CALGARY, Oct. 30, 2012 /CNW/ - Legacy Oil + Gas Inc. ("Legacy" or the "Company")(TSX: LEG) is pleased to provide an operational update for its activities in the Williston Basin and most recent Turner Valley drilling success.
In the third quarter of 2012, the Company drilled 46 (36.2 net) wells all targeting light oil, with a 100 percent success rate. This total included 18 (14.6 net) horizontal wells in its Spearfish play at Pierson, Manitoba and Bottineau County, North Dakota. The Company continues to be on track to meet its full year production guidance.
At Pierson, Manitoba, the Company continues to deliver excellent production results in the Spearfish compared to both the previous operator's drilling and the type curve used in the 2011 year-end independent engineering report. Legacy has achieved these rates while constraining production to maximize ultimate recovery. All recent wells carry significant fluid levels, with some wells having fluid just below surface. The Company estimates that initial productive capability of a number of these Pierson wells would range from 120 to 280 Boe per day; well in excess of the currently constrained rates. The Company believes these achievements will lead to superior long term performance, higher per well reserve bookings plus additional locations booked.
Legacy has continued to improve capital efficiencies in the Spearfish play in Pierson. Through a combination of reduced day rates for both drilling and stimulation services and improved operations execution, wells drilled in Pierson over the first nine months of 2012 have drill, complete, equip and tie-in costs of less than $1.5 million. Wells drilled in the most recent quarter have all-in capital costs between $1.2 million to $1.3 million. Average number of drilling days has been reduced from 10 days in 2011 to 6 to 7 days in the most recent quarter. This excellent performance has been on "long" horizontal wells which are typically drilled across an entire section. Operating costs continue to be reduced as additional wells are tied-in to the central oil battery. Current operating costs in Pierson are down 35 percent in the third quarter of 2012 from the third quarter of 2011.
At Bottineau County, North Dakota, no new operated wells were brought on production in the quarter however the Company anticipates having 6 (4.5 net) additional wells on production in the fourth quarter of 2012. The first two wells of this recent program have come on production at an average production rate of more than 150 Boe per day per well. Legacy has achieved these rates while constraining production to maximize ultimate recovery as all wells carry fluid levels.
Legacy has also continued to improve capital efficiencies in the Spearfish play in Bottineau County. Through a combination of reduced day rates for both drilling and stimulation services and improved operations execution, wells drilled in Bottineau County in the last half of 2012 have drill, complete, equip and tie-in costs of less than $1.6 million. Wells drilled in the most recent quarter have all-in capital costs between $1.4 million to $1.5 million on an all-in basis. Average number of drilling days has been reduced from 12 days in 2011 to 7 to 8 days in the most recent quarter. Similar to Pierson, this excellent performance has been on "long" horizontal wells that are typically drilled across an entire section.
The total Spearfish play development drilling inventory of 440 net potential locations (88 percent unbooked) is based on eight wells per section. Based on other operators' results in the play, Legacy's location count could increase by 50 percent through downspacing. In addition, the Company is evaluating the waterflood potential in the play and anticipates recovery factors of up to 14 percent, based on analogous pools.
At Star Valley, Legacy has applied its leading fracture stimulation design developed in Heward to this area with good success. Legacy brought 11 (7.8 net) wells on production since the start of the third quarter of 2012 and these wells have average 30 day initial rates of 200 Boe per day per well. As previously disclosed, the Company believes the Bakken play boundaries have expanded and has increased its drilling location inventory to more than 50 net wells in Star Valley.
At Taylorton, the Company has continued to observe improved waterflood response in the original pilot area. The 91/12-29 horizontal well has seen its oil production rate increase to nearly 50 Bbl per day, with a corresponding increase in fluid rate, fluid level and reduction in water cut. The pilot was expanded into section 28 in July 2012. Continuous improvement of drilling and completion practices has resulted in a reduction in capital costs in Taylorton, with drilling, completion, equip and tie-in costs for recent wells being 15 percent less than historical costs.
At Heward, the pilot waterflood project initiated in December 2011 continues to demonstrate waterflood response as the oil production rate in eight offsetting wells has increased since the commencement of the pilot. Individual well oil production rates are up 50 to 500 percent from prior to initiation of the waterflood. Plans are underway for expansion of the pilot waterflood project in the latter part of 2012.
Legacy has remained active drilling conventional Mississippian horizontal wells throughout its SE Saskatchewan properties. These wells typically cost approximately $1 million to drill, complete, equip and tie-in as they generally are not fracture stimulated and have excellent rates of return and quick payouts.
At Alameda/Steelman, Legacy's recent wells targeting the Frobisher and Midale have achieved tremendous production results. Five of the wells drilled in the third quarter of 2012 have average 30 day initial production rates of 440 Boe per day per well. The majority of these wells carry high fluid levels. The Company has identified a significant number of follow-up locations in both areas.
