Storm Resources Ltd. — Interim / Quarterly Report 2021

Aug 12, 2021

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Thousands of Cdn$, except volumetric and per-share amounts Three Months to June 30, 2021 Three Months to June 30, 2020 Six Months to June 30, 2021 Six Months to June 30, 2020 FINANCIAL Revenue fromproduct sales(1) 65,554 30,191 139,228 72,114 Funds flow 27,902 10,904 64,434 27,793 Per share – basic and diluted($) 0.23 0.09 0.53 0.23 Net income (loss) (11,843) (11,665) (694) (1,153) Per share – basic and diluted($) (0.10) (0.10) (0.01) (0.01) Cash return on capital employed(“CROCE”)(2) 19% 12% 19% 12% Return on capital employed(“ROCE”)(2)(4) 2% 2% 2% 2% Capital expenditures 10,017 2,394 34,869 28,869 Debt including working capital deficiency/ surplus(2)(3) 101,712 130,317 101,712 130,317 Common shares (000s) Weighted average – basic 121,892 121,557 121,804 121,557 Weighted average – diluted 121,892 121,557 121,804 121,557 Outstandingend ofperiod – basic 122,042 121,557 122,042 121,557 OPERATIONS (Cdn$ per Boe) Revenue from product sales(1) 26.82 13.86 29.15 16.55 Transportation costs (4.85) (5.50) (4.90) (5.24) Revenue net of transportation 21.97 8.36 24.25 11.31 Royalties (0.97) (0.44) (1.74) (0.70) Production costs (4.64) (4.50) (4.47) (4.83) Field operating netback(2) 16.36 3.42 18.04 5.78 Realized gain (loss) on risk management contracts (3.71) 2.99 (3.00) 2.12 General and administrative (0.50) (0.72) (0.64) (0.79) Interest and finance costs (0.65) (0.68) (0.77) (0.71) Decommissioningexpenditures (0.08) (0.01) (0.16) (0.03) Funds flowper Boe 11.42 5.00 13.47 6.37 Barrels of oil equivalent per day (6:1) 26,862 23,935 26,389 23,941 Natural gas production Thousand cubic feet per day 130,173 114,772 127,364 115,365 Price(Cdn$ per Mcf)(1) 3.58 2.23 4.08 2.39 Condensate production Barrels per day 2,434 2,305 2,420 2,464 Price(Cdn$ per barrel)(1) 78.53 25.92 74.58 44.41 NGL production Barrels per day 2,732 2,501 2,742 2,249 Price(Cdn$ per barrel)(1) 23.28 6.23 25.03 4.92 Wells drilled (net) - - 1.5 1.0 Wells completed (net) - - 3.0 3.5 Wells startedproduction(net) 1.0 1.0 3.0 3.0 Highlights	Thousands of Cdn$, except volumetric and per-share amounts Three Months to June 30, 2021 Three Months to June 30, 2020 Six Months to June 30, 2021 Six Months to June 30, 2020 FINANCIAL Revenue fromproduct sales(1) 65,554 30,191 139,228 72,114 Funds flow 27,902 10,904 64,434 27,793 Per share – basic and diluted($) 0.23 0.09 0.53 0.23 Net income (loss) (11,843) (11,665) (694) (1,153) Per share – basic and diluted($) (0.10) (0.10) (0.01) (0.01) Cash return on capital employed(“CROCE”)(2) 19% 12% 19% 12% Return on capital employed(“ROCE”)(2)(4) 2% 2% 2% 2% Capital expenditures 10,017 2,394 34,869 28,869 Debt including working capital deficiency/ surplus(2)(3) 101,712 130,317 101,712 130,317 Common shares (000s) Weighted average – basic 121,892 121,557 121,804 121,557 Weighted average – diluted 121,892 121,557 121,804 121,557 Outstandingend ofperiod – basic 122,042 121,557 122,042 121,557 OPERATIONS (Cdn$ per Boe) Revenue from product sales(1) 26.82 13.86 29.15 16.55 Transportation costs (4.85) (5.50) (4.90) (5.24) Revenue net of transportation 21.97 8.36 24.25 11.31 Royalties (0.97) (0.44) (1.74) (0.70) Production costs (4.64) (4.50) (4.47) (4.83) Field operating netback(2) 16.36 3.42 18.04 5.78 Realized gain (loss) on risk management contracts (3.71) 2.99 (3.00) 2.12 General and administrative (0.50) (0.72) (0.64) (0.79) Interest and finance costs (0.65) (0.68) (0.77) (0.71) Decommissioningexpenditures (0.08) (0.01) (0.16) (0.03) Funds flowper Boe 11.42 5.00 13.47 6.37 Barrels of oil equivalent per day (6:1) 26,862 23,935 26,389 23,941 Natural gas production Thousand cubic feet per day 130,173 114,772 127,364 115,365 Price(Cdn$ per Mcf)(1) 3.58 2.23 4.08 2.39 Condensate production Barrels per day 2,434 2,305 2,420 2,464 Price(Cdn$ per barrel)(1) 78.53 25.92 74.58 44.41 NGL production Barrels per day 2,732 2,501 2,742 2,249 Price(Cdn$ per barrel)(1) 23.28 6.23 25.03 4.92 Wells drilled (net) - - 1.5 1.0 Wells completed (net) - - 3.0 3.5 Wells startedproduction(net) 1.0 1.0 3.0 3.0 Highlights
	FINANCIAL Revenue fromproduct sales(1) 65,554 30,191 139,228 72,114
	Funds flow 27,902 10,904 64,434 27,793 Per share – basic and diluted($) 0.23 0.09 0.53 0.23
	Net income (loss) (11,843) (11,665) (694) (1,153) Per share – basic and diluted($) (0.10) (0.10) (0.01) (0.01)
	Cash return on capital employed(“CROCE”)(2) 19% 12% 19% 12%
	Return on capital employed(“ROCE”)(2)(4) 2% 2% 2% 2%
	Capital expenditures 10,017 2,394 34,869 28,869
	Debt including working capital deficiency/ surplus(2)(3) 101,712 130,317 101,712 130,317
	Common shares (000s) Weighted average – basic 121,892 121,557 121,804 121,557 Weighted average – diluted 121,892 121,557 121,804 121,557 Outstandingend ofperiod – basic 122,042 121,557 122,042 121,557
	OPERATIONS (Cdn$ per Boe) Revenue from product sales(1) 26.82 13.86 29.15 16.55 Transportation costs (4.85) (5.50) (4.90) (5.24)
	Revenue net of transportation 21.97 8.36 24.25 11.31 Royalties (0.97) (0.44) (1.74) (0.70) Production costs (4.64) (4.50) (4.47) (4.83)
	Field operating netback(2) 16.36 3.42 18.04 5.78 Realized gain (loss) on risk management contracts (3.71) 2.99 (3.00) 2.12 General and administrative (0.50) (0.72) (0.64) (0.79) Interest and finance costs (0.65) (0.68) (0.77) (0.71) Decommissioningexpenditures (0.08) (0.01) (0.16) (0.03)
	Funds flowper Boe 11.42 5.00 13.47 6.37
	Barrels of oil equivalent per day (6:1) 26,862 23,935 26,389 23,941
	Natural gas production Thousand cubic feet per day 130,173 114,772 127,364 115,365 Price(Cdn$ per Mcf)(1) 3.58 2.23 4.08 2.39
	Condensate production Barrels per day 2,434 2,305 2,420 2,464 Price(Cdn$ per barrel)(1) 78.53 25.92 74.58 44.41
	NGL production Barrels per day 2,732 2,501 2,742 2,249 Price(Cdn$ per barrel)(1) 23.28 6.23 25.03 4.92
	Wells drilled (net) - - 1.5 1.0 Wells completed (net) - - 3.0 3.5 Wells startedproduction(net) 1.0 1.0 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 attached Management’s Discussion and Analysis. 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 $30.3 million for the three months ended June 30, 2021 (three months ended June 30, 2020 - unrealized loss of $13.8 million) and an unrealized loss of $39.0 million for the six months ended June 30, 2021 (six months ended June 30, 2020 - unrealized loss of $3.3 million) .

