Committee"). The board of directors or the Committee will select the eligible employees and non-employee directors to whom awards will be granted and will set the terms of such awards, including any performance goals applicable to annual and long-term incentive awards. The board of directors or the Committee has the authority to permit or require the deferral of payment of awards. The board of directors or the Committee may delegate its authority under the Omnibus Plan to our officers, subject to guidelines prescribed by the board of directors or the Committee, but only with respect to employees who are not subject to Section 16 of the Exchange Act or Section 162(m) of the Internal Revenue Code of 1986, as amended (the "Code"). Shares Reserved for Awards The Omnibus Plan provides for up to 2.2 million shares of common stock to be used for awards. The shares may be newly issued shares and to the extent that any award under the Omnibus Plan is exercised, cashed out, terminates, expires or is forfeited without payment being made in the form of common stock, the shares subject to such award that were not so paid will again be available for distribution under the Omnibus Plan. However, any shares withheld for the purpose of satisfying any tax withholding obligation will be counted against the authorized limit and not be available for distributions. If a stock appreciation right award or a similar award based on the spread value of common stock is exercised, only the number of shares of common stock issued, if any, will be considered delivered for the purpose of determining availability of shares for delivery under the Omnibus Plan. Unless otherwise determined by the Committee, stock options may be exercised by payment in cash or tendering shares of common stock to us in full or partial payment of the exercise price. 61 The number of shares of common stock authorized for awards is subject to adjustment for changes in capitalization, reorganizations, mergers, stock splits, and other corporate transactions as the board of directors or the Committee determines to require an equitable adjustment, including, for example the 2.5 to 1 reverse stock split that became effective October 31, 2005. See Items 1. and 2. "Business and Properties--Recent Developments--Recapitalization --Reverse Stock Split." The Omnibus Plan will remain in effect until all the shares available have been used to pay awards, subject to the right of the board of directors to amend or terminate the Omnibus Plan at any time. General Terms of Awards The board of directors or the Committee will select the grantees and set the term of each award, which may not be more than ten years. The board of directors or the Committee has the power to determine the terms of the awards granted, including the number of shares subject to each award, the form of consideration payable upon exercise, the period in which the award may be exercised after termination of employment, and all other matters. The exercise price of an option and the strike price of a stock appreciation right must be at least the fair market value of a share of common stock as of the grant date, unless the award is replacing an award granted by an entity that is acquired by us or one of our subsidiaries. The board of directors or the Committee will also set the vesting conditions of the award, except that vesting will be accelerated if, within one year after we undergo a "change of control," a grantee's employment or services is terminated by us or one of our majority owned subsidiaries other than for "cause" or the grantee terminates employment for a "good reason" (e.g., a material diminution in compensation or status or a required move of over 50 miles). Awards granted under the Omnibus Plan are not generally transferable by the grantee except in the event of the employee's death or unless otherwise required by law or provided in an award agreement. An award agreement may provide for the transfer of an award in limited circumstances to certain members of the grantee's family or a trust or trusts established for the benefit of such a family member. Any such transfer, if permitted under the award agreement, cannot be for consideration, other than nominal consideration. Other terms and conditions of each award will be set forth in award agreements, which can be amended by the board of directors or the Committee. Except as otherwise described below under "--October 2005 Stock Awards Under the 2005 Omnibus Stock Award Plan," the number and type of awards that will be granted under the Omnibus Plan is not determinable at this time as the board of directors or Committee will make these determinations in its sole discretion. Performance Awards Performance unit and performance share awards may be granted under the Omnibus Plan. Such awards will be earned only if corporate, business unit or individual performance objectives over performance cycles, established by or under the direction of the board of