Continental Resources Inc. CEO Harold Hamm bought 36210 shares on 7-30-2008 at $55.9
We are an independent oil and natural gas exploration and production company with operations in the Rocky Mountain, Mid-Continent and Gulf Coast regions of the United States. We were originally formed in 1967 to explore, develop and produce oil and natural gas properties. Through 1993, our activities and growth remained focused primarily in Oklahoma. In 1993, we expanded our activity into the Rocky Mountain and Gulf Coast regions. Approximately 82% of our estimated proved reserves as of December 31, 2007 are located in the Rocky Mountain region. We completed an initial public offering of our common stock on May 14, 2007, and began trading on the New York Stock Exchange on May 15, 2007 under the ticker symbol â€śCLRâ€ť.
We focus our exploration activities in large new or developing plays that provide us the opportunity to acquire undeveloped acreage positions for future drilling operations. We have been successful in targeting large repeatable resource plays where horizontal drilling, advanced fracture stimulation and enhanced recovery technologies provide the means to economically develop and produce oil and natural gas reserves from unconventional formations. As a result of these efforts, we have grown substantially through the drillbit, adding 89.0 MMBoe of proved oil and natural gas reserves through extensions and discoveries from January 1, 2003 through December 31, 2007 compared to 0.9 MMBoe added through proved reserve purchases during that same period.
As of December 31, 2007, our estimated proved reserves were 134.6 MMBoe, with estimated proved developed reserves of 101.2 MMBoe, or 75% of our total estimated proved reserves. Crude oil comprised 77% of our total estimated proved reserves. For the year ended December 31, 2007, we generated revenues of $582.2 million, and operating cash flows of $390.6 million. For the year and quarter ended December 31, 2007, daily production averaged 29,099 and 30,369 Boe per day, respectively. This represents growth of 18% and 15% as compared to the year and quarter ended December 31, 2006, when daily production averaged 24,706 and 26,503, respectively.
The following table summarizes our total estimated proved reserves, PV-10 and net producing wells as of December 31, 2007, average daily production for the three months ended December 31, 2007 and the reserve-to-production index in our principal regions. Our reserve estimates as of December 31, 2007 are based primarily on a reserve report prepared by Ryder Scott Company, L.P., our independent reserve engineers. In preparing its report, Ryder Scott Company, L.P. evaluated properties representing approximately 85% of our PV-10. Our technical staff evaluated properties representing the remaining 15% of our PV-10.
Our Business Strategy
Our goal is to increase shareholder value by finding and developing crude oil and natural gas reserves at costs that provide an attractive rate of return on our investment. The principal elements of our business strategy are:
Focus on Oil. During the late 1980â€™s we began to believe that the valuation potential for crude oil exceeded that of natural gas. Accordingly, we began to shift our reserve and production profiles towards crude oil. As of December 31, 2007, crude oil comprises 77% of our total proved reserves and 82% of our 2007 annual production. Although we do pursue natural gas opportunities, we continue to believe that crude oil valuations will remain superior to natural gas valuations on a relative Btu basis.
Growth Through Low-Cost Drilling . Substantially all of our annual capital expenditures are invested in drilling projects and acreage and seismic acquisitions. From January 1, 2003 through December 31, 2007, proved oil and natural gas reserve additions through extensions and discoveries were 89.0 MMBoe compared to 0.9 MMBoe of proved reserve purchases.
Internally Generate Prospects . Our technical staff has internally generated substantially all of the opportunities for the investment of our capital. As an early entrant in new or emerging plays, we expect to acquire undeveloped acreage at a lower cost than those of later entrants into a developing play.
Focus on Unconventional Oil and Natural Gas Resource Plays . Our experience with horizontal drilling, advanced fracture stimulation and enhanced recovery technologies allows us to commercially develop unconventional oil and natural gas resource plays, such as the Red River B dolomite, Bakken Shale and Arkoma Woodford formations. Production rates in the Red River units also have been increased through the use of enhanced recovery technology. Our production from the Red River units, the Bakken field, and the Arkoma Woodford comprised approximately 8,310 MBoe, or 78% of our total oil and natural gas production during the year ended December 31, 2007.
Acquire Significant Acreage Positions in New or Developing Plays . In addition to the 465,207 net undeveloped acres held in the Montana and North Dakota Bakken shale and Arkoma Woodford fields, we held 171,475 net undeveloped acres in other oil and natural gas shale plays as of December 31, 2007. Our technical staff is focused on identifying and testing new unconventional oil and natural gas resource plays where significant reserves could be developed if commercial production rates can be achieved through advanced drilling, fracture stimulation and enhanced recovery techniques.
Our Business Strengths
We have a number of strengths that we believe will help us successfully execute our strategies:
Large Acreage Inventory . We own 733,132 net undeveloped and 372,329 net developed acres as of December 31, 2007. Approximately 72% of the undeveloped acres are found within unconventional shale resource plays including the Bakken shale in North Dakota and Montana and the Woodford shale in southeast Oklahoma. The balance of the locations and undeveloped acreage is found in other emerging unconventional resource plays including the Woodford and Atoka of western Oklahoma and the Red River of South Dakota as well as more conventional plays including 3D defined locations for the Trenton-Black River of Michigan, Red River of Montana, and Frio in South Texas.
Horizontal Drilling and Enhanced Recovery Experience . In 1992, we drilled our initial horizontal well, and we have drilled over 460 horizontal wells since that time. We also have substantial experience with enhanced recovery methods and currently serve as the operator of 48 waterflood units. Additionally, we operate eight high pressure air injection (â€śHPAIâ€ť) floods in the United States.
Control Operations Over a Substantial Portion of Our Assets and Investments . As of December 31, 2007, we operated properties comprising 93% of our PV-10. By controlling operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and fracture stimulation methods used.
Experienced Management Team . Our senior management team has extensive expertise in the oil and gas industry. Our Chief Executive Officer, Harold G. Hamm, began his career in the oil and gas industry in 1967. Our seven senior officers have an average of 27 years of oil and gas industry experience. Additionally, our technical staff, which includes 21 petroleum engineers, 16 geoscientists and 10 landmen, has an average of 19 years experience in the industry.
Strong Financial Position . As of February 29, 2008, we had outstanding borrowings under our credit facility of approximately $222.0 million and available capacity under our selected commitment level of $178.0 million. We have elected to set the commitment level at $400 million, which is below the established borrowing base of $600 million, in order to minimize commitment fees. We believe that our planned exploration and development activities will be funded substantially from our operating cash flows and borrowings under our credit facility.
Oil and Gas Operations
The following tables set forth our estimated proved oil and natural gas reserves, percent of total proved reserves that are proved developed, the PV-10 and standardized measure of discounted future net cash flows as of December 31, 2007 by reserve category and region. Ryder Scott Company, L.P., our independent petroleum engineers, evaluated properties representing approximately 85% of our PV-10, and our technical staff evaluated the remaining properties. The year-end weighted average oil and natural gas prices used in the computation of future net cash flows at December 31, 2007 were $82.86 per barrel and $6.14 per Mcf, respectively.
As of December 31, 2007, there were 26 gross (12.7 net) development wells and 42 gross (19.9 net) exploratory wells in the process of drilling.
As of February 29, 2008, we operated 15 rigs on our properties and have plans to add additional rigs during the year. There can be no assurance, however, that additional rigs will be available to us at an attractive cost. See â€śRisk Factorsâ€”The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.â€ť
Summary of Oil and Natural Gas Properties and Projects
Rocky Mountain Region
Our properties in the Rocky Mountain region represented 87% of our PV-10 as of December 31, 2007. During the three months ended December 31, 2007, our average daily production from such properties was 22,365 net Bbls of oil and 13,409 net Mcf of natural gas. Our principal producing properties in this region are in the Red River units, the Bakken field and the Big Horn Basin.
