CALGARY, Alberta, Nov. 12, 2019 (GLOBE NEWSWIRE) — Storm Resources Ltd. (TSX:SRX)

Storm has also filed its unaudited condensed interim consolidated financial statements as at September 30, 2019 and for the three and nine 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 and nine months ended September 30, 2019 appears below and should be read in conjunction with the related financial statements and MD&A.


Thousands of Cdn$, except volumetric and per-share amounts Three Months to
Sept. 30, 2019
  Three Months to
Sept. 30, 2018
  Nine Months to Sept. 30, 2019   Nine Months to
Sept. 30, 2018
Revenue from product sales(1) 31,417   51,253   124,751   151,459  
Funds flow 11,973   22,227   41,080   69,151  
Per share – basic and diluted ($)  0.10   0.18   0.34   0.57  
Net income (loss) (64 ) 7,174   8,407   13,253  
Per share – basic and diluted ($)  (0.00 ) 0.06   0.07   0.11  
Cash return on capital employed (“CROCE”)(2) 15 % 21 % 15 % 21 %
Return on capital employed (“ROCE”)(2) 9 % 6 % 9 % 6 %
Capital expenditures 32,841   21,845   72,930   47,663  
Debt including working capital deficiency(2)(3) 123,342   84,648   123,342   84,648  
Common shares (000s)        
Weighted average – basic 121,557   121,557   121,557   121,557  
Weighted average – diluted 121,557   121,557   121,557   121,557  
Outstanding end of period – basic 121,557   121,557   121,557   121,557  
(Cdn$ per Boe)        
Revenue from product sales(1) 18.36   27.24   23.50   27.88  
Transportation costs (5.83 ) (5.98 ) (5.84 ) (5.94 )
Revenue net of transportation 12.53   21.26   17.66   21.94  
Royalties 0.19   (1.03 ) (0.92 ) (1.28 )
Production costs (5.88 ) (5.54 ) (5.96 ) (5.52 )
Field operating netback(2) 6.84   14.69   10.78   15.14  
Realized gain (loss) on risk management contracts 1.64   (1.73 ) (1.35 ) (0.89 )
General and administrative (0.79 ) (0.66 ) (1.02 ) (0.92 )
Interest and finance costs (0.69 ) (0.49 ) (0.67 ) (0.61 )
Funds flow per Boe 7.00   11.81   7.74   12.72  
Barrels of oil equivalent per day (6:1) 18,596   20,455   19,443   19,900  
Natural gas production        
Thousand cubic feet per day 91,053   101,905   95,013   98,154  
Price (Cdn$ per Mcf)(1) 2.42   3.21   3.19   3.39  
Condensate production        
Barrels per day 1,856   2,059   2,044   2,035  
Price (Cdn$ per barrel)(1) 63.45   84.97   65.81   82.46  
NGL production        
Barrels per day 1,564   1,412   1,563   1,506  
Price (Cdn$ per barrel)(1) 2.29   38.64   12.59   35.92  
Wells drilled (net) 1.0     6.0    
Wells completed (net) 5.0   5.0   5.0   8.0  
  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 26 of the MD&A.  CROCE and ROCE are presented on a 12-month trailing basis.
  3. Excludes the fair value of risk management contracts and lease liability.



Production and funds flow were reduced by a 14-day outage at the McMahon Gas Plant and from shutting in wells during several periods of very low natural gas prices at AECO and BC Station 2.  Construction of the 50 Mmcf per day Nig Gas Plant is ongoing with major equipment deliveries to the site beginning in September while start-up is planned for January 2020.  A four-well pad in the Nig area was completed in June and July; however, the pipeline tie-in was not finished until mid-November as a result of delays due to rain and wet field conditions. 

  • Production was 9% lower year over year and was within the guidance range for the quarter of 18,000 to 20,000 Boe per day.  Production was reduced by approximately 2,400 Boe per day due to an unplanned third-party outage at the McMahon Gas Plant (loss of 16,000 Boe per day for 14 days) and by approximately 800 Boe per day due to low natural gas prices at AECO and Station 2 (shut in 5,000 Boe per day for a total of 15 days).
  • Liquids production (field condensate plus gas plant NGL) represented 18% of total production and 36% of production revenue.
  • Three new horizontal wells have started producing in 2019 which has offset corporate declines.  A four-well pad at Nig (includes one well in the lower Montney) will start production in mid-November which is expected to increase fourth quarter production to 22,000 to 24,000 Boe per day (the first three wells at Nig had average first year calendar day rates of 1,400 Boe per day sales). 
  • Revenue per Boe declined by 33% year over year.  The NGL price declined 94% primarily as a result of lower contracted butane and propane prices during the current marketing period which runs from April 2019 to March 2020.  The realized natural gas price declined by 25%, however, was still approximately 270% higher than the Station 2 price as a result of diversified sales.    
  • Controllable cash costs including transportation, production, general and administrative, and interest were $13.19 per Boe which is an increase from $12.67 per Boe in the prior year.  Higher production cost was due to the effect of lower production levels on fixed costs while higher interest and finance costs were the result of debt increasing during the construction of the Nig Gas Plant.
  • Funds flow was $12.0 million, or $0.10 per share, a decrease of 46% on a per-share basis year over year with the decrease largely the result of lower commodity prices and production being reduced by the McMahon Gas Plant outage.      
  • Net income was nil compared to $7.2 million in the prior year and is primarily attributable to lower commodity prices reducing the funds flow netback to $7.00 per Boe from $11.81 per Boe last year. 
  • Capital investment was $32.8 million which included $26.7 million for the Nig Gas Plant project (includes $4.3 million to drill and complete a horizontal well for acid gas disposal) plus $6.1 million to finish completing and pipeline connect a four-well pad at Nig.
  • Year-to-date capital investment is $72.9 million with 60% invested in future growth opportunities (Nig Gas Plant project $42.1 million plus Fireweed $1.4 million).
  • Total debt which includes the working capital deficiency was $123 million, represents approximately 60% utilization of the $205 million bank line, and is an increase from $91.0 million at the start of the year due to the large proportion of 2019 capital investment being directed to the Nig Gas Plant project.  Total debt was 2.6 times annualized quarterly funds flow and is expected to decline below 2.0 times following completion of the Nig Gas Plant which increases funds flow by reducing per-Boe operating costs and improving liquids recovery.


Umbach, Nig and Fireweed Areas, Northeast British Columbia

Storm’s land position is prospective for liquids-rich natural gas from the Montney formation and totaled 121,000 net acres (172 net sections) at the end of the quarter with 78 horizontal wells (73.9 net) drilled to date.  

Third quarter field activity was mainly focused on the Nig Gas Plant project which included site preparation, delivery of major equipment to the site, and drilling and completing a horizontal well for acid gas disposal.  In addition, completion of a pad at Nig with four horizontal wells (4.0 net) was finished in July and the pipeline tie-in was finished in mid-November after being delayed by rain and wet field conditions.  The four-well pad will evaluate different intervals in the Montney with two wells in the upper, one well in the mid and one well in the lower. 

At the end of the quarter, there was an inventory of nine (8.5 net) drilled Montney horizontal wells that had not started producing which included five (4.5 net) completed wells.  During the quarter, there were no new wells that started production.

Field activity in the fourth quarter will include the ongoing construction of the 50 Mmcf per day Nig Gas Plant and finishing the pipeline tie-in of a four-well pad at Nig.

At Umbach (100% working interest), production in the quarter was 16,430 Boe per day with 2,980 barrels per day of liquids (18%) and was reduced by the 14-day unplanned outage at the McMahon Gas Plant.  There are currently four standing wells (4.0 net) with none having been completed.  Produced raw natural gas is sour (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 plus 15 Mmcf per day at Stoddart).  Field compression capacity totals 150 Mmcf per day raw gas with throughput in the second quarter averaging 94 Mmcf per day raw gas (includes 11 Mmcf per day raw from Nig). 

At Nig (100% working interest), production from the three producing wells averaged 2,070 Boe per day with 430 barrels per day of liquids (21%) in the quarter which was reduced by the outage at the McMahon Gas Plant plus the wells were shut in for varying periods to complete an adjacent four-well pad.  At the end of the quarter there were four standing and completed wells (4.0 net) which will start production in mid-November.  Produced raw natural gas contains approximately 0.2% H2S.  The sour gas plant that is under construction has capacity of 50 Mmcf per day and start-up is planned for January 2020.  Total estimated cost of the Nig Gas Plant project has increased to $86 million (was $81 million) with $11 million invested in 2018, $70 million planned for 2019 and the remaining $5 million in 2020.  The project cost increased as a result of a higher cost for site construction as well as scope changes and now includes $77 million for the gas plant, $5 million for an acid gas injection well and $4 million for a sales pipeline.  Sales volume from the gas plant is forecast to be 10,500 Boe per day with an estimated operating cost of less than $2.00 per Boe reducing the corporate operating cost to approximately $4.25 per Boe.  Liquids recovery will improve and is forecast to be 27% of total production from the gas plant (43% condensate, 57% NGL).

At Fireweed (50% working interest), construction of a 50 Mmcf per day field compression facility (expandable to 100 Mmcf per day) is anticipated to begin in mid-2020 with start-up in late 2020 or early 2021.  The estimated cost of the facility is $38 million which also includes an access road and sales pipeline.  There is currently one standing well (0.5 net) with a length of 1,520 metres (36 frac stages) that has been completed which averaged 10.9 Mmcf per day raw gas, 660 barrels per day of field condensate and 1,140 barrels per day of frac water over the last 12 hours of a six-day clean-up (final flowing casing pressure of 4,800 kPa).  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.

A summary of horizontal well results at Nig and Umbach is provided below.  Note that IP90 and IP180 rates are not reliable indicators of relative performance since wells are initially rate restricted for up to nine months to manage fluid rates.  In addition, recent wells have been affected by outages which have totaled 43 days to date in 2019.

Year of Completion Frac
IP90 Cal Day IP180 Cal Day IP365 Cal Day
Umbach 2014 – 2016
33 hz’s(1)
22 1350 m 4.9 Mmcf/d(2)
19 Bbls/Mmcf(3)
33 hz’s
4.3 Mmcf/d(2)
16 Bbls/Mmcf(3)
33 hz’s
3.4 Mmcf/d(2)
13 Bbls/Mmcf(3)
33 hz’s
Umbach 2017 – 2018
19 hz’s
34 1895 m 4.6 Mmcf/d(2)
24 Bbls/Mmcf(3)
19 hz’s
4.3 Mmcf/d(2)
20 Bbls/Mmcf(3)
18 hz’s
4.1 Mmcf/d(2)
14 Bbls/Mmcf(3)
14 hz’s
Nig 2018
3 hz’s
37 2180 m 8.1 Mmcf/d(2)
29 Bbls/Mmcf(3)
3 hz’s
8.2 Mmcf/d(2)
25 Bbls/Mmcf(3)
3 hz’s
7.5 Mmcf/d(2)
21 Bbls/Mmcf(3)
3 hz’s
  1. This table provides analysis of upper Montney wells only (2014 – 2016 wells exclude a middle Montney well).
  2. Raw gas rate.
  3. Bbls/Mmcf is the field condensate-gas ratio or barrels of field condensate per Mmcf raw.

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 with the objective being to protect pricing on 50% of current production for the next 12 months and 25% for 13 to 24 months forward (future production growth is not hedged).  The current hedge position (excluding price differential contracts which are shown in the financial statements) protects approximately 41% of forecast production for the fourth quarter of 2019 and 14% of forecast production for 2020.

Q4 2019



Crude Oil


850 Bpd WTI Cdn$73.28/Bbl floor, Cdn$87.95/Bbl ceiling
650 Bpd WTI Cdn$81.51/Bbl
Propane 200 Bpd Conway Cdn$42.87/Bbl
Natural Gas 38,000 Mmbtu/d (32.0 Mmcf/d) Chicago Cdn$3.24/Mmbtu
8,500 Mmbtu/d (7.2 Mmcf/d) Sumas Cdn$2.67/Mmbtu
1,000 GJ/d (0.8 Mmcf/d) AECO Cdn$2.00/GJ
3,670 GJ/d (2.9 Mmcf/d) AECO Cdn$1.77/GJ floor, $2.28/GJ ceiling
7,300 GJ/d (5.8 Mmcf/d) Station 2 Cdn$1.93/GJ
2020 Crude Oil


375 Bpd WTI Cdn$71.07/Bbl floor, Cdn$81.21/Bbl ceiling
375 Bpd WTI Cdn$71.92/Bbl
Natural Gas 10,750 Mmbtu/d (9.1 Mmcf/d) Chicago Cdn$3.33/Mmbtu
2,000 Mmbtu/d (1.7 Mmcf/d) NYMEX US$2.49 floor, US$2.62 ceiling
1,750 Mmbtu/d (1.5 Mmcf/d) Sumas Cdn$3.94/Mmbtu
375 GJ/d (0.3 Mmcf/d) AECO Cdn$2.00/GJ
1,375 GJ/d (1.1 Mmcf/d) AECO Cdn$1.77/GJ floor, $2.28/GJ ceiling
3,250 GJ/d (2.6 Mmcf/d) Station 2 Cdn$1.92/GJ
  1. The Alliance Pipeline tariff to Chicago is approximately Cdn$1.20 per Mmbtu including the cost of fuel.

Firm transportation commitments for natural gas provide sales diversification and are summarized below for 2020:

Alliance to Chicago(1) 57 Mmcf/d
Enbridge T-north to Station 2 18 Mmcf/d
Enbridge T-north & TCPL to AECO 14 Mmcf/d
Enbridge T-north to Station 2/Sumas(2) 12 Mmcf/d
Alliance to ATP 5 Mmcf/d
Total 106 Mmcf/d
  1. When available, Preferential Interruptible Service (‘PITS’) adds up to 14 Mmcf/d of capacity.
  2. Deliver at Station 2 for Sumas price less US$0.69/Mmbtu.


Production in the fourth quarter of 2019 is forecast to average 22,000 to 24,000 Boe per day with capital investment estimated to be $32 to $37 million (approximately 73% allocated to the Nig Gas Plant project).  Production is below previous guidance mainly because of shut-ins during October due to the low natural gas price at Station 2 ($0.36 per GJ).  

Updated guidance for 2019 is provided below.  Changes include reducing forecast fourth quarter production due to low natural gas prices at Station 2 and updating forecast pricing to reflect actual prices to date plus the approximate forward strip for the remainder of the year.  Approximately 70% of estimated capital investment is funding future growth (Nig Gas Plant project $70 million plus Fireweed $5 million).

2019 Guidance    
August 13, 2019
November 12, 2019
Cdn$/US$ exchange rate 0.755 0.755
Chicago daily natural gas – US$/Mmbtu $2.45 $2.45
Sumas monthly natural gas – US$/Mmbtu $3.40 $3.50
AECO daily natural gas – Cdn$/GJ $1.55 $1.65
Station 2 daily natural gas – Cdn$/GJ $1.00 $0.90
WTI – US$/Bbl $55.00 $56.00
Edmonton condensate diff – US$/Bbl -$5.10 -$4.20
Est revenue net of transport (excl hedges) – $/Boe $16.50 – $17.00 $17.25 – $17.75
Est operating costs – $/Boe $5.75 – $6.00 $5.75 – $6.00
Est royalty rate (% revenue net transportation) 5% – 7% 5% – 6%
Est mid-point field operating netback – $/Boe $9.87 $10.65
Est hedging loss – $ million $4.0 – $5.0 $6.5 – $7.5
Est cash G&A  – $ million  $6.0 – $6.5 $6.5 – $7.0
Est interest expense – $ million $5.5 – $6.5 $5.0 – $5.5
Est capital investment (excl A&D) – $ million $110.0 $105.0 – $110.0
Forecast fourth quarter production – Boe/d
% liquids
23,000 – 25,000
22,000 – 24,000
Forecast annual production – Boe/d
% liquids
20,000 – 22,000
20,000 – 22,000
Est annual funds flow – $ million $55.0 – $61.0(1) $58.7 – $64.5(1)
Horizontal wells drilled – gross
Horizontal wells completed – gross
Horizontal wells starting production – gross
 9 (7.5 net)
 8 (6.5 net)
 7 (7.0 net)
 6 (6.0 net)
 5 (5.0 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
Capital Investment
($ million)
Funds Flow
($ million)
Forecast Annual
Nov 13, 2018 $ 2.50 $ 1.25 $ 60.00 $ 128.0 $ 72.0 – $88.0 21,000 – 24,000
Feb 28, 2019 $ 2.60 $ 1.25 $ 55.00 $ 128.0 $ 67.0 – $79.0 21,000 – 24,000
May 14, 2019 $ 2.65 $ 1.20 $ 55.00 $ 128.0 $ 65.0 – $77.0 21,000 – 24,000
Aug 13, 2019 $ 2.45 $ 1.00 $ 55.00 $ 110.0 $ 55.0 – $61.0 20,000 – 22,000
Nov 12, 2019 $ 2.45 $ 0.90 $ 56.00 $ 105.0 – $110.0 $ 58.7 – $64.5 20,000 – 22,000

Natural gas prices have steadily declined since last winter primarily because of supply growth exceeding demand growth in both the US and Western Canada with price volatility amplified at AECO and Station 2 as a result of recurring pipeline restrictions and outages (several days of negative pricing).  There are indications that supply growth in the US is slowing while Western Canadian production has been declining since mid-summer which has recently improved the AECO price and narrowed the NYMEX-AECO price differential.  Future pricing for 2020 is approximately $1.85 per GJ at AECO and $1.60 per GJ at Station 2 which is materially higher than pricing to date in 2019 ($1.44 per GJ at AECO and $0.81 per GJ at Station 2).   Station 2 pricing could continue to improve now that repairs on the T-south pipeline to Sumas have been completed (the failure in October 2018 reduced throughput by 15% to as much as 45%) and with expected start-up of the NGTL North Montney extension into northeast British Columbia in early 2020 (delayed from initial start-up date in mid-September 2019).  Although only 18% of year-to-date natural gas sales has been at Station 2, most of Storm’s incremental production growth will be directed to Station 2.

Capital investment in 2020 is expected to be $75 to $90 million (previous estimate was $80 million) which will be approximately equal to estimated funds flow at current strip pricing (WTI US$54/Bbl, Chicago US$2.45/Mmbtu, AECO $1.85/GJ, Station 2 $1.60/GJ, Edmonton condensate WTI –US$5/Bbl, Cdn$0.76 per US$1).  Investment in 2020 includes:

  • $35 to $50 million at Fireweed which includes constructing a 50 Mmcf per day field compression facility that is expandable to 100 Mmcf per day (50% working interest), drilling four to eight horizontal wells (2.0 to 4.0 net), and completing three to seven wells (1.5 to 3.5 net);
  • $28 to $40 million at Nig and Umbach which includes drilling four horizontal wells (4.0 net) and completing three to seven horizontal wells (3.0 to 7.0 net).

Capital investment in both 2019 and 2020 has been reduced from earlier estimates as a result of 2019 funds flow being lower than initial expectations due to the unplanned outages at the McMahon Gas Plant and lower commodity prices.  This delays growth from Fireweed with first production now expected in late 2020 or early 2021 (previously expected to be in the second half of 2020).  Adjusting capital investment is the main way to maintain a strong balance sheet (an important part of Storm’s business strategy) given that commodity prices and funds flow are less controllable.

Total debt exiting 2019 is forecast to be below 2.0 times annualized fourth quarter funds flow and is expected to decline further after start-up of the Nig Gas Plant which adds $15 to $20 million to 2020 funds flow depending on liquids pricing. 

Corporate production is forecast to average 22,000 to 24,000 Boe per day in the fourth quarter of 2019 (4,000 to 4,300 barrels per day of liquids) and is forecast to increase to 27,000 to 30,000 Boe per day in the fourth quarter of 2020 (5,700 to 6,300 barrels per day of liquids).  Average annual production in 2020 is forecast to be 24,000 to 26,000 Boe per day which represents an increase of approximately 25% from 2019 with liquids production increasing by approximately 45%.  This includes the impact of a planned 25-day maintenance outage at the McMahon Gas Plant in September 2020 (financial effect will be largely mitigated by the Nig Gas Plant) and assumes first production from Fireweed in late 2020 or early 2021 depending on the timing to construct infrastructure. 

The near-term plan remains focused on growing funds flow which will come from start-up of the Nig Gas Plant in early 2020 (reduces per-Boe operating costs and increases liquids production) and from first production at Fireweed in late 2020 or early 2021 (increases condensate production).  Although planned growth has been delayed as a result of reducing 2019 and 2020 capital investment, this was necessary to maintain a strong balance sheet in response to 2019 funds flow being reduced by unplanned outages at the McMahon Gas Plant and by lower commodity prices.  The start-up of Storm’s Nig Gas Plant (100% working interest) diversifies processing and will reduce the effect of any future outages at third-party gas processing plants. 


Brian Lavergne,
President and Chief Executive Officer

November 12, 2019

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 November 12, 2019 for the period ended September 30, 2019 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 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 29, 2019 and the MD&A dated November 12, 2019 for the period ended September 30, 2019 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.

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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