CALGARY, Alberta, March 01, 2018 (GLOBE NEWSWIRE) — Storm Resources Ltd. (TSX:SRX)

Storm has also filed its audited consolidated financial statements as at December 31, 2017 and for the three months and year then ended along with Management’s Discussion and Analysis (“MD&A”) for the same periods.  This information appears on SEDAR at and on Storm’s website at

Selected financial and operating information for the three months and year ended December 31, 2017, as well as reserves information at December 31, 2017, appears below and should be read in conjunction with the related financial statements and MD&A.


Thousands of Cdn$, except volumetric and
 per-share amounts
Three Months to
 Dec. 31, 2017
  Three Months to
Dec.31, 2016
  Year Ended
Dec. 31, 2017
  Year Ended
Dec. 31, 2016


Revenue from product sales(1) 34,844   26,244   123,306   77,283  
Funds flow 21,323   11,985   64,080   34,380  
  Per share – basic and diluted ($) 0.18   0.10   0.53   0.29  
Net income (loss) 8,624   (12,898 ) 39,689   (38,460 )
  Per share – basic and diluted ($) 0.07   (0.11 ) 0.33   (0.32 )
Operations capital expenditures(2) 26,126   33,399   81,685   65,538  
Land and property acquisitions/(dispositions)       (600 )
Debt including working capital deficiency(2)(3) 106,124   89,841   106,124   89,841  
Common shares (000s)        
  Weighted average – basic 121,557   120,488   121,531   120,053  
  Weighted average – diluted 121,557   120,488   121,616   120,053  
  Outstanding end of period – basic 121,557   120,764   121,557   120,764  
(Cdn$ per Boe)        
Revenue from product sales(1) 21.12   21.42   21.09   15.97  
Royalties (0.63 ) (0.99 ) (1.19 ) (0.79 )
Production (5.68 ) (6.95 ) (6.04 ) (6.78 )
Transportation (0.69 ) (0.55 ) (0.76 ) (0.45 )
Field operating netback(2) 14.12   12.93   13.10   7.95  
Realized (loss) gain on hedging 0.41   (1.45 ) (0.40 ) 0.93  
General and administrative (0.94 ) (0.95 ) (1.05 ) (1.10 )
Interest and finance costs (0.67 ) (0.74 ) (0.69 ) (0.68 )
Funds flow per Boe 12.92   9.79   10.96   7.10  
Barrels of oil equivalent per day (6:1) 17,936    




Natural gas production        
  Thousand cubic feet per day 87,375   66,173   78,521   65,478  
  Price (Cdn$ per Mcf)(1) 2.26   2.86   2.58   2.05  
Condensate production        
  Barrels per day 1,914   1,381   1,685   1,303  
  Price (Cdn$ per barrel)(1) 69.53   57.17   61.80   49.34  
NGL production        
  Barrels per day 1,460   910   1,245   1,003  
  Price (Cdn$ per barrel)(1) 33.29   18.64   25.15   12.51  
Wells drilled (100% working interest) 7.0   5.0   16.0   12.0  
Wells completed (100% working interest) 3.0   5.0   12.0   10.0  
  1. Excludes gains and losses on commodity price contracts.
  2. Certain financial amounts shown above are non-GAAP measurements including field operating netback, operations capital expenditures, debt including working capital deficiency and all measurements per Boe.  See discussion of Non-GAAP Measurements on page 39 of the MD&A.
  3. Excludes the fair value of commodity price contracts.



  • Production increased by 34% on a per-share basis from the prior year to a record high of 17,936 Boe per day which was consistent with the low end of guidance (18,000 to 19,000 Boe per day).   
  • Liquids production (condensate plus NGL) increased 47% from the prior year to 3,374 barrels per day and exceeded the 32% increase in natural gas production as drilling has shifted to areas at Umbach where higher condensate-gas ratios are being realized.  Liquids represented 48% of production revenue versus 34% last year.
  • At the end of the quarter, there was an inventory of 12 Montney horizontal wells (12.0 net) at Umbach that had not started producing which includes two completed wells.  Five horizontal wells (5.0 net) started production in the quarter.
  • Montney horizontal well performance at Umbach continues to improve as length is increased.  The three wells (3.0 net) from 2017 with the most history have an average length of 1,650 metres and averaged 4.0 Mmcf per day gross raw gas during their eleventh month which is approximately 50% better than the average well completed in 2014 to 2016.  Wells drilled in the fourth quarter averaged 2,090 metres which is expected to result in further improvements.
  • Revenue per Boe declined by 1% year over year with higher liquids production and pricing offsetting a 21% decrease in the natural gas price.
  • Natural gas sales continue to be maximized into the higher priced Chicago market with 70% of fourth quarter sales being at Chicago.
  • Controllable cash costs (production, general and administrative, interest and finance) decreased 16% year over year to $7.29 per Boe.  This was mainly due to production costs declining 18% as a result of continuing production growth and a new processing arrangement. 
  • Funds flow was $21.3 million ($12.92 per Boe) which was the highest quarterly funds flow achieved since inception and represents a per-share increase of 83% from a year ago.  The improvement was largely the result of a 35% increase in production volumes and a 32% increase in the funds flow netback.    
  • Net income was $8.6 million or $0.07 per share and a significant improvement from the net loss of $12.9 million in the prior year as net revenue increased more than expenses.  Net revenue including hedging increased with production growth and with a $13.1 million reduction in the unrealized hedging loss.
  • Capital investment was $26.1 million with 82% being invested in drilling seven horizontal wells (7.0 net) and completing three horizontal wells (3.0 net).  This was consistent with guidance at $26.0 million.
  • Total debt including working capital deficiency was $106.1 million which is 1.2 times annualized fourth quarter funds flow.  The bank credit facility is $165.0 million.
  • Commodity price hedges continue to be added and currently protect approximately 40% of forecast production for 2018 using the low end of guidance (20,000 Boe per day).


