Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.

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.

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

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, 2006, the last business day of the registrant’s most recently completed second fiscal quarter, at $13.55 per share was $267,070,066. This figure assumes that only the directors and officers of the registrant, their spouses and controlled corporations were affiliates. There were 22,206,014 shares outstanding of the registrant’s common stock as of March 6, 2007.

The definitive proxy statement relating to the issuer’s 2007 Annual Meeting of Stockholders is incorporated by reference in Part III to the extent described therein.

This Amendment No. 2 on Form 10-K/A (this “Amendment 2”) to the Annual Report on Form 10-K, originally filed with the Securities and Exchange Commission on March 16, 2007 (the “Original Filing”), as amended by Amendment No. 1 on Form 10-K/A filed with the Securities and Exchange Commission on May 3, 2007 (the “Amendment 1”) of Quest Resource Corporation (the “Company”), is being filed to make the following revisions:

Statements”, (iv) in Note 17. SFAS 69 Supplemental Disclosures (Unaudited)—Natural Gas and Oil Reserve Quantities under “Item 8. Financial Statements—Notes to Consolidated Financial Statements”, and (v) in Note 17. SFAS 69 Supplemental Disclosures (Unaudited)—Standardized Measure of Discounted Future Net Cash Flows under “Item 8. Financial Statements—Notes to Consolidated Financial Statements”.

This Amendment 2 amends and restates only the information in Items 1, 1A and 2 of Part I, Items 6, 7 and 8 of Part II and Item 15 of Part IV of the Original Filing, as modified by Amendment 1, and no other information in the Original Filing, as modified by Amendment 1, is amended hereby. Except for the foregoing amended and restated information, this Amendment 2 speaks as of the filing date of the Original Filing and does not update or discuss any other Company developments after the date of the Original Filing. Accordingly, this Amendment 2 should be read in conjunction with the Company’s filings made with the Securities and Exchange Commission after the filing of the Original Filing on March 16, 2007.

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 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 wells and 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 was a wholly-owned subsidiary of Quest Cherokee until the formation and contribution of our midstream assets to Quest Midstream Partners, L.P. on December 22, 2006.

Quest Cherokee Oilfield Service, 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 that work on our natural gas and oil wells. QCOS is a wholly-owned subsidiary of Quest Cherokee.

QES, QOG, PGPC and STP are wholly-owned by Quest. PGPC owns all of the outstanding member interests 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.

On December 13, 2006, we formed Quest Midstream to own and operate our natural gas gathering pipeline system. On December 22, 2006, we transferred Bluestem to Quest Midstream in exchange for 4.9 million class B subordinated units, 35,134 class A subordinated units and a 2% general partner interest. Also on December 22, 2006, Quest Midstream sold 4,864,866 common units, representing an approximate 48.64% interest in Quest Midstream, for $18.50 per common unit, or approximately $90 million of gross proceeds, pursuant to a purchase agreement dated December 22, 2006, to a group of institutional investors led by Alerian Capital Management, LLC, and co-led by Swank Capital, LLC.

owns 75 Member Interests representing a 7.5% ownership interest in Quest Midstream GP and Swank owns 75 Member Interests representing a 7.5% ownership interest in Quest Midstream GP.

Quest Midstream GP’s sole business activity is to act as the general partner of Quest Midstream and employs approximately 46 personnel that perform activities primarily related to the pipeline infrastructure.

See “—Recent Developments” for additional information regarding our formation of Quest Midstream.

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, the calendar year ended December 31, 2005 and the calendar year ended December 31, 2006.

A Glossary of Oil and Gas Terms is included in this report beginning on page 23.

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 15 county region in southeastern Kansas and northeastern Oklahoma known as the Cherokee Basin. As of December 31, 2006, we had 198.2 Bcfe of net proved reserves. Our reserves are approximately 99% CBM and 60.4% proved developed. We believe we are the largest producer of natural gas in the Cherokee Basin with an average net daily production of 33.8 mmcfe for the year ended December 31, 2006. Our average reserve-to-production ratio is 16 years (7.63 years for our proved developed properties) based on our reserves as of December 31, 2006 and our production (12.34 Bcfe) for the year ended December 31, 2006. Based on our current rate of new well development and our current undeveloped acreage, we estimate that it would take us approximately 4.87 years to fully develop our existing acreage, using 160 acre spacing. In addition, the standard economic life of our typical Cherokee Basin well is approximately 15 years.

As of December 31, 2006, we owned the development rights to 523,929 net CBM acres throughout the Cherokee Basin and had developed approximately 46% of our acreage. We presently operate approximately 1,650 producing gas and oil wells. Our undeveloped acreage contains approximately 1,760 proved undeveloped CBM drilling locations. Over 99% of the CBM wells that have been drilled on our acreage to date 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 through Quest Midstream, a gas gathering pipeline network of approximately 1,600 miles that serves our acreage position. Presently, this system has a maximum daily throughput of 70 mmcf/d and is operating at about 77% 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, 2006, we had an inventory of approximately 250 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 through Quest Midstream to serve other areas of the Cherokee Basin where we intend to acquire additional CBM acreage for development.

On June 9, 2006, we and Quest Cherokee entered into a $75 million six-year Third Lien Term Loan Agreement among us, Quest Cherokee, Guggenheim Corporate Funding, LLC (“Guggenheim”), as administrative agent, and the lenders party thereto that was fully funded at the closing. See Note 3 to our consolidated financial statements included elsewhere in this report for additional information regarding our third lien term loan facility.

On December 13, 2006, we formed Quest Midstream to own and operate our natural gas gathering pipeline system. On December 22, 2006, Quest Midstream sold 4,864,866 common units, representing an approximate 48.64% interest in Quest Midstream, for $18.50 per common unit, or approximately $90 million of gross proceeds, pursuant to a purchase agreement dated December 22, 2006, to a group of institutional investors led by Alerian, and

co-led by Swank. The investors consisted of Alerian Opportunity Partners IV, LP (“Alerian”), Swank MLP Convergence Fund, LP (“Swank MLP Fund”), Swank Investment Partners, LP (“SIP”), The Cushing MLP Opportunity Fund I, LP (“Cushing MLP Fund”), The Cushing GP Strategies Fund, LP (“Cushing GP Fund”, together with Swank MLP Fund, SIP and Cushing MLP Fund, “Swank”), Tortoise Capital Resources Corporation (“Tortoise”), Huizenga Opportunity Partners, LP (“Huizenga”) and HCM Energy Holdings, LLC (“HCM” and together with Alerian, Swank, Tortoise and Huizenga, collectively, the “Investors”). In addition, investors that purchased more than $25 million of limited partner interests in Quest Midstream (that is, Alerian and Swank) were able to purchase an aggregate 15% of the member interests of Quest Midstream GP, Quest Midstream’s general partner, for a nominal amount of $150. Quest Midstream GP owns 200,000 general partner units and all of the incentive distribution rights in Quest Midstream and we own 35,134 class A subordinated units and 4,900,000 class B subordinated units. Since we continue to own a majority of the partner interests in Quest Midstream and 85% of the member interests in Quest Midstream GP, the financial statements of Quest Midstream are consolidated with our financial statements.

As part of these transactions, we contributed all of the member interests in Bluestem, which owns our natural gas gathering pipeline system, to Quest Midstream. As a result, Bluestem is now a wholly-owned subsidiary of Quest Midstream.

The proceeds of the offering were used as follows: (i) $40 million was used to repay the outstanding indebtedness under our revolving credit facility, (ii) approximately $5.2 million was used to repay trade payables incurred in connection with the construction and operation of Bluestem’s natural gas gathering pipeline network, (iii) approximately $8 million was used to pay fees and expenses related to these transactions, and (iv) the remaining funds of approximately $36.8 million were distributed to us and will be used for future development and acquisition activities in the Cherokee Basin. Of this amount, $15 million was initially to be retained by Quest Midstream as temporary working capital until the partnership obtained its own working capital facility on January 31, 2007, at which time the $15 million was distributed to us.

See our Form 8-K filed December 29, 2006 for additional information regarding the formation of Quest Midstream and the terms of the transaction.

Investors’ Rights Agreement. In connection with the formation of Quest Midstream, we, Quest Midstream and Quest Midstream GP entered into an investors’ rights agreement dated as of December 22, 2006 with the Investors. Pursuant to the terms of the investors’ rights agreement, Alerian and Swank each received a separate and independent right to designate one natural person to serve as a member of Quest Midstream GP’s board of directors. We have the right to designate the remaining four members of the board of directors of Quest Midstream GP (two of whom must be independent directors). Swank’s right to designate a member of the board of directors terminates upon the completion by Quest Midstream of an initial public offering. In addition, the right to designate a member of Quest Midstream GP’s board of directors terminates as to Alerian or Swank if it ceases to own at least 5% of Quest Midstream’s common units (on a fully diluted basis) that are not held by us and our affiliates.

Subject to certain exceptions set forth in the investors’ rights agreement, if Quest Midstream has not completed an initial public offering by December 22, 2008, then until such time as an initial public offering is completed by Quest Midstream, the Investors, acting by majority vote, may require Quest Midstream GP to effect a sale of either all of Quest Midstream’s assets or partner interests. If the Investors make such an election, Quest Midstream GP will have the right to offer to purchase all of the Investors’ interests in Quest Midstream. If Quest Midstream GP’s offer is not accepted, Quest Midstream GP will be obligated to undertake to solicit offers for all of the assets or partner interests of Quest Midstream as promptly as commercially reasonable with a view to maximizing the aggregate consideration to be received for such sale. The offers must meet certain minimum requirements that are contained in the investors’ rights agreement. If a qualifying offer is accepted by a majority of the Investors, we and the other Investors will be required to participate in the sale. Subject to certain limitations, Quest Midstream GP will have a right of first refusal to match any offer accepted by a majority of the Investors.

If a change of control of us occurs, a majority of Investors will have the right to cause Quest Midstream GP to affect a sale of Quest Midstream following the same procedures described above, if an initial public offering for Quest Midstream is not completed within half of the number of days remaining between the change of control date and December 22, 2008.

In connection with any such sale of the assets or partner interests of Quest Midstream, the Investors will be entitled to a return of their initial investment (plus a 10% premium) and any unpaid distributions before any funds will be distributed to us on account of our general partner and subordinated units. If the sale is not completed within

180 days after the Investors’ inform Quest Midstream GP that they desire to exercise their right to require a sale of Quest Midstream, the premium will increase by 750 basis points each quarter, until it reaches a maximum of 40%.

Subject to certain exceptions, any issuances of additional partner interests by Quest Midstream for less than 115% of the price at which the common units were issued to the Investors will require the consent of the representatives of Swank and Alerian serving on the board of directors of Quest Midstream GP.

If we and our affiliates desire to dispose of all or substantially all of our collective Quest Midstream partner interests and our collective general partner member interests to a non-affiliated third-party, then the Investors will have the right to participate in such transaction. We also have the right to require the Investors to participate in such a transaction if certain conditions are satisfied.

If we desire to sell a majority of our member interests in Quest Midstream GP, Alerian and Swank will have a right of first refusal to acquire the member interests being transferred.

Except for Alerian’s right to designate a member to serve on Quest Midstream GP’s board of directors, the investors’ rights agreement terminates upon the completion of an initial public offering of Quest Midstream, which results in the common units of Quest Midstream being listed on the Nasdaq Global Market or the New York Stock Exchange.

Omnibus Agreement. In connection with the transactions contemplated by the purchase agreement, we, Quest Midstream, Quest Midstream GP and Bluestem entered into an omnibus agreement dated as of December 22, 2006. The omnibus agreement governs (i) the obligations of us and our affiliates to refrain from engaging in certain business opportunities that compete with Quest Midstream, (ii) our obligations to indemnify Quest Midstream, Quest Midstream GP and Bluestem against certain environmental and other liabilities that occurred or existed prior to the closing date, (iii) the obligation of Quest Midstream to reimburse us for certain insurance, operating and general and administrative expenses incurred on behalf of Quest Midstream (subject to certain limitations), (iv) a right of first offer allowing Quest Midstream to acquire certain of our assets in the event of a sale or transfer of such assets, and (v) an option allowing Quest Midstream to provide midstream services for any acreage located outside the Cherokee Basin that we or any of our affiliates may acquire in the future.

Midstream Services and Gas Dedication Agreement. We and Bluestem entered into a midstream services and gas dedication agreement on December 22, 2006. Pursuant to the midstream services agreement, Bluestem agreed to gather and provide certain midstream services to us for all natural gas produced from wells in a 15-county area in Kansas and Oklahoma known as the Cherokee Basin that are connected to Bluestem’s gathering system. The term of the midstream services agreement is ten years, with two additional five-year periods. Under the midstream services agreement, we will pay Bluestem $0.50 per thousand cubic feet (“mcf”) of gas for gathering, dehydration and treating services and $1.10 per mcf of gas for compression services, subject to annual adjustment based on changes in natural gas prices and the producers price index. Such fees are subject to renegotiation in connection with each renewal term.

Bluestem has the option to connect all of the natural gas wells that we develop in the Cherokee Basin to its gathering system. In addition, Bluestem is required to connect to its gathering system, at its expense, any new natural gas well(s) that we complete in the Cherokee Basin if Bluestem would earn a specified internal rate of return from those wells. We also committed to drill a total of 750 new wells in the Cherokee Basin by December 22, 2008.

First Amended and Restated Agreement of Limited Partnership of Quest Midstream Partners, L.P. In connection with the closing of the purchase agreement, we and Quest Midstream GP entered into the first amended and restated agreement of limited partnership of Quest Midstream Partners, L.P., which sets forth our rights and obligations with respect to Quest Midstream.

Under the partnership agreement, during the subordination period, the common units in Quest Midstream have the right to receive quarterly distributions of available cash from operating surplus (each as defined in the partnership agreement) in an amount equal to the minimum quarterly distribution of $0.425 per common unit plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. No arrearages will be paid on the subordinated units during the subordination period.

The class A subordinated units will automatically convert on a one-for-one basis to common units upon the completion by Quest Midstream of an initial public offering. Generally, the subordination period for the class B

subordinated units will extend until the first day of any quarter beginning after December 22, 2013 or, if an initial public offering by Quest Midstream has occurred, the fifth anniversary of the closing of the initial public offering that certain financial tests are met. Generally, upon expiration of the subordination period for the class B subordinated units; each outstanding class B subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash.

If the tests for ending the subordination period are satisfied for any three consecutive four-quarter periods ending on or after the last day of the quarter containing the third anniversary of the initial public offering of Quest Midstream, 25% of the subordinated units will convert into an equal number of common units. Similarly, if those tests are also satisfied for any three consecutive four-quarter periods ending on or after the last day of the quarter containing the fourth anniversary of the initial public offering of Quest Midstream, an additional 25% of the subordinated units will convert into an equal number of common units. The second early conversion of subordinated units may not occur, however, until at least one year following the end of the period for the first early conversion of subordinated units.

