ICD's and Strategic Review The extra news today is that (1) the Inflow control devices (ICD’s) on IP5 seems to have had a positive effect (over doubling previous fluid rates) (2) the ICD effect on 2P1 (700 bbl/d) is maintained, (3) ICDs reduce the Steam to Oil ratio (SOR) and as a consequence of (1)-(3), ICD’s will be deployed on all other well pairs.
My record of production for IP5 for last June, July, August, September, and October was 100, 100, 150, 190 and 168 bbl/d respectively. Using 168-190 bbl/d as the previous rate (and assuming over double fluid rates equates to doubling of the production rate), that would put the preliminary ICD rate for IP5 at about 336–380 bbl/d. I use the word “preliminary”, because the news release mentions that pad 1 wells need more time to achieve conformity.
Given this information, I think it is worthwhile to review the outlook expressed in the Dec 11, 2013 news release. At that time, STP described ICD devices as one of the acceleration techniques they were considering. They stated that “if given appropriate time, the Company expects that well pair conformance will develop on its own.” (i.e. without ICD acceleration). They stated that their various tests on the best wells indicated that the “original twelve well pairs will have the potential to ramp in aggregate to a rate of approximately 7,000 bbl/d by the first calendar quarter of 2015. “
The success of the ICD devices and the commitment to deploy them on all pairs indicates that acceleration is possible. To get to 7000 bbl/d, each well pair would have to produce 7000/12=583 bbl/d. With 2P1 already exceeding this average rate, 7000 bbl/d later this year seems attainable. We should contemplate what increased volume does to cash flow, profitability and financing.
As well, we should consider the impact of increased volume on the strategic review. The latest news release says that the strategic review is ongoing. Recall, however, that the December 11 news release contemplated a $51 million program to drill 6 infill pairs that would reduce spacing (from 100 metres to 50 metres between pairs). It was the additional capital for this drilling plus the anticipated longer ramp up that caused the company to undertake the strategic review.
“The determination that additional capital will be required to fill the STP-McKay project to capacity, coupled with the understanding of the ramp-up rate on the existing 12 well pairs has resulted in the Company’s Board of Directors electing to initiate a process of examining all options available to maximize shareholder value as the Company moves forward.”
Whereas previously it looked like ramp up would cost $51 million and take one year, it now appears that it may be achievable for $12 million in half that time. Moreover, a lower SOR means reduced costs of natural gas to produce steam.
The dynamics and strategic imperatives have changed.