PRESIDENT’S MESSAGE

2021 SECOND QUARTER HIGHLIGHTS

Improving commodity prices continue to provide a ‘tail wind’ with funds flow exceeding capital investment for the second consecutive quarter which resulted in debt being reduced by $18 million from the previous quarter and by $30 million in the first half of 2021. Capital efficiencies remain strong with production increasing 4% from the previous quarter with only one new well starting production in early June.

• Production was 26,862 Boe per day which is a 12% increase year over year and a 4% increase from the previous quarter. This was consistent with guidance for an average of 25,000 to 27,000 Boe per day.

• Liquids production (condensate plus NGL) totaled 5,166 barrels per day which was 19% of total production and 35% of total revenue. Liquids production increased 7% from last year.

• During the quarter, one new horizontal well started production in early June at Umbach and, year to date, three new horizontal wells started production, all at Umbach.

• Performance of recent wells continues to be strong with the Nig Creek wells completed in 2020 having an average IP270 of 1,900 Boe per day sales (23% liquids) and the Umbach wells completed in 2021 having an average IP90 of 1,080 Boe per day sales (22% liquids).

• Revenue net of transportation was $21.97 per Boe, a 163% increase from last year as a result of higher commodity prices and a 12% decrease in the per-Boe transportation cost. Liquids prices saw the biggest improvement with condensate and NGL prices rising 203% and 274% respectively.

• Production, general and administrative, and interest and finance costs totaled $5.79 per Boe, a year-over-year reduction of 2%.

• Realized hedging loss was $9.1 million, or $3.71 per Boe, which is a result of the rapid and unexpected improvement in commodity prices over the last 12 months.

• Funds flow was $27.9 million, or $0.23 per share, an increase of 155% from last year. This was largely from higher production and higher commodity prices which were partially offset by the $9.1 million hedging loss.

• The net loss was $11.8 million, or $0.10 per share, which was largely the result of an unrealized hedging loss of $30.3 million (change in the mark-to-market valuation of future hedging contracts).

• Cash return on capital employed (CROCE) was 19% and return on capital employed (ROCE) was 2% with both calculated on a 12-month trailing basis. ROCE was reduced by non-cash hedging losses of $30.3 million in the quarter and $39.0 million for the year to date.

• Capital investment was $10 million (versus guidance for $14 million). At Fireweed, investment included $2.2 million net for equipment deposits for the facility and $0.8 million net to complete the gathering and sales pipelines. At Nig Creek, $5.2 million was invested to purchase an inlet compressor for the gas plant which was installed in July.

• Total debt including working capital surplus was $102 million which is a reduction of $18 million from the previous quarter and represents 0.9 X annualized quarterly funds flow.

• Commodity price hedges protect revenue on approximately 47% of current production for the remainder of 2021 and on approximately 33% of current production for 2022. The financial liability for future hedging contracts totaled $47 million using forward strip pricing at the end of the quarter.

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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 approximately 120,000 net acres (189 gross sections, 170 net sections) with 90 horizontal wells (83.4 net) drilled to the end of the second quarter.

Field activity in the second quarter was minimal and included completing construction of gathering and sales pipelines at Fireweed plus work to upgrade leases and roads in preparation for a busy third quarter. Wet weather in June and early July delayed some activity including the movement of a drilling rig to Nig Creek by approximately three weeks.

Expected field activity in the third quarter will include drilling and starting completions on four lower Montney wells (4.0 net) at Nig Creek, drilling three wells (3.0 net) at Umbach, drilling one well (0.5 net) and completing three wells (1.5 net) at Fireweed, installing inlet compression at the Nig Creek Gas Plant in early July, and starting construction of the field compression facility at Fireweed.

At the end of the second quarter, there were seven Montney horizontal wells (4.0 net) that had not started producing which included one well (1.0 net) at Umbach and six wells (3.0 net) at Fireweed.

At Umbach, produced raw natural gas contains 1.2% H2S, field compression capacity totals 150 Mmcf raw per day, and firm processing commitments total 80 Mmcf raw per day. Second quarter gross raw gas averaged 96 Mmcf per day (Storm working interest approximately 98%) while net sales were 16,450 Boe per day (80.8 Mmcf per day, 1,515 barrels per day condensate, 1,470 barrels per day NGL). Activity in the remainder of 2021 is expected to include drilling and completing four wells (4.0 net).

At Nig Creek (100% working interest), produced raw natural gas contains up to 0.5% H2S and is directed to Storm’s 100% working interest sour gas plant. Gas plant inlet volumes in the second quarter averaged 52 Mmcf per day raw, sales were 10,065 Boe per day (47.4 Mmcf per day, 910 barrels per day condensate, 1,255 barrels per day NGL), and the production cost was $1.25 per Boe. Capacity of the gas plant is estimated to be 70 Mmcf per day at current average H2S of 0.3%. Activity in the remainder of 2021 is expected to fill the gas plant and will include adding inlet compression in July plus drilling and completing four wells (4.0 net) this summer in the lower Montney.

At Fireweed (50% working interest), activity in the remainder of 2021 is expected to include construction of a 50 Mmcf raw per day field compression facility, drilling five wells (2.5 net) and completing six wells (3.0 net). First production of approximately 2,500 Boe per day net is expected in the fourth quarter of 2021 from five wells (2.5 net).

Recent wells at Nig Creek and Umbach continue to meet or exceed expectations:

• The four wells completed at Nig Creek in 2020 started producing in late October, have an average calendar day IP270 of 9.5 Mmcf per day raw or approximately 1,900 Boe per day sales (8.8 Mmcf per day, 200 barrels per day condensate, 235 barrels per day NGL), and cumulative operating income from all four wells was $41 million to the end of June. Payout of the $17 million cost to drill, complete and equip was achieved in five months.

• The three wells completed at Umbach in 2021 started producing in late March and early June, have an average calendar day IP90 of 5.7 Mmcf per day raw or approximately 1,080 Boe per day sales (5.1 Mmcf per day, 155 barrels per day condensate, 80 barrels per day NGL), and cumulative operating income from all three wells was $5 million to the end of June. The cost was $15 million to drill, complete and equip.

