UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

Form 10-K

 

 

Commission file number: 0-17371

 

 

QUEST RESOURCE CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

Registrant’s Telephone Number, including area code:

405-600-7704

 

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.  o

 

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

 

 

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

 

The aggregate market value of the voting common equity held by non-affiliates computed by reference to the last reported sale of the registrant’s common stock on June 29, 2007, the last business day of the registrant’s most recently completed second fiscal quarter, at $11.68 per share was $230,212,426. This figure assumes that only the directors and officers of the registrant, their spouses and controlled corporations were affiliates. There were 23,455,427 shares outstanding of the registrant’s common stock as of March 4, 2008.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

The definitive proxy statement relating to the registrant’s 2008 Annual Meeting of Stockholders is incorporated by reference in Part III to the extent described therein.

 

 

TABLE OF CONTENTS

 

 

 

General

 

Quest Resource Corporation is a Nevada corporation and was incorporated on July 12, 1982. Its principal executive offices are located at 210 Park Avenue, Suite 2750, Oklahoma City, OK 73102 and its telephone number is (405) 600-7704. Quest Resource Corporation is referred to in this report as the “Company,” “Quest,” “we,” “us” and “our.” Unless otherwise indicated, references to the Company include the Company’s subsidiaries.

 

We are an independent energy company engaged in the exploration, development, production and transportation of natural gas.

 

We divide our operations into two reportable business segments:

 

 

Gas and Oil Production Operations.  We conduct our gas and oil production operations through Quest Energy Partners, L.P. (Nasdaq: QELP), which we refer to as Quest Energy or QELP, in which we own approximately 57% of the limited partner interests. The general partner of Quest Energy is Quest Energy GP, LLC, which we refer to as Quest Energy GP, a wholly-owned subsidiary of the Company. Quest Energy GP has a 2% general partner interest and all incentive distribution rights in Quest Energy.

 

Our gas and oil production 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, 2007, we had 211.1 Bcfe of net proved reserves, of which approximately 99% were CBM and 66.9% were proved developed. We operate over 99% of our existing wells, with an average net working interest of 99% and an average net revenue interest of approximately 82%. We believe we are the largest producer of natural gas in the Cherokee Basin with an average net daily production of 46.7 Mmcfe for the year ended December 31, 2007. Our estimated net proved reserves at December 31, 2007 had estimated future net revenues discounted at 10%, which we refer to as the “standardized measure,” of $270.7 million. Our reserves are long-lived, with an average proved reserve-to-production ratio of 12.3 years (8.12 years for our proved developed properties) as of December 31, 2007. Our typical Cherokee Basin CBM well has a predictable production profile and a standard economic life of approximately 15 years.

 

We have entered into derivative contracts with respect to approximately 80% of our estimated net production from proved developed producing reserves through the fourth quarter of 2010. The derivative contracts for 2008 cover approximately 58% of our total estimated net production for 2008. We also intend to diversify our operations by pursuing accretive acquisitions of conventional and unconventional gas and oil assets outside the Cherokee Basin. Even if we do not make additional acquisitions, we believe that our multi-year inventory of additional development and drilling locations on our undeveloped acreage gives us the opportunity to maintain and increase our proved reserves and average net daily production.

 

As of December 31, 2007, we were operating approximately 2,254 gross gas wells, of which over 90% were multi-seam wells, and 29 gross oil wells. As of December 31, 2007, we owned the development rights to approximately 558,190 net acres throughout the Cherokee Basin and had only developed approximately 52% of our acreage. For 2008, we have budgeted approximately $39.3 million to drill and complete an estimated 325 gross wells and recomplete an estimated 60 gross wells, as well as an additional $37.0 million for acreage, equipment and vehicle replacement and purchases and salt water disposal facilities. Our recompletions generally consist of converting wells that were originally completed with single seam completions into multi-seam completions, which allows us to produce additional gas from different levels. For 2007, we had total capital expenditures of approximately $45.5 million, including $34.3 million to connect 251 gross wells and recomplete 34 gross wells. We expect to drill and connect 325 wells in 2008. At this time, we have identified our drilling locations for 2008 and many of these wells will be drilled on locations that are classified as containing proved reserves in our December 31, 2007 reserve report. As of December 31, 2007, our undeveloped acreage contained approximately 2,100 gross CBM

drilling locations, of which approximately 800 were classified as proved undeveloped. Over 99% of the CBM wells that have been drilled on our acreage to date have been successful. Our Cherokee Basin acreage is currently being developed utilizing primarily 160-acre spacing. However, several of our competitors are currently developing their CBM reserves in the Cherokee Basin on 80-acre spacing. We are currently conducting a pilot program to test the development of a portion of our acreage using 80-acre spacing. If our pilot project is successful, we could significantly increase the number of CBM drilling locations which are present on our acreage. None of our acreage or producing wells is associated with coal mining operations.

 

Natural Gas Pipelines Operations.  We conduct our natural gas pipelines operations through Quest Midstream Partners, L.P., which we refer to as Quest Midstream or QMLP, in which we own approximately 36.4% of the limited partner interests. The general partner of Quest Midstream is Quest Midstream GP, LLC, which we refer to as Quest Midstream GP, in which we own an 85% interest. Quest Midstream GP has a 2% general partner interest and all incentive distribution rights in Quest Midstream.

 

Bluestem Pipeline, LLC, a wholly-owned subsidiary of Quest Midstream (“Bluestem”), owns and operates a gas gathering pipeline network of approximately 1,994 miles that serves our acreage position. Presently, this system has a maximum daily throughput of 85 Mmcf/d and is operating at about 86% capacity. Quest Energy transports 100% of its gas production through our gas gathering pipeline network to interstate pipeline delivery points. Approximately 9% of the current volumes transported on our natural gas gathering pipeline system are for third parties.

 

As of December 31, 2007, we had an inventory of approximately 212 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.

 

Quest Pipelines (KPC), which we refer to as KPC, owns and operates a 1,120 mile interstate gas pipeline (the “KPC Pipeline”) which transports natural gas from Oklahoma and western Kansas to the metropolitan Wichita and Kansas City markets. Further, it is one of the only three pipeline systems currently capable of delivering gas into the Kansas City metropolitan market. The KPC system includes three compressor stations with a total of 14,680 horsepower and has a capacity of approximately 160 Mmcf/d. KPC has supply interconnections with the Transok, Panhandle Eastern and ANR pipeline systems, allowing distribution from the Anadarko and Arkoma basins, as well as the western Kansas and Oklahoma panhandle producing regions. KPC’s two primary customers are Kansas Gas Service (KGS) and Missouri Gas Energy (MGE), both of which are served under long-term natural gas transportation contracts. KGS, a division of ONEOK, Inc., is the local distribution company in Kansas for Kansas City and Wichita as well as a number of other municipalities. MGE, a division of Southern Union Company, is a natural gas distribution company that serves over a half-million customers in 155 western Missouri communities.

Organizational Structure.  The following chart reflects our organizational structure.

 

Recent Developments

 

Formation and IPO for Quest Energy.  In July 2007, we formed Quest Energy to acquire, exploit and develop oil and natural gas properties. On November 15, 2007, we transferred Quest Cherokee, LLC (which owned all of our Cherokee Basin gas and oil leases) and Quest Cherokee Oilfield Service, LLC (which owned all of our Cherokee Basin field equipment and vehicles) to Quest Energy in exchange for 3,201,521 common units and 8,857,981 subordinated units and a 2% general partner interest. Also on November 15, 2007, Quest Energy completed an initial public offering of 9,100,000 common units at $18.00 per unit, or $16.83 per unit after payment of the underwriting discount (excluding a structuring fee). Total proceeds from the sale of the common units in the initial public offering were $163.8 million, before underwriting discounts, a structuring fee and offering costs, of approximately $10.6 million, $0.4 million and $1.5 million, respectively. On November 9, 2007, Quest Energy’s common units began trading on the NASDAQ Global Market under the symbol “QELP”. We used the net proceeds of $151.2 million from Quest Energy’s initial public offering to repay a portion of our outstanding indebtedness.

 

Quest Energy GP, the sole general partner of Quest Energy, was formed in July 2007. Quest Energy GP is a wholly-owned subsidiary of the Company. Quest Energy GP owns 431,827 general partner units representing a 2% general partner interest in Quest Energy and all of the incentive distribution rights. For more information regarding Quest Energy’s initial public offering and related transactions, see Quest Energy’s Current Reports on Form 8-K filed November 9 and November 21, 2007.

 

KPC Acquisition; Quest Midstream Private Placement.  On November 1, 2007, Quest Midstream completed the purchase of the KPC Pipeline (a 1,120-mile interstate gas pipeline running from Oklahoma to Missouri, and certain lateral pipelines related to the KPC Pipeline) pursuant to a Purchase and Sale Agreement, dated as of October 9, 2007, by and among Quest Midstream, Enbridge Midcoast Energy, L.P. and Midcoast Holdings No. One, L.L.C., whereby Quest Midstream purchased all of the membership interests in the two general partners of Enbridge Pipelines (KPC), the owner of the KPC Pipeline, for a purchase price of approximately $133 million in cash, subject to adjustment for working capital at closing. In connection with this acquisition, Quest Midstream issued 3,750,000 common units for $20.00 per common unit, or approximately $75 million of gross proceeds. The net proceeds from the offering were used to pay a portion of the purchase price.

 

New Credit Agreements.  In connection with the closing of the acquisition of the KPC Pipeline, on November 1, 2007, Quest Midstream and Bluestem entered into an Amended and Restated Credit Agreement (the “QMP Credit Agreement”) that increased the aggregate commitment under Bluestem’s existing five-year revolving credit facility from $75 million to $135 million, added Quest Midstream as a co-borrower instead of a guarantor and changed the maturity date from January 31, 2012 to November 1, 2012. The QMP Credit Agreement is among Bluestem, Quest Midstream, Royal Bank of Canada (“RBC”), as administrative agent and collateral agent, and the lenders party thereto. As of December 31, 2007, the amount borrowed under the QMP Credit Agreement was $95 million.

 

In connection with the closing of Quest Energy’s initial public offering, on November 15, 2007, we entered into an Amended and Restated Credit Agreement (the “Quest Cherokee Credit Agreement”), as the initial co-borrower, with Quest Cherokee, as the borrower, Quest Energy Partners, as a guarantor, RBC, as administrative agent and collateral agent, KeyBank National Association, as documentation agent and the lenders party thereto. We and Quest Cherokee had previously been parties to the following credit agreements with Guggenheim Corporate Funding, LLC (“Guggenheim”): (i) Amended and Restated Senior Credit Agreement, dated February 7, 2006, as amended; (ii) Amended and Restated Second Lien Term Loan Agreement, dated June 9, 2006, as amended; and (iii) Third Lien Term Loan Agreement, dated June 9, 2006, as amended (collectively, the “Prior Credit Agreements”). Guggenheim and the lenders under the Prior Credit Agreements assigned all of their interests and rights (other than certain excepted interests and rights) in the Prior Credit Agreements to RBC and the new lenders under the Quest Cherokee Credit Agreement pursuant to a Loan Transfer Agreement, dated November 15, 2007, by and among us, Quest Cherokee, certain of our subsidiaries, Guggenheim, Wells Fargo Foothill, Inc., the lenders under the Prior Credit Agreements and RBC. The Quest Cherokee Credit Agreement amended and restated the Prior Credit Agreements in their entirety.

 

The credit facility under the Quest Cherokee Credit Agreement consists of a five-year $250 million revolving credit facility. Availability under the revolving credit facility is tied to a borrowing base that will be redetermined

by RBC and the lenders every six months taking into account the value of Quest Cherokee’s proved reserves. In addition, Quest Cherokee and RBC each have the right to initiate a redetermination of the borrowing base between each six-month redetermination. As of December 31, 2007, the borrowing base was $160 million, and the amount borrowed under the Quest Cherokee Credit Agreement was $94 million. At the closing of Quest Energy’s initial public offering, we were released as a co-borrower under the Quest Cherokee Credit Agreement.

 

Upon our release as a co-borrower under the Quest Cherokee Credit Agreement, we entered into a Credit Agreement (the “QRC Credit Agreement”), as the borrower, with RBC, as administrative agent and collateral agent, and the lenders party thereto. The credit facility under the QRC Credit Agreement consists of a three-year $50 million revolving credit facility. Availability under the revolving credit facility is tied to a borrowing base (which is equal to 50% of the market value of the common and subordinated units of Quest Energy and Quest Midstream owned by us) that will be redetermined each quarter by reference to the most recent compliance certificate delivered to RBC. As of December 31, 2007, the borrowing base was $50 million, and the amount borrowed under the QRC Credit Agreement was $44 million.

 

For more information regarding these credit agreements, see Note 3. Long-Term Debt to the consolidated financial statements included in this Form 10-K.

 

Pinnacle Merger.  On October 15, 2007, we, Quest MergerSub, Inc., our wholly-owned subsidiary (“MergerSub”), and Pinnacle Gas Resources, Inc. (“Pinnacle”) entered into an Agreement and Plan of Merger, pursuant to which MergerSub will merge (the “Merger”) with and into Pinnacle, with Pinnacle continuing as the surviving corporation and as our wholly-owned subsidiary. Pinnacle is an independent energy company engaged in the acquisition, exploration and development of domestic onshore natural gas reserves. It focuses on the development of CBM properties located in the Rocky Mountain region. Pinnacle holds CBM acreage in the Powder River Basin in northeastern Wyoming and southern Montana as well as in the Green River Basin in southern Wyoming. As of December 31, 2007, Pinnacle owned natural gas and oil leasehold interests in approximately 494,000 gross (316,000 net) acres, approximately 94% of which were undeveloped.

