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Article by DailyStocks_admin    (03-24-08 06:38 AM)

Filed with the SEC from Mar 13 to Mar 19:

Quest Resource (QRCP) Advisory Research raised its stake to about 2.78 million shares (11.9%) from the 2.53 million (10.8%) reported on March 18.

BUSINESS OVERVIEW

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; and

• Natural gas pipelines — transporting, selling, gathering, treating and processing natural gas.

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.

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:


• Seek out opportunities to grow our upstream and midstream master limited partnerships and hence the distributions they make to us;

• Efficiently control the drilling and development of Quest Energy’s acreage position in the Cherokee Basin;

• Expand Quest Midstream’s gas gathering system throughout the Cherokee Basin in order to accommodate the development of a wider acreage footprint;

• Accumulate additional acreage in the Cherokee Basin through Quest Energy in areas where management believes the most attractive development opportunities exist;

• Pursue selected strategic acquisitions in the Cherokee Basin through Quest Energy and Quest Midstream that would add attractive development opportunities and critical gas gathering infrastructure;

• Maintain operational control over our assets whenever possible;

• Limit our reliance on third party contractors with respect to the completion, stimulation and connection of our wells;

• Maintain a low cost and efficient operating structure through the use of remote data monitoring technology;

• Pursue opportunities to apply our expertise with conventional and unconventional resource development in other basins; and

• Pursue opportunities to apply our expertise with building and operating natural gas gathering and transportation infrastructure in other basins.

Competitive Strengths


• Experienced management. Key members of our executive management and technical teams have on average more than 20 years of experience developing conventional and unconventional oil and natural gas fields in the United States. Several have been developing CBM in the Cherokee Basin since 1995.

• Master limited partnership control and incentive distribution rights. Through our ownership of their respective general partners, we control and hold incentive distribution rights in both Quest Energy and Quest Midstream. These incentive distribution rights entitle us to a greater percentage of the distributions made by the partnerships after certain distribution levels are exceeded.

• Low geological risk. The coal seams from which Quest Energy produces CBM are notable for their consistent thickness and gas content. In addition, extensive drilling dating back 60 to 80 years for the development of oil reserves in the Cherokee Basin gives us access to substantial information related to the coal seams Quest Energy targets. Over 100,000 well bores have penetrated the Cherokee Basin since the 1920s. Data available from the drilling records of these wells allows us to determine the aerial extent, thickness and relative permeability of the coal seams Quest Energy targets for development, which greatly reduces its dry hole risk.

• High rate of drilling success. Over 99% of the CBM wells that have been drilled on Quest Energy’s acreage have been, or are capable of being, completed as economic producers.

• Expertise in Cherokee Basin geology. We have spent several years conducting technical research on historical data related to the development of the Cherokee Basin. From this analysis, we believe we have determined where the most attractive opportunities for CBM development exist within the basin.

• Large acreage position and inventory of drilling sites. Quest Energy has the right to develop 558,190 net CBM acres in the Cherokee Basin. As of December 31, 2007, Quest Energy’s acreage was approximately 51.6% developed and offered approximately 2,100 gross CBM drilling locations, of which approximately 800 were classified as proved undeveloped.

• Availability of significant quantities of low cost acreage. Presently, several hundred thousand acres of unleased CBM acreage are available in the Cherokee Basin. We believe this acreage generally can be leased for an amount less than acreage in other basins. These circumstances afford us the opportunity to sustain long-term organic growth by adding undeveloped acreage and CBM drilling locations at a reasonable cost.

• Competitive advantage of our gas gathering agreement. Quest Energy’s gathering agreement with Quest Midstream represents a competitive advantage compared to third parties seeking to lease acreage that is readily served by the system. The gathering fee that Quest Midstream receives for gathering Quest Energy’s gas is determined annually compared to a volume take allowance of up to 30% before royalties for third party operators in the basin. This not only makes development economics less attractive for third party operators to lease land served by the system, it also makes Quest Energy a more attractive lessee for landowners. The vast geographic extent of Quest Midstream’s gas gathering system together with Quest Energy’s large land position makes it unattractive for third parties to lease proximate acreage and build duplicate gas gathering facilities.

• Attractive geological characteristics of Cherokee Basin CBM. Compared to some other basins in the United States where CBM is produced, CBM production in the Cherokee Basin has distinct economic advantages. First, the coal seams in the Cherokee Basin are relatively more permeable and thus tend to produce at a faster rate. This results in a shorter reserve life, the need to drill fewer wells, a faster payout period and a higher present value of reserves. Second, Cherokee Basin coal seams produce relatively less water than coal seams in some other basins. Cherokee Basin CBM wells produce gas immediately, have a shorter dewatering period, and produce less water overall than CBM wells in some other basins.

• Predictable results of our CBM wells. Quest Energy’s CBM wells in the Cherokee Basin have highly consistent behavior in terms of recoverable reserves, production rates and decline curves, which results in lower development risk.