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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). Future production growth is not hedged.

production growth is not hedged.
	H2/21	2022
Natural Gas Hedges
% Current Nat Gas Production(1)	48%	36%
	4,500 Mcf/d(2)	10,300 Mcf/d(2)
Collars	Floor Cdn$3.92per Mcf(3)	Floor Cdn$3.57per Mcf(3)
	CeilingCdn$4.74per Mcf(3)	CeilingCdn$4.56per Mcf(3)
	56,200 Mcf/d(2)	35,100 Mcf/d(2)
Fixed Price	Cdn$3.19per Mcf(3)	Cdn$3.25per Mcf(3)
Crude Oil Hedges
% Current Liquids Production(1)	45%	26%
	1,250 Bpd	1,100 Bpd
Collars	Floor WTI Cdn$53.41per barrel(3)	Floor WTI Cdn$60.95per barrel(3)
	CeilingWTI Cdn$64.24per barrel(3)	CeilingWTI Cdn$74.98per barrel(3)
	650 Bpd	150 Bpd
	WTI Cdn$54.33per barrel	WTI Cdn$63.78per barrel(3)
Fixed Price	400 Bpd Propane	100 Bpd Propane
	Cdn$47.14per barrel(3)	Cdn$58.30per barrel(3)

(1) Using Q2 2021 actual production.

(2) Using corporate average heat content 1.22 GJ per Mcf and 1.16 Mmbtu per Mcf.

(3) Hedges in US$ are converted using an exchange rate of Cdn$1.24 per US$1.

OUTLOOK

Production in the third quarter of 2021 is forecast to average 25,000 to 28,000 Boe per day (production to date in the quarter has averaged approximately 26,500 Boe per day based on field estimates). Capital investment in the quarter is forecast to be $43 to $48 million which includes $18 million ($9.0 million net) for construction of the Fireweed facility, $17 million to drill 7.5 net wells and $15 million to complete and equip 5.5 net wells.

Updated guidance for 2021 is provided below. Capital investment is being increased to a range of $110 to $115 million from $85 to $90 million. Forecast pricing and annual funds flow was updated to reflect actual prices to date with assumed prices for the remainder of the year being approximately equal to the current forward strip.

2021 Guidance

2021 Guidance
	Previous	Current
	May 12, 2021	August 11, 2021
Cdn$/US$ exchange rate	0.79	0.80
Chicago daily natural gas - US$/Mmbtu(1)	$3.50	$4.10
AECO daily natural gas - Cdn$/GJ(1)	$2.60	$3.25
BC Station 2 daily natural gas - Cdn$/GJ	$2.55	$3.20
WTI - US$/Bbl	$57	$65
Edmonton condensate diff - US$/Bbl	($1.30)	($0.00)
Est transportation cost - $/Boe	$4.50 - $4.75	$4.50 - $4.75
Est revenue net of transport (excl hedges) - $/Boe	$20.50 - $21.50	$26.25 - $26.75

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2021 Guidance

2021 Guidance
	Previous	Current
	May 12, 2021	August 11, 2021
Est royalty rate (% revenue net transportation)	8% - 9%	8% - 9%
Est production cost - $/Boe	$4.00 - $4.50	$4.00 - $4.50
Est mid-point field operating netback - $/Boe(2)	$14.95	$20.00
Est realized hedging gains or (losses) - $ million	($15.0 - $17.0)	($40.0 - $45.0)
Est cash G&A - $ million	$6.0 - $7.0	$5.0 - $6.0
Est interest expense - $ million	$6.0 - $7.0	$6.0 - $7.0
Est capital investment (excluding A&D) - $ million	$85 - $90	$110 - $115
Forecast fourth quarter Boe/d	30,000 - 32,000	30,000 - 32,000
Forecast fourth quarter liquids Bbls/d	6,800 - 7,300	6,800 - 7,300
Forecast annual Boe/d	26,000 - 28,000	26,000 - 28,000
Forecast annual liquids Bbls/d	5,600 - 6,000	5,600 - 6,000
Est annual funds flow - $ million(3)	$112 - $122	$135 - $149
Horizontal wells drilled - gross	11 - 12 (9.0 - 9.5 net)	16 (12.0 net)
Horizontal wells completed - gross	13 (11.5 net)	17 (14.0 net)
Horizontal wells starting production - gross	14 - 15 (11.5 - 12.5 net)	19 (15.0 net)

(1) Approximately 50% of natural gas sales are at the daily or spot price and 50% at the monthly index price.

(2) Based on the mid-point for each of revenue net of transportation, royalty rate and production costs.

(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.

2021 Guidance History

					Forecast
	Chicago	BC Station 2		Capital	Annual	Forecast Annual
	Daily	Daily	WTI	Investment	Funds Flow	Production
	(US$/Mmbtu)	(Cdn$/GJ)	(US$/Bbl)	($ million)	($ million)	(Boe/d)
Nov 10, 2020	$2.65	$2.50	$40	$85 - $90	$90 - $99	26,000 - 28,000
Mar 2, 2021	$3.50	$2.55	$51	$85 - $90	$109 - $120	26,000 - 28,000
May 12, 2021	$3.50	$2.55	$57	$85 - $90	$112 - $122	26,000 - 28,000
August 11, 2021	$4.10	$3.20	$65	$110 - $115	$135 - $149	26,000 - 28,000

2021 Investment and Activity by Area

	Capital Investment	% for	Net Wells	Net Wells	Net Wells
	($million)	Infrastructure	Drilled	Completed	Starting Production
Fireweed	$42 - $47	46%	4.0	3.0	4.0
Nig Creek	$29	28%	4.0	4.0	4.0
Umbach	$39		4.0	7.0	7.0
Total	$110 - $115		12.0	14.0	15.0

Capital investment is being increased by $25 million which represents approximately half of the increase in forecast annual funds flow from the initial estimate in November 2020 (remainder will be directed to debt reduction which also increases asset value per share). The increase adds 3.0 net drills and 2.5 net completions, includes $3 million to advance construction of a multi-well pad and access road into 2021 from 2022, and assumes that inflation adds $2 million to the cost of previously planned drills and completions in the second half of 2021. The additional wells will start production late in the fourth quarter, are expected to benefit from higher winter pricing for natural gas and are forecast

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to add approximately 2,000 Boe per day to average production in 2022. Strong rates of return are anticipated from the incremental capital investment given unused capacity at existing facilities with half-cycle payouts estimated to be less than one year at current forward strip commodity prices.

Development at Fireweed continues to progress as planned with construction of the large diameter gathering and sales pipelines completed early in the second quarter while site preparation for the facility has been completed and equipment deliveries will start in late August. Wet weather in June resulted in a delayed start to site preparation for the facility; however, first production of approximately 2,500 Boe per day net is still expected in the fourth quarter of 2021.

The financial liability for future hedges totaled $47 million at the end of the second quarter. The large future liability is the result of the rapid and unexpected increase in commodity prices over the last 12 months since the hedges were layered on. In response to the backwardation in pricing where future prices are below current spot prices, additional hedges for the second half of 2022 will be layered on more slowly depending on pricing and market conditions. This is expected to result in approximately 45% of current production being hedged six to nine months forward with a lesser volume 10 to 18 months forward. Currently, approximately 45% of production is hedged 12 months forward through the first half of 2022 while the second half of 2022 is approximately 25% hedged.

There is no additional information available at this time regarding the Judgement in the Supreme Court of British Columbia in the Yahey (Blueberry River First Nations) v. British Columbia case on June 29, 2021 which declared that cumulative effects of industrial development have infringed on rights guaranteed under Treaty 8. At this time, the Judgement is not expected to affect Storm’s planned activity for 2021 and 2022. Potential longer term effects, if any, are not known at this time.

