Our properties in the Rocky Mountain region represented 84% of our PV-10 as of December 31, 2006. During the three months ended December 31, 2006, our average production from such properties was 20,092 net Bbls of oil and 7,572 net Mcf of natural gas per day. Our principal producing properties in this region are in the Red River units, the Bakken field and the Big Horn Basin. Additionally, we have prospective acreage for the Lewis Shale in southern Wyoming, another unconventional resource play in the Rocky Mountain Region.
For the six month period ended October 31, 2006, we ranked second among all oil companies in terms of gross operated crude oil production within the Rocky Mountain states of Montana, North Dakota, South Dakota and Wyoming.
Red River Units
Our Red River units represented 59% of our PV-10 in the Rocky Mountain Region as of December 31, 2006 and 55% of our average daily Rocky Mountain Region equivalent production for the three months ended December 31, 2006. 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 “B” 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 2004 as the 23rd largest field in the United States ranked by liquids 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, 2006, we had drilled 154 horizontal wells within this 49,700-acre unit, with 90 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, 2006, this 7,800-acre unit contained ten horizontal producing wells and four HPAI 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 and water injection, production from the Cedar Hills units increased to 9,561 net Boe per day in December 2006 from 2,185 net Boe per day in November 2003. As of December 31, 2006, the average density in the Cedar Hill units was approximately one producing wellbore each 575 acres. We currently plan to drill 83 new horizontal wellbores and 9 horizontal extensions of existing wellbores in the Cedar Hills units during the next two to three years, increasing the density of both the producing and injection wellbores. We believe this operation will increase production and sweep efficiency. Production in the two units, as projected by our proved reserves report for the year ended December 31, 2006, is expected to peak in late 2008 at approximately 15,400 net Boe per day. In 2007, we plan to invest approximately $95 million drilling in the Cedar Hills units.
On November 8, 2005, we entered into a contract with Hiland Partners, LP (“Hiland”) for the processing and treatment of gas produced from the CHNU and CHWU. Under the terms of the contract we agree to deliver low pressure gas to Hiland for compression, treatment and processing at a facility to be constructed by Hiland. Nitrogen and carbon dioxide must be removed from the gas production associated with the increasing oil production from CHNU and CHWU 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. If the average composite volume of carbon dioxide is less than 10%, we pay an additional $0.10 per Mcf treating fee, otherwise the treating fee is $0.20 per Mcf. The plant is currently expected to be operational in May 2007.
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 33 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 1,105 net Bbls of oil and 184 net Mcf of natural gas per day in December 2006. We currently plan to drill 16 new horizontal wellbores and seven horizontal extensions of existing wellbores during the next two years, increasing the density of both producing and injection wellbores. We believe these operations will increase production and sweep efficiency. In 2007, we plan to invest approximately $15 million for drilling in MPHU.
Buffalo Red River Units. The 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. During 2005 and 2006, we re-entered 23 existing vertical wells and drilled horizontal laterals to increase production and sweep efficiency. Production for the month of December 2006 was 1,443 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 20 horizontal extensions of existing wellbores and 28 new horizontal wellbores in the Buffalo Red River units over the next three years. We believe these operations will increase production and sweep efficiency. In 2007, we plan to invest $16 million for drilling in the Buffalo Red River units.
Bakken Field
Our properties within the Bakken field in Montana and North Dakota represented 33% of our PV-10 in the Rocky Mountain Region as of December 31, 2006 and 37% of our average daily Rocky Mountain Region equivalent production for the three months ended December 31, 2006. The Bakken formation is widespread and relatively uniform in development throughout the Montana and North Dakota portions of the Williston Basin. The Bakken formation consists of three lithologic members—the upper shale, middle member and locally a lower shale. The shales are highly organic, thermally mature and overpressured and act as both a source and reservoir for the oil. The middle member is also productive locally and varies in composition from a silty dolomite, to shalely limestone or sand across the Williston Basin. Horizontal drilling and advanced fracture stimulation technologies have enabled commercial recovery from this historically non-commercial reservoir. Generally, the Bakken formation is drilled horizontally on 1,280-acre units to vertical depths ranging from 9,000 to 10,500 feet with opposing horizontal laterals each extending approximately 4,500 feet, for a total drilled footage of approximately 18,000 to 21,000 feet. The wells are typically fracture stimulated to maximize recovery and economic returns.