directors or the Committee, are met. The performance objectives may vary from participant to participant, group to group and period to period, and may be based on internal or external requirements, and will be based on satisfaction of performance objectives for one or more of the following: earnings per share, net income, return on equity, pro forma net income, return on designated assets, return on revenues, fair market value (i.e., market price) per share, book value per share, debt reduction or such other criteria approved by the board of directors or the Committee and the stockholders. Awards may be paid in the form of cash, common stock or any combination thereof, as determined by the board of directors or the Committee. Restricted Stock Restricted shares of common stock may also be awarded. The restricted shares will vest and become transferable upon the satisfaction of conditions set forth in the respective restricted share award agreement. Restricted share awards may be forfeited if, for example, the recipient's employment terminates before the award vests. Bonus Shares and Deferred Shares The board of directors or the Committee may grant shares of common stock to participants from time-to-time as a bonus. Such shares may be paid on a current basis or may be deferred and paid in the future. The board of directors or the Committee may impose such conditions or restrictions on any such deferred shares as it may deem advisable including time-vesting restrictions and deferred payment features. 62 Stock Options The Omnibus Plan will permit the grant of ISOs, which qualify for special tax treatment, to eligible employees, and nonqualified stock options to eligible employees and non-employee directors. The exercise price for any stock option will not be less than the fair market value of a share of common stock on the date of grant. No stock option may be exercised more than ten years after the date of grant. Stock Appreciation Rights Stock Appreciation Rights ("SARs") may be granted either singly (freestanding SARs) or in combination with underlying stock options (tandem SARs). SARs entitle the holder upon exercise to receive an amount in common stock equal in value to the excess of the fair market value of the shares covered by such right over the grant price. The grant price for SARs will not be less than the fair market value of the common stock on the SARs' date of grant. The payment upon a SAR exercise may be settled in whole shares of equivalent value, cash or a combination thereof. Fractional shares will be paid in cash. Change of Control Provisions The Omnibus Plan provides that, if, within the one-year period beginning on the date of a Change of Control (as defined in the Omnibus Plan) an employee separates from service with us or a majority owned subsidiary other than due to us terminating the employee's employment for cause or the employee resigning for good reason (e.g., a material diminution in compensation or status or a required move of over 50 miles), then, all stock options and SARs will become fully vested and immediately exercisable, the restrictions applicable to outstanding restricted stock, deferred shares, and other stock-based awards will lapse, and, unless otherwise determined by the board of directors or the Committee, all deferred shares will be settled, and outstanding performance awards will be vested and paid out on a prorated basis, based on the maximum award opportunity of such awards and the number of months elapsed compared with the total number of months in the performance cycle. The board of directors or the Committee may also make certain adjustments and substitutions in connection with a Change of Control or similar transactions or events as described under "--Shares Reserved for Awards." Federal Income Tax Consequences Based on current provisions of the Code and the existing regulations thereunder, the anticipated U.S. federal income tax consequences of stock options and SARs granted under the Omnibus Plan are as described below. The following discussion is not intended to be a complete discussion of applicable law and is based on the U.S. federal income tax laws as in effect on the date hereof: Non-Qualified Stock Options. An employee receiving a non-qualified option does not recognize taxable income on the date of grant of the non-qualified option, provided that the non-qualified option does not have a readily ascertainable fair market value at the time it is granted. In general, the employee must recognize ordinary income at the time of exercise of the non-qualified option in the amount of the difference between the fair market value of the shares of common stock on the date of exercise and the option price. The ordinary income recognized will constitute compensation for which tax withholding generally will be required. The amount of ordinary income recognized by an employee will be deductible by us in the year that the employee recognizes the income if we comply