The focus of the business plan in 2021 remains on growing asset value and funds flow per share which will largely be accomplished by:

• 1) Filling the Nig Creek Gas Plant which reduces production cost and increases the proportion of liquids;

• 2) Adding future drilling inventory in the lower Montney at Nig Creek;

• 3) Starting production from the Fireweed area where condensate is forecast to be a higher proportion of production; 4) Continuing to evolve drilling and completion techniques to reduce well costs while improving performance; and

• 5) Reducing debt to increase future financial flexibility for acquisitions, accelerating organic growth or returning capital to shareholders.

This summer will be busy in terms of field operations and we look forward to reporting on our progress in the second half of the year.

Respectfully,

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Brian Lavergne, President and Chief Executive Officer

August 11, 2021

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 natural gas to one barrel of oil. Mboe means 1,000 Boe.

Initial Production Rates - References to initial production rates (“IP”), and other short-term production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. Additionally, such rates may also include recovered "load oil" fluids used in well completion stimulation. Readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, the Company cautions that the test results should be considered to be preliminary.

Forward-Looking Statements - Such statements made in this report are subject to the limitations set out in Storm’s Management’s Discussion and Analysis dated August 11, 2021 for the three and six months ended June 30, 2021.

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MANAGEMENT’S DISCUSSION & ANALYSIS

INTRODUCTION

Set out below is management’s discussion and analysis ("MD&A") of financial and operating results for Storm Resources Ltd. (“Storm” or the “Company”) for the three and six months ended June 30, 2021. It should be read in conjunction with (i) the Company’s unaudited condensed interim consolidated financial statements for the three and six months ended June 30, 2021, (ii) the Company’s MD&A and audited consolidated financial statements for the year ended December 31, 2020, and (iii) the press release issued by the Company on August 11, 2021, and other operating and financial information included in this report. All of these documents as well as the Company’s Annual Information Form dated March 31, 2021 are filed on SEDAR (www.sedar.com) and appear on the Company’s website (www.stormresourcesltd.com).

The Company trades on the Toronto Stock Exchange (“TSX”) under the symbol “SRX”.

This MD&A is dated August 11, 2021.

See discussion related to “Forward Looking Statements”, “Boe Presentation”, and “Non-GAAP Measurements” on pages 22 to 24.

BASIS OF PRESENTATION

Financial data presented below have been derived from the Company’s unaudited condensed interim consolidated financial statements (the “financial statements”) for the three and six months ended June 30, 2021, prepared in accordance with International Accounting Standard (“IAS”) 34 “Interim Financial Reporting” using accounting policies consistent with International Financial Reporting Standards (“IFRS”). Accounting policies adopted by the Company are referred to in Note 3 to the audited consolidated financial statements for the year ended December 31, 2020. The reporting and the functional currency is the Canadian dollar.

Unless otherwise indicated, tabular financial amounts, other than per-share amounts, are in thousands. Comparative information is provided for the three and six month periods ended June 30, 2020.

OPERATIONAL AND FINANCIAL RESULTS

Overview

With strong price momentum across all product streams in the quarter due to demand recovery coupled with capital discipline from industry, Storm recorded another quarter of strong funds flow. From an operational standpoint, there was a modest level of capital spending in the second quarter of 2021 which was directed to the inlet compressor at the Nig Creek Gas Plant and equipment deposits for the Fireweed field compression facility. Production of 26,862 Boe per day was in line with previously announced guidance while capital expenditures of $10 million came in slightly below guidance of $14 million due to timing of development with the incremental expenditures now expected to be incurred in the third quarter. With funds flow of approximately $28 million in the quarter outpacing capital expenditures, debt including working capital surplus was reduced to $102 million, a decrease of $18 million from the previous quarter and a decrease of $30 million from year-end 2020.

Natural gas prices have risen dramatically over the quarter, and are up materially from this time last year, from a combination of strong US demand, namely LNG exports, combined with storage levels being lower than last year and the five-year average. With corporate production weighted 80% to natural gas, the strength in natural gas prices has been a big contributor to the year-over-year increase in funds flow. While demand for crude oil continues to improve and WTI prices have stabilized around the US$70.00 per barrel level, the economic situation remains highly volatile with new waves of COVID-19 underway across the globe along with the ongoing emergence of new variants. As previously stated, predicting the extent to which the continuing presence of COVID-19 may affect the Company remains difficult; however, depending on the severity and duration of the pandemic, it is possible that COVID-19 may have further adverse effects on commodity prices, the Company’s business, results of operations and financial condition.

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While Storm entered these challenging times in a position of strength, both from an operational and liquidity standpoint, management will continue to monitor this rapidly changing situation to determine what, if any, additional measures need to be taken.

During the quarter, the annual review process was completed with the credit facility reconfirmed at $190 million and the term extended until May 27, 2022. The credit facility was approximately 64% drawn at the end of the second quarter (including $14 million for outstanding letters of credit). With funds flow for the remainder of the year expected to be in excess of capital expenditures, low maintenance capital, a balanced hedge portfolio, and unused credit capacity, Storm maintains adequate financial liquidity to continue executing on its capital program with a focus on growing asset value and funds flow per share.

Production and Revenue

Average Daily Production

	Three Months to	Three Months to	Quarter-Over-Quarter	Six Months to	Six Months to	Year-Over-Year
	June 30,2021	June 30,2020	Change	June 30,2021	June 30,2020	Change
Natural gas (Mcf/d)	130,173	114,772	13%	127,364	115,365	10%
Condensate (Bbls/d)	2,434	2,305	6%	2,420	2,464	(2%)
NGL (Bbls/d)	2,732	2,501	9%	2,742	2,249	22%
Total (Boe/d)	26,862	23,935	12%	26,389	23,941	10%
Natural gas weighting	81%	80%		81%	80%
Condensate weighting	9%	10%		9%	10%
NGL weighting	10%	10%		10%	10%

Production for natural gas, condensate and NGL in the second quarter and first half of 2021 was 12% and 10% higher than the second quarter and first half of 2020, respectively, primarily due to incremental production from new wells brought on stream. Furthermore, the first half of 2021 benefitted from a full period of operation of the Nig Creek Gas Plant (incremental production from higher NGL recovery and reduced gas shrinkage) relative to the same period in 2020 as the gas plant was commissioned in February 2020.

The Company started production from one new 100% working interest horizontal well at Umbach in the second quarter of 2021 and three new 100% working interest horizontal wells at Umbach during the first six months of 2021.

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Average Daily Production
6,000 140,000
4,500 105,000
3,000 70,000
1,500 35,000
- -
Condensate (Bbls/d) NGL (Bbls/d) Natural Gas (Mcf/d)
Bbls/d
Mcf/d
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8

									Production Per Share	Production Per Share	Production Per Share	Production Per Share	Production Per Share	Production Per Share	Production Per Share	Production Per Share
	Volume Per MM Shares Outstanding	90 120 150 180 210 240																						5,000 10,000 15,000 20,000 25,000 30,000	Boe/d
					Production Volumes (Boe/d)									Volumes per MM Shares Outstanding
Revenue from Product Sales(1)
											Three		Months to			Three Months to				Six Months to				Six Months to
												June 30,2021				June 30,2020				June	30,2021			June 30,2020
Natural gas												$	42,372			$		23,335		$	94,143			$	50,185
Condensate													17,395					5,437			32,663				19,915
NGL													5,787					1,419			12,422				2,014
Total												$	65,554			$		30,191		$	139,228			$	72,114
% of Total Revenue			by Product Type
Natural gas													65%					77%				68%			70%
Condensate		and NGL											35%					23%				32%			30%
Total													100%					100%			100%				100%

(1) Before realized gains and losses on risk management contracts.

