UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-K/A-1

 

 

Commission file number: 0-17371

 

 

 

 

QUEST RESOURCE CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

 

 

Registrant’s Telephone Number:

405-488-1304

 

Securities Registered Pursuant to Section 12(b) of the Exchange Act:

 

 

Securities Registered Pursuant to Section 12(g) of the Exchange Act:

None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o      No þ

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.  Yes o      No þ

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o

 

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.

 

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

Large accelerated filer o          Accelerated filer þ          Non-accelerated filer o

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes o      No þ

 

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.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

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.

 

Explanatory Note

 

The purpose of this Amendment No. 1 to the Annual Report on Form 10-K is to correct certain typographical errors in the report of the Independent Registered Public Accounting Firm on page F-1 of this report.

 

This amended Form 10-K/A-1 does not attempt to modify or update any other disclosures set forth in the original Form 10-K except as set forth above. Additionally, this amended Form 10-K/A-1, except as set forth above, speaks as of the filing date of the original Form 10-K and does not update or discuss any other Company developments after the date of the original filings.

 

TABLE OF CONTENTS

 

 

The Company and Subsidiaries

 

Quest Resource Corporation.  Quest Resource Corporation is a Nevada corporation and was incorporated on July 12, 1982. Its principal executive offices are located at 9520 N. May Avenue, Suite 300, Oklahoma City, OK 73120 and its telephone number is (405) 488-1304. Quest Resource Corporation is referred to in this report as the “Company,” “Quest,” “we,” “us” and “our.” The Company is a holding company that conducts its operations primarily through its 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.

 

Other Subsidiaries.  Our remaining subsidiaries are:

 

 

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.

 

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. We own 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.

 

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.

 

General

 

A Glossary of Oil and Gas Terms is included in this report beginning on page 21.

 

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 198.0 Bcfe of net proved reserves with a PV-10 value of $268.1 million. 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 reserves are long-lived with a reserve life index of 20.3 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.

 

Summary of Cherokee Basin Properties as of December 31, 2006

 

 

 

Recent Drilling and Completion Activity and Pipeline Miles

 

 

 

 

Recent Developments

 

Third Lien Credit Facility

 

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.

 

Formation of Quest Midstream

 

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.

 

Amendment to Credit Facilities

 

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.

 

Quest Midstream Credit Agreement

 

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.

 

Business Strategy

 

Our goal is to create stockholder value by investing capital to increase reserves, production and cash flow. We intend to accomplish this goal by focusing on the following key strategies:

 

 

Competitive Strengths

 

 

 

Cherokee Basin CBM Production

 

The Cherokee Basin is located in southeastern Kansas and northeastern Oklahoma. Geologically, it is situated between the Forest City Basin to the north, the Arkoma Basin to the south, the Ozark Dome to the east and the Nemaha Ridge to the west. Structurally, the Cherokee Basin is separated from the Forest City Basin by the Bourbon Arch. The Cherokee Basin is a mature producing area with respect to conventional reservoirs such as the Bartlesville sandstones and the Mississippian 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.

 

Exploration & Production Activities

 

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 198.0 Bcf is net to the Company, and estimated proved oil reserves of 40,800 gross (32,272 net) barrels. The present value of these proved reserve assets, discounted at 10% of the future net cash flow from the net natural gas and oil reserves, is $268.1 million, before the effect of income taxes.

 

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%.

 

Producing Wells and Acreage

 

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.

 

Natural Gas and Oil Reserves

 

The following table summarizes the reserve estimate and analysis of net proved reserves of natural gas and oil as of December 31, 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 present value of estimated future net revenues from these reserves was calculated on a non-escalated price basis discounted at 10% per year. 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 and present value of future net cash flow amounts are estimates based upon current prices at the time the reports were prepared and do not take into account the effects of our natural gas hedging program.

 

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.

 

Production Volumes, Sales Prices, and Production Costs

 

The following tables set 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.

 

 

 

 

 

Summary of New and Abandoned Well Activity

 

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.