At Turner Valley, Legacy has continued to evolve drilling and completion practices to optimize both production rate and capital costs. Drilling to-date has targeted infill locations testing areas of varying water cut, reservoir pressure, proximity to water injection and three different stratigraphic horizons. As previously disclosed, horizontal wells in Turner Valley have typically come on production with a high water cut and as load fluid is recovered, the water cuts decrease and the oil rates increase. This phenomenon has been observed in the 22 previously drilled unfrac'd horizontal wells and in the wells drilled by Legacy. In turn, the Company expects the Turner Valley horizontal wells to produce at stable, low decline rates based on the production profile demonstrated by both the previously drilled and Legacy drilled wells.
The Hartell #6 well and Boyd #1 well continue to deliver excellent performance. Hartell #6 has produced nearly 50 MBoe in 11 months of production and Boyd #1 has produced nearly 40 MBoe in six months of production and has averaged 250 Boe per day for the last four months. Both wells did not reach peak rates until considerably after first production date. Production has continued to trend higher on the remainder of the Turner Valley wells as artificial lift optimization has taken place, production run times have improved and recovery of load fluid has resumed.
Legacy's most recent horizontal well at Herriman #5 is an example of the progression of positive production results as the Turner Valley completion practices are further refined. The well has increased from 100 Boe per day to over 300 Boe per day in its first weeks of production, while still producing at approximately 70 percent water cut and carrying a high fluid level. Offset producers have water cuts between 16 and 45 percent and it is anticipated Herriman #5 will continue to trend lower in water cut and higher in oil rate.
The Company has made great strides in reducing capital costs since the end of 2011/early 2012. With an ongoing program, refinement of mud programs and bit selection, Legacy continues to improve its drilling performance in Turner Valley, leading to decreased capital costs. The recent dual lateral horizontal wells have cost approximately $6 million for drilling, completion, equip and tie-in, driving much improved capital efficiencies. Legacy believes there is potential for additional capital cost reductions on future wells.
Operational momentum that began in late 2011 has continued through 2012. Legacy continues to deliver solid production growth with improved capital efficiencies from its extensive inventory of 1,200 net light oil development locations and waterflood assets. The Company plans to release its third quarter 2012 results on November 8, 2012 and has scheduled a conference call to discuss the results on Friday, November 9, 2012 at 9:00 a.m. (MDT) (11:00 a.m. EDT).
Legacy is a uniquely positioned, technically driven intermediate oil and natural gas company with a proven management team committed to aggressive, cost-effective growth of light oil reserves and production in large hydrocarbon in-place assets and resource plays. Legacy's common shares trade on the TSX under the symbol LEG.
Forward-Looking Information - This press release contains forward-looking statements. More particularly, this press release contains forward-looking statements concerning: (i) the Company being on track to meet its full year production guidance, (ii) the initial productive capability of wells drilled at Pierson, (iii) the Company's belief that the recent performance of wells at Pierson will lead to superior long term performance and higher per well reserves bookings, (iv) the number of identified drilling locations at Pierson, (v) anticipated improvements in operating costs at Pierson, (vi) the initial productive capability of wells drilled at Bottineau County, (vii) the Company's belief that the recent performance of wells at Bottineau County will lead to superior long term performance and higher per well reserves bookings, (viii) the number of identified drilling locations at Bottineau County, (ix) the total number of potential drilling locations in the Company's Spearfish play, * anticipated recovery factors in the Spearfish play, (xi) the Company's plans to expand its waterflood project at Taylorton and the potential impact on reserves bookings and decline rates, (xii) the number of identified drilling locations at Star Valley, and (xiii) the Company's expectations as to the production characteristics of horizontal wells at Turner Valley.
The forward-looking statements contained in this press release are based on certain key expectations and assumptions made by Legacy, including expectations and assumptions concerning: (i) the success of future drilling and development activities, (ii) the performance of existing wells, (iii) the performance of new wells, (iv) the availability and performance of facilities, (v) the geological characteristics of Legacy's properties, (vi) the successful application of drilling, completion and seismic technology, (vii) prevailing weather conditions, commodity prices, royalty regimes and exchange rates, (viii) the application of regulatory and licensing requirements and (ix) the availability of capital, labour and services.
Although Legacy believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because Legacy can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (which include operational risks in development, exploration and production; risk that there will be delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses; the uncertainty of well performance; and health, safety and environmental risks), uncertainty as to weather conditions, uncertainty as to the availability of labour and services, commodity price and exchange rate fluctuations and changes to existing laws and regulations. These and other risks are set out in more detail in Legacy's Annual Information Form which has been filed on SEDAR and can be accessed at www.sedar.com.
The forward-looking statements contained in this press release are made as of the date hereof and Legacy undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
Meaning of Boe: When used in this press release, Boe means a barrel of oil equivalent on the basis of 1 Boe to 6 thousand cubic feet of natural gas. Boe per day means a barrel of oil equivalent per day. Boe's may be misleading, particularly if used in isolation. A Boe conversion ratio of 1 Boe for 6 thousand cubic feet of natural gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
SOURCE: Legacy Oil + Gas Inc.
For further information:
Trent J. Yanko, P.Eng.
President + CEO
Legacy Oil + Gas Inc.
4400, 525 - 8th Avenue S.W.
Calgary, AB T2P 1G1
Matt Janisch, P.Eng.
Vice-President, Finance + CFO
Legacy Oil + Gas Inc.
4400, 525 - 8th Avenue S.W.
Calgary, AB T2P 1G1