The partnership agreement sets forth the levels of distributions to be made to each of the common unit holders and Quest Midstream GP of available cash from operating surplus for any quarter during and after the subordination period. The partnership agreement provides that Quest Midstream GP initially will be entitled to 2% of all distributions that Quest Midstream makes prior to its liquidation. Quest Midstream GP has the right, but not the obligation, to contribute a proportionate amount of capital to Quest Midstream to maintain its 2% general partner interest if Quest Midstream issues additional units. Quest Midstream GP’s 2% interest, and the percentage of Quest Midstream’s cash distributions to which it is entitled, will be proportionately reduced if Quest Midstream issues additional units in the future and Quest Midstream GP partner does not contribute a proportionate amount of capital to Quest Midstream in order to maintain its 2% general partner interest.

The incentive distribution rights in Quest Midstream represent the right to receive an increasing percentage (13%, 23% and 48%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and certain specified target distribution levels have been achieved. Quest Midstream GP partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.

Quest Midstream GP, as the holder of our incentive distribution rights, has the right under the partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to Quest Midstream GP would be set. Such reset right may be exercised, without approval of the unit holders or the conflicts committee of Quest Midstream GP, at any time when there are no subordinated units outstanding and Quest Midstream has made cash distributions with respect to the incentive distribution rights at the highest level for each of the prior four consecutive fiscal quarters.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by Quest Midstream GP of incentive distribution payments, Quest Midstream GP will be entitled to receive a number of newly issued class C units based on a formula that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by Quest Midstream GP for the two quarters prior to the reset event as compared to the average cash distributions per common unit during this period.

Following a reset election by Quest Midstream GP, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that Quest Midstream would distribute all of its available cash from operating surplus for each quarter as set forth in the partnership agreement.

Quest Midstream GP may not be removed except with the vote of two-thirds of all of the outstanding units (including those owned by us and our affiliates).

Amended and Restated Limited Liability Company Agreement of Quest Midstream GP, LLC. In connection with the closing of the purchase agreement, we, Alerian and Swank entered into the amended and restated limited liability company agreement of Quest Midstream GP, which sets forth our rights and obligations with respect to Quest Midstream GP.

Quest Midstream GP limited liability company agreement requires all available cash (as defined in the agreement) to be distributed each quarter pro rata among the members in proportion to their member interests. Subject to certain exceptions, if Quest Midstream GP issues additional member interests, each member has a pre-emptive right to acquire additional member interests in order to maintain its percentage ownership in Quest Midstream GP.

If a member desires to transfer its member interests in Quest Midstream GP, Quest Midstream GP and then we (in that order) have a right of first refusal to acquire the member interests being transferred.

If we desire to transfer more than 50% of the member interests, then we have the option to require Alerian and Swank to participate in the sale on the same terms (the drag-along right). If we do not exercise our drag-along right, then Alerian and Swank have the right to elect to participate in the transfer on the same terms and conditions (the tag-along right). These rights are in addition to those described above with respect to the investors’ rights agreement.

In addition, on December 22, 2006, we entered into amendments to our current credit facilities. Among other things, the amendments permitted us to transfer the member interests in Bluestem to Quest Midstream, released the security interests of the lenders in the member interests and assets of Bluestem and resulted in the pledge of our class A and class B subordinated partner interests in Quest Midstream and our 85% member interest in Quest Midstream GP as collateral for these credit facilities. In addition, the prepayment premiums for the Second Lien Term Loan and Third Lien Term Loan were amended. See Note 3 to our consolidated financial statements included elsewhere in this report for additional information regarding the amendments to our credit facilities.

On January 31, 2007, Bluestem and Quest Midstream entered into a $75 million five-year revolving credit facility. The Credit Agreement is among Bluestem, as the borrower, Quest Midstream, as a guarantor, Royal Bank of Canada (“RBC”), as administrative agent and collateral agent, and the lenders party thereto. The credit facility is secured by all of the member interests in Bluestem and substantially all of Bluestem’s assets. See our Form 8-K filing dated February 7, 2007 for further information regarding Quest Midstream’s credit facility.

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:

develop our existing acreage, using 160 acre spacing. In addition, the standard economic life of our typical Cherokee Basin well is approximately 15 years. We believe this long reserve life reduces the reinvestment risk associated with our asset base.

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 lime stones, which were developed beginning in the early 1900s.

The Cherokee Basin is part of the Western Interior Coal Region of the central United States. The coal seams we target for development are 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 average cost for 2006 to drill and complete a well and to build the related pipeline infrastructure was approximately $180,000. We estimate that for 2007, our average cost for drilling and completing a well will be approximately $135,000 and Quest Midstream’s average cost for building the related pipeline infrastructure will be approximately $60,000 per well. We perforate and frac the multiple coal seams present in each well. Our typical Cherokee Basin multi-seam CBM well has net reserves of 130 mmcf. Our general production profile for a CBM well averages an initial 15-20 mcf/d (net), steadily rising for the first 12 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 approximately 12 months. After 24 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. During the year ended December 31, 2006, we recompleted approximately 146 wellbores in Kansas and an additional 5 wellbores in Oklahoma and we had an additional 150 wellbores 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 approximately $20,000 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, we believe the impact of the multi-seam recompletions will be positive as a result of an increase in the rate of production and the ultimate recoverable reserves available per well.

Wells are equipped with small pumping units to facilitate the 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.

As of December 31, 2006, we controlled approximately 542,000 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, 2006: estimated gross natural gas proved reserves of 242.4 Bcf, of which 198.2 Bcf is net to the Company, and estimated proved oil reserves of 40,800 gross (32,272 net) barrels.

As of December 31, 2006, we were producing natural gas from approximately 1,650 wells (gross). Our total daily natural gas sales (including pipeline-earned volume) as of December 31, 2006 were approximately 40.8 mcf/d net (54.4 mcf/d gross).

We have a significant amount of acreage available for development. As of December 31, 2006, we had leases with respect to approximately 283,000 net undeveloped acres. For the year ended December 31, 2006, we drilled approximately 622 gross wells and connected 638 gross wells to our pipeline systems. We intend to drill approximately 550 gross wells annually during 2007 and 2008. We have identified approximately 1,760 proved undeveloped drilling locations and many more probable and possible drilling locations. Management believes that we have the necessary expertise, manpower and equipment capabilities required to carry out these development plans. Management believes that significant additional value will be created 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.

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 99%.

The following table sets forth certain information regarding our ownership of productive wells and total acreage, as of December 31, 2006, 2005 and 2004. For purposes of this table, productive wells are wells currently in production and wells capable of production.

As of December 31, 2006, we had 241,634 net developed acres and 282,922 net undeveloped acres.

During the year ended December 31, 2006, we drilled 622 gross (605.8 net) new wells on our properties, all being 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, 2006, we continued to lease additional acreage in certain core development areas of the Cherokee Basin.

The following table summarizes the reserve estimate and analysis of net proved reserves of natural gas and oil as of December 31, 2006, 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 value of estimated future net revenues from these reserves was calculated on a non-escalated price basis. During 2006, we filed estimates of our natural gas and oil reserves for the year 2005 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%.

The Company’s total proved reserves increased from 134.5 bcfe as of December 31, 2005 to 198.0 bcfe as of December 31, 2006.

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 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.

Our proved reserves will generally decline as they are produced, except to the extent that we conduct revitalization activities, or acquire 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 our 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 is a speculative activity and the possibility always exists that newly drilled wells will be non-productive or fail to produce enough revenue to be commercially worthwhile.

The following table sets forth certain information regarding the natural gas and oil properties owned by us through our 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 Mos		Year Ended
		December 31,						May 31,
		2006		2005		2004		2004
		(Restated)
Avg Sales Price (excluding effects of hedging):
Gas ($ per mcf)	$	5.93	$	7.44	$	5.74	$	5.19
Oil ($ per bbl)	$	58.95	$	53.46	$	44.14	$	41.06
Gas equivalent ($ per mcfe)	$	5.95	$	7.45	$	5.77	$	5.02
Avg Sales Price (including effects of hedging):
Gas ($ per mcf)	$	5.29	$	4.61	$	4.83	$	5.04
Oil ($ per bbl)	$	58.95	$	53.46	$	44.14	$	41.06
Gas equivalent ($ per mcfe)	$	5.31	$	4.63	$	4.79	$	5.04
Expenses ($ per mcfe):
Lifting	$	1.29	$	0.98	$	0.72	$	0.91
Production and property tax	$	0.55	$	0.58	$	0.37	$	0.34
Net Revenue ($ per mcfe)	$	3.47	$	3.07	$	3.70	$	3.79

For purposes of the table below, the number of wells drilled refers to the number of wells completed at any time during the period, regardless of when drilling was initiated. 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, 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:

The 638 gross new natural gas wells completed for the year ended December 31, 2006 reflect an average activity level of approximately 53 gross wells per month. We plan to drill and complete an average of approximately 46 gross wells per month for year 2007, subject to capital being available for such expenditures.

During the period from December 31, 2006 through March 6, 2007, we drilled 79 gross wells and connected 74 gross wells. As of March 6, 2007, we were drilling 11 gross wells and approximately 5 gross wells were in the process of being completed.

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 2006. More than 95% of our natural gas was sold to ONEOK Energy Marketing and Trading Company in 2005 and in the seven month transition period ended December 31, 2004. More than 90% of our 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 years ended December 31, 2006 and 2005, the transition period ended December 31, 2004 or the fiscal year ended May 31, 2004.

Our oil is currently being sold to Coffeyville Refining. Previously, it had been sold to Plains Marketing, LP. We do not have a long-term contract for our oil sales.

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, 2006. See Note 15 —Derivatives, in notes to consolidated financial statements of this Form 10-K.

	Years Ending December 31,
	2007			2008			Total
		(Dollars in thousands, except price data)
Natural Gas Collars:
Contract vols (MMBtu):
Floor			8,433,000		7,027,000			15,460,000
Ceiling			8,433,000		7,027,000			15,460,000
Weighted-avg fixed price per MMBtu (1):
Floor	$		6.63	$	6.54		$	6.59
Ceiling	$		7.54	$	7.53		$	7.54
Fixed-price sales (2)	$		55,890	$	45,973		$	101,863
Fair value, net	$		3,525	$	(2,729	)	$	796

Total Natural Gas Contracts:
Contract vols (MMBtu)			10,787,000		7,027,000			17,814,000
Weighted-avg fixed price per MMBtu (1):	$		6.75	$	6.54		$	6.67
Fixed-price sales (2)	$		72,838	$	45,973		$	118,811
Fair value, net	$		5,732	$	(2,729	)	$	3,003

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.

Some of 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 Central TX/KS/OK (“Southern Star”) first of month index, with a small portion being sold based on the daily price on the Southern Star index. The difference between natural gas prices on the NYMEX and the price actually received by the Company is referred to as a basis differential. Typically, the price for natural gas on the Southern Star first of the 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 the 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.

Our approximately 1,600 mile gas gathering pipeline network is owned by Bluestem Pipeline. Prior to December 22, 2006, Bluestem was a wholly-owned subsidiary. As discussed in “—Recent Developments”, on December 22, 2006, we formed Quest Midstream and contributed our ownership interest in Bluestem to Quest Midstream in exchange for general and limited partner interests. We own approximately 51% of the partnership interests in Quest Midstream and through our 85% ownership interest in the general partner of Quest Midstream we continue to control the day to day operations of our gas gathering pipeline network.

Our natural gas gathering pipeline network is located in southeastern Kansas and northeastern Oklahoma and provides a market outlet for natural gas in a region of approximately 1,000 square miles in size and has connections to both intrastate and interstate delivery pipelines. As of December 31, 2006, this pipeline network included 15 natural gas compressors that are owned by Bluestem and 68 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 the development of new pipelines and to a lesser extent, through the acquisition of existing pipelines.

The following table sets forth the number of miles of pipeline acquired or constructed during the periods indicated.

The table below sets forth the natural gas volumes transported on our pipeline network during the year ended December 31, 2006 and 2005; the seven-month transition period ended December 31, 2004 and for the fiscal year ended May 31, 2004.

The natural gas volumes for 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, 2006, the total daily capacity was approximately 70 mmcf and the total utilization was approximately 54 mmcf or 77%.

Field operations conducted by our 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 our field personnel.

We also provide, on an in-house basis, many of the services required for the completion and maintenance of our CBM wells. Internally sourcing these functions significantly reduces our reliance on third-party contractors, which typically provide these services. We believe 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 20 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.

Various aspects of our operations are, or in the future may be, regulated by agencies of the federal government.

Under the Natural Gas Act of 1938, the Federal Energy Regulatory Commission, or the FERC, regulates various aspects of the operations of any “natural gas company,” including the transportation of natural gas, rates and charges, construction of new facilities, extension or abandonment of services and facilities, the acquisition and disposition of facilities, reporting requirements, and similar matters. Section 1(b) of the Natural Gas Act of 1938 exempts natural gas gathering facilities from the jurisdiction of the FERC. We believe our gas gathering system meets 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 and are therefore not subject to FERC jurisdiction.

If we were determined to be a natural gas company, our operations would become regulated under the Natural Gas Act. We believe the expenses associated with seeking certificate authority for construction, service and abandonment, establishing rates and a tariff for our gas gathering activities, and meeting the detailed regulatory accounting and reporting requirements would substantially increase our operating costs and would adversely affect our profitability.

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

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

These regulatory burdens may affect profitability, and management is unable to predict the future cost or impact of complying with such regulations. We do not own any pipelines that provide intrastate natural gas transportation, so state regulation of pipeline transportation does not directly affect our operations. As with the FERC regulation described above, however, state regulation of pipeline transportation may influence certain aspects of our business and the market price for our products.

The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and

regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry, and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of the FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action materially differently than other natural gas marketers with whom we compete.

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

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

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

The exploration for and production of natural gas and the related operation of pipelines, plants and other facilities for gathering, compressing, dehydrating or treating natural gas and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of natural gas wells and related gathering facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of substances or other waste products into the environment.

It is possible that additional environmental regulations will place more restrictions and limitations on activities that may affect our business, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance.

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. 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.

At the present time, we do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations. We cannot assure you, however that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions, will not cause us to incur significant costs. The following is a discussion of the material environmental and safety laws and regulations that relate to the midstream natural gas industry. We believe that we are in substantial compliance with all of these environmental laws and regulations.