Richland County, Montana. Commercial production data available on wells completed after February 2001 in the Bakken formation by various operators in Richland County, Montana report 433 productive wells with cumulative production as of October 2006 of 43 MMBbls of oil and 25 Bcf of natural gas. Daily production from these wells for the month of October 2006 was approximately 52 MBbls of oil and 36 MMcf of natural gas.
Our initial well in the Richland County, Montana portion of the Bakken field, the Goss #34-26 completed in August 2003, has produced approximately 218,000 gross Bbls of oil and 100,000 gross Mcf of natural gas as of December 31, 2006 and averaged 75 gross Bbls of oil and 52 gross Mcf of natural gas per day during the month of December 2006. Our average daily rate from 100 gross (59 net) wells in this field was approximately 6,737 net Bbls of oil and 4,372 net Mcf of natural gas during the month of December 2006. Substantially all of our wells have been horizontally drilled on 1,280-acre units within the middle dolomite member, which is well developed under our leasehold in Richland County. In 2006, we drilled several second horizontal wells in 1,280-acre units and plan to drill a horizontal well in 2007 to test the incremental reserves of a third well in a 1,280-acre unit.
As of December 31, 2006, we held 104,000 gross (79,000 net) undeveloped acres in the Richland County, Montana portion of the Bakken field with 39 proved undeveloped and 58 additional scheduled drilling locations. We currently have five operated drilling rigs in this part of the field and plan to invest $57 million in the drilling of 21 horizontal Bakken wells in Montana during 2007.
North Dakota Bakken. Encouraged by the results in Richland County, Montana, operators have begun drilling horizontal wells in the Bakken formation in North Dakota. Since this play is in the early stages of development, results are limited but encouraging. As of December 31, 2006, production data had been reported to the North Dakota Oil and Gas Commission on 86 horizontal North Dakota Bakken wells completed since March 2004. The initial production rates on the 86 wells ranged up to 1,355 Boe per day and averaged 192 Boe per day per well. Cumulative and daily production from the 86 wells as of December 31, 2006 was 2.0 MMBoe and 5,863 Boe, respectively.
As in Richland County, Montana, the upper Bakken shale in western North Dakota is highly organic, thermally mature and over-pressured. Within our North Dakota acreage, the formation is found at vertical depths ranging from 8,500 to 11,000 feet. In North Dakota, the Bakken formation gross interval ranges up to 130 feet compared to about 30 feet in Richland County, Montana. Similarly, the upper Bakken shale thickness ranges up to 20 feet in North Dakota compared to about 7 feet in Richland County, Montana. The middle dolomite member of the Bakken formation in the southern portion of our North Dakota acreage is similar to that present in the Richland County, Montana producing area. Moving north on our acreage, the middle dolomite member increases in thickness but diminishes in reservoir quality. We believe the loss of quality of the middle member is offset by the increasing thickness of the upper and lower shales as one moves north and the strategic position of our acreage along the axis of the Nesson anticline.
In March 2004, we served as contract operator on a well completed in the Bakken formation near the northern border of our acreage. We drilled a 4,376-foot single horizontal lateral within the middle dolomite member of the Bakken Shale in an abandoned dry hole. The well has produced approximately 58,000 gross Boe through December 31, 2006 and is estimated to ultimately produce approximately 219,000 gross Boe. The well, initially owned by our principal shareholder and his family, was acquired by us in August 2005.
In October 2004, we completed a well in the Bakken formation on the extreme southeastern edge of our North Dakota acreage in a well originally planned as a shallower Lodgepole formation test. This well is over 120 miles south of our initial test. The well was unsuccessful in the Lodgepole formation and was deepened to test the Bakken formation at this location. The middle dolomite member significantly thins along the southern edge of our acreage and, in this test well, the middle member was essentially not present. The well has produced approximately 17,000 gross Boe through December 31, 2006 from a single 6,199-foot horizontal lateral and is estimated ultimately to produce approximately 32,000 gross Boe.
In 2005, we participated with a small working interest in two non-operated Bakken formation tests in North Dakota. One is expected to ultimately produce about 12,000 gross Boe and the other, 121,000 gross Boe.
