CALGARY, Alberta, Nov. 10, 2020 (GLOBE NEWSWIRE) — Storm Resources Ltd. (TSX:SRX)

Storm has also filed its unaudited condensed interim consolidated financial statements as at September 30, 2020 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 www.sedar.com and on Storm’s website at www.stormresourcesltd.com.

Selected financial and operating information for the three and nine months ended September 30, 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 to
Sept. 30, 2020
  Three Months to
Sept. 30, 2019
  Nine Months to
Sept. 30, 2020
  Nine Months to
Sept. 30, 2019
 

FINANCIAL
         
Revenue from product sales(1)   30,010   31,417   102,124   124,751  
Funds flow   6,681   11,973   34,474   41,080  
Per share – basic and diluted ($)   0.05   0.10   0.28   0.34  
Net income (loss)   (16,934 ) (64 ) (18,087 ) 8,407  
Per share – basic and diluted ($)   (0.14 ) (0.00 ) (0.15 ) 0.07  
Cash return on capital employed (“CROCE”)(2)   11%   15%   11%   15%  
Return on capital employed (“ROCE”)(2)(4)   (2% ) 9%   (2% ) 9%  
Capital expenditures   14,219   32,841   43,088   72,930  
Debt including working capital deficiency(2)(3)   137,983   123,342   137,983   123,342  
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  

OPERATIONS

         
(Cdn$ per Boe)          
Revenue from product sales(1)   17.14   18.36   16.72   23.50  
Transportation costs   (6.43 ) (5.83 ) (5.58 ) (5.84 )
Revenue net of transportation   10.71   12.53   11.14   17.66  
Royalties   (0.77 ) 0.19   (0.72 ) (0.92 )
Production costs   (4.84 ) (5.88 ) (4.83 ) (5.96 )
Field operating netback(2)   5.10   6.84   5.59   10.78  
Realized gain (loss) on risk management contracts   0.51   1.64   1.66   (1.35 )
General and administrative   (0.72 ) (0.79 ) (0.77 ) (1.02 )
Interest and finance costs   (1.08 ) (0.69 ) (0.81 ) (0.67 )
Decommissioning expenditures       (0.02 )  
Funds flow per Boe   3.81   7.00   5.65   7.74  
Barrels of oil equivalent per day (6:1)   19,027   18,596   22,291   19,443  
Natural gas production          
Thousand cubic feet per day   91,526   91,053   107,361   95,013  
Price (Cdn$ per Mcf)(1)   2.47   2.42   2.41   3.19  
Condensate production          
Barrels per day   1,637   1,856   2,186   2,044  
Price (Cdn$ per barrel)(1)   46.79   63.45   45.01   65.81  
NGL production          
Barrels per day   2,136   1,564   2,211   1,563  
Price (Cdn$ per barrel)(1)   10.95   2.29   6.87   12.59  
Wells drilled (net)   4.0   1.0   5.0   6.0  
Wells completed (net)     5.0   3.5   5.0  
Wells started production (net)       3.0   3.0  

(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 24 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.
(4) Includes a non-cash unrealized loss on risk management contracts of $21.4 million for the nine months ended September 30, 2020.

PRESIDENT’S MESSAGE

2020 THIRD QUARTER HIGHLIGHTS

Production, pricing and funds flow for the quarter were reduced by planned turnarounds at two third-party gas plants and a pipeline outage which reduced natural gas sales into higher priced Canadian markets. Cost structure continues to improve with lower production costs being realized following start-up of the Nig Creek Gas Plant in February 2020 while record low drilling and completion costs were realized for the four wells at Nig Creek. To date, the COVID-19 pandemic has had no direct impact on Storm’s operations.

  • Production was 19,027 Boe per day, a decrease of 20% from the previous quarter and an increase of 2% year over year. This was consistent with guidance of 19,000 to 21,000 Boe per day. Approximately 40% of corporate production was shut in during September for planned turnarounds at third-party gas plants.
  • Liquids production (condensate plus NGL) totaled 3,773 barrels per day and represented 20% of total production and 31% of total revenue. NGL production increased 37% from last year as a result of higher recoveries that are realized at the Nig Creek Gas Plant.
  • Capacity of the 100% working interest Nig Creek Gas Plant is now estimated to be 60 to 70 Mmcf raw per day based on throughput in September when several wells were redirected from Umbach during the third-party gas plant turnarounds. Design capacity was 50 Mmcf raw per day.
  • Nig Creek area sales averaged 7,845 Boe per day (41% of corporate production) at a production cost of $1.21 per Boe. Well productivity continues to meet or exceed expectations and results from the first well in the lower Montney (840 Boe per day sales with 33% liquids over the first 9 months) indicate that there is a second layer to develop. Four new wells (4.0 net) were recently drilled and completed and started producing in late October.
  • Drilling and completion costs for the four most recent wells at Nig Creek averaged $4.1 million based on field estimates which is a reduction of approximately 25% from last year’s average cost.
  • Revenue net of transportation was $10.71 per Boe, a 15% decline from last year mainly due to a lower condensate price and an increase in the transportation cost per Boe due to the third-party gas plant turnarounds which resulted in approximately $1.0 million of unused firm transportation. The realized natural gas price did not reflect the recent improvement in AECO and BC Station 2 prices given that 67% of sales were into the lower priced Chicago market, an increase from previous quarters as a result of an outage in September on Spectra’s T-north Fort St. John lateral to BC Station 2 (coincided with the third-party gas plant turnarounds).
  • Production, general and administrative, and interest and finance costs totaled $6.64 per Boe, a reduction of 10% year over year. Production costs per Boe declined 18% as a result of reduced third-party processing fees following start-up of the Nig Creek Gas Plant in February. The reduction would have been larger if not for the third-party gas plant turnarounds which reduced production resulting in approximately $1.2 million of unused firm processing.
  • Funds flow was $6.7 million, or $0.05 per share, a reduction from $12.0 million last year. With production largely unchanged, the reduction in production costs per Boe was more than offset by lower revenue net of transportation, an increase in royalties related to the timing of infrastructure royalty credits, and a reduced hedging gain.
  • Net loss was $16.9 million with the largest contributor to the loss being an unrealized (non-cash) hedging loss of $18.0 million which represents the change in the value of future hedging contracts from the previous quarter.
  • Capital investment was $14.2 million (within guidance of $10 to $15 million) with the majority, or $10.1 million, directed to drilling and starting the completions of four wells at Nig Creek.
  • Total debt including working capital deficiency was $138 million. With capital investment in 2020 being approximately equal to funds flow, debt is forecast to be approximately $130 million at year end which will represent 2.2 times forecast annual funds flow.
  • Hedges protect revenue on approximately 47% of forecast production for the fourth quarter of 2020 and 40% for 2021. The financial liability for future hedging contracts was $23.2 million, an $18.0 million increase from the previous quarter as a result of the recent improvement in the forward strip for commodity prices.

OPERATIONS REVIEW

Umbach, Nig Creek 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 83 horizontal wells (78.4 net) drilled to the end of the third quarter.

Field activity in the third quarter included drilling and starting the completions of four horizontal wells (4.0 net) in the Nig Creek area.

Fourth quarter activity will include finishing the completions and pipeline connections of the four wells at Nig Creek with production starting in late October. At Umbach, the first two or three wells (2.0 or 3.0 net) on a six-well pad will be drilled with completions planned for the first quarter of 2021.

At the end of the third quarter, there were eight Montney horizontal wells (6.5 net) that had not started producing which included four wells (4.0 net) at Nig Creek and three wells (1.5 net) at Fireweed. Completed wells included two (1.0 net) at Fireweed while completions were underway on four wells (4.0 net) at Nig Creek.

At Umbach (average 90% working interest), produced raw natural gas contains 1.2% H2S with approximately 80% directed to the McMahon Gas Plant and 20% to the Stoddart Gas Plant. Field compression capacity totals 150 Mmcf raw per day while firm processing commitments total 80 Mmcf raw gas per day (65 Mmcf per day at McMahon and 15 Mmcf per day at Stoddart). Third quarter volumes averaged 63 Mmcf raw per day and were reduced approximately 17 Mmcf raw per day by planned turnarounds at the McMahon and Stoddart Gas Plants in September. Activity in 2021 is expected to include drilling the remaining three or four wells (3.0 or 4.0 net) on a six-well pad and completing all six wells (6.0 net).

At Nig Creek (100% working interest), produced raw natural gas contains 0.1% H2S and is directed to the 100% working interest sour gas plant that started up in February 2020. Third quarter throughput averaged 42 Mmcf raw per day, sales were 7,845 Boe per day with liquids at 46 barrels per Mmcf sales, and the production cost was $1.21 per Boe. Estimated capacity of the gas plant has been revised higher to 60 to 70 Mmcf raw per day from design capacity of 50 Mmcf raw per day as a result of H2S content being lower than forecast. Higher capacity was tested during September with several wells from Umbach being redirected to the gas plant during the third-party gas plant outages. Future drilling is expected to include three to four wells in the mid/upper Montney each year to keep the gas plant full. The first well in the lower Montney has averaged 840 Boe per day sales over the first 9 months (including 200 barrels per day of condensate and 75 barrels per day of NGL) and the timing for further drilling will largely depend on the WTI oil price given that condensate is expected to represent 20% to 25% of the first year sales volume (versus 10% of corporate sales year to date). Activity in 2021 is expected to include adding a low pressure inlet with compression at the gas plant to increase rates from existing wells plus drilling and completing three wells (3.0 net) in the upper/mid Montney in the third quarter of 2021.

At Fireweed (50% working interest), activity was previously deferred by up to one year following the collapse in the WTI crude oil price in April 2020. 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 and Nig Creek. There are currently three standing wells (1.5 net) with two completed wells (1.0 net). In the third quarter of 2020, construction of an access road was restarted in anticipation of advancing development in 2021. Activity levels for 2021 are expected to be finalized before year end with preliminary plans including four drills (2.0 net), two completions (1.0 net), and constructing a 50 Mmcf raw per day field compression facility with associated pipelines (50% working interest). First production from the area could be realized as early as the fourth quarter of 2021.

HEDGING

The objective of the commodity price hedging program is to support longer-term growth by protecting revenue on up to 50% of current production for the next 18 months and up to 25% for 19 to 36 months forward. The current hedge position is shown below (excludes price differential contracts which are shown in the financial statements) with hedges for 2021 protecting approximately 40% of forecast production. Future production growth is not hedged and will receive actual pricing.

  Q4/20 2021
Natural Gas Hedges    
% Forecast Nat Gas Production 50% 45%
Collars 33,000 Mcf/d(1)
Floor Cdn$2.99 per Mcf(2)
Ceiling Cdn$3.68 per Mcf(2)
9,000 Mcf/d(1)
Floor Cdn$3.48 per Mcf(2)
Ceiling Cdn$4.15 per Mcf(2)
Fixed Price 28,000 Mcf/d(1)
Cdn$2.90 per Mcf(2)
48,700 Mcf/d(1)
Cdn$3.16 per Mcf(2)
Liquids Hedges    
% Forecast Liquids Production 37% 25%
Collars 800 Bpd
Floor WTI Cdn$57.81 per barrel
Ceiling WTI Cdn$67.60 per barrel
650 Bpd
Floor WTI Cdn$50.54 per barrel
Ceiling WTI Cdn$59.93 per barrel
Fixed Price 950 Bpd
WTI Cdn$59.75 per barrel
750 Bpd
WTI Cdn$53.02 per barrel
  200 Bpd Propane
Conway Cdn$28.25 per barrel
50 Bpd Propane
Conway Cdn$27.30 per barrel

(1) Using corporate average heat content 1.23 GJ per Mcf and 1.17 Mmbtu per Mcf.
(2) Hedges in US$ are converted using an exchange rate of Cdn$1.34 per US$1.

OUTLOOK

Production in the fourth quarter of 2020 is forecast to average 25,000 to 27,000 Boe per day with capital investment of approximately $15 million to finish the completion of a four-well (4.0 net) pad at Nig Creek and to drill two or three wells (2.0 or 3.0 net) at Umbach on a six-well pad.

Updated guidance for 2020 is provided below. Capital investment is expected to be approximately equal to or less than forecast funds flow. Forecast pricing reflects actual prices to date plus the approximate forward strip for the remainder of the year.

2020 Guidance    
  Current
August 13, 2020
Current
November 10, 2020
Cdn$/US$ exchange rate 0.74 0.75
Chicago daily natural gas – US$/Mmbtu $1.85 $1.90
AECO daily natural gas – Cdn$/GJ $2.00 $2.15
BC Station 2 daily natural gas – Cdn$/GJ $1.95 $2.15
WTI – US$/Bbl $38.50 $38.50
Edmonton condensate diff – US$/Bbl ($3.50) ($2.25)
Est revenue net of transport (excl hedges) – $/Boe $12.00 – $12.50 $12.75 – $13.00
Est production costs – $/Boe $4.50 – $4.75 $4.50 – $4.75
Est royalty rate (% revenue net transportation) 5% – 6% 7%
Est mid-point field operating netback – $/Boe(1) $6.70 $7.35
Est realized hedging gains or (losses) – $ million $10.0 – $11.0 $6.5 – $7.5
Est cash G&A – $ million $6.0 – $7.0 $6.0 – $6.5
Est interest expense – $ million $7.0 – $8.0 $7.0 – $7.5
Est capital investment (excluding A&D) – $ million

$52.0 – $60.0
(Nig Crk GP $12.0 million)
$58.0
(Nig Crk GP $12.0 million)
Forecast fourth quarter Boe/d
Forecast fourth quarter liquids Bbls/d
25,000 – 28,000
5,100 – 5,600
25,000 – 27,000
5,100 – 5,500
Forecast annual Boe/d
Forecast annual liquids Bbls/d
22,500 – 24,000
4,300 – 4,800
23,000 – 23,500
4,600 – 4,700
Est annual funds flow – $ million(2) $53.0 – $57.0(2) $55.0 – $57.0
Horizontal wells drilled – gross
Horizontal wells completed – gross
Horizontal wells starting production – gross
6 – 9 (5.0 – 8.0 net)
8 (7.5 net)
7 (7.0 net)
8 (7.0 net)
8 (7.5 net)
7 (7.0 net)

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

2020 Guidance History
  Chicago
Daily
(US$/Mmbtu)
BC Station 2
Daily
(Cdn$/GJ)
WTI
(US$/Bbl)
Capital
Investment
($ million)
Forecast
Annual
Funds Flow
($ million)
Forecast Annual
Production
(Boe/d)
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
Aug 13, 2020 $1.85 $1.95 $38.50 $52.0 – $60.0 $53.0 – $57.0 22,500 – 24,000
Nov 10, 2020 $1.90 $2.15 $38.50 $58.0 $55.0 – $57.0 23,000 – 23,500

Initial guidance for 2021 is provided below. Capital investment is intended to be less than forecast funds flow. Comparing to the current forward strip, Storm’s forecast pricing is approximately 5% lower for the WTI oil price and for natural gas pricing.

2021 Guidance    
    Initial
November 10, 2020
Cdn$/US$ exchange rate   0.76
Chicago daily natural gas – US$/Mmbtu   $2.65
AECO daily natural gas – Cdn$/GJ   $2.50
BC Station 2 daily natural gas – Cdn$/GJ   $2.50
WTI – US$/Bbl   $40.00
Edmonton condensate diff – US$/Bbl   ($3.00)
Est revenue net of transport (excl hedges) – $/Boe   $17.00 – $18.00
Est production costs – $/Boe   $4.00 – $4.50
Est royalty rate (% revenue net transportation)   7% – 8%
Est mid-point field operating netback – $/Boe(1)   $11.95
Est realized hedging gains or (losses) – $ million   ($8.0 – $10.0)
Est cash G&A – $ million   $6.0 – $7.0
Est interest expense – $ million   $7.0 – $8.0
Est capital investment (excluding A&D) – $ million   $85.0 – $90.0
Forecast fourth quarter Boe/d(2)
Forecast fourth quarter liquids Bbls/d
  30,000 – 32,000
6,800 – 7,300
Forecast annual Boe/d
Forecast annual liquids Bbls/d
  26,000 – 28,000
5,600 – 6,000
Est annual funds flow – $ million(3)   $90.0 – $99.0
Horizontal well drilled – gross
Horizontal wells completed – gross
Horizontal wells starting production – gross
  11 (9.0 net)
11 (10.0 net)
13 (11.0 net)

(1) Based on the mid-point for each of revenue net of transportation, royalty rate and production costs.
(2) Assuming first production from the Fireweed area in October 2021.
(3) Based on the range for forecast annual production and using the mid-points for the estimated field operating netback, estimated cash G&A, estimated hedging gain or loss and estimated interest expense.

Capital investment for 2021 is expected to be allocated as follows:

  • up to $35 million at Fireweed to drill four horizontal wells (2.0 net), complete two wells (1.0 net), and to construct a 50 Mmcf raw per day field compression facility with associated pipelines (50% working interest);
  • $28 million at Nig Creek which includes $7 million to add a low pressure inlet with compression at the gas plant (100% working interest) and to drill, complete and pipeline connect three horizontal wells (3.0 net); and
  • $27 million at Umbach to drill, complete and pipeline connect six horizontal wells (6.0 net).

Development at Fireweed was previously paused for up to one year, however, the recent improvement in the WTI oil price and BC Station 2 natural gas price supports the restart of development. Planned activity levels for 2021 are not expected to be finalized until the end of 2020 with preliminary plans including net capital investment of up to $35 million with first production in October 2021.

Based on forecast production, natural gas sales in 2021 are expected to be 46% at Chicago, 36% at BC Station 2, 11% at AECO and 7% at Alliance ATP. Sales into Canadian markets will increase from approximately 35% in 2020 to 54% in 2021 as a result of the expiry of a sales commitment in October 2020 for 12 Mmcf per day at Sumas and as incremental production growth is directed to BC Station 2. Sales into Chicago use contracted capacity on the Alliance Pipeline which currently totals 57 Mmcf per day with Storm having the option to renew any portion or all of the capacity on an annual basis. Storm’s natural gas price for the first nine months of 2020 declined by 25% year over year largely as a result of 67% of sales being into US markets at Chicago and Sumas where prices declined by an average of 40% (as compared to the average increase of 75% for Canadian prices at AECO and BC Station 2). The natural gas marketing strategy will continue to be based on diversifying sales as much as possible to mitigate regional price differences caused by supply/demand imbalances that are difficult to predict in terms of timing and duration.

At Nig Creek, results from the first well targeting the lower Montney show that there is a second layer to develop with rates of return expected to be comparable to development at Umbach depending on the WTI oil price. With production having a higher proportion of condensate (average 840 Boe per day sales including 200 barrels per day of condensate over the first 9 months), the timing for follow-up wells is largely dependent on the WTI oil price.

Financial results are expected to improve significantly in the fourth quarter of 2020 and into 2021 with higher forward strip commodity prices, increased natural gas sales into Canadian markets, and with production growth from the Nig Creek area where production costs are materially lower ($1.29 per Boe year to date) than the corporate average and where liquids recoveries are the highest (22% liquids year to date).

As always, capital investment will remain flexible and may be adjusted up or down depending on commodity prices. In 2020, capital investment is expected to be equal to or less than funds flow with forecast annual production increasing by 15% from last year. For 2021, the intent is to improve financial flexibility with capital investment expected to be less than funds flow while forecast annual production increases by a further 18%.

Respectfully,

Brian Lavergne,
President and Chief Executive Officer

November 10, 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 November 10, 2020 for the period ended September 30, 2020 which is available on Storm’s SEDAR profile at www.sedar.com and on Storm’s website at www.stormresourcesltd.com.

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 November 10, 2020 for the period ended September 30, 2020 which are available on Storm’s SEDAR profile at www.sedar.com and on Storm’s website at www.stormresourcesltd.com.

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
www.stormresourcesltd.com

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