 

On February 6, 2008, the parties entered into an Amended and Restated Agreement and Plan of Merger (the “Merger Agreement”) to, among other things, modify the exchange ratio of Quest common stock that Pinnacle stockholders will receive in exchange for each share of Pinnacle stock from 0.6584 to 0.5278. Following the Merger, current Quest stockholders will own approximately 60.5% of the combined company and current Pinnacle stockholders will own approximately 39.5% of the combined company. The Merger will qualify as a reorganization within the meaning of Section 368(a) of the Internal Revenue Code of 1986, as amended, and the rules and regulations promulgated thereunder. Accordingly, the Merger is expected to be a tax-free transaction for the stockholders of both companies.

 

Business Strategy

 

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

 

 

 

Competitive Strengths

 

 

 

Our Relationship with Quest Energy

 

We conduct our gas and oil production operations through Quest Energy, in which we own approximately 57% of the limited partner interests. The general partner of Quest Energy is Quest Energy GP, a wholly-owned subsidiary of the Company. Quest Energy GP has a 2% general partner interest and all of the incentive distribution rights in Quest Energy.

 

In connection with Quest Energy’s initial public offering, we entered into the following agreements:

 

Omnibus Agreement.  Quest Energy, Quest Energy GP and we entered into an Omnibus Agreement, which governs Quest Energy’s relationship with us and our affiliates regarding the following matters:

 

 

Our maximum liability for our environmental indemnification obligations will not exceed $5 million, and we will not have any indemnification obligation for environmental claims or title defects until Quest Energy’s aggregate losses exceed $500,000.

Management Agreement.  Quest Energy, Quest Energy GP and Quest Energy Service, LLC, our wholly-owned subsidiary (“Quest Energy Service”), entered into a Management Services Agreement, under which Quest Energy Service will perform acquisition services and general and administrative services, such as accounting, finance, tax, property management, risk management, land, marketing, legal and engineering to Quest Energy, as directed by Quest Energy GP, for which Quest Energy will reimburse Quest Energy Service on a monthly basis for the reasonable costs of the services provided.

 

Our Relationship with Quest Midstream

 

We conduct our natural gas pipelines operations through Quest Midstream. The general partner of Quest Midstream is Quest Midstream GP, in which we own an 85% interest. Quest Midstream GP has a 2% general partner interest and all of the incentive distribution rights in Quest Midstream.

 

Investors’ Rights Agreement.  In connection with the formation of Quest Midstream in December 2006, we, Quest Midstream and Quest Midstream GP entered into an investors’ rights agreement dated as of December 22, 2006 with a group of institutional investors led by Alerian Capital Management, LLC (“Alerian”), and co-led by Swank Capital, LLC (“Swank”). 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 the Company occurs, a majority of the investors will have the right to cause Quest Midstream GP to effect 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 receive $20 per common unit (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 advise 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 $23.00 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 Quest Midstream GP 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 that results in the common units of Quest Midstream being listed on the Nasdaq Global Market or the New York Stock Exchange.

 

In connection with the closing of the acquisition of the KPC Pipeline, we, Quest Midstream, Quest Midstream GP, certain of the original investors and the new investors entered into an amended and restated investors’ rights agreement. The amended and restated investors’ rights agreement amended the original investors’ rights agreement to add the new investors that were not already a party to the original agreement and to make certain minor changes to reflect the occurrence of the private placement, which changes are reflected in the above description.

 

Omnibus Agreement.  In connection with the formation of Quest Midstream in December 2006, 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.

 

Registration Rights Agreement.  Quest Midstream also entered into a registration rights agreement with the investors on December 22, 2006. Under the registration rights agreement, Quest Midstream granted the investors certain piggyback registration rights and certain rights to require Quest Midstream to file and maintain a shelf registration statement for the resale of the common units by the investors. Under the registration rights agreement, at any time on or after the date that is 270 days after December 22, 2006, the investors (by action of the investors holding a majority of the common units subject to registration or action of certain of the investors) may require Quest Midstream to (a) file the shelf registration statement as soon as reasonably practicable, but in any event within 90 days, after notice to Quest Midstream, subject to certain changes in timing if Quest Midstream is then working toward the filing of a registration statement for an initial public offering, (b) use its commercially reasonable efforts to cause the shelf registration statement to be declared effective within 210 days after the initial filing of the shelf registration statement and (c) maintain effectiveness of the shelf registration statement with respect to each common unit included in the shelf registration statement, subject to certain suspension and blackout periods, until (i) the common unit is sold pursuant to a registration statement, (ii) the common unit is distributed to the public pursuant to Rule 144 or is eligible for sale without registration pursuant to Rule 144(k), in the opinion of counsel to Quest Midstream, or (iii) the common unit is sold to Quest Midstream or to the registrant or any subsidiary of the registrant.

 

Under the registration rights agreement, Quest Midstream is required to pay liquidated damages if the shelf registration statement is not filed or declared effective within the time periods established in the agreement, if the shelf registration statement is not maintained in accordance with the agreement and with respect to any common units required to be included in the shelf registration statement that are not included. The liquidated damages amount payable is $0.175 per common unit entitled to liquidated damages for each 90-day period for which liquidated damages are payable, subject to proration for periods of less than 90 days.

 

Description of Our Exploration and Production Properties and Projects

 

Cherokee Basin.  We produce CBM gas out of our properties located in the Cherokee Basin. 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. The Cherokee Basin is a mature producing area with respect to conventional reservoirs such as the Bartlesville sandstones and the Mississippian limestones, which were developed beginning in the early 1900s.

The Cherokee Basin is part of the Western Interior Coal Region of the central United States. The coal seams we target for development 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.

 

Characteristics of Coal Bed Methane.  The rock containing gas, referred to as “source rock,” is usually different from reservoir rock, which is the rock through which the gas is produced, while in CBM, the coal seam serves as both the source rock and the reservoir rock. The storage mechanism is also different. Gas is stored in the pore or void space of the rock in conventional gas, but in CBM, most, and frequently all, of the gas is stored by adsorption. This adsorption allows large quantities of gas to be stored at relatively low pressures. A unique characteristic of CBM is that the gas flow can be increased by reducing the reservoir pressure. Frequently, the coal bed pore space, which is in the form of cleats or fractures, is filled with water. The reservoir pressure is reduced by pumping out the water, releasing the methane from the molecular structure, which allows the methane to flow through the cleat structure to the well bore. Because of the necessity to remove water and reduce the pressure within the coal seam, CBM, unlike conventional hydrocarbons, often will not show immediately on initial production testing. Coalbed formations typically require extensive dewatering and depressuring before desorption can occur and the methane begins to flow at commercial rates. Our Cherokee Basin CBM properties typically dewater for a period of 12 months before peak production rates are achieved.

 

CBM and conventional gas both have methane as their major component. While conventional gas often has more complex hydrocarbon gases, CBM rarely has more than 2% of the more complex hydrocarbons. Once coalbed methane has been produced, it is gathered, transported, marketed and priced in the same manner as conventional gas. The CBM produced from our Cherokee Basin properties has an MMBtu content of approximately 970 MMBtu, compared to conventional natural gas hydrocarbon production which can typically vary from 1,050-1,300 MMBtus.

 

The content of gas within a coal seam is measured through gas desorption testing. The ability to flow gas and water to the well bore in a CBM well is determined by the fracture or cleat network in the coal. While, at shallow depths of less than 500 feet, these fractures are sometimes open enough to produce the fluids naturally, at greater depths the networks are progressively squeezed shut, reducing the ability to flow. It is necessary to provide other avenues of flow such as hydraulically fracturing the coal seam. By pumping fluids at high pressure, fractures are opened in the coal and a slurry of fluid and sand is pumped into the fractures so that the fractures remain open after the release of pressure, thereby enhancing the flow of both water and gas to allow the economic production of gas.

 

Cherokee Basin Projects.  Historically, we have developed our CBM reserves in the Cherokee Basin on 160-acre spacing. However, we are beginning to develop some test wells on 80-acre spacing. Our wells generally reach total depth in 1.5 days and our average cost for 2007 to drill and complete a well, excluding the related pipeline infrastructure, was approximately $124,000. We estimate that for 2008, Quest Energy’s average cost for drilling and completing a well will be approximately $121,000, excluding the related pipeline infrastructure. 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 production rate of 15-20 Mcf/d (net), steadily rising for the first twelve 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 dewatering period for a period of approximately twelve months. After 24 months, production begins to decline. The standard economic life is approximately 15 years. Our completed wells rely on very basic industry technology.

 

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, 2007, we recompleted approximately 43 wellbores in Kansas and an additional 7 wellbores in Oklahoma and we had an additional 100 wellbores awaiting recompletion to multi-seam producers. The recompletion strategy is to add four to five 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 dewatering 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 dewatering 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.

 

Other Basins.  Part of our business strategy is to expand our exploration, development and production activities beyond the Cherokee Basin. We currently own approximately 23,000 net undeveloped acres in Pennsylvania, Maryland, Texas and New Mexico. We expect our first vertical well in Pennsylvania to be completed and tested by the end of the second quarter of 2008. We plan to drill and complete additional wells during 2008 if the first well is successful. Additionally, we have drilled one well in New Mexico that is currently being tested. Overall, we plan to spend between $2.0 million and $3.0 million on drilling and completion of exploratory wells in 2008. In addition, we have entered into a Merger Agreement with Pinnacle that would add approximately 494,000 gross (316,000 net) acres, approximately 94% of which were undeveloped as of December 31, 2007. We also are actively seeking large acreage positions in other basins with emerging unconventional resource plays.

 

Gas and Oil Data

 

Estimated Net Proved Reserves.  The following table presents our estimated net proved gas and oil reserves relating to our natural gas and oil properties as of the dates presented based on our reserve reports as of the dates listed below. The data was prepared by the petroleum engineering firm Cawley, Gillespie & Associates, Inc. in Ft. Worth, Texas. We filed estimates of our gas and oil reserves for the calendar years 2007, 2006 and 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 gas and oil volumes from our operated properties only, regardless of net interest. The difference between the gas and oil reserves reported on Form EIA-23 and those reported in this table exceeds 5%. The standardized measure values shown in the table are not intended to represent the current market value of our estimated gas and oil reserves.

 

 

 

 

The data in the table above represents estimates only.  Gas and oil reserve engineering is inherently a subjective process of estimating underground accumulations of gas and oil that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of gas and oil that are ultimately recovered. See Item 1A — “Risk Factors — Risks Related to our Business — Our estimated proved reserves are based on many assumptions that may prove to be inaccurate.”

 

Production Volumes, Sales Prices and Production Costs.  The following table sets forth information regarding the natural gas and oil properties owned by us through our subsidiaries. The 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.

 

Producing Wells and Acreage.  The following tables set forth information regarding our ownership of productive wells and total acres as of December 31, 2005, 2006 and 2007. For purposes of the table below, productive wells consist of producing wells and wells capable of production.

 

 

 

 

During the year ended December 31, 2007, we drilled 575 gross (571 net) new wells on our properties, all being 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 have been focused on adding gas reserves. See “— Drilling Activities.” During the year ended December 31, 2007, we continued to lease additional acreage in certain core development areas of the Cherokee Basin.

 

 

 

 

As of December 31, 2007, in the Cherokee Basin, we had 287,903 net developed acres and 270,287 net undeveloped acres; in New Mexico, we had 184 net undeveloped acres; in Pennsylvania, we had 22,092 net undeveloped acres; in Maryland, we had 277 net undeveloped acres; and in Texas we had 141 net undeveloped acres. Developed acres are acres spaced or assigned to productive wells/units. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of gas or oil, regardless of whether such acreage contains proved reserves.

Drilling Activities.  The table below sets forth 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, recompletion, abandonment, and acquisition activities for the periods indicated are shown below (all wells are in the Cherokee Basin):

 

 

 

 

The 575 gross new natural gas wells completed for the year ended December 31, 2007 reflect an average activity level of approximately 48 gross wells per month. We plan to drill and complete an average of approximately 27 gross wells per month for year 2008, subject to capital being available for such expenditures.

 

During the period from December 31, 2007 through March 4, 2008, we drilled 73 gross wells and connected 65 gross wells. As of March 5, 2008, we were drilling 2 gross wells and approximately 140 gross wells were in the process of being completed.

 

Oilfield Operations

 

General.  As the operator of wells in which we have an interest, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Quest Energy Service manages all of our properties and employs production and reservoir engineers, geologists and other specialists. Quest Cherokee Oilfield Service, LLC, a wholly-owned subsidiary of Quest Energy, employs our Cherokee Basin field personnel.

 

Field operations conducted by our personnel include duties performed by “pumpers” or employees whose primary responsibility is to operate the wells. Other field personnel are experienced and involved in the activities of well servicing, the development and completion of new wells and the construction of supporting infrastructure for new wells (such as electric service, salt water disposal facilities, and 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. We are also 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, either we or a third-party contractor will run the casing, and we will perform the 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.

 

Gas and Oil Leases.  As of December 31, 2007, we had over 4,500 leases covering approximately 581,004 net acres. The typical gas lease provides for the payment of royalties to the mineral owner for all gas produced from any well drilled on the lease premises. This amount ranges from 18.75% to 12.5% resulting in an 81.25% to 87.5% net revenue interest to us.