• Concentrated ownership and operational control. Quest Energy owns 100% of the working interest in over 95% of the wells in which it has ownership. As a result of this ownership position, Quest Energy operates substantially all of the wells in which it owns an economic interest.

• Long-lived reserves. Quest Energy’s average reserve-to-production ratio is 8.12 years for its proved developed properties based on its reserves as of December 31, 2007 and production (17.15 Bcfe) for the year ended December 31, 2007. Based on Quest Energy’s current rate of new well development and current undeveloped acreage, we estimate that it would take approximately 6.34 years to fully develop its existing acreage, using 80 acre spacing. In addition, the standard economic life of our typical Cherokee Basin well is approximately 15 years. We believe this long reserve life reduces the reinvestment risk associated with Quest Energy’s asset base.

• Predictable revenue from interstate pipeline. Quest Midstream owns and operates over 1,100 miles of interstate natural gas transmission pipelines in Kansas and Missouri. Shippers on the KPC Pipeline have entered into firm capacity contracts which require them to pay us the same amount regardless of the amount of their contracted throughput they utilize.

• Marketing Flexibility. Quest Midstream’s gas gathering system is able to access several interstate pipelines, providing access to major gas demand centers in the central United States.

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:


• reimbursement of certain insurance, operating and general and administrative expenses incurred on behalf of Quest Energy;

• indemnification for certain environmental liabilities, tax liabilities, tax defects and other losses in connection with assets;

• a license for the use of the Quest name and mark; and

• Quest Energy’s right to purchase from us and our affiliates certain assets that we and our affiliates acquire within the Cherokee Basin.

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.

CEO BACKGROUND

Mr. Cash has been active in the oil and gas exploration and development business for over 25 years. Mr. Cash has been the Chairman of the Board since November 2002 and has been Chief Executive Officer since September 2004. From November 2002 until September 2004, he was Co-Chief Executive Officer and from November 2002 until June 2004, he was Chief Financial Officer. From 1980 to 1986, Mr. Cash worked for Bodard & Hale Drilling Company while pursuing a petroleum engineering degree at Oklahoma State University. During this period, Mr. Cash drilled several hundred wells throughout Oklahoma. In 1987, Mr. Cash formed STP and directed that company in the identification and realization of numerous successful oil, gas and CBM exploration projects. A long-time resident of Oklahoma, Mr. Cash maintains an active role in several charitable organizations.

Mr. Kite is the Chief Executive Officer of Boothbay Royalty Company, based in Oklahoma City, Oklahoma. Boothbay Royalty Company was founded in 1977 as an independent investment company with its primary concentration in the field of oil & gas exploration and production. Mr. Kite spent several years in the commercial banking industry with an emphasis in credit and loan review prior to his involvement in the oil and gas industry. Mr. Kite presently is a director of The All Souls’ Anglican Foundation and the St. Anthony Hospital Foundation. Mr. Kite earned a bachelor’s of business administration in finance from the University of Oklahoma.

Mr. Mitchell founded Riata Energy in 1984. He served as operations manager until 1989 when he assumed the roles of Chief Executive Officer and Chairman, which positions he held until June 2006. Mr. Mitchell was President and COO from June 2006 until December 2006, at which time he retired. Prior to his involvement with Riata, he worked in the oil field services industry and was employed in his family’s ranching and aviation businesses. Mr. Mitchell is presently a director of SandRidge. Mr. Mitchell graduated from Oklahoma State University in 1983 with a Bachelor of Science degree.

Mr. Damon has over 30 years of professional experience specializing in engineering design and development of electric generation and cogeneration systems. He currently is the Chief Executive Officer of Cummins & Barnard, Inc. (“C&B”), which is a privately held engineering-consulting firm focused on power generation development and engineering projects for electric utilities, independent power producers, large industrials and institutional clients throughout the United States. Mr. Damon has been a principal and co-owner of C&B since 1990, leading the project development and strategic consulting business for coal, natural gas and renewable fired power projects. He previously worked for Consumers Power Company, Gilbert-Commonwealth, Inc. and Alternative Energy Ventures before joining C&B. He has also held board seats on a minerals and wind turbine company, MKBY, and a start-up construction company that was recently sold to Aker Kvaerner Songer in which he was also a founding member. Mr. Damon graduated from Michigan State University with a B.S. in Mechanical Engineering and continued graduate studies at both Michigan State University and the University of Michigan.

Mr. Garrison brings expertise in public company activities and issues. Mr. Garrison served as our Treasurer from 1998 to September 2001. Mr. Garrison has been a Certified Public Accountant in public practice providing financial management and accounting services to a variety of businesses for over twenty years. Since July 2004, Mr. Garrison has been the Chief Financial Officer of ICOP Digital, Inc. Mr. Garrison presently is also a director of Empire Energy Corporation. Mr. Garrison holds a bachelor’s degree in Accounting from Kansas State University.