 

Delivery Commitments

 

Natural Gas

 

We do not have long-term delivery commitments. We market our own natural gas and more than 95% of the natural gas was sold to ONEOK Energy Marketing and Trading Company during 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.

 

Oil

 

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.

 

Hedging Activities

 

We seek to reduce our exposure to unfavorable changes in natural gas prices, which are subject to significant and often volatile fluctuation, through the use of fixed-price contracts. The fixed-price contracts are comprised of energy swaps and collars. These contracts allow us to predict with greater certainty the effective natural gas prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, we will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. Collar structures provide for participation in price increases and decreases to the extent of the ceiling prices and floors provided in those contracts.

 

The following table summarizes the estimated volumes, fixed prices, fixed-price sales and fair value attributable to the fixed-price contracts as of December 31, 2006. See Note 15 — Derivatives, in notes to consolidated financial statements of this Form 10-K.

 

 

 

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.

 

Pipeline Operations

 

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%.

 

Service Operations

 

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.

 

Regulation

 

Federal Regulation of the Gathering and Transportation of Gas

 

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.

 

None of our current activities are subject to such regulation by the FERC.

 

State Regulation of Natural Gas Gathering Pipelines

 

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.

 

Sales of Natural Gas

 

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.

 

Other

 

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.

 

Environmental Matters

 

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.

 

Air Emissions

 

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.

 

Hazardous Waste

 

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.

 

Site Remediation

 

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.

 

Waste and Storm Water Discharges

 

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.

 

Pipeline Safety

 

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.

 

Employee Health and Safety

 

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

 

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.

 

Competition

 

We operate in the highly competitive areas of acquisition and exploration of natural gas properties in which other competing companies may have substantially larger financial resources, operations, staffs and facilities. In seeking to acquire desirable new properties for future exploration we face competition from other natural gas and oil companies. Such companies may be able to pay more for prospective natural gas properties or prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit.

 

Since a significant majority of our pipeline and service operations presently support our exploration and development operations, these aspects of our business do not experience any significant competition.

 

Employees

 

At March 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.

 

Administrative Facilities

 

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.

 

Where To Find Additional Information

 

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.

 

Glossary of Oil and Gas Terms

 

The terms defined in this section are used throughout this Form 10-K.

 

Bcf.  Billion cubic feet of natural gas.

 

Bcfe.  Billion cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

 

Btu or British Thermal Unit.  The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

 

CBM.  Coal bed methane.

 

Cherokee Basin.  As used in this Form 10-K a ten county region in southeastern Kansas and northeastern Oklahoma.

 

Completion.  The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

 

Developed acreage.  The number of acres that are allocated or assignable to productive wells or wells capable of production.

 

Development well.  A well drilled within the proved boundaries of an oil or natural gas reservoir with the intention of completing the stratigraphic horizon known to be productive.

 

Dry hole.  A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

 

Exploitation.  Ordinarily considered to be a form of development within a known reservoir.

 

Exploratory well.  A well drilled to find and produce oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.

 

Farm-in or farm-out.  An agreement under which the owner of a working interest in an oil or gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

 

Field.  An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

 

Frac/fracturing.  The method used to increase the deliverability of a well by pumping a liquid or other substance into a well under pressure to crack and prop open the hydrocarbon formation.

 

Gathering system.  Pipelines and other equipment used to move natural gas from the wellhead to the trunk or the main transmission lines of a pipeline system.

 

Gross acres or gross wells.  The total acres or wells, as the case may be, in which a working interest is owned.

 

Highly volatile bituminous coal.  Bituminous coal with a high concentration of methane gas.

 

Horizon or formation.  The section of rock, from which gas is expected to be produced in commercial quantities.

 

mcf.  Thousand cubic feet of natural gas.

 

mcfe.  Thousand cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

 

MMBtu.  Million British thermal units.

 

mmcf.  Million cubic feet of natural gas.

mmcfe.  Million cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

 

Net acres or net wells.  The sum of the fractional working interests owned in gross acres or well, as the case may be.

 

NYMEX.  The New York Mercantile Exchange.