 

Because the acquisition of gas and oil leases is a very competitive process, and involves certain geological and business risks to identify productive areas, prospective leases are sometimes held by other gas and oil operators. In order to gain the right to drill these leases, we may purchase leases from other gas and oil operators. In some cases, the assignor of such leases will reserve an overriding royalty interest, ranging from 1/32nd to 1/16th (3.125% to 6.25%), which further reduces the net revenue interest available to us to between 78.125% and 81.25%.

 

Approximately 75% of our gas and oil leases are held by production, which means that for as long as our wells continue to produce gas or oil, we will continue to own the lease.

 

Gas Gathering Operations

 

Gas Gathering System.  Our approximately 1,994 mile low pressure gas gathering pipeline network is owned by Bluestem, a wholly-owned subsidiary of Quest Midstream. 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. It is the largest gathering system in the Cherokee Basin with a current capacity of approximately 85 Mmcf/d and delivers virtually all its gathered gas into Southern Star Central Gas Pipeline at multiple interconnects. This gathering system includes approximately 48,000 horsepower of compression in the field (most of which are currently rented) as well as seven CO₂ amine treating facilities.

 

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 gas gathering pipeline infrastructure through the development of new pipelines and to a lesser extent, through the acquisition of existing pipelines.

 

For 2007, our average cost for pipeline infrastructure to connect a Cherokee Basin well was approximately $68,000. We estimate that our cost for pipeline infrastructure to connect a Cherokee Basin well will be approximately $65,000 for 2008. We expect to connect 325 wells in the Cherokee Basin in 2008.

 

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

 

 

The table below sets forth the natural gas volumes transported on our gas gathering pipeline network during the years ended December 31, 2007, 2006 and 2005.

 

Midstream Services Agreement.  Quest Energy and Quest Midstream are parties to a midstream services and gas dedication agreement entered into on December 22, 2006, but effective as of December 1, 2006. Pursuant to the midstream services agreement, Quest Midstream gathers and provides certain midstream services, including dehydration, treating and compression, to Quest Energy for all gas produced from Quest Energy’s wells in the Cherokee Basin that are connected to Quest Midstream’s gathering system.

 

The initial term of the midstream services agreement expires on December 1, 2016, with two additional five-year extension periods that may be exercised by either party upon 180 days’ notice. The fees charged under the midstream services agreement are subject to renegotiation upon the exercise of each five-year extension period.

 

Under the midstream services agreement, Quest Energy agreed to pay Quest Midstream an initial fee equal to $0.50 per MMBtu of gas for gathering, dehydration and treating services and $1.10 per MMBtu of gas for compression services, subject to an annual adjustment to be determined by multiplying each of the gathering services fee and the compression services fee by the sum of (i) 0.25 times the percentage change in the producer price index for the prior calendar year and (ii) 0.75 times the percentage change in the Southern Star first of month index for the prior calendar year. Such adjustment will be calculated within 60 days after the beginning of each year, but will be retroactive to the beginning of the year. Such fees will never be reduced below the initial rates described above. For 2008, the fees will be $0.51 per MMBtu of gas for gathering, dehydration and treating services and $1.13 per MMBtu of gas for compression services. In addition, at any time after each five year anniversary of the date of the midstream services agreement, each party will have a one-time option to elect to renegotiate the fees and/or the basis for the annual adjustment to the fees if the party believes there has been a material change to the economic returns or financial condition of either party. If the parties are unable to agree on the changes, if any, to be made to such terms, then the parties will enter into binding arbitration to resolve any dispute with respect to such terms.

 

In accordance with the midstream services agreement, Quest Energy bears the cost to remove and dispose of free water from its gas prior to delivery to Quest Midstream and of all fuel requirements necessary to perform the gathering and midstream services, plus any gas shrinkage.

 

Quest Midstream has an exclusive option for sixty days to connect to its gathering system each of the gas wells that Quest Energy develops in the Cherokee Basin. In addition, Quest Midstream will be required to connect to its gathering system, at its expense, any new gas wells that Quest Energy completes in the Cherokee Basin if Quest Midstream would earn a specified internal rate of return from those wells. This rate of return is subject to renegotiation once after the fifth anniversary of the agreement and once during each renewal period at the election of either party. Quest Midstream also has the sole discretion to cease providing services on all or any part of its gathering system if it determines that continued operation is not economically justified. If Quest Midstream elects to do so, it must provide Quest Energy with 90 days’ written notice and will offer Quest Energy the right to purchase that part of the terminated system. If Quest Energy does acquire that part of the system and it remains connected to any other portion of Quest Midstream’s gathering system, then Quest Energy may deliver its gas from the terminated system to Quest Midstream’s system, and a fee for any services provided by Quest Midstream will be negotiated.

 

In addition, Quest Midstream agreed to install the saltwater disposal lines for Quest Energy’s gas wells connected to Quest Midstream’s gathering system for an initial fee of $1.25 per linear foot and connect such lines to Quest Energy’s saltwater disposal wells for a fee of $1,000 per well, subject to an annual adjustment based on changes in the Employment Cost Index for Natural Resources, Construction, and Maintenance. For 2008, the fees will be $1.29 per linear foot to install saltwater disposal lines and $1,030 per well to connect such lines to Quest Energy’s saltwater disposal wells.

 

The midstream services agreement also requires the drilling of a minimum of 750 new wells in the Cherokee Basin during the two year period ending December 1, 2008, 575 of which have been drilled in the Cherokee Basin through December 31, 2007. Quest Energy expects to drill 325 wells in 2008. At this time, we have identified our drilling locations for 2008 and many of these wells will be drilled on locations that are classified as containing proved reserves in our December 31, 2007 reserve report.

Third Party Gas Gathering.  For services rendered to parties other than Quest Energy, Quest Midstream retains a portion of the gas ranging from 20-40% of the volumes sold. Approximately 9% of the gas transported on Quest Midstream’s natural gas gathering pipeline system is for third parties.

 

Interstate Pipeline Operations

 

On November 1, 2007, Quest Midstream completed the purchase of the KPC Pipeline pursuant to a Purchase and Sale Agreement, dated as of October 9, 2007, by and among Quest Midstream, Enbridge Midcoast Energy, L.P. and Midcoast Holdings No. One, L.L.C., whereby Quest Midstream purchased all of the membership interests in the two general partners of Enbridge Pipelines (KPC), the owner of the KPC Pipeline for a purchase price of approximately $133 million in cash, subject to adjustment for working capital at closing. Through the KPC acquisition, Quest Midstream acquired 1,120 miles of interstate pipeline in southeastern Kansas, northeastern Oklahoma, and southwestern Missouri.

 

Quest Pipelines (KPC) owns and operates a 1,120 mile interstate gas pipeline which transports natural gas from Oklahoma and western Kansas to the metropolitan Wichita and Kansas City markets. Further, it is one of the only three pipeline systems currently capable of delivering gas into the Kansas City metropolitan market. The KPC system includes three compressor stations with a total of 14,680 horsepower and has a capacity of approximately 160 Mmcf/day. KPC has supply interconnections with the Transok, Panhandle Eastern and ANR pipeline systems, allowing distribution from the Anadarko and Arkoma basins, as well as the western Kansas and Oklahoma panhandle producing regions.

 

Marketing and Major Customers

 

Exploration and Production Activities.  We market our own natural gas. For 2007, approximately 79% of our gas was sold to ONEOK Energy Marketing and Trading Company (“ONEOK”) and 21% was sold to Tenaska Marketing Ventures (“Tenaska”). More than 95% of our natural gas was sold to ONEOK in 2006 and 2005. No other customer accounted for more than 10% of our consolidated revenues for the years ended December 31, 2007, 2006 and 2005.

 

Our oil is currently being sold to Coffeyville Refining. Previously, it had been sold to Plains Marketing, L.P. We do not have long term delivery commitments for our gas and oil production.

 

If we were to lose any of these gas and oil purchasers, we believe that we would be able to promptly replace the purchaser.

 

Gas Gathering Activities.  Approximately 91% of the throughput on Quest Midstream’s gas gathering pipeline system is attributable to Quest Energy production with the balance being other third-party customers.

 

Interstate Pipeline Activities.  KPC’s two primary customers are Kansas Gas Service (KGS) and Missouri Gas Energy (MGE), both of which are served under long-term natural gas transportation contracts. For the period from November 1, 2007, the date of acquisition, through December 31, 2007, KPC sold approximately 60% of its gas to Kansas Gas Services (“KGS”), and 36% was sold to Missouri Gas Energy (“MGE”). KPC has nine firm transportation agreements with a weighted average remaining contract term of approximately five years. KGS, a division of ONEOK, Inc., is the local distribution company in Kansas for Kansas City and Wichita as well as a number of other municipalities; while MGE, a division of Southern Union Company, is a natural gas distribution company that serves over half-million customers in 155 western Missouri communities.

 

Hedging Activities

 

We seek to mitigate our exposure to volatility in commodity prices through our use of derivative contracts including fixed-price contracts comprised of energy swaps and collars. We have entered into derivative contracts with respect to approximately 80% of our total estimated net production from proved developed producing reserves through the fourth quarter of 2010. We have fixed price swaps and collars covering 40% and 40%, respectively, of our estimated net gas production from proved developed producing reserves in 2008 or 29% and 29%, respectively, of our total estimated net production for 2008. In addition, for 2009 and 2010, we have fixed price swaps covering 80% and 80%, respectively, of our estimated net gas production from proved developed producing reserves. By

removing a significant portion of price volatility of our future gas production we have mitigated, but not eliminated, the potential effects of changing gas prices on our cash flows from operations for those periods. We sell the majority of our gas based on the Southern Star first of month index, with the remainder sold on the daily price on the Southern Star index. All of our derivative contracts are based on the Southern Star first of month index, except for some of our older collar agreements covering approximately 2.9 Bcf of gas in 2008 (17% of our estimated net gas production from proved developed producing reserves) and fixed price swaps covering approximately 4.8 Bcf of gas in 2008 (27% of our estimated net gas production from proved developed producing reserves) that are based on NYMEX pricing. As a result, our derivative contracts do not expose us to basis differential risk, except for the NYMEX collars and swaps. We have entered into derivative contracts locking the basis differential on approximately 25% of these NYMEX volumes at a weighted average rate of approximately $1.09 per Mcf. For more information on our derivative contracts, see Note 14. Financial Instruments and Note 15. Derivatives, in the notes to the consolidated financial statements of this Form 10-K.

 

Competition

 

Oil and Gas Properties.  We operate in a highly competitive environment for acquiring properties, marketing gas and oil and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. As a result, our competitors may be able to pay more for productive gas and oil properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the gas and oil industry.

 

We are also affected by competition for drilling rigs, completion rigs and the availability of related equipment. In the past, the gas and oil industry has experienced shortages of drilling and completion rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant increases in the prices for this equipment and personnel. We are unable to predict when, or if, such shortages may occur or how they would affect our exploitation program.

 

Competition is also strong for attractive gas and oil producing properties, undeveloped leases and drilling rights, and we cannot assure you that we will be able to compete satisfactorily when attempting to make further acquisitions.

 

Gas Gathering.  Quest Midstream’s gas gathering system experiences minimal competition because approximately 91% of this system’s throughput is attributable to Quest Energy production under a long-term contract.

 

Interstate Pipelines.  We compete with other interstate and intrastate pipelines in the transportation of natural gas for transportation customers primarily on the basis of transportation rates, access to competitively priced supplies of natural gas, markets served by the pipelines, and the quality and reliability of transportation services. Major competitors include Southern Star Central Gas Pipeline, Kinder Morgan Interstate Gas Transmission’s Pony Express Pipeline and Panhandle Eastern Pipeline Company in the Kansas City market and Southern Star Central Gas Pipeline in the Wichita market.

 

Title to Properties

 

Oil and Gas Properties.  As is customary in the gas and oil industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of development operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence development operations on a property until we have cured any material title defects on such property. Prior to completing an acquisition of producing gas and oil leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title

opinions. As a result, we believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the gas and oil industry.

 

Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the gas and oil industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or will materially interfere with our use in the operation of our business. In many cases lands over which leases have been obtained are subject to prior liens which have not been subordinated to the leases. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this prospectus.

 

On a small percentage of our acreage (less than 1.0%), the land owner in the past transferred the rights to the coal underlying their land to a third party. With respect to those properties, we have obtained gas and oil leases from the owners of the oil, gas, and minerals other than coal underlying those lands. In Oklahoma and Kansas, the law is unsettled as to whether the owner of the gas rights or the coal rights is entitled to the CBM gas. We are currently involved in litigation with the owner of the coal rights on these lands to determine who has the rights to the CBM gas. See Note 8. Contingencies to the notes to the consolidated financial statements included in this Form 10-K.

 

Pipeline Rights-of-Way.  Substantially all of our gathering systems and our transmission pipeline are constructed within rights-of-way granted by property owners named in the appropriate land records. All of our compressor stations are located on property owned in fee or on property obtained via long-term leases or surface easements.

 

Our property or rights-of-way are subject to encumbrances, restrictions and other imperfections. These imperfections have not interfered, and we do not expect that they will materially interfere, with the conduct of our business. In many instances, lands over which rights-of-way have been obtained are subject to prior liens which have not been subordinated to the right-of-way grants. In some cases, not all of the owners named in the appropriate land records have joined in the right-of-way grants, but in substantially all such cases signatures of the owners of majority interests have been obtained. Substantially all permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets, and state highways, where necessary. Substantially all permits have also been obtained from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election.