  • Production was 16,017 Boe per day (18% condensate and NGL), a year-over-year increase of 20% on a per-share basis and consistent with guidance (16,200 Boe per day). 
  • Liquids production (condensate plus NGL) was 2,930 barrels per day, an increase of 27% from last year and higher than the 20% increase in natural gas production.
  • The corporate decline rate was approximately 32% in 2017 (December 2016 corporate production was 14,666 Boe per day with the same wells producing 9,900 Boe per day in December 2017).  The 13 horizontal wells that were turned on in 2017 produced 9,300 Boe per day in December 2017.
  • The 12 horizontal wells completed in 2017 had an average length of 1,750 metres which is 38% longer than wells completed in 2014 to 2016.  The last seven wells that were drilled in 2017 averaged 2,090 metres (these wells will be completed in 2018).  Rates and reserves are expected to increase in proportion to the added length.
  • Controllable cash costs (production, general and administrative, interest and finance) averaged $7.78 per Boe for the year, a decrease of $0.78 per Boe, or 9%, from the previous year. 
  • Funds flow was $64.1 million ($0.53 per share), a year-over-year increase of 83% on a per-share basis with the improvement coming from production growth combined with a 54% increase in the funds flow netback.  The higher funds flow netback was mainly from higher commodity prices and a reduction in per-Boe controllable cash costs. 
  • Net income improved to $39.7 million ($0.33 per share) from a net loss of $38.5 million in the prior year.  This was primarily due to an unrealized hedging gain which was a $54.8 million improvement from last year plus increased production and higher realized commodity prices.


  • The all-in in Finding, Development & Acquisition (“FD&A”) cost showed significant year-over-year improvement.  Proved developed producing (“PDP”) FD&A was $5.76 per Boe, a 16% improvement.  Total proved (“1P”) FD&A was $3.06 per Boe, a 38% improvement.  Total proved plus probable (“2P”) FD&A was $1.27 per Boe, a 77% improvement. 
  • Recycle ratio using the funds flow netback divided by FD&A was 1.9 for PDP, 3.6 for 1P, and 8.6 for 2P.  Excluding hedging, the PDP recycle ratio improves to 2.0.
  • By commodity and on a 2P basis, liquids reserves increased 36% while natural gas reserves increased 21%.
  • Reserve life index (“RLI”) using fourth quarter production is 5.2 years for PDP, 14.9 years for 1P, and 19.7 years for 2P.
  • Reserve additions for PDP were the highest since Storm’s inception and replaced 143% of annual production (351% for 1P and 424% for 2P).
  • Reserve quality continued to improve with PDP increasing to 26% of 2P from 24% last year.
  • On a per-share basis, the year-over-year increase in reserves was 32% for PDP, 26% for 1P, and 23% for 2P.
  • 2P reserves are recognized in the Montney at Umbach on 33.5 net sections which is only 22% of the total land position.
  • Technical revisions added 13% to PDP, 14% to 1P, and 13% to 2P as a result of actual well performance exceeding the PDP forecast and with longer horizontal wells used for 1P and 2P future drilling locations.
  • Actual results achieved by Storm in 2017 were significantly better than what was predicted in last year’s evaluation.  The actual average drill and complete cost in 2017 was $4.2 million which was less than the estimated cost of $4.5 million in last year’s evaluation even though longer horizontal wells were drilled.  Estimated 2P reserves assigned to wells drilled and completed in 2017 averaged 6.6 Bcf gross raw gas which was materially higher than the 4.6 Bcf estimate for future 2P drilling locations in last year’s evaluation.
Reserves Increase From        
(Mboe) Last Year   2017   2016   2015  
PDP +33 % 33,729   25,395   20,810  
1P +27 % 97,617   77,097   73,434  
2P  +24 % 128,963   104,192   100,722  
PDP as % of 2P   26 % 24 % 21 %
1P as a % of 2P   76 % 74 % 73 %

Reserves Per Share Outstanding
(Mboe per million shares) 
Increase From
Last Year
PDP +32 % 277 210 174
1P +26 % 803 638 615
2P +23 % 1,061 862 844

All-in FD&A Cost Including Change in FDC
   2017    2016    2015  3 Year Total
PDP $ 5.76 $ 6.89 $ 6.53 $ 6.31
1P $ 3.06 $ 4.97 $ 3.38 $ 3.48 
2P $ 1.27 $ 5.48 $ 0.50 $ 1.68 

Recycle Ratio Using All-in FD&A Cost   2017   2016   2015 3 Year Total
Funds Flow netback ($/Boe) $ 10.96 $ 7.10 $ 10.76 $ 9.60
PDP Recycle   1.9   1.0   1.6   1.5
1P Recycle   3.6   1.4   3.2   2.8 
2P Recycle   8.6   1.3   21.5   5.7


Umbach, Northeast British Columbia

Storm’s land position at Umbach is prospective for liquids-rich natural gas from the Montney formation and currently totals 109,000 net acres (155 net sections).  To date, Storm has drilled 69 horizontal wells (65.4 net).

Liquids recovery during the fourth quarter was 39 barrels per Mmcf sales (57% being higher priced condensate), an increase from 36 barrels per Mmcf sales last year.  

Activity in the fourth quarter included completing three horizontal wells (3.0 net) and drilling seven horizontal wells (7.0 net).  Notably, the horizontal drills had an average length of 2,090 metres, an increase of 57% from the average length of the wells drilled in 2014 to 2016.  Five horizontal wells (5.0 net) started production which left an inventory of 12 horizontal wells (12.0 net) that had not started producing at the end of the quarter including two completed wells.  During 2017, 13 horizontal wells (13.0 net) started producing with these wells adding 7,730 Boe per day in the fourth quarter. 

With drilling focused in the south and to the northwest, the condensate-gas ratio on the 2017 wells is approximately 30% higher than on the 2014 to 2016 wells.  This has resulted in corporate liquids production increasing at a higher rate than natural gas production.  

Since 2013, approximately $100.0 million has been invested in building out infrastructure (pipelines and facilities) with current capacity totaling 115 Mmcf per day raw gas from three field compression facilities.  Throughput in the fourth quarter was 93 Mmcf per day raw gas (December averaged 100 Mmcf per day).  Capacity can be increased to 150 Mmcf per day by installing additional compression which was purchased and moved to site in the first quarter of 2018 at a cost of $5.0 million (requires additional $2.0 million for installation).  The increased compression capacity would support growth in corporate production to approximately 27,000 Boe per day.

Storm’s produced raw natural gas is sour (approximately 1.2% H2S) with 81% directed to the McMahon Gas Plant in the fourth quarter and 19% directed to the Stoddart Gas Plant.  Firm processing commitments total 65 Mmcf raw gas per day with terms of 5 to 15 years at McMahon and 15 Mmcf per day until April 2018 at Stoddart. 

A summary of horizontal wells is provided below.  The wells completed in 2017 are 38% longer than 2014 to 2016 wells while the drilling and completion cost per meter decreased by 16% from 2016.  Results to date from the 2017 wells are very encouraging even though this is not apparent from IP90 and IP180 rates as the majority of wells are initially rate restricted to manage fluid rates.  More information on well performance is available in the presentation on Storm’s website.

Year of
Actual Drill &
Complete Cost
IP90 Cal Day
Mmcf/d Raw
IP180 Cal Day
Mmcf/d Raw
IP365 Cal Day
Mmcf/d Raw
12 hz’s(1)
19 1,170 m $4.6 million
$3,950 per meter
4.9 Mmcf/d
12 hz’s
4.4 Mmcf/d
12 hz’s
3.5 Mmcf/d
12 hz’s
11 hz’s
22 1,360 m $4.5 million
$3,300 per meter
4.7 Mmcf/d
11 hz’s
4.2 Mmcf/d
11 hz’s
3.3 Mmcf/d
11 hz’s
10 hz’s
25  1,300 m $3.7 million
$2,850 per meter
5.1 Mmcf/d
10 hz’s
4.2 Mmcf/d
10 hz’s
3.5 Mmcf/d
7 hz’s
12 hz’s
34 1,750 m $4.2 million
$2,400 per meter
4.9 Mmcf/d
8 hz’s
4.4 Mmcf/d
5 hz’s
4.4 Mmcf/d
2 hz’s
3 hz’s
37 2,090 m $5.3 million
$2,550 per meter
  1. 2014 wells exclude a middle Montney well (this table provides analysis of upper Montney wells only).


Commodity price hedges are used to support longer-term growth by continually layering in hedges to protect pricing on 50% of current production for the next 12 months and 25% for 13 to 24 months forward.  Anticipated production growth is not hedged.  Note that approximately 80% of Storm’s liquids production is priced in reference to WTI.  The current hedge position is summarized below and protects approximately 40% of forecast production for 2018 using the low end of guidance (20,000 Boe per day).

 Crude Oil  1,362 Bpd  WTI Cdn$64.43/Bbl floor, Cdn$68.08/Bbl ceiling
 Propane  300 Bpd  Conway Cdn$39.55/Bbl
 Natural Gas  750 GJ/d (600 Mcf/d)  AECO Cdn$2.80/GJ
   34,200 Mmbtu/d (29,000 Mcf/d)  Chicago Cdn$3.81/Mmbtu(1)
   2,200 Mmbtu/d (1,850 Mcf/d)  Chicago US$2.70/Mmbtu(1)
   9,000 Mmbtu/d (7,600 Mcf/d)  Sumas Cdn$3.02/Mmbtu
 3,000 GJ/d (2,400 Mcf/d)  Station 2 – AECO basis -$0.345/GJ
 Crude Oil  325 Bpd  WTI Cdn$67.28/Bbl floor, Cdn$71.14/Bbl ceiling
 Natural Gas  4,000 Mmbtu/d (3,400 Mcf/d)  Chicago Cdn$3.50/Mmbtu(1)
   1,500 Mmbtu/d (1,275 Mcf/d)  Chicago US$2.65/Mmbtu(1)
  1. The Alliance Pipeline tariff to Chicago is approximately Cdn$1.20 per Mmbtu including the cost of fuel.

Total firm transportation capacity is currently 77 Mmcf per day and increases to 102 Mmcf per day in April 2018.  Capacity on the Alliance Pipeline to Chicago increased by five Mmcf per day in December 2017 and currently totals 55 Mmcf per day.  Natural gas production exceeding firm capacity is directed to Chicago and/or Station 2 using interruptible pipeline capacity (depending on which sales point offers a higher price).  Using forecast production for 2018, firm transportation capacity will result in approximately 54% to 68% of natural gas sales at Chicago pricing, 11% at Sumas pricing less a marketing adjustment, 5% at ATP pricing, 3% to 17% at Station 2 pricing and 13% at AECO pricing.  Note that natural gas marketing arrangements result in the cost of transportation on the Alliance Pipeline for sales in Chicago being deducted from revenue ($8.3 million deducted in the fourth quarter of 2017).  Additional information is provided in the presentation on Storm’s website.


In the fourth quarter of 2017, actual production of 17,936 Boe per day was at the low end of guidance of 18,000 to 19,000 Boe per day.  This was the result of the low Station 2 natural gas price in the quarter ($0.53/GJ) which resulted in the start-up of new wells being deferred until December when Alliance capacity was increased by an additional five Mmcf per day.  During October and November, production was maintained at a level that fulfilled firm transportation commitments.

For the first quarter of 2018, production is forecast to be 19,500 to 20,500 Boe per day which represents year-over- year growth of 18% at the mid-point.  Production to date in the first quarter has averaged 19,700 Boe per day based on field estimates.  Capital investment is expected to be $23.0 million which includes completing three horizontal wells on the Nig land block at Umbach plus constructing a 13-kilometer gathering pipeline to the Nig land block. 

In the first half of 2018, capital investment is expected to be less than funds flow using forecast commodity prices which is expected to result in debt being reduced by approximately $10.0 million to $15.0 million.

Updated guidance for 2018 is provided in the table below and is largely unchanged except for updating forecast commodity prices to reflect pricing to date and approximately the current forward strip for the remainder of the year.  A range has been provided for capital investment and for forecast production with both mainly contingent on the natural gas price at Station 2 which is where Storm’s incremental natural gas growth would be sold.  The low end of forecast production for the year represents year-over-year growth of 25% with capital investment expected to be less than estimated funds flow.  The production forecast uses a 7.5 Bcf type curve for future horizontal wells at Umbach (previously a 6.3 Bcf type curve was used which was based on the performance of shorter horizontal wells completed in 2014 to 2016).

 2018 Guidance


November 14, 2017
March 1, 2018
$Cdn/$US exchange rate   0.79   0.80
Chicago daily natural gas – US$/Mmbtu $2.80 $2.60
Sumas monthly natural gas – US$/Mmbtu $2.40 $1.90
AECO daily natural gas – Cdn$/GJ $1.80 – $2.10 $1.40
Station 2 daily natural gas – Cdn$/GJ $1.30 – $1.70 $1.05
WTI – US$/bbl $52.00 $56.00
Edmonton light oil – Cdn$/Bbl $62.00 $64.00
Est revenue net of transport (excl hedges) – $/Boe $18.00 – $19.25 $17.00 – $18.50
Est operating costs – $/Boe $5.75 $5.75
Est royalty rate (% revenue before hedging) 6% – 9% 6% – 8%
Est operations capital investment (excl A&D) – $ million $55.0 – $90.0 $55.0 – $90.0
Est cash G&A  – $ million  $6.0 – $7.0 $6.0 – $7.0
   – $/Boe $0.70 – $0.95 $0.70 – $0.95
Est interest expense – $ million $4.5 – $5.5 $4.5 – $5.5
Forecast fourth quarter production – Boe/d
% liquids
20,000 – 27,000
17% liquids
20,000 – 27,000
18% liquids
Forecast annual production – Boe/d
% liquids
20,000 – 23,000
17% liquids
20,000 – 23,000
18% liquids
Est annual funds flow at 20,000 Boe/d – $ million   $70.0 – $78.0
Umbach horizontal wells drilled – gross
Umbach horizontal wells completed – gross
Umbach horizontal wells connected – gross
6 – 12 (6.0 – 12.0 net)
11 – 17 (11.0 – 17.0 net)
11 – 16 (11.0 – 16.0 net)
3 – 12 (3.0 – 12.0 net)
11 – 17 (11.0 – 17.0 net)
11 – 16 (11.0 – 16.0 net)

2018 Guidance History



Station 2



Estimated Operations
$ million
Fourth Quarter

Forecast Annual

Nov 14, 2017 $2.80 $1.30 – $1.70   $1.80 – $2.10 $55.0 – $90.0 20,000 – 27,000 20,000 – 23,000
Mar 1, 2018 $2.60 $1.05   $1.40 $55.0 – $90.0 20,000 – 27,000 20,000 – 23,000

The continuing volatility in Western Canadian natural gas prices has been largely mitigated for Storm by increasing liquids production and through diversified natural gas sales.  In 2017, liquids represented 40% of production revenue while only 34% of natural gas sales were at Western Canadian prices.     

Although Storm’s production in 2017 grew by 21% from 2016, growth in the second half of the year was less than expected primarily because of declining Western Canadian natural gas prices.  From H1/17 to H2/17, the natural gas price declined by approximately 45% at AECO and by 70% at Station 2.  This was mainly from production growing by 1 Bcf per day since the summer of 2017, storage levels that are relatively high, and export pipelines to other markets that are full (in general, too much supply and nowhere to take it).  In addition, the price differential between Station 2 and AECO in H2/17 widened to -$0.80 per GJ as a result of maintenance on the Enbridge and TransCanada pipeline systems restricting takeaway out of northeast British Columbia (“NE BC”).  Spot or daily natural gas prices have shown recent improvement with AECO averaging approximately $2.00 per GJ and Station 2 averaging approximately $1.75 per GJ to date in 2018 (increases of 34% and 157% respectively versus H2/17).  The differential between Station 2 and AECO has narrowed with the completion of the TCPL Towerbirch expansion which increased flows out of NE BC.  Spot or daily prices have been stronger than the forward strip with strong physical demand from a cold winter, rising oil sands demand, and higher electricity generation as coal plants are decommissioned.  In addition, there has been a year-over-year decrease in rigs drilling for natural gas which likely will reduce supply later in 2018.   

Incremental production growth above Storm’s firm transportation capacity (102 Mmcf per day sales or 20,000 to 21,000 Boe per day) is primarily directed to Station 2 and growth will continue to be contingent on the natural gas price at Station 2.  Capital investment has been designed to be flexible where activity and production growth can be rapidly increased if supported by the natural gas price.  At Umbach, additional compression can be installed quickly plus there are currently four completed horizontal wells that can be turned on and another five standing horizontal wells awaiting completion (all longer wells). 

Storm’s business plan continues to be focused on adding value by converting the multi-year drilling inventory in the Montney into funds flow growth while generating reasonable risk-adjusted rates of return.  Although the current forward strip for Western Canadian natural gas prices makes this challenging, the significant improvement in liquids prices over the last 12 months has resulted in several alternatives being identified for growing funds flow by increasing liquids production. 

Liquids production will be increased by continuing to drill wells in areas where higher condensate-gas ratios can be realized (Nig and Fireweed land blocks) and can also come from adding infrastructure to increase plant NGL recoveries at Umbach.  Current liquids recovery from the liquids-rich Montney is less than optimal and either adding or redirecting raw gas to access a shallow-cut refrigeration process is being evaluated which would increase NGL recovery from the raw gas by approximately 100% to 125%. 

Partially mitigating the decline in Western Canadian natural gas prices, Storm’s capital efficiencies are expected to improve based on preliminary results from recent longer horizontal wells that are more than 2,000 meters in length (approximately 60% longer than wells completed in 2014 to 2016).  Rates and reserves are expected to increase in proportion to the added length while the total well cost is increasing by 15% to 25%.

Maintaining production at current levels would also add value as debt would be reduced with maintenance capital being less than estimated funds flow at current strip pricing for 2018 and 2019.  The estimated capital required to maintain production is $55.0 million to $60.0 million in 2018 and $35.0 million to $40.0 million in 2019.  This option is less desirable as it adds value at a slower rate versus growing production and/or increasing liquids production.