Red River Units
Our Red River units represented 56% of our PV-10 in the Rocky Mountain region as of December 31, 2007 and 58% of our average daily Rocky Mountain region equivalent production for the three months ended December 31, 2007. The eight units comprising the Red River units are located along the Cedar Hills Anticline in North Dakota, South Dakota and Montana and produce oil and natural gas from the Red River â€śBâ€ť formation, a thin, continuous, dolomite formation at depths of 8,000 to 9,500 feet. Our Red River units comprise a portion of the Cedar Hills field, listed by the Energy Information Administration in 2006 as the 13 th largest onshore, lower 48 field in the United States ranked by liquid proved reserves.
Cedar Hills Units . The Cedar Hills North unit (CHNU) is located in Bowman and Slope Counties, North Dakota. We drilled the initial horizontal well in the CHNU, the Ponderosa 1-15, in April 1995. As of December 31, 2007, we had drilled 185 horizontal wells within this 49,700-acre unit, with 113 producing wellbores and the remainder serving as injection wellbores. We operate and own a 98% working interest in the CHNU.
The Cedar Hills West unit (CHWU), in Fallon County, Montana, is contiguous to the northern portion of CHNU. As of December 31, 2007, this 7,800-acre unit contained ten horizontal producing wells and five horizontal injection wells. We operate and own a 100% working interest in the CHWU.
In January 2003, we commenced enhanced recovery in the two Cedar Hills units, with HPAI used throughout most of the area and water injected generally along the boundary of the CHNU. Under HPAI, compressed air injected into a reservoir oxidizes residual oil and produces flue gases (primarily carbon dioxide and nitrogen) that mobilize and sweep the crude oil into producing wellbores. In response to the HPAI, water injection and increased density drilling operations, production from the Cedar Hills units increased to 10,869 net Boe per day in December 2007 from 2,185 net Boe per day in November 2003. As of December 31, 2007, the average density in the Cedar Hill units was approximately one producing wellbore per 467 acres. We currently plan to drill 56 new horizontal wellbores and 5 horizontal extensions of existing wellbores in the Cedar Hills units during the next two years, increasing the density of both the producing and injection wellbores. The reduced distance between wells will allow part of the field to be converted from air injection to water injection. This conversion will begin in 2008 and is forecast to lower operating expenses, as water is less costly to inject than air. In 2008, we plan to invest approximately $113 million drilling in the Cedar Hills units.
On August 22, 2007 the Hiland Partners, LP (â€śHilandâ€ť) Badlands gas plant became operational for the processing and treatment of gas produced from the CHNU and CHWU and Medicine Pole Hills Unit. Under the terms of the November 8, 2005 contract we agree to deliver low pressure gas to Hiland for compression, treatment and processing. Nitrogen and carbon dioxide must be removed from the gas production associated with oil production from the units for the gas production to be marketable. Under the terms of the contract, we pay $0.60 per Mcf in gathering and treating fees, and 50% of the electrical costs attributable to compression and plant operation and receive 50% of the proceeds from residue gas and plant product sales. After we deliver 36 Bcf of gas, the $0.60 per Mcf gathering and treating fee is eliminated. During December 2007, we sold 5,322 net Mcf of natural gas per day.
Medicine Pole Hills Units . The Medicine Pole Hills units (MPHU) are approximately five miles east of the southern portion of the CHNU. We acquired the Medicine Pole Hills unit in 1995. At that time, the 9,600- acre unit consisted of 18 vertical producing wellbores and four injection wellbores under HPAI producing 525 net Bbls of oil per day. We have since drilled 40 horizontal wellbores extending production to the west with the formation of the 15,000-acre Medicine Pole Hills West unit and to the south, with the 11,500-acre Medicine Pole Hills South unit. All three units are under HPAI. We operate and own an average 77% working interest in the three units. Production from the units averaged 1,234 net Bbls of oil and 409 net Mcf of natural gas per day during December 2007. We are currently operating one rig and plan to drill 12 new horizontal wellbores and four horizontal extensions of existing wellbores during the next 18 months, increasing the density of both producing and injection wellbores. We believe these operations will increase production and sweep efficiency. In 2008, we plan to invest approximately $29.0 million for drilling in MPHU.
Buffalo Red River Units . Three contiguous Buffalo Red River units (Buffalo, West Buffalo and South Buffalo) are located in Harding County, South Dakota, approximately 21 miles south of the MPHU. When we purchased the units in 1995, there were 73 vertical producing wellbores and 38 injection wellbores under HPAI producing approximately 1,906 net Bbls of oil per day. We operate and own an average working interest of 95% in the 32,900 acres comprising the three units. From 2005 to 2008, we re-entered 42 existing vertical wells and drilled horizontal laterals to increase production and sweep efficiency from the three units. Production for the month of December 2007 was 1,945 net Bbls of oil per day compared to an average of 1,162 net Bbls of oil per day for the first half of 2005. We currently plan to drill 5 horizontal extensions of existing wellbores and 25 new horizontal wellbores in the Buffalo Red River units over the next two years. We believe these operations will increase production and sweep efficiency. In 2008, we plan to invest $23 million for drilling in the Buffalo Red River units.
Our properties within the Bakken field in Montana and North Dakota represented 28% of our PV-10 in the Rocky Mountain region as of December 31, 2007 and 35% of our average daily Rocky Mountain region equivalent production for the three months ended December 31, 2007. The Bakken formation or â€ś Bakken shaleâ€ť as it is often called has become one of the most actively drilled unconventional oil resource plays in the United States with approximately 54 rigs drilling in the play as of February 29, 2008, including 48 in North Dakota and 6 in Montana. The Bakken formation is a Devonian-age shale found within the Williston Basin underlying portions of North Dakota and Montana that contains three lithologic members including the upper shale, middle member and lower shale that combined range up to 130 feet thick. The upper and lower shales are highly organic, thermally mature and over pressured and act as both a source and reservoir for the oil. The middle member, which varies in composition from a silty dolomite, to shalely limestone or sand, also serves as a reservoir and locally is thought to be a critical component for commercial production. Recently, the Three Forks-Sanish formation found immediately under the Lower Bakken Shale has emerged as another potential reservoir that could add significant incremental reserves to the play. These reservoir rocks have inherently low porosity and permeability and depend on natural fracturing and artificial fracture stimulation to produce economically. Horizontal drilling and advanced fracture stimulation technologies have enabled commercial production from this historically non-commercial reservoir. Generally, the Bakken formation is found at vertical depths of 9,000 to 10,500 feet and drilled horizontally on 640 or 1,280-acre spacing with single, dual or triple leg horizontal laterals extending 4,500 to 9,000 feet into the formation. These wells are fracture stimulated to maximize recovery and economic returns. The fracture stimulation techniques vary but are evolving to a more common practice of mechanically diverted stimulations using un-cemented liners and packers which appears to improve rates and recoveries.
Montana Bakken . The Montana Bakken field is listed by the Energy Information Administration as the 15 th largest onshore, lower 48 field in the United States ranked by liquid proved reserves. Since drilling our first well in August 2003, we have completed a total of 134 gross (84 net) wells in the field as of December 31, 2007. Our daily average production from these wells was approximately 6,334 net Bbls of oil and 4,814 net Mcf of natural gas during the month of December 2007. The field has been developed exclusively with horizontal drilling and has been substantially drilled on 640-acre spacing. During 2007 we completed 35 gross (25.9 net) wells as we continued to develop and expand the field. Two of these wells successfully demonstrated that development of the field on 320-acre spacing is warranted. These 2 gross (1.3 net) wells were assigned average estimated recoverable reserves of 468 gross MBoe, which exceeded our economic model of 300 MBoe per well. We also successfully demonstrated that 640-acre tri-lateral drilling was an effective technique to expand the economic limits of the field with the completion of 8 gross (6.2 net) tri-lateral wells which were assigned average estimated reserves consistent with our economic model of 250 MBoe per well.