 

Certain of our rights to lay and maintain pipelines are derived from recorded gas well leases, for wells that are currently in production; however, the leases are subject to termination if the wells cease to produce. In most cases, the right to maintain existing pipelines continues in perpetuity, even if the well associated with the lease ceases to be productive. In addition, because some of these leases affect wells at the end of lines, these rights-of-way will not be used for any other purpose once the related wells cease to produce.

 

Seasonal Nature of Business

 

Exploration, Production and Gas Gathering Activities.  Seasonal weather conditions and lease stipulations can limit our development activities and other operations and, as a result, we seek to perform a significant percentage of our development during the spring and summer months. These seasonal anomalies can pose challenges for meeting our well development objectives and increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

 

In addition, freezing weather, winter storms and flooding in the spring and summer have in the past resulted in a number of our wells being knocked off-line for a short period of time, which adversely affects our production volumes and revenues and increases our lease operating costs due to the time spent by field employees to bring the wells back on-line.

Generally, but not always, the demand for gas decreases during the summer months and increases during the winter months thereby affecting the price we receive for gas. Seasonal anomalies such as mild winters and hot summers sometimes lessen this fluctuation.

 

Interstate Pipeline Activities.  Due to the nature of the markets served by the KPC Pipeline, primarily the metropolitan Wichita and Kansas City markets’ heating load, the utilization rate of the KPC Pipeline has traditionally been much higher in the winter months (December through April) than in the remainder of the year. However, due to the nature of the firm transportation agreements under which the vast majority of the KPC Pipeline revenue is derived, we are, to a material degree, profit neutral to these seasonal fluctuations.

 

Environmental Matters and Regulation

 

General.  Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:

 

 

These laws, rules and regulations may also restrict the rate of gas and oil production below the rate that would otherwise be possible. The regulatory burden on the gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the gas and oil industry could have a significant impact on our operating costs.

 

The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

 

Waste Handling.  The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous solid wastes. Under the auspices of the federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, production and transportation of gas and oil are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain gas and oil exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, and waste oils, that may be regulated as hazardous wastes. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements.

 

Comprehensive Environmental Response, Compensation and Liability Act.  The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and

past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain environmental studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

 

We currently own, lease or operate numerous properties that have been used for gas and oil exploration, production, and transportation for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. In fact, there is evidence that petroleum spills or releases have occurred in the past at some of the properties owned or leased by us. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform plugging or pit closure operations to prevent future contamination.

 

Water Discharges.  The Clean Water Act (“CWA”) and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants in waste water and storm water, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The CWA regulates storm water run-off from oil and gas production operations and requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of the CWA may require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. Federal and state regulatory agencies can also impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

 

Our operations also produce wastewaters that are disposed via underground injection wells. These activities are regulated by the Safe Drinking Water Act (“SDWA”) and analogous state and local laws. The underground injection well program under the SDWA classifies produced wastewaters and imposes controls relating to the drilling and operation of the wells as well as the quality of the injected wastewaters. This program is designed to protect drinking water sources and requires a permit from the EPA or the designated state agency — in our case, the Oklahoma Corporation Commission and the Kansas Corporation Commission. Currently, our operations comply with all applicable requirements and have a sufficient number of operating injection wells. However, a change in the regulations or the inability to obtain new injection well permits in the future may affect our ability to dispose of the produced waters and ultimately affect the results of operations.

 

The primary federal law for oil spill liability is the Oil Pollution Act, or OPA, which addresses three principal areas of oil pollution: prevention, containment, and cleanup. OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, may be subject to oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills.

 

Air Emissions.  The Federal Clean Air Act (“CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. Such laws and regulations may require a facility to 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 or strictly comply with air permits containing various emissions and operational limitations or utilize specific emission control technologies to limit emissions. In addition, EPA has developed, and continues to develop, stringent

regulations governing emissions of toxic air pollutants at specified sources. Moreover, depending on the state-specific statutory authority, states may be able to impose air emissions limitations that are more stringent than the federal standards imposed by EPA. Federal and state regulatory agencies can also impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations.

 

Permits and related compliance obligations under the CAA, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas, may require gas and oil exploration, production and transportation operations to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies. In addition, some gas and oil facilities may be included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under the CAA. Failure to comply with these requirements could subject a regulated entity to monetary penalties, injunctions, conditions or restrictions on operations and enforcement actions. Gas and oil exploration and production facilities may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

 

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.

 

The Kyoto Protocol to the United Nations Framework Convention on Climate Change, or the Protocol, became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as “greenhouse gases”, that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol; however, Congress has recently considered proposed legislation directed at reducing “greenhouse gas emissions”, and certain states have adopted legislation, regulations and/or initiatives addressing greenhouse gas emissions from various sources, primarily power plants. Additionally, on April 2, 2007, the U.S. Supreme Court ruled in Massachusetts v. EPA that the EPA has authority under the CAA to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks). The Court also held that greenhouse gases fall within the CAA’s definition of “air pollutant”, which could result in future regulation of greenhouse gas emissions from stationary sources, including those used in gas and oil exploration, production and transportation operations. The gas and oil industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. Our operations are not adversely impacted by the current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

 

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.

 

National Environmental Policy Act.  Gas and oil exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more

detailed Environmental Impact Statement that may be made available for public review and comment. If we were to conduct any exploration and production activities on federal lands in the future, those activities would need to obtain governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of gas and oil projects.

 

Endangered Species Act.  The Endangered Species Act (“ESA”) and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Although we believe that our current operations do not affect endangered or threatened species or their habitats, the existence of endangered or threatened species in areas of future operations and development could cause us to incur additional mitigation costs or become subject to construction or operating restrictions or bans in the affected areas.

 

OSHA and Other Laws and Regulation.  We are subject to the requirements of the federal Occupational Safety and Health Act, or OSH Act, and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The Occupational Safety and Health Administration’s hazard communication standard, EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other comparable laws.

 

We believe that we are in substantial compliance with all existing environmental and safety laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. For instance, we did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2007. Additionally, as of the date of this report, we are not aware of any environmental issues or claims that will require material capital expenditures during 2008. However, accidental spills or releases may occur in the course of our operations, and we cannot assure you that we will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. Moreover, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our business, financial condition, or results of operations.

 

Other Regulation of the Gas and Oil Industry

 

The gas and oil industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the gas and oil industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the gas and oil industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

 

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including gas and oil facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

 

Drilling and Production.  Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

 

 

 

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from gas and oil wells, generally prohibit the venting or flaring of gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, gas and gas liquids within its jurisdiction.

 

The Cherokee Basin has been an active gas and oil producing region for a number of years. Many of our properties had abandoned oil and conventional gas wells on them at the time the current lease was entered into with the landowner. A number of these wells remain unplugged or were improperly plugged by a prior landowner or operator. Many of the former operators of these wells have ceased operations and cannot be located or do not have the financial resources to plug these wells. We believe that we are not responsible for plugging an abandoned well on one of our leases, unless we have used, attempted to use or invaded the abandoned well bore in our operations on the land or have otherwise agreed to assume responsibility for plugging the wells. The law is unsettled in the State of Kansas as to who has the responsibility to plug such abandoned wells and the Kansas Corporation Commission, or KCC, issued a Show Cause Order in February 2007 requiring Quest Energy’s operating company, Quest Cherokee, to demonstrate why it should not be held responsible for plugging 22 abandoned and unplugged oil wells on land covered by a gas lease that it owns and operates in Wilson County, Kansas, and upon which Quest Cherokee has drilled and is operating a gas well. See Note 8. Contingencies to the notes to the consolidated financial statements in this Form 10-K.

 

Gas Marketing.  The availability, terms and cost of transportation significantly affect sales of gas. The interstate transportation and sale for resale of gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to gas pipeline transportation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the gas industry, most notably interstate gas transmission companies that remain subject to FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the gas industry, and these initiatives generally reflect more light handed regulation. We cannot predict the ultimate impact of these regulatory changes to our gas marketing operations, and we note that some of 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 gas marketers with which we compete.

 

The Energy Policy Act of 2005, or EP Act 2005, gave FERC increased oversight and penalty authority regarding market manipulation and enforcement. EP Act 2005 amended the NGA to prohibit market manipulation and also amended the Natural Gas Act of 1938 or NGA, and the Natural Gas Policy Act of 1978, or NGPA, to increase civil and criminal penalties for any violations of the NGA, NGPA and any rules, regulations or orders of FERC to up to $1,000,000 per day, per violation. In addition, FERC issued a final rule effective January 26, 2006 regarding market manipulation, which makes it unlawful for any entity, in connection with the purchase or sale of gas or transportation service subject to FERC’s jurisdiction, to defraud, make an untrue statement or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud. This final rule works together with FERC’s enhanced penalty authority to provide increased oversight of the gas marketplace.

 

Although gas prices are currently unregulated, FERC promulgated regulations in December 2007 requiring natural gas sellers to submit an annual report, beginning in May 2009, reporting certain information regarding natural gas purchases and sales (e.g., total volumes bought and sold, volumes bought and sold and index prices, etc.). Additionally, Congress historically has been active in the area of gas regulation. We cannot predict whether

new legislation to regulate gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and gas liquids are not currently regulated and are made at market prices.

 

State Regulation.  The various states regulate the drilling for, and the production, gathering and sale of, gas and oil, including imposing severance taxes and requirements for obtaining drilling permits. For example, Kansas currently imposes a severance tax on the gross value of gas and oil produced from wells having an average daily production during a calendar month with a gross value of more than $87 per day. Kansas also imposes gas and oil conservation assessments per barrel of oil and per 1,000 cubic feet of gas produced. In general, gas and oil leases and gas and oil wells (producing or capable of producing), including all equipment associated with such leases and wells, are subject to an ad valorem property tax.

 

Oklahoma imposes a monthly gross production tax and excise tax based on the gross value of the gas and oil produced. Oklahoma also imposes an excise tax based on the gross value of gas and oil produced. All property used in the production of gas and oil is exempt from ad valorem taxation if gross production taxes are paid. Lastly, the rate of taxation of locally assessed property varies from county to county and is based on the fair cash value of personal property and the fair cash value of real property.

 

States may regulate rates of production and may establish maximum daily production allowables from gas and oil wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of gas and oil that may be produced from our wells and to limit the number of wells or locations we can drill.

 

Federal Regulation of the Gathering and Transportation of Gas

 

FERC regulates interstate natural gas pipelines pursuant to the NGA, NGPA and EP Act 2005. Generally, FERC’s authority over interstate natural gas pipelines extends to:

 

 

Rates charged by interstate natural gas pipelines may generally not exceed the just and reasonable rates approved by FERC. In addition, interstate natural gas pipelines are prohibited from granting any undue preference to any person, or maintaining any unreasonable difference in their rates, terms, or conditions of service. Consistent with these requirements, the rates, terms, and conditions of the natural gas transportation services provided by interstate pipelines are governed by tariffs approved by FERC.

 

We own and operate one interstate natural gas pipeline system that is subject to these regulatory requirements. Specifically, we acquired ownership of Enbridge Pipelines (KPC) effective November 1, 2007, and renamed that entity Quest Pipelines (KPC) (“KPC”). KPC owns and operates a 1,120-mile interstate natural gas pipeline system which transports natural gas from Oklahoma and western Kansas to the metropolitan Wichita and Kansas City markets. As an interstate natural gas pipeline, KPC is subject to FERC’s jurisdiction and the regulatory requirements summarized above. We believe KPC is in full compliance with these requirements. Maintaining such compliance on an ongoing basis requires KPC to incur various expenses. Additional compliance expenses could be

incurred if new or amended laws or regulations are enacted or existing laws or regulations are reinterpreted. KPC’s customers, state commissions, and other interested parties also have the right to file complaints seeking changes in the KPC tariff, including with respect to the transportation rates stated therein.

 

Our remaining natural gas pipeline facilities are generally exempt from FERC’s jurisdiction and regulation pursuant to section 1(b) of the NGA, which exempts pipeline facilities that perform primarily a gathering function, rather than a transportation function. We believe our pipeline facilities (other than the KPC system) meet the traditional tests used by FERC to distinguish gathering facilities from transportation facilities. However, if FERC were to determine that the facilities perform primarily a transportation function, rather than a gathering function, these facilities may become subject to regulation as interstate natural gas pipeline facilities. We believe the expenses associated with seeking certificate authority for construction, service and abandonment, establishing rates and a tariff for these other facilities, and meeting the detailed regulatory accounting and reporting requirements would substantially increase our operating costs and would adversely affect our profitability.

 

Additionally, while generally exempt from FERC’s jurisdiction, FERC has nevertheless proposed new internet posting requirements that may be applicable to certain gathering facilities and other non-interstate pipelines meeting size and other thresholds. If these rules are adopted and become applicable to our gathering facilities, they would likely require us to post certain pipeline operational information on a daily basis, which could require us to incur additional compliance expenses.

 

State Regulation of Natural Gas Gathering Pipelines

 

Our natural gas gathering 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 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 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. 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 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 FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines.

Pipeline Safety

 

Our pipelines are subject to regulation by the U.S. Department of Transportation, or the DOT, under the Natural Gas Pipeline Safety 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.

 

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.