Our operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or use specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. Historically, air pollution control has become more stringent over time. This trend is expected to continue. The cost of technology and systems to control air pollution to meet regulatory requirements is significant today. These costs are expected to increase as air pollution control requirements increase. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

Our operations generate wastes, including some hazardous wastes that are subject to the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes associated with the exploration, development or production of crude oil and natural gas. However, these oil and gas exploration and production wastes may still be regulated under state law or the less stringent requirements of the Solid Waste Disposal Act. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements.

The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, or CERCLA, also known as “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Although natural gas is excluded from CERCLA’s definition of “hazardous substance,” in the course of our ordinary operations we generate wastes and materials that fall within the definition of a “hazardous substance.” Under CERCLA, we could be subject to joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources and for the costs of certain health studies.

Our operations are subject to the Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed permit requirements and strict controls regarding the discharge of pollutants in waste water and in storm water, including the discharge of dredged or fill material, into waters of the United States. The unpermitted discharge of pollutants, including discharges resulting from a spill or leak incident, is prohibited. Any unpermitted release of pollutants from our pipelines or facilities could result in fines or penalties as well as significant remedial obligations.

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

We are subject to the requirements of the Occupational Safety and Health Act, referred to as OSHA, and comparable state laws and standards that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, federal, state and local government authorities and citizens.

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

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.

At March 6, 2007, we had an experienced staff of 265 field employees in offices located in Chanute and Howard, Kansas and Lenapah, Oklahoma, and 47 pipeline operations employees. Also, at the headquarters office in Oklahoma City, our staff consists of 42 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.

The office space for the corporate headquarters for us and our subsidiaries is leased and is located at 9520 N. May Avenue, Suite 300, Oklahoma City, OK 73120.

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.

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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:

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. 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 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. For the year ended December 31, 2006, the Company recorded a provision for impairment of its gas properties in the amount of $30.7 million.

The Company’s estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of the Company’s reserves.

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 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:

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, 2006 would decrease from $268.1 million to $263.6 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:

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

The Company’s operations are subject to hazards and risks inherent in producing and transporting natural gas and oil, including:

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

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. Additionally, the Company may elect not to obtain insurance if it believes that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets subsequent to the terrorist attacks on September 11, 2001 and the hurricanes in 2005 have made it more difficult for the Company to obtain certain types of coverage. There can be no assurance that the Company will be able to obtain the levels or types of insurance the Company would otherwise have obtained prior to these market changes or that the

insurance coverage the Company does obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. 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 Item 7. “Management’s Discussion and Analysis of Financial Condition Results of Operations — Quantitative and Qualitative Disclosures About Market Risk” and Items 1. and 2. “Description of Business and Properties — Delivery Commitments — Hedging Activities.”

The Company markets its own natural gas and more than 95% of its natural gas was sold to ONEOK Energy Marketing and Trading Company (“ONEOK”) during 2006. Tenaska was added as a purchaser in December 2006 and may purchase 10% or more during year 2007. In the event that ONEOK or Tenaska 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 constantly evaluates opportunities to acquire additional natural gas and oil properties and frequently engages 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.

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’s operations expose it to significant costs and liabilities with respect to environmental and operational safety matters applicable to natural gas exploration and production operations.

The Company may incur significant costs and liabilities as a result of environmental, health and safety requirements applicable to natural gas exploration and production activities. These costs and liabilities could arise under a wide range of federal, state and local environmental, health and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property may result from environmental and other impacts of the Company’s operations.

The Company is subject to regulation that restricts its ability to discharge water produced as part of its coal bed methane gas production operations. 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, and the Company’s ability to remove and dispose of sufficient quantities of water from the coal seam will determine whether or not it can produce gas in commercial quantities. The cost of water disposal, including the cost of complying with regulations concerning water disposal, may adversely affect the Company.

Strict, joint and several liability may be imposed under certain environmental laws, which could cause the Company to become liable for the conduct of others or for consequences of its own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. The Company does not carry insurance coverage against many of these potential environmental liabilities. Consequently, if the Company would be directly liable for damages resulting from the occurrence of any such event, its financial condition could be negatively impacted and, its ability to execute its business plan could be impaired.

The Company’s 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. The Company’s 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 adversely affect the Company’s 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.

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.

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.

Shortages of natural gas and oil field service personnel and equipment could adversely affect the Company’s business.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Due to recent high natural gas and oil prices, the Company has experienced shortages of drilling rigs and other equipment, as demand for rigs and equipment has increased along with the number of wells being drilled. Higher natural gas and oil prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, oilfield equipment and services and personnel in the Company’s exploration and production operations. These types of shortages or price increases could significantly decrease the Company’s profit margin, cash flow and operating results or restrict or delay its ability to drill those wells and conduct those operations that it currently has planned and budgeted.

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 12, 2007 the Company had incurred $225 million of indebtedness for borrowed money and $10 million of indebtedness had been incurred by Quest Midstream. 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.

The Company’s financial position and past financial performance could have the following material adverse consequences for its business:

If the Company fails to maintain an effective system of internal controls, then it may not be able to accurately report its financial results or prevent fraud.

Effective internal controls are necessary for the Company to provide reliable financial reports, prevent fraud and operate successfully as a public company. The Company cannot be certain that its efforts to maintain its internal controls will be successful, that it will be able to maintain adequate controls over its financial processes and reporting in the future or that it will be able to comply with its obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective internal controls or difficulties encountered in implementing or improving the Company’s internal controls could harm its operating results or cause it to fail to meet its reporting obligations. Ineffective internal controls also could cause the Company’s shareholders and potential investors to lose confidence in the Company’s reported financial information, which would likely have a negative effect on the trading price of its common stock.

The Company’s credit agreements contain operating and financial restrictions that may restrict its business and financing activities.

The operating and financial restrictions and covenants in the Company’s credit agreements could restrict its ability to finance future operations or capital needs or to engage, expand or pursue its business activities or to pay distributions. The Company’s credit agreements restrict its ability to:

The Company is also required to comply with certain financial covenants and ratios. The Company’s ability to comply with these restrictions and covenants in the future is uncertain and will be affected by its results of operations and financial conditions and events or circumstances beyond its control. If market or other economic conditions deteriorate, the Company’s ability to comply with these covenants may be impaired. If the Company violates any of the restrictions, covenants, ratios or tests in its credit agreements, a significant portion of its indebtedness may become immediately due and payable, its ability to make distributions will be inhibited and the lenders’ commitment to make further loans to the Company may terminate. The Company might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, the Company’s obligations under its credit agreements are secured by substantially all of its assets, and if it is unable to repay indebtedness under its credit agreements, the lenders could seek to foreclose on its assets.

The Company’s credit agreements limit the amounts it can borrow to a borrowing base amount, determined by the lenders in their sole discretion. Outstanding borrowings in excess of the borrowing base will be required to be repaid (1) within 90 days following receipt of notice of the new borrowing base or (2) immediately if the borrowing base is reduced in connection with a sale or disposition of certain properties in excess of 5% of the borrowing base. Additionally, if the lenders’ exposure under letters of credit exceeds the borrowing base after all borrowings under the credit agreements have been repaid, the Company will be required to provide additional cash collateral.

Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to the Company’s business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact the Company’s results of operations.

The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks on the Company’s industry in general, and on the Company in particular, is not known at this time. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect the Company’s operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror.

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:

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 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 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 200,000,000 shares of common stock and is not 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.

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.

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).

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.

The following table sets forth selected consolidated financial data of Quest for the years ended December 31, 2006 and 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. Comparability between years is affected by (1) changes in the annual average prices for oil and gas, (2) increased production from drilling and development activity and (3) significant acquisitions that were made during the fiscal year ended May 31, 2004. 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.

	Year Ended December 31,								7 Mos Ended December 31,				Year Ended May 31,
	2006				2005				2004				2004	2003				2002
Statement of Operations Data:	($ in thousands, except per share data)
Revenues:
Oil and gas sales		$	65,551			$	44,565		$	24,201		$	28,147		$	8,345			$	1,699
Gas pipeline revenue			5,014				3,939			1,918			2,707			632				433
Other revenue/expense			(80	)			389			37			(843	)		(879	)			303
Total revenues			70,485				48,893			26,156			30,011			8,098				2,435
Costs and expenses:
Oil and gas production			21,208				14,388			5,389			6,835			1,979				593
Pipeline operating			13,247				8,470			3,653			3,506			912				662
General and administrative			8,840				4,802			2,681			2,555			977				370
Provision for impairment of oil and gas properties			30,719				—			—			—			—				—
Depreciation and amortization			28,025				22,199			7,671			7,650			1,822				401
Total costs and expenses			102,039				49,859			19,394			20,546			5,690				2,026
Operating income (loss)			(31,554	)			(966	)		6,762			9,465			2,408				409
Other income (expense):
Change in derivative fair value			6,410				(4,668	)		(1,487	)		(2,013	)		(4,867	)			—
Sale of assets			3				12			—			(6	)		(3	)			—
Interest expense, net			(23,093	)			(26,319	)		(10,138	)		(8,056	)		(727	)			(213	)
Total other expense			(16,680	)			(30,975	)		(11,625	)		(10,075	)		(5,597	)			(213	)
Income (loss) before income taxes			(48,234	)			(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			(48,234	)			(31,941	)		(4,863	)		(365	)		(3,563	)			124
Minority interest in continuing operations of QMP			(244	)			—			—			—			—				—
Cumulative effect of accounting change, net of tax			—				—			—			(28	)		—				—
Net income (loss)			(48,478	)			(31,941	)		(4,863	)		(393	)		(3,563	)			124
Preferred stock dividends			—				(10	)		(6	)		(10	)		(10	)			(10	)
Net income (loss) available to common shareholders		$	(48,478	)		$	(31,951	)	$	(4,869	)	$	(403	)	$	(3,573	)		$	114
Income (loss) per common share:
Basis		$	(2.19	)		$	(3.81	)	$	(0.86	)	$	(0.07	)	$	(0.87	)		$	0.04
Diluted		$	(2.19	)		$	(3.81	)	$	(0.86	)	$	(0.07	)	$	(0.87	)		$	0.04
Cash Flow Data:
Cash provided (used) by operating activities		$	7,000			$	(4,914	)	$	25,484		$	12,197		$	4,211			$	1,306
Cash used in investing activities			172,617				73,601			48,814			146,834			8,804				3,494
Cash provided by financing activities			204,878				74,616			26,280			135,456			7,205				2,077
Balance Sheet Data:
Total assets		$	463,300			$	297,803		$	237,962		$	190,375		$	36,533			$	9,671

	Year Ended December 31,						7 Mos Ended December 31,					Year Ended May 31,
	2006				2005		2004					2004				2003										2002
	($ in thousands, except per share data)
Earnings:
Income (loss) before income taxes		$	(48,478,000	)	$	(31,941,000			$	(4,863,000	)		$	(610,000	)		$		(3,189,000	)		$			196,000
Interest expense(1)			23,483,000			26,365,000				10,147,000				8,057,000					727,000						216,000
Loan cost amortization			1,204,000			5,106,000				530,000				172,000					20,000						—
Earnings		$	(23,791,000	)	$	(470,000		)	$	5,814,000			$	7,619,000			$		(2,442,000	)		$			412,000
Fixed Charges:
Interest expense		$	23,483,000		$	26,365,000			$	10,147,000			$	8,057,000				$	727,000				$	216,000
Loan cost amortization			1,204,000			5,106,000				530,000				172,000					20,000					—
Fixed charges		$	24,687,000		$	31,471,000			$	10,677,000			$	8,229,000				$	747,000				$	216,000
Preferred Stock Dividends		$	—		$	10,000			$	6,000			$	10,000				$	10,000				$	10,000
Ratio of income before taxes			1.0			1.0				1.0				1.7					0.9					1.6
Subtotal-Preferred Dividends		$	—		$	10,000			$	6,000			$	17,000				$	9,000				$	16,000
Combined fixed charges and preferred dividends		$	24,687,000		$	31,481,000			$	10,683,000			$	8,246,000				$	756,000				$	232,000
Ratio of earnings to fixed charges(2)(3)			(1.0	)		(0.0		)		0.5				0.9					(3.3		)			1.9
Insufficient coverage		$	48,478,000		$	31,941,000			$	4,863,000			$	610,000				$	3,189,000				$	—
Ratio of earnings to combined fixed charges and preferred dividends(4)			(1.0	)		(0.0		)		0.5				0.9					(3.2		)			1.8
Insufficient coverage		$	48,478,000		$	31,951,000			$	4,869,000			$	627,000				$	3,198,000				$	—

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			Year Ended
	December 31,									May 31,
	2006			2005			2004			2004
Net Production:
Gas (bcf)		12.29			9.57			5.01			5.53
Oil (bbls)		9,737			9,241			5,551			8,549
Gas equivalent (bcfe)		12.34			9.62			5.05			5.58
Gas and Oil Sales ($ in thousands):
Gas sales	$	72,865		$	71,137		$	28,864		$	27,694
Gas derivatives — gains (loss)	$	(7,888	)	$	(27,066	)	$	(4,908	)	$	102
Total gas sales	$	64,977		$	44,071		$	23,956		$	27,796
Oil sales	$	574		$	494		$	245		$	351
Total gas and oil sales	$	65,551		$	44,565		$	24,201		$	28,147
Avg Sales Price (excluding effects of hedging):
Gas ($ per mcf)	$	5.93		$	7.44		$	5.74		$	5.19
Oil ($ per bbl)	$	58.95		$	53.46		$	44.14		$	41.06
Gas equivalent ($ per mcfe)	$	5.95		$	7.45		$	5.77		$	5.02
Avg Sales Price (including effects of hedging):
Gas ($ per mcf)	$	5.29		$	4.61		$	4.83		$	5.04
Oil ($ per bbl)	$	58.95		$	53.46		$	44.14		$	41.06
Gas equivalent ($ per mcfe)	$	5.31		$	4.63		$	4.79		$	5.04
Expenses ($ per mcfe):
Lifting	$	1.29		$	0.98		$	0.72		$	0.91
Production and property tax	$	0.55		$	0.58		$	0.37		$	0.34
Pipeline operating	$	0.96		$	0.82		$	0.70		$	0.61
General and administrative	$	0.70		$	0.50		$	0.53		$	0.46
Depreciation and amortization	$	2.37		$	2.31		$	1.52		$	1.37
Interest expense	$	1.91		$	2.74		$	2.01		$	1.44
Capital expenditures	$	172,617		$	73,601	(1)	$	48,814		$	146,834	(2)
Miles of Pipeline Constructed		392			120			124			20
Wells Connected (Gross)		638			233			117			477
Wells Drilled (Gross)		622			99			330			153
Producing Gas & Oil Wells (Gross) as of the End of the Period(3)		1,653			1,055			824			707

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.

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:

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:

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.”