As of December 31, 2007, we held 86,488 gross (64,536 net) undeveloped acres in the Richland County, Montana portion of the Bakken field. We currently have three operated rigs drilling in the field and plan to invest $48.0 million in the drilling of 17 gross (13 net) horizontal Bakken wells in the field during 2008.
North Dakota Bakken. Since drilling our first well in October, 2004, we have completed a total of 54 gross (21 net) horizontal wells in the North Dakota Bakken field as of December 31, 2007. Our daily average production from these 54 wells was approximately 1,351 net Bbls of oil and 820 net Mcf of natural gas during the month of December 2007. Our drilling to date has been primarily exploratory and step-out in nature to evaluate and define areas of economic production for further development on our acreage. As of December 31, 2007, we owned approximately 296,000 net acres preferentially located along the prolific Nesson anticline where fracturing in the Bakken is expected to be enhanced. We accelerated our drilling activity in the field during 2007, completing 38 gross (14.7 net) wells during the year. Twenty seven of these completed wells were located in the central and northern portions of our acreage and were assigned average estimated recoverable reserves of 335 gross MBoe per well, which is in line with our economic model of 315 MBoe per well. During the year, we modified our horizontal drilling and completion design and now drill primarily 1,280-acre spaced, single leg laterals utilizing uncemented liners and packers to mechanically divert the fracture stimulation.
As of December 31, 2007, we held 553,516 gross (271,667 net) undeveloped acres in the North Dakota Bakken field. We currently have six drilling rigs in the field, three of which are operated by Conoco-Phillips through a joint venture. We plan to add three to five operated rigs to the play and invest approximately $105 million in the drilling of 74 gross (20 net) horizontal wells in the North Dakota Bakken field during 2008.
Haley Red River.
Our Haley Red River project is located approximately 12 miles northeast of our Buffalo Red River units located in Harding County, South Dakota. The producing reservoir is the same Red River B dolomite that produces in our Red River units. Here the dolomite occurs at a depth of approximately 9,000 feet and averages 4 to 6 feet thick. The dolomite is widely present and oil saturated and, as in our Red River units, must be drilled horizontally to produce at economic rates. Horizontal wells are typically drilled on 640-acre spacing as single leg laterals and completed open hole without stimulation. As of December 31, 2007 we have completed 4 gross (4 net) horizontal wells with initial rates of up to 419 Boe per well per day. Based on our economic model, we expect to recover approximately 250 MBoe per well. We owned approximately 58,000 net acres as of December 31, 2007 and continue to build acreage in the project. We plan to invest approximately $18 million drilling 9 gross (7.7 net) wells during 2008 in the Haley Red River project.
Big Horn Basin and Other Rockies
Our wells within the Big Horn Basin in northern Wyoming and other areas within the Rocky Mountain region represented 4% of our PV-10 in the Rocky Mountain Region as of December 31, 2007 and 4% of our average daily Rocky Mountain Region equivalent production for the three months ended December 31, 2007. During the three months ended December 31, 2007, we produced an average of 767 net Bbls of oil and 1,060 net Mcf of natural gas per day from our wells in the Big Horn Basin and other areas within the Rocky Mountain region. Our principal property in the Big Horn Basin, the Worland field, produces primarily from the Phosphoria formation. We also have several other projects ongoing in the Rockies including conventional 3D defined Red River and Lodgepole structures in North Dakota and Montana, horizontal Winnipegosis and Fryburg opportunities in North Dakota and the Lewis Shale and Fort Union in Wyoming. We plan to invest $9 million drilling 11 gross (5.1 net) wells in 2008.
Mid-Continent and Gulf Coast Region
Our properties in the Mid-Continent region represented 13% of our PV-10 as of December 31, 2007. During the three months ended December 31, 2007, our average daily production from such properties was 1,613 net Bbls of oil and 20,949 net Mcf of natural gas. Our principal producing properties in this region are located in the Anadarko and Arkoma Basins of Oklahoma, the Michigan Basin and the Illinois Basin.
Our properties within the Anadarko Basin represent 40% of our PV-10 in the Mid-Continent Region as of December 31, 2007 and 52% of our average daily Mid-Continent Region equivalent production for the three months ended December 31, 2007. Our wells within the Anadarko Basin produce from a variety of sands and carbonates in both stratigraphic and structural traps. In 2008, we plan to invest approximately $18 million in the drilling of 14 gross (10.5 net) wells in the Anadarko Basin.
Our properties within the Illinois Basin represent 30% of the PV-10 in the Mid-Continent Region as of December 31, 2007 and 21% of our average daily Mid-Continent Region equivalent production for the three months ended December 31, 2007. Our wells within the Illinois Basin produce primarily crude oil from units comprised of shallow sand formations under water injection. In 2008, we plan to invest approximately $3 million in the drilling of 21 gross (20.6 net) wells in the Illinois Basin.
The Arkoma Woodford play in Atoka, Coal, Hughes and Pittsburg Counties, Oklahoma has emerged into one of the most active unconventional gas resource plays in the country with 34 rigs drilling in the play as of February 29, 2008. We owned approximately 145,000 gross (44,000 net) acres in the Woodford play as of December 31, 2007. Since drilling our first well in February, 2006, we have completed a total of 132 gross (16.1 net) horizontal Woodford wells as of December 31, 2007. The majority of this drilling occurred in 2007 with 110 gross (14.8 net) horizontal wells completed during the year. These Arkoma Woodford wells represent 30% of the PV10 in the Mid-Continent Region as of December 31, 2007 and 26% of our average daily Mid-Continent Region equivalent production for the three months ended December 31, 2007. Our drilling has been primarily focused on exploration and step-out drilling to secure leases and delineate areas of economic production for development. This drilling has been conducted primarily on 640-acre spacing but is expected to be ultimately drilled more densely. Recent testing by other operators in the play indicated it may be economic to drill the Woodford on 80-acre and possibly 40-acre spacing.
We plan to invest approximately $93 million in the drilling of 139 gross (19.9 net) horizontal wells in the Arkoma Woodford during 2008. We currently have four operated rigs in the play and plan to add two more rigs by mid-year. Most of our operated drilling activity in 2008 will focus on development and step-out opportunities.
Michigan Trenton-Black River
Our Trenton-Black River project in and around Hillsdale County, Michigan continues to produce excellent results. Guided by innovative 3D seismic techniques, we have experienced 100% success completing 3 gross (2.5 net) operated wells in the project. Our initial discovery well, the McArthur 1-36 (83% WI) has been assigned gross proved reserves of 824,000 barrels of crude oil equivalent. Our second well, the Anspaugh 1-1 (83% WI) encountered similar type pay and was flow testing at a rate of approximately 200 Bopd on March 3, 2008. Our third well, the Wessel 1-6 (83% WI) was flow testing at a rate of approximately 200 Bopd on March 3, 2008. Testing will continue on the Anspaugh 1-1 and Wessel 1-6 to establish reservoir characteristics and estimated reserves. We have also participated in 2 gross (0.6 net) non-operated Trenton-Black River tests. The Clark 1-36 (21%WI) is testing very low volumes of oil. The Young 10-34 (42%WI) encountered encouraging shows while drilling and is currently waiting on completion. We own approximately 29,000 gross (23,000 net) acres in the play and have shot, processed and interpreted 11 square miles of 3D seismic on the acreage so far. We are currently permitting 5 additional wells and will begin acquisition of 20 square miles of new 3D data in March with plans to acquire additional data later this year.