 

Permeability.  The ease of movement of water and/or gases through a soil material.

 

Perforation.  The making of holes in casing and cement (if present) to allow formation fluids to enter the well bore.

 

PV-10 or present value of estimated future net revenues.  An estimate of the present value of the estimated future net revenues from proved gas reserves at a date indicated after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of federal income taxes. The estimated future net revenues are discounted at an annual rate of 10% in accordance with the SEC’s practice, to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future net revenues are made using oil and natural gas prices and operating costs at the date indicated and held constant for the life of the reserves.

 

Productive well.  A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

 

Proved developed non-producing reserves.  Proved developed reserves expected to be recovered from zones behind casings in existing wells.

 

Proved developed reserves.  Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

 

Proved reserves.  The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

 

Proved undeveloped reserves or PUD.  Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

 

Reserve life index.  This index is calculated by dividing total proved reserves by the production from the previous year to estimate the number of years of remaining production.

 

Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

 

scf.  Standard cubic feet of natural gas.

 

Shut in.  Stopping an oil or gas well from producing.

 

Unconventional resource development.  A development in which the targeted reservoirs generally fall into three categories: (1) tight sands, (2) coal beds, and (3) gas shales. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require stimulation treatments or other special recovery processes in order to produce economic flow rate.

 

Undeveloped acreage.  Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas regardless of whether or not such acreage contains proved reserves.

 

Working interest.  The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

 

Risks Related to the Company’s Business

 

The volatility of natural gas and oil prices could have a material adverse effect on the Company’s business.

 

The Company’s revenues, profitability and future growth and the carrying value of its natural gas and oil properties depend to a large degree on prevailing natural gas and oil prices. The Company’s ability to maintain or increase its borrowing capacity and to obtain additional capital on attractive terms also substantially depends upon natural gas and oil prices. Prices for natural gas and oil are subject to large fluctuations in response to relatively minor changes in the supply and demand for natural gas and oil, uncertainties within the market and a variety of other factors in large part beyond the Company’s control, such as:

 

 

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.

 

Because the Company faces uncertainties in estimating proven recoverable natural gas reserves, you should not place undue reliance on such reserve information.

 

This Form 10-K contains estimates of natural gas reserves, and the future net cash flows attributable to those reserves, prepared by Cawley, Gillespie & Associates, Inc., the Company’s independent petroleum and geological engineers. There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond the Company’s control and the control of Cawley, Gillespie & Associates, Inc. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to these reserves, is a function of the available data; assumptions regarding future natural gas and oil prices; expenditures for future development and exploitation activities; and engineering and geological interpretation and judgment. Reserves and future cash flows may also be subject to material downward or upward revisions based upon production history, development and exploitation activities and natural gas and oil prices. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and value of cash flows from those reserves may vary significantly from the assumptions and estimates in this Form 10-K. Any significant variance from these assumptions to actual figures could greatly affect the Company’s estimates of reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classification of reserves based on risk of recovery, and estimates of the future net cash flows. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same available data. The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves included in this Form 10-K were prepared by Cawley, Gillespie & Associates, Inc. in accordance with the rules of the SEC, and are not intended to represent the fair market value of such reserves.

 

The 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’s natural gas sales are dependent on two customers.

 

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 incurs risks in acquiring producing properties.

 

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.

 

The Company may have difficulty managing growth in its business.

 

Because of the Company’s small size, growth in accordance with its business plans, if achieved, will place a significant strain on the Company’s financial, technical, operational and management resources. As the Company expands its activities and increases the number of projects it is evaluating or in which it participates, there will be additional demands on the Company’s financial, technical and management resources. The failure to continue to upgrade the Company’s technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the recruitment and retention of experienced managers, geoscientists and engineers, could have a material adverse effect on the Company’s business, financial condition and results of operations and the Company’s ability to timely execute its business plan.

 

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.

 

Risks Relating to the Company’s Common Stock

 

The Company’s stock price may be volatile.

 

The Company cannot assure you that an active public market for the Company’s common stock will develop in the future. The following factors could affect the Company’s stock price:

 

 

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.