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 2006 as compared to calendar year 2005 resulted from an approximate 28% increase in production volumes, which were partially offset by lower product prices (before hedge settlements) for natural gas.

At December 31, 2006, we had an interest in 1,653 natural gas and oil wells (gross) and natural gas and oil leases on approximately 542,000 gross acres. Management believes that the proximity of the 1,600 miles of Quest Midstream owned pipeline network to these natural gas and oil leases will enable us to develop new producing wells on many of our undeveloped properties. We have currently identified approximately 1,760 additional proved undeveloped natural gas well drilling sites on our proved undeveloped acreage. With approximately 550 wells planned to be drilled during each of 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.

The results of our drilling and well development program for calendar year 2006 included the drilling of 622 new gas wells (gross), the connecting of 638 new gas wells (gross) into our gas gathering pipeline network, the construction of approximately 392 miles of pipeline infrastructure and the re-completion of 125 wells from single seam to multi-seam wells.

On June 9, 2006, we and Quest Cherokee entered into a $75 million six-year Third Lien Term Loan Agreement among us, Quest Cherokee, Guggenheim Corporate Funding, LLC, as administrative agent, and the lenders party thereto that was fully funded at the closing. See Note 3 to our consolidated financial statements included elsewhere in this report for additional information regarding our third lien term loan facility.

On December 22, 2006, Quest Midstream, a Delaware limited partnership formed to own and operate our natural gas gathering pipeline system, sold 4,864,866 common units, representing an approximate 48.64% interest in Quest Midstream, for $18.50 per common unit, or approximately $90 million, pursuant to a purchase agreement dated December 22, 2006, to a group of institutional investors led by Alerian, and co-led by Swank. See Items 1 and 2, “Description of Business and Properties-Recent Events-Formation of Quest Midstream.”

The following discussion of results of operations will compare audited balances for the year ended December 31, 2006 to the audited balances for the year ended December 31, 2005, as follows:

Total revenues of $60.3 million for the year ended December 31, 2006 represents an increase of 23% when compared to total revenues of $48.9 million for the year ended December 31, 2005. The increase in natural gas and oil sales from $44.6 million for the year ended December 31, 2005 to $65.6 million for the year ended December 31, 2006 and the increase in natural gas pipeline revenue from $3.9 million to $5.0 million resulted from the additional wells and pipelines completed during the past twelve months. The additional wells completed contributed to the production of 12,282,000 mcf of net gas for the year ended December 31, 2006, as compared to 9,565,000 net mcf produced for the year ended December 31, 2005. Our product prices before hedge settlements on an equivalent basis (mcfe) decreased from $7.45 mcfe average for the 2005 period to $5.95 mcfe average for the 2006 period. Accounting for hedge settlements, the product prices decreased from $4.63 mcfe average for the 2005 period to $4.48 mcfe average for the 2006 period. With our continuing well development 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, 2007, we had entered into hedging transactions covering a total of approximately 20 Bcf of natural gas production through December 2008. See Items 1 and 2 “Description of Business and Properties—Delivery Commitments—Hedging Activities” and Notes 14 and 15 to the consolidated financial statements included in this report.

Other expense for the year ended December 31, 2006 was $10.3 million that resulted from a reclassification from gas sales of cash settlements for derivative contracts that did not qualify as cash flow hedges as compared to other revenue of $389,000 for the year ended December 31, 2005, that was primarily the result of an adjustment of overhead fees.

The operating costs for the year ended December 31, 2006 totaled approximately $21.2 million as compared to operating costs of approximately $14.4 million incurred for the year ended December 31, 2005. Operating costs, excluding gross production and ad valorem taxes, were $1.29 per mcf for 2006 compared to $0.99 for the year ended December 31, 2005. Operating costs, inclusive of gross production and ad valorem taxes, were $1.84 per mcf for the 2006 period as compared to $1.57 per mcf for the year ended December 31, 2005 period, representing a 16% increase. Approximately 40% 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 15% of the increase was due to increased gross production taxes from increased production volumes 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 incurred during the fourth quarter of 2006. Approximately 15% is due to an increase in our treating program to reduce pump failures. Pipeline operating costs for the year ended December 31, 2006 totaled approximately $13.2 million ($1.08 per mcf) as compared to pipeline operating costs of $8.5 million ($0.89 per mcf) for the year ended December 31, 2005. Pipeline operating costs, excluding ad valorem taxes, were $0.96 per mcf for 2006 as compared to $0.82 per mcf for 2005. This increase in operating costs was due to the delivery of additional compressors in anticipation of increased pipeline volumes, the number of wells completed and operated during the year, the increased miles of pipeline in service and the increase in property taxes. The increase in depreciation, depletion and amortization to approximately $28.0 million in 2006 from approximately $22.2 million in 2005 is a result of the increased number of producing wells and miles of pipeline developed, the higher volumes of natural gas and oil produced and the resulting increased depletion rate. In 2007, we anticipate these operating costs to decrease on a per mcf basis due to the increased volumes forecasted from new wells completed last year and the new wells to be completed in 2007.

General and administrative expenses increased to approximately $8.8 million for the year ended December 31, 2006 from $4.8 million in the year ended December 31, 2005 due to an increase in board fees, professional fees, Nasdaq listing fees, travel expenses for presentations to increase the visibility of the Company, costs for establishing a Houston office and staffing requirements, increased staffing to support the higher levels of development and operational activity and the added resources to enhance our internal controls and financial reporting to comply with the requirement for the 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 decreased to approximately $23.5 million for the year ended December 31, 2006 from $26.4 million for the year ended December 31, 2005 (inclusive of a $4.3 million write-off of debt issue costs realized in connection with the refinancing of our credit facilities in 2005). Excluding the write-off of debt issue costs in 2005, the approximate $1.4 million increase in interest expense in 2006 was due to higher average outstanding borrowings, partially offset by lower average interest rates under our new credit facilities that were entered into in November 2005.

Change in derivative fair value was a non-cash gain of $6.4 million for the year ended December 31, 2006, which included a $12.2 million gain attributable to the change in fair value for certain derivative contracts that did not qualify as cash flow hedges pursuant to SFAS 133, settlements due to ineffective cash flow hedges of $10.2 million and a gain of $4.4 million relating to hedge ineffectiveness. Change in derivative fair value was a non-cash net loss of $4.7 million for the year ended December 31, 2005, which included an $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. 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 $65.1 million (including $23.5 million of interest expense and a $30.7 million provision for impairment of oil and gas properties from a full cost pool ceiling write-down) before income taxes and before the change in derivative fair value of $16.6 million non-cash net gain for the year ended December 31, 2006 as compared to 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 non-cash net loss for the year ended December 31, 2005. No income tax expense or benefit resulted for the years ended December 31, 2006 or 2005. The provision for impairment is primarily attributable to declines in estimated reserves due to the prevailing market prices of oil and gas at the measurement date.

We recorded a net loss of $48.5 million for the year ended December 31, 2006 as compared to a net loss of $31.9 million for the year ended December 31, 2005.

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:

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.

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

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:

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.

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.

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.

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.

Analysis of cash flows. The following analysis of cash flows will compare audited balances for the year ended December 31, 2006 to the audited balances for the year ended December 31, 2005, as follows:

	Year Ended December 31,
	2006			2005
	($ in thousands)
Cash flows from operating activities:
Net income (loss)	$	(48,478	)	$	(31,941	)
Adjustments to reconcile net income (loss) to cash Provided by operations:
Depreciation and depletion		30,898			22,949
Write down of gas properties		30,719			—
Accrued interest subordinated note		—			9,586
Change in derivative fair value		(16,644	)		4,668
Stock issued for retirement plan		428			266
Stock issued for director fees		429			19
Stock awards granted to employees		779			352
Amortization of loan origination fees		1,204			5,106
Amortization of gas swap fees		208			—
Amortization of deferred hedging gains		(328	)		(831	)
Bad debt expense		37			192
Minority interest		244			—
Other		(3	)		56
Change in assets and liabilities:
Restricted cash		(17,275	)		(4,318	)
Accounts receivable		(219	)		(3,646	)
Other receivables		(29	)		181
Other current assets		894			(1,695	)
Inventory		(37	)		(2,499	)
Accounts payable		2,400			(4,957	)
Revenue payable		(505	)		1,537
Accrued expenses		1,836			61
Net cash provided by (used in) operating activities		(13,442	)		(4,914	)
Cash flows from investing activities:
Other assets		(5,712	)		(6,071	)
Equipment, development and leasehold costs		(166,905	)		(67,530	)
Net cash used in investing activities		(172,617	)		(73,601	)

At December 31, 2006, we had current assets of $59.9 million, working capital (current assets minus current liabilities, excluding the short-term derivative asset and liability of $10.8 million and $5.2 million, respectively) of $37.7 million and had used $13.5 million net cash from operations during the year ended December 31, 2006.

During the year ended December 31, 2006, a total of approximately $172.6 million was invested in new natural gas wells and properties, new pipeline facilities, and other additional capital items. This investment was funded through approximately $40 million of the net proceeds from the issuance of common units of Quest Midstream to a group of investors, $200 million of bank borrowings during 2006 and $511,000 from the issuance of common stock. Net cash used by operating activities increased substantially from $4.9 million for the year ended December 31, 2005 to $13.5 million of net cash used for the year ended December 31, 2006 due primarily to an increase in operating costs and the fact that we expanded our operations during 2006.

Our working capital (current assets minus current liabilities, excluding the short-term derivative asset and liability of $10.8 million and $5.2 million, respectively) was $37.7 million at December 31, 2006, compared to working capital of $3.1 million, (excluding the short-term derivative asset and liability of $95,000 and $38.2 million, respectively) at December 31, 2005. The change in working capital is due to the formation of Quest Midstream in December 2006 and the issuance of common units in Quest Midstream to a group of investors for approximately $90 million before expenses. Additionally, inventory, accounts payable and accrued expenses balances increased as we expanded our operations.

During 2007, we intend to focus on drilling and completing approximately 550 additional new wells. We also currently intend to drill approximately 550 wells during 2008. Management currently estimates that it will require over the next two years a capital investment of approximately $113 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 550 new wells planned for 2007 utilizing cash flow from operations, remaining cash from the Quest Midstream transaction, available borrowings under the revolving credit facility and/or the sale of additional equity interests. In addition, in the near term, we intend to fund additional pipeline expansion to connect these new wells to our gas gathering system with Bluestem’s new $75 million revolving credit facility that was closed in January 2007. The Company intends to

finance capital expenditures during 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 are currently seeking to raise additional equity capital to decrease the amount of our debt as a percentage of our total capitalization. However, there can be no assurance that we will be able to obtain such additional equity capital on terms that are favorable to us.

At December 31, 2006, $569,000 of notes payable to banks and finance companies were outstanding 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.

Future payments due on our contractual obligations as of December 31, 2006 are as follows:

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, 2006.

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 we believe that these hedges are generally effective in realizing this objective. 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.

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.

At December 31, 2006, 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.

Please see the accompanying financial statements attached hereto beginning on page F-1.

We have audited the accompanying consolidated balance sheets of QUEST RESOURCE CORPORATION and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years ended December 31, 2006 and 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. An audit 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, 2006 and 2005, and the consolidated results of their operations and cash flows for the years ended December 31, 2006 and 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.

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As discussed in note 16 to the financial statements, certain reclassifications regarding cash and the reporting of certain cash settlements have been made to the December 31, 2006 financial statements.

(November 30, 2007, as to the effect of the restatements noted in note 16 and as to additional disclosures in notes 1, 3, 4, and 17 to the financial statements)

	December 31,			December 31,
	2006			2005
	($ in thousands)
ASSETS		<Restated>
Current assets:
Cash	$	41,820		$	2,559
Restricted cash		1,150			4,318
Accounts receivable, trade		9,840			9,658
Other receivables		371			343
Other current assets		1,068			1,936
Inventory		5,632			2,782
Short-term derivative asset		10,795			95
Total current assets		70,676			21,691
Property and equipment, net of accumulated depreciation of $5,107,000
and $2,114,000		16,212			13,490
Pipeline assets, net of accumulated depreciation of $6,104,000 and $3,598,000		127,690			60,150
Pipeline assets under construction		880			12,699
Oil and gas properties:
Properties being amortized		316,780			201,788
Properties not being amortized		9,545			18,285
		326,325			220,073
Less: Accumulated depreciation, depletion, amortization and impairment		(92,732	)		(36,703	)
Net property, plant and equipment		233,593			183,370
Other assets, net		9,467			6,310
Long-term derivative asset		4,782			93
Total assets	$	463,300		$	297,803

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	14,778		$	12,381
Revenue payable		4,540			5,044
Accrued expenses		2,525			649
Current portion of notes payable		324			407
Short-term derivative liability		5,244			38,195
Total current liabilities		27,411			56,676
Non-current liabilities:
Long-term derivative liability		7,449			23,723
Asset retirement obligation		1,410			1,150
Notes payable		225,569			100,988
Less current maturities		(324	)		(407	)
Non-current liabilities		234,104			125,454
Minority interest in QMLP		84,431			—
Total liabilities		345,946			182,130
Commitments and contingencies		—			—
Stockholders’ equity:
10% convertible preferred stock, $.001 par value, 50,000,000 shares authorized,
0 and 0 shares issued and outstanding at December 31, 2006 and 2005		—			—
Common stock, $.001 par value, 200,000,000 and 380,000,000 shares
authorized at December 31, 2006 and 2005, 22,206,014 and 22,072,383 shares
issued and outstanding at December 31, 2006 and 2005		22			22
Additional paid-in capital		205,994			203,434
Accumulated other comprehensive income (loss)		428			(47,171	)
Accumulated deficit		(89,090	)		(40,612	)
Total stockholders’ equity		117,354			115,673
Total liabilities and stockholders’ equity	$	463,300		$	297,803

The accompanying notes are an integral part of these consolidated financial statements