 

Employees

 

At March 1, 2008, we had an experienced staff of 309 field employees in offices located in Olathe, Wichita, Medicine Lodge, Chanute and Howard, Kansas and Lenapah, Oklahoma, which offices include 59 pipeline operations employees. Also, at the headquarters office in Oklahoma City and the Quest Midstream office in Houston, TX, our staff consists of 66 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 210 Park Avenue, Suite 2750, Oklahoma City, OK 73102. The office lease is for 10 years expiring August 31, 2017 covering approximately 35,000 square feet with annual rental costs of approximately $631,000.

 

Quest Midstream has 3,433 square feet of office space for some of its management personnel that is leased and is located at 3 Allen Center, 333 Clay Street, Suite 3650, Houston, TX 77002. The office lease is for 60 months expiring March 31, 2012 with annual rental costs of $101,000.

We 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. We own an additional building on Johnson Road for field offices. An office building at 127 West Main in Chanute, Kansas is owned and operated by us as a geological laboratory.

 

Quest Midstream owns an operational office that is located east of Chanute, Kansas.

 

KPC has leased facilities at Olathe, Wichita, and Medicine Lodge, Kansas for the operations of its interstate pipeline. The Olathe office consists of approximately 7,650 square feet for a lease term of five years expiring October 31, 2011 with annual lease costs of $113,640. The Wichita office consists of approximately 1,240 square feet on a one year lease, with an extension expiring December 31, 2008, with annual rental payments of $13,200. The Medicine Lodge field office is leased on a month to month basis with monthly rental payments of $300.

 

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 SELECTED TERMS

 

The following is a description of the meanings of some of the oil and natural gas industry terms used in this Form 10-K.

 

Bbl.  One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.

 

Bbl/D.  One Bbl per day.

 

Bcf.  One billion cubic feet of gas.

 

Bcfe.  One billion cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of crude oil, condensate or gas liquids.

 

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

 

CBM.  Coal bed methane.

 

Cherokee Basin.  A fifteen-county region in southeastern Kansas and northeastern Oklahoma.

 

Completion.  The installation of permanent equipment for the production of oil or 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 gas reservoir to the depth of a stratigraphic horizon known to be productive.

 

Dry hole or well.  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.  A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

 

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.

 

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.

 

Gas.  Hydrocarbon gas found in the earth, composed of methane, ethane, butane, propane and other gases.

 

Gathering system.  Pipelines and other equipment used to move 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 we have a working interest.

 

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

 

Mcf.  One thousand cubic feet of gas.

 

Mcf/D.  One Mcf per day.

 

Mcfe.  One thousand cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of crude oil, condensate or gas liquids.

 

MBbl.  One thousand Bbls.

 

MMBtu.  One million British thermal units.

 

MMcf.  One million cubic feet of gas.

MMcf/D.  One MMcf per day.

 

MMcfe.  One Mcf equivalent, determined using the ratio of six Mcf of gas to one Bbl of crude oil, condensate or gas liquids.

 

MMcfe/D.  One MMcfe per day.

 

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

 

Net production.  Production that is owned by us less royalties and production due others.

 

Net revenue interest.  The percentage of revenues due an interest holder in a property, net of royalties or other burdens on the property.

 

NGLs.  The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

 

NYMEX.  The New York Mercantile Exchange.

 

Oil.  Crude oil, condensate and NGLs.

 

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

 

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

 

Productive well.  A well that produces commercial quantities of hydrocarbons exclusive of its capacity to produce at a reasonable rate of return.

 

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. This definition of proved developed reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the internet at http://www.sec.gov/about/forms/regs-x.pdf.

 

Proved reserves.  The estimated quantities of crude oil, natural gas and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. This definition of proved reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the internet at http://www.sec.gov/about/forms/regs-x.pdf.

 

Proved undeveloped reserves or PUDs.  Proved reserves that are expected to be recovered from new wells drilled to known reservoirs on acreage yet to be drilled for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required to establish production. This definition of proved undeveloped reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the internet at www.sec.gov/about/forms/regs-x.pdf.

 

Recompletion.  The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

 

Reserve.  That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.

 

Reserve-to-production ratio.  This ratio is calculated by dividing estimated net 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.

 

Royalty Interest.  A real property interest entitling the owner to receive a specified portion of the gross proceeds of the sale of oil and natural gas production or, if the conveyance creating the interest provides, a specific portion of oil or natural gas produced, without any deduction for the costs to explore for, develop or produce the oil and gas. A royalty interest owner has no right to consent to or approve the operation and development of the property, while the owners of the working interests have the exclusive right to exploit the mineral on the land.

 

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

 

Standardized measure.  The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Standardized measure does not give effect to derivative transactions.

 

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 Our Business.

 

Gas prices are very volatile, and if commodity prices decline significantly for a temporary or prolonged period, our revenues, profitability and cash flows will decline.

 

The gas market is very volatile, and we cannot predict future gas prices. Prices for gas may fluctuate widely in response to relatively minor changes in the supply of and demand for gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

 

 

 

In the past, the prices of gas have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2007, the NYMEX monthly gas index price (last day) ranged from a high of $7.59156 per MMBtu to a low of $5.445 per MMBtu.

 

Our revenue, profitability and cash flow depend upon the prices and demand for gas and oil, and a drop in prices can significantly affect our financial results and impede our growth. In particular, declines in commodity prices will:

 

 

Future price declines may result in a write-down of our asset carrying values.

 

Lower gas prices may not only decrease our revenues, profitability and cash flows, but also reduce the amount of gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. Substantial decreases in gas prices would render a significant number of our planned exploitation projects uneconomic. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our gas properties for impairments. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and may, therefore, require a write-down of such carrying value. For example, for the year ended December 31, 2006, we had an impairment charge of $30.7 million. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our credit facilities.

 

Unless we replace the reserves that we produce, our existing reserves and production will decline, which would adversely affect our revenues, profitability and cash flows.

 

Producing gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. CBM production generally declines at a shallow rate after initial increases in production as a consequence of the dewatering process. Our future gas reserves, production, cash flow and ability to make distributions depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations. Factors that may hinder our ability to acquire additional reserves include competition, access to capital, prevailing gas prices and attractiveness of properties for sale.

 

As of December 31, 2007, our proved reserve-to-production ratio was 12.3 years. Because this ratio includes our proved undeveloped reserves, we expect that this ratio will not increase even if those proved undeveloped reserves are developed and the wells produce as expected. The proved reserve-to-production ratio reflected in our reserve report of December 31, 2007 will change if production from our existing wells declines in a different manner than we have estimated and can change when we drill additional wells, make acquisitions and under other circumstances.

We may not be able to replace our reserves or generate cash flows if we are unable to raise capital.

 

In order to increase our asset base, we will need to make substantial capital expenditures for the exploitation, development, production and acquisition of gas and oil reserves and the construction of additional gas gathering pipelines and related facilities. These maintenance capital expenditures may include capital expenditures associated with drilling and completion of additional wells to offset the production decline from our producing properties or additions to our inventory of unproved properties or our proved reserves to the extent such additions maintain our asset base. These expenditures could increase as a result of:

 

 

Our cash flow from operations and access to capital are subject to a number of variables, including:

 

 

Historically, we have financed these expenditures primarily with cash generated by operations and proceeds from bank borrowings and equity financings. If our revenues or borrowing base decreases as a result of lower natural gas and oil prices, operating difficulties or declines in reserves, we 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 we borrow money to expand our business, we will face the risks of leverage.

 

As of December 31, 2007, we had incurred $44 million of indebtedness for borrowed money, Quest Energy had incurred $94 million of indebtedness for borrowed money and Quest Midstream had incurred $95 million of indebtedness for borrowed money. We anticipate that we may in the future incur additional debt for financing our growth. Our 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 we did not borrow. The risk of loss in such circumstances is increased because we would be obligated to meet fixed payment obligations on specified dates regardless of our revenue. If we do not make our debt service payments when due, we may sustain the loss of our equity investment in any of our assets securing such debt, upon the foreclosure on such debt by a secured lender. The interest payable on our debt varies with the movement of interest rates charged by financial institutions. An increase in our 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 our common stock.

 

Our indebtedness could have important consequences to us, including:

 

 

 

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.

 

Our credit agreements contain operating and financial restrictions that may restrict our business and financing activities.

 

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

 

 

We are also required to comply with certain financial covenants and ratios. In the past, we have not satisfied all of the financial covenants contained in our credit facilities. In January 2005, we determined that we were not in compliance with the leverage and interest coverage ratios under a prior secured credit agreement and, in connection with a February 2005 amendment to such credit agreement, we were unable to drill any additional wells until our gross daily production reached certain levels. We were unable to reach these production goals without the drilling of additional wells and, in the fourth quarter of 2005, we undertook a significant recapitalization that included a private placement of our common stock and the refinancing of our credit facilities. For the quarter ended March 31, 2007, we were not in compliance with the maximum total debt to EBITDA ratio under our prior credit facilities, and we obtained a waiver from our lenders.

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

 

Quest Energy’s credit agreement limits the amount 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. Our credit agreement limits the amount we can borrow to a borrowing base amount, which is equal to 50% of the market value of the common and subordinated units of Quest Energy and Quest Midstream that we have pledged to the lenders. The amount of the borrowing base is redetermined each quarter by reference to the most recent compliance certificate delivered to RBC. If the amount outstanding under our credit agreement exceeds the borrowing base, we will be required to repay the amount of such excess within 30 days after we become aware of such excess. Additionally, if the lenders’ exposure under letters of credit exceeds the borrowing base after all borrowings under the credit agreements have been repaid, Quest Energy or we, as applicable, will be required to provide additional cash collateral.

 

We are exposed to trade credit risk in the ordinary course of our business activities.

 

We are exposed to risks of loss in the event of nonperformance by our customers and by counterparties to our derivative contracts. Some of our customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our customers and/or counterparties could adversely affect our results of operations and financial condition.

 

There is a significant delay between the time we drill and complete a CBM well and when the well reaches peak production. As a result, there will be a significant lag time between when we expend capital expenditures and when we will begin to recognize significant cash flow from those expenditures.

 

Our general production profile for a CBM well averages an initial 15-20 Mcf/d (net), steadily rising for the first twelve months while water is pumped off and the formation pressure is lowered until the wells reach peak production (an average of 55-60 Mcf/d (net)). In addition, there could be significant delays between the time a well is drilled and completed and when the well is connected to a gas gathering system. This delay between the time when we expend capital expenditures to drill and complete a well and when we will begin to recognize significant cash flow from those expenditures may adversely affect our cash flow from operations.

 

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

 

It is not possible to measure underground accumulations of gas in an exact way. Gas reserve engineering requires subjective estimates of underground accumulations of gas and assumptions concerning future gas prices, production levels and operating and development costs. In estimating our level of gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to:

 

 

 

If these assumptions prove to be incorrect, our estimates of proved reserves, the economically recoverable quantities of gas and oil attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly. For example, if gas prices at December 31, 2007 had been $1.00 less per Mcf, then the standardized measure of our proved reserves as of December 31, 2007 would have decreased by $105.1 million.

 

Our standardized measure is calculated using unhedged gas prices and is determined in accordance with the rules and regulations of the SEC. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual drilling and production.

 

The present value of future net cash flows from our estimated proved reserves is not necessarily the same as the current market value of our estimated proved reserves. We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of estimate. However, actual future net cash flows from our gas properties also will be affected by factors such as:

 

 

The timing of both our production and our incurrence of expenses in connection with the development and production of 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 we use when calculating discounted future net cash flows in compliance with the Financial Accounting Standards Board’s Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the gas industry in general.

 

Drilling for and producing gas are costly and high-risk activities with many uncertainties that could adversely affect our financial condition or results of operations.

 

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Furthermore, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

 

 

 

A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances. We may drill wells that are unproductive or, although productive, do not produce gas in economic quantities. Unsuccessful drilling activities could result in higher costs without any corresponding revenues. Furthermore, a successful completion of a well does not ensure a profitable return on the investment.

 

Our hedging activities could result in financial losses or reduce our income.

 

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of gas, we currently and may in the future enter into derivative arrangements for a significant portion of our gas production that could result in both realized and unrealized hedging losses. The extent of our commodity price exposure is related largely to the effectiveness and scope of our hedging activities.

 

Our actual future production may be significantly higher or lower than we estimate at the time we enter into hedging transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our hedging activities are subject to the following risks:

 

 

Because of our lack of asset and geographic diversification, adverse developments in our operating area would adversely affect our results of operations.

 

Substantially all of our assets are currently located in the Cherokee Basin. As a result, our business is disproportionately exposed to adverse developments affecting this region. These potential adverse developments could result from, among other things, changes in governmental regulation, capacity constraints with respect to the pipelines connected to our wells, curtailment of production, natural disasters or adverse weather conditions in or affecting this region. Due to our lack of diversification in asset type and location, an adverse development in our

business or this operating area would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.

 

We may be unable to compete effectively with larger companies, which may adversely affect our results of operations.

 

The gas and oil industry is intensely competitive with respect to acquiring prospects and productive properties, marketing gas and oil and securing equipment and trained personnel, and we compete with other companies that have greater resources. Many of our competitors are major and large independent gas and oil companies, and they not only drill for and produce gas and oil, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. Our larger competitors also possess and employ financial, technical and personnel resources substantially greater than ours. These companies may be able to pay more for gas and oil properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, there is substantial competition for investment capital in the gas and oil industry. These larger companies may have a greater ability to continue drilling activities during periods of low gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with larger companies could have a material impact on our business activities, results of operations and financial condition.