with the applicable withholding requirement. Shares of common stock acquired upon the exercise of a non-qualified option will have a tax basis equal to their fair market value on the exercise date or other relevant date on which ordinary income is recognized, and the holding period for the common stock generally will begin on the date of exercise or such other relevant date. Upon subsequent disposition of the common stock, the employee will recognize long-term capital gain or loss if the employee has held the common stock for more than one year prior to disposition, or short-term capital gain or loss if the employee has held the common stock for one year or less. If an employee pays the exercise price, in whole or in part, with previously acquired common stock, the employee will recognize ordinary income in the amount by which the fair market value of the shares of common stock received exceeds the exercise price. The employee will not recognize gain or loss upon delivering the previously acquired common stock to us. Common stock received by an employee, equal in number to the previously acquired shares of common stock exchanged therefore, will have the same basis and holding period for long-term capital gain purposes as the previously acquired common stock. Common stock received by an employee in excess of the number of such previously acquired shares of common stock will have a basis equal to the fair market value of the additional shares of common stock as of the date ordinary income is recognized. The holding period for the additional common stock will commence as of the date of exercise or such other relevant date. 63 Incentive Stock Options. As addressed above, ISOs will be granted under the Omnibus Plan if, and only if, the Omnibus Plan is approved by the stockholders. ISOs are defined by Section 422 of the Code. An employee who is granted an ISO does not recognize taxable income either on the date of grant or on the date of exercise. Upon the exercise of an ISO, the difference between the fair market value of the common stock received and the option price is, however, a tax preference item potentially subject to the alternative minimum tax. Upon disposition of shares of common stock acquired from the exercise of an ISO, long-term capital gain or loss is generally recognized in an amount equal to the difference between the amount realized on the sale or disposition and the exercise price. However, if the employee disposes of the common stock within two years of the date of grant or within one year of the date of the transfer of the shares of common stock to the employee (a "Disqualifying Disposition"), then the employee will recognize ordinary income, as opposed to capital gain, at the time of disposition. In general, the amount of ordinary income recognized will be equal to the lesser of (a) the amount of gain realized on the disposition, or (b) the difference between the fair market value of the common stock received on the date of exercise and the exercise price. Any remaining gain or loss is treated as a short-term or long-term capital gain or loss, depending on the period of time the common stock has been held. We are not entitled to a tax deduction upon either the exercise of an ISO or the disposition of common stock acquired pursuant to the exercise of an ISO, except to the extent that the employee recognizes ordinary income in a Disqualifying Disposition. For alternative minimum taxable income purposes, on the later sale or other disposition of the common stock, generally only the difference between the fair market value of the common stock on the exercise date and the amount realized on the sale or disposition is includable in alternative minimum taxable income. If an employee pays the exercise price, in whole or in part, with previously acquired common stock, the exchange should not affect the ISO tax treatment of the exercise. Upon the exchange, and except as otherwise described herein, no gain or loss is recognized by the employee upon delivering previously acquired shares of common stock to us as payment of the exercise price. The shares of common stock received by the employee, equal in number to the previously acquired common stock exchanged therefore, will have the same basis and holding period for long-term capital gain purposes as the previously acquired common stock. The employee, however, will not be able to utilize the prior holding period for the purpose of satisfying the ISO statutory holding period requirements. Common stock received by the employee in excess of the number of previously acquired common stock will have a basis of zero and a holding period which commences as of the date the common stock are transferred to the employee upon exercise of the ISO. If the exercise of any ISO is effected using common stock previously acquired through the exercise of an ISO, the exchange of the previously acquired common stock will be considered a disposition of the common stock