Revenue from product sales for the second quarter of 2021 increased by 117% when compared to the second quarter of 2020 as a result of the Company’s average realized price increasing by 94% combined with a 12% increase in production volumes. For the six month periods, revenue from product sales increased by 93% year over year due to the Company’s average realized price increasing by 76% combined with a 10% increase in production volumes.

Average Selling Prices[(1) ]

Average Selling Prices(1)
	Three Months to	Three Months to	Six Months to	Six Months to
	June 30,2021	June 30,2020	June 30,2021	June 30,2020
Natural gas – Mcf	$ 3.58	$ 2.23	$ 4.08	$ 2.39
Condensate – Bbl	$ 78.53	$ 25.92	$ 74.58	$ 44.41
NGL – Bbl	$ 23.28	$ 6.23	$ 25.03	$ 4.92
Per Boe	$ 26.82	$ 13.86	$ 29.15	$ 16.55

(1) Before realized gains and losses on risk management contracts.

On a per-Boe basis, the Company’s average realized price for the three months ended June 30, 2021 increased 94% compared to the same period of 2020 due to higher natural gas, condensate and NGL pricing. The increase in natural gas pricing is primarily due to a significant increase in Chicago and domestic Western Canadian natural gas pricing resulting from higher demand primarily driven by an increase in LNG exports. The higher condensate pricing aligns to an increase in WTI pricing from demand recovery, which was partially offset by strengthening of the Canadian dollar relative to the US dollar. The Company’s NGL price for the second quarter of 2021 was 29% of WTI, which was higher than the guidance range of 20% to 25% of WTI due to continued strength in propane pricing.

9

On a per-Boe basis, the Company’s average realized price for the first six months of 2021 increased 76% compared to the first six months of 2020, primarily driven by increases in natural gas, condensate and NGL pricing which corresponds to higher benchmark pricing across all product lines.

Benchmark Prices

Benchmark Prices
	Three Months to	Three Months to	Six Months to	Six Months to
	June 30,2021	June 30,2020	June 30,2021	June 30,2020
Natural gas
Chicago monthly index (US$/Mmbtu)	2.74	1.63	2.68	1.79
Chicago daily index (US$/Mmbtu)	2.83	1.64	6.04	1.69
AECO monthly index (Cdn$/GJ)	2.70	1.81	2.74	1.92
AECO daily index (Cdn$/GJ)	2.93	1.89	2.96	1.91
BC Station 2(Cdn$/GJ)	2.84	1.87	2.88	1.87
Crude Oil
WTI (US$/Bbl)	66.07	27.85	61.95	37.01
WTI (Cdn$/Bbl)	81.11	38.59	77.26	50.53
Edmonton condensate (Cdn$/Bbl)	81.49	30.92	77.48	46.23
Exchange rate(US$/Cdn$)	0.81	0.72	0.80	0.73

US natural gas prices were lower in 2020 because of reduced demand in the 2019-2020 winter which resulted in higher storage levels at the end of the winter heating season.

In February 2021, North America experienced frigid cold temperatures caused by a polar vortex that resulted in significant spikes in North American natural gas spot prices related to higher demand and lower production, which constrained supply. This resulted in the Chicago daily index price averaging US$6.04 per Mmbtu in the first half of 2021, an increase of 257% from US$1.69 per Mmbtu in the first half of 2020.

During the first half of 2021, US natural gas production was in line with 2020, however, demand has increased year over year due to higher exports for LNG and to Mexico. Year-to-date demand being higher than supply has resulted in storage levels trending lower than in 2020, which has strengthened pricing in the US. Similarly, AECO and Station 2 pricing have strengthened in 2021, when compared to 2020, due to strong local demand and increased demand for exports to the US.

WTI crude oil pricing, the benchmark for mid-continent inland North American crude oil prices at Cushing, Oklahoma, on which a large part of the Company’s condensate and NGL revenue is based, averaged US$66.07 per barrel in the second quarter of 2021, an increase of 137% from US$27.85 per barrel during the second quarter of 2020 and an increase of 67% during the six months ended June 30, 2021 compared to the same period of 2020. The increase was the result of rising oil demand from resumption of global economic activity with higher COVID-19 vaccination rates.

Condensate price differential to WTI was largely nil in the second quarter and first six months of 2021 as a result of continuing high demand for condensate in Western Canada.

The Company’s natural gas production during the second quarter and first six months of the year was sold as follows:

	Three Months to	Three Months to	Six Months to	Six Months to
	June 30,2021	June 30,2020	June 30,2021	June 30,2020
Chicago monthly index price	23%	41%	25%	29%
Chicago daily index price	22%	15%	22%	24%
AECO index price	18%	17%	17%	12%
BC Station 2 index price	33%	12%	32%	18%
Sumas index price	0%	10%	0%	11%
Alliance Transfer Point(“ATP”)	4%	5%	4%	6%
Total	100%	100%	100%	100%

10

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Storm Realized Natural Gas Price vs. Benchmark
$10.00
$9.00
$8.00
$7.00
$6.00
$5.00
$4.00
$3.00
$2.00
$1.00
$0.00
Q3/19 Q4/19 Q1/20 Q2/20 Q3/20 Q4/20 Q1/21 Q2/21
Storm Realized Nat Gas Price ($/Mcf) Station 2 ($/GJ)
AECO Daily ($/GJ) Chicago Monthly (Cdn$/Mmbtu)
Chicago Daily (Cdn$/Mmbtu)
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In the second quarter of 2021, Storm’s realized natural gas price increased 61% from the second quarter of 2020. Commencing in the fourth quarter of 2020, the Company had increased exposure to BC Station 2 pricing with the expiry of its Sumas marketing arrangement in October 2020, thereby increasing the Company’s exposure to Western Canadian gas pricing (AECO and BC Station 2). Approximately 50% of the Company’s production is sold at AECO and BC Station 2 pricing. Daily pricing at AECO and BC Station 2 increased approximately 54% in the second quarter of 2021 compared to the second quarter of 2020.

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Storm Condensate Price vs. Benchmark
$85.00
$75.00
$65.00
$55.00
$45.00
$35.00
$25.00
$15.00
Q3/19 Q4/19 Q1/20 Q2/20 Q3/20 Q4/20 Q1/21 Q2/21
Storm Condensate Price WTI Cdn$
Cdn$/Bbl
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Storm’s realized condensate price of $78.53 per barrel for the second quarter of 2021 increased by 203% from the second quarter of 2020, in line with the increase in WTI.

11

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Storm NGL Price vs. Benchmark
$75.00 50%
$60.00 40%
$45.00 30%
$30.00 20%
$15.00 10%
$0.00 0%
Q3/19 Q4/19 Q1/20 Q2/20 Q3/20 Q4/20 Q1/21 Q2/21
Storm NGL Price Conway Propane
Argus Far East Index Propane Storm NGL Price (% of WTI)
Cdn$/Bbl
% of WTI Cdn$
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In the second quarter of 2021, Storm’s realized price for NGL, excluding condensate, increased by 274% relative to the same period of 2020 due to higher WTI and propane pricing.

When comparing the first six months of 2021 to the same period of 2020, the realized price for NGL, excluding condensate, increased by 409% due to higher WTI and propane pricing and higher contracted prices with marketers from a more balanced NGL market.

Storm’s NGL price net of transportation is anticipated to be approximately 25% to 30% of WTI in Canadian dollar terms for the contract period that ends in March 2022.

Realized Gain (Loss) on Risk Management

	Three Months to	Three Months to	Three Months to	Six Months to	Six Months to	Six Months to
	June 30,2021		June 30,2020	June 30,2021		June 30,2020
Natural gas	$ (3,981)		$ 1,659	$ (5,768)		$ 3,383
Liquids(1)	(5,093)		4,854	(8,562)		5,867
Realized gain (loss) on risk management
contracts	$ (9,074)		$ 6,513	$ (14,330)		$ 9,250
Per Boe	$(3.71)		$ 2.99	$(3.00)		$ 2.12

(1) Liquids includes field condensate, plant pentanes, butane and propane.

Although the Company has no crude oil production, condensate and approximately half of the NGL stream is priced with reference to WTI and, as a result, the Company enters into WTI crude oil risk management contracts to hedge liquids prices.

The realized gains and losses on risk management contracts consists of the portion of contracts that have settled during the reporting period. The realized losses for the three and six months ended June 30, 2021 are primarily due to the improvement over the last 12 months in WTI crude oil pricing and BC Station 2 pricing compared to the Company’s financial risk management contracted prices on swaps and costless collars.

Royalties

Royalties
	Three Months to	Three Months to	Six Months to	Six Months to
	June 30,2021	June 30,2020	June 30,2021	June 30,2020
Charge for period	$ 2,381	$ 949	$ 8,288	$ 3,056
Percentage of revenue fromproduct sales	3.6%	3.1%	6.0%	4.2%
Per Boe	$ 0.97	$ 0.44	$ 1.74	$ 0.70

12

Royalties, as a percentage of revenue from product sales, increased in the second quarter and first half of 2021 compared to the same periods in 2020 primarily due to higher realized commodity prices, partially offset by the receipt of BC infrastructure royalty credits of $1.8 million in the second quarter of 2021.

Storm currently has remaining infrastructure royalty credits of $4.5 million that will reduce future royalties. Future royalty credits are dependent on commodity prices and production levels from individual wells and thus the timing to receive future royalty credits cannot be readily forecast; correspondingly, royalty rates reported in future quarters will vary as these credits are realized.

Production Costs

Production Costs
	Three Months to	Three Months to	Six Months to	Six Months to
	June 30,2021	June 30,2020	June 30,2021	June 30,2020
Charge forperiod	$ 11,346	$ 9,792	$ 21,327	$ 21,051
Per Boe	$ 4.64	$ 4.50	$ 4.47	$ 4.83

Total production costs for the second quarter and first six months of 2021 increased by 16% and 1%, respectively, when compared to the same periods of 2020. The increase in total production costs for the second quarter of 2021 compared to the same period in 2020 is primarily due to higher production volumes. On a per-Boe basis, production costs for the first half of 2021 decreased 7% when compared to the first half of 2020 due to lower third-party gas processing costs as a result of the start-up of the Company’s Nig Creek Gas Plant in February 2020.

Carbon Tax

With the majority of the Company’s operations located in British Columbia, the Company is subject to the British Columbia Carbon Tax Act. The BC carbon tax was increased on April 1, 2021 to the current rate of $45 per tonne (was $40 per tonne). Storm pays carbon tax on fuel used in the Company’s own facilities (direct) as well as on natural gas volumes processed at third-party facilities (indirect). The following table outlines the total carbon taxes (direct and indirect) that are included within production costs. The increase of $0.4 million from last year was primarily from the increase in the carbon tax rate on April 1.

increase in the carbon tax rate on April 1.
	Three Months to	Three Months to	Six Months to	Six Months to
	June 30,2021	June 30,2020	June 30,2021	June 30,2020
Charge forperiod	$ 1,879	$ 1,511	$ 3,287	$ 3,171
Per Boe	$ 0.77	$ 0.69	$ 0.69	$ 0.73

Transportation Costs

Transportation Costs
	Three Months to	Three Months to	Six Months to	Six Months to
	June 30,2021	June 30,2020	June 30,2021	June 30,2020
Charge forperiod	$ 11,844	$ 11,982	$ 23,397	$ 22,816
Condensate per barrel	$ 6.57	$ 6.15	$ 5.97	$ 5.44
Naturalgasper Mcf	$ 0.88	$ 1.02	$ 0.90	$ 0.96
Per Boe	$ 4.85	$ 5.50	$ 4.90	$ 5.24

Transportation costs include pipeline tariffs for natural gas sold at various price points, as well as trucking costs and pipeline tariffs for wellhead condensate. Natural gas sales volumes destined for Chicago and markets outside Western Canada have higher per-unit transportation costs, but obtain higher sales prices.

Transportation costs for the second quarter of 2021 decreased marginally when compared to the second quarter of 2020 primarily due to lower costs associated with transporting natural gas volumes on the Alliance Pipeline as a result of strengthening of the Canadian dollar relative to the US dollar between the periods, and a lower proportion of natural gas sales sold at Chicago in the second quarter of 2021 compared to the second quarter of 2020, partially offset by higher production volumes in 2021.

Transportation costs for the first six months of 2021 increased by 3% when compared to the same period in 2020 primarily due to higher production volumes in 2021.

Transportation costs for the second quarter and first six months of 2021 decreased by 12% and by 6%, respectively, on a per-Boe basis when compared to the same periods of 2020, primarily due to lower proportions of natural gas sales volumes transported on the Alliance Pipeline and sold at Chicago.

13

Field Operating Netbacks

Details of field operating netbacks are as follows:

	Three Months to	Three Months to	Six Months to	Six Months to
($/Boe)	June 30,2021	June 30,2020	June 30,2021	June 30,2020
Revenue from product sales	26.82	13.86	29.15	16.55
Royalties	(0.97)	(0.44)	(1.74)	(0.70)
Production costs	(4.64)	(4.50)	(4.47)	(4.83)
Transportation costs	(4.85)	(5.50)	(4.90)	(5.24)
Field operating netback	16.36	3.42	18.04	5.78
Realizedgain(loss)on risk management contracts	(3.71)	2.99	(3.00)	2.12
Filed operatingnetback includinghedging	12.65	6.41	15.04	7.90

The field operating netback for the second quarter of 2021 increased by 97% after hedging compared to the second quarter of 2020.

Change in Quarterly Field Operating Netback Including Hedging: Q2/20 vs. Q2/21

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$20.00 $12.96 ($0.53) ($0.14) $0.65 ($6.70)
$15.00
$12.65
$10.00
$6.41
$5.00
$-
Q2 2020 Revenue Royalties Prod. Costs Transp. Realized Q2 2021
Hedging
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14

The field operating netback for the first six months of 2021 increased by 90% after hedging compared to the first six months of 2020.

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Change in YTD Field Operating Netback Including Hedging: Q2/20 vs. Q2/21
$25.00
$12.60 ($1.04) $0.70 ($5.12)
$20.00
$15.04
$15.00
$10.00
$7.90
$5.00
$-
2020 Revenue Royalties Prod. & Transp. Realized Hedging 2021
Costs
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General and Administrative Costs

General and Administrative Costs
	Three Months to	Three Months to	Six Months to	Six Months to
	June 30,2021	June 30,2020	June 30,2021	June 30,2020
Charge for period – before recoveries	$ 1,820	$ 1,730	$ 4,817	$ 4,297
Overhead recoveries	(593)	(160)	(1,774)	(860)
Charge forperiod – net of recoveries	$ 1,227	$ 1,570	$ 3,043	$ 3,437
Per Boe	$ 0.50	$ 0.72	$ 0.64	$ 0.79

General and administrative costs before recoveries for the second quarter of 2021 were largely unchanged when compared to the second quarter of 2020. General and administrative costs before recoveries for the six months ended June 30, 2021 increased by 12% compared to the same period of 2020 primarily due to the employee performance bonus in 2021 being higher than in 2020.

Fluctuations in overhead recoveries are generally related to the amount and type of field capital expenditures incurred. The increase in overhead recoveries in the second quarter and first six months of 2021 compared to the same periods in 2020 is due to an increase in capital expenditures in 2021 and higher recoveries from third parties.

Net general and administrative costs on a per-Boe measure for the second quarter and first half of 2021 were lower compared to the second quarter and first half of 2020 due to higher production volumes. Generally, the Company’s general and administrative cost structure is predictable year to year and variability in per-Boe metrics is due to changes in production volumes.

Interest and Finance Costs

Interest and Finance Costs
	Three Months to	Three Months to	Six Months to	Six Months to
	June 30,2021	June 30,2020	June 30,2021	June 30,2020
Charge for period(1)	$ 1,609	$ 1,519	$ 3,708	$ 3,165
Average interest rate(2)	5.3%	4.7%	5.8%	5.0%
Per Boe	$ 0.66	$ 0.70	$ 0.78	$ 0.73

(1) Includes lease interest.

(2) Includes financing and standby fees; excludes lease interest.

15

The interest rate on the Company’s bank facility is based on bankers’ acceptance rates plus a stamping fee which is amended each quarter in response to changes in the Company’s debt-to-funds-flow ratio.

Interest costs for the second quarter and first half of 2021 increased by 6% and 17%, respectively, compared to the second quarter and first half of 2020 as a result of a higher effective interest rate due to tightening of credit markets as a result of the COVID-19 pandemic, partially offset by lower average bank borrowings. The effective interest rate increased due to higher fees from tightening of credit markets.

With an improved commodity price outlook for the remainder of 2021, the expected increase in funds flow should result in a continued reduction in bank stamping fees and interest expense.

Funds Flow

Funds Flow
	Three Months to		Three Months to		Six Months to		Six Months to
	June	30,2021	June 30,2020		June	30,2021	June	30,2020
		Per		Per		Per		Per
		diluted		diluted		diluted		diluted
		share		share		share		share
Funds flow	$27,902	$0.23	$10,904	$0.09	$64,434	$0.53	$27,793	$0.23

Funds flow, a measure that is not defined under IFRS, is cash generated from operating activities before changes in non-cash working capital, as presented on the statement of cash flows. The measurement of funds flow is used to benchmark operations against prior and future periods and peer group companies and is used by lenders to establish interest rates applied to credit facilities.

Change in Quarterly Funds Flow ($M): Q2/20 vs. Q2/21

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----- Start of picture text -----

$50,000
$31,797 ($1,432)
($1,554)
$138 ($15,587)
$40,000
$30,000 $70 $27,902
$20,000
$3,566
$10,904
$10,000
$-
Q2 2020 Revenue - Revenue - Royalties Prod. Costs Transp. Realized Other (1) Q2 2021
Volume Price Hedging
----- End of picture text -----

(1) Includes general and administrative cost, interest and finance costs and decommissioning expenditures and excludes lease interest.

Higher realized commodity prices were the predominant factor in the 156% increase in funds flow in the second quarter of 2021 versus the second quarter of 2020.

16

The cash return on capital employed (“CROCE”) over the last 12 months, which is a measurement of the Company’s cash profitability as a proportion of the funding utilized to generate it (shareholders’ equity plus debt including working capital deficiency/surplus), was 19% in the second quarter of 2021 compared to 12% in the second quarter of 2020.

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Change in YTD Funds Flow ($M): Q2/20 vs. Q2/21
$100,000 $62,237 ($5,232)
($857) ($23,580)
$80,000
($804) $64,434
$60,000
$40,000
$4,877
$27,793
$20,000
$-
2020 Revenue - Revenue - Royalties Prod. & Realized Other (1) 2021
Volume Price Transp. Costs Hedging
----- End of picture text -----

(1) Includes general and administrative cost, interest and finance costs and decommissioning expenditures and excludes lease interest.

Funds flow for the first six months of 2021 increased by 132% from the first six months of 2020 primarily due to stronger realized prices across all products.

Share-Based Compensation

Share-Based Compensation
	Three Months to	Three Months to	Six Months to	Six Months to
	June 30,2021	June 30,2020	June 30,2021	June 30,2020
Charge forperiod	$ 625	$ 428	$ 1,251	$ 904
Per Boe	$ 0.26	$ 0.20	$ 0.26	$ 0.21

Share-based compensation is a non-cash charge which reflects the estimated value of stock options issued to Storm’s directors, officers and employees. Share-based compensation increased by 46% in the second quarter of 2021 compared to the second quarter of 2020 and increased by 38% when comparing the six month periods. The increase in share-based compensation in both the three and six month periods is primarily attributable to the improvement in Storm’s share price.

Depletion and Depreciation

Depletion and Depreciation
	Three Months to	Three Months to	Six Months to	Six Months to
	June 30,2021	June 30,2020	June 30,2021	June 30,2020
Depletion	$ 9,789	$ 9,260	$ 19,126	$ 19,039
Depreciation	2,790	2,593	5,519	4,819
Charge forperiod	$ 12,579	$ 11,853	$ 24,645	$ 23,858
Per Boe	$ 5.14	$ 5.44	$ 5.16	$ 5.48

Depletion and depreciation in the second quarter and first half of 2021 was comparable to the same periods in 2020. Depreciation expense increased 15% in the first half of 2021 compared to the first half of 2020 primarily due to the start-up of the Nig Creek Gas Plant in February 2020. On a per-Boe basis, the decrease in depletion and depreciation

17

in the second quarter and first half of 2021 when compared to the second quarter and first half of 2020 is due to lower finding and development costs incurred in 2020.

Unrealized Loss on Risk Management

Unrealized Loss on Risk Management
	Three Months to		Three Months to	Six Months to		Six Months to
	June 30,2021		June 30,2020	June 30,2021		June 30,2020
Natural gas	$ (23,289)		$ (4,834)	$ (26,659)		$ (5,456)
Liquids(1)	(7,142)		(8,993)	(12,663)		3,280
Interest rate	113		3	351		(1,171)
Unrealized loss on risk management
contracts	$ (30,318)		$ (13,824)	$ (38,971)		$ (3,347)
Per Boe	$(12.40)		$(6.35)	$(8.16)		$(0.77)

(1) Liquids includes field condensate, plant pentanes, butane and propane.

The unrealized loss on risk management contracts is a non-cash charge representing the change in the mark-to-market position of remaining unexpired contracts at the end of the period.

Income Taxes

The Company did not incur any cash tax expense in the three and six months ended June 30, 2021, nor does it expect to pay any cash tax in the remainder of 2021 or in 2022 based on current commodity prices, forecast taxable income, existing tax pools and planned capital expenditures.

