Storm Resources Ltd. (“Storm” or the “Company”) is Pleased to Announce Its Financial and Operating Results for the Three and Nine Months Ended September 30, 2018

CALGARY, Alberta, Nov. 13, 2018 (GLOBE NEWSWIRE) — Storm has also filed its unaudited condensed interim consolidated financial statements as at September 30, 2018 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 (www.sedar.com) and on Storm’s website (www.stormresourcesltd.com.)  Selected financial and operating information for the three and nine months ended September 30, 2018 appears below and should be read in conjunction with the related financial statements and MD&A.

Highlights
 
Thousands of Cdn$, except volumetric and
  per-share amounts
Three Months to
Sept. 30, 2018
Three Months to
Sept. 30, 2017
Nine Months to
Sept. 30, 2018
Nine Months to
Sept. 30, 2017
         
 FINANCIAL        
         
Revenue from product sales(1) 51,253   31,719   151,459   109,373  
Funds flow 22,227   13,170   69,151   42,757  
Per share – basic and diluted ($) 0.18   0.11   0.57   0.35  
Net income 7,174   682   13,253   31,065  
Per share – basic and diluted ($) 0.06   0.01   0.11   0.26  
Capital expenditures(2) 21,845   23,895   47,663   55,559  
Debt including working capital deficiency(2)(3) 84,648   101,297   84,648   101,297  
Common shares (000s)        
Weighted average – basic 121,557   121,557   121,557   121,522  
Weighted average – diluted 121,557   121,613   121,557   121,679  
Outstanding end of period – basic 121,557   121,557   121,557   121,557  
         
 OPERATIONS        
         
(Cdn$ per Boe)        
Revenue from product sales(1) 27.24   22.68   27.88   26.07  
Transportation costs (5.98 ) (6.09 ) (5.94 ) (5.78 )
Revenue net of transportation 21.26   16.59   21.94   20.29  
Royalties (1.03 ) (0.85 ) (1.28 ) (1.41 )
Production costs (5.54 ) (6.03 ) (5.52 ) (6.17 )
Field operating netback(2) 14.69   9.71   15.14   12.71  
Realized (loss) gain on hedging (1.73 ) 1.34   (0.89 ) (0.72 )
General and administrative (0.66 ) (1.03 ) (0.92 ) (1.10 )
Interest and finance costs (0.49 ) (0.61 ) (0.61 ) (0.69 )
Funds flow per Boe 11.81   9.41   12.72   10.20  
                 
Barrels of oil equivalent per day (6:1) 20,455   15,193   19,900   15,371  
Natural gas production        
Thousand cubic feet per day 101,905   74,318   98,154   75,537  
Price (Cdn$ per Mcf)(1) 3.21   3.13   3.39   3.72  
Condensate production        
Barrels per day 2,059   1,600   2,035   1,608  
Price (Cdn$ per barrel)(1) 84.97   53.52   82.46   58.70  
NGL production        
Barrels per day 1,412   1,206   1,506   1,173  
Price (Cdn$ per barrel)(1) 38.64   21.66   35.92   21.74  
Wells drilled (100% working interest)   3.0     9.0  
Wells completed (100% working interest) 5.0   5.0   8.0   9.0  
  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 24 of the MD&A.
  3. Excludes the fair value of commodity price contracts.

PRESIDENT’S MESSAGE

2018 THIRD QUARTER HIGHLIGHTS

  • Production increased by 35% on a per-share basis from the prior year to a record 20,455 Boe per day which was consistent with guidance (19,500 to 20,500 Boe per day).   
     
  • Liquids production (field condensate plus gas plant NGL) grew by 24% year over year with liquids representing 17% of total production and 41% of production revenue.  Condensate increased by 29% while NGL increased by 17% as a result of lower NGL recoveries at the McMahon Gas Plant.
     
  • Growth over the last 12 months has been achieved while investing less than funds flow (debt reduced by $17 million).
     