 

We may have difficulty managing growth in our business.

 

Because of the relatively small size of our business, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As we increase our activities and the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the recruitment and retention of required personnel could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

 

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

 

There are a variety of risks inherent in our operations that may generate liabilities, including contingent liabilities, and financial losses to us, such as:

 

 

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

 

In accordance with typical industry practice, we currently possess property, business interruption and general liability insurance at levels we believe are appropriate; however, insurance against all operational risk is not available to us. We are not fully insured against all risks, including drilling and completion risks that are generally not recoverable from third parties or insurance. Pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe 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 us to obtain certain types of coverage. There can be no assurance that we will be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition and results of operations.

 

Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters applicable to gas and oil exploitation and production operations.

 

We may incur significant costs and liabilities as a result of environmental, health and safety requirements applicable to our gas and oil exploitation 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 our operations. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for damages as a result of environmental and other impacts.

 

Strict, joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our 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. If we are not able to recover the resulting costs through insurance or increased revenues, our results of operations and financial condition could be adversely affected.

 

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

 

Our gas and oil exploitation, development and production operations are subject to complex and stringent laws, rules and regulations. In order to conduct our operations in compliance with these laws, rules and regulations, we must obtain and maintain numerous permits, licenses, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws, rules and regulations. In addition, our costs of compliance may increase if existing laws, rules and regulations are revised or reinterpreted, or if new laws, rules and regulations become applicable to our operations.

 

The Cherokee Basin has been an active gas and oil producing region for a number of years. Many of our properties had abandoned oil and conventional gas wells on them at the time the current lease was entered into with the landowner. A number of these wells remain unplugged or were improperly plugged by a prior landowner or operator. Many of the former operators of these wells have ceased operations and cannot be located or do not have the financial resources to plug these wells. We believe that we are not responsible for plugging an abandoned well on one of our leases, unless we have used, attempted to use or invaded the abandoned well bore in our operations on the land or have otherwise agreed to assume responsibility for plugging the wells. The law is unsettled in the State of Kansas as to who has the responsibility to plug such abandoned wells. The KCC issued a Show Cause Order in February 2007 requiring Quest Energy’s operating company, Quest Cherokee, LLC to demonstrate why it should not be held responsible for plugging 22 abandoned and unplugged oil wells on land covered by a gas lease that it owns and operates in Wilson County, Kansas, and upon which Quest Cherokee has drilled and is operating a gas well. If it is ultimately determined that we are responsible for plugging all of the wells located on our leased acreage that were abandoned by former operators, the costs for plugging and abandoning those wells would increase our costs and decrease our cash available for distribution. At this time, we are unable to determine the total number of wells located on our leased acreage that have been abandoned by prior operators.

We may face unanticipated water disposal costs.

 

We are subject to regulation that restricts our ability to discharge water produced as part of our CBM 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 our ability to remove and dispose of sufficient quantities of water from the coal seam will determine whether we can produce gas in commercial quantities. The produced water must be transported from the lease and injected into disposal wells. The availability of disposal wells with sufficient capacity to receive all of the water produced from our wells may affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability.

 

Where water produced from our projects fail to meet the quality requirements of applicable regulatory agencies, our wells produce water in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of all applicable regulatory agencies, or we are unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur:

 

 

Shortages of crews could delay our operations, adversely affect our ability to increase our reserves and production and adversely affect our results of operations.

 

Higher gas and oil prices generally stimulate increased demand and result in increased wages for crews and personnel in our production operations. These types of shortages or wage increases could increase our costs and/or restrict or delay our ability to drill the wells and conduct the operations that we currently have planned. Any delay in the drilling of new wells or significant increase in labor costs could adversely affect our ability to increase our reserves and production and reduce our revenue and cash available for distribution. Additionally, higher labor costs could cause certain of our projects to become uneconomic and therefore not be implemented, reducing our production and adversely affecting our results of operations.

 

We depend on two customers for sales of our gas. To the extent these customers reduce the volumes of gas they purchase from us and are not replaced by new customers, our revenues and net income could decline.

 

During the year ended December 31, 2007, we sold approximately 79% of our gas to ONEOK Energy Marketing and Trading Company (“ONEOK”) and 21% of our gas to Tenaska Marketing Ventures (“Tenaska”) under sale and purchase contracts, which have indefinite terms but may be terminated by either party on 30 days’ notice, other than with respect to pending transactions, or less following an event of default. If either of these customers were to reduce the volume of gas it purchases from us, our revenue and net income for distribution may decline to the extent we are not able to find new customers for our production.

 

Certain of our undeveloped leasehold acreage is subject to leases that may expire in the near future.

 

As of December 31, 2007, we held gas leases on approximately 164,869 net acres in the Cherokee Basin and 22,694 net acres outside the Cherokee Basin that are still within their original lease term and are not currently held by production. Unless we establish commercial production on the properties subject to these leases during their term, these leases will expire. Leases covering approximately 4,928 net acres are scheduled to expire before December 31, 2008 and an additional 80,843 net acres are scheduled to expire before December 31, 2009. If our leases expire, we will lose our right to develop the related properties. We typically acquire a three-year primary term

when the original lease is acquired, with an option to extend the term for up to three additional years, if the primary three-year term reaches expiration without a well being drilled to establish production for holding the lease.

 

Our identified drilling location inventories will be developed over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, resulting in temporarily lower cash from operations, which may impact our results of operations.

 

Our management has specifically identified drilling locations for our future multi-year drilling activities on our existing acreage. We have identified, as of December 31, 2007, approximately 800 gross proved undeveloped drilling locations and approximately 1,300 additional gross potential drilling locations. These identified drilling locations represent a significant part of our future development drilling program for the Cherokee Basin. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, gas prices, costs and drilling results. In addition, no proved reserves are assigned to any of the approximately 1,300 potential drilling locations we have identified and therefore, there may exist greater uncertainty with respect to the likelihood of drilling and completing successful commercial wells at these potential drilling locations. Our final determination of whether to drill any of these drilling locations will be dependent upon the factors described above as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, we do not know if the numerous drilling locations we have identified will be drilled within our expected timeframe or will ever be drilled or if we will be able to produce gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could have a significant adverse effect on our financial condition and results of operations.

 

We may incur losses as a result of title deficiencies in the properties in which we invest.

 

If an examination of the title history of a property reveals that a gas or oil lease has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would be worthless. In such an instance, the amount paid for such gas or oil lease or leases would be lost. It is our practice, in acquiring gas and oil leases, or undivided interests in gas and oil leases, not to incur the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease. Rather, we rely upon the judgment of 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 drilling a gas or oil well, however, it is the normal practice in the 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 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. Our failure to obtain these rights may adversely impact its ability in the future to increase production and reserves.

 

On a small percentage of our acreage (less than 1.0%), the land owner in the past transferred the rights to the coal underlying their land to a third party. With respect to those properties we have obtained gas and oil leases from the owners of the oil, gas, and minerals other than coal underlying those lands. In Oklahoma and Kansas, the law is unsettled as to whether the owner of the gas rights or the coal rights is entitled to the CBM gas. We are currently involved in litigation with the owner of the coal rights on these lands to determine who has the rights to the CBM gas. In the event that the courts were to determine that the owner of the coal rights is entitled to extract the CBM gas, we would lose these leases and the associated wells and reserves. In addition, we may be required to reimburse the owner of the coal rights for some of the gas produced from those wells.

 

If we are unable to obtain new rights-of-way or the cost of renewing existing rights-of-way increases, then we may be unable to fully execute our growth strategy and our cash flows could be reduced. The construction of additions to our existing gathering assets may require us to obtain new rights-of-way before constructing new pipelines. We may be unable to obtain rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to

obtain new rights-of-way or to renew existing rights-of-way. If the cost of obtaining new rights-of-way or renewing existing rights-of-way increases, then our cash flows could be reduced.

 

Pipeline integrity programs and repairs may impose significant costs and liabilities.

 

In December 2003, the United States Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs for intrastate and interstate natural gas and natural gas liquids pipelines located near high consequence areas, where a leak or rupture could do the most harm. The final rule requires operators to perform ongoing assessments of pipeline integrity; identify and characterize applicable threats to pipeline segments that could impact a high consequence area; improve data collection, integration and analysis; repair and remediate the pipeline as necessary; and implement preventive and mitigating actions. The final rule incorporates the requirements of the Pipeline Safety Improvement Act of 2002 and became effective in January 2004. The results of these testing programs could cause us to incur significant capital and operating expenditures to make repairs or take remediation, preventive or mitigating actions that are determined to be necessary.

 

Growing our business by constructing new pipelines and new processing and treating facilities or making modifications to our existing facilities subjects us to construction risks and risks that adequate natural gas supplies will not be available upon completion of the facilities.

 

One of the ways we intend to grow our business is through the construction of pipelines and modifications to our existing pipeline systems and the construction of new pipelines and new gathering, processing and treatment facilities. The construction and modification of pipelines and gathering, processing, fractionation and treatment facilities requires the expenditure of significant amounts of capital, which may exceed our expectations, and involves numerous regulatory, environmental, political and legal uncertainties. Construction projects in our industry may increase demand on labor and material which may in turn impact our costs and schedule. If we undertake these projects, we may not be able to complete them on schedule or at the budgeted cost. Additionally, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time, and we will not receive any material increases in revenues until after completion of the project. We may have only limited natural gas supplies committed to these facilities prior to their construction. Additionally, we may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. We may also rely on estimates of proved reserves in our decision to construct new pipelines and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved reserves. As a result, new facilities may not be able to attract enough natural gas to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

 

Our regulated natural gas pipeline’s transportation rates are subject to review and possible adjustment by federal regulators.

 

Our regulated pipeline is subject to extensive regulation by the FERC, which regulates most aspects of our pipeline business, including our transportation rates, and on a more limited basis by state regulatory agencies. Under the Natural Gas Act, interstate transportation rates and terms and conditions of service must be just and reasonable and not unduly discriminatory. Shippers have the right to file complaints seeking reductions in transportation rates which, if successful, may adversely affect our revenues.

 

Our interstate natural gas pipeline has recorded certain assets that may not be recoverable from our customers.

 

Accounting policies for FERC-regulated companies permit certain assets that result from the regulated ratemaking process to be recorded on our balance sheet that could not be recorded under GAAP for nonregulated entities. We consider factors such as regulatory changes and the impact of competition to determine the probability of future recovery of these assets. If we determine future recovery is no longer probable, we would be required to write off the regulatory assets at that time.

Reduction in firm reservation agreements and the demand for interruptible services could cause significant reductions in our revenues and operating results.

 

For the year ended December 31, 2007, approximately 98% of our firm contracted capacity is under long-term contracts (i.e. contracts with terms longer than one year). A decision by customers upon the expiration of long-term agreements to substantially reduce or cease to ship volumes of natural gas on our pipeline system could cause a significant decline in our revenues. Our results of operations could also be adversely affected by decreased demand for interruptible services.

 

Decreases in the availability of natural gas supplies could have a significant negative impact on our revenues and results of operations.

 

Our operating results are dependent upon our customers having access to adequate supplies of natural gas. We depend on having access to multiple sources of gas production so that customers can satisfy their total gas requirements and have the opportunity to source gas at the lowest overall delivered cost. Moreover, we may not have the ability to operate our pipeline system at full capacity without access to multiple gas sources. The ability of producers to maintain production is dependent on the prevailing market price of natural gas, the exploration and production budgets of the major and independent gas companies, the depletion rate of existing sources, the success of new sources, environmental concerns, regulatory initiatives and other matters beyond our control. Additionally, some of our customers deliver gas to our pipeline system through other pipelines. Operational failures on those other pipelines, such as reductions in pressure or volume, or interruptions in service due to maintenance activities or unanticipated emergencies, could result in lower volumes of gas being available to us for transportation. We cannot assure that production or supplies of natural gas available to our customers will be maintained at sufficient levels to sustain our expected volume of transportation commitments on our pipeline system or that multiple sources of gas will remain available to provide our customers with access to sufficient low cost supplies. If the availability of natural gas supplies decreases, our revenues and results of operations could be adversely affected.

 

Operational limitations of the pipeline system could cause a significant decrease in our revenues and operating results.

 

In order to satisfy firm transportation commitments, our customers must nominate and schedule, and we must be able to receive, required volumes of gas in accordance with contract terms, and must be able to reliably and safely deliver those volumes. Our customers’ ability to schedule natural gas transportation to certain locations is constrained by the physical limitations of our pipeline system. These physical limitations can be significant during periods of peak demand because many sections of our pipeline do not have redundant or looped lines and do not have additional available compression. During peak demand periods, failures of compression equipment or pipelines could limit our ability to meet firm commitments, which may limit our ability to collect reservation charges from our customers and, if so, could negatively impact our revenues.

 

Decreases in demand for natural gas may reduce our revenues and operating results.

 

Demand for our interstate natural gas transportation services depends on the ability and willingness of customers with access to our facilities to deliver natural gas through our interstate pipeline system. Demand for natural gas is dependent upon the impact of weather, industrial and economic conditions, fuel conservation measures, alternative fuel availability and requirements, market price of gas, fuel taxes, price competition, drilling activity and supply availability, governmental regulation and technological advances in fuel economy and energy generation devices. Any decrease in demand for our interstate natural gas transportation services could result in a significant reduction in our revenues.

 

Competitive pressures could reduce our revenues and operating results.

