Third Quarter 2008 Highlights
CORE AREA REVIEW
Parkland/Fort St. John Area, North East British Columbia
This area includes our Montney discovery and is the largest of Storm's core areas, with net production averaging 4,425 Boe per day in the third quarter, an increase of 101% from production of 2,200 Boe per day in the third quarter of 2007. Current production from this area is approximately 5,400 Boe per day.
During the third quarter of 2008, our activity included:
To date in the fourth quarter, we have drilled another three Montney horizontal development wells and one more successful vertical step-out. Two more Montney horizontal development wells will be drilled before year-end.
As a result of the successful vertical step-outs we drilled in the third quarter, we now estimate that gross original gas in place(1) has increased to 410 Bcf, which is at the upper end of the range (330 to 430 Bcf) which was provided in our last quarterly update on August 14th. This was determined based on an internal evaluation by Storm's technical staff using an areal extent of 10.25 sections (6,640 acres) with log analysis from 13 successful vertical gas wells, which show average net pay of 39 meters (average gross pay of 86 meters) and average porosity of 7.9%. Net pay has been determined using gas effect on logs which is evidenced by cross-over on limestone scale neutron-density logs; this is approximately equivalent to a 6% sandstone scale cut-off.
Using a 3% sandstone scale cut-off would result in gross original gas in place(1) increasing to 770 Bcf with average net pay being 87 meters and with 6.4% average porosity. Our confidence regarding the areal extent of the pool has increased greatly as a result of the vertical step-outs we have drilled this year. Geological mapping suggests that there is still potential to further expand the size of our discovery and, as a result, we plan to drill one more vertical step-out in the fourth quarter and one to two more in the first quarter next year.
Development of our Montney discovery continues to progress as expected. During October, we produced 20 Mmcf per day of gross raw gas from eight horizontal Montney gas wells plus 3.2 Mmcf per day of gross raw gas from ten Montney vertical wells. The ninth horizontal well has been drilled, completed and tested nine Mmcf/d of gross raw gas, and will be pipeline connected and producing by mid-November.
Completion of the tenth horizontal well is underway and we expect that it will be producing by the end of November. First year rates from each horizontal well are expected to average approximately 2.2 Mmcf per day of raw gas. Cost inflation and increasing the number of fracs (seven to eight fracs instead of five) has increased the cost of drilling, completing and pipelining each horizontal to $5.5 million.
We are currently planning to drill four horizontal wells per section to develop this pool which results in an undrilled inventory of 35 horizontal wells, representing three years of activity. This inventory of horizontal locations will further increase should our vertical well step-out program continue to be successful in further expanding the pool size. Note that production results from our vertical wells would suggest that reservoir quality and thickness does vary across the pool, which is likely to result in the need for increased horizontal well density in areas of thicker reservoir as well as in areas with lower reservoir quality in order to ensure that the recovery of the resource in place is maximized.
As a result of the success of our horizontal Montney development program, our facility at Parkland is very close to being full, and we have started start constructing a second facility with 12.5 Mmcf per day of initial capacity. The total cost of this project is estimated to be $13.5 million, which includes $1.5 million to twin parts of our gathering system.
When we first announced our intention to add a second facility in mid-August, it was expected to be operational by the end of November; however, due to a reduction in expected 2008 cash flow, this facility will now be operational in late January of 2009. This results in approximately $7.5 million of the total cost being incurred in 2008 with the remainder incurred in early 2009.
In the third quarter of 2009, an additional $14 million will be invested on this facility to install a second compressor which will increase the capacity of the second facility to 25 Mmcf per day, electrify both compressors, and install a refridge plant which will allow us to increase natural gas liquids recovery. This facility has been designed to be expandable to 50 Mmcf per day of capacity.
Financial results from our Parkland property continue to exceed our expectations. Operating costs at Parkland averaged $3.70 per Boe in the third quarter and $4.10 per Boe year to date. The field netback during the third quarter was $46.40 per Boe and is currently $34.00 per Boe, assuming a natural gas price of $6.75 per GJ at AECO, an Edmonton Par oil price of $72.00 per barrel, transportation costs of $1.60 per Boe and a royalty rate of 23%.