Mr. Rateau is currently the Vice President of Business Development of Alcoa Primary Metals, Energy Division and has been at Alcoa Primary Metals since 1996. Before that, Mr. Rateau held a number of managerial positions with National Steel Corporation from 1981 to 1996. He brings expertise in business acquisitions and divestitures, capital budgets and project management, energy contracting, and applied research of complex technology and processes. Mr. Rateau holds an M.B.A. from Michigan State University and received a B.S. in Industrial Engineering from West Virginia University.

Mr. Grose has been Chief Financial Officer since June 2004. Mr. Grose has 25 years of financial experience, primarily in the exploration, production, and drilling sectors of the oil and gas industry. Mr. Grose also has significant knowledge and expertise in capital development and in the acquisition of oil and gas companies. In previous years, he held various positions including Vice-President and/or CFO for Oxley Petroleum Company during 2002 and 2003, a telecommunications company from 2000 to 2001, Bayard Drilling Technologies, Inc. from 1997 to 1999, and Alexander Energy Corporation from 1980 to 1997. Mr. Grose earned a B.A. in Political Science from Oklahoma State University in 1974 and an MBA from the University of Central Oklahoma in 1977.



Mr. Marlin has served as Executive Vice President – Engineering since September 2004. He also was our Chief Operations Officer from February 2005 through July 2006. He was our engineering manager from November 2002 to September 2004. Prior to that, he was the engineering manager for STP from 1999 until STP’s acquisition by the Company in November 2004. Prior to that, he was employed by Parker and Parsley Petroleum as the Mid-Continent Operations Manager for 12 years. Mr. Marlin has more than 28 years industry experience involving all phases of drilling and production in more than 14 states. His experience also involved primary and secondary operations along with the design and oversight of gathering systems that move as much as 175 MMcf/d. He is a registered Professional Engineer holding licenses in Oklahoma and Colorado. Mr. Marlin earned a B.S. in Industrial Engineering and Management from Oklahoma State University in 1974. Mr. Marlin is a Director of the Mid-Continent Coal Bed Methane Forum.



Mr. Hoover joined us in June of 2006 to manage the organization of our midstream partnership and leads the effort to optimize and grow the Bluestem Gathering System located in the Cherokee Basin and is actively seeking to diversify the holdings of Quest Midstream Partners, L.P. through acquisition and development of new systems in existing and emerging basins. Prior to joining us, Mr. Hoover held the position of Senior Vice President at Enterprise Products Partners L. P. where he managed gathering, processing and treating assets located in the San Juan and Permian Basins. Mr. Hoover’s service at Enterprise came by way of El Paso Field Service Corporation, El Paso Energy Partners L. P. and GulfTerra Energy Partners L. P. where over the course of 10 years he was promoted to Sr. Vice President and managed various midstream assets located in Alabama, Mississippi, Oklahoma, Texas, New Mexico, Arizona, Colorado, Utah and Wyoming. Prior to joining El Paso Field Services, Mr. Hoover held various sales and supply positions with Delhi Gas Pipeline Corporation for 8 years and managed the commercial operation of assets located in Oklahoma and Texas. Mr. Hoover also gained experience in the Independent Power Generation sector with Panda Energy Corporation as well as the Oil and Gas Exploration and Production sector with Champlin Petroleum Company from 1981 to 1988. Mr. Hoover earned a Bachelor of Business Administration degree in Petroleum Land Management from the University of Oklahoma in 1981.



Mr. Bolton has served as Executive Vice President - Land since May 2006. Prior to that, he was a Land Manager for a large, Oklahoma based oil and gas lease broker. Mr. Bolton is a Certified Professional Landman with over 15 years of experience in various aspects of the oil and gas industry, and has worked extensively throughout Oklahoma, Texas, and Kansas. Mr. Bolton holds a Bachelor of Liberal Studies degree from the University of Oklahoma, attended the Oklahoma City University School of Law, and is a member of American Association of Petroleum Landmen, Oklahoma City Association of Petroleum Landmen, the American Bar Association, and the Energy Bar Association.



Mr. Hochstein joined us in January of 2006 as Manager of New Ventures. He assumed the Executive Vice President – Exploration/A&D position effective March 16, 2007. While serving as Manager of New Ventures, Mr. Hochstein led resource assessment efforts for several acquisition projects and was responsible for generating two new resource plays for the company. In his new role, Mr. Hochstein will continue to develop new opportunities for the company, lead the A&D efforts, and oversee all geologic and reservoir engineering functions. Before joining us, Mr. Hochstein served for two years as a partner in Rockport Energy, a small E&P company. Prior to that he worked 23 years with Sonat Exploration Co. / El Paso, where he held various technical and management positions including Technical Director and Vice President of CBM/Rockies. Mr. Hochstein has more than 25 years of industry experience and more than 10 years of unconventional resource experience. Mr. Hochstein holds a Bachelor of Science in Geologic Sciences from the University of Texas, Austin, and is a member of the American Association of Petroleum Geologists.