 

Although most of our interstate pipeline system’s current transportation capacity is contracted under long-term firm reservation agreements, the market for the transportation of natural gas is competitive. Other entities could construct new pipelines or expand existing pipelines that could potentially serve the same markets as our pipeline system. Any such new pipelines could offer services that are more desirable to customers because of locations,

facilities or other factors. These new pipelines could charge rates or provide service to locations that could result in savings for shippers and producers and thereby force us to lower the rates charged for services on our pipeline in order to extend existing service agreements or to attract new customers. New pipeline projects are always possible in the future and proposals are made from time to time. An increase in the availability of competing alternative facilities or services could result in a significant reduction in our revenue.

 

We compete with other interstate and intrastate pipelines in the transportation of natural gas for transportation customers primarily on the basis of transportation rates, access to competitively priced supplies of natural gas, markets served by the pipelines, and the quality and reliability of transportation services. Major competitors include Southern Star Central Gas Pipeline, Kinder Morgan Interstate Gas Transmission’s Pony Express Pipeline and Panhandle Eastern Pipeline Company. We compete with these pipelines in Wichita and Kansas City, Kansas and Kansas City, Missouri.

 

Natural gas also competes with other forms of energy available to our customers, including electricity, coal, hydroelectric power, nuclear power and fuel oil. The impact of competition on us could be significantly increased as a result of factors that have the effect of significantly decreasing demand for natural gas in the markets served by our pipeline, such as competing or alternative forms of energy; adverse economic conditions; weather; higher fuel costs; and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.

 

Federal and state regulation of natural gas interstate pipelines has changed dramatically in the last 25 years and could continue to change over the next several years. These regulatory changes have resulted and will continue to result in increased competition in the pipeline business. In order to meet competitive challenges, we will need to adapt our marketing strategies and the type of transportation services we offer to our customers and to adapt our pricing and rates in response to competitive forces. We are not able to predict the financial consequences of these changes at this time, but they could have a material adverse effect on our business, financial condition and results of operations.

 

The revenues of our interstate pipeline business are generated under contracts that must be renegotiated periodically.

 

Substantially all of KPC’s revenues are generated under contracts which expire periodically and must be renegotiated and extended or replaced. If we are unable to extend or replace these contracts when they expire or renegotiate contract terms as favorable as the existing contracts, we could suffer a material reduction in our revenues, earnings and cash flows. In particular, our ability to extend and replace contracts could be adversely affected by factors we cannot control, including:

 

 

Fluctuations in energy commodity prices could adversely affect our pipeline businesses.

 

Revenues generated by our transmission contracts depend, in part, on volumes and rates, both of which can be affected by the prices of natural gas. Increased prices could result in a reduction of the volumes transported by our customers. Increased prices could also result in industrial plant shutdowns or load losses to competitive fuels as well as local distribution companies’ loss of customer base. The success of our transmission operations is subject to continued development of additional gas supplies to offset the natural decline from existing wells connected to our systems, which requires the development of additional oil and natural gas reserves and obtaining additional supplies

from interconnecting pipelines on or near our systems. A decline in energy prices could cause a decrease in these development activities and could cause a decrease in the volume of reserves available for transmission through our systems. Pricing volatility may impact the value of under or over recoveries of retained natural gas and imbalances. If natural gas prices in the supply basins connected to our pipeline systems are higher than prices in other natural gas producing regions, our ability to compete with other transporters may be negatively impacted on a short-term basis, as well as with respect to our long-term recontracting activities. Furthermore, fluctuations in pricing between supply sources and market areas could negatively impact our transportation revenues. Fluctuations in energy prices are caused by a number of factors, including:

 

 

Quest Energy and Quest Midstream may not have sufficient cash flow from operations to pay the minimum quarterly distribution, or MQD, to us on our subordinated units following the establishment of cash reserves and payment of fees and expenses and payment of the MQD on their common units.

 

Quest Energy and Quest Midstream may not have sufficient cash flow from operations each quarter to pay the MQD of $0.40 and $0.425, respectively. Under the terms of their limited partnership agreements, the amount of cash otherwise available for distribution will be reduced by their operating expenses and the amount of any cash reserve amounts that the boards of directors of their general partners establish to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions. The amount of cash they can distribute principally depends upon the amount of cash they generate from their operations, which will fluctuate from quarter to quarter.

 

In addition, the actual amount of cash we will receive from their distributions will depend on other factors, some of which are beyond their control, including:

 

 

As a result of these factors, the amount of cash Quest Energy and/or Quest Midstream distributes in any quarter to us may fluctuate significantly from quarter to quarter and may be significantly less than the MQD amount that we expect to receive.

 

We depend on a limited number of key management personnel, who would be difficult to replace.

 

Our operations and activities are dependent to a significant extent on the efforts and abilities of our executive officers and key employees. The loss of any member of our executive officers or other key employees could negatively impact our ability to execute our strategy.

If we do not make acquisitions on economically acceptable terms, our future growth and profitability will be limited.

 

Our ability to grow and to increase our profitability depends in part on our ability to make acquisitions that result in an increase in our net income. We may be unable to make such acquisitions because we are: (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms or (3) outbid by competitors. If we are unable to acquire properties containing proved reserves, our total level of proved reserves will decline as a result of our production, which will adversely affect our results of operations.

 

Any acquisitions we complete are subject to substantial risks that could reduce our profitability.

 

Even if we do make acquisitions that we believe will increase our net income and cash flows, these acquisitions may nevertheless result in a decrease in net income and/or cash flows. Any acquisition involves potential risks, including, among other things:

 

 

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and investors will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

 

In addition, we may pursue acquisitions outside the Cherokee Basin. We currently operate substantially in the Cherokee Basin, and consequently acquisitions in areas outside the Cherokee Basin may not allow us the same operational efficiencies we benefit from in the Cherokee Basin. In addition, acquisitions outside the Cherokee Basin will expose us to different operational risks due to potential differences, among others, in:

 

 

 

Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume environmental and other risks and liabilities in connection with acquired properties.

 

Risks Related to the Pinnacle Merger

 

To develop our current reserves and the reserves acquired from Pinnacle, we will require significant additional capital.

 

As discussed in Items 1 and 2. “Business and Properties — Recent Developments,” we and Mergersub have entered into a Merger Agreement to acquire Pinnacle by merger. As a result of the Merger, the combined company will have significantly more development opportunities than we currently have by ourselves, which will require significantly greater capital expenditures in order to fully develop our properties. We currently have a $50 million revolving credit facility that as of March 7, 2008 had $44 million of outstanding borrowings. It is currently anticipated that after the payment of merger-related expenses, we will have little or no availability under our current credit facility for development of the Pinnacle properties. Quest Energy and Quest Midstream have significant availability under their credit facilities, but those credit facilities will only be available to fund the development of those Pinnacle properties, if any, that are contributed to the partnerships.

 

We currently intend to either obtain an increase in the commitments under our existing credit facility or obtain a new credit facility with a higher borrowing base. No assurance can be given that we will be able to successfully increase our commitments or enter into a new credit facility. Even if we are able to successfully increase the commitments under our credit facilities, we anticipate that cash available under our credit facilities, together with cash flow expected to be generated from operations and distributions from Quest Midstream and Quest Energy will only be sufficient to meet our cash requirements for the development of Pinnacle’s reserves for a period less than 12 months. Historically, we have financed our business and operations primarily with internally generated cash flow, bank borrowings and equity investments, including the issuance of common units of Quest Midstream and Quest Energy. Therefore, unless we are successful at increasing cash flow from operations, increasing distributions from Quest Midstream and Quest Energy, increasing the commitments under our credit facilities, raising additional capital or a combination of any of the foregoing, we will be unable to fully develop our reserves, including the reserves acquired pursuant to the merger with Pinnacle. In such event, we may be required to curtail our drilling, development and other activities which could cause a decline in the value of our reserves or be forced to sell assets on unfavorable terms.

 

The value of the consideration received by Pinnacle stockholders will vary with the value of our common stock.

 

The exchange ratio in the Merger is fixed and will not be adjusted in the event of any change in the stock prices of Pinnacle or us prior to the Merger. Accordingly, the value of the consideration that Pinnacle stockholders will be entitled to receive pursuant to the Merger will depend on the trading price of our common stock. This means that there is no “price protection” mechanism contained in the Merger Agreement that would adjust the number of shares that Pinnacle stockholders will receive based on any increases or decreases in the trading price of our common stock. If our stock price increases, the market value of the consideration will also increase. Stock price

changes may result from a variety of factors, including general market and economic conditions, changes in oil and natural gas prices, changes in our respective businesses, operations and prospects, and regulatory considerations. Many of these factors are beyond our control.

 

The integration of Pinnacle following the Merger will present significant challenges that may reduce the anticipated potential benefits of the merger.

 

We will face significant challenges in consolidating functions and integrating Pinnacle’s and our organizations, procedures and operations within a timely and efficient manner, as well as retaining key personnel. The integration of Pinnacle with us will be complex and time-consuming due to the size and complexity of each organization. The principal challenges will include the following:

 

 

Our management will have to dedicate substantial effort to integrating the businesses. These efforts could divert management’s focus and resources from other day-to-day tasks, corporate initiatives or strategic opportunities during the integration process.

 

We and Pinnacle will incur significant transaction and merger-related integration costs in connection with the Merger.

 

Pinnacle and we expect to pay significant transaction costs. These transaction costs include investment banking, legal and accounting fees and expenses, SEC filing fees, printing expenses, mailing expenses and other related charges and are estimated to be approximately $5.5 million. A portion of the transaction costs will be incurred regardless of whether the Merger is consummated. Pinnacle and we will each pay our own transaction costs, except that we will share equally or pro rata certain filing, printing and other costs and expenses.

 

In addition, Pinnacle and we will incur approximately $2.1 million relating to severance, retention and option payouts to Pinnacle employees.

 

We currently estimate integration costs associated with the Merger to be approximately $500,000. We are in the early stages of assessing the magnitude of these costs, and, therefore, these estimates may change substantially and additional unanticipated costs may be incurred in the integration of Pinnacle’s business with us.

 

While the Merger is pending, we will be subject to business uncertainties and contractual restrictions that could adversely affect their businesses.

 

Uncertainty about the effect of the Merger on employees, customers and suppliers may have an adverse effect on both us and Pinnacle and, consequently, on the combined company. These uncertainties may impair our and Pinnacle’s ability to attract, retain and motivate key personnel until the Merger is consummated and for a period of time thereafter, and could cause customers, suppliers and others who deal with us and Pinnacle to seek to change existing business relationships with us and Pinnacle. Employee retention may be particularly challenging during the pendency of the Merger because employees may experience uncertainty about their future roles with the combined company. If, despite our and Pinnacle’s retention efforts, key employees depart because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, the combined company’s business could be seriously harmed. In addition, the Merger Agreement restricts us and Pinnacle, without the other party’s consent and subject to certain exceptions, from making certain acquisitions and taking other specified actions until the Merger occurs or the Merger Agreement terminates. These restrictions may prevent us and Pinnacle from pursuing otherwise attractive business opportunities and making other changes to our businesses that may arise prior to completion of the Merger or termination of the Merger Agreement.

Failure to complete the Merger could negatively impact our stock price and future business and financial results because of, among other things, the disruption that would occur as a result of uncertainties relating to a failure to complete the Merger.

 

Both our stockholders and those of Pinnacle may not approve the Merger. If the Merger is not completed for any reason, we could be subject to several risks, including the following:

 

 

In addition, we would not realize any of the expected benefits of having completed the Merger.

 

If the Merger is not completed, the price of our common stock may decline to the extent that the current market price of our common stock reflects a market assumption that the Merger will be completed and that the related benefits and synergies will be realized, or as a result of the market’s perceptions that the Merger was not consummated due to an adverse change in our business. In addition, our business may be harmed, and the price of our stock may decline as a result, to the extent that suppliers and others believe that we cannot compete in the marketplace as effectively without the Merger or otherwise remain uncertain about our future prospects in the absence of the Merger. Similarly, our current and prospective employees may experience uncertainty about their future roles with the resulting company and choose to pursue other opportunities, which could adversely affect us if the Merger is not completed. The realization of any of these risks may materially adversely affect our business, financial results, financial condition and stock price.

 

The Merger Agreement limits our ability to pursue an alternative acquisition proposal and requires us to pay a termination fee of up to $3.0 million if we do.

 

The Merger Agreement prohibits us from soliciting, initiating or encouraging alternative merger or acquisition proposals with any third party. The Merger Agreement also provides for the payment by us of a termination fee of up to $3.0 million if the Merger Agreement is terminated in certain circumstances in connection with a competing acquisition proposal or the withdrawal by our board of directors of its recommendation that our stockholders vote for the adoption of the Merger Agreement as the result of the existence of a material adverse effect with respect to Pinnacle. In addition, the Merger Agreement provides for a payment by us to Pinnacle of a termination fee of $5 million if the Merger Agreement is terminated due to the withdrawal by our board of directors of its recommendation that our stockholders vote to approve the issuance of shares if there is no superior proposal or a Pinnacle material adverse effect does not exist.

 

These provisions limit our ability to pursue offers from third parties that could result in greater value to our stockholders. The obligation to make the termination fee payment also may discourage a third party from pursuing an alternative acquisition proposal.

 

The price of Quest’s common stock may experience volatility following the consummation of the Merger.

