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Questerre Energy Corporation
Beaver River Gas Field
Beaver River Field (the "Field") is located approximately 160 km northwest of Fort Nelson, on the border of British Columbia and the Yukon. Production from the field benefits from extensive infrastructure including processing facilities, a local gathering system and a tie-in to the Spectra Energy pipeline. Questerre currently holds a 50% interest in over 23,000 acres in this area. The Beaver River natural gas field is expressed on surface as an anticline approximately 16 km long and 4 km wide.
There are multiple zones of interest including three interbedded shale, siltstone and sandstone intervals known as the Mattson, Besa River and Golata at a depth of 1,300 – 3,300m and the Nahanni, a hydrothermally dolomitized carbonate sequence at a depth of approximately 3,300m.
Mattson/Besa River/Golata Formations
Questerre, in conjunction with its partner conducted a work program to evaluate the shallow Mattson/Besa River horizon over the last four years. This included re-entering three existing wells and stimulating two in addition to drilling two new wells, A-7 and B-3 since the fall of 2005. Different stimulation techniques including energized carbon dioxide and nitrogen foam were evaluated and results to date have been mixed.
The A-2 well has produced over 2 Bcf and continues to produce at rates in excess of 1 mmcf/d from the middle shale interval. By comparison, there were no commercial rates from any interval in the B-3 well. The A-7 well has produced from the uppermost interval at rates of approximately 0.5 mmcf/d. These results indicate that natural fracturing and predominantly sand/carbonate intervals result in better deliverability than any specific stimulation technique.
In the summer of 2008, Questerre re-entered the A-5 well to identify prospective shale intervals. After a minor stimulation of a dolomitic brittle sequence above the deepest interval, the well flowed at rates in excess of 10 mmcf/d. It was placed on a long term production test in the fourth quarter of 2008 at a facility constrained rate of 5 mmcf/d to determine the contribution from the deeper shale interval. Results to date indicate limited contribution from the shale.
Based on an independent study on the shale intervals commissioned by the joint venture estimates of the discovered resource of the Mattson/Besa River interval alone ranges between 495 Bcf – 750 Bcf per square mile and for the entire shale intervals at over 1 Tcf per square mile. Notwithstanding the magnitude of this resource, Questerre anticipates future work on these shale intervals will be highly selective and contingent upon results from A-5 and improved natural gas prices.
The Nahanni accounts for the majority of historical production from Beaver River since it was discovered in 1961 and placed on production in 1971. With a discovered resource estimated at 1.4 Tcf, production in the 1970s of 178 Bcf recovered only 12% and fell short of the estimated recovery of 60% due to premature water influx.
Questerre acquired a majority interest in Beaver River in 2001 to complete a secondary recovery scheme for the Nahanni. This included the acquisition of a 3-D seismic survey and extensive technical work including hydrodynamic pressure studies and material balance studies.
The technical work corroborated Questerre’s interpretation of the Nahanni formation that is based on compartmentalization and preferential flow of water in the fracture system (“coning”) - the majority of the recoverable reserves could be contained in undrilled fault blocks or compartments and the remainder behind water cones in existing compartments.
Questerre drilled two wells – A-5 in 2003/2004 and A-8 in 2007/2008 to test this hypothesis. A-5 was unsuccessful largely due to improperly processed seismic data that resulted in the well missing its target up-dip structure. A-8 was drilled for a potentially undrilled compartment that had a different sealing mechanism than originally expected. While several Nahanni infill and step-out locations have been identified, Questerre expects to pursue these in the future contigent upon partner participation, capital allocation and equipment availability.
The Greater Sierra Region
The Greater Sierra region lies approximately 100 km east of Fort Nelson, British Columbia. The primary zone of interest is the Devonian Jean Marie at a depth of 1400m. The region is also prospective for shallower zones including the Mississippian Debolt and deeper Devonian Keg River and Slave Point formations.
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In late 2007, Questerre concluded a seismic and farm-in agreement with a major E&P company covering 54 square miles in the Greater Sierra region. Questerre’s partner is one of the largest operators in the region with over 2.4 million net acres and estimated production of over 200 mmcf/d from the Jean Marie formation in 2007.
Questerre acquired itsinterest in the area through the acquisition of a 46-square mile 3-D seismic survey and the drilling and completion of two test wells. The wells were completed and tied in to its partner’s extensive gathering system in early 2008.
Subject to improved prices, Questerre plans to drill additional wells on thier acreage.
Horn River Shale
Questerre Energy exploration licenses cover over 17,900 (12,800 net) acres prospective for the Devonian Horn River shales.
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The Horn River shale play is still at a very early stage and relatively underexplored. Recent wells have been very promising with inital production rates of around 10-23,000 mcf/d with 10-14 stage frac's. Such production rates should imply recoverable resources of close to 10 Bcf per well on average.
The acreage is on trend with recent and planned shale wells by several majors in the Horn River Basin in northeast British Columbia (BC). It also lies adjacent to several deeper Keg River and Slave Point discoveries in the area as well as the Company's acreage in Greater Sierra region.
Large players currently focusing at the Horn River shale, Nexen, Apache and EOG, have estimated a shale gas resource potential of 18 to 31 Tcf based on a 20% recovery rate. Other plays have proved higher recovery rates as the play matures. The Barnett shale play initially displayed 10% recovery rates, whereas the current figure is above 25%.
British Columbia offers a very encouraging royalty scheme. These include "net profit royalty" schemes with a 2% gross revenue royalty until CAPEX plus 30% is recovered, 20% net revenue royalty until CAPEX plus 105% is recovered and 35% net revenue royalty thereafter. BC natural gas development economics are typically depressed by high CAPEX (limited infrastructure and climate) and typical USD2/mcf discount to NYMEX prices (distance end-user). The favorable royalty scheme partially offsets these factors and could prove natural gas production in BC competitive to other areas.