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JANUARY 2021 UPDATE

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TSX symbol “SRX”, started Sep 2010 • fourth ‘Storm’ since Nov 1998, disciplined with capital investment • officer + director ownership 12% (16% FD)

Market cap $275 MM (~$2.25/share)• 2020 est FF $57 MM, est year end debt $132 MM• 121 MM shares + 10 MM options

Objective is growing funds flow and asset/reserve valueper share from large Montney land position in NE BCResults reflect improving hz’s, low maintenance capex, declining costs‘Free cash flow’ in 2018 – 20 reinvested to build gas plant at Nig Crk and develop new area at Fireweed• contingent on achieving attractive ROR

OVERVIEW

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PRODUCTION GROWTHest Q4/20 prod’n per share+138% from Q4/15 (5 yrs)

4

FINANCIAL RESULTShigher prod’n in 2020 largely offset by lower Chicago nat gas price

5

RESERVESsimple business; FD&A and recycle are the most important metrics

expect material improvement in PDP FD&A for 2020

6

RETURN ON CAPITALfocused on achieving attractive full-cycle rate of return

ROCE affected by non-cash hedging gain/lossQ1-Q3/20 -$21 MM2019 +$2 MM2018 -$6 MM2017 +$25 MM

return on capital reflects PDP recycle (3 yr 1.6 X)

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Montney liquids rich gas• raw gas 1,200 - 1,300 btu/scf~20% liquids• ~41 bbls/mmcf, ~49% condensateDrilled 87 hz’s (82 net)Drill hz in 12 - 15 days• shallow depth ~1,600 metresFull-cycle F&D ~$6/BoeHalf-cycle F&D $2 - $4/Boe(achieved, not a target)• 2020 avg D&C $4.5 MM/hz

(~2300 m & 38 fracs) • 2018-19 Nig Crk hz upper avg 2P:

2,300 Mboe sales (12.7 Bcf raw)Montney producing

hz’s in grey

UMBACH/NIG CREEK/FIREWEED (NE BC)

0.1% - 1.2% H2S requires processing at sour gas plant

McMahon GP accesses 3 sales pipelines

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LARGE LAND POSITION

170 net sections120,000 net acresGrowth from Fireweed

learning from offsetting hz results

material future upside, PDP on 8% lands in upper Montney only

Montney producing hz’s in red

initial hz’s in upper Montney, recent hz’stesting mid & lower

shows raw gas rate + field condensate(gas plant condensate adds ~10 bbls/mmcf)

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UMBACH (100% WI)

2021 hz drills

113 net sections, drilled 73 hzQ4/20 est 14,200 boe/d (19% liquids)• ~38 bbls/mmcf (~55% cond)Facility capacity 150 mmcf/d raw• Q4/20 ~88 mmcf/d raw (incl 10 mmcf/d

from Nig Crk), room for growth• raw gas to McMahon & Stoddart GP’s

(80 mmcf/d firm proc, see appendix)

2021: drill 3 hz’s (Q1) compl 6 hz’s (Q1 - 3, Q4 - 3)

mgmt type curve 8 Bcf/hz(1st yr field cond 10 – 20 bbls/mmcf)

maintaining prod’n to fill firm processing commitments

H2S ~1.2%

half cycle ROR ~35% Stn 2 $2.25/GJ & WTI US$40

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NIG CREEK (100% WI)

16 net sections, drilled 11 hzQ4/20 est 11,600 boe/d (22% liquids)• ~47 bbls/mmcf (~42% cond)Gas plant capacity 60 mmcf/d raw• start-up Feb/20, YTD op cost $1.30/boe• Q4/20: 50 mmcf/d raw to Nig Crk GP

10 mmcf/d raw to McMahon GP

2021 hz drills

mgmt type curve 14 Bcf/hz upper Mont(1st yr field cond 10 – 20 bbls/mmcf)

half cycle upper ROR ~110% half-cycle lower ROR ~60%Stn 2 $2.25/GJ & WTI US$40(economics in appendix)