During 2007 our geoscientists identified two new potential unconventional resource opportunities in the Mid-Continent region. Details of these opportunities have not been disclosed to minimize competition as we are in the process of acquiring leases. As of December 31, 2007 we had acquired 17,000 net acres. We plan to invest approximately $20 million drilling 19 gross (7.1 net) wells on these and other emerging opportunities in the Mid-Continent region in 2008.
Harold G. Hamm has served as Chief Executive Officer (â€śCEOâ€ť) and a director since our inception in 1967 and currently serves as Chairman of the Board. He serves as Chairman of the board of directors of the general partner of Hiland Partners LP, one of our affiliates and a NASDAQ publicly traded midstream master limited partnership, and he serves as Chairman of the board of directors of the general partner of Hiland Holdings GP, LP (â€śHiland Holdingsâ€ť), also publicly traded on NASDAQ. Hiland Holdings owns the general partner interest and units in Hiland Partners LP. Mr. Hamm also serves as a director of Complete Production Services, Inc., an NYSE publicly traded oil and gas service company. Mr. Hamm served as Chairman of the Oklahoma Independent Petroleum Association from June 2005 to June 2007. He was President of the National Stripper Well Association, founder and Chairman of Save Domestic Oil, Inc., and served on the board of the Oklahoma Energy Explorers.
Mark E. Monroe became President and Chief Operating Officer in October 2005 and has served as a member of our Board since November 2001. He was Chief Executive Officer and President of Louis Dreyfus Natural Gas Corp. prior to its merger with Dominion Resources, Inc. in October 2001. After the merger, Mr. Monroe was a consultant and served as a member of the Board of Directors of Unit Corporation, a NYSE publicly traded onshore drilling and oil and gas exploration and production company from October 2003 through October 2005. Prior to the formation of Louis Dreyfus Natural Gas Corp. in 1990, he was Chief Financial Officer of Bogert Oil Company. He has served as Chairman of the Oklahoma Independent Petroleum Association, served on the Domestic Petroleum Council and the National Petroleum Council, and on the boards of the Independent Petroleum Association of America, the Oklahoma Energy Explorers, and the Petroleum Club of Oklahoma City. Mr. Monroe is a Certified Public Accountant and received his Bachelor of Business Administration degree from the University of Texas at Austin.
Jack H. Stark became Senior Vice Presidentâ€”Exploration and a director in May 1998. Prior to joining us as Vice President of Exploration in June 1992, he was the exploration manager for the Western Mid-Continent Region for Pacific Enterprises. From 1978 to 1988, he held various staff and middle management positions with Cities Service Co. and TXO Production Corp. He is a member of the American Association of Petroleum Geologists, Oklahoma Independent Petroleum Association, Rocky Mountain Association of Geologists, Houston Geological Society, and Oklahoma Geological Society. Mr. Stark holds a Masters degree in Geology from Colorado State University. Currently a director, Mr. Stark will not be standing for re-election when his term expires in 2008. Mr. Stark will remain employed as our Senior Vice Presidentâ€”Exploration.
Robert J. Grant has been a director since January 2006. He was an audit partner of Deloitte & Touche LLP and a predecessor firm from 1969 to 2000. He served as partner in charge of the Dallas, Texas office audit department for ten years and a member of the firmâ€™s audit management group for twelve years. He has been a member of the Independent Petroleum Association of America, the American Petroleum Institute, and the Texas Independent Producers and Royalty Owners Association, and currently is a member of the American Institute of Certified Public Accountants and the Texas Society of Certified Public Accountants. Mr. Grant graduated from the University of Detroit with an MBA and BA in accounting.
George S. Littell has been a director since November 2004. He is a partner in the firm of Groppe, Long & Littell, a petroleum consulting firm. Prior to joining the firm in 1975, he held various positions in the natural gas, refining, supply and distribution, and gas liquids departments of Mobil Oil Corporation. Mr. Littell received a Bronze Star for his service as an officer in the US Army, Vietnam in 1968-1969. He is a member of the International Association for Energy Economics, an Eagle Scout, and a director of the Sam Houston Area Council for the Boy Scouts of America. Mr. Littell graduated from Yale University in 1966, earned an MBA degree from New York University, and a law degree from La Salle Extension University.
Lon McCain has been a director since February 2006. He was Vice President, Treasurer, and Chief Financial Officer of Westport Resources Corporation, a publicly traded exploration and production company, from 2001 until the sale of Westport to Kerr McGee Corporation and his retirement in 2004. From 1992 until joining Westport in 2001, Mr. McCain was Senior Vice President and Principal of Petrie Parkman & Co., an investment banking firm specializing in the oil and gas industry. From 1978 until joining Petrie Parkman, Mr. McCain held senior financial management positions with Presidio Oil Company, Petro-Lewis Corporation, and Ceres Capital. He was an Adjunct Professor of Finance at the University of Denver from 1982 through 2005. Mr. McCain currently serves on the board of Crimson Exploration, Inc., a domestic exploration and production company traded on the OTC Bulletin Board, TransZap, Inc., a privately held provider of accounting software, and Cheniere Energy Partners, GP, LLC, the general partner of Cheniere Energy Partners, L.P., a publicly traded partnership. Mr. McCain received a Bachelor of Business Administration and a Masters of Business Administration/Finance from the University of Denver.
H.R. Sanders, Jr. has been a director since November 2001. He served as a board member of Devon Energy Corporation from 1981 through 2000. In addition, he held the position of Executive Vice President for Devon Energy from 1981 until his retirement in 1997. From 1970 to 1981, Mr. Sanders was a Senior Vice President for Republic Bank of Dallas, N.A. with direct responsibility for independent oil, gas, and mining loans. Mr. Sanders is a former member of the Independent Petroleum Association of America, Texas Independent Producers and Royalty Owners Association, and Oklahoma Independent Petroleum Association, and a former director of Triton Energy Corporation. He currently serves on the board of Toreador Resources Corporation, a NASDAQ publicly traded oil and gas company with principal operations in France, Romania, and Turkey.
MANAGEMENT DISCUSSION FROM LATEST 10K
We are engaged in oil and natural gas exploration and exploitation activities in the Rocky Mountain, Mid-Continent and Gulf Coast regions of the United States. Crude oil comprised 77% of our 134.6 MMBoe of estimated proved reserves as of December 31, 2007 and 82% of our 10,621 MBoe of production for the year then ended. We seek to operate wells in which we own an interest, and we operated wells that accounted for 93% of our PV-10 and 79% of our 1,822 gross wells as of December 31, 2007. By controlling operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and fracture stimulation methods used.
Our business strategy has focused on reserve and production growth through exploration and development. For the three-year period ended December 31, 2007, we added 66,087 MBoe of proved reserves through extensions and discoveries, compared to 561 MBoe added through purchases. During this period, our production increased from 7,209 MBoe in 2005 to 10,621 MBoe in 2007. An aspect of our business strategy has been to acquire large undeveloped acreage positions in new or developing resource plays. As of December 31, 2007, we held approximately 1,359,098 gross (733,132 net) undeveloped acres, including 336,000 net acres in the Bakken field in Montana and North Dakota and 70,554 net acres in the Arkoma Woodford and Lewis Shale projects. As an early entrant in new or emerging plays, we expect to acquire undeveloped acreage at a lower cost than those of later entrants into a developing play.
In the year ended December 31, 2007, our oil and gas production increased to 10,621 MBoe (29,099 Boe per day), up 18% from the year ended December 31, 2006. The increase in 2007 production primarily resulted from an increase in production from our Red River units, Bakken field and Arkoma Woodford. Oil and natural gas revenues for the year 2007 increased by 29% to $606.5 million due to increases in volumes and price. Our realized price per Boe increased $6.22 to $58.31 for the year 2007 compared to the year 2006. While we experienced increases in production expense and production tax of a combined total of $23.9 million, or 28%, our increase in combined per unit cost was only 11%, or $1.01 per Boe, due to the increase in sales volumes of 1,405 MBoe, or 16%. Oil sales volumes were 221 MBbls less than oil production for the year ended December 31, 2007 and 21 MBbls less for the same period in 2006, due to an increase in crude oil inventory for pipeline line fill and temporarily stored barrels. Our cash flow from operating activities for the year ended December 31, 2007, was $390.6 million, a decrease of $26.4 million from $417.0 million provided by our operating activities during the comparable 2006 period. The decrease in operating cash flows was mainly due to changes in working capital items including an increase in accounts receivables and an increase in crude oil inventory. During the year ended December 31, 2007, we invested $525.7 million (inclusive of non-cash accruals of $36.4 million) in our capital program primarily in the Red River units, the Bakken field and the Arkoma Woodford play.
How We Evaluate Our Operations
We use a variety of financial and operational measures to assess our performance. Among these measures are (1) volumes of oil and natural gas produced, (2) oil and natural gas prices realized, (3) per unit operating and administrative costs and (4) EBITDAX. The following table contains financial and operational highlights for each of the three years ended December 31, 2007.
Results of Operation
Year ended December 31, 2007 compared to the year ended December 31, 2006
Oil production volumes increased 16% during the year ended December 31, 2007 in comparison to the year ended December 31, 2006. Production increases in the Red River units contributed incremental volumes in excess of 2006 levels of 849 MBbls, and the Bakken field contributed 426 MBbls of incremental production. Initial production commenced in the Bakken field in August 2003 and has increased thereafter, as we have continued exploration and development activities within the Montana and North Dakota portions of the field. Favorable results from our enhanced recovery program and increased density drilling have been the primary contributors to production growth in the Red River units. Gas volumes increased 2,309 MMcf, or 25%, during the year ended December 31, 2007 compared to 2006. The majority of the increase, 1,833 MMcf, was from the Mid-Continent region due to the results of our exploration efforts in the Arkoma Woodford. The Rocky Mountain gas production was up 1,227 MMcf for the year ended December 31, 2007 compared to 2006. The new Hiland Partners Badlands Plant became operational in late August 2007. Through December 31, 2007, we sold 672 MMcf of gas from the Red River units through the new plant. We have invested a minimal amount of capital in our Gulf Coast region resulting in a decline in production in this area of 751 MMcf for the year ended December 31, 2007 compared to 2006.
Oil and Natural Gas Sales. Oil and natural gas sales for the year ended December 31, 2007 were $606.5 million, a 29% increase from sales of $468.6 million for 2006. Our sales volumes increased 1,403 MBoe or 16% over the 2006 volumes due to the continuing success of our enhanced oil recovery and drilling programs. Our realized price per Boe increased $6.22 to $58.32 for the year ended December 31, 2007 from $52.09 for the year ended December 31, 2006. During 2007, the differential between NYMEX calendar month average crude oil prices and our realized crude oil prices narrowed. The differential per barrel for the year ended December 31, 2007 was $8.85 compared to $11.04 for 2006. Factors contributing to the higher differentials in 2006 included Canadian oil imports, increases in production in the Rocky Mountain region, coupled with downstream transportation capacity constraints, refinery downtime in the Rocky Mountain region, and reduced seasonal demand for gasoline. Crude oil differentials were better during 2007 due to additional transportation capacity and efforts by us to move crude oil to more favorable markets.
During the fourth quarter of 2007, we elected not to sell some of our Rocky Mountain area crude oil as price differentials were unacceptable to us and we expected the differentials to improve in early 2008. This resulted in an increase in our crude oil inventory of 125,000 barrels. The price we were offered was adversely affected by seasonal demand. In the fourth quarter of 2007, we shipped some of our Rocky Mountain area crude by railcar to help alleviate this situation. We were able to sell the majority of this oil at improved differentials during January and February 2008.
Derivatives. In July 2007, we entered into fixed-price swap contracts covering 10,000 barrels of oil per day for the period from August 2007 through April 2008. During each month of the contract, we will receive a fixed-price of $72.90 per barrel and will pay to the counterparties the average of the prompt NYMEX crude oil futures contract settlement prices for such month. SFAS No. 133, â€śAccounting for Derivative Instruments and Hedging Activitiesâ€ť requires recognition of all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We elected not to designate our derivatives as cash flow hedges under the provisions of SFAS No. 133. As a result, we mark our derivative instruments to fair value in accordance with the provisions of SFAS No. 133 and recognize the realized and unrealized change in fair value as a gain (loss) on derivative instruments in the statements of income. During the year ended December 31, 2007, we had realized losses on derivatives of $18.2 million and unrealized losses on derivatives of $26.7 million.
Oil and Natural Gas Service Operations. Our oil and natural gas service operations consist primarily of sales of high-pressure air and the treatment and sale of lower quality crude oil, or reclaimed oil. We sold high-pressure air from our Red River units to a third party and recorded revenues of $3.1 million for the years ended December 31, 2007 and 2006. Prices for reclaimed oil sold from our central treating unit were higher for the year ended December 31, 2007 than the comparable 2006 period, and the number of barrels sold increased approximately 68,000 barrels which increased reclaimed oil income by $5.5 million contributing to an overall increase in oil and gas service operations revenue of $5.5 million for the year ended December 31, 2007. Associated oil and natural gas service operations expenses increased $4.5 million to $12.7 million during the year ended December 31, 2007 from $8.2 million during the year ended December 31, 2006 due mainly to an increase in additional barrels treated in 2007 and to an increase of $5.71 per barrel in the costs of purchasing and treating oil for resale compared to the same period in 2006.
Operating Costs and Expenses
Production Expense and Tax . Production expense increased $13.6 million, or 22% during the year ended December 31, 2007 to $76.5 million from $62.9 million during the year ended December 31, 2006. The increase in production expense is commensurate with our increase in production of 18% which is a direct result of new wells being drilled. Additionally, we have experienced a slight increase in service and energy costs. During the year ended December 31, 2007, we participated in the completion of 262 gross (112.1 net) wells. Production expense per Boe increased to $7.35 per Boe for the year ended December 31, 2007 from $6.99 per Boe for the year ended December 31, 2006.