In 2006, we participated in 9 gross (4.8 net) operated and 10 gross (1.6 net) non-operated horizontal Bakken Shale wells in North Dakota. Of these, 16 gross (5.2 net) have been completed as producers and the remaining are awaiting completion. Initial production rates for the 16 producing wells ranged from 182 Boe to 1,355 Boe per day.
In June 2006, we entered into an agreement with ConocoPhillips Company to form an area of mutual interest (“AMI”) within Dunn, McKenzie, Mountrail and Williams Counties, North Dakota and jointly drill wells to test the Bakken formation. Within the AMI, we own approximately 97,000 net acres. Initial wells proposed under the agreement establish exploration blocks covering the 1,280-acre spacing unit for the initial well and two adjacent 1,280-acre spacing units. Each party has the right to acquire from the other party an undivided 50% interest in the exploration block acreage owned by the other party at $500 per net acre. ConocoPhillips Company has proposed and we have agreed to participate in the initial three wells to be drilled under the agreement. As of April 12, 2007, ConocoPhillips Company had three drilling rigs operating within the AMI and we had two drilling rigs operating on our North Dakota Bakken acreage outside the AMI.
As of December 31, 2006, we held 478,000 gross (263,000 net) undeveloped acres in contiguous counties in North Dakota across the state border from the Richland County, Montana drilling activity. During 2007, we plan to invest approximately $71 million in the drilling of 37 horizontal Bakken wells on our acreage in North Dakota.
Big Horn Basin and Other
Our wells within the Big Horn Basin in northern Wyoming and other areas within the Rocky Mountain region represented 8% of our PV-10 in the Rocky Mountain Region as of December 31, 2006 and 8% of our average daily Rocky Mountain Region equivalent production for the three months ended December 31, 2006. During the three months ended December 31, 2006, we produced an average of 1,277 net Bbls of oil and 2,638 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 have 41 additional proved undeveloped drilling locations in the Worland field. During 2007, we plan to invest approximately $2 million in the drilling of 4 wells in this region.
Lewis Shale Project
As of December 31, 2006, we owned approximately 123,000 gross (31,000 net) undeveloped acres in the Washakie Basin in Carbon and Sweetwater Counties, Wyoming. Our objective is the Lewis Shale, a shale formation up to 1,500 feet thick with thin interbedded and discontinuous siltstones and sandstones. Underlying our acreage, the Lewis Shale is over-pressured, fractured and gas charged with the potential to develop into an economic unconventional gas resource play. Previous drilling in the area has encountered gas from the thick,fractured shale, but only the thin, isolated sands within the shale have been produced. As of October 2006, the Triton field, located in the center of our acreage block, has produced a total of 6.7 Bcf of natural gas from 5 wells with up to 40 feet of perforations in thin sands within the Lewis Shale. We plan to produce the entire Lewis Shale sequence with the expectation that ultimate recoveries per well will be greater than previous results.
During 2006, we participated in the drilling of 4 gross (1.3 net) productive wells in the Lewis Shale project. The first well, the CEPO Federal 20-17, was completed in September 2006, has produced approximately 600,000 Mcf of natural gas through March 2007 and produced at an average rate of approximately 4,300 Mcf of natural gas per day in March 2007. The well is producing from the first of two productive sands encountered in the well. The second sand tested at rates of 2,000 Mcf of natural gas per day with flowing pressures of 1,000 pounds per square inch and will be produced at a later date. The second well, the Neptune 13-11, began producing at a rate of approximately 1,200 Mcf of natural gas per day after fracture stimulation in August 2006. The well has produced approximately 173,000 Mcf of natural gas through March 2007 and produced at an average rate of approximately 320 Mcf of natural gas per day in March 2007. The third well, the Barricade 44-1, was completed in December 2006 and produced at an average rate of approximately 320 Mcf of natural gas per day in March 2007. The fourth well, the CEPO Lewis 23-17, is currently being completed and produced at a rate of approximately 4,450 Mcf of natural gas per day on April 12, 2007. We participated in the drilling of a fifth well in the project in 2007 which was abandoned during drilling operations due to mechanical problems. During 2007, we plan to invest approximately $1 million in the drilling of two Lewis Shale wells.