Peace River Arch, North West Alberta
Production from this area averaged 1,750 Boe per day in the third quarter, a decline of 1% from the 1,760 Boe per day produced in the immediately prior quarter. Declines are continuing to flatten as evidenced by current production being approximately 1,700 Boe per day. Production in the third quarter of 2007 averaged 2,270 Boe per day.
During the quarter, we tied in one standing well (1.0 net) at our Culp property which is currently producing 70 Boe per day. We have postponed drilling the four wells (2.2 net) we had planned for this area in the second half of 2008 because of the recent decline in natural gas prices. At higher commodity prices which prevailed in the first half of 2008, the economic returns associated with these prospects were reasonable under Alberta's New Royalty Framework ('NRF') which is being implemented January 1, 2009. However, at current commodity prices the economic return under the NRF is not great enough to put Storm's capital at risk.
We are currently reviewing our producing wells in this area in order to ensure that each well's production rate is optimized so that Storm's economic return is maximized once the NRF is implemented January 1, 2009. This may lead to a modest reduction in production from this area in January.
Cabin-Kotcho-Junior Area, North East British Columbia
Net production from this area averaged 885 Boe per day in the third quarter. This represents a decline of 18% from average production of 1,075 Boe per day in the year earlier period. Current production is approximately 850 Boe per day.
Historically, our drilling activity in this winter access area has mainly targeted the Slave Point formation. In the future, our drilling activity will also include prospects in the Bluesky/Debolt formations and horizontal wells in the Jean Marie formation, all in the Junior area. This winter we do not plan to be active in this area drilling wells targeting these conventional prospects, given that our capital resources will be directed towards higher impact opportunities including our Montney discovery at Parkland and the Horn River Basin Devonian shale project.
Since the beginning of this year (including land acquired to date in the fourth quarter), Storm has acquired a 40% interest in 34 sections of undeveloped land (8,940 net acres) prospective for Devonian shale gas in the Horn River Basin, which is just to the west of the Cabin area. This land position was acquired at an average cost of $550 per acre. These lands were purchased in partnership with Storm Gas Resource Corp. ('SGR') which owns the remaining 60% working interest. Combined with Storm's 23% ownership position in SGR, our exposure to this unconventional shale gas play is approximately 54%.
Two to three vertical wells (0.8 to 1.2 net) will be drilled and completed this winter to test the productivity of the acquired lands. One of these wells will be drilled in December but won't be completed until January. Approximately 21 sections (8.4 net) are located in close proximity to the planned vertical test wells, and we estimate that there is 1.6 Tcf of gross original gas-in-place(1) (internal estimate by Storm and SGR) on these lands which is based on average gross pay of 80 meters in the Muskwa and Otter Park shales.
The Klua/Evie shale was not included in this estimate because less information is available regarding the productivity of this shale in the area. Although this winter's drilling program will prove productivity of these lands, we don't expect to have an indication regarding upside or potential economic returns until we have drilled several horizontal wells and have long term production data from those wells, which is likely at least two years away.
Surmont Oil Sands Lease, Alberta
As reported in our first quarter update on May 8th, McDaniel &Associates Consultants Ltd updated its evaluation of the bitumen contingent resource contained in the McMurray formation on Storm's 3,840 acres (6 sections) of oil sands leases. The best case estimate of discovered bitumen resource (defined as bitumen in place exploitable using a Steam-Assisted-Gravity Drainage or SAGD process) is 312 million barrels with the best estimate of contingent bitumen resources recoverable using a SAGD process, being 113 million barrels.
This winter (possibly in December), Storm will drill an additional three test holes to further prove up and expand the estimated bitumen in place. One section remains largely unevaluated and could materially increase our bitumen contingent resources. Storm has no plans at present to initiate development of this resource and no assurance can be provided that this resource will ever be exploited with a conventional SAGD project.
(1) Original Gas in Place (OGIP) is the same as discovered Petroleum Initially in Place which is defined in the COGEH handbook as the quantity of hydrocarbons that are estimated to be in place within a known accumulation. OGIP is used here as it is a more commonly used industry term when referring to gas accumulations. Discovered Petroleum Initially in Place is divided into recoverable and unrecoverable portions, with the estimated future recoverable portion classified as reserves and contingent resources. There is no certainty that it will be economically viable or technically feasible to produce any portion of this Discovered Petroleum Initially in Place except for those portions identified as proved or probable reserves.
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