Production taxes increased $10.2 million, or 46% during the year ended December 31, 2007 compared to the year ended December 31, 2006 primarily as a result of higher revenues resulting from increased sales volumes and prices. The majority of the production tax increase was in the Rocky Mountain region due to an increase of 1,261 MBoe sold in the year ended December 31, 2007 compared to the year ended December 31, 2006. Production tax as a percentage of oil and natural gas sales was 5.4% for the year ended December 31, 2007 compared to 4.8% for the year ended December 31, 2006. Production taxes are based on the wellhead values of production and vary by state. Additionally, some states offer exemptions or reduced production tax rates for wells that produce less than a certain quantity of oil or gas and to encourage certain activities, such as horizontal drilling and enhanced recovery projects. In Montana, new horizontal wells qualify for a tax incentive and are taxed at 0.76% during the first 18 months of production. After the 18 month incentive period expires, the tax rate increases to 9.26%. During the year ended December 31, 2007, 32 wells had reached the end of the 18 month incentive period and the tax rate increased from 0.76% to 9.26%. Our overall rate is expected to increase as production tax incentives received for horizontal wells in Montana reach the end of the 18 month incentive period. We are also receiving a 6% tax incentive on horizontal wells drilled in the Arkoma Woodford play in Oklahoma that continues for up to four years or until the revenue from such well exceeds the cost to drill and complete. In North Dakota, we are receiving a 4.5% tax credit on horizontal Bakken wells spud after July 1, 2007 and completed before June 30, 2008. The incentive expires on the earliest to occur of 75,000 barrels of production or eighteen months.
Exploration Expense . Exploration expense consists primarily of dry hole costs and exploratory geological and geophysical costs that are expensed as incurred. Exploration expenses decreased $10.6 million in the year ended December 31, 2007 to $9.2 million due primarily to a decrease in dry hole expense of $9.8 million and a decrease in seismic expense of $0.9 million. The majority of the dry hole costs were in the Mid-Continent region in the 2006 period and in the Mid-Continent and Rocky Mountain regions in the same period in 2007. Dry hole costs were down in 2007 even though exploratory capital expenditures increased by approximately 144% as a result of more successful exploration activities.
Depreciation, Depletion, Amortization and Accretion (DD&A.) Total DD&A increased $28.2 million in 2007 primarily due to an increase in oil and gas DD&A of $27.9 million as a result of increased production and additional properties being added through our drilling program. The DD&A rate for the year ended December 31, 2007 was $9.00 per Boe, including $8.63 per Boe on oil and gas properties and $0.37 per Boe for other equipment and asset retirement obligation accretion, compared to $7.27 per Boe, including $6.91 per Boe for oil and gas properties and $0.36 per Boe for other equipment and asset retirement obligation accretion, for the same period in 2006. The increase in the oil and gas DD&A rate reflects the additional costs incurred to develop proved undeveloped reserves and the higher costs of drilling and completing wells.
Property Impairments. Property impairments increased in the year ended December 31, 2007 by $6.1 million to $17.9 million compared to $11.8 million during the year ended December 31, 2006 reflecting higher amortization of lease costs in our existing fields resulting from further defining likely drilling locations and amortization of new fields. Impairment of non-producing properties increased $7.7 million during the year ended December 31, 2007 to $13.1 million compared to $5.4 million for 2006. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Individually significant non-producing properties are periodically assessed for impairment of value and a loss is recognized at the time of impairment by providing an impairment allowance. Other non-producing properties are amortized on a composite method based on our estimated experience of successful drilling and the average holding period.
Impairment provisions for developed oil and gas properties were approximately $4.7 million for the year ended December 31, 2007 compared to approximately $6.3 million for the year ended December 31, 2006.
General and Administrative Expense. General and administrative expense increased $1.7 million to $32.8 million during the year ended December 31, 2007 from $31.1 million during the comparable period of 2006. General and administrative expense includes non-cash charges for stock-based compensation of $12.8 million and $10.9 million for the years ended December 31, 2007 and 2006, respectively. The increase was due to new grants under the Continental Resources, Inc. 2005 Long-Term Incentive Plan (2005 Plan) during the year ended December 31, 2007. On a volumetric basis, general and administrative expense was $3.15 per Boe for the year ended December 31, 2007 compared to $3.45 per Boe for the year ended December 31, 2006. We have granted stock options and restricted stock to our employees and directors. While we were a private company, the terms of the grants required us to purchase vested options and restricted stock at each employeeâ€™s request. The obligation to purchase the options was eliminated when we became a reporting company under Section 12 of the Exchange Act on May 14, 2007.
Gain on Sale of Assets. Gains on miscellaneous asset sales for the year ended December 31, 2007 were approximately $1.0 million compared to $0.3 million for the year ended December 31, 2006.
Interest Expense. Interest expense increased 14%, or $1.6 million for the year ended December 31, 2007 compared to the year ended December 31, 2006, due to a higher average outstanding debt balance on our credit facility. Our average debt balance was $182.2 million for the year ended December 31, 2007 compared to $156.6 million for the year ended December 31, 2006. The weighted average interest rate on our credit facility was slightly higher at 6.47% for the year ended December 31, 2007 compared to 6.36% for the same period in 2006. At December 31, 2007 our outstanding debt balance was $165.0 million.
Income Taxes. Income taxes for the year ended December 31, 2007 were $268.2 million and included $198.4 million recorded to recognize deferred taxes upon the conversion from a subchapter S corporation to a subchapter C corporation on May 14, 2007 for temporary differences that existed at that date primarily as a result of deducting intangible drilling costs for tax purposes. We provide taxes at a combined federal and state tax rate of approximately 38% after taking into account permanent taxable differences. See Footnote 7 of Notes to Consolidated Financial Statements for more information.
J. Warren Henry - Vice President of Investor Relations
Good morning, everyone and welcome to our second quarter 2008 earnings conference call. Today's call will include forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the company's control. Other than historical facts all company statements included in this conference call, regarding the company's strategy, future operations, future production, estimated capital expenditures, projected costs and other plans and objectives of management are forward-looking information that speaks only as of today's date.
Although, we believe that the plans, intentions and expectations reflected herein as suggested by forward-looking statements are reasonable, there is no assurance that these will be achieved. Actual results may differ materially due to many factors, including changes in oil and natural gas prices, industry conditions, drilling results, uncertainties in estimating reserves, uncertainties in estimating future production, availability of drilling rigs and other services, availability of oil and natural gas transportation capacity, availability of capital resources and other factors. For a more complete statement of risks, please see the company's reports that have been filed or maybe filed with the Securities and Exchange Commission.
The format for this morning's call will be as follows: Chairman and CEO, Harold Hamm, will provide a brief overview of second quarter achievements and our opportunities for growth in the second half. Jack Stark, Senior Vice President of Exploration, will provide greater detail on recent developments, focusing on each of our key operating regions. At that point, we will be ready for Q&A.
Also available at that time will be Mark Monroe, President and COO; and John Hart, VP and Chief Financial Officer. Jeff Hume, our SVP of Operations; is not in his usual role on the call today, because he's traveling out of the country. With that, I would like to turn the call over to Harold.
Harold G. Hamm - Chairman and Chief Executive Officer
Good morning, everyone. Thanks for joining us on the call today. We are very pleased to announce record quarterly financial results for the second quarter of 2008. Total revenues of $303 million were more than double the second quarter of 2007. Crude oil and natural gas sales increased little bit more beating last year's second quarter by 113%. We also saw higher margins as EBITDAX increased 125% over the same period last year.
Net income was $127.3 million or $0.75 per diluted share, compared on pro forma basis to $44.2 million or $0.27 per share in the second quarter last year. The actual reported number of the last year's second quarter was a net loss of $142.5 million, reflecting a tax charge in connection with the conversion to a subchapter C corporation.
Average daily production was 31,623 barrels of oil equivalent per day during the second quarter of 2008, an increase of 5%over the first quarter of 2008 and an increase of 11% over the second quarter of last year. As we noted in the press release this morning, our June production rate was even higher just over 33,000 boepd, showing great acceleration during the quarter and a positive trend in line with our expectation for the remainder of the year.
We benefited from strong commodity prices as our average crude oil price was $118.28 and our average natural gas price was $8.82 per Mcf, for the second quarter of 2008. As we noted on our previous earnings conference call three months ago, our only crude oil has expired on April 30th. So certainly we have captured a full benefit of higher oil and natural gas prices.
We expect to remain unhedged, given the strength of our balance sheet and our outlook on commodity prices. We continue to be bullish on crude oil prices in 2008, 09 and beyond. As many of you know, an Oklahoma company of Sandburg [ph] filed for bankruptcy protection last week. Continental has no significantly receivables due from Sandburg [ph]. We have a small interest in a couple of oils operated by others; it may have sold to Sandburg [ph]. If that is the case, we may have small receivable due probably less than $1000.
Given our strong growth and cash flow performance, we announced in this morning's press release that we are increasing our operated drilling rig count and plant to request more pivotal for a second increase in our 2008 CapEx budget. We've raised our CapEx budget and to $783 million and our current internal cash flow projection is significantly north of that number. Consequently we intend to put additional cash flow to work in terms of more drilling rigs and addition raising.
This increased CapEx budget will enable us to have approximately 35 operated drilling rigs by year end, compared with the earlier expectation of 30. We have also continued to grow and develop acreage positioned in the Bakken, Anadarko, Woodford, Atoka, Marcellus, Rhinestreet, Huron and Haynesville Shale plays.
During the first half of this year, we invested $56 million in land acquisitions and increased our undeveloped acreage positions to approximately $1 million acres in U.S. shale resource plays. Importantly, we still opportunities to add significant additional acreage in these plays. We planned to request Board authorization for an additional $100 million increase in our land budget raising the total land acquisition budget to $178 million for 2008.
This is consistent with the tremendous opportunity as of today for independents to relating the charge in shale resources plays throughout the United States. Continental has obviously been a pioneer and innovator in recognizing productive potential of these plays, and in most cases, we're getting ready to established a strong acreage position. We were an early adopter and avocation of horizontal drilling and advanced compression technologies that are critical to expand reporting [ph] resources shale.
In the Bakken, we've expanded the use of state-the-art, multistage mechanically diverted frac techniques. These have had a significant impact on the productivity of wells drilled in 2008 versus those completed only a year ago. In the Arkoma Woodford, our simultaneous multistage frac treatments appeared to be generating much better results than the previous single well frac stimulations. In addition to the Continental number one of acreage position in the Bakken, we'll establish a strong position in the Arkoma Woodford, the Anadarko Woodford, the Atoka and Western Oklahoma and the Texas Panhandle and the Marcellus, Rhinestreet and Huron shales in Appalachians. We also have a proven presence in the Haynesville Shale play in Louisiana and East Texas.
Continental of late is expanding this scope of shale resource plays. We have redirected our Bakken drilling program to target primarily the Three Forks/Sanish formation, which we'll believe will be significantly incremental to the Bakken play. Most wells today in this play have been completed in higher and middle Bakken formation. Along with the two TFS wells that we have announced, we have drilled seven additional Three Forks/Sanish wells to total depth and expect to have production results on those wells over the next few weeks.
Both in revenues and earnings continues to strengthen in our outlook, additional growth is very positive. We expect the strong rapid production through the second half driven by the deployment of additional operated rigs. We will continue to build our acreage position where we see strong potential for good returns.
At this point, before I turn the call over to Jack, I'd like thank Mark Monroe for key management role. He's played at Continental the last three years, as President and Chief Operating Officer. We looked Mark at retirement late 2005; wanted to capitalize on his experience like the both credit companies. We relied on his experience and leadership, as we prepared and then launched for IPO last year, last year through a transition from private to public company. Now having accomplished goals we have set, Mark is retiring to spend more time with friends and family as black house [ph] and in the Texas Hill Country and we wish him the best.
Although, he will no longer be a full time member of management at Continental, we will continue to rely on his counsel as a full time Board member. Jeff Hume will step up the role of Chief Operating Officer. And so we move forward with a strong proven management team.
And with that I will turn the call over to another key member of our management team Jack Stark, our senior VP of Exploration. Jack.
Jack Stark - Senior Vice President of Exploration
Thank you, Harold. And Good morning everyone. I appreciate your interest in our second quarter results. I'll start out with a couple of brief comments regarding our Red River units.
We continue to drill infield wells for four rigs and are implementing the plan we announced last quarter to accelerate production by expanding the water injection capacity in the Cedar Hills units. As you may recall, we increased the capital budget by $17 million earlier in this year to implement this expansion, which is expected to do increase peak production for the Red River units from 19,000 net barrels equivalent per day to 21,000 net equivalent barrels per day in mid 2009.
During the second quarter, it was determined that two additional water source wells are necessary to achieve the required injection rates, which in turn will delay reaching the peak production rate of 21,000 net barrels equivalent per day until late 2009. It will happen in the Dakota as the late winter storm struck the first week of May; cutting power to significant parts of the South Dakota units from most of month. As a result, production from the units in other South Dakota wells that we include in our other Rockies category, was reduced by approximately 500 barrels equivalent per day for the quarter.
Moving to our and North Dakota Montana Bakken play, I am pleased to announce we made significant progress on several fronts during... in the play during the second quarter. We grew our acreage position to approximately 525,000 net acres and we remain the largest leasehold owner in the play. We also identified and plan to close on another 36,000 net acres in North Dakota during the third quarter. We had a two operator rigs and remained most active operator in play with 15 rigs total; this includes twelve rigs operated by Continental and three operated by Conoco-Philips our AMI partner.
Net completions were up 56% over the first quarter of 2008, reflecting the growing rig count that we have. To the second quarter completions were exceptional Three Forks producers as Harold mentioned. We continue to see improved results through better completion technology and have begun testing the merits of 10 to 12-stage fracs per well, instead of our typical 8 to 9-stage cracks. And going forward we've planed at four rigs to the play during the second half of 2008, bringing our total rig count to 19 going into the next year. This would include 16 operated by Continental and three operated Conoco-Phillips. We expect to of these rigs to begin drilling in next 30 days.
In the Montana Bakken, we continue to have success with the 320-acre infield and 640 trilateral drilling, supporting the potential for significant unbuilt reserve potential on our HVP [ph] acreage and our 79,000 net acres went to that leasehold.
Since beginning of the tri-lateral and infield drilling program in late 2006, we have drilled 17 gross, 13 net tri-lateral wells and 8 gross 6 net, 320-acre infield wells with average 7-day initial rates of 365 barrels equivalent per day and 395 barrels equivalent a day, respectively. We currently have three rigs drilling in the Montana Bakken and expect to maintain that rig count for the foreseeable future.
As you may have noticed in the press release, production in the Montana Bakken was down approximately 5% in the first quarter '08. This reflects to combination of lower rig count, normal production declines and occasional interruptions in production from shutting wells in while adjacent field wells are being stimulated.
To the increase ultimate recovery of oil from the reservoir, we are planning those CO2 open pumps and water injection pilot ER projects. We're currently in a design to modeling stages and have applied for a grant from the DoE for these projects. But no, we plan to drill our first Three Forks/Sanish test in the Northwest portion of undeveloped Montana acreage block in the early fourth quarter. We suspect the Three Forks/Sanish will prove to be a more effective reservoir than a traditional middle Bakken in this area.
In North Dakota, our second quarter drilling and completion activity increased significantly over the first quarter 2008 and is expected to increase throughout the year as we add up to four rigs North Dakota by year end. During the second quarter, we completed 33 gross, 8.7 net wells as compared to 13 gross, 3.7 net wells, completed during the first quarter, an increase of 135% on a net-well basis.
Initial production rates in our second quarter, of North Dakota Bakken wells also improved averaging 513 barrels equivalent per day, up 13% over the average first quarter of 2008 initial rates of 455 barrels equivalent per day. Usually these improved results directly reflect moving to single lateral wells, multistage mechanically diverted fracs, utilizing open-hole liners in well packers. As a result, we have increased the average estimated ultimate recoveries in our economic model from 315,000 barrels equivalent per well to 400,000 barrels equivalent per well, on a gross basis.
During the quarter, we completed Two, Three Forks/Sanish wells, the Bice 1-29, in which we have 44% working interest and the Mathistad 1-35, in which we have 40% working interest. As previously reported the Mathistad produced an average rate of 1095 barrels equivalent per day during the first five days. But to be consistent with our typical reporting, the Mathistad 7-day average IP was actually 1260 barrels equivalent per day and during its first 20 days online, the Mathistad produced an impressive total of 17,700 barrels of oil equivalent.
Because of these encouraging results and the potential for the Three Forks/Sanish to add significant incremental reserves to the play. As Harold mentioned, we have adjusted the drilling target for most of our recent wells in North Dakota to the Three Forks/Sanish. We currently have seven gross, three nets, Three Forks/Sanish wells in various stages of completion. And nine gross 3.4 net wells... Three Forks/Sanish wells that are drilling.
In other Rocket activity, we've drilled two verticals wells on our East Lustre project in Roosevelt County, Montana targeting three redefined Lodgepole reefs. And as predicted, we did penetrate Lodgepole risk, but the rock was tight and these wells were ploughed. We have no plans to drill additional wells in this project at this time.
In our Haley Red river project, we completed two gross 1.8 net force on our Red River wells, during the second quarter as part of 13-5H and the Merle Johnson 11-4H. Results for these wells so far have been disappointing with higher than expected water cuts, but we believe the water production is related to fall some fracture zones and kind of log drilling in our designing plans to increase oil production by isolating the suspected water production... producing zones from the well board.
We remain optimistic regarding the potential of the play and are currently shedding 95 square miles of 3D seismic to make to further evaluate our acreage. We are preparing to build our... to test our third Haley Red River well this year, the Povchesky 1-1 [ph] and are drilling a fourth well to build more grants [ph] at this time.
In Richland County, Montana we had a significant vertical Red River discovery on our Montana Bakken acreage. The Smart 123 [ph] in which were 89% working interest floated a seven day average initial rate of 442 barrels of oil equivalent per day from 32 feet of perforations in the Red River D Zone. This is the second successful vertical Red River well drilled on our 33 square mile typical 3D survey, utilizing proprietary processing and interpretation techniques. Our first well the year ago 19 [ph] was completed last year. We are very encouraged by the technical and economic success of these two wells and it demonstrates the potential that exists from conventional reservoirs underlying our Bakken acreage in Montana, North Dakota.
To further identify these Red River opportunities under our 153,000 net acres in Montana Bakken, we have a licensed, reprocessed then interpreted a total of 88 square miles of 3D data and have another 120 square miles of data being processed. To-date we have identified 19 gross, 11 net prospective Red River locations and are drilling the first of the four locations we plan to drill in the second half for the year.
Moving on to the mid-continent, the drilling program on our 46,000 net acres in the Arkoma Woodford continues to provide good results. During the second quarter, we completed 18 gross, 3.3 net wells. We continue to see efficiencies in our operations, particularly with regard to drilling days which are consistently averaging around 30 days per bud, which is 40% below the last year. Of note are the results of our recent two well simul-frac of the Ireland 215 and Ireland 315 wells in our Ashland project. These two-wells float at 7-day average initial rates of 6.2 and 7.2 million cubic feet per day respectively. The wells were drilled parallel to each other approximately 1320 feet apart, 4400 feet in length and were stimulated with 9 stage fracs. The nearby Ireland 415 was fracture stimulated immediately following the Ireland 215 and 315 and slowed at an average 7-day initial rate of 1.7 million cubic feet per day.
We had 21% working interest in each of these wells. We believe by fracking the well simultaneously or near simultaneously we are more effectively fracturing a rock due to better pressure consignment. We adjusted our drilling schedule to accommodate simul-fracking as often as possible and there are several planned in the third quarter.
We've recently completed shooting 18 square miles of proprietary 3D data, in our Salt Creek project and expect processing to be completed by late August. To cost effectively expand this 3D coverage in Salt Creek, we also licensed in additional 8 square miles of non-proprietary data. Combined this data, we used to evaluate and guide future development of the Salt Creek area. Then to guide development of our East McAlester project, we are in a process of acquiring 55 square miles of 3D data as part of our larger group shoot. We expect delivery of this data in the late fourth quarter or really first quarter next year. We currently have five rigs drilling in the Arkoma Woodford and plan to add up to two additional rigs in the play, the first in August and the second probably in October.
Moving, in second quarter we reported that the Marriott 1-18, located in Blaine County, Okalahoma produced at a 7-day average initial rate of 2.5 million cubic feet per day and 45 barrels per day from the Springer wood sand. We had another significant discovery during the second quarter in our Wolsey 2-9, also located in Blaine County. The Wolsey 2-9 completed flowing at a 7-day average initial rate of 5.6 million a day and a 142 barrels account received from the Springer Cunningham sand. We have 85% working interest in this well. Both wells are unstimulated natural completions and appear to be outstanding producers.
In our Michigan Trenton/Black River, project we drilled two gross 1.7 net wells during the second quarter. Both were producers including the Boardman 1-1and the Wessel 2-6A. The Boardman 1-1 is currently flowing at 150 barrels a day under state restricted test rates and will increase to 200 barrels per day and really August is part of the testing process.
The Wessel 2-6A is also undergoing state testing, and is currently flowing 110 barrels of oil per day under state restricted rates. We expect to increase the test rates to 150 barrels a day and 200 per barrels per day in the next 30 to 60 days if gas oil ratios warrant.
To-date we have drilled 10 gross 6.8 net Trenton/Black River wells with nine producers and one well temporarily abandoned. Five of the producers are capable of producing in access of states restricted reliable rates of 110 barrels a day. The state has conducted hearings to consider increasing their levels with these wells and we expect to have ruling from the state in early October. The Trenton/Black River is a 3D seismic driven play and we currently have seismic coverage of approximately 15% of our 48,000 net acres.
We will complete acquisition of another 20 square miles in our Chicago and Ohio [ph] 3D shoot by mid August and expect to acquire another 5 square miles on our Dog Lake project later in the year. Although it's difficult to predict just how many opportunities will be identified on the new data, it seems reasonable to expect that we will commence a multi-well drilling program, during the fourth quarter this year.
In other emerging shale plays, as you knowledge, we are one of the more active resource players in the industry and we have leasing efforts ongoing in several emerging plays. And have begun or will begin drilling on this acreage before year end. In the rapidly expanding Haynesville shale play, we'll now control approximately 17,000 net acres in the Northern Louisiana area and continue to add acreage to our position. We expect to spud our first well in the fourth quarter. In the Anadarko Basin in Western Okalahoma, we now control approximately 94,000 net acres that we consider as prospective for the Woodford and plan to spud our first tracery towards test in August.
We also own approximately 32,000 net acres in the Atoka fair away and are drilling our first horizontal test this time. A pilot hole was drilled in course of the Atoka were taken for further evaluation of the reservoir. And in the Appalachians, we now own 88,000 net acres in the Lower Huron, Rhinestreet Marcellus plays and continue to build on our position. The bulk for this acreage is located West Virginia, Ohio, and New York where the shales have at found debts of 1000 to 5400 feet. We're currently drilling our first-four wells targeting Rhinestreet, then Lower Huron shales in Southeast, Ohio.
And with that, I'll turn it back to Harold.