 

The common stock is an unsecured equity interest.

 

As an equity interest, the common stock will not be secured by any of the Company’s assets. Therefore, in the event of the Company’s liquidation, the holders of the common stock will receive a distribution only after all of the Company’s secured and unsecured creditors have been paid in full. There can be no assurance that the Company will have sufficient assets after paying its secured and unsecured creditors to make any distribution to the holders of the common stock.

 

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.

 

None.

 

See Note 8 — Contingencies, in notes to consolidated financial statements, which is incorporated herein by reference.

 

No matters were submitted to a vote of security holders during the fourth quarter of 2006.

 

Market Information

 

Our common stock trades on The Nasdaq Global Market under the symbol “QRCP”. During the period from January 1, 2005 until April 10, 2006, our common stock was traded on the OTC Bulletin Board. Since April 10, 2006, the Company’s common stock has traded on The Nasdaq Global Market or its predecessor, The Nasdaq National Market (collectively, “NASDAQ”).

 

The table set forth below lists the range of high and low prices of the Company’s common stock on NASDAQ since April 11, 2006 and high and low bids on the OTC Bulletin Board for each quarter of our last two fiscal years. The high and low bids on the OTC Bulletin Board in the table reflect inter-dealer prices, without retail markup, markdown or commission and may not represent actual transactions. Prices have been adjusted to give effect to the 2.5 to 1.0 reverse stock split that was effective October 31, 2005.

 

 

The closing price for QRCP stock on March 6, 2007 was $8.00.

 

Record Holders

 

As of March 6, 2007, there were 22,206,014 shares of common stock issued and outstanding, held of record by approximately 880 shareholders.

 

Dividends

 

The payment of dividends on our stock is within the discretion of the board of directors and will depend on our earnings, capital requirements, financial condition and other relevant factors. We have not declared any cash dividends on our common stock for the last two fiscal years and do not anticipate paying any dividends on our common stock in the foreseeable future.

 

Our ability to pay dividends on our common stock is subject to restrictions contained in our credit facilities. See Item 7. “Management’s Discussion and of Financial Conditions and Results of Operations — Capital Resources and Liquidity” for a discussion of these restrictions.

 

In addition, the partnership agreement for Quest Midstream restricts the ability of Quest Midstream to pay distributions on the class A and class B subordinated units that we own if the minimum quarterly distribution has not been paid on all of the Quest Midstream common units. See Items 1 and 2 “Description of Business and Properties — Recent Events — First Amended and Restated Agreement of Limited Partnership of Quest Midstream Partners, L.P.” for additional information. The revolving credit facility for Bluestem also restricts the ability of Bluestem to pay any distributions if Bluestem is in default under the credit facility.

 

Recent Sales of Unregistered Securities

 

In connection with the amendment to our third lien term loan agreement, on December 22, 2006, we issued 82,500 shares of our common stock to the lenders under that agreement as a portion of the fees owed to such lenders in connection with the amendment. The shares were issued pursuant to Rule 506 of Regulation D under the Securities Act of 1933. In connection with the issuance of these shares, we agreed to file a re-sale shelf registration statement on Form S-3 with respect to these shares as soon as practicable, but in no event later than January 19, 2006.

 

Purchases of Equity Securities

 

None.

STOCK PRICE PERFORMANCE GRAPH

 

The following graph compares the performance of our Common Stock to a peer group in our SIC code index and to the Nasdaq market index for the past five years. The graph assumes the investment of $100 on December 31, 2001 and the reinvestment of all dividends. The graph shows the value of the investment at the end of each year.

 

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*

Among Quest Resource Corp, The NASDAQ Composite Index And A Peer Group

 

 

• $100 invested on 12/31/01 in stock or index-including reinvestment of dividends.

Fiscal year ending December 31.

 

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.

 

Ratio of Earnings to Combined Fixed Charges

 

 

 

 

Financial Data

 

The following table sets forth certain information regarding the production volumes, oil and gas sales, average sales prices received and expenses for the periods indicated: