CALGARY, Alberta, May 12, 2020 (GLOBE NEWSWIRE) — Storm Resources Ltd. (TSX:SRX)

Storm has also filed its unaudited condensed interim consolidated financial statements as at March 31, 2020 and for the three months then ended along with Management’s Discussion and Analysis (“MD&A”) for the same period. This information appears on SEDAR at and on Storm’s website at

Selected financial and operating information for the three months ended March 31, 2020 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 Ended
March 31, 2020
Three Months Ended
March 31, 2019
Revenue from product sales(1)   41,923   55,766  
Funds flow   16,889   16,517  
  Per share – basic and diluted ($)   0.14    0.14  
Net income   10,512   607  
  Per share – basic and diluted ($)   0.09    0.00  
Cash return on capital employed (“CROCE”)(2)   12 % 20 %
Return on capital employed (“ROCE”)(2)   7 % 8 %
Capital expenditures   26,475   16,944  
Debt including working capital deficiency(2)(3)   138,632   91,585  
Common shares (000s)      
  Weighted average – basic   121,557   121,557  
  Weighted average – diluted   121,557   121,853  
  Outstanding end of period – basic   121,557   121,557  
(Cdn$ per Boe)      
Revenue from product sales(1)   19.24   31.26  
Transportation costs   (4.97 )  (5.72 )
Revenue net of transportation   14.27   25.54  
Royalties   (0.97 ) (2.61 )
Production costs   (5.17 ) (6.09 )
Field operating netback(2)   8.13   16.84  
Realized gain (loss) on risk management contracts   1.26   (5.38 )
General and administrative   (0.86 ) (1.60 )
Interest and finance costs   (0.74 ) (0.61 )
Decommissioning expenditures   (0.04 )  
Funds flow per Boe   7.75   9.25  

Barrels of oil equivalent per day (6:1)

  23,946   19,823  
Natural gas production      
  Thousand cubic feet per day   115,957   96,537  
  Price (Cdn$ per Mcf)(1)   2.54   4.49  
Condensate production      
  Barrels per day   2,623   2,199  
  Price (Cdn$ per barrel)(1)   60.66   62.77  
NGL production      
  Barrels per day   1,998   1,534  
  Price (Cdn$ per barrel)(1)   3.27   31.43  
Wells drilled (net)   1.0   5.0  
Wells completed (net)   3.5    
  1. Excludes gains and losses on risk management contracts.
  2. Certain financial amounts shown above are non-GAAP measurements. See discussion of Non-GAAP Measurements on page 28 of the MD&A. CROCE and ROCE are presented on a 12-month trailing basis.
  3. Excludes the fair value of risk management contracts, decommissioning liability and lease liability.



Funds flow was largely unchanged from the first quarter of last year with higher production and lower production costs offset by lower NGL and natural gas prices.  

  • Production was 23,946 Boe per day, an increase of 7% from the previous quarter and an increase of 21% year over year.  This was consistent with guidance (24,000 to 25,000 Boe per day) with the increase resulting from the start-up of the Nig Gas Plant plus a full quarter of production from a four-well pad at Nig.  
  • Liquids production (field condensate plus gas plant NGL) totaled 4,621 barrels per day, an increase of 8% from the previous quarter and an increase of 24% year over year.  
  • Production from the most recent four wells in the Nig area continue to meet expectations since start-up in November 2019 with the IP150 averaging approximately 1,500 Boe per day sales (8% field condensate) for the three upper/mid Montney wells and approximately 1,000 Boe per day sales (30% field condensate) for the lower Montney well.     
  • Revenue net of transportation was $14.27 per Boe, a decline of $11.27 per Boe, or 44% from last year, mainly due to lower NGL and natural gas prices. The NGL price declined 90% as a result of lower propane prices and from larger pricing deductions during the current marketing year ending March 2020. The natural gas price declined 43% as a result of lower pricing in the Chicago and Sumas markets (60% of sales).  
  • Liquids represented 19% of sales volumes and 36% of production revenue (versus 19% and 30% respectively in the prior year period).
  • Production, general and administrative, and interest and finance costs were $6.77 per Boe, a year-over-year decline of $1.53 per Boe.  Production cost decreased $0.92 per Boe with start-up of the Nig Gas Plant and the previous year was higher due to an unplanned outage at the McMahon Gas Plant.
  • Hedging provided a realized gain of $2.7 million versus a realized loss of $9.6 million in the prior year.  The gain was from contracts for Chicago natural gas and WTI oil while the prior year loss was mainly from contracts for Sumas natural gas that were entered into before a failure on the Enbridge T-south pipeline in October 2018.
  • Funds flow was $16.9 million or $0.14 per share which was largely unchanged from last year with higher production and lower costs offsetting lower commodity prices.      
  • Net income was $10.5 million compared to $0.6 million in the prior year with the improvement primarily from a non-cash hedging gain of $10.5 million on the mark-to-market value of future hedging contracts which was partially offset by the deferred income tax expense of $3.9 million. 
  • Capital investment was $26.5 million (below guidance of $30 million) and included $11 million for the Nig Gas Plant project plus $9 million to complete and tie in a three-well pad at Umbach.
  • Total debt including working capital deficiency was $139 million or 2.1 times annualized quarterly funds flow and, including letters of credit, represents 73% utilization of the $205 million bank line.
  • Commodity price hedges have increased and during the remainder of 2020 protect approximately 42% of forecast production using the mid-point of guidance.  Hedges provide floor prices of approximately Cdn$2.90 per Mcf (15% higher than the first quarter average price) and WTI Cdn$64.00 per barrel in 2020 with approximately half of the hedges being collars which provide exposure to higher prices.


Umbach, Nig and Fireweed Areas, Northeast British Columbia

Storm’s land position is prospective for liquids-rich natural gas from the Montney formation and totals 121,000 net acres (172 net sections) with 79 horizontal wells (74.4 net) drilled to date.  

First quarter field activity was mainly focused on completing the Nig Gas Plant and associated sales gas and NGL pipelines with start-up occurring February 22. In addition, a three-well pad (3.0 net) was completed and pipeline connected on the west side of Umbach. 

During the quarter, two new wells started production leaving an inventory at the end of the quarter of two (2.0 net) drilled Montney horizontal wells that had not started producing which included one (1.0 net) completed well.

At Umbach (100% working interest), produced raw natural gas contains 1.2% H2S with approximately 85% directed to the McMahon Gas Plant and 15% to the Stoddart Gas Plant where firm processing commitments total 80 Mmcf raw gas per day (65 Mmcf per day at McMahon and 15 Mmcf per day at Stoddart). There remains significant capacity for future growth with field compression capacity totaling 150 Mmcf per day raw gas while throughput in the first quarter averaged 103 Mmcf per day (including 28 Mmcf per day from the Nig area that has been redirected to the new gas plant). During the second half of 2020, three horizontal wells (3.0 net) will be drilled depending on commodity prices and forecast funds flow.

At Nig (100% working interest), produced raw natural gas contains 0.1% H2S and is directed to the recently constructed 50 Mmcf per day sour gas plant that started up February 22. Total estimated cost of the Nig Gas Plant project is $84 million ($11 million in 2018, $61 million in 2019, $12 million in 2020) which is a reduction from the previous estimate of $86 million but higher than the initial estimate of $81 million. The project includes the facility, an eight-kilometre sales gas pipeline and a horizontal well for acid gas injection.  At full capacity, incremental production versus processing at the McMahon Gas Plant is expected to be 1,500 Boe per day (50% propane, 20% butane, 5% condensate, 25% sales gas) as a result of higher NGL recovery and reduced gas shrinkage.  In addition, eliminating third-party processing fees results in an operating cost of less than $2.00 per Boe which reduces the corporate operating cost.  Propane will be sold at the Far East Asia Index price via the Altagas Ridley Island Export Terminal (RIPET).  Since start-up, inlet volumes have gradually ramped up to 40 to 45 Mmcf per day raw and are expected to reach full capacity by the end of the third quarter. The plant has been ‘warmed up’ since mid-April to decrease NGL recovery (propane and butane) by approximately 8 Bbls per Mmcf sales as a result of current low liquids prices. Activity for the remainder of 2020 is expected to include drilling and completing four wells (4.0 net) this summer.

At Fireweed (50% working interest), first quarter activity included drilling two horizontal wells (1.0 net), completing one well (0.5 net), and starting site preparation for a 50 Mmcf per day field compression facility (expandable to 100 Mmcf per day).  Further activity in 2020 has been deferred as a result of the rapid decline in oil prices.  There are currently three standing wells (1.5 net) with two wells (1.0 net) having been completed with test results meeting expectations for the area (strong gas rates with higher condensate-gas ratios). Based on production history from offsetting horizontal wells, first year average field condensate-gas ratios are expected to be 30 to 70 barrels per Mmcf raw which is 100% to 400% higher than at Umbach.  Investment in 2020 is expected to total $6 million net with all of this incurred in the first quarter.

A summary of horizontal well results at Nig and Umbach is provided below. IP90 and IP180 rates are less reliable indicators of relative longer-term performance since wells are initially rate restricted to manage fluid rates. Note that the 2019 wells at Nig in the upper/mid Montney were drilled on tighter inter-well spacing versus the 2018 wells (400 metres versus 465 metres) which may reduce longer-term rates and ultimate recovery.


Year of Completion


IP90 Cal Day


IP180 Cal Day


IP365 Cal Day

Umbach 2017 – 2018
19 hz’s
34 1895 m 4.6 Mmcf/d(1)
24 Bbls/Mmcf(2)
19 hz’s
4.4 Mmcf/d(1)
20 Bbls/Mmcf(2)
19 hz’s
4.0 Mmcf/d(1)
15 Bbls/Mmcf(2)
19 hz’s
Nig 2018 upper
3 hz’s
37 2180 m 8.1 Mmcf/d(1)
29 Bbls/Mmcf(2)
3 hz’s
8.2 Mmcf/d(1)
25 Bbls/Mmcf(2)
3 hz’s
7.5 Mmcf/d(1)
21 Bbls/Mmcf(2)
3 hz’s
Nig 2019 upper/mid
3 hz’s
42 2240 m 8.1 Mmcf/d(1)
20 Bbls/Mmcf(2)
3 hz’s
Nig 2019 lower
1 hz
42 2280 m 5.5 Mmcf/d(1)
57 Bbls/Mmcf(2)
1 hz
  1. Raw gas rate.
  2. Bbls/Mmcf is the condensate-gas ratio or barrels of field condensate per Mmcf raw.
  3. Shut in mid-April 2020 after 140 days of production as a result of the low condensate price.

Based on results from the 2017 and 2018 wells, Storm management is using 8 Bcf and 14 Bcf raw gas type curves (internal estimates) to forecast production at Umbach and Nig respectively. More detail on well performance and management’s type curve is available in the presentation on Storm’s website at


Commodity price hedges are used to support longer-term growth by protecting pricing on up to 50% of current production for the next 18 months and up to 25% for 19 to 36 months forward (future production growth is not hedged). The current hedge position is shown below (excludes price differential contracts which are shown in the financial statements) with hedges for the remainder of 2020 protecting approximately 42% of forecast annual production using the mid-point of guidance. Hedges provide floor prices of approximately Cdn$2.90 per Mcf and WTI Cdn$64.00 per barrel in 2020 (half of the hedges are collars) and Cdn$3.10 per Mcf in 2021 (there are no WTI hedges in 2021).

Q2 – Q4,



Crude Oil


633 Bpd WTI Cdn$66.79/Bbl floor, Cdn$77.08 ceiling
822 Bpd WTI Cdn$61.19/Bbl
Natural Gas


8,670 Mmbtu/d (7.5 Mmcf/d) Chicago Cdn$3.33/Mmbtu
2,200 Mmbtu/d (1.9 Mmcf/d) Chicago US$1.54/Mmbtu floor, US$1.96 ceiling
15,400 Mmbtu/d (13.3 Mmcf/d) Chicago Cdn$2.48/Mmbtu floor, Cdn$3.01 ceiling
6,300 Mmbtu/d (5.5 Mmcf/d) NYMEX US$1.95/Mmbtu floor, US$2.48 ceiling
2,500 Mmbtu/d (2.2 Mmcf/d) NYMEX Cdn$2.75/Mmbtu floor, Cdn$3.26 ceiling
2,560 Mmbtu/d (2.2 Mmcf/d) NYMEX US$2.45/Mmbtu
1,110 Mmbtu/d (1.0 Mmcf/d) NYMEX Cdn$2.86/Mmbtu
2,000 Mmbtu/d (1.7 Mmcf/d) Sumas Cdn$3.07/Mmbtu
10,400 GJ/d (8.5 Mmcf/d) AECO Cdn$1.77/GJ
2,000 GJ/d (1.6 Mmcf/d) AECO Cdn$2.02/GJ floor, Cdn$2.49 ceiling
9,200 GJ/d (7.5 Mmcf/d) Station 2 Cdn$1.79/GJ
1,550 GJ/d (1.2 Mmcf/d) Station 2 Cdn$1.80/GJ floor, Cdn$2.47 ceiling
2021 Natural Gas


17,600 Mmbtu/d (15.2 Mmcf/d) Chicago Cdn$3.20/Mmbtu
3,620 Mmbtu/d (3.1 Mmcf/d) Chicago Cdn$3.53/Mmbtu floor, Cdn$4.06 ceiling
750 Mmbtu/d (0.6 Mmcf/d) NYMEX US$2.40/Mmbtu floor, US$2.75 ceiling
1,250 Mmbtu/d (1.1 Mmcf/d) NYMEX Cdn$3.45/Mmbtu floor, Cdn$4.10 ceiling
2,080 Mmbtu/d (1.8 Mmcf/d) NYMEX US$2.32/Mmbtu
6,460 Mmbtu/d (5.6 Mmcf/d) NYMEX Cdn$3.35/Mmbtu
7,670 GJ/d (6.3 Mmcf/d) AECO Cdn$2.16/GJ
2,250 GJ/d (1.8 Mmcf/d) AECO Cdn$2.02/GJ floor, Cdn$2.49 ceiling
21,670 GJ/d (17.8 Mmcf/d) Station 2 Cdn$1.96/GJ
1,750 GJ/d (1.4 Mmcf/d) Station 2 Cdn$1.80/GJ floor, Cdn$2.47 ceiling


Production in the second quarter of 2020 is forecast to average 23,000 to 25,000 Boe per day with capital investment expected to be less than $3 million. Production in April was approximately 24,500 Boe per day based on field estimates and is expected to be lower in May and June as liquids production is being reduced as much as possible to avoid sales at very low prices after deducting transportation costs and price differentials (WTI has averaged approximately US$23.00 per barrel to date in May with the Edmonton condensate differential at -US$16.55 per barrel). Liquids production is being reduced by shutting in the lower Montney well at Nig (850 Boe per day sales, 37% liquids) and restricting wells with the highest condensate-gas ratios. 

Updated guidance for 2020 is provided below.  Forecast production includes the effect of a planned 25-day maintenance outage at the McMahon Gas Plant in September 2020 and from NGL recovery being reduced after ‘warming up’ the Nig Gas Plant. The ceiling for forecast fourth quarter production was reduced to 28,000 Boe per day from 30,000 Boe per day as a result of the deferral of activity at Fireweed. Capital investment is intended to be approximately equal to or less than forecast funds flow and is being reduced approximately $25 million by deferring activity at Fireweed for up to one year (first production in the second half of 2021 or in early 2022). Forecast pricing provided below reflects actual prices to date plus the approximate forward strip for the remainder of the year.   

2020 Guidance  

February 27, 2020       Current
May 12, 2020
Cdn$/US$ exchange rate   0.76     0.72  
Chicago daily natural gas – US$/Mmbtu $1.90   $2.05  
Sumas monthly natural gas – US$/Mmbtu $1.90   $2.20  
AECO daily natural gas – Cdn$/GJ $1.75   $2.20  
Station 2 daily natural gas – Cdn$/GJ $1.65   $2.15  
WTI – US$/Bbl $50.50   $30.50  
Edmonton condensate diff – US$/Bbl   ($4.00 )   ($4.50 )
Est revenue net of transport (excl hedges) – $/Boe   $13.50 – $13.75       $12.00 – $13.00  
Est production costs – $/Boe   $4.50 – $4.75       $4.50 – $4.75  
Est royalty rate (% revenue net transportation)   5% – 7%       5% – 6%  
Est mid-point field operating netback – $/Boe $8.20   $7.20  
Est realized hedging gains or (losses) – $ million   $5.0 – $6.0       $11.0 – $12.0  
Est cash G&A – $ million    $6.0 – $7.0       $6.0 – $7.0  
2020 Guidance (continued)  

February 27, 2020

May 12, 2020
Est interest expense – $ million $7.0 – $8.0 $7.0 – $8.0
Est capital investment (excluding A&D) – $ million


$75.0 – $85.0
(Nig GP $14.0 million)
$52.0 – $60.0
(Nig GP $12.0 million)
Forecast fourth quarter Boe/d
Forecast fourth quarter liquids Bbls/d
25,000 – 30,000
5,300 – 6,300
25,000 – 28,000
5,100 – 5,600
Forecast annual Boe/d
Forecast annual liquids Bbls/d
23,500 – 26,000
4,900 – 5,500
23,500 – 26,000
4,500 – 5,000
Est annual funds flow – $ million $62.0 – $69.0 (1) $59.0 – $66.0 (1)
Horizontal wells drilled – gross
Horizontal wells completed – gross
Horizontal wells starting production – gross
6 – 10 (4.0 – 8.5 net)
8 – 10 (6.5 – 8.5 net)
 5 – 10 (5.0 – 8.5 net)
6 – 9 (5.0 – 8.0 net)
8 (7.5 net)
7 (7.0 net)

   (1)    Based on the range for forecast annual production and using the mid-point for each of the estimated field operating netback, estimated cash G&A, estimated hedging gain or loss and estimated interest expense.

Guidance History




Station 2





($ million)

Funds Flow
($ million)

Forecast Annual

Nov 12, 2019 $2.45 $1.60 $54.00 $75.0 – $90.0 not provided 24,000 – 26,000
Feb 27, 2020 $1.90 $1.65 $50.50 $75.0 – $85.0 $62.0 – $69.0 23,500 – 26,000
May 12, 2020 $2.05 $2.15 $30.50 $52.0 – $60.0 $59.0 – $66.0 23,500 – 26,000

Capital investment in 2020 will be allocated as follows:

  • $6 million at Fireweed in the first quarter to drill two horizontal wells (1.0 net) and complete one well (0.5 net);
  • $36 million at Nig includes $12 million to complete the gas plant (100% working interest), drill four horizontal wells (4.0 net) and complete and pipeline connect four wells (4.0 net); and
  • $10 – $18 million at Umbach to complete and pipeline connect three horizontal wells (3.0 net) plus drill three horizontal wells (3.0) which are contingent on commodity prices and forecast funds flow.

Firm pipeline capacity and marketing arrangements will result in approximately 60% of forecast natural gas production in 2020 being sold into US markets and the remaining 40% in Western Canadian markets (52% directed to Chicago, 18% to BC Station 2, 17% to AECO, 8% to Sumas and 5% to Alliance ATP).

The recent, rapid decline in oil prices has materially reduced NGL and condensate prices. Based on the current forward strip, Storm’s revenue from condensate plus NGL is forecast to decline to approximately 15% of total revenue during the remainder of 2020 versus 36% in the first quarter.  In response, liquids production has been reduced as much as possible while maximizing natural gas sales which includes reducing NGL recovery, storing condensate and reducing production from wells with higher condensate-gas ratios.  Hedges will also mitigate the effect of low liquids prices during the remainder of 2020 with a floor of approximately WTI Cdn$64.00 per barrel on 1,450 barrels per day while the Edmonton condensate differential to WTI was fixed at -Cdn$7.24 per barrel on 730 barrels per day.

Partially offsetting the effect of lower oil prices is stronger natural gas prices which have strengthened significantly over the last two months in anticipation of declining associated gas production from US oil producers and from liquids-rich natural gas producers in Canada where growth has been largely subsidized by revenue from liquids production. With the improvement in natural gas prices the hedge position was expanded and currently protects pricing during the remainder of 2020 on approximately 42% of forecast annual production versus 16% at the last update on February 27.

Previously, the emphasis was on growing liquids production to increase revenue and that was largely going to come from growth at Fireweed where condensate makes up a larger proportion of the sales volume than at Nig and Umbach.  With the decline in the WTI oil price reducing expected rates of return and forecast funds flow for 2020, activity at Fireweed will be deferred by up to one year with an option to accelerate depending on commodity prices.  Partially offsetting this, the improvement in the Station 2 natural gas price has improved rates of return at Umbach and three horizontal wells are being planned for drilling in the second half of 2020 depending on commodity prices and forecast funds flow (completions in early 2021).     

Regarding the COVID-19 pandemic, the impacts to date for Storm have been relatively minor. The health and safety of everyone working at Storm has always been and will continue to be a priority and since March 13, the majority of office employees transitioned to working remotely while field employees have adjusted procedures and travel arrangements to minimize contact with others.  The efforts of everyone at Storm in managing the challenges caused by the pandemic are greatly appreciated. 

The objective remains to increase asset value per share by converting resource into per-share growth of funds flow and reserves value. Commodity price volatility continues to be one of the biggest risks to manage with the recent reversal of oil and natural gas prices requiring that the near-term growth plan be changed to adapt to the ‘new normal’.  Shifting the operational focus away from growing liquids revenue will take some time to execute and will be challenging given that liquids revenue was a big contributor to funding Storm’s growth over the last several years (and other producers to an even greater extent).  However, Storm’s main competitive advantage has not changed and remains a large, high quality land position in the Montney fairway where significant longer-term upside remains given PDP reserves are recognized only in the upper Montney on approximately 8% of the total land position.


Brian Lavergne,
President and Chief Executive Officer

May 12, 2020

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”, “CROCE”, “ROCE”, 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 May 12, 2020 for the period ended March 31, 2020 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 production costs, estimated average royalty rate, estimated operations capital, estimated general and administrative costs, estimated quarterly and annual production and estimated number of 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 carry 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 30, 2020 and the MD&A dated May 12, 2020 for the period ended March 31, 2020 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

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