 

Following the consummation of the Merger, the price of our common stock may be volatile. Some of the factors that could affect the price of our common stock are quarterly increases or decreases in revenue or earnings, changes in revenue or earnings estimates by the investment community, our ability to implement our integration strategy and to realize the expected synergies and other benefits from the Merger and speculation in the press or investment community about our financial condition or results of operations. General market conditions and U.S. or international economic factors and political events unrelated to our performance may also affect our stock price. For these reasons, investors should not rely on recent trends in the price of our common stock to predict the future price of our common stock or our financial results.

Risks Relating to Our Common Stock

 

Our stock price may be volatile.

 

The following factors could affect our stock price:

 

 

It is unlikely that we will be able to pay dividends on our common stock.

 

We cannot predict with certainty that our operations will result in sufficient revenues to enable us to operate profitably and with sufficient positive cash flow so as to enable us to pay dividends to the holders of common stock. In addition, our credit facilities generally prohibit it from paying any dividend to the holders of our 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.

 

We are authorized to issue up to 200,000,000 shares of common stock and are not prohibited from issuing additional shares of such common stock. Moreover, to the extent that we issue 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.

Our common stock is an unsecured equity interest.

 

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

 

Provisions in Nevada law could delay or prevent a change in control, even if that change would be beneficial to our stockholders.

 

Certain provisions of Nevada law may delay, discourage, prevent or render more difficult an attempt to obtain control of us, 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 us to first negotiate with our 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 us 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. Our restated articles of incorporation, as amended, 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. Our restated articles of incorporation and bylaws, as amended, 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. Our status at the time of the occurrence of a transaction governed by the Control Share Act (assuming that our 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. We do 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. Our restated articles of incorporation and bylaws, as amended, 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. Our restated articles of incorporation and bylaws, as amended, 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. Our restated articles of incorporation and bylaws, as amended, do not address this matter.

 

 

None.

 

 

See Note 8. Contingencies, in the notes to the consolidated financial statements in this Form 10-K, which is incorporated herein by reference.

 

 

No matters were submitted to a vote of security holders during the fourth quarter of 2007.

 

 

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 (or high and low bids on the OTC Bulletin Board prior to April 11, 2006) for each quarter of the last two 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.

 

 

The closing price for QRCP stock on March 5, 2008 was $7.20.

 

Record Holders

 

As of March 5, 2008, there were 23,455,427 shares of common stock issued and outstanding, held of record by approximately 694 stockholders.

 

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 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 Analysis of Financial Conditions and Results of Operation — Capital Resources and Liquidity” for a discussion of these restrictions.

 

In addition, the partnership agreements for Quest Energy and Quest Midstream restrict the ability of Quest Energy and Quest Midstream to pay distributions on the subordinated units of such partnerships that we own if the minimum quarterly distribution has not been paid on all of the common units of such partnerships. The revolving credit facilities for Quest Energy and Quest Midstream also restrict the ability of Quest Energy and Quest Midstream to pay any distributions if they are in default under the credit facilities.

 

Recent Sales of Unregistered Securities

 

None.

 

Purchases of Equity Securities

 

None.

STOCK PRICE PERFORMANCE GRAPH

 

The following graph compares the performance of our common stock to a new peer group and to our old peer group in our SIC code index and to the Nasdaq market index for the past five years. The new peer group consists of the following companies: Abraxas Petroleum Corporation; Credo Petroleum Corporation; Double Eagle Petroleum Company; Dune Energy Inc; Edge Petroleum Corporation; Evolution Petroleum Corporation; FX Energy Inc.; Georesources Inc.; Houston American Energy Corporation; Kodiak Oil & Gas Corporation; Meridian Resources Corporation; Ngas Resources Inc.; Northern Oil & Gas Inc.; Pinnacle Gas Resources Inc.; Platinum Energy Resources Inc.; Primeenergy Corporation; South Texas Oil Company; Toreador Resources Corporation; and Tri Valley Corporation.

 

Our old peer group consisted of the following companies: Abraxas Petroleum Corporation; Alon USA Energy Inc.; Altex Industries Inc.; American Oil & Gas Inc.; American Resource Technologies Inc.; Anadarko Petroleum Corporation; Apollo Resources International Inc.; Atlas Energy Resources Limited Liability; ATP Oil & Gas Corporation; Austin Chalk Oil Gas Limited; Avalon Oil And Gas Inc.; Barnwell Industries Inc.; Baseline Oil & Gas Corporation; Basic Earth Science Systems Inc.; Bayou City Exploration Inc.; Berry Petroleum; Big Sky Energy Corporation; Bill Barrett Corporation; Bois Darc Energy Inc.; BPZ Resources Inc.; Breitburn Energy Limited Liability; Compa; Cabot Oil & Gas Corporation; Callon Petroleum Company; Canargo Energy Corporation; Capco Energy Inc.; Carrizo Oil & Company Inc.; China North East Petroleum Holdings Limited; China Yili Petroleum Company; Clayton Williams Energy Inc.; Comstock Resources Inc.; Consolidated Medical Management Inc.; Credo Petroleum Corporation; Crimson Exploration Inc.; Cygnus Oil & Gas Corporation; Daleco Resources Corporation; Delek Resources Inc.; Delta Petroleum Corporation; Denbury Resources Inc.; Devon Energy Corporation; Dorchester Minerals Limited Partnership; Double Eagle Petroleum Company; Drucker Inc.; Dune Energy Inc.; Dynegy Inc.; Eagle Rock Energy Partners Limited Partners; Eden Energy Corporation; Edge Petroleum Corporation; Encore Acquisition Company; Endeavour International Corporation; Endevco Inc.; Energas Resources Inc.; Energy Exploration Technologies Inc.; Energytec Inc.; Enterprise GP Holdings Limited Partnership; Enterprise Products Partners Limited Partnership; Erhc Energy Inc.; Eurogas Inc.; Evolution Petroleum Corporation; Falcon Natural Gas Corporation; Fellows Energy Limited; Fieldpoint Petroleum Corporation; Finmetal Mining Limited; Forest Oil Corporation; Galaxy Energy Corporation; Galton Biometrics Inc.; Geomet Inc.; Georesources Inc.; GNC Energy Corporation; Golden Aria Corporation; Goodrich Petroleum Corporation; Gulf Western Petroleum Corporation; Gulfport Energy Corporation; Hallador Petroleum Company; Harvest Natural Resources Inc.; Helmerich Payne Inc.; Hiko Bell Mining & Oil Company; Houston American Energy Corporation; Ignis Petroleum Group Inc.; Imperial Petroleum Inc.; Interline Resources Corporation; Isramco Inc.; KAL Energy Inc.; Lexaria Corporation; Linn Energy Limited Liability Company; Lions Petroleum Inc.; Lucas Energy Inc.; Matrix Energy Services Corporation; McMoran Exploration Company; Meridian Resources Corporation; Mexco Energy Corporation; Monument Resources Corporation Inc.; Morgan Creek Energy Corporation; Mountains West Exploration Inc.; Ness Energy International Inc.; New Frontier Energy Inc.; Newfield Exploration Company; Ngas Resources Inc.; Nicor Inc.; Noble Energy Inc.; Oakridge Energy Inc.; Occidental Petroleum Corporation; Pangea Petroleum Corporation; Panhandle Oil & Gas Inc.; Parallel Petroleum Corporation; Park Place Energy Corporation; Penn Virginia Corporation; Petro Resources Inc.; Petrohawk Energy Corporation; Petrohunter Energy Corporation; Petrol Oil And Gas Inc.; Petrominerals Corporation; Petroquest Energy Inc.; Petrosearch Energy Corporation; Pioneer Natural Resources Company; Plains All American Pipeline Limited Partnership; Plains Exploration & Production Company; Pluris Energy Group Inc.; Primeenergy Corporation; Pyramid Oil Company; Questar Corporation; Quicksilver Resources Inc.; Ram Energy Resources Inc.; Rancher Energy Corporation; Range Resources Corporation Commerce; Regency Energy Partners Limited Partners; Rosetta Resources Inc.; Saint Mary Land & Exploration Company; Sonoran Energy Inc.; South Texas Oil Company; Southwestern Energy Company; Spindletop Oil & Gas Company; Stallion Group; Star Energy Corporation; Stone Energy Corporation; Swift Energy Company; Texas Vanguard Oil Company; Toreador Resources Corporation; Torrent Energy Corporation; Trans Energy Inc.; True North Energy Corporation; Txco Resources Inc.; Ultra Petroleum Corporation; United Heritage Corporation; Vaalco Energy Inc.; W & T Offshore Inc.; Whiting Petroleum Corporation; XCL Limited and XTO Energy Inc.

The new peer group was chosen to reflect a comparison of companies more closely aligned with Quest’s market capitalization value.

 

The graph assumes the investment of $100 on December 31, 2002 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,
A New Peer Group And An Old Peer Group

 

 

The following table sets forth selected consolidated financial data of Quest for the years ended December 31, 2007, 2006 and 2005, the seven month transition period ended December 31, 2004 and the fiscal years ended May 31, 2004 and 2003. 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, (3) significant acquisitions that were made during the fiscal year ended May 31, 2004, (4) the change in the fiscal year end on December 31, 2004, (5) formation of Quest Midstream during 2006, (6) acquisition of KPC on November 1, 2007, and (7) Quest Energy’s IPO effective November 15, 2007. The table should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operation” and our consolidated financial statements, including the notes, appearing in Items 7 and 8 of this report.

 

Ratio of Earnings to Combined Fixed Charges

 

 

 

 

 

Cautionary Statements for Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995

 

We are including the following discussion to inform you of some of the risks and uncertainties that can affect our company and to take advantage of the “safe harbor” protection for forward-looking statements that applicable federal securities law affords. Various statements this report contains, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements. These include such matters as:

 

 

When we use the words “believe,” “intend,” “expect,” “may,” “will,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this report speak only as of the date of this report; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. All subsequent oral and written forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these factors. These risks, contingencies and uncertainties relate to, among other matters, the following:

 

 

 

When you consider these forward-looking statements, you should keep in mind these risk factors and the other factors discussed under Item 1A. “Risk Factors.”

 

Overview of the Year Ended December 31, 2007

 

Our strategic positioning in the southeastern Kansas and northeastern Oklahoma natural gas industry has contributed to increases in total revenues and has resulted in a solid foundation for future growth. The increase in total revenues in 2007 as compared to 2006 resulted from an approximate 39% increase in production volumes and an approximate 24% increase in natural gas prices, including hedges.

 

At December 31, 2007, we had an interest in 2,254 natural gas and oil wells (gross) and natural gas and oil leases on approximately 583,000 gross acres, located in the Cherokee Basin. Management believes that the proximity of the 1,994 miles of Quest Midstream owned gas gathering pipeline network to these natural gas and oil leases will enable us to develop new producing wells on many of our undeveloped properties. We have currently identified approximately 2,100 additional gross natural gas well drilling sites on our undeveloped acreage, of which 800 are classified as proved undeveloped. With approximately 325 wells planned to be drilled during each of 2008 and 2009, we are positioned for significant growth in natural gas production, revenues, and net income. However, no

assurance can be given that we will be able to achieve our anticipated rate of growth or that adequate sources of capital will be available.

 

The results of our drilling and well development program for calendar year 2007 included the drilling of 575 new gas wells (gross), the connecting of 575 new gas wells (gross) into our gas gathering pipeline network, the construction of approximately 315 miles of natural gas gathering pipeline, the purchase of approximately 1,120 miles of interstate natural gas transmission pipeline and the recompletion of 50 wells from single seam to multi-seam wells.

 

On October 15, 2007, Quest announced its proposed Merger with Pinnacle. Each share of Pinnacle common stock outstanding prior to the Merger will be exchanged for 0.5278 shares of Quest common stock. At the effective time of the Merger, each share of Pinnacle common stock issued and held in Pinnacle’s treasury or owned by Quest (or any of their respective wholly-owned subsidiaries) will be canceled without payment of any consideration. As a result of the Merger, Pinnacle will become a wholly-owned subsidiary of Quest. Following the Merger, current Quest stockholders will own approximately 60.5% of Quest and current Pinnacle stockholders will own approximately 39.5% of Quest. The Merger will qualify as a reorganization within the meaning of Section 368(a) of the Internal Revenue Code of 1986, as amended, and the rules and regulations promulgated thereunder. Accordingly, the Merger is expected to be a tax-free transaction for the stockholders of both companies.

 

On November 1, 2007, Quest Midstream completed the purchase of the KPC Pipeline pursuant to a Purchase and Sale Agreement, dated as of October 9, 2007, by and among Quest Midstream, Enbridge Midcoast Energy, L.P. and Midcoast Holdings No. One, L.L.C., whereby Quest Midstream purchased all of the membership interests in the two general partners of Enbridge Pipelines (KPC), the owner of the KPC Pipeline for a purchase price of approximately $133 million in cash, subject to adjustment for working capital at closing. In connection with this acquisition, Quest Midstream issued 3,750,000 common units for $20.00 per common unit, or approximately $75 million of gross proceeds.

 

On November 15, 2007, Quest Energy completed an initial public offering of 9,100,000 common units at $18.00 per unit, or $16.83 per unit after payment of the underwriting discount (excluding a structuring fee). On November 9, 2007, Quest Energy’s common units began trading on the NASDAQ Global Market under the symbol “QELP”. Total proceeds from the sale of the common units in the initial public offering were $163.8 million, before underwriting discounts, a structuring fee and offering costs, of approximately $10.6 million, $0.4 million and $1.5 million, respectively. Quest Energy used the net proceeds of $151.2 million to repay a portion of the indebtedness of Quest.

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: