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, 2017

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CALGARY, ALBERTA–(Marketwired – Nov. 14, 2017) – Storm Resources Ltd. (TSX:SRX)

Storm has also filed its unaudited condensed interim consolidated financial statements as at September 30, 2017 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, 2017 appears below and should be read in conjunction with the related financial statements and MD&A.

Highlights

Thousands of Cdn$, except volumetric and per-share amounts Three Months to Sept. 30, 2017 Three Months to Sept. 30, 2016 Nine Months to Sept. 30, 2017 Nine Months to Sept. 30, 2016
FINANCIAL
Revenue from product sales(1) 24,100 21,047 88,462 51,038
Funds flow 13,170 8,759 42,757 22,395
Per share – basic and diluted ($) 0.11 0.07 0.35 0.19
Net income (loss) 682 (85 ) 31,065 (25,562 )
Per share – basic and diluted ($) 0.01 0.26 (0.21 )
Operations capital expenditures(2) 23,895 7,580 55,559 32,139
Land and property acquisitions (600 ) (600 )
Debt including working capital deficiency(2)(3) 101,297 69,303 101,297 69,303
Common shares (000s)
Weighted average – basic 121,557 120,195 121,522 119,907
Weighted average – diluted 121,613 120,195 121,679 119,907
Outstanding end of period – basic 121,557 120,283 121,557 120,283
OPERATIONS
(Cdn$ per Boe)
Revenue from product sales(1) 17.23 17.22 21.08 14.13
Royalties (0.85 ) (1.19 ) (1.41 ) (0.72 )
Production (6.03 ) (6.69 ) (6.17 ) (6.72 )
Transportation (0.64 ) (0.39 ) (0.79 ) (0.42 )
Field operating netback(2) 9.71 8.95 12.71 6.27
Realized (loss) gain on hedging 1.34 (0.03 ) (0.72 ) 1.74
General and administrative (1.03 ) (1.03 ) (1.10 ) (1.15 )
Interest and finance costs (0.61 ) (0.72 ) (0.69 ) (0.65 )
Funds flow per Boe 9.41 7.17 10.20 6.21
Barrels of oil equivalent per day (6:1) 15,193 13,285 15,371 13,185
Natural gas production
Thousand cubic feet per day 74,318 65,914 75,537 65,245
Price (Cdn$ per Mcf)(1) 2.02 2.41 2.70 1.77
Condensate production
Barrels per day 1,600 1,210 1,608 1,278
Price (Cdn$ per barrel)(1) 53.52 49.01 58.70 46.51
NGL production
Barrels per day 1,206 1,089 1,173 1,033
Price (Cdn$ per barrel)(1) 21.66 10.03 21.74 10.70
Wells drilled (100% working interest) 3.0 9.0 7.0
Wells completed (100% working interest) 5.0 3.0 9.0 5.0
(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 25 of the MD&A.
(3) Excludes the fair value of commodity price contracts.