for the purpose of determining whether a Disqualifying Disposition has occurred. Stock Appreciation Rights. To the extent that the requirements of the Code are met, there are no immediate tax consequences to an employee when a SAR is granted. When an employee exercises the right to the appreciation in fair market value of shares represented by a SAR, payments made in shares of common stock are normally includable in the employee's gross income for regular income tax purposes. We will be entitled to deduct the same amount as a business expense in the same year. The includable amount and corresponding deduction each equal the fair market value of the common stock payable on the date of exercise. Restricted Stock. The recognition of income from an award of restricted stock for federal income tax purposes depends on the restrictions imposed on the shares. Generally, taxation will be deferred until the first taxable year the common shares are no longer subject to substantial risk of forfeiture or the common shares are freely transferable. At the time the restrictions lapse, the grantee will recognize ordinary income equal to the then fair market value of the shares. The grantee may, however, make an election to include the value of the shares in gross income in the year such restricted shares are granted despite such restrictions. Generally, we will be entitled to deduct the fair market value of the shares transferred to the grantee as a business expense in the year the grantee includes the compensation in income. Deferred Shares. Generally, the grantee will not recognize ordinary income until common shares become payable under the deferred share award, even if the award vests in an earlier year. We will generally be entitled to deduct the amount the grantee includes in income as a business expense in the year of payment. 64 Other Stock-Based Performance Awards. Any cash payments or the fair market value of any common shares or other property the grantee receives in connection with other stock-based awards, incentive awards, or as unrestricted payments equivalent to dividends on unfunded awards or on restricted stock are includable in income in the year received or made available to the grantee without substantial limitations or restrictions. Generally, we will be entitled to deduct the amount the grantee includes in income as a business expense in the year of payment. Deferred Compensation. Any deferrals made under the Omnibus Plan, including awards granted under the plan that are considered to be deferred compensation, must satisfy the requirements of Section 409A of the Code to avoid adverse tax consequences to participating employees. These requirements include limitations on election timing, acceleration of payments, and distributions. We intend to structure any deferrals and awards under the Omnibus Plan to meet the applicable tax law requirements. Other Tax Consequences. State tax consequences may in some cases differ from those described above. Awards under the Omnibus Plan will in some instances be made to employees who are subject to tax in jurisdictions other than the United States and may result in tax consequences differing from those described above. Other Information The Omnibus Plan was effective October 14, 2005, and will remain in effect, subject to the right of the Board to amend or terminate the Omnibus Plan (subject to certain limitations set forth in the Omnibus Plan), at any time until all shares subject to it shall have been purchased or acquired according to the Omnibus Plan's provisions. Any awards granted before the Omnibus Plan is terminated may extend beyond the expiration date. The board of directors may amend the Omnibus Plan at any time, provided that no such amendment will be made without stockholder approval if such approval is required under applicable law, regulation, or stock exchange rule, or if such amendment would: (i) decrease the grant or exercise price of any stock option, SAR or other stock-based award to less than fair market value on the date of grant (except as discussed above under "--Shares Reserved for Awards"), (ii) increase the number of shares of common stock that may be distributed under the Omnibus Plan or adversely affect in any material way any award previously granted under the Omnibus Plan, without the written consent of the grantee of such award. October 2005 Stock Awards Under the 2005 Omnibus Stock Award Plan On October 14, 2005 our board of directors approved grants of 176,000 bonus shares of common stock (on a post-reverse stock split basis) to certain of our officers, subject to certain conditions. Two of our executive officers received a portion of these grants. Our Chief Financial Officer, David Grose, will receive (i) 16,000 bonus shares on January 1, 2007, regardless of whether he is employed by us on such date, (ii) an additional 16,000 bonus shares on January 1, 2007, provided he is employed (and has at all times from the date of the agreement