  • At the end of the quarter, there was an inventory of six Montney horizontal wells (5.5 net) at Umbach that had not started producing which included four completed wells.  One horizontal well (1.0 net) started production at the end of the quarter.
     
  • As a result of the continuing improvement in horizontal well performance at Umbach, the internal type curve used by management to forecast production from new wells is being increased to 11 Bcf raw from 9 Bcf raw which is based on the performance of wells completed in 2017 and 2018 that have higher rates and shallower declines than previously forecast.
     
  • At the Nig land block, three wells completed in 2018 are exceeding expectations and have averaged 8.2 Mmcf per day raw gas over the first 120 calendar days plus 225 barrels per day of field condensate (average of 1,600 Boe per day sales with 23% liquids including NGL recovered at the gas plant).  The field condensate-gas ratio is approximately 50% higher than the average well at Umbach.
     
  • Diversified sales resulted in the natural gas price net of transportation being $2.13 per Mcf which was materially higher than Western Canadian pricing (AECO was $1.13 per GJ while Station 2 was $1.24 per GJ).
     
  • Production costs, cash G&A and interest expense on a per-Boe basis declined by 11% year over year. 
     
  • Funds flow was $22.2 million, or $0.18 per share, a 64% increase on a per-share basis from last year which was largely from higher production volumes and higher liquids prices.
     
  • Net income for the year to date is $13.3 million or $0.11 per share which is a decrease from $31.1 million last year as a result of non-cash unrealized gains or losses on hedging which reduced the year to date by $18.1 million while adding $25.4 million in the previous year.
     
  • Capital investment was $21.8 million which included five horizontal well completions, installing additional compression at Umbach and twinning part of a field gathering pipeline to Nig. 
     
  • The balance sheet remains strong with debt including the working capital deficiency being $84.6 million which represents 1.0 times annualized quarterly funds flow and 47% of the bank credit facility ($180 million).
     
  • Commodity price hedges continue to be added and currently protect approximately 42% of forecast production for 2019.

OPERATIONS REVIEW

Umbach, Nig and Fireweed Areas, Northeast British Columbia

Storm’s land position at Umbach is prospective for liquids-rich natural gas from the Montney formation and currently totals 113,000 net acres (161 net sections).  During the third quarter, two sections of land were acquired. 

Third quarter field activity included completing five horizontal wells (5.0 net), adding compression and twinning part of a gathering pipeline to Nig that will reduce wellhead flowing pressure and increase capacity.  One horizontal well started production on September 19th and there remains an inventory of six horizontal wells (5.5 net) that had not started producing at the end of the quarter which includes four completed wells.   

Fourth quarter field activity is expected to include drilling five wells (5.0 net) and completing three wells (2.5 net) which includes the standing well (0.5 net) at Fireweed.

The drilling program for this winter and into 2019 will generally target areas where higher field condensate-gas ratios are expected.  In the fourth quarter of 2018, two wells (2.0 net) will be drilled at Umbach and three wells (3.0 net) at Nig.  During 2019, four wells (4.0 net) will be drilled at Nig including an acid gas disposal well and three wells (1.5 net) at Fireweed.  One of the wells at Nig will be drilled into the lower Montney. 

At Umbach, approximately $115 million has been invested since 2013 to build infrastructure (pipelines and facilities) with current field compression capacity totaling 150 Mmcf per day raw gas after additional compression was installed at the end of the third quarter.  Throughput in the third quarter averaged 107 Mmcf per day raw gas.  Current compression capacity supports growth in corporate production to approximately 27,000 Boe per day with growth dependent on the Station 2 price (incremental natural gas production would be directed to Station 2).  Produced raw natural gas is sour (approximately 1.2% H2S) with approximately 85% directed to the McMahon Gas Plant and 15% directed to the Stoddart Gas Plant.  Firm processing commitments are 65 Mmcf raw gas per day at McMahon (5 to 15 year terms) and 15 Mmcf per day at Stoddart (1 year term). 

At Nig, the regulatory application for the planned 50 Mmcf per day gas plant (100% working interest) was submitted in mid-September.  Depending on when approval is received, site preparation would occur in the first half of 2019, construction in the second half of 2019, and start-up is anticipated to be between the fourth quarter of 2019 and the first quarter of 2020.  The main benefits from the gas plant are a forecast operating cost of $2.00 per Boe (reduces the corporate operating cost to approximately $4.25 per Boe) and incremental production totaling approximately 1,500 Boe per day which comes from improved liquids recovery (adds 1,100 barrels per day with 90% NGL) plus a 5% reduction in process shrinkage.  The total cost of the project is estimated to be $81 million which includes $73 million for the gas plant, $4 million for an acid gas injection well and $4 million for a sales pipeline.  During the third quarter, $2.5 million was invested primarily for equipment deposits and, in the fourth quarter, $11 million is expected to be invested for equipment deposits.

At Fireweed, engineering and design is underway for the planned 50 Mmcf per day field compression facility (50% working interest).  The expected cost of the facility is $34 million gross and it is designed to be expandable to 100 Mmcf per day.  Depending on when regulatory approvals are received, construction is expected to start later in 2019 or early in 2020 with start-up in the second half of 2020.  Based on the production history from offsetting horizontal wells, field condensate-gas ratios are expected to be approximately 25 barrels per Mmcf higher than Umbach over the life of a well and up to 60 barrels per Mmcf higher in the first year.  The first phase of development will include drilling and completing up to 12 horizontal wells (6.0 net) which are expected to add 4,000 to 5,000 Boe per day on a net basis (25% liquids) once the facility is completed in the second half of 2020.  

Initial flow results after completing the standing well (0.5 net) at Fireweed are encouraging.  The well is located at C-74-G/94-A-13, has a completed length of 1,420 metres and was completed using the ball drop hydraulic fracturing method with 2,300 tonnes of proppant pumped into 35 stages using slick-water.  After flowing the frac fluid back on a six-day cleanup, the flow rate averaged 10.9 Mmcf per day raw gas plus 660 barrels per day of 54 degree field condensate and 1,140 barrels per day of frac water over the last 12 hours while flowing up the casing with a final flowing pressure of 4,800 kPa.  The well was shut in after recovering 23% of the frac water and is expected to remain shut in until the Fireweed field compression facility is completed.

Initial rates from the wells completed in 2018 (all on the Nig land block) have been very strong with no decline to date.  Rates over the first 120 calendar days have averaged 8.2 Mmcf per day raw gas plus 225 barrels per day of field condensate (average 1,600 Boe per day sales with 23% liquids including NGL recovered at the gas plant).  The field condensate-gas ratio is 50% higher than the average well at Umbach.  Current rates are averaging approximately 8.0 Mmcf per day plus 150 barrels per day of field condensate.

Given the improvement in rates that has been realized from longer horizontal wells, Storm management is now using an 11 Bcf raw gas type curve (internal estimate) to forecast production from new wells.  Previously, management used a 9 Bcf raw gas type curve (internal estimate).  The revised type curve is based on the performance of the wells completed in 2017 which have a shallower decline than previously forecast.  Future wells will be materially longer (2,400 metres) and have more frac stages (40 to 46) than the 2017 wells.  A summary of horizontal well results is provided below with more information on well performance and management’s type curve being available in the presentation on Storm’s website.

Year of
Completion
Frac
Stages
Completed
Length
Actual Drill &
Complete Cost
IP90 Cal Day
Mmcf/d Raw
IP180 Cal Day
Mmcf/d Raw
IP365 Cal Day
Mmcf/d Raw
2014 – 16
33 hz’s(1)
22 1270 m $4.3 million
$3,400 per metre
4.9 Mmcf/d
12 hz’s
4.3 Mmcf/d
12 hz’s
3.4 Mmcf/d
12 hz’s
2017
12 hz’s
34 1750 m $4.2 million
$2,400 per metre
5.0 Mmcf/d
12 hz’s
4.5 Mmcf/d
12 hz’s
4.3 Mmcf/d
10 hz’s
2018
8 hz’s
35 1970 m $5.0 million
$2,540 per metre
8.1 Mmcf/d
3 hz’s
   
  1. 2014 wells exclude a middle Montney well (this table provides analysis of upper Montney wells only).


HEDGING AND TRANSPORTATION

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 protects approximately 58% of forecast production for the fourth quarter of 2018 and 42% for 2019.

2018 Q4 Crude Oil 800 Bpd WTI Cdn$67.50/Bbl floor, Cdn$77.75/Bbl ceiling
700 Bpd WTI Cdn$64.84/Bbl
Propane 300 Bpd Conway Cdn$39.55/Bbl
Natural Gas 45,500 Mmbtu/d (38.4 Mmcf/d) Chicago Cdn$3.42/Mmbtu
  11,500 Mmbtu/d (9.7 Mmcf/d) Sumas Cdn$2.92/Mmbtu
  7,000 GJ/d (5.6 Mmcf/d) AECO Cdn$1.92/GJ
  7,000 GJ/d (5.6 Mmcf/d) Station 2 Cdn $1.72/GJ
  3,000 GJ/d (2.4 Mmcf/d) Station 2 – AECO basis -$0.345/GJ

2019 Crude Oil 875 Bpd WTI Cdn$71.24/Bbl floor, Cdn$84.60/Bbl ceiling
625 Bpd WTI Cdn$78.51/Bbl
Propane 200 Bpd Conway Cdn$42.87/Bbl
Natural Gas 43,500 Mmbtu/d (36.7 Mmcf/d) Chicago Cdn$3.26/Mmbtu
  8,400 Mmbtu/d (7.1 Mmcf/d) Sumas Cdn$2.86/Mmbtu
  2,500 GJ/d (2.0 Mmcf/d) AECO Cdn$1.94/GJ
  2,250 GJ/d (1.8 Mmcf/d) Station 2 Cdn $1.73/GJ

Transportation capacity for natural gas is summarized below:

56 – 70 Mmcf per day Alliance – Chicago (preferential interruptible service adds up to 14 Mmcf per day)
  12 Mmcf per day Enbridge T-north – Station 2 for Sumas price less a marketing adjustment
    5 Mmcf per day Alliance – ATP
  16 Mmcf per day Enbridge T-north – Station 2
  13 Mmcf per day Enbridge T-north & TCPL NGTL – AECO
102 – 116 Mmcf per day

Transportation capacity provides diversification for natural gas sales to several different markets.  During the third quarter, 61% of natural gas production was sold in Chicago, 27% in Western Canada and 12% at Sumas.  Production exceeding firm capacity is directed to Chicago and/or Station 2 on an interruptible basis depending on which sales point offers a higher net price.

OUTLOOK

For the fourth quarter of 2018, production is forecast to be 19,000 to 21,000 Boe per day with production to date averaging 19,300 Boe per day based on field estimates which includes three days with no production due to outages at the McMahon Gas Plant and the Enbridge T-south pipeline failure on October 9th.  The effect of the pipeline failure on the Station 2 price is uncertain at this time due to varying restrictions on flow rates for repairs as well as the timing for storage withdrawals from the Aitken Creek storage facility (some production will be shut in as receipts and deliveries at Station 2 must be equal).  To date in the fourth quarter, the Station 2 price has averaged $0.72 per GJ which has resulted in Storm’s production being restricted to minimize sales at Station 2.  The lower Station 2 price is not expected to have a material effect on Storm’s fourth quarter financial results since it is largely mitigated by diversified natural gas sales (less than 15% of sales are at Station 2), existing hedges at Station 2 (5.6 Mmcf per day), unhedged volumes sold at a much higher Sumas price (2.3 Mmcf per day), and the ability to divert some production onto the Alliance Pipeline to the higher priced Chicago market (up to 14 Mmcf per day).

Updated guidance for 2018 is provided below.  Capital investment is increasing to $85 million (was $80 million) as the completion of a standing horizontal well at Fireweed was advanced into 2018 from 2019 and the estimated drilling and completion cost for a horizontal well was increased to $5.8 million (was $5.0 million) to reflect increased length with more frac stages (2,400 metres with 40 to 46 frac stages).  With the increased length and frac stages, the type curve used by Storm management to forecast production from new wells has been increased to 11 Bcf raw gas (was 9 Bcf raw gas).  This is supported by the performance to date of the wells completed in 2017 and 2018.  Fourth quarter capital investment is expected to be $37 million which includes $11 million for the Nig Gas Plant.  Forecast commodity prices reflect pricing to date and the approximate forward strip for the remainder of the year.  Notably, the mid-point of forecast annual funds flow is approximately 15% higher than initial guidance provided in November 2017.

     
2018 Guidance    
  Previous
August 14, 2018
Current
November 13, 2018
Cdn$/US$ exchange rate 0.78 0.77
Chicago daily natural gas – US$/Mmbtu $2.70 $2.90
Sumas monthly natural gas – US$/Mmbtu $2.05 $3.25
AECO daily natural gas – Cdn$/GJ $1.45 $1.50
Station 2 daily natural gas – Cdn$/GJ $1.35 $1.30
WTI – US$/Bbl $66.00 $66.00
Edmonton condensate diff – US$/Bbl   -$3.10
Est revenue net of transport (excluding hedges) – $/Boe $20.50 – $21.50 $23.00 – $23.50
Est operating costs – $/Boe $5.75 $5.50 – $5.75
Est royalty rate (% revenue before hedging) 5% – 7% 4% – 6%
Est capital investment (excluding A&D) – $ million $80.0 $85.0
Est cash G&A  – $ million $6.0 – $7.0 $6.0 – $6.5
– $/Boe $0.78 – $0.95 $0.80 – $0.91
Est interest expense – $ million $4.0 $4.0
Forecast fourth quarter production – Boe/d
% liquids
20,000 – 21,000
18%
19,000 – 21,000
18%
Forecast annual production – Boe/d
% liquids
20,000 – 20,500
18%
19,500 – 20,500
18%
Est annual funds flow – $ million $85.0 – $90.0 $90.0 – $96.0(1)
Umbach horizontal wells drilled – gross
Umbach horizontal wells completed – gross
Umbach horizontal wells connected – gross
5 (5.0 net)
10 (10.0 net)
8 (8.0 net)
5 (5.0 net)
11 (10.5 net)
7 (7.0 net)
  1. Based on mid-point field operating netback of $16.45 per Boe.
 
Guidance History
  Chicago
Daily
(US$/Mmbtu)
Station 2
Daily
(Cdn$/GJ)
WTI
(US$/bbl)
Estimated Operations
Capital
($ million)
Forecast
Annual
Funds Flow
($ million)
Forecast Annual
Production
(Boe/d)
Nov 14, 2017 $2.80 $1.30 – $1.70 $52.00 $55.0 – $90.0 $73.0 – $90.0 20,000 – 23,000
Mar 1, 2018 $2.60 $1.05 $56.00 $55.0 – $90.0 $70.0 – $78.0 20,000 – 23,000
May 15, 2018 $2.60 $1.20 $64.00 $55.0 – $65.0 $76.0 – $80.0 20,000 – 21,000
Aug 14, 2018 $2.70 $1.35 $66.00 $80.0 $85.0 – $90.0 20,000 – 20,500
Nov 13, 2018 $2.90 $1.30 $66.00 $85.0 $90.0 – $96.0 19,500 – 20,500

Guidance for 2019 is summarized below and includes capital investment of $128 million which includes $68 million for the sour gas plant at Nig and $14 million at Fireweed.  Approximately 40% of capital investment will be in the first half of 2019.  Drilling plans include five horizontal wells (5.0 net) at Nig including an acid gas disposal well, and three wells (1.5 net) at Fireweed.  The estimated cost to drill and complete a horizontal well is $5.8 million for 2,400 metres of length with 40 to 46 frac stages. Capital investment is supported by commodity price hedges which protect approximately 42% of forecast production.  The production forecast assumes an 11 Bcf raw gas type curve (internal estimate) for new horizontal wells.  If required, capital investment and production growth can be reduced to ensure total debt is maintained at an appropriate level. 

   
2019 Guidance  
   
  November 13, 2018
Cdn$/US$ exchange rate 0.78
Chicago daily natural gas – US$/Mmbtu $2.50
Sumas monthly natural gas – US$/Mmbtu $2.50
AECO daily natural gas – Cdn$/GJ $1.50
Station 2 daily natural gas – Cdn$/GJ $1.25
WTI – US$/Bbl $60.00
Edmonton condensate diff – US$/Bbl -$8.00
Est revenue net of transport (excluding hedges) – $/Boe $17.50 – $18.00
Est operating costs – $/Boe $5.50 – $5.75
Est royalty rate (% revenue before hedging) 5% – 7%
Est capital investment (excluding A&D) – $ million $128.0
Est cash G&A  – $ million $6.0 – $7.0
– $/Boe $0.66 – $0.91
Est interest expense – $ million $5.5 – $6.5
Forecast fourth quarter production – Boe/d
% liquids
23,000 – 25,000
18%
Forecast annual production – Boe/d
% liquids
21,000 – 24,000
18%
Est annual funds flow – $ million $72.0 – $88.0(1)
Umbach horizontal wells drilled – gross
Umbach horizontal wells completed – gross
Umbach horizontal wells connected – gross
8 (6.5 net)
11 (9.5 net)
11 (11.0 net)
  1. Based on mid-point field operating netback of $11.05 per Boe.

For the nine months to date in 2018, financial results have improved materially when compared to last year which has further strengthened Storm’s balance sheet.  Funds flow is up 62% year over year as a result of 29% production growth with diversified natural gas sales mitigating the decline in Western Canadian natural gas prices (decline of 36% at AECO and 24% at Station 2) and growing liquids production benefitting from the 35% increase in the WTI price.  In addition, the significant improvement in horizontal well results has reduced capital investment required to grow production.  As a result, total debt has decreased by $17 million over the last 12 months.     

Storm’s improving financial position will be used to self-fund planned growth from Nig (2019 – 2020), Fireweed (2020) and Umbach (contingent on the Station 2 price).  This includes a large capital investment to expand infrastructure by constructing a sour gas plant at Nig and constructing a new field compression facility at Fireweed. The upfront investment in infrastructure is large but will provide a significant long-term benefit.  Production is expected to increase to 25,000 Boe per day by the end of 2019 and to 30,000 Boe per day by the end of 2020 while increasing liquids as a proportion of total production and reducing operating costs which reduces exposure to current low Western Canadian natural gas prices. 

With a large, multi-year drilling inventory in the Montney in an area that is liquids-rich and higher quality, Storm is well positioned to continue growing asset value per share over the next three years by advancing development at both Nig and Fireweed.

Respectfully,

Brian Lavergne,
President and Chief Executive Officer

November 13, 2018

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 November 13, 2018 for the period ended September 30, 2018 which is available on Storm’s SEDAR profile at www.sedar.com and on Storm’s website at www.stormresourcesltd.com.

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, Nig and Fireweed 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, 2018 and the MD&A dated November 13, 2018 for the period ended September 30, 2018 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

PDF available: http://resource.globenewswire.com/Resource/Download/2f808fd7-5ea5-434b-b25a-12289b2a9f13

2018-12-11T00:00:07+00:00

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