Time to start digging more at Arcan and Second Wave. Both have exposure to large pools of oil and seem likely to be quite cheap vs what they can currently recover.
The market won't pay much until the reserves hit the books, but the land base has value that an acquirer will pay for.
Gameplan. Learn these companies. They are small, they are volatile. Wait for a selloff (Japan just gave us one). Be ready for when the next one comes.
RBC highlights:
Arcan's premium trading valuation is warranted in our view, given the
company's visible inventory of oil weighted locations, and our expectation that Arcan will be able
to grow production and reserves per share at a faster rate than its peers.
Arcan's PDP reserves
component of 54% is
higher than the peer
group average of ~35%,
suggesting a
conservative reserve
bookings
Exhibit 11 illustrates the history of Arcan's production base. We estimate the company's base
decline rate to be about 20-25% which is lower than the peer-group average of approximately 35%
and largely attributable to its legacy land position at Swan Hills (which includes many low-rate
producers). With a lower decline rate, the company should be able to grow corporate volumes
faster than peers (given similar project types).
The Swan Hills Beaverhill Lake Play
The Swan Hills complex is located in north-central Alberta (approximately 200 kilometres
northwest of Edmonton) and was discovered and developed through vertical drilling in the 1950s
and 1960s. The reef complex is very large (more than 80 kilometres long) and covers more than 24
townships of land. With more than 3 billion barrels of oil (40º API) originally in place, it is
recognized as one of the largest oil pools in Western Canada.
Recent development of the lower-permeability eastern part of the reef has been driven by
horizontal drilling and acid fracturing, in combination with ongoing waterflooding efforts. Recent
activities suggest that acid frac'd horizontal wells combined with pressure maintenance will
deliver high-rate, shallow-decline oil wells with substantially improved recoveries (versus vertical
wells). These efforts appear to more efficiently drain areas of the reservoir with less attractive
reservoir parameters.
Arcan estimates there are 4 mmboe/section to 10 mmboe/section in place across its 150-section
land base, with potential recoveries of up to 40% in a waterflood scenario.
The 2011 drilling program should prove out the economic borders of the play to the
south of the Deer Mountain Unit where the bulk of Arcan's land base lies. Management believes it
has 220+ Beaverhill Lake locations across its land base.
The shallow production declines of the
wells are attributable to the effects of maintaining reservoir pressure via the injection of water; as a result, management expects all future wells in the area to be
flooded almost immediately (or
within 6 months) after being drilled to maintain appropriate reservoir pressure to limit declines.
Arcan's last four wells have been drilled to a total measured depth of 4,005 metres, qualifying the
wells for Alberta's new-well royalty incentive (first 90,000 bbls at 5%, up to 18 months). The
wells are drilled to a vertical depth of 2,450 metres, with a horizontal leg of 1,400 metres. Wells
have been completed using 10-to 14-stage fracture stimulations, comprised largely of 43 m3 28%
HCL acid fracs. Total well costs including equip and tie-in have averaged approximately $4.7
million, which is expected to trend downward over time as drilling and completion techniques are
refined.
While the production history from ARN's Beaverhill Lake horizontal program is limited, results to
date appear to be very good in the context of the cost of the wells. Key to the production rates
Arcan has been able to show within its Deer Mountain Unit is the utilization of water injectors to
maintain reservoir pressure; within the unit there are currently six active water injectors, and the
company is in the process of adding an additional two injectors. The very low initial decline rates
are attributable to the ongoing water-injection process.
We forecast Arcan's wells coming on production at 280 bbl/d and recovering 486
mboe, which is based on the assumption of water injection immediately or soon after the well is
brought on-stream.
we are using well costs of $4.7 million (including
infrastructure & injection wells) and a gas /oil ratio of 10%. These metrics, combined with our
type curve, generate an IRR of 33% and an NPV per well of ~$4.2 million (Exhibit 21). It's
notable that our estimates of per-well economics are more conservative than the company.
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