RESERVES

Storm’s year-end reserve evaluation effective December 31, 2016 was prepared by InSite Petroleum Consultants Ltd. (“InSite”) in a report dated of February 24, 2017.  InSite has evaluated all of Storm’s natural gas and NGL reserves.  The InSite price forecast at December 31, 2016 was used to determine estimates of net present value (“NPV”). Storm’s Reserves Committee, which is made up of independent and appropriately qualified directors, has reviewed and approved the evaluation prepared by InSite, and the report of the Reserves Committee has been accepted by the Company’s Board of Directors.

Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without including any royalty interests) unless noted otherwise. All reserves information has been prepared in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). In addition to the information disclosed herewith, more detailed information will be included in Storm's Annual Information Form for the year ended December 31, 2016 (the “AIF”) available at www.sedar.com or www.stormresourcesltd.com.

Summary

  • Reserve additions in 2016 replaced 195% of production for proved developed producing (“PDP”), 175% for total proved (“1P”) and 172% for total proved plus probable (“2P”). 
  • 2P reserves include 529 Bcf of natural gas and 16 Mmbbl of NGL at year-end 2016. The NGL component includes 60% condensate (9.6 Mmbbl), 24% butane (3.8 Mmbbl) and 16% propane (2.6 Mmbbl). 
  • The all-in finding, development, and acquisition (“FD&A”) cost(1) to add reserves was $6.89 per Boe for PDP, $4.97 per Boe for 1P and $5.48 per Boe for 2P. 
  • Technical revisions were primarily due to horizontal well performance exceeding the InSite forecast from the previous year which increased PDP reserves by 1,392 Mboe (7%), 1P reserves by 3,319 Mboe (5%) and 2P reserves by 3,419 Mboe (3%). 
  • Breaking down 2P reserves by area, 96.3% is at Umbach, 3.3% is at the HRB and 0.4% is at Grande Prairie. 
  • Future development costs (“FDC”) were $412.8 million on a 1P basis and $524.0 million on a 2P basis and are fully financeable from forecast revenue and production within five years which complies with the Canadian Oil and Gas Evaluation (“COGE”) Handbook. 
  • At Umbach, the 100% working interest lands were assigned 61 net 2P horizontal drilling locations at an average of 4.9 Bcf gross raw gas (last year was 66 net 2P locations with 4.7 Bcf gross raw gas). On the 60% working interest lands, 20.4 net 2P horizontal drilling locations were assigned an average of 3.7 Bcf gross raw gas (unchanged from last year). 
  • For the wells drilled in 2016 at Umbach, ultimate 2P recovery is forecast to average 5.6 Bcf gross raw gas. 
  • At Umbach, 2P reserves were recognized in the upper Montney only on 21% or 32.6 net sections of Storm’s 154 net sections in the area (an increase of 2.2 net sections from last year). DPIIP averages 48 Bcf gross raw gas per section in the upper Montney (total net DPIIP 1.6 Tcf on 32.6 net sections).  Forecast recovery of DPIIP totals 36% for 2P reserves. 
  • Umbach 2P FDC includes $53.0 million net for future infrastructure expansion (last year was $31.0 million net for future infrastructure expansion). 
  • The estimated cost to drill and complete a future Montney horizontal well at Umbach was unchanged year over year at approximately $4.5 million (actual cost in 2016 was $3.9 million).
  • The all-in calculation reflects the result of Storm’s entire capital investment program as it takes into account the effect of acquisitions, dispositions and revisions, as well as the change in FDC. 

 

INFORMATION REGARDING DISCLOSURE ON OIL AND GAS RESERVES AND RESOURCES

All amounts are stated in Canadian dollars unless otherwise specified.  Where applicable, natural gas has been converted to barrels of oil equivalent ("Boe") based on 6 Mcf:1 Boe. The Boe rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not recognize a value equivalent at the wellhead.  Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value.  Production volumes and revenues are reported on a company gross basis, before deduction of Crown and other royalties, unless otherwise stated. Unless otherwise specified, all reserves volumes are based on "company gross reserves" using forecast prices and costs. The oil and gas reserves statement for the year ended December 31, 2016, which will include complete disclosure of oil and gas reserves and other information in accordance with NI 51-101, will be contained within the AIF which will be available on SEDAR.

References to estimates of oil and gas classified as DPIIP are not, and should not be confused with, oil and gas reserves.

To view detailed Reserves tables, please visit our 2016 Year-End Report on this website under "Investor Relations","Financial Reports", "Reserves".