COMPENSATION

Base Salary: Base salaries for all Senior Executives are established base on their scope of responsibilities, taking into account competitive market compensation paid by other companies in the Company’s peer group (described below). The Committee considers the median salary range for each Senior Executive’s counterpart, but makes adjustments to reflect differences in job descriptions and scope of responsibilities for each Senior Executive and to reflect the Committee’s philosophy that each Senior Executive’s total compensation should be at the median level (50 th percentile) relative to the Company’s peer group. The Compensation Committee annually reviews base salaries for Senior Executives and makes adjustments from time to time to realign their salaries, after taking into account individual performance, responsibilities, experience, autonomy, strategic perspectives and marketability, as well as the recommendations of the Chief Executive Officer.

As discussed above, during 2006 the Company and the Committee hired T-P to conduct a comprehensive benchmarking survey and to evaluate the Company’s overall compensation program. After review and evaluation of the T-P base salary data, the Committee approved significant base salary increases for certain Senior Executives, as shown above, because the 2006 base salaries were significantly below market levels for the group of 13 peer companies.



Annual Cash Bonus Awards: Our Management Annual Incentive Plan (“Bonus Plan”) is intended to recognize value creation by providing competitive incentives for meeting and exceeding annual financial and operating performance measurement targets. By providing market-competitive bonus awards, the Committee believes the plan will support the attraction and retention of Senior Executive talent critical to achieving the strategic business objectives of the Company. Our Bonus Plan puts a significant portion of total compensation at risk by linking potential annual compensation to the Company’s achievement of specific performance goals during the year, which creates a direct connection between the executive’s pay and the Company’s financial performance.

Each year the Committee establishes goals at the beginning of each calendar year. For 2006, these goals included:




o


Operational goals consisting of finding and development costs per mcf, reserve replacement and revisions and production growth; and




o


Financial discipline goals consisting of lease operating expense, pipeline operating expense and earnings before interest, taxes, depreciation and amortization (“EBITDA”).

Each of these six performance goals was equally weighted for all participants in the Bonus Plan. The Committee believed the thresholds set would require the Senior Executives to improve the Company’s financial and operational performance, and that it would be difficult for the Senior Executives to reach the target levels.

The Committee developed and reviewed financial and operating performance measures to help ensure that the compensation paid to the Senior Executives reflected the success of the Company, as well as the value provided to our stockholders. The Committee established bonus award levels as a percentage of the participant’s base salary. The percentages varied based on organizational responsibilities and market-compilation bonus levels based on industry data. The amount of bonus award earned in a Plan Year is based on the achievement of performance goals.

For 2006, the Bonus Plan provided for bonuses to be paid in the form of 2/3 cash and 1/3 common stock. The 2006 target goals for each of the Company’s president and chief executive officer and the chief financial officer were as follows: If he achieved 60% of his target goal, his incentive award under the plan would be 22% of his base salary (payable 15% in cash and 7% in Company stock). If he achieved 100% of his target goal, his incentive award would be 42% of his base salary (payable 28% in cash and 14% in Company stock). If he achieved 150% of his target goal, his incentive award would be 99% of his base salary (payable 66% in cash and 33% in Company stock).



The 2006 target goals for each of the other Senior Executives were as follows: If he achieved 60% of his target goal, his incentive award under the plan would be 7% of his base salary (payable 5% in cash and 2% in Company stock). If he achieved 100% of his target goal, his incentive award would be 27% of his base salary (payable 18% in cash and 9% in Company stock). If he achieved 150% of his target goal, his incentive award would be 73.5% of his base salary (payable 49% in cash and 24.5% in Company stock).



For 2007, the Committee established performance targets for each of the five corporate financial goals described below. The Committee eliminated “pipeline operating expense” as a performance measure in 2007, because the midstream pipeline operations were dropped into Quest Midstream Partners, L.P. in December 2006.




o


EBITDA (earning before interest, taxes, depreciation and amortization)




o


Lease Operating Expense (excluding gross production taxes and ad valorem taxes)




o


Finding and Development Cost




o


Year-End Proved Reserves




o


Production



The Committee increased the 2007 performance targets from the 2006 levels. The Committee believes the Senior Executives must continue to improve the Company’s financial and operating performance in order to achieve the targets, and that it will be difficult for Senior Executives to reach the target levels.

For 2007, awards under the Bonus Plan will be payable solely in cash. The Committee anticipates that future annual bonus awards will also be paid only in the form of cash awards. The Committee made this change because of the roll out of the long-term incentive plan, as described below, so that the Committee could preserve the number of shares remaining under the 2005 Omnibus Stock Award Plan for the long-term incentive plan. Any shares paid as part of the Bonus Plan for 2006 are considered part of the 2005 Omnibus Stock Award Plan and count against the total number of shares that may be issued pursuant to that plan.



For 2007, the target goals for each of the Company’s president and chief executive officer and the chief financial officer are as follows: If he achieves 60% of his target goal, his incentive award under the plan would be 22% of his base salary. If he achieves 100% of his target goal, his incentive award would be 42% of his base salary. If he achieves 150% of his target goal, his incentive award would be 99% of his base salary. The 2007 target goals for each of the Company’s executive vice president-engineering and executive vice president-land are as follows: If he achieves 60% of his target goal, his incentive award under the plan would be 7% of his base salary. If he achieves 100% of his target goal, his incentive award would be 27% of his base salary. If he achieves 150% of his target goal, his incentive award would be 73.5% of his base salary. In setting the 2007 performance targets and target goals, the Committee considered the recommendation of the Company’s chief executive officer and chief financial officer. Mr. Hoover, as President of Quest Midstream Partners, L.P., will not participate in the Bonus Plan for 2007 and future years.

After the end of the Plan Year, the Committee determines to what extent the Company and the participants have achieved the performance measurement goals. The Committee calculates and certifies in writing the amount of each participant’s bonus based upon the actual achievements and computation formulae set forth in the Bonus Plan. The Committee has no discretion to increase the amount of any Senior Executive’s bonus as so determined, but may reduce the amount of or totally eliminate such bonus, if it determines, in its absolute and sole discretion that such reduction or elimination is appropriate in order to reflect the Senior Executive’s performance or unanticipated factors. The performance period (“Incentive Period”) with respect to which target awards and bonuses may be payable under the Bonus Plan will generally be the fiscal year beginning on January 1 and ending on December 31, but the Committee has the authority to designate different Incentive Periods.

Productivity Gain Sharing Payments: A one-time cash payment equal to 10% of an individual’s monthly base salary is earned during each month that the Company’s CBM production rate increases by 1000 MCF/day over the prior record. All employees of the company (other than those employed by Quest Midstream GP) are eligible to receive productivity gain sharing payments. The purpose of these payments is to incentivize all employees, including Senior Executives, to continually and immediately focus on production. The Senior Executives received payments equal to approximately 1.6 additional months of base salary as a result of this plan, as follows: Jerry Cash - $53,333; David Grose - $36,667; Richard Marlin - $33,000; Randy Hoover - $20,625 and David Bolton - $15,625. Management of the Company believes this incentive plan is unique to the Company and is not used by peer group companies. As a result, the Committee believes these productivity payments help the Company attract and retain talented and highly motivated Senior Executives. Mr. Hoover, as President of Quest Midstream Partners, L.P., will not participate in the productivity gain sharing payments for 2007 and future years.



Equity Awards:



Omnibus Stock Award Plan: On October 14, 2005, the Board of Directors adopted our 2005 Omnibus Stock Award Plan that provides for grants of non-qualified stock options, restricted shares, bonus shares, deferred shares, stock appreciation rights, performance units and performance shares. The Omnibus Plan was approved by our stockholders at the 2006 annual meeting. The total number of shares that may be issued under the Omnibus Plan is 2,200,000. The Omnibus Plan also permits the grant of incentive stock options (“ISOs”). The objectives of the Omnibus Plan are to strengthen key employees’ and non-employee directors’ commitment to our success, to stimulate key employees’ and non-employee directors’ efforts on our behalf and to help us attract new employees with the education, skills and experience we need and retain existing key employees. All of our equity awards are issued under the Omnibus Plan.

Management Annual Incentive Awards: As described above, in 2006 the Committee granted awards under the Bonus Plan that were comprised of 2/3 cash and 1/3 Company stock. In 2007, no stock awards will be made under the Bonus Plan because the Committee will use the long-term incentive plan described below for equity awards.

MANAGEMENT DISCUSSION FROM LATEST 10K

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:


• projections and estimates concerning the timing and success of specific projects;

• financial position;

• business strategy;

• budgets;

• amount, nature and timing of capital expenditures;

• drilling of wells and construction of pipeline infrastructure;

• acquisition and development of natural gas and oil properties and related pipeline infrastructure;

• timing and amount of future production of natural gas and oil;

• operating costs and other expenses;

• estimated future net revenues from natural gas and oil reserves and the present value thereof;

• cash flow and anticipated liquidity; and

• other plans and objectives for future operations.

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


• our ability to implement our business strategy;

• the extent of our success in discovering, developing and producing reserves, including the risks inherent in exploration and development drilling, well completion and other development activities, including pipeline infrastructure;

• fluctuations in the commodity prices for natural gas and crude oil;

• engineering and mechanical or technological difficulties with operational equipment, in well completions and workovers, and in drilling new wells;

• land issues;

• the effects of government regulation and permitting and other legal requirements;

• labor problems;

• environmental related problems;

• the uncertainty inherent in estimating future natural gas and oil production or reserves;

• production variances from expectations;

• the substantial capital expenditures required for construction of pipelines and the drilling of wells and the related need to fund such capital requirements through commercial banks and/or public securities markets;

• disruptions, capacity constraints in or other limitations on our pipeline systems;

• costs associated with perfecting title for natural gas rights and pipeline easements and rights of way in some of our properties;

• the need to develop and replace reserves;

• competition;

• dependence upon key personnel;

• the lack of liquidity of our equity securities;

• operating hazards attendant to the natural gas and oil business;

• down-hole drilling and completion risks that are generally not recoverable from third parties or insurance;

• potential mechanical failure or under-performance of significant wells;

• climatic conditions;

• natural disasters;

• acts of terrorism;

• availability and cost of material and equipment;

• delays in anticipated start-up dates;

• our ability to find and retain skilled personnel;

• availability of capital;

• the strength and financial resources of our competitors; and

• general economic conditions.

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

Overview of 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.

Results of Operations

As a result of the acquisition of KPC Pipeline in November 2007, we have begun reporting our results of operations as two segments: Gas and Oil Production and Natural Gas Pipelines. Previously reported amounts have been adjusted to reflect this change, which did not impact our consolidated financial statements.

The following discussion of financial condition and results of operations should be read in conjunction with the consolidated financial statements and the notes to the consolidated financial statements, which are included elsewhere in this report.

Gas and Oil Production Segment

Year ended December 31, 2007 compared to the year ended December 31, 2006

Oil and Gas Sales. Oil and gas sales of $113.0 million for the year ended December 31, 2007 represents an increase of 73% when compared to oil and gas sales of $65.6 million for the year ended December 31, 2006. The increase in oil and gas sales from $65.6 million for the year ended December 31, 2006 to $113.0 million for the year ended December 31, 2007 resulted from the additional wells completed during the past twelve months. The additional wells completed contributed to the production of 17,148 Mmcfe of net gas for the year ended December 31, 2007, as compared to 12,341 net Mmcfe produced for the year ended December 31, 2006. Our product prices before hedge settlements on an equivalent basis (mcfe) increased from $5.95 per Mcfe average for the 2006 period to $6.17 per Mcfe average for the 2007 period. Accounting for hedge settlements, the product prices increased from $5.31 per Mcfe average for the 2006 period to $6.59 per Mcfe average for the 2007 period.

Operating Expenses. Operating expenses for the Gas and Oil Production Segment, which consist of oil and gas production costs and transportation expense, were $57.2 million for the year ended December 31, 2007, as compared to $38.5 million for the year ended December 31, 2006, an increase of $18.7 million, or 48.6%. Oil and gas production costs for the year ended December 31, 2007 were $28.0 million as compared to $21.2 million for the year ended December 31, 2006, an increase of $6.8 million, or 32%. Production costs, excluding gross production and ad valorem taxes, were $1.27 per Mcfe for 2007 compared to $1.29 per Mcfe for the year ended December 31, 2006. Production costs, inclusive of gross production and ad valorem taxes, were $1.63 per Mcfe for the 2007 period as compared to $1.84 per Mcfe for the year ended December 31, 2006 period, representing an 11% decrease. This decrease was a result of the higher production volumes for the year ended December 31, 2007 and the benefits from certain cost cutting programs started during the third quarter.

Transportation expense increased from $1.40 per Mcfe for 2006 to $1.69 per Mcfe for 2007. This increase resulted from the midstream services agreement with Quest Midstream that became effective December 1, 2006, which provided for a fixed transportation fee that was higher than the fees in the year earlier period.

Depreciation, Depletion and Amortization. We are subject to variances in our depletion rates from period to period, including the periods described below. These variances result from changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our gas and oil properties. Our depletion of gas and oil properties as a percentage of oil and gas sales was 31% in the year ended December 31, 2007 compared to 39% in 2006. Depreciation, depletion and amortization expense was $2.10 per Mcfe in December 31, 2007 compared to $2.05 per Mcfe in 2006. Increases in our depletable basis and production volumes caused depletion expense to increase $10.0 million to $35.5 million in 2007 compared to $25.5 million in 2006.

Depreciation and amortization expense for our Gas and Oil Production Segment was $327,000 in the year ended December 31, 2007 compared to $209,000 in 2006. The increase of $118,000, or 56%, is due to additional vehicles, equipment, and facilities acquired during 2007.

Change in Derivative Fair Value. Change in derivative fair value was a non-cash loss of $6.5 million for the year ended December 31, 2007, which included an $11.3 million loss attributable to the change in fair value for certain derivative contracts that did not qualify as cash flow hedges pursuant to SFAS 133 and a gain of $4.8 million relating to hedge ineffectiveness. Change in derivative fair value was a non-cash gain of $6.4 million for the year ended December 31, 2006, which included a $12.2 million gain attributable to the change in fair value for certain derivative contracts that did not qualify as cash flow hedges pursuant to SFAS 133, settlements due to ineffective cash flow hedges of $10.2 million and a gain of $4.4 million relating to hedge ineffectiveness. Amounts recorded in this caption represent non-cash gains and losses created by valuation changes in derivatives that are not entitled to receive hedge accounting. All amounts recorded in this caption are ultimately reversed in this caption over the respective contract term.