been employed) by us on June 1, 2006, and (iii) 16,000 bonus shares on June 1, 2007, provided he is employed (and has at all times from the date of the agreement been employed) by us on June 1, 2007. Richard Marlin, Executive Vice President of Engineering, will receive (i) 12,000 bonus shares on January 1, 2007, provided he is employed (and has at all times from the date of the agreement been employed) by us on April 4, 2006, (ii) 12,000 bonus shares on April 4, 2007, provided he is employed (and has at all times from the date of the agreement been employed) by us on April 4, 2007, and (iii) 12,000 bonus shares on April 4, 2008 provided he is employed (and has at all times from the date of the agreement been employed) by us on April 4, 2008. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. None. ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES. Audit and Non-Audit Fees The following table lists fees paid to Murrell, Hall, McIntosh & Co., PPLP, for services rendered in the seven-month transition period ended December 31, 2004 and for the year ended December 31, 2005. 65 7 Months Ended Year Ended December 31, December 31, 2004 2005 ---------------- -------------- Audit Fees (1) $102,941 $ 173,376 Audit-Related Fees (2) -- 38,093 Tax Fees (3) 84,260 171,099 All Other Fees -- -- ---------------- -------------- Total Fees $ 187,201 $382,568 ================ ============== 1. Audit Fees include fees billed and expected to be billed for services performed to comply with Generally Accepted Auditing Standards (GAAS), including the recurring audit of the Company's consolidated financial statements for such period included in the Annual Report on Form 10-K and for the reviews of the consolidated quarterly financial statements included in the Quarterly Reports on Form 10-Q filed with the Securities and Exchange Commission. This category also includes fees for audits provided in connection with statutory filings or procedures related to audit of income tax provisions and related reserves, consents and assistance with and review of documents filed with the SEC. 2. Audit-Related Fees include fees for services associated with assurance and reasonably related to the performance of the audit or review of the Company's financial statements. This category includes fees related to assistance in financial due diligence related to mergers and acquisitions, consultations regarding Generally Accepted Accounting Principles, reviews and evaluations of the impact of new regulatory pronouncements, general assistance with implementation of the new SEC and Sarbanes-Oxley Act of 2002 requirements and audit services not required by statute or regulation. This category also includes audits of pension and other employee benefit plans, as well as the review of information systems and general internal controls unrelated to the audit of the financial statements. 3. Tax fees consist of fees related to the preparation and review of the Company's federal and state income tax returns and tax consulting services. The Audit Committee has concluded the provision of the non-audit services listed above as "Audit-Related Fees" and "Tax Fees" is compatible with maintaining the auditors' independence. All services to be performed by the independent public accountants must be pre-approved by the Audit Committee, which has chosen not to adopt any pre-approval policies for enumerated services and situations, but instead has retained the sole authority for such approvals. ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES. (a)(1) and (2) Financial Statements and Financial Statement Schedules. See "Index to Financial Statements" set forth on page F-1 of this Form 10-K. (a)(3) Index to Exhibits. Exhibits requiring attachment pursuant to Item 601 of Regulation S-K are listed in the Index to Exhibits beginning on page 68 of this Form 10-K that is incorporated herein by reference. 66 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized this 31st day of March, 2006. Quest Resource Corporation /s/ Jerry D. Cash ----------------------------- Jerry D. Cash Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

---------------------------------------- -------------------------------------- -------------------------------------- Signature Title Date ---------------------------------------- -------------------------------------- -------------------------------------- /s/ Jerry D. Cash Director and Chief Executive Officer March 31, 2006 ---------------------- (principal executive officer) Jerry D. Cash ---------------------------------------- -------------------------------------- -------------------------------------- /s/ Jon H. Rateau Director March 31, 2006 ---------------------- Jon H. Rateau ---------------------------------------- -------------------------------------- -------------------------------------- /s/ Ronnie K. Irani Director March 31, 2006 ---------------------- Ronnie K. Irani ---------------------------------------- -------------------------------------- -------------------------------------- /s/ Kevin R. White Director March 31, 2006 ---------------------- Kevin R. White ---------------------------------------- -------------------------------------- -------------------------------------- /s/ John C. Garrison Director March 31, 2006 ---------------------- John C. Garrison ---------------------------------------- -------------------------------------- -------------------------------------- /s/ James B. Kite, Jr. Director March 31, 2006 ---------------------- James B. Kite, Jr. ---------------------------------------- -------------------------------------- -------------------------------------- /s/ David E. Grose Principal Financial and Accounting March 31, 2006 ---------------------- Officer David E. Grose ---------------------------------------- -------------------------------------- --------------------------------------

67 INDEX TO EXHIBITS Exhibit No. Description 2.1* Stock Purchase Agreement by and among Perkins Oil Enterprises, Inc. and E. Wayne Willhite Energy, L.L.C, as Sellers, and Ponderosa Gas Pipeline Company, Inc. and Quest Resource Corporation, as Purchasers, dated as of April 1, 2003 (incorporated herein by reference to Exhibit 2.1 to the Company's Quarterly Report on Form 10-QSB filed on April 14, 2003). 2.2* Purchase and Sale Agreement by and among James R. Perkins Energy, L.L.C., E. Wayne Willhite Energy, L.L.C., and J-W Gas Gathering, L.L.C., as Sellers, and Quest Oil & Gas Corporation, as Purchaser, dated as of April 1, 2003 (incorporated herein by reference to Exhibit 2.2 to the Company's Quarterly Report on Form 10-QSB filed on April 14, 2003). 2.3* Purchase and Sale Agreement by and between Devon Energy Production Company, L.P., Tall Grass Gas Services, L.L.C., and Quest Resource Corporation, dated as of the 10th day of December, 2003 (incorporated herein by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K filed on January 6, 2004). 2.4* Assignment Agreement by and between Quest Resource Corporation and Quest Cherokee, LLC, dated as of the 22nd day of December, 2003, assigning the Purchase and Sale Agreement (incorporated herein by reference to Exhibit 2.4 to the Company's Annual Report on Form 10-KSB filed on September 20, 2004). 2.5* Hold Back Agreement by and between Devon Energy Production Company, L.P. and Quest Cherokee, LLC, dated as of the 22nd day of December, 2003 (incorporated herein by reference to Exhibit 2.3 to the Company's Current Report on Form 8-K filed on January 6, 2004). 2.6* Contribution, Conveyance, Assignment and Assumption Agreement by and between Quest Oil & Gas Corporation, Quest Energy Service, Inc., STP Cherokee, Inc., Ponderosa Gas Pipeline Company, Inc., Producers Service Incorporated, J-W Gas Gathering, L.L.C., Quest Cherokee, LLC and Bluestem Pipeline, LLC, dated as of the 22nd day of December, 2003 (incorporated herein by reference to Exhibit 2.4 to the Company's Current Report on Form 8-K filed on January 6, 2004). 2.7* Agreement for Purchase and Sale of Units, dated as of November 7, 2005, by and among Cherokee Energy Partners, LLC, STP Cherokee, Inc., Quest Oil & Gas Corporation, Quest Energy Service, Inc., Ponderosa Gas Pipeline Company, Inc., Producers Service, Incorporated and J-W Gas Gathering, L.L.C. (incorporated herein by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K filed on November 18, 2005). 3.1* The Company's Restated Articles of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company's Registration Statement on Form 8-A12G/A (Amendment No. 2) filed on December 7, 2005). 3.2* The Second Amended and Restated Bylaws of the Company (incorporated herein by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K filed on October 18, 2005). 4.1* Specimen of certificate for shares of Common Stock (incorporated herein by reference to Exhibit 4.1 to the Company's Registration Statement on Form 8-A12G/A (Amendment No. 2) filed on December 7, 2005). 4.2 Amended and Restated Senior Credit Agreement by and among Quest Resource Corporation, Quest Cherokee, LLC, Guggenheim Corporate Funding, LLC, and the Lenders party thereto, dated as of the 7th day of February, 2006. 4.3* Second Lien Term Loan Agreement by and among Quest Resource Corporation, Quest Cherokee, LLC, Guggenheim Corporate Funding, LLC, and the Lenders party thereto, dated as of the 14th day of November, 2005 (incorporated herein by reference to Exhibit 4.3 to the Company's Registration Statement on Form S-1 filed on December 12, 2005. 68 4.4 Amended and Restated Security Agreement for Senior Credit Agreement by Quest Cherokee, LLC, Quest Resource Corporation, and the Guarantors party thereto in favor of Guggenheim Corporate Funding, LLC, dated as of the 7th day of February, 2006. 4.5* Security Agreement for Second Lien Term Loan Agreement by Quest Cherokee, LLC, Quest Resource Corporation, and the Guarantors party thereto in favor of Guggenheim Corporate Funding, LLC, dated as of the 14th day of November, 2005 (incorporated herein by reference to Exhibit 4.5 to the Company's Registration Statement on Form S-1 filed on December 12, 2005. 