H2S 0.1%

low op cost results in high ROR, adding inventory in lower Montney

lower Montney 1st hz Dec/191st yr 770 boe/d (25% cond)D&C payout ~14 months

3 - 4 hz’s per year to keep gas plant full

2021: drill & compl 3 hz’s inlower Montney (Q3)

gas plant reduces op cost ~$16 MM/yr vs McMahon GP at 50 mmcf/d raw

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FIREWEED (50% WI)

mgmt type curve average 7.5 Bcf/hzwith high 9.0 Bcf, low 6.5 Bcf(1st yr field cond 30 - 70 bbls/mmcf)

growth 2021+, increases condensate prod’n (CGR 2 – 5 X vs Umbach)

full cycle ROR ~25% for ‘high CGR’Stn 2 $2.25/GJ & WTI US$40/bbl(economics in appendix)

2021: drill 5 hz (Q1 - 3, Q4 - 2)compl 3 hz (Q3) 24 net sections, drilled 3 hz, 50/50 JV

1st prod’n planned for Q4/21• initially ~2,000 Boe/d net (40% liquids)Build 50 mmcf/d field compression • $45 MM gross ($22 MM net)• including pipelines and access road

2021 hz drills

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Estimated lifetimeRaw Gas Sales Liquids Condensate averageBcf/hz(1) Gas Plant Mboe Mbbls Mbbls CGR(2)

Umbach upr 8.0 McMahon(4) 1,420 250 [17%] 140 [10%] 10Nig Crk upr 14.0 Nig Crk(5) 2,880 710 [25%] 275 [10%] 10Nig Crk lwr 6.0 Nig Crk(5) 1,320 390 [30%] 190 [15%] 20-25Fireweed(3) 7.5 McMahon(4) 1,460 360 [25%] 250 [17%] 15-35

high CGR(2) 6.5 1,330 380 280 35low CGR(2) 9.0 1,650 330 210 17

(1) Storm management estimate is forecast average for multiple wells based on historical well performance in each area (will vary for individual wells)

(2) ’CGR’ is field condensate-gas-ratio in barrels per mmcf raw (3) Fireweed estimates are based on offsetting producing hz’s(4) McMahon GP est shrink 12%, plant liquids 24 bbls/mmcf sales (34% cond, 40% C4, 26% C3)(5) Nig Creek GP est shrink 7%, plant liquids 45 bbls/mmcf sales (24% cond, 35% C4, 41% C3)

RECOVERIES BY AREA

est1st yr

30-70

large land position, liquids recovery varies by area

have alternatives for development depending on WTI vs natural gas prices

highest % condensate from NigCrk lower Montney & Fireweed

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NEAR TERM OPPORTUNITIES

Nig Creek• maximize gas plant throughput, netback +$3/boe vs corp avg,

estimated capacity ~60 mmcf/d raw vs design 50 mmcf/d• add inlet compression at gas plant Q2/21 ($7 MM), +800 Boe/d

from existing wells (lower Montney hz +30% with compression)• add inventory in 2nd layer, drill & complete 3 hz’s in 2021 in lower

MontneyFireweed • build 50 mmcf/d facility with 1st prod’n Q4/21 (~2,000 boe/d net)• advance development, drill 5 hz’s & complete 3 hz’s in 2021Umbach• maintain prod’n, drill 3 hz’s & complete 6 hz’s in 2021 • test additional layers (lower & mid Montney), likely in 2022Modify wellbore design to reduce drill/complete cost

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COMPARING HZ RESULTSimproving with longer hz’s & targeting better quality areas

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DAILY GAS RATES

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FIELD CONDENSATE RATES

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FIREWEED TYPE CURVEStype curve based on adjacent producing hz’s

Storm mgmt average type curve is forecast average across Storm's lands for a 2400 m hz, based on performance of offsetting hz’s(low case 6.5 Bcf to high case 9 Bcf)

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UMBACH & NIG CREEK HZ COST

COMPL’N hz’s fracs length cost2018 10 36 2110 m $3.1 MM2019 4 42 2250 m $2.8 MM2020 7 38 2410 m $2.4 MM

DRILLING hz’s length cost 2018 4 2400 m $2.9 MM2019 5 2265 m $2.6 MM2020 7 2280 m $2.1 MM

includes all costs (roads, lease construction, & water handling)

cost reduction in 2020 from both lower service costs and modifying wellbore design

2020 cost declined 17% vs 2019

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COMPARING RESULTSresults show Storm has higher quality land position

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CORPORATE DECLINEflattening decline & improving hz’sreduces maintenance capex

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CAPITAL INVESTMENTlow maintenance capex

2021 capexexpected to be less than forecast funds flow at current strip pricing

‘free cash flow’ in 2018 – 20 reinvested in Nig Crk GP and developing Fireweed

2020 ‘free cash flow’ ~$24 MM when Nig Crk GP & Fireweed capex excluded

2018 – 20 capexfor Nig Crk GP & Fireweed ~$98 MM

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FORECAST PRODUCTIONgrowth contingent on achieving attractive RORpreliminary 2021 forecast 26 - 28,000 boe/d, capex $85 - $90 MM (incl ~$35 MM at Fireweed)

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NATURAL GAS SALES

estimated sales split:2020 2021

Chicago 56% 46%AECO 18% 11%Stn 2 12% 36%Sumas 9%ATP 5% 7%

objective is diversifying sales to mitigate regional price volatility

transportation cost will decrease in 2021 with lower % to Chicago

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US NAT GAS SUPPLY/DEMAND/PRICE

US supply/demand has rebalanced quickly:1) prod’n -7.8 Bcf/d from

peak Nov-Dec/192) demand -1.3 Bcf/d YTD

vs last year (Jan–Oct)

US demand +25% from 2015 to 2020 (consumption + net imports)

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Focused on growing asset/reserve value per share• reflected in 2015 to 2019 results with funds flow per share +44%,

avg CROCE 14%, op cost/G&A/interest -$4/boe

Low maintenance capex as hz’s improve & decline flattens

Majority of recent capex directed to build Nig Crk Gas Plant and advance development at Fireweed• gas plant has attractive ROR (op cost -$16 MM/yr, liquids +600 bpd)

Develop Fireweed and continue to add value at Nig Crk• expect 1st prod’n at Fireweed Q4/21• Nig Crk add inlet compression & develop 2nd layer in lower Montney

Will maintain balance sheet strength with flexible capex• can control capex, not commodity prices

SUMMARY

moderate growth near term with focus on reducing debt to increase financial flexibility

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For further information please contact:Brian Lavergne, President and Chief Executive Officer

Michael Hearn, Chief Financial Officer

Carol Knudsen, Manager Corporate Affairs

Address: #600, 215 – 2nd Street S.W., Calgary, Alberta T2P 1M4

Phone: (403) 817-6145

Fax: (403) 817-6146

Website: www.stormresourcesltd.com

STORM RESOURCES LTD CONTACT INFO

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Reserves – All reserves in this presentation are, unless indicated otherwise, as at December 31, 2019 as evaluated by Insite PetroleumConsultants Ltd. in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas EvaluationHandbook and National Instrument 51-101 – Standards for Disclosure for Oil and Gas Activities.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. Barrels of oil equivalent (“Boe”)may be misleading, particularly if used in isolation. A Boe conversion ratio of six Mcf to one barrel (“bbl”) is based on an energyequivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. AllBoe measurements and conversions in this report are derived by converting natural gas to oil in the ratio of six thousand cubic feet ofgas to one barrel of oil.Type Curves – Certain type curves presented herein represent estimates of production decline and ultimate volumes expected to berecovered over the life of a well. Storm management generated the 14 Bcf raw (ultimate raw gas volume expected to be recovered overthe life of a well based on the type curve) with 7.3 mmcf/d IP365 (average first year production rate) and the 8 Bcf raw with 4.1 mmcf/dIP365 Upper Montney type curves using the first 9 months of actual calendar day production data from the horizontal wells completedin 2017. After the first 9 months, production is declined at the same rate as the forecast decline used by InSite for future proved andprobable drilling locations at Umbach and Nig Creek in the 2019 reserve evaluation. Individual wells may be higher or lower but,management expects the average to be consistent with the type curve for a larger number of wells.Forward-Looking Information - certain information set forth in this presentation, including management’s assessment of Storm’s futureplans and operations, contains forward-looking statements. These statements are based on current beliefs and expectations based onthe information available at the time the applicable assumptions were made. By their nature, forward-looking statements are subject tonumerous risks, uncertainties and assumptions, some of which are beyond the Company’s control, including the material risks describedin Storm’s Annual Information Form dated March 30, 2020 under “Risk Factors” and Management’s Discussion and Analysis for thequarter ending September 30, 2020 under “Business Risks”, the effect of general economic conditions, industry conditions, volatility ofcommodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other industryparticipants, the lack of availability of qualified personnel or management, stock market volatility and ability to access sufficient capitalfrom internal and external sources. Readers are advised that the assumptions used in the preparation of such information, althoughconsidered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed onforward-looking statements. Storm’s actual results, performance or achievement, could differ materially from those expressed in, orimplied by, these forward-looking statements. Storm disclaims any intention or obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required under securities law.Reference is made to “Forward-Looking Statements” in Storm’s Management’s Discussion and Analysis dated November 10, 2020 for theperiod ending September 30, 2020 which may be found on Storm’s website at www.stormresourcesltd.com or on SEDAR atwww.sedar.com and which are hereby incorporated by reference in this presentation and which outline a number of assumptions, risks,and uncertainties associated with forward-looking statements.

ADVISORY

about:blankabout:blank

APPENDIX

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2021 Preliminary

2020 GuidanceNov 10/20 2019 2018 2017 2016

Average – Boe/dper MM shares

% liquids

26,000 – 28,00022221%

23,000 – 23,50019121%

20,18216719%

20,53816918%

16,01713218%

13,21910917%

FX $US/$CdnChicago US$/mmbtuAECO $/GJBC STN 2 $/GJWTI $US/bblEdm cond diff $US/bbl

0.76$2.65$2.50$2.50

$40.00($3.00)

0.75$1.90$2.15$2.15

$38.50($2.25)

0.75$2.42$1.67$0.96$57

($4.18)

0.77$3.02$1.43$1.19$65

($3.77)

0.77$2.90$2.04$1.49$51

($2.44)

0.76$2.47$2.05$1.64$43

Gas ($/mcf)NGL ($/bbl)Condensate ($/bbl)Transportation ($/Boe)

Net Revenue ($/Boe)Production Cost ($/Boe)Royalty (% revenue)Hedging ($MM)Cash G&A ($MM)Interest ($MM)

$17.00 - $18.00($4.00 - $4.50)

(7% - 8%)($8.0 - $10.0)($6.0 - $7.0)($7.0 - $8.0)

$12.75 - $13.00($4.50 - $4.75)

(7%)$6.5 - $7.5

($6.0 - $6.5)($7.0 - $7.5)

$3.21$10.75$66.03($5.66)$17.88($5.87)(4.7%)($8.8)($6.9)($5.2)

$3.98$35.69$75.61($5.84)$24.34($5.50)(4.4%)($22.7)($6.1)($4.2)

$3.61$25.15$61.80($5.82)$20.33($6.04)(5.9%)($2.4)($6.2)($3.9)

$2.05$12.51$49.34($0.45)$15.52($6.78)(4.9%)$4.5($5.3)($3.3)

Funds Flow ($MM)per Share

per Boe

$90 - $99$0.74 - $0.81

$55 - $57$0.45 - $0.47

$60$0.49$8.09

$100$0.82

$13.34

$64$0.53

$10.96

$34$0.29$7.10

Capital Investment ($MM) $85 - $90 $58 $97 $85 $82 $65Ending Debt ($MM) $129 $91 $106 $90

GUIDANCE & RESULTS

bank line $190 MM29

increase in debt since 2018 partially funded Nig Crk GP (total investment $84 MM during 2018 – 20)

2019 ‘free cash flow’ $24 MM if $61 MM capex for Nig Crk GP is deducted

Flat Pricing: Stn 2 $2.25/GJ WTI US$40/bbl Edm cond -US$4/bbl FX 0.76butane 37% WTI propane Conway US$0.45/gal & FEI US$0.67/gal

Fireweed 7.5 Bcf raw(1) Nig Creek 14.0 Bcf raw(1)Full-Cycle (growth) Half-Cycle (maintain prod’n)

Cumulative Sales 1,460 Mboe, 25% liquids(2) 2,880 Mboe, 25% liquids (3)field CGR 27 bbls/mmcf(1)(4) field CGR 10 bbls/mmcf(1)(4)

Avg 1st Year Sales 3.5 mmcf/d sales + 280 bpd liq(2)(5) 6.75 mmcf/d sales + 400 bpd liq(3)(5)4.0 mmcf/d raw, field CGR 49 bbls/mmcf(1)(5) 7.3 mmcf/d raw, field CGR 14 bbls/mmcf(1)(5)

Propane $11.10/bbl (Conway) $6.75/bbl (FEI)Butane $20.00/bbl $10.30/bblCondensate $45.70/bbl $43.50/bblNat gas $2.80/mcf $2.70/mcfRevenue 1st Year $24.40/boe $18.40/boeTransportation -$3.20 ($0.27/mcf & $5.10/bbl) -$2.70 ($0.38/mcf & $3.60/bbl)Op Cost -$5.70 -$1.25Royalty -$1.00 (~5% with hz roy credit) -$0.95 (~5% with hz roy credit)Field Netback 1st Year $14.50/boe $13.50/boecapex $8.8 MM/hz $5.1 MM/hzF&D $6.00/boe $1.80/boebtax ROR 20% 110%payout 3.0 yrs 0.7 yrs(1) Storm management estimates(2) McMahon GP est shrink 12%, plant liquids 24 bbls/mmcf sales (34% C5/cond, 40% C4, 26% C3)(3) Nig Creek GP est shrink 6.5%, plant liquids 44 bbls/mmcf sales (24% C5/cond, 34% C4, 42% C3)(4) field CGR is lifetime avg field condensate-gas ratio bbls/mmcf raw(5) 1st year rate uses estimated 1st yr field CGR (Fireweed 54 bbls/mmcf raw, Nig Crk 14 bbls/mmcf raw)

ECONOMICS FIREWEED & NIG CREEK

$6400 K/hz D & C $600 K/hz gathering, tie-in

$1700 K/hz facility[$45 MM for 50 mmcf/dcompression, 25 hz’s over5 yrs to fill = $1,800 K/hz]

$4800 K/hz D & C$300 K/hz tie-in

2021 fwd strip 10% - 20% higher

30 expect Fireweed D&C to improve over time

Fireweed high CGR area ROR ~25% at WTI $40, ~35% at WTI $50

UMBACH & NIG CREEK CUM GAS VS TIME

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HEDGING (to Nov 10/20)growth is not hedged

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Q4/20 2021Natural Gas Hedges

% Current Nat Gas Prod’n 50% 45%Collars 33,000 Mcf/d (1)

floor Cdn$2.99/Mcf (2)ceiling Cdn$3.68/Mcf (2)

9,000 Mcf/d (1)floor Cdn$3.48/Mcf (2)

ceiling Cdn$4.15/Mcf (2)

Fixed Price 28,000 Mcf/d (1)Cdn$2.90/Mcf (2)

48,700 Mcf/d (1)Cdn$3.16/Mcf (2)

Liquids Hedges% Current Liquids Prod’n 37% 25%Collars 800 Bpd WTI

floor Cdn$57.81/bblceiling Cdn$67.60/bbl

650 Bpd WTIfloor Cdn$50.54/bbl

ceiling Cdn$59.93/bblFixed Price 950 Bpd WTI

Cdn$59.75/bbl750 Bpd WTI

Cdn$53.01/bbl200 Bpd Propane

Conway Cdn$28.25/bbl50 Bpd Propane

Conway Cdn$27.30/bbl

(1) using corporate average heat content 1.23 GJ per Mcf or 1.17 Mmbtu per Mcf.(2) hedges in US$ converted using exchange rate of Cdn$1.34 per US$1.

Processing (firm commitments + Nig Crk GP capacity)McMahon GP 65 mmcf/d raw 10 mmcf/d to Dec/22, 55 mmcf/d to Dec/31Nig Crk GP 60 mmcf/d raw owned capacity, 100% working interestStoddart GP 15 mmcf/d raw 15 mmcf/d to Oct/22

140 mmcf/d raw (127 mmcf/d sales)2020 actual ~123 mmcf/d raw

Transportation commitments2020 2021

Alliance - Chicago 59 mmcf/d 59 mmcf/dAlliance - ATP 15 10 Spectra - Stn 2 24 44Spectra/TCPL - AECO 14 14Spectra - Stn 2/Sumas 10

121 mmcf/d 127 mmcf/dIT to Stn 2 or Chicago for sales > commitments

PROCESSING & TRANSPORTATIONavoid overcommitting, reduces capex flexibility when prices decline

future transportation:+7 mmcf/d AECO - Empress Apr/21+7 mmcf/d AECO - Iroquois Nov/2133

estimated 2021 sales based on transportation commitmentsChicago 46%Stn 2 36%AECO 11%ATP 7%

2021 FWD STRIP (Dec 21/20)NYMEX US$2.77/mmbtuNYMEX - Chicago diff -US$0.16/mmbtuFX 0.78AECO $2.49/GJAECO - Stn 2 diff +$0.07/GJ

Sell in Chicago (Alliance pipeline)Chicago price US$2.61/mmbtuChicago price cdn$3.18/GJAlliance fuel -cdn$0.15/GJAlliance tariff -cdn$1.10/GJ@ McMahon GP cdn$1.93/GJ

$2.37/mcfSell at AECO (Spectra + TCPL pipelines)AECO $2.49/GJTCPL & Spectra fuel -$0.06/GJTCPL & Spectra 5 yr tariff -$0.42/GJ@ McMahon GP cdn$2.01/GJ

$2.47/mcf

Sell at Stn 2 (Spectra T-north pipeline)Stn 2 $2.56/GJSpectra fuel -$0.01/GJSpectra 5 yr tariff + fuel -$0.18/GJ@ McMahon GP cdn$2.37/GJ

$2.92/mcf2021 firm transport & marketing:

Alliance Pipeline to Chicago 59 mmcf/d (72,000 GJ/d)Chicago price less pipeline tariff + fuel $1.25/GJ

Alliance Pipeline to ATP 10 mmcf/d (12,000 GJ/d)ATP price less pipeline tariff + fuel $0.55/GJ

Spectra T-north 44 mmcf/d (54,000 GJ/d)44 mmcf/d Stn 2 price less pipeline tariff + fuel $0.19/GJ

Spectra T-north & TCPL (Sunset) 14 mmcf/d (17,000 GJ/d)AECO price less pipeline tariff + fuel $0.48/GJ

PLANT GATE NAT GAS PRICE CALCULATION

remainder on IT to Chicago or Stn 2

high heat content 1.23 GJ = 1 mcf1.17 mmbtu = 1 mcf

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funds flow netback comparison for 2019Marcellus/Utica Storm

$US $Cdnrevenue $2.58/mcfe $2.98/mcfecash costs -$1.60 -$1.43

$0.98/mcfe $1.55/mcfehedging +$0.22 -$0.20funds flow $1.20/mcfe $1.35/mcfe

MARCELLUS/UTICA NAT GAS PRODUCERSfrom AR, ASCENT, CNX, COG, EQT, GPOR, MR, RRC, SWN (~60% Appalachiaprod’n in 2019)

financially challenged • high debt• rising cash costs• declining funds flow

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Marcellus/Utica funds flow netbackscash funds costs flow

2017 $1.45/mcfe $1.39/mcfe2018 $1.43 $1.662019 $1.60 $1.20Q1-Q3/20 $1.60 $0.78

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BP REVIEW OF WORLD ENERGY 2020

wind typically generates ~25% of nameplate capacity (40% offshore) and solar ~20%; requires other source of generation to offset low operating efficiency

demand for gas fired electricity generation will increase with renewable growth

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