Results from 2017 show that Storm’s business plan works at low natural gas prices.  In addition, the large, higher quality, liquids-rich asset in the Montney at Umbach offers alternatives for growth that are less dependent on natural gas pricing.  For 2018, production is expected to grow by a minimum of 25% year over year to average 20,000 Boe per day.  Existing infrastructure will support further growth to 27,000 Boe per day with the timing to do so dependent on natural gas prices.  For 2019, the focus will be to identify ways to grow funds flow by increasing liquids production which could come from adding infrastructure and/or drilling wells in areas with higher condensate-gas ratios. 

In closing, I would like to thank Storm’s employees for their hard work which has resulted in record levels of production and significant growth in funds flow while continuing to improve capital efficiencies and reduce costs.  In addition, the invaluable advice, guidance and support provided by Storm’s Board of Directors continues to be much appreciated. 


Brian Lavergne,

President and Chief Executive Officer

March 1, 2018



Storm’s year-end reserve evaluation effective December 31, 2017 was prepared by InSite Petroleum Consultants Ltd. (“InSite”) in a report dated February 23, 2018.  InSite has evaluated all of Storm’s natural gas and NGL reserves.  The InSite price forecast at December 31, 2017 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 in this report, more detailed information will be included in Storm’s Annual Information Form for the year ended December 31, 2017 (the “AIF”).


  • Reserve additions in 2017 replaced 143% of production for proved developed producing (“PDP”), 351% for total proved (“1P”) and 424% for total proved plus probable (“2P”).
  • 2P reserves include 643 Bcf of natural gas and 22 Mmbbl of NGL at year-end 2017.  The NGL component includes 62% condensate (13.5 Mmbbl), 23% butane (5.0 Mmbbl) and 15% propane (3.3 Mmbbl).
  • The all-in finding, development, and acquisition (“FD&A”) cost(1) to add reserves was $5.76 per Boe for PDP, $3.06 per Boe for 1P and $1.27 per Boe for 2P. 
  • Technical revisions increased PDP reserves by 3,342 Mboe (13%), 1P reserves by 10,949 Mboe (14%) and 2P reserves by 13,976 Mboe (13%).  PDP revisions were primarily due to well performance exceeding the InSite forecast from the previous year, while 1P and 2P revisions were due to using longer horizontal wells.
  • Breaking down 2P reserves by area, 99.4% is at Umbach, 0.3% is at the HRB and 0.3% is at Grande Prairie.
  • Future development costs (“FDC”) were $412 million on a 1P basis and $481 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.
  • FDC declined from last year with longer horizontal wells being recognized for future drilling locations in the Montney at Umbach.  This reduced the total number of locations while reserves per location were increased. 
  • At Umbach there are 78.6 net 2P future horizontal drills assigned an average of 6.2 Bcf gross raw gas (last year was 86.4 net 2P locations with 4.5 Bcf gross raw gas).
  • Wells drilled in 2017 were assigned an average of 6.6 Bcf gross raw gas on a 2P basis.
  • At Umbach, 2P reserves were recognized in the upper Montney on 22% or 33.5 net sections of Storm’s 155 net sections in the area (an increase of 0.8 net sections from last year).  DPIIP averages 45 Bcf gross raw gas per section in the upper Montney (total net DPIIP 1.5 Tcf on 33.5 net sections).  Forecast recovery of DPIIP totals 52% for 2P reserves.
  • FDC includes $55.0 million net on a 2P basis for future infrastructure expansion at Umbach (last year was $53.0 million net for future infrastructure expansion).
  • The estimated cost to drill and complete a future Montney horizontal well at Umbach was $4.8 million compared to $4.5 million for the previous year (actual cost in 2017 was $4.2 million).

(1) 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.


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, 2017, 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.

Gross Company Interest Reserves as at December 31, 2017
(Before deduction of royalties payable, not including royalties receivable)

     Sales Gas
 6:1 Oil
Proved producing   167,747 5,771 33,729
Proved non-producing   3,706 92 710
Total proved developed   171,453 5,863 34,439
Proved undeveloped   314,872 10,700 63,179
Total proved   486,325 16,563 97,617
Probable additional   156,390 5,281 31,346
Total proved plus probable   642,715 21,844 128,963

   Numbers in this table may not add due to rounding.

Gross Company Reserve Reconciliation for 2017
(Gross company interest reserves before deduction of royalties payable)

  6:1 Oil Equivalent (Mboe)  


  Probable   Proved plus
 December 31, 2016 – opening balance 25,395   77,097   27,096   104,192  
 Extensions 11,132   16,690   2,945   19,635  
 Category transfer        
 Technical revisions 3,342   10,949   3,027   13,976  
 Economic factors (294 ) (1,271 ) (1,723 ) (2,994 )
 Production (5,846 ) (5,846 )   (5,846 )
 December 31, 2017 – closing balance 33,729   97,617   31,346   128,963  

   Numbers in this table may not add due to rounding.

Reserve Life Index (“RLI”) Using Fourth Quarter Production

    2017 2016 2015
 PDP   5.2 5.2 5.3
 1P   14.9 15.9 18.8
 2P   19.7 21.4 25.7

Future Development Costs (“FDC”)


Proved ($M)


Proved Plus Probable ($M)

 2018     60,050 64,300
 2019     103,071 119,391
 2020     179,781 207,352
 2021     68,745 90,075
 Total FDC – undiscounted     411,647 481,118
 Total FDC – discounted at 10%     340,908 395,976
 ($million)     2017   2016   2015  
 1P FDC   $ 412 $ 413 $ 435  
 2P FDC   $ 481 $ 524 $ 543  

Note:  InSite escalates capital costs at 2% per year after 2018.

All-in Finding, Development and Acquisition Costs (“FD&A”)
(including acquisitions, dispositions and revisions)

 Proved Developed Producing FD&A Cost (All-in)   2017     2016     2015   3 Year Total  
 Net capital investment (000s) $   81,685   $   64,938   $   71,509   $   218,130  
 Total capital $   81,685   $   64,938   $   71,509   $   218,130  
 Total reserve additions (Mboe)   14,180     9,424     10,956     34,560  
 All-in PDP FD&A cost (per Boe) $   5.76   $   6.89   $   6.53   $   6.31  


 Total Proved FD&A Cost (All-in)   2017     2016     2015   3 Year Total  
 Net capital investment (000s) $   81,685   $   64,938   $   71,509   $   218,130  
 Change in FDC (000s)   (1,127 )   (22,669 )   (12,275 )   (36,071 )
 Total capital including change in FDC (000s) $   80,558   $   42,269   $   59,234   $   182,059  
 Total reserve additions (Mboe)   26,366     8,501     17,517     52,384  
 All-in 1P FD&A cost (per Boe) $   3.06   $   4.97   $   3.38   $   3.48  


 Total Proved Plus Probable FD&A Cost (All-in)   2017     2016     2015   3 Year Total
 Net capital investment (000s) $   81,685   $   64,938   $   71,509   $   218,130  
 Change in FDC (000s)   (42,755 )   (19,395 )   (63,288 )   (125,438 )
 Total capital including change in FDC (000s) $   38,930   $   45,543   $   8,221   $   92,692  
 Total reserve additions (Mboe)   30,617     8,308     16,332     55,257  
 All-in 2P FD&A cost (per Boe) $   1.27   $   5.48   $   0.50   $   1.68  

Finding and Development Costs (“F&D”)
(excluding acquisitions, dispositions and revisions)

 Total Proved F&D Cost   2017     2016     2015 3 Year Total  
 Capital expenditures excluding acquisitions        
  and dispositions (000s) $   81,685   $   64,938   $   95,099 $   241,720  
 Change in FDC (000s)   (1,127 )   (22,669 )   18,604   (5,192 )
 Total capital including change in FDC (000s) $   80,558   $   42,269   $   113,703 $   236,528  
 Reserve additions excluding acquisitions, dispositions,        
  and revisions (Mboe)   16,669     5,182     14,950   36,801  
 1P F&D cost (per Boe) $   4.83   $   8.16   $   7.61 $   6.43  
 Total Proved Plus Probable F&D Cost   2017     2016     2015 3 Year Total  
 Capital expenditures excluding acquisitions        
  and dispositions (000s) $   81,685   $   64,938   $   95,099 $   241,720  
 Change in FDC (000s)   (42,755 )   (19,395 )   30,717   (31,433 )
 Total capital including change in FDC (000s) $   38,930   $   45,543   $   125,816 $   210,287  
 Reserve additions excluding acquisitions, dispositions,        
  and revisions (Mboe)   19,615     4,890     19,457   43,962  
 2P F&D cost (per Boe) $   1.98   $   9.31   $   6.47 $    4.78  

Net Present Value Summary (before tax) as at December 31, 2017

Benchmark oil and NGL prices used are adjusted for quality of oil or NGL produced and for transportation costs.  The calculated NPV include a deduction for estimated future well abandonment costs. The NPV disclosed does not represent fair market value of reserves.

 (000s) Undiscounted Discounted at
Discounted at
Discounted at
Discounted at
 Proved producing 613,055 476,124 389,466 330,863 289,021
 Proved non-producing 7,396 4,839 3,341 2,395 1,763
 Total proved developed 620,451 480,963 392,806 333,258 290,784
 Proved undeveloped 915,449 590,662 399,234 278,439 198,009
 Total proved 1,535,899 1,071,625 792,040 611,697 488,792
 Probable additional 658,780 357,091 215,918 141,347 97,907
 Total proved plus probable 2,194,678 1,428,716 1,007,958 753,044 586,700

   Numbers in this table may not add due to rounding.

Net Present Value Summary (after tax) as at December 31, 2017

Benchmark oil and NGL prices used are adjusted for quality of oil or NGL produced and for transportation costs.  The calculated NPV each include a deduction for estimated future well abandonment costs.  The NPV disclosed does not represent fair market value of reserves.