PRESIDENT'S MESSAGE

2017 THIRD QUARTER HIGHLIGHTS

  • Production increased 14% from the prior year (13% on a per-share basis) to average 15,193 Boe per day. The increase was achieved with approximately 2,500 Boe per day being shut in as a result of the maintenance turnaround at the McMahon Gas Plant (loss of 14,000 Boe per day for 14 days in July) and 1,100 Boe per day was shut in during September due to the very low natural gas price at Station 2 ($0.66 per GJ).
  • Condensate and NGL production increased 22% from the prior year to 2,806 barrels per day which represented 18% of per-Boe production and 43% of total revenue.
  • In response to the low Western Canadian natural gas prices during the quarter, sales were maximized into the higher priced Chicago market which resulted in 71% of third quarter natural gas sales being at Chicago, 5% at Alliance Transfer Point (“ATP”) and the remainder at Station 2.
  • At the end of the quarter, there was an inventory of ten Montney horizontal wells (10.0 net) at Umbach that had not started producing which includes four completed wells. Two horizontal wells (2.0 net) started production in the quarter while eight horizontal wells (8.0 net) have started production during the first nine months of the year.
  • Montney horizontal well performance at Umbach continues to improve as length is increased and as drilling targets areas where field condensate rates are higher. The three wells (3.0 net) completed in 2017 with enough history averaged 4.1 Mmcf per day gross raw gas plus 128 barrels per day of field condensate over the first 180 calendar days (approximately 800 Boe per day sales with 24% liquids including gas plant NGL). After adjusting for the 39 days of downtime with the McMahon Gas Plant turnaround, the gas rate would be 23% higher than the average well completed in 2014 to 2016 while the field condensate rate would be 130% higher.
  • Controllable cash costs (production, general and administrative, interest and finance) were $7.67 per Boe which is a year-over-year decrease of 9%. The decrease was mainly due to production costs declining 10% as a result of production growth and the long-term processing arrangement at the McMahon Gas Plant which commenced in January 2017.
  • Funds flow was $13.2 million ($9.41 per Boe), an increase of 50% from a year ago. The improvement was primarily from a higher netback combined with a 14% increase in production volumes. The netback increased by $2.24 per Boe with most of this from hedging (+$1.37 per Boe) and lower production costs (+$0.66 per Boe).
  • Net income was $0.7 million or $0.01 per share. Hedging continues to have a recurring impact on quarterly net income with the realized and unrealized gains and losses on hedging adding $1.7 million to net income.
  • Capital investment was $23.9 million with 81% being invested in drilling and completions at Umbach. This was less than the original forecast of $28.0 million as a result of lower than budgeted drilling and completion costs.
  • Total debt including working capital deficiency was $101.3 million which is 1.9 times annualized third quarter funds flow. The bank credit facility is $165.0 million.
  • Natural gas sales will be further diversified through recently added marketing arrangements that now result in approximately 54% to 68% of firm transportation capacity for 2018 being sold at the Chicago price, 11% at the Sumas price less a marketing adjustment (US$0.69/Mmbtu), 5% at the ATP price, 3% to 17% at the Station 2 price and 13% at the AECO price.
  • Commodity price hedges continue to be added and currently protect approximately 30% of forecast production for 2018.

OPERATIONS REVIEW

Umbach, Northeast British Columbia

Storm's land position at Umbach is prospective for liquids-rich natural gas from the Montney formation and currently totals 109,000 net acres (155 net sections). To date, Storm has drilled 65 horizontal wells (61.4 net).

Production in the third quarter was 15,073 Boe per day with liquids recovery representing 38 barrels per Mmcf sales (57% being higher priced condensate).

Activity in the third quarter included completing five horizontal wells (5.0 net) and drilling three horizontal wells (3.0 net). Two horizontal wells (2.0 net) started production which left an inventory of ten horizontal wells (10.0 net) that had not started producing at the end of the quarter including four completed wells. Eight horizontal wells (8.0 net) have started production in 2017 with production from these wells totaling 4,800 Boe per day in the third quarter.

Since 2013, approximately $100 million has been invested in building out infrastructure (pipelines and facilities) with current capacity totaling 115 Mmcf per day raw gas from three field compression facilities. Throughput in the third quarter was 79 Mmcf per day raw gas (August and September averaged 88 Mmcf per day). Capacity can be increased to 150 Mmcf per day by installing additional compression at a cost of $7.0 million with the installation timing dependent on well performance and commodity prices. The increased compression capacity would support growth in corporate production to approximately 27,000 Boe per day.

Storm's produced raw natural gas is sour (approximately 1.2% H2S) with 78% directed to the McMahon Gas Plant in the third quarter and 22% directed to the Stoddart Gas Plant. At the Stoddart Gas Plant, the firm processing commitment is 15 Mmcf raw gas per day until April 2018. At the McMahon Gas Plant, the firm processing commitment started in January 2017, totals 65 Mmcf raw gas per day, has terms of 5 to 15 years, and includes the option to add up to 35 Mmcf raw gas per day.

A summary of horizontal well performance and costs is provided below. The drilling and completion cost per meter for the 2017 wells has decreased by 12% from 2016. The 2017 wells are 28% longer than wells completed in 2014 to 2016 and the average rate over the first 180 calendar days is approximately 20% better after adjusting for the 39 days of downtime for the McMahon Gas Plant turnaround. Notably, the field condensate rate averaged 128 barrels per day over the same period, an improvement of 130% after adjusting for the downtime. IP90's are not used for comparing well performance as the majority of new horizontal wells are initially restricted to manage fluid production. Further improvements in well performance and costs will be realized from the wells being drilled in the second half of 2017 which are approximately 60% longer than wells completed in 2014 to 2016.