							Seven Months
	Year Ended			Year Ended			Ended			Year Ended
	December 31,			December 31,			December 31,			May 31,
	2006			2005			2004			2004
	<Restated>
	($ in thousands, except per share data)
Revenue:
Oil and gas sales	$	65,551		$	44,565		$	24,201		$	28,147
Gas pipeline revenue		5,014			3,939			1,918			2,707
Other revenue and expense		(80	)		389			37			(843	)
Total revenues		70,485			48,893			26,156			30,011
Costs and expenses:
Oil and gas production		21,208			14,388			5,389			6,835
Pipeline operating		13,247			8,470			3,653			3,506
General and administrative expenses		8,840			4,802			2,681			2,555
Provision–impairment of gas properties		30,719			—			—			—
Depreciation, depletion and amortization		28,025			22,199			7,671			7,650
Total costs and expenses		102,039			49,859			19,394			20,546
Operating income (loss)		(31,554	)		(966	)		6,762			9,465
Other income (expense):
Change in derivative fair value		6,410			(4,668	)		(1,487	)		(2,013	)
Sale of assets		3			12			—			(6	)
Interest expense		(23,483	)		(26,365	)		(10,147	)		(8,057	)
Interest income		390			46			9			1
Total other income and expense		(16,680	)		(30,975	)		(11,625	)		(10,075	)
Loss before income taxes		(48,234	)		(31,941	)		(4,863	)		(610	)
Deferred income tax benefit (expense)		—			—			—			245
Net loss before cumulative effect of accounting change		(48,234	)		(31,941	)		(4,863	)		(365	)
Minority interest in continuing operations of QMLP		(244	)		—			—			—
Cumulative effect of accounting change, net of income tax of $19,000		—			—			—			(28	)
Net loss		(48,478	)		(31,941	)		(4,863	)		(393	)
Preferred stock dividends		—			(10	)		(6	)		(10	)
Net loss available to common shareholders	$	(48,478	)	$	(31,951	)	$	(4,869	)	$	(403	)
Loss per common share:
Basic	$	(2.19	)	$	(3.81	)	$	(0.86	)	$	(0.07	)
Diluted	$	(2.19	)	$	(3.81	)	$	(0.86	)	$	(0.07	)
Weighted average common and common equivalent shares outstanding:
Basic		22,100,753			8,390,092			5,661,352			5,558,352
Diluted		22,100,753			8,390,092			5,661,352			5,588,352

The accompanying notes are an integral part of these consolidated financial statements

							Seven Months
	Year Ended			Year Ended			Ended			Year Ended
	December 31,			December 31,			December 31,			December 31,
	2006			2005			2004			2004
	<Restated>
	($ in thousands)
Cash flows from operating activities:
Net (loss)	$	(48,478	)	$	(31,941	)	$	(4,863	)	$	(393	)
Adjustments to reconcile net (loss) to cash provided by operations:
Depreciation		5,496			2,315			846			835
Depletion		25,402			20,634			7,187			6,802
Write down of gas properties		30,719			—			—			—
Accrued interest		—			9,586			4,866			3,459
Change in derivative fair value		(16,644	)		4,668			1,487			2,013
Cumulative effect-accounting change		—			—			—			47
Deferred income taxes		—			—			—			(263	)
Accretion of line of credit		—			—			—			1,204
Stock issued for retirement plan		428			266			—			121
Stock options granted for director fees		429			—			—			—
Stock issued for audit committee fees		—			19			62			—
Stock awards granted to employees		779			352			—			—
Stock issued for services		—			—			—			94
Amortization of loan origination fees		1,204			5,106			530			172
Amortization of gas swap fees		208			—			—			—
Amortization of deferred hedging gains		(328	)		(831	)		163			—
Bad debt expense		37			192			—			—
Minority interest		244			—			—			—
Other		(3	)		56			28			44
Change in assets and liabilities:
Restricted cash		3,167			(4,318	)		—			—
Accounts receivable		(219	)		(3,646	)		893			(4,751	)
Other receivables		(29	)		181			85			(1,432	)
Other current assets		894			(1,695	)		16			(257	)
Inventory		(37	)		(2,499	)		208			(244	)
Accounts payable		2,400			(4,957	)		13,628			2,302
Revenue payable		(505	)		1,537			222			2,221
Accrued expenses		1,836			61			126			223
Net cash provided by (used in) operating activities		7,000			(4,914	)		25,484			12,197
Cash flows from investing activities:
Acquisition of proved oil and gas properties-Devon		—			—			—			(111,849	)
Acquisition of gas gathering pipeline – Devon		—			—			—			(21,964	)
Other assets		(5,712	)		(6,071	)		(527	)		(393	)
Equipment, development and leasehold		(166,905	)		(67,530	)		(48,287	)		(12,628	)
Net cash used in investing activities		(172,617	)		(73,601	)		(48,814	)		(146,834	)
Cash flows from financing activities:
Proceeds from bank borrowings		200,170			100,103			136,118			105,000
Repayments of note borrowings		(31,339	)		(135,565	)		(104,732	)		(21,682	)
Repayment of revolver note		(44,250	)		—			—			—
Proceeds from Quest Midstream		84,187			—			—			—
Proceeds from subordinated debt		—			15,000			—			51,000
Repayment of subordinated debt		—			(83,912	)		—			—
Refinancing costs – Guggenheim		(4,568	)		(5,892	)		—			—
Refinancing costs – UBS		—			(380	)		(4,942	)		—
Dividends paid		—			(10	)		(6	)		—
Change in other long-term liabilities		167			—			(638	)		638
Proceeds from issuance-common stock		511			185,272			480			500
Net cash provided by financing activities		204,878			74,616			26,280			135,456
Net increase (decrease) in cash		39,261			(3,899	)		2,950			819
Cash, beginning of period		2,559			6,458			3,508			2,689
Cash, end of period	$	41,820		$	2,559		$	6,458		$	3,508

The accompanying notes are an integral part of these consolidated financial statements.

						Common					Accumulated
				Preferred		Stock		Additional			Other
	Preferred		Common	Stock		Par		Paid-in			Comprehensive			Accumulated
	Shares		Shares	Par Value		Value		Capital			Income (Loss)			Deficit			Total
	($ in thousands, except per share amounts)
Balance, May 31, 2004	10,000		5,645,077	$	—	$	6	$	16,650		$	(10,629	)	$	(3,792	)	$	2,235
Comprehensive income:
Net loss															(4,863	)		(4,863	)
Other comprehensive loss, net of tax:
Change in fixed-price contract and other derivative fair value												(5,258	)					(5,258	)
Reclassification adjustments-contract settlements												4,744						4,744
Total comprehensive loss																		(5,377	)
Dividends on preferred stock															(6	)		(6	)
Stock sales for cash			48,000						480									480
Stock issued for services			6,800						62									62
Balance, December 31, 2004	10,000		5,699,877	$	—	$	6	$	17,192		$	(11,143	)	$	(8,661	)	$	(2,606	)
Comprehensive income:
Net loss															(31,941	)		(31,941	)
Other comprehensive loss, net of tax:
Change in fixed-price contract and other derivative fair value												(63,924	)					(63,924	)
Reclassification adjustments-contract settlements												27,896						27,896
Total comprehensive loss																		(67,969	)
Dividends on preferred stock															(10	)		(10	)
Equity offering			15,258,164				15		183,257									183,272
Conversion of preferred stock	(10,000	)	16,000															—
Stock sales for cash			400,000						2,000									2,000
Stock issued for exercise of warrant			639,840				1		(1	)								—
Stock issued to employees 401(k) plan			49,842						495									495
Stock awards granted to employees									427									427
Stock issued for services			8,660						64									64
Balance, December 31, 2005	—		22,072,383	$	—	$	22	$	203,434		$	(47,171	)	$	(40,612	)	$	115,673
Comprehensive income:
Net loss															(48,478	)		(48,478	)
Other comprehensive loss, net of tax:
Change in fixed-price contract and other derivative fair value												39,710						39,710
Reclassification adjustments-contract settlements												7,889						7,889
Total comprehensive loss																		(879	)
Equity offering costs									(393	)								(393	)
Stock awards granted to employees									1,012									1,012
Stock options granted to directors									430									430
Stock issued to employees 401(k) plan			51,131						607									607
Stock issued to refinance debt			82,500						904									904
Balance, December 31, 2006	—		22,206,014	$	—	$	22	$	205,994		$	428		$	(89,090	)	$	117,354

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 pipeline network owned through Quest Midstream.

All of the Company’s natural gas and oil wells and natural gas and oil leasehold interests are owned by Quest Cherokee.

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, indirect subsidiary of the Company. The membership interests of Quest Cherokee are owned by QES, QOG, PGPC, STP, PSI and J-W Gas. QES, QOG, PGPC and STP are wholly-owned by the Company. PGPC is the sole member of PSI and PSI is the sole member of J-W Gas.

Quest Cherokee is the sole member of QCOS. QCOS owns all of the Company’s oilfield service equipment and vehicles and employs all of the Company’s field level employees and first line supervisors that work on the Company’s natural gas and oil wells.

QES employs all of the Company’s non-field employees that work on the Company’s natural gas and oil wells. 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.

Our natural gas gathering pipeline network is owned by Bluestem. Bluestem was a wholly-owned subsidiary of Quest Cherokee until the formation and contribution of our mid-stream assets to Quest Midstream on December 22, 2006.

On December 13, 2006, we formed Quest Midstream to own and operate our natural gas gathering pipeline system. On December 22, 2006, we transferred Bluestem to Quest Midstream in exchange for 4.9 million class B subordinated units, 35,134 class A subordinated units and a 2% general partner interest. Also on December 22, 2006, Quest Midstream sold 4,864,866 common units, representing an approximate 48.64% interest in Quest Midstream, for $18.50 per common unit, or approximately $90 million, pursuant to a purchase agreement dated December 22, 2006, to a group of institutional investors led by Alerian Capital Management, LLC, and co-led by Swank Capital, LLC.

Quest Midstream GP, the sole general partner of Quest Midstream, was formed on December 13, 2006. Quest Midstream GP owns 200,000 General Partner Units representing a 2% general partner interest in Quest Midstream. The Company owns 850 Member Interests representing an 85% ownership interest in Quest Midstream GP, Alerian owns 75 Member Interests representing a 7.5% ownership interest in Quest Midstream GP and Swank owns 75 Member Interests representing a 7.5% ownership interest in Quest Midstream GP.

Financial reporting by the Company’s subsidiaries is consolidated into one set of financial statements with the Company.

Terms of Subordinated Promissory Notes. Prior to November 14, 2005, the subordinated promissory notes of Quest Cherokee 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.

Consolidation Policy. Investee companies in which the Company directly or indirectly owns more than 50% of the outstanding voting securities or those in which the Company has effective control over are generally accounted for under the consolidation method of accounting. Under this method, an Investee company’s balance sheet and results of operations are reflected within the Company’s Consolidated Financial Statements. All significant intercompany accounts and transactions have been eliminated. Minority interests in the net assets and earnings or losses of a consolidated Investee are reflected in the caption “Minority interest” in the Company’s Consolidated Balance Sheet and Statement of Operations. Minority interest adjusts the Company’s consolidated results of operations to reflect only the Company’s share of the earnings or losses of the consolidated Investee company. Upon dilution of control below 50%, the accounting method is adjusted to the equity or cost method of accounting, as appropriate, for subsequent periods.

Financial reporting by the Company’s subsidiaries is consolidated into one set of financial statements for QRC.

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.

The Company’s financial statements are prepared using the accrual method of accounting. Revenues are recognized when earned and expenses when incurred.

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.

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. The Company’s cash balances typically are in excess of this amount.

Restricted Cash represents cash pledged to support reimbursement obligations under outstanding letters of credit.

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, 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.

A significant portion of the Company’s liquidity is concentrated in cash and derivative contracts 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 years ended December 31, 2006 and 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.

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. The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred. Unevaluated properties are assessed individually when individual costs are significant.

We review the carrying value of our oil and natural gas properties under the full-cost accounting rules of the Securities and Exchange Commission on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, plus the cost of properties not being amortized, less any related income tax effects. In calculating future net revenues, current prices and costs used are those as of the end of the appropriate quarterly period. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives qualifying as cash flow hedges. Two primary factors impacting this test are reserve levels and current prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of natural gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. Under SEC regulations, the excess above the ceiling is not expensed (or is reduced) if, subsequent to the end of the period, but prior to the release of the financial statements, oil and natural gas prices increase sufficiently such that an excess above the ceiling would have been eliminated (or reduced) if the increased prices were used in the calculations.

As of December 31, 2006, the Company’s net book value of oil and gas properties exceeded the ceiling. Accordingly, a provision for impairment was recognized in the fourth quarter of 2006 of $30.7 million. The provision for impairment is primarily attributable to declines in the prevailing market prices of oil and gas at the measurement date.

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 is reviewed on an annual basis for impairment and as of December 31, 2006, 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.

Included in other assets are costs associated with bank credit facilities. The remaining unamortized debt issue costs at December 31, 2006 and 2005 totaled $9.1 million and $5.8 million, respectively, and are being amortized over the life of the credit facilities.

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.

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, 2006 and 2005, the Company did not have any investments in its investment portfolio classified as available for sale and held to maturity.

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.

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.

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.

The Company’s financial instruments consist of cash, receivables, deposits, hedging contracts, accounts payable, accrued expenses 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 notes payable approximate fair value due to the variable nature of the interest rates of the notes payable.

Stock Awards. The Company granted shares of common stock to certain employees in October, November and December, 2006 and in October 2005. The shares are subject to pro rata vesting which ranges from 0 to 4 years. During this vesting period, the fair value of the stock awards granted is recognized pro rata as compensation expense. 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.

Stock Options. Effective January 1, 2006, the Company adopted SFAS No. 123 (Revised 2004), Share-Based Payment, which requires that compensation related to all stock-based awards, including stock options, be recognized in the financial statements based on their estimated grant-date fair value. We have previously recorded stock compensation pursuant to the intrinsic value method under APB Opinion No. 25, whereby compensation was recorded related to performance share and unrestricted share awards and no compensation was recognized for most stock option awards. We are using the modified prospective application method of adopting SFAS No. 123R, whereby the estimated fair value of unvested stock awards granted prior to January 1, 2006 will be recognized as compensation expense in periods subsequent to December 31, 2005, based on the same valuation method used in our prior pro forma disclosures. We have estimated expected forfeitures, as required by SFAS No. 123R, and we are recognizing compensation expense only for those awards expected to vest. Compensation expense is amortized over the estimated service period, which is the shorter of the award’s time vesting period or the derived service period as implied by any accelerated vesting provisions when the common stock price reaches specified levels. All compensation must be recognized by the time the award vests. The cumulative effect of initially adopting SFAS No. 123R was immaterial.

The following are pro forma net income and earnings per share for the year ended December 31, 2005, the seven months ended December 31, 2004, and the year ended May 31, 2004, as if stock-based compensation had been recorded at the estimated fair value of stock awards at the grant date, as prescribed by SFAS No. 123, Accounting for Stock-Based Compensation :

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. The Company has adopted SFAS 133, as amended by SFAS 138, Accounting for Derivative Instruments and Hedging Activities, which contains 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.

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.

The Company has 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.

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.

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.

In November, 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 million was allocated to wells and $7 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 a $120 million term loan that closed in June 2004.

The Company acquired approximately 80 miles of an inactive oil pipeline for approximately $1 million on August 10, 2004. Additionally, the Company acquired 8 wells and approximately 8,000 acres in the Cherokee Basin on August 6, 2004 for $750,000. These acquisitions were funded with a portion of the remaining net proceeds from a $120 million term loan that closed in June 2004.