4.6* Guaranty for Senior Credit Agreement by Bluestem Pipeline, LLC, J-W Gas Gathering, L.L.C., Ponderosa Gas Pipeline Company, Inc., Producers Service Incorporated, Quest Cherokee Oilfield Service, LLC, Quest Energy Service, Inc., Quest Oil & Gas Corporation, and STP Cherokee, Inc. in favor of Guggenheim Corporate Funding, LLC, dated as of the 14th day of November, 2005 (incorporated herein by reference to Exhibit 4.6 to the Company's Registration Statement on Form S-1 filed on December 12, 2005). 4.7* Guaranty for Second Lien Term Loan Agreement by Bluestem Pipeline, LLC, J-W Gas Gathering, L.L.C., Ponderosa Gas Pipeline Company, Inc., Producers Service Incorporated, Quest Cherokee Oilfield Service, LLC, Quest Energy Service, Inc., Quest Oil & Gas Corporation, and STP Cherokee, Inc. in favor of Guggenheim Corporate Funding, LLC, dated as of the 14th day of November, 2005 (incorporated herein by reference to Exhibit 4.7 to the Company's Registration Statement on Form S-1 filed on December 12, 2005). 4.8 Amended and Restated Intercreditor Agreement by and among Quest Resource Corporation, Quest Cherokee, LLC, STP Cherokee, Inc., Quest Oil & Gas Corporation, Quest Energy Service, Inc., Ponderosa Gas Pipeline Company, Inc., Producers Service, Incorporated, J-W Gas Gathering, LLC, Bluestem Pipeline, LLC, Quest Cherokee Oilfield Service, LLC, and Guggenheim Corporate Funding, LLC, dated as of the 7th day of February, 2006. 4.9* Mortgage, Deed of Trust, Security Agreement, Financing Statement and Assignment of Production by Quest Cherokee, LLC, to Guggenheim Corporate Funding, LLC, dated November 14, 2005 (incorporated herein by reference to Exhibit 4.9 to the Company's Registration Statement on Form S-1 filed on December 12, 2005). 10.1* Employment Agreement dated as of October 17, 2005 between the Company and Jerry D. Cash (incorporated herein by reference to Exhibit 10.1 to the Company's Registration Statement on Form S-1 filed on December 12, 2005). 10.2* Employment Agreement dated as of October 17, 2005 between the Company and David Grose (incorporated herein by reference to Exhibit 10.2 to the Company's Registration Statement on Form S-1 filed on December 12, 2005). 10.3* Non-Competition Agreement by and between Quest Resource Corporation, Quest Cherokee, LLC, Cherokee Energy Partners LLC, Quest Oil & Gas Corporation, Quest Energy Service, Inc., STP Cherokee, Inc., Ponderosa Gas Pipeline Company, Inc., Producers Service Incorporated and J-W Gas Gathering, L.L.C., dated as of the 22nd day of December, 2003 (incorporated herein by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K filed on January 6, 2004). 10.4* Interest Rate Cap Transaction Agreements between Quest Cherokee L.L.C. and UBS AG London Branch dated September 21, 2004 (incorporated herein by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-QSB filed on February 24, 2005). 10.5* Summary of director compensation arrangements (incorporated herein by reference to Exhibit 10.5 to the Company's Registration Statement on form S-1 filed on December 12, 2005). 10.6* Summary of executive officer compensation arrangements (incorporated herein by reference to Exhibit 10.6 to the Company's Registration Statement on Form S-1 filed on December 12, 2005). 69 10.7* Company's 2005 Omnibus Stock Award Plan (incorporated herein by reference to Exhibit 10.7 to the Company's Registration Statement on Form S-1 filed on December 12, 2005). 10.8* Form of the Company's 2005 Omnibus Stock Award Plan Nonqualified Stock Option Agreement (incorporated herein by reference to Exhibit 10.8 to the Company's Registration Statement on Form S-1 filed on December 12, 2005). 10.9* Form of the Company's 2005 Omnibus Stock Award Plan Bonus Shares Award Agreement (incorporated herein by reference to Exhibit 10.9 to the Company's Registration Statement on Form S-1 filed on December 12, 2005). 10.10* Purchase/Placement Agreement by and among Quest Resource Corporation, Quest Cherokee, LLC, Bluestem Pipeline, LLC, Quest Cherokee Oilfield Service, LLC, and Friedman, Billings, Ramsey & Co., Inc., dated as of the 7th day of November, 2005 (incorporated herein by reference to Exhibit 10.10 to the Company's Registration Statement on Form S-1 filed on December 12, 2005). 10.11 Form of Indemnification Agreement with Directors and Executive Officers. 21.1* List of Subsidiaries (incorporated herein by reference to Exhibit 21.1 to the Company's Annual Report on Form 10-KSB filed on March 31, 2005). 23.1 Consent of Cawley and Gillespie & Associates, Inc. 23.2 Consent of Murrell, Hall, McIntosh & Co., PLLP. 31.1 Certification by Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification by Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1 Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. ------------ * Incorporated by reference. 70