Impairment Charge. In the year ended December 31, 2006, we recognized a $30.7 million provision for impairment of oil and gas properties from a full cost pool ceiling write-down, primarily as a result of declines in estimated reserves due to the prevailing market prices of oil and gas at the measurement date.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

Results of Operations
The following discussion is based on the consolidated operations of all our subsidiaries and should be read in conjunction with the financial statements included in this report; and should further be read in conjunction with the audited financial statements and notes thereto included in our annual report on Form 10-K/A for the year ended December 31, 2006. Comparisons made between reporting periods herein are for the three and nine month periods ended September 30, 2006 as compared to the same period in 2007.

Three Months Ended September 30, 2006 and September 30, 2007

Revenues. Oil and gas sales were $28.5 million for the three months ended September 30, 2007 compared to $15.3 million for the three months ended September 30, 2006, an increase of $13.2 million, or 85.9%. The increase in oil and gas sales for the three months ended September 30, 2007 was the result of a 36.7% increase in sales volumes that was achieved by the addition of more producing wells and an increase in natural gas prices between periods, which was partially offset by the natural decline in production from some of our older gas wells.
Gas pipeline revenue was $1.8 million for the three months ended September 30, 2007 compared to $1.4 million for the three months ended September 30, 2006, an increase of $0.4 million, or 30.3%. The increase was due to the increased volumes flowing through our pipelines and an increase in natural gas prices, which resulted in increased revenues for gas transported on a percentage of proceeds basis.
The additional wells contributed to the production of 4,544,000 net Mcf of gas for the three months ended September 30, 2007, as compared to 3,331,000 net Mcf produced in the same quarter last year. Our product prices on an equivalent basis (Mcfe) increased from $5.67 per Mcfe on average for the three months ended September 30, 2006 to $6.24 per Mcfe on average for the three months ended September 30, 2007.
Operating Expenses. Oil and gas production costs, including gross production tax and ad valorem tax were $7.3 million for the three months ended September 30, 2007, as compared to $5.5 million for the three months ended September 30, 2006, an increase of $1.8 million, or 32.6%. Lease operating costs, excluding gross production tax and ad valorem tax, per Mcfe for the three months ended September 30, 2007, decreased to $1.20 per Mcfe as compared to $1.31 per Mcfe for the three months ended September 30, 2006. The lease operating cost per Mcfe decreased due to reductions in several cost categories, including chemical treatment and third party service units.
Pipeline operating costs increased by approximately 47.2% from $3.4 million for the three months ended September 30, 2006 to $5.0 million for the three months ended September 30, 2007. Pipeline operating costs per Mcf for the three months ended September 30, 2007 and 2006 were $1.10 per Mcf and $1.02 per Mcf, respectively. The cost increases incurred for pipeline operations are due to a number of factors, including: excessively wet summer weather conditions (including flooding) that resulted in significant overtime hours for our field labor force working to restore production, the number of wells acquired, completed and operated during the quarter, the increased miles of pipeline and compression in service and increased property taxes due to both the increased miles of pipeline and an increase in property tax rates.
Depreciation, Depletion and Amortization. For the three months ended September 30, 2007, depreciation, depletion and amortization increased to $9.3 million as compared to $7.9 million for the three months ended September 30, 2006. The increase in depreciation, depletion and amortization is a result of the increased number of producing wells and miles of pipelines developed and the higher volumes of gas and oil produced.
General and Administrative Expenses . General and administrative expenses increased from $2.7 million for the three months ended September 30, 2006 to $3.7 million for the three months ended September 30, 2007, an increase of $1.0 million, or 34.2%. This increase resulted primarily from a non-cash charge of approximately $976,000 for amortization of equity incentive awards. The remainder of the increase is due to an increase in staff personnel, legal, accounting and professional fees related to the increased size and complexity of our operations.
Interest Expense. Interest expense was $8.2 million for the three months ended September 30, 2007 as compared to $7.0 million for the three months ended September 30, 2006, an increase of $1.2 million, or 17.7%. This increase was due to an increase in our outstanding borrowings related to equipment, development and leasehold expenditures and higher average interest rates.
Other Expense. Other expense for the three months ended September 30, 2007 was $5,000 as compared to other income of $4,000 for the three-month period ended September 30, 2006.
Change in Derivative Fair Value . Change in derivative fair value was a non-cash gain of $5.5 million for the three months ended September 30, 2007, which included a $4.7 million gain attributable to the change in fair value for certain derivatives that did not qualify as cash flow hedges pursuant to SFAS 133 and a gain of $791,000 relating to hedge ineffectiveness. Change in derivative fair value was a non-cash loss of $332,000 for the three months ended September 30, 2006, which included a $1.3 million loss attributable to the change in fair value for certain derivatives that did not qualify as cash flow hedges pursuant to SFAS 133 and a gain of $998,000 relating to hedge ineffectiveness. Amounts recorded in this caption represent non-cash gains and losses created by valuation changes in derivatives that are not entitled to receive hedge accounting. All amounts recorded in this caption are ultimately reversed in this caption over the respective contract term.