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:

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 then existing credit facilities. 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:

The following pro forma summary data for 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.

The aggregate scheduled maturities of notes payable and long-term debt for the five years ending December 31, 2011 and thereafter were as follows as of December 31, 2006:

As of December 31, 2006, the Company’s credit facilities consisted 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, a $100 million Second Lien Term Loan Agreement between the Company, Quest Cherokee, Guggenheim, as Administrative Agent, and the lenders party thereto and a $75 million Third 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 of the Second Lien Term Loan Agreement on November 14, 2005. The Third Lien Term Loan Agreement consists of a six year $75 million third lien term loan that was fully funded at the closing of the Third Lien Term Loan Agreement on June 9, 2006.

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. As of December 31, 2006, the borrowing base under the revolving credit facility was $100 million.

The Company pays 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.

Interest accrues on the revolving credit facility at LIBOR plus 1.75% or the base rate plus 0.75%, at our option. Interest accrues on the first lien term loan at LIBOR plus 3.25% or the base rate plus 2.50%, at our option. Interest accrues on the second lien term loan at LIBOR plus 5.50%. Interest accrues on the third lien term loan at LIBOR plus 8.00%. The effective interest rates for the year ended December 31, 2006 under the Company’s credit facilities are as follows:

The revolving credit facility and the first lien term loan may be prepaid, without any premium or penalty, at any time. The second lien term loan may be repaid at any time, subject to the payment of a prepayment premium described below. The third lien term loan may not be repaid prior to June 10, 2007. Thereafter, the third lien term loan may be repaid at any time, subject to the payment of a prepayment premium described below.

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 third lien term loan is secured by a third 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, or whose obligations under the hedging agreements are guaranteed by an entity with such a rating. As of December 31, 2006, all of the Company’s natural gas swap and collar hedging agreements were secured on a pari passu basis with the revolving credit facility.

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.

Under all three 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 all three 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.

As of December 31, 2006, the Company was in compliance with the covenants under its credit facilities and other notes payable. The Company subsequently determined that it would not be in compliance with the Total Net Debt to EBITDA ratio under its credit facilities as of March 31, 2007 without raising additional capital. The board of directors considered issuing a sufficient number of additional shares of common stock in order to enable the Company to comply with this loan covenant. However, the board of directors determined that the cost of obtaining a waiver from its lenders would be more favorable to the Company’s existing shareholders than issuing additional equity at the then current market price for the Company’s common stock. On April 25, 2007, the

Company obtained a waiver of the breach of the Total Net Debt to EBITDA covenant as of March 31, 2007 and reset the covenant for the remainder of 2007.

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%.

In connection with the formation of Quest Midstream, L.P. on December 22, 2006, the Company entered into amendments to each of the credit agreements. Among other things, the amendments permitted the Company to transfer the member interests in Bluestem to Quest Midstream, released the security interests of the lenders in the member interests and assets of Bluestem and resulted in the pledge of the Company’s class A and class B subordinated limited partner interests in Quest Midstream and the Company’s 85% member interest in Quest Midstream GP as collateral for the credit facilities.

In connection with the amendments, the prepayment provisions of the second and third lien term loans were amended. After giving effect to the amendments, the prepayment provisions are as follows: If the Company prepays second lien term loan during the 12 months beginning on (i) November 15, 2006, the Company will pay a 3.5% premium, (ii) November 15, 2007, the Company will pay a 2.25% premium, and (iii) November 15, 2008, the Company will pay a 1.124% premium. Thereafter, the Company may repay the second lien term loan at any time without any premium or prepayment penalty. The third lien term loan may not be repaid prior to June 10, 2007. If the Company prepays the third lien term loan during the 12 months beginning on (i) June 10, 2007, the Company will pay a 2.5% premium, (ii) June 10, 2008, the Company will pay a 1.25% premium, and (iii) June 10, 2009, the Company will pay a 0.5% premium. Thereafter, the Company may repay the third lien term loan at any time without any premium or prepayment penalty.

$569,000 of notes payable to banks and finance companies were outstanding at December 31, 2006 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.

The Company has authorized 200,000,000 shares of common stock and 50,000,000 shares of preferred stock. As of December 31, 2006, there were 22,206,014 shares of common stock outstanding and no shares of preferred stock outstanding. During the year ended December 31, 2006, the Company recorded the following transactions:

The following transactions were recorded in the Company’s financial statements during the year ended December 31, 2005.

The following transactions were recorded in the Company’s financial statements during the seven-month transition period ended December 31, 2004.

The following transactions were recorded in the Company’s financial statements during the fiscal year ended May 31, 2004.

Stock Awards. The Company granted a total of 80,000 shares of common stock to a total of 2 employees in 2006 and a total of 140,000 shares of common stock to a total of 5 employees in 2005. The shares are subject to pro rata vesting which ranges from 0 to 4 years. During this vesting period, the fair value of the stock awards granted is recognized pro rata as compensation expense. 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, 2006 and 2005, the Company recognized $1,063,000 and $427,000 of total compensation related to stock awards. Of these amounts, $779,000 and $352,000 were reflected in general and administrative expenses as compensation expense with the remaining $284,000 and $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.

During 2006, two of the directors resigned. Each resigning director forfeited options to acquire 30,000 shares that were unvested at the time of resignation. The remaining 20,000 options expired in 2007 (90 days after the date of resignation) without being exercised.

A summary of the status of the Company’s stock options as of December 31, 2006, and changes during the year then ended is presented below.

Outstanding options to acquire 250,000 shares of common stock at December 31, 2006 had an exercise price of $10.00, a weighted-average exercise price of $10.00, and had a weighted-average remaining contractual life of 8.9 years.

Stock Rights. On May 31, 2006, the board of directors of the Company declared a dividend distribution of one right for each share of common stock of the Company, and the dividend was distributed on June 15, 2006. The rights are governed by a Rights Agreement, dated as of May 31, 2006, between the Company and UMB bank, n.a. Pursuant to the Rights Agreement, each right entitles the registered holder to purchase from the Company one one-thousandth of a share (“Unit”) of Series B Junior Participating Preferred Stock, $0.001 par value per share, at a purchase price of $75.00 per Unit. The rights, however, will not become exercisable unless and until, among other things, any person acquires 15% or more of the outstanding shares of common stock of the Company. If a person acquires 15% or more of the outstanding stock of the Company (subject to certain exceptions more fully described in the Rights Agreement), each right will entitle the holder (other than the person who acquired 15% or more of the outstanding common stock) to purchase common stock of the Company having a value equal to twice the exercise price of a right. The rights are redeemable under certain circumstances at $0.001 per right and will expire, unless earlier redeemed, on May 31, 2016.

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.

The components of other comprehensive income (loss) and related tax effects for the years ended December 31, 2006 and 2005, the seven-month transition period ended December 31, 2004 and the fiscal year ended May 31, 2004 are shown as follows:

	Gross			Tax Effect			Net of Tax
Year Ended December 31, 2006:
Change in fixed-price contract and other
derivative fair value	$	39,710,000		$	—		$	39,710,000
Reclassification adjustments –contract settlements		7,889,000			—			7,889,000
	$	47,599,000		$	—		$	47,599,000
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	)
Year Ended May 31, 2004:
Change in fixed-price contract and other
derivative fair value	$	(11,132,000	)	$	(1,088,000	)	$	(10,044,000	)
Reclassification adjustments –contract settlements		(649,000	)		(64,000	)		(585,000	)
	$	(11,781,000	)	$	(1,152,000	)	$	(10,629,000	)

The components of income tax expense for the years ended December 31, 2006 and 2005, for the seven-month transition period ended December 31, 2004 and for the fiscal year ended May 31, 2004 are as follows:

Reconciliations of income tax at the statutory rate to the Company’s effective rate for the years ended December 31, 2006 and 2005, for the seven-month transition period ended December 31, 2004 and for the fiscal year ended May 31, 2004 are as follows:

The following temporary differences gave rise to the net deferred tax liabilities at December 31, 2006, 2005 and 2004 and at May 31, 2004:

							Seven Months
	Year Ended			Year Ended			Ended			Year Ended
	December 31,			December 31,			December 31,			May 31,
	2006			2005			2004			2004
Deferred income tax assets, current:
Hedging contracts expenses per books but deferred for income tax reporting purposes	$	—		$	9,895,000		$	4,162,000		$	2,752,000
Total current deferred income tax assets		—			9,895,000			4,162,000			2,752,000
Deferred income tax assets, non- current:
Net operating loss carryforwards		28,643,000			16,849,000			8,961,000			4,715,000
Percentage depletion carryforwards		1,947,000			800,000			608,000			—
Total deferred income tax assets - non-current		30,590,000			17,649,000			9,569,000			4,715,000
Total deferred income tax assets		30,590,000			27,544,000			13,731,000			7,467,000
Deferred income tax liability, current:
Hedging contract income per books but deferred for income tax reporting purposes, net of other comprehensive income		(946,000	)		—			—			—
Total current deferred income tax liability		(946,000	)		—			—			—
Deferred income tax liability, long-term:
Book basis in property and equipment in excess of income tax basis		(111,000	)		(12,405,000	)		(7,424,000	)		(2,686,000	)
Total deferred income tax liability – long-term		(111,000	)		(12,405,000	)		(7,424,000	)		(2,686,000	)
Total deferred income tax liability		(1,057,000	)		(12,405,000	)		(7,424,000	)		(2,686,000	)
Net deferred income tax asset		29,533,000			15,139,000			6,307,000			4,781,000
Less: Valuation allowance		(29,533,000	)		(15,139,000	)		(6,307,000	)		(4,781,000	)
Total deferred tax (liability) asset	$	—		$	—		$	—		$	—

At December 31, 2006, the Company had federal income tax net operating loss (NOL) carryforwards of approximately $74,000,000. 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 $4,000,000. NOL’s incurred after November 14, 2005 will not be limited.

During the year ended December 31, 2006, non-cash investing and financing activities were as follows:

During the year ended December 31, 2005, non-cash investing and financing activities were as follows:

During the seven-month transition period ended December 31, 2004, non-cash investing and financing activities are as follows:

During the fiscal year ended May 31, 2004, non-cash investing and financing activities are as follows:

Quest Cherokee, LLC (“Quest Cherokee”), STP Cherokee, Inc. (“STP”), and Bluestem Pipeline, LLC (“Bluestem”) have been named defendants in a lawsuit (Case #CJ-2003-30) filed by plaintiffs, Eddie R. Hill, et al, on September 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 Quest Cherokee. Bluestem owns the gathering system that is used to gather gas from the wells in issue. The plaintiffs also allege, among other things, that STP and Quest Cherokee have engaged in self-dealing, have breached their fiduciary duties to the plaintiffs and have acted fraudulently towards the plaintiffs. Plaintiffs also allege that the gathering fees and related charges imposed by Bluestem should not be deducted by STP and Quest Cherokee in paying royalties. The plaintiffs are seeking unspecified actual and punitive damages as a result of the alleged conduct by STP, Quest Cherokee, and Bluestem. Discovery is ongoing and defendants intend to defend vigorously against these claims.

STP, Inc., STP Cherokee, Inc., and Bluestem have been named defendants in a lawsuit (Case No. CJ-2005-143) by plaintiffs John C. Kirkpatrick, et ux., in the District Court for Craig County, Oklahoma. Plaintiffs allege that STP, Inc., et al., through Bluestem, sold natural gas from wells owned by the plaintiffs to Quest Cherokee without proper notice to plaintiffs. Plaintiffs have requested an accounting and stated that if plaintiffs have suffered any damages for failure to properly pay royalties, plaintiffs have a right to recover those damages. Plaintiffs have not quantified their alleged damages. Discovery is ongoing and defendants are vigorously contesting the plaintiffs’ claims.

Quest Cherokee and Bluestem were named as defendants 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. Bluestem purchases and gathers the gas produced by Quest Cherokee. Plaintiff alleges that it is entitled to the coal bed methane gas produced and revenues from these leases and that Quest Cherokee is a trespasser. Plaintiff is seeking quiet title and an equitable accounting for the revenues from the coal bed methane gas produced. Plaintiff has alleged that Bluestem converted the gas and seeks an accounting for all gas purchased by Bluestem from the wells in issue. Quest Cherokee contends it has valid leases with the owners of the coal bed methane gas rights. The issue is whether the coal bed methane gas is owned by the owner of the coal rights or by the owners of the gas rights. If Quest Cherokee prevails on that issue, then the plaintiff’s claims against Bluestem fail. All issues relating to ownership of the coal bed methane gas and damages have been bifurcated. Cross motions for summary judgment on the ownership of the coal bed methane were filed by Quest Cherokee and the plaintiff, with summary judgment being awarded in Quest Cherokee’s favor. The plaintiff has appealed the summary judgment and that appeal is pending. Quest Cherokee and Bluestem intend to defend vigorously against these claims.

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. Bluestem is not a party to this lawsuit. Central Natural Resources owns the coal underlying approximately 2,250 acres of land in Craig

County, Oklahoma. Quest Cherokee has obtained oil and gas leases from the owners of the oil, gas, and minerals other than coal underlying those lands, and has drilled and completed 20 wells that produce coal bed methane gas on those lands. Plaintiff alleges that it is entitled to the coal bed methane gas produced and revenues from these leases and that Quest Cherokee is a trespasser. Plaintiff seeks to quiet its alleged title to the coal bed methane and an accounting of the revenues from the coal bed methane gas produced by Quest Cherokee. Quest Cherokee contends it has valid leases from the owners of the coal bed methane gas rights. The issue is whether the coal bed methane gas is owned by the owner of the coal rights or by the owners of the gas rights. Quest Cherokee has answered the petition and discovery is ongoing. Quest Cherokee intends to defend vigorously against these claims.

Quest Cherokee was named as a defendant in a lawsuit (Case No. 05 CV 41) filed by Labette Energy, LLC in the district court of Labette County, Kansas. Plaintiff claims to own a 3.2 mile gas gathering pipeline in Labette County, Kansas, and that Quest Cherokee used that pipeline without plaintiff’s consent. Plaintiff also contends that the defendants slandered its alleged title to that pipeline and suffered damages from the cancellation of their proposed sale of that pipeline. Plaintiff claims that they were damaged in the amount of $202,375. Discovery in that case is ongoing and Quest Cherokee intend to defend vigorously against the plaintiff’s claims.

Quest Energy Service, Inc. (“QES”) was named as a defendant in a lawsuit (Case No. 2006 CV 103) filed by Western Uniform and Towel Service, Inc. in the district court of Neosho County, Kansas. Plaintiff contends that QES has failed to pay for goods and services provided by the Plaintiff, and that QES wrongfully terminated certain contracts with the plaintiff to provide uniforms and merchandise to QES. Plaintiff has claimed damages of $464,267.33 for breach of contract, and $53,448.70 for lost goods. Discovery in that case is ongoing. QES intends to defend vigorously against plaintiff’s claims.

Bluestem and Quest Cherokee were named as defendants in a lawsuit (Case No. CJ-2007-325) filed by Devonian Enterprises, Inc. d/b/a Permian Land Company (“Permian”) in the district court of Oklahoma County, Oklahoma. Permian has asserted claims against Quest Cherokee and Bluestem in the amount of $521,252.88 for land services allegedly rendered to Quest Cherokee and Bluestem by Permian and for which no payment has purportedly been received by Permian. Quest Cherokee and Bluestem have asserted counterclaims against Permian for breach of contract and negligence, among other theories, due to Permian’s failure to file acquired instruments of record and deliver such records to Quest Cherokee and Bluestem, which has caused Quest Cherokee and Bluestem to incur unnecessary costs to re-acquire such instruments. In addition, Permian failed to ascertain whether or not minerals were leased or otherwise burdened and acquired oil and gas leases for Quest Cherokee and Bluestem, which were, in fact, burdened, causing Quest Cherokee and Bluestem to incur thousands of dollars in curative costs to acquire title to such minerals. Further, without approval, Permian inserted non-standard construction completion penalty provisions into said rights-of-way and easements, forcing Quest Cherokee and Bluestem to incur thousands of dollars in damages resulting from the unauthorized construction penalty provisions. Finally, Plaintiff has failed to return confidential information to Quest Cherokee and Bluestem pursuant to the parties’ written confidentiality and non-disclosure agreement. Quest Cherokee and Bluestem seek an undetermined amount of damages, injunctive relief, and an accounting to determine whether and to what extent Permian charged excessive fees for purported services it provided. Discovery is ongoing. Quest Cherokee and Bluestem intend to defend vigorously against Permian’s claims.

Quest Cherokee is a counterclaim defendant in a lawsuit (Case No. 2006 CV 74) filed by Quest Cherokee in district court of Labette County, Kansas. Quest Cherokee filed that lawsuit seeking a declaratory judgment that several oil and gas leases owned by Quest Cherokee are valid and in effect. In the counterclaim, defendants allege that those leases have expired by their terms and have been forfeited by Quest Cherokee. Defendants seek a declaration that those leases are null and void, statutory damages of $100, and their attorney’s fees. Discovery in that case is ongoing. Quest Cherokee intends to vigorously defend against those counterclaims.

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.

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:

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 years ended December 31, 2006 and 2005 and for the seven months ended December 31, 2004:

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 years ended December 31, 2006 and 2005, employees contributed $490,880 and $298,937, respectively to the plan and the Company contributed 51,131 and 49,842 shares of its common stock to the plan. The Company valued the 2006 and 2005 common stock contribution at $607,000 and $495,000, respectively, of which $428,000 and $266,000, respectively, was included as an expense in the statement of operations and $179,000 and $229,000, respectively, was included in oil and gas properties. 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.

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, 2006 and 2005, the Company’s monthly obligation under these leases totaled $736,000 and $490,000, respectively.

Additionally, the minimum annual rental commitments as of December 31, 2006 under non-cancellable office space leases are as follows: 2007 — $150,000; 2008 — $142,000 and 2009 — $59,000.

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 years ended December 31, 2006 and 2005 and for the seven-month transition period ended December 31, 2004 and 90% for the fiscal year ended May 31, 2004

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, 2006 and 2005 and the methods and assumptions used to estimate their fair value:

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 notes payable approximate fair value due to the variable nature of the interest rates of the notes payable.

The fair value of all derivative instruments as of December 31, 2006 and 2005 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.

Derivative assets and liabilities reflected as current in the December 31, 2006 and 2005 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.

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 years ended December 31, 2006 and 2005, the seven months ended December 31, 2004 and the fiscal year ended May 31, 2004, fixed-price contracts hedged approximately 61.0%, 89.0%, 85.0% and 83.0%, respectively, of the Company’s natural gas production. As of December 31, 2006, fixed-price contracts are in place

to hedge 20.1 Bcf of estimated future natural gas production. Of this total volume, 10.8 Bcf are hedged for 2007 and 9.3 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 a regional spot market index or in some cases, NYMEX future prices), 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) (generally a regional spot market index or in some cases, NYMEX future prices). 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, 2006. See “—Market Risk.”

(3) Does not include basis swaps with notional volumes by year, as follows: TBtu; 2007: 1.8 TBtu; 2008: 1.5 TBtu

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 years ended December 31, 2006 and 2005, the seven-month transition period ended December 31, 2004 and the fiscal year ended May 31, 2004, oil and gas sales included $7.9 million, $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 years ended December 31, 2006 and 2005, the seven months ended December 31, 2004 and the year ended May 31, 2004, other revenue and expense included $10.2 million, $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, 2006, the estimated amount of unrealized gains 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 $5.3 million.

The Company has entered into interest rate caps designed to hedge the interest rate exposure associated with borrowings under its credit facilities. All interest rate caps have been approved by the Company’s board of directors. The excess, if any, of the floating rate over the interest rate cap multiplied by the notional amount is the cap gain. This gain is included in interest expense in the period for which the interest rate exposure was hedged.

For interest rate 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 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, 2006, 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 $197,000.

The following table summarizes the notional amounts, interest rates and the fair value attributable to the interest rate caps as of December 31, 2006.

In connection with entering into the Company’s existing 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 in the statements of operations for the years ended December 31, 2006 and 2005, the seven-month transition period ended December 31, 2004 and the fiscal year ended May 31, 2004 are comprised of the following:

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.

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 the Company’s natural gas production to market prices, which, in a low price environment, could have an adverse effect on its future operating results. Cancellation or termination of an interest rate swap or cap would subject a greater portion of the Company’s long-term debt to market interest rates, which, in an inflationary environment, could have an adverse effect on its future net income. In addition, the associated carrying value of the derivative contract would be removed from the balance sheet.

The differential between the floating price paid under each energy swap or collar 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, some of 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 Central TX/KS/OK (“Southern Star”) first of month index, with a small portion being sold based on the daily price on the Southern Star index. The difference between natural gas prices on the NYMEX and the price actually received by the Company is referred to as a basis differential. Typically, the price for natural gas on the Southern Star first of the 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 the

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.

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.

The December 31, 2006 financial statements have been restated to correct for a misclassification of cash not subject to restrictions and for the manner in which certain settlements on derivative contracts were reflected in the income statement. The settlements on ineffective derivative contracts were reclassified from other revenue to change in derivative fair value. These reclassifications had no impact on earnings.

The Company’s aggregate capitalized costs related to natural gas and oil producing activities are summarized as follows:

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 in natural gas and oil property acquisition, exploration and development activities that have been capitalized are summarized as follows:

The Company’s results of operations from natural gas and oil producing activities are presented below for the years ended December 31, 2006 and 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.

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.

During 2005 we recorded revisions of 6 bcfe of downward adjustments caused by the under-performance of wells in a new area of development.

During 2006, we recorded revisions of 11 bcfe of downward adjustments caused by lower natural gas prices at December 31, 2006. Lower prices reduce the economic lives of the underlying oil and natural gas properties and thereby decrease the estimate future reserves.

The following schedule presents the standardized measure of estimated discounted future net cash flows from the Company’s proved reserves for the years ended December 31, 2006 and 2005, 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, 2006, 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.

The principal changes in the standardized measure of discounted future net cash flows relating to proven natural gas and oil properties were as follows:

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, 2006, 2005 and 2004:

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 change		(4,863,000	)		1,895,000
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

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

Summarized unaudited quarterly financial data for 2006, 2005 and 2004 are as follows:

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.

In February 2006, the FASB issued Statement No. 155, “Accounting for Certain Hybrid Financial Instruments” (“SFAS No. 155”), which amends FASB Statements No. 133 and 140. SFAS No. 155 permits fair value remeasurement for any hybrid financial instrument containing an embedded derivative that would otherwise require bifurcation, and broadens a Qualified Special Purpose Entity’s permitted holdings to include passive derivative financial instruments that pertain to other derivative financial instruments. SFAS No. 155 is effective for

all financial instruments acquired, issued or subject to a remeasurement event occurring after the beginning of an entity’s first fiscal year beginning after September 15, 2006. SFAS No. 155 has no current applicability to the Company’s financial statements. Management plans to adopt SFAS No. 155 on January 1, 2007 and it is anticipated that the initial adoption of this statement will not have a material impact on the Company’s financial position, results of operations, or cash flows.

In June 2006, the FASB issued Interpretation 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”), an interpretation of FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 clarifies the accounting and reporting for income taxes where interpretation of the law is uncertain. FIN 48 prescribes a comprehensive model for the financial statement recognition, measurement, presentation and disclosure of income tax uncertainties with respect to positions taken or expected to be taken in income tax returns. FIN 48 is effective for fiscal years beginning after December 15, 2006 and has no current applicability to the Company’s financial statements. Management plans to adopt FIN 48 on January 1, 2007 and it is anticipated that the initial adoption of FIN 48 will not have a material impact on the Company’s financial position, results of operations, or cash flows.

In September 2006, the FASB issued Statement No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 addresses how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands the required disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, with earlier adoption permitted. Management is assessing the impact of the adoption of SFAS No. 157.

In September 2006, the FASB issued Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (“SFAS No. 158”), an amendment of FASB Statements No. 87, 88, 106 and 132(R). SFAS No. 158 requires (a) recognition of the funded status (measured as the difference between the fair value of the plan assets and the benefit obligation) of a benefit plan as an asset or liability in the employer’s statement of financial position, (b) measurement of the funded status as of the employer’s fiscal year-end with limited exceptions, and (c) recognition of changes in the funded status in the year in which the changes occur through comprehensive income. The requirement to recognize the funded status of a benefit plan and the disclosure requirements are effective as of the end of the fiscal year ending after December 15, 2006. The requirement to measure the plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. SFAS No. 158 has no current applicability to the Company’s financial statements. Management plans to adopt SFAS No. 158 on December 31, 2006 and it is anticipated the adoption of SFAS No. 158 will not have a material impact to the Company’s financial position, results of operations, or cash flows.

In September 2006, the Securities Exchange Commission issued Staff Accounting Bulletin No. 108 (“SAB No. 108”). SAB No. 108 addresses how the effects of prior year uncorrected misstatements should be considered when quantifying misstatements in current year financial statements. SAB No. 108 requires companies to quantify misstatements using a balance sheet and income statement approach and to evaluate whether either approach results in quantifying an error that is material in light of relevant quantitative and qualitative factors. When the effect of initial adoption is material, companies will record the effect as a cumulative effect adjustment to beginning of year retained earnings and disclose the nature and amount of each individual error being corrected in the cumulative adjustment. SAB No. 108 will be effective beginning January 1, 2007 and it is anticipated that the initial adoption of SAB No. 108 will not have a material impact on the Company’s financial position, results of operations, or cash flows.

In February 2007, the FASB issued Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”), an amendment of FASB Statement No. 115. SFAS No. 159 addresses how companies should measure many financial instruments and certain other items at fair value. The objective is to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007, with earlier adoption permitted. Management is assessing the impact of the adoption of SFAS No. 159.

On January 31, 2007, our majority-owned subsidiary, Quest Midstream Partners, and its wholly-owned subsidiary, Bluestem, entered into a new credit agreement consisting of a five-year $75 million revolving credit facility. The Credit Agreement is among Bluestem, as the borrower, Quest Midstream, as a guarantor, Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto. Upon closing of this credit facility, $5 million was drawn as the initial borrowing. Further information regarding this transaction is disclosed in our Current Report on Form 8-K filed with the Securities and Exchange Commission on February 7, 2007.

(a)(1) and (2) Financial Statements and Financial Statement Schedules. See “Index to Financial Statements” set forth on page 49 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 52 of this Form 10-K that is incorporated herein by reference.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized this 14th day of January, 2008.

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

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

Title of Each Class	Name of Each Exchange on Which Registered
Common Stock	Nasdaq Global Market
Series B Junior Participating Preferred Stock Purchase Rights	Nasdaq Global Market

	PART I

ITEMS 1. AND 2.	BUSINESS AND PROPERTIES	5


ITEM 1A.	RISK FACTORS	26


	PART II

ITEM 6.	SELECTED FINANCIAL DATA	39

ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	41

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	56


	PART IV

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	57

	SIGNATURES	58

	INDEX TO EXHIBITS	59

Estimated Net Proved Reserves (Bcfe)	198.0
Percent Proved Developed (1)	60.4%
Producing Gas and Oil Wells (gross)	1,650
Approximate No. Proved Undeveloped Drill Sites (gross) (2)	1,760
Net Developed Acres (3)	241,634
Net Undeveloped Acres (3)	282,295
Total Net Acres	523,929

	12 Months Ended December 31,
	2006	2005	2004
Wells Drilled	622	99	466
Wells Recompleted	125	205	18
Wells Connected	638	233	164
Pipeline Miles	392	120	141
Well Completion %	99%	98%	98%
Total Capital Expenditures – (in thousands) (1)	$166,801 (2)	$41,442 (3)	$53,600

	Productive Wells								Leasehold Acreage (2)
As of	Natural Gas (1)		Oil		Total			Producing (3)			Non-Producing		Total Leased
Dec. 31	Gross	Net	Gross	Net	Gross	Net	Gross			Net	Gross	Net	Gross	Net
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
2006	1,653	1,609.9	29	27.9	1,682	1,637.8	394,795			385,149	147,247	138,780	542,042	523,929

	Year Ended December 31,		Seven Month Transition Period Ended December 31,	Year Ended May 31,
	2006	2005	2004	2004
Miles constructed	392	120	124	5
Miles acquired	—	10	—	300

	Year Ended December 31, 2006		Year Ended December 31, 2005		7 Months Ended December 31, 2004		Year Ended May 31, 2004
Pipeline Natural Gas Vols (mcf)	16,714,000		13,257,000		7,004,000		8,157,000

Long-term debt, net of current maturities			225,245			100,581			193,984			159,290			16,081			2,167
Stockholders’ equity (deficit)			117,354			115,673			(2,606	)		2,235			11,142			4,612

(1)	Excludes the effect of unrealized gains or losses on interest rate derivatives.

(2)	Fixed charges means the sum of (a) interest expensed and capitalized, (b) amortized premiums, discounts and capitalized expenses related to indebtedness, (c) an estimate of the interest within rental expense, and (d) preference security dividend requirements of consolidated subsidiaries.

(3)	Earnings is the amount resulting from (a) adding (i) pre-tax income from continuing operations, (ii) fixed charges, (iii) amortization of capitalized interest, (iv) distributed income of equity investees, and (v) our share of pre-tax losses of equity investees for which charges arising from guarantees are included in fixed charges and (b) subtracting from the total of the previous items (i) interest capitalized, (ii) preference security dividend requirements of consolidated subsidiaries, and (iii) the minority interest in pre-tax income of subsidiaries that have not incurred fixed charges. Equity investees are investments that we account for using the equity method of accounting.

(4)	Preference security dividend is the amount of pre-tax earnings that is required to pay dividends on outstanding preference securities. The dividend requirement is computed as the amount of the dividend divided by (1 minus the effective income tax rate applicable to continuing operations).

	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

	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		2007		2008-2009		2010-2011		Thereafter
First Lien Term Note	$	50,000,000	$	—	$	—	$	50,000,000	$	—
Second Lien Term Note		100,000,000		—		—		100,000,000		—
Third Lien Term Note		75,000,000		—		—		—		75,000,000
Revolver (1)		—		—		—		—		—
Asset retirement obligations		1,410,000		—		—		—		1,410,000
Drilling contractor		11,030,000		6,789,000		4,241,000		—		—
Notes payable		569,000		324,000		140,000		13,000		92,000
Lease obligations		351,000		150,000		142,000		59,000		—
Derivatives		12,693,000		5,244,000		7,449,000		—		—
Total	$	251,053,000	$	12,507,000	$	11,972,000	$	150,072,000	$	76,502,000

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM	F-1

CONSOLIDATED BALANCE SHEETS	F-3

CONSOLIDATED STATEMENTS OF OPERATIONS	F-4

CONSOLIDATED STATEMENTS OF CASH FLOWS	F-5

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY	F-6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	F-7

	Pipeline	15 to 40 years
	Buildings	25 years
	Equipment	10 years
	Vehicles	7 years

	Year Ended December 31,			Seven Months Ended December 31,			Year Ended May 31,
		2005			2004			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	)

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

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

2007	$	324,000
2008		110,000
2009		30,000
2010		50,007,000
2011		100,006,000
Thereafter		75,092,000
	$	225,569,000

	Year Ended December 31, 2006
			Weighted-Average
	Shares		Exercise Price
Outstanding at beginning of year		250,000	$	10.00
Granted		—		—
Exercised		—		—
Canceled/Forfeited		60,000	$	10.00
Outstanding at end of year		190,000	$	10.00
Exercisable at end of year		80,000	$	10.00
Weighted-average fair value of options granted during year	$	10.00

	Year Ended December 31,				Seven Months Ended December 31,		Year Ended May 31,
	2006		2005		2004		2004
Cash paid for interest	$	20,418,000	$	10,315,000	$	4,760,000	$	3,354,000
Cash paid for income taxes	$	—	$	—	$	—	$	—

	Income (Numerator)			Shares (Denominator)	Per Share Amount
For the year ended December 31, 2006:
Net loss	$	(48,478,000	)
Basic EPS income available to common shareholders	$	(48,478,000	)	22,100,753	$	(2.19	)
Effect of dilutive securities:
None		—		—
Diluted EPS income available to common shareholders	$	(48,478,000	)	22,100,753	$	(2.19	)


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 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	)

	December 31, 2006						December 31, 2005
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Derivative assets:
Interest rate swaps and caps	$	197,000		$	197,000		$	188,000		$	188,000
Basis swaps	$	62,000		$	62,000		$	—		$	—
Fixed-price natural gas swaps	$	2,207,000		$	2,207,000		$	—		$	—
Fixed-price natural gas collars	$	13,111,000		$	13,111,000		$	—		$	—
Derivative liabilities:
Basis swaps	$	(377,000	)	$	(377,000	)	$	—		$	—
Fixed-price natural gas swaps	$	—		$	—		$	(31,185,000	)	$	(31,185,000	)
Fixed-price natural gas collars	$	(12,316,000	)	$	(12,316,000	)	$	(30,733,000	)	$	(30,733,000	)
Credit facilities	$	(225,000,000	)	$	(225,000,000	)	$	(100,000,000	)	$	(100,000,000	)
Other financing agreements	$	(569,000	)	$	(569,000	)	$	(988,000	)	$	(988,000	)

Instrument Type	Term		Notional Amount (1)	Fixed Rate/Cap Rate	Floating Rate		Fair Value as of December 31, 2006
		$	98,705,000		3-month
Interest Rate Cap	Jan. 2007 - Sept. 2007	$	70,174,600	5.000%	LIBOR	$	197,000

	December 31,
Natural gas and oil properties and related lease equipment:		2006			2005
Proved	$	316,780,000		$	201,788,000
Unproved		9,545,000			18,285,000
		326,325,000			220,073,000
Accumulated depreciation, depletion and impairment		(92,732,000	)		(36,703,000	)
Net capitalized costs	$	233,593,000		$	183,370,000

	Gas – mcf		Oil – bbls
Proved reserves:
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
Purchase of reserves-in-place	—		—
Extensions and discoveries	87,002,842		9,740
Revisions of previous estimates	(11,000,000	)	—
Production	(12,282,142	)	(9,737	)
Balance, December 31, 2006	198,040,000		32,272
Proved developed reserves:
Balance, December 31, 2004	81,467,220		47,834

Balance, December 31, 2005		71,638,250		32,269
Balance, December 31, 2006		122,390,000		32,272

	Quarters Ended
	December 31,			September 30,			June 30,			March 31,
	2006			2006			2006			2006
Total revenues	$	27,944,000		$	16,705,000		$	13,716,000		$	12,120,000
Gross profit (loss) (1) (2)		(23,462,000	)		(2,785,000	)		(3,209,000	)		(2,098,000	)
Net income (loss) (3)		(41,342,000	)		(10,073,000	)		(5,780,000	)		8,717,000
Net income (loss) per common share:
Basic	$	(1.87	)	$	(0.46	)	$	(0.26	)	$	0.39
Diluted	$	(1.87	)	$	(0.46	)	$	(0.26	)	$	0.39

	Quest Resource Corporation

	/s/ Jerry D. Cash
	Jerry D. Cash
	Chief Executive Officer

Exhibit No.	Description
2.1*	Contribution, Conveyance and Assumption Agreement by and among Quest Midstream Partners, L.P., Quest Midstream GP, LLC, Quest Resource Corporation, Quest Cherokee, LLC, Bluestem Pipeline, LLC and the other subsidiaries of Quest Resource Corporation designated therein entered into on December 22, 2006, but effective as of December 1, 2006 (incorporated herein by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on December 29, 2006).
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*	Certificate of Designations for Series B Junior Participating Preferred Stock (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 1, 2006).
3.3*	Amendment to the Company’s Restated Articles of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 6, 2006).
3.4*	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*	Rights Agreement dated as of May 31, 2006, between Quest Resource Corporation and UMB Bank, n.a., which includes as Exhibit A, the Certificate of Designations Preferences and Rights of Series B Preferred Stock, as Exhibit B, the Form of Rights Certificate, and as Exhibit C, the Summary of Rights to Purchase Preferred Stock (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on June 1, 2006).
4.3*	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 (incorporated herein by reference to Exhibit 4.2 to the Company’s Annual Report on 10-K filed on March 31, 2006).
4.4*	Amendment No. 1 to 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 9th day of June, 2006 (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on June 14, 2006).
4.5*	Waiver and Amendment No. 2 dated as of December 22, 2006 by and among Quest Cherokee, LLC and Quest Resource Corporation, as borrowers, the financial institutions from time to time parties thereto and Guggenheim Corporate Funding, LLC, as administrative agent under that certain Amended and Restated Senior Credit Agreement dated as of February 7, 2006 by and among Quest Cherokee, LLC and Quest Resource Corporation, the financial institutions from time to time parties thereto and Guggenheim Corporate Funding, LLC, as administrative agent (incorporated herein by reference to Exhibit 10.9 to the Company’s Current Report on Form 8-K filed on December 29, 2006).
4.6*	Second Amended and Restated Security Agreement dated as of December 22, 2006 made by Quest Cherokee, LLC and Quest Resource Corporation and the Guarantors listed on the signature pages thereto or from time to time party thereto by execution of a Joinder Agreement in favor of Guggenheim Corporate Funding, LLC, in its capacity as Administrative Agent for the benefit of the Secured Parties under the Senior Credit Agreement (incorporated herein by reference to Exhibit 10.12 to the Company’s Current Report on Form 8-K filed on December 29, 2006).

4.7*	Amended and Restated Guaranty dated as of December 22, 2006, by each of J-W Gas Gathering, L.L.C., Ponderosa Gas Pipeline Company, LLC, Producers Service, LLC, Quest Cherokee Oilfield Service, LLC, Quest Energy Service, LLC, Quest Oil & Gas, LLC, and STP Cherokee, LLC, in favor of Guggenheim Corporate Funding, LLC, as administrative agent for the benefit of the secured parties under the Amended and Restated Security Agreement for the Senior Credit Agreement (incorporated herein by reference to Exhibit 10.15 to the Company’s Current Report on Form 8-K filed on December 29, 2006).
4.8*	Second 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, L.L.C., Bluestem Pipeline, LLC, Quest Cherokee Oilfield Service, LLC, and Guggenheim Corporate Funding, LLC, dated as of the 9th day of June, 2006 (incorporated herein by reference to Exhibit 4.8 to the Company’s Current Report on Form 8-K filed on June 14, 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).
4.10**	First Amendment to Mortgage, Deed of Trust, Security Agreement, Financing Statement and Assignment of Production by Quest Cherokee, LLC to Guggenheim Corporate Funding, LLC, dated July 31, 2006.
4.11*	Amended and Restated Second Lien Term Loan Agreement by and among Quest Cherokee, LLC, Quest Resource Corporation, Guggenheim Corporate Funding, LLC, and the Lenders party thereto, dated as of the 9th day of June, 2006 (incorporated herein by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on June 14, 2006).
4.12*	Waiver and Amendment No. 1 dated as of December 22, 2006 by and among Quest Cherokee, LLC and Quest Resource Corporation, as borrowers, the financial institutions from time to time parties thereto and Guggenheim Corporate Funding, LLC, as administrative agent under that certain Amended and Restated Second Lien Term Loan Agreement dated as of June 9, 2006 by and among Quest Cherokee, LLC and Quest Resource Corporation, the financial institutions from time to time parties thereto and Guggenheim Corporate Funding, LLC, as administrative agent (incorporated herein by reference to Exhibit 10.10 to the Company’s Current Report on Form 8-K filed on December 29, 2006).
4.13*	Second Amended and Restated Security Agreement dated as of December 22, 2006 made by Quest Cherokee, LLC and Quest Resource Corporation and the Guarantors listed on the signature pages thereto or from time to time party thereto by execution of a Joinder Agreement in favor of Guggenheim Corporate Funding, LLC, in its capacity as Administrative Agent for the benefit of the Secured Parties under the Second Lien Term Loan (incorporated herein by reference to Exhibit 10.13 to the Company’s Current Report on Form 8-K filed on December 29, 2006).
4.14*	Amended and Restated Guaranty dated as of December 22, 2006, by each of J-W Gas Gathering, L.L.C., Ponderosa Gas Pipeline Company, LLC, Producers Service, LLC, Quest Cherokee Oilfield Service, LLC, Quest Energy Service, LLC, Quest Oil & Gas, LLC, and STP Cherokee, LLC, in favor of Guggenheim Corporate Funding, LLC, as administrative agent for the benefit of the secured parties under the Second Amended and Restated Security Agreement for the Second Lien Term Loan (incorporated herein by reference to Exhibit 10.16 to the Company’s Current Report on Form 8-K filed on December 29, 2006).
4.15*	Third Lien Term Loan Agreement by and among Quest Cherokee, LLC, Quest Resource Corporation, Guggenheim Corporate Funding, and the Lenders party thereto, dated as of the 9th day of June, 2006 (incorporated herein by reference to Exhibit 4.5 to the Company’s Current Report on Form 8-K filed on June 14, 2006).

4.16*	Waiver and Amendment No. 1 dated as of December 22, 2006 by and among Quest Cherokee, LLC and Quest Resource Corporation, as borrowers, the financial institutions from time to time parties thereto and Guggenheim Corporate Funding, LLC, as administrative agent under that certain Third Lien Term Loan Agreement dated as of June 9, 2006, by and among Quest Cherokee, LLC and Quest Resource Corporation, the financial institutions from time to time parties thereto and Guggenheim Corporate Funding, LLC, as administrative agent (incorporated herein by reference to Exhibit 10.11 to the Company’s Current Report on Form 8-K filed on December 29, 2006).
4.17*	Amended and Restated Security Agreement dated as of December 22, 2006 made by Quest Cherokee, LLC and Quest Resource Corporation and the Guarantors listed on the signature pages thereto or from time to time party thereto by execution of a Joinder Agreement in favor of Guggenheim Corporate Funding, LLC, in its capacity as Administrative Agent for the benefit of the Secured Parties for the Third Lien Term Loan (incorporated herein by reference to Exhibit 10.14 to the Company’s Current Report on Form 8-K filed on December 29, 2006).
4.18*	Amended and Restated Guaranty dated as of December 22, 2006, by each of J-W Gas Gathering, L.L.C., Ponderosa Gas Pipeline Company, LLC, Producers Service, LLC, Quest Cherokee Oilfield Service, LLC, Quest Energy Service, LLC, Quest Oil & Gas, LLC, and STP Cherokee, LLC, in favor of Guggenheim Corporate Funding, LLC, as administrative agent for the benefit of the secured parties under the Amended and Restated Security Agreement for the Third Lien Term Loan (incorporated herein by reference to Exhibit 10.17 to the Company’s Current Report on Form 8-K filed on December 29, 2006).
4.19**	Credit Agreement dated as of January 31, 2007, by and among Bluestem Pipeline, LLC, Quest Midstream Partners, L.P., Royal Bank of Canada, and the Lenders party thereto.
4.20**	Guaranty for Credit Agreement by Quest Midstream Partners, L.P. in favor of Royal Bank of Canada, dated as of January 31, 2007.
4.21**	Pledge and Security Agreement for Credit Agreement by Quest Midstream Partners, L.P. for the benefit of Royal Bank of Canada, dated as of January 31, 2007.
4.22**	Pledge and Security Agreement for Credit Agreement by Bluestem Pipeline, LLC for the benefit of Royal Bank of Canada, dated as of January 31, 2007.
4.23**	Mortgage, Assignment, Security Agreement, Fixture Filing and Financing Statement (KS) by Bluestem Pipeline, LLC to Royal Bank of Canada, dated January 31, 2007.
4.24**	Mortgage, Assignment, Security Agreement, Fixture Filing and Financing Statement (OK) by Bluestem Pipeline, LLC to Royal Bank of Canada, dated January 31, 2007.
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).