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
12 hz's(1)
19 1,170 m $4.6 million
$3,900 per meter
4.9 Mmcf/d
12 hz's
4.4 Mmcf/d
12 hz's
3.5 Mmcf/d
12 hz's
2015
11 hz's
22 1,360 m $4.4 million
$3,200 per meter
4.7 Mmcf/d
11 hz's
4.2 Mmcf/d
11 hz's
3.3 Mmcf/d
11 hz's
2016
10 hz's
25 1,300 m $3.8 million
$2,900 per meter
5.1 Mmcf/d
10 hz's
4.2 Mmcf/d
10 hz's
3.6 Mmcf/d
7 hz's
2017
5 hz's
34 1,630 m $4.2 million
$2,600 per meter
4.9 Mmcf/d(2)
5 hz's
4.1 Mmcf/d(3)
3 hz's
(1) 2014 wells exclude a middle Montney well (this table provides analysis of upper Montney wells only).
(2) Produced for an average of approximately 80 days due to the McMahon maintenance turnaround June 5 to July 14.
(3) Produced for an average of approximately 141 days due to the McMahon maintenance turnaround June 5 to July 14.

Horn River Basin, Northeast British Columbia

Storm has a 100% working interest in 119 sections in the Horn River Basin (78,000 net acres) which are prospective for natural gas from the Muskwa, Otter Park and Evie/Klua shales. Storm's one horizontal well averaged 57 Boe per day in the third quarter and was as shut in at the end of July due to the low natural gas price at Station 2. Cumulative production to date from this well is 5.7 Bcf raw.

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 WTI is hedged as approximately 80% of Storm's liquids production is priced in reference to WTI. The current hedge position is summarized below with prices being hedged on approximately 30% of forecast production for 2018.

Q4 2017
Crude Oil 1,300 Bpd WTI Cdn$64.60/Bbl floor, Cdn$68.95/Bbl ceiling
Natural Gas 38,000 GJ/d (30,400 Mcf/d) AECO Cdn$2.71/GJ
12,800 Mmbtu/d (10,800 Mcf/d) Chicago Cdn$4.18/Mmbtu(1)
5,300 GJ/d (4,200 Mcf/d) Station 2 Cdn$1.81/GJ
35,000 Mmbtu/d Chicago – AECO basis +US$0.58/Mmbtu
2,670 GJ/d (2,140 Mcf/d) Station 2 – AECO basis -$0.41/GJ
2018
Crude Oil 1,110 Bpd WTI Cdn$64.30/Bbl floor, Cdn$66.59/Bbl ceiling
Propane 200 Bpd Conway Cdn$38.12/Bbl
Natural Gas 750 GJ/d (600 Mcf/d) AECO Cdn$2.80/GJ
24,400 Mmbtu/d (20,700 Mcf/d) Chicago Cdn$3.92/Mmbtu(1)
4,000 Mmbtu/d (3,400 Mcf/d) Chicago US$2.82/Mmbtu(1)
9,000 Mmbtu/d (7,600 Mcf/d) Sumas Cdn$3.02/Mmbtu
3,000 GJ/d (2,400 Mcf/d) Station 2 – AECO basis -$0.345/GJ
(1) The Alliance Pipeline tariff to Chicago is approximately Cdn$1.21 per Mmbtu including the cost of fuel.

Natural gas transportation capacity totals 102 Mmcf per day sales in 2018 with natural gas production exceeding this directed to Chicago and/or Station 2 using interruptible pipeline capacity (depending on which sales point offers a higher price). Using the firm transportation capacity for 2018 (102 Mmcf per day sales), approximately 54% to 68% will be sold at Chicago pricing, 11% at Sumas pricing less a marketing adjustment, 5% at ATP pricing, 3% to 17% at Station 2 pricing and 13% at AECO pricing. Natural gas marketing arrangements result in the cost of transportation on the Alliance Pipeline for sales in Chicago being deducted from revenue ($7.1 million deducted in the third quarter of 2017). Further information on pipeline tariffs and price deductions is provided in the presentation on Storm's website.

2017 2018
Alliance Pipeline(1)
51 Mmcf/d Chicago price
5 Mmcf/d ATP price
Alliance Pipeline(1)
55 Mmcf/d Chicago price
5 Mmcf/d ATP price
Enbridge T-North
16 Mmcf/d Station 2 price
Enbridge T-North
17 Mmcf/d Station 2 price
12 Mmcf/d Sumas price -US$0.69/mmbtu
Enbridge T-North & TCPL NGTL
13 Mmcf/d AECO price
(1) Interruptible capacity on the Alliance Pipeline adds up to 25% of contracted capacity.

OUTLOOK

Third quarter production was 15,193 Boe per day which was less than guidance of 15,500 to 17,000 Boe per day provided on August 15, 2017. This was primarily due to natural gas prices being lower than forecast which resulted in approximately 1,100 Boe per day that was shut in during September while the start-up of recently completed horizontal wells has been delayed until the fourth quarter.

For the fourth quarter of 2017, production is forecast to be 18,000 to 19,000 Boe per day which represents year-over- year growth of 39% at the mid-point. This is a reduction from guidance provided on August 15, 2017 due to continued weak natural gas prices at Station 2 in October (averaged $0.33/GJ) which further delayed the start-up of new horizontal wells until November. Production to date in the fourth quarter has averaged 17,200 Boe per day based on field estimates. Capital investment is expected to be $26.0 million which includes drilling seven horizontal wells plus completing three horizontal wells at Umbach.

Updated guidance for 2017 is summarized in the tables below. Forecast commodity prices reflect actual year-to-date pricing plus the approximate forward strip for the remainder of 2017. With continuing low natural gas prices at Station 2 delaying the start-up of recently completed horizontal wells, completions originally planned for the fourth quarter have been delayed until 2018. As a result, capital investment will be reduced to $82.0 million (lower end of the range previously indicated) and year-end debt is expected to be at or below 1.5 times fourth quarter funds flow.

2017 Guidance

August 15, 2017 Updated
November 14, 2017
$Cdn/$US exchange rate 0.775 0.77
Chicago daily natural gas – US$/Mmbtu $2.90 $2.90
AECO daily natural gas – Cdn$/GJ $2.45 $2.10
Station 2 daily natural gas – Cdn$/GJ $2.00 $1.70
Edmonton light oil – Cdn$/Bbl $60.00 $61.00
Estimated average operating costs – $/Boe $5.75 – $6.00 $6.00
Estimated average royalty rate
(% production revenue before hedging)
6% – 8% 6%
Estimated capital investment – $ million
(excluding acquisitions & dispositions)
$75.0 – $95.0 $82.0
Estimated cash G&A – $ million $6.0 – $6.5 $6.0 – $6.5
– $/Boe $0.95 – $1.05 $1.00 – $1.10
Forecast fourth quarter production – Boe/d 19,000 – 21,000 18,000 – 19,000
% condensate and NGL 17% 18%
Forecast annual production – Boe/d 16,500 – 18,000 16,200
% condensate and NGL 17% 18%
Umbach horizontal wells drilled 12 – 15 gross (12.0 – 15.0 net) 16 gross (16.0 net)
Umbach horizontal wells completed 10 – 16 gross (10.0 – 16.0 net) 12 gross (12.0 net)
Umbach horizontal wells connected 13 – 16 gross (13.0 – 16.0 net) 15 gross (15.0 net)

2017 Guidance History

Chicago
Daily
(US$/Mmbtu)
Station 2
Daily
(Cdn$/GJ)
AECO
Daily
(Cdn$/GJ)
Estimated
Operations
Capital
($ million)
Forecast
Fourth Quarter
Production
(Boe/d)
Forecast Annual
Production
(Boe/d)
September 7, 2016 $3.00 $2.25 $2.65 $75.0 – $80.0 18,000 – 20,000 16,500 – 18,000
November 15, 2016 $3.00 $2.20 $2.65 $75.0 – $80.0 18,000 – 20,000 16,500 – 18,000
March 2, 2017 $3.00 $2.00 $2.50 $75.0 – $80.0 18,000 – 20,000 16,500 – 18,000
May 15, 2017 $3.00 $2.10 $2.50 $75.0 – $80.0 19,000 – 21,000 17,000 – 18,000
August 15, 2017 $2.90 $2.00 $2.45 $75.0 – $95.0 19,000 – 21,000 16,500 – 18,000
November 14, 2017 $2.90 $1.70 $2.10 $82.0 18,000 – 19,000 16,200

Guidance for 2018 is provided in the table below. Based on the assumptions provided in the table, capital investment is expected to be $55.0 to $90.0 million depending on commodity prices with average annual production forecast to increase by 22% to 32%. The production forecast uses a 6.3 Bcf type curve for future horizontal wells at Umbach with the type curve based on the performance of horizontal wells completed in 2014 to 2016. Recently drilled wells are approximately 60% longer and are expected to outperform this type curve. The cost to drill and complete a horizontal well is estimated to be $4.4 million while the equipping and pipeline tie-in cost is expected to average $0.9 million per well. The timing to install additional compression at Umbach will largely depend on the outlook for the natural gas price at Station 2. For the first half of the year, capital investment is expected to be $25.0 to $44.0 million depending on commodity prices and funds flow.