 (000s) Undiscounted Discounted at
Discounted at
Discounted at
Discounted at
 Proved producing 576,702 455,976 377,775 323,808 284,617
 Proved non-producing 5,476 3,661 2,585 1,893 1,419
 Total proved developed 582,178 459,637 380,360 325,701 286,036
 Proved undeveloped 677,095 430,687 285,517 194,069 133,346
 Total proved 1,259,272 890,324 665,877 519,770 419,382
 Probable additional 488,035 263,033 157,653 102,008 69,645
 Total proved plus probable 1,747,307 1,153,356 823,530 621,778 489,027

   Numbers in this table may not add due to rounding.

InSite Escalating Price Forecast as at December 31, 2017


Crude Oil
Edmonton Par
 Crude Oil
Henry Hub
Natural Gas
Natural Gas
 2018 60.00 71.36 3.10 2.52
 2019 62.50 73.44 3.30 2.93
 2020 65.00 75.47 3.50 3.22
 2021 70.00 80.49 3.70 3.51
 2022 72.50 82.38 3.90 3.75

Boe Presentation For the purpose of calculating unit revenues and costs, natural gas is converted to a barrel of oil equivalent (“Boe”) using six thousand cubic feet (“Mcf”) of natural gas equal to one barrel of oil unless otherwise stated. Boe may be misleading, particularly if used in isolation. A Boe conversion ratio of six Mcf to one barrel (“Bbl”) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All Boe measurements and conversions in this report are derived by converting natural gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil. Mboe means 1,000 Boe.

Non-GAAP Measures – This document may refer to the terms “debt including working capital deficiency”, “field operating netbacks”, “field operating netbacks including hedging”, the terms “cash” and “non-cash”, “cash costs”, and measurements “per commodity unit” and “per Boe” which are not recognized under Generally Accepted Accounting Principles (“GAAP”) and are regarded as non-GAAP measures. These non-GAAP measures may not be comparable to the calculation of similar amounts for other entities and readers are cautioned that use of such measures to compare enterprises may not be valid. Non-GAAP terms are used to benchmark operations against prior periods and peer group companies and are widely used by investors, analysts and other parties.  Additional information relating to certain of these non-GAAP measures can be found in Storm’s MD&A dated March 1, 2018 for the period ended December 31, 2017 which is available on Storm’s SEDAR profile at and on Storm’s website at

Initial Production Rates – Initial production rates (“IP”) provided refer to actual raw natural gas rates reported to the British Columbia government.  IP rates are not necessarily indicative of long-term performance or of ultimate recovery.

Forward-Looking Information – This press release contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words “will”, “would”, “expect”, “anticipate”, “intend”, “believe”, “plan”, “potential”, “outlook”, “forecast”, “estimate”, “budget” and similar expressions are intended to identify forward-looking statements or information. More particularly, and without limitation, this press release contains forward-looking statements and information concerning: current and future years’ guidance in respect of certain operational and financial metrics, including, but not limited to, commodity pricing, estimated average operating costs, estimated average royalty rate, estimated operations capital, estimated general and administrative costs, estimated quarterly and annual production and estimated number of Umbach horizontal wells drilled, completed and connected, capital investment plans, infrastructure plans, anticipated United States exports, pipeline capacity, price volatility mitigation strategy and cost reductions. Statements of “reserves” are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

The forward-looking statements and information in this press release are based on certain key expectations and assumptions made by Storm, including: prevailing commodity prices and exchange rates; applicable royalty rates and tax laws; future well production rates; reserve and resource volumes; the performance of existing wells; success to be expected in drilling new wells; the adequacy of budgeted capital expenditures to carrying out planned activities; the availability and cost of services; and the receipt, in a timely manner, of regulatory and other required approvals. Although the Company believes that the expectations and assumptions on which such forward-looking statements and information are based are reasonable, undue reliance should not be placed on these forward-looking statements and information because of their inherent uncertainty. In particular, there is no assurance that exploitation of the Company’s undeveloped lands and prospects will result in the emergence of profitable operations.

Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to the risks associated with the oil and gas industry in general such as: general economic conditions in Canada, the United States and internationally; operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to reserves, production, costs and expenses; health, safety and environmental risks; commodity price and exchange rate fluctuations; marketing and transportation of petroleum and natural gas and loss of markets; competition; ability to access sufficient capital from internal and external sources; geopolitical risk; stock market volatility; and changes in legislation, including but not limited to tax laws, royalty rates and environmental regulations.

Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect the operations or financial results of the Company are included or are incorporated by reference in the Company’s Annual Information Form dated March 31, 2017 and the MD&A dated March 1, 2018 for the period ended December 31, 2017 which are available on Storm’s SEDAR profile at and on Storm’s website at

The forward-looking statements and information contained in this press release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

For further information please contact:

Brian Lavergne
President & Chief Executive Officer

Michael J. Hearn
Chief Financial Officer

Carol Knudsen
Manager, Corporate Affairs

(403) 817-6145