Revenues. Oil and gas sales were $81.9 million for the nine months ended September 30, 2007 compared to $49.1 million for the nine months ended September 30, 2006, an increase of $32.8 million, or 66.8%. The increase in oil and gas sales for the nine months ended September 30, 2007 resulted from a 40.6% increase in sales volumes that was achieved by the addition of more producing wells, which was partially offset by the natural decline in production from some of our older gas wells.
Gas pipeline revenue was $5.1 million for the nine months ended September 30, 2007 compared to $3.7 million for the nine months ended September 30, 2006, an increase of $1.4 million, or 37.6%. The increase was due to the increased volumes flowing through our pipelines and an increase in natural gas prices, which resulted in increased revenues for gas transported on a percentage of proceeds basis.
The additional wells contributed to the production of 12,338,000 net Mcf of gas for the nine months ended September 30, 2007, as compared to 8,718,000 net Mcf produced in the same nine month period last year. Our product prices on an equivalent basis (Mcfe) increased from $6.08 per Mcfe on average for the nine months ended September 30, 2006 to $6.21 per Mcfe on average for the nine months ended September 30, 2007.
Operating Expenses . Oil and gas production costs including gross production tax and ad valorem tax were $22.2 million for the nine months ended September 30, 2007, as compared to $14.1 million for the nine months ended September 30, 2006, an increase of $8.1 million, or 58%. Lease operating costs excluding gross production tax and ad valorem tax, per Mcfe for the nine months ended September 30, 2007 increased to $1.31 per Mcfe as compared to $1.23 per Mcfe for the nine months ended September 30, 2006. The lease operating cost per Mcfe increased due to a number of factors, including: winter weather and excessively wet spring and summer weather conditions (including flooding) that resulted in a larger percentage of the field labor force being charged to operating expense as compared to capital expenditures, our increased development program, an increase in wage rates due to a tight labor market for skilled workers in the Cherokee Basin, an increase in well repairs, utilities and fuel costs due to the increase in the number of wells being operated, an increase in energy and raw material costs.
Pipeline operating costs increased by approximately 53% from $9.3 million for the nine months ended September 30, 2006 to $14.3 million for the nine months ended September 30, 2007. Pipeline operating costs per Mcf for the nine months ended September 30, 2007 increased to $1.16 per Mcf as compared to $1.07 per Mcf for the nine months ended September 30, 2006. The cost increases incurred for pipeline operations are due to a number of factors, including: winter weather and excessively wet spring and summer weather conditions (including flooding) that resulted in significant overtime hours for our field labor force working to restore production, the number of wells acquired, completed and operated during the quarter, the increased miles of pipeline and compression in service and increased property taxes due to both the increased miles of pipeline and an increase in property tax rates.
Depreciation, Depletion and Amortization . For the nine months ended September 30, 2007, depreciation, depletion and amortization increased to $25.6 million as compared to $20.6 million for the nine months ended September 30, 2006. The increase in depreciation, depletion and amortization is a result of the increased number of producing wells and miles of pipelines developed and the higher volumes of gas and oil produced.
General and Administrative Expenses . General and administrative expenses increased from $6.6 million for the nine months ended September 30, 2006 to $11.7 million for the nine months ended September 30, 2007, an increase of $5.1 million, or 77.3%. This increase resulted primarily from a non-cash charge of approximately $3.9 million for amortization of equity incentive awards. The remainder of the increase is due to an increase in staff personnel, legal, accounting and professional fees related to the increased size and complexity of our operations.
Interest Expense . Interest expense was $22.9 million for the nine months ended September 30, 2007 as compared to $15.9 million for the nine months ended September 30, 2006, an increase of $7.0 million, or 44.3%. This increase was due to an increase in our outstanding borrowings related to equipment, development and leasehold expenditures and higher average interest rates.
Other Expense. Other expense for the nine months ended September 30, 2007 was $37,000 as compared to other expense of $63,000 for the nine-month period ended September 30, 2006. The decrease is due to a reduction in overhead and pumper charges.
Change in Derivative Fair Value. Change in derivative fair value was a non-cash gain of $5.4 million for the nine months ended September 30, 2007, which included a $3.3 million gain attributable to the change in fair value for certain derivatives that did not qualify as cash flow hedges pursuant to SFAS 133 and a gain of $2.0 million relating to hedge ineffectiveness. Change in derivative fair value was a non-cash gain of $6.3 million for the nine months ended September 30, 2006, which included a $13.3 million gain attributable to the change in fair value for certain derivatives that did not qualify as cash flow hedges pursuant to SFAS 133, a $10.2 million loss due to the contracts not qualifying for hedge accounting treatment, and a gain of $3.2 million relating to hedge ineffectiveness. Amounts recorded in this caption represent non-cash gains and losses created by valuation changes in derivatives that are not entitled to receive hedge accounting. All amounts recorded in this caption are ultimately reversed in this caption over the respective contract term.




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