2018 Guidance

November 14, 2017
$Cdn/$US exchange rate 0.79
Chicago daily natural gas – US$/Mmbtu $2.80
Sumas monthly natural gas – US$/Mmbtu $2.40
AECO daily natural gas – Cdn$/GJ $1.80 – $2.10
Station 2 daily natural gas – Cdn$/GJ $1.30 – $1.70
WTI – US$/bbl $52.00
Edmonton light oil – Cdn$/Bbl $62.00
Estimated revenue net of transportation – $/Boe
(excluding hedging)
$18.00 – $19.25
Estimated average operating costs – $/Boe $5.75
Estimated average royalty rate
(% production revenue before hedging)
6% – 9%
Estimated capital investment – $ million
(excluding acquisitions & dispositions)
$55.0 – $90.0
Estimated cash G&A – $ million $6.0 – $7.0
– $/Boe $0.70 – $0.95
Estimated interest expense – $ million $4.5 – $5.5
Forecast fourth quarter production – Boe/d 20,000 – 27,000
% condensate and NGL 17%
Forecast annual production – Boe/d 20,000 – 23,000
% condensate and NGL 17%
Umbach horizontal wells drilled 6 -12 gross (6.0 – 12.0 net)
Umbach horizontal wells completed 11 – 17 gross (11.0 – 17.0 net)
Umbach horizontal wells connected 11 – 16 gross (11.0 – 16.0 net)

The low case for 2018 guidance offers the least exposure to Station 2 natural gas prices and would result in capital investment of $55.0 million with annual average production of 20,000 to 21,000 Boe per day, a year-over-year increase of 22%. This would fill firm transportation capacity which is 102 Mmcf per day sales in 2018. Capital investment would be approximately 75% of funds flow using the low end of the range for forecast commodity prices (year-over-year growth would be achieved while reducing debt).

The high case for 2018 guidance would result in capital investment of $90.0 million with annual average production of 22,000 to 23,000 Boe per day, a year-over-year increase of 32%. Production in the fourth quarter of 2018 would increase to 25,000 to 27,000 Boe per day. Capital investment would largely equal funds flow using the high end of the range for forecast commodity prices. An infrastructure investment of $7.0 million to add compression at Umbach is required to achieve this growth.

Horizontal well performance and capital efficiencies are expected to continue improving with longer wells being drilled at Umbach. The five wells completed in 2017 that have started production are 28% longer and the improvement in initial rates is encouraging although more history is required to determine the magnitude of the improvement. Capital efficiencies have also improved with the drilling and completion cost per meter of length in 2017 decreasing by 12% when compared to wells completed in 2016. Further improvements are expected given that wells drilled in the second half of 2017 are 60% longer than the average well completed in 2014 to 2016 and will target areas where higher field condensate rates are expected.

The effect of continuing volatility in Western Canadian natural gas prices is largely mitigated for Storm by liquids production, commodity price hedges and firm transportation capacity which has diversified natural gas sales. Liquids production represented 37% of year-to-date revenue, commodity price hedges are currently in place for approximately 30% of forecast 2018 production, and natural gas sales are now more diversified with only 16% to 30% of firm transportation for 2018 being sold at Western Canadian prices. However, incremental production growth above Storm's firm transportation capacity (102 Mmcf per day sales or 20,000 to 21,000 Boe per day) is largely directed to Station 2 where recent prices have provided for the lowest netback within Storm's marketing portfolio. As a result, capital investment has been designed to be flexible where activity and production growth can be quickly adjusted in direct response to the Station 2 natural gas price (currently there are four newly completed horizontal wells that are pipeline connected and can be turned on). Generating a return on invested capital as well as maintaining a strong balance sheet are important to the long-term sustainability of the Company and the amount of production growth that is achieved will largely be dependent on commodity prices.

With a large liquids-rich resource in the Montney at Umbach offering multiple years of drilling inventory, the longer-term focus continues to be growing net asset value for shareholders by converting resource into production and funds flow growth on a per-share basis.

Respectfully,

Brian Lavergne,
President and Chief Executive Officer

November 14, 2017

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 14, 2017 for the period ended September 30, 2017 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 horizontal wells drilled, completed and connected, capital investment plans, infrastructure plans, anticipated United States exports, pipeline capacity, price volatility mitigation strategy and cost reductions. Statements of “reserves” are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

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

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

Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect the operations or financial results of the Company are included or are incorporated by reference in the Company's Annual Information Form dated March 31, 2017 and the MD&A dated November 14, 2017 for the period ended September 30, 2017 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.

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