As at June 30, 2021, the Company has tax pools associated with exploration and evaluation and property and equipment of approximately $294 million as well as non-capital losses of approximately $182 million.

Deferred income taxes arise from differences between the accounting and tax bases of the Company’s assets and liabilities. For the three and six months ended June 30, 2021, the Company recognized a deferred income tax recovery of $3.7 million and a deferred income tax expense of $0.4 million, respectively, as a result of a net loss before taxes of $15.6 million and $0.3 million, respectively. As at June 30, 2021, the Company had a deferred income tax liability of $11.2 million.

Net Loss

The mark-to-market valuation of risk management contracts resulted in a distortion on reported net loss for the three and six months ended June 30, 2021 relative to the comparable periods in 2020. For the three and six months ended June 30, 2021, the unrealized loss on risk management contracts amounted to $30.3 million and $39.0 million, respectively, compared to an unrealized loss for the three and six months ended June 30, 2020 of $13.8 million and $3.3 million, respectively.

The return on capital employed (“ROCE”) over the last 12 months, which is a measurement of the Company’s income profitability as a proportion of the funding utilized to generate it (shareholders’ equity plus debt including working capital deficiency/surplus), was 2% in the second quarter of 2021 and in the second quarter of 2020, although as mentioned above is distorted by unrealized losses on the Company’s risk management contracts.

	Three Months to June 30,2021 Three Months to June 30,2020	Six Months to June 30,2021 Six Months to June 30,2020
Net loss	$(11,843) $(11,665)	$(694) $(1,153)
Per basic and diluted share	$(0.10) $(0.10)	$(0.01) $(0.01)

18

INVESTMENT AND FINANCING

Financial Resources and Liquidity

As at June 30, 2021, the Company had an extendible revolving credit facility in the amount of $190 million (December 31, 2020 - $190 million) based on a bank determined borrowing base related to the Company’s proved developed producing reserves. The credit facility is available to the Company until May 27, 2022 at which time the borrowing base will be reviewed and in the ordinary course of business the Company will have the option to extend the facility for an additional year subject to approval by the lenders. If the credit facility is not extended, the facility moves into a term phase whereby the outstanding loan amount is to be repaid in full one year later. In the event that the lenders reduce the borrowing base below the amount drawn, the Company would have 90 days to eliminate any borrowing base shortfall by repaying the amount drawn in excess of the re-determined borrowing base or by providing additional security or other consideration satisfactory to the lenders. Repayments of principal are not required provided that the borrowings under the credit facility do not exceed the authorized borrowing amount. Interest is paid on the utilized portion of the credit facility at bankers’ acceptance rates, plus a stamping fee. Collateral comprises a floating charge demand debenture on the assets of the Company.

At June 30, 2021, debt including working capital surplus amounted to $101.7 million. Bank debt including outstanding letters of credit represented approximately 64% utilization of the available credit facility.

As at June 30, 2021, the Company had issued letters of credit in the amount of $14.1 million (December 31, 2020 - $13.7 million) in support of future natural gas transportation and processing obligations. Availability under the Company’s credit facility is reduced by a like amount.

In quarters of high field activity, Storm operates with a working capital deficit, which will be reduced in quarters of lower field activity. The Company's capital expenditure budget is set by management at the beginning of the calendar year and approved by the Board of Directors. It is updated regularly with changes subject to approval by the Board of Directors. Management is accountable to the Board of Directors for the execution of the business plan represented by the budget and updates the Board on progress at least four times a year.

Capital Expenditures

In the second quarter of 2021, the Company incurred capital expenditures of $10.0 million compared to $2.4 million in the second quarter of 2020.

In the first six months of 2021, the Company incurred capital expenditures of $34.9 million (first six months of 2020 - $28.9 million). Capital expenditures were primarily related to costs incurred for drilling three horizontal wells (1.5 net) at Fireweed and completing three horizontal wells (3.0 net) at Umbach. In addition, $5.7 million was incurred on inlet compression at the Nig Creek Gas Plant and $10.9 million was incurred relating to construction costs associated with the field compression facility and related pipeline infrastructure at Fireweed.

	Three Months to	Three Months to	Six Months to	Six Months to
	June 30,2021	June 30,2020	June 30,2021	June 30,2020
Land and seismic	$ 96	$ 101	$ 340	$ 334
Drilling	297	324	4,511	4,003
Completions	-	290	7,565	9,966
Facilities	8,421	1,673	12,418	12,882
Equipping and pipelines	1,132	-	9,099	1,553
Recompletions and workovers	40	-	903	87
Propertyacquisition and administrative assets	31	6	33	44
Total capital expenditures	$ 10,017	$ 2,394	$ 34,869	$ 28,869

Net capital investment was allocated as follows:

	Three Months to	Three Months to	Six Months to	Six Months to
	June 30,2021	June 30,2020	June 30,2021	June 30,2020
Exploration and evaluation	$ 96	$ 101	$ 340	$ 334
Propertyand equipment	9,921	2,293	34,529	28,535
Total capital expenditures	$ 10,017	$ 2,394	$ 34,869	$ 28,869

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Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities include operating, general and administrative and capital costs payable. When appropriate, net payables in respect of cash calls issued to partners regarding capital projects and estimates of amounts owing but not yet invoiced to the Company are included in accounts payable. The level of accounts payable and accrued liabilities at June 30, 2021 corresponds to the Company’s field capital expenditure program.

Decommissioning Liability

The Company’s decommissioning liability of $30.5 million (December 31, 2020 - $32.9 million) represents the present value of estimated future costs to be incurred to abandon and reclaim wells and facilities drilled, constructed or purchased by Storm. The undiscounted and inflated amount of the liability at June 30, 2021 was $43.1 million (December 31, 2020 - $40.5 million), with $1.3 million expected to be incurred in the next 12 months. The liability for currently inactive wells and facilities is approximately $9 million with approximately 75% of this expected to be incurred by 2025.

CONTRACTUAL OBLIGATIONS

In the course of its business, Storm enters into various contractual obligations, including the following:

• purchase of services;

• royalty agreements;

• operating agreements;

• processing and transportation agreements;

• right-of-way agreements;

• lease obligations for office space and field equipment;

• rental obligations for accommodation, office equipment and automotive equipment;

• banking agreements; and

• risk management contracts.

All such contractual obligations reflect market conditions at the time of contract and do not involve related parties. In the first quarter of 2018, the Company entered into an office lease agreement commencing on October 1, 2018. The remaining aggregate commitment approximates $3.7 million over five years. In addition, as at the date of this report, the Company has transportation and processing commitments of approximately $354 million.

QUARTERLY RESULTS

2021 2020 2019	2021 2020 2019	2021 2020 2019	2021 2020 2019
($000s unless otherwise stated)	Q2 Q1	Q4 Q3 Q2 Q1	Q4 Q3
Revenue from product sales Funds flow Per share – basic and diluted ($) Net income (loss) Per share – basic and diluted ($) Net capital expenditures Average daily production (Boe) Debt including working capital deficiency/surplus(1)	65,554 73,674 27,902 36,532 0.23 0.30 (11,843) 11,149 (0.10) 0.09 10,017 24,852 26,862 25,910 101,712 120,021	52,941 30,010 30,191 41,923 22,350 6,681 10,904 16,889 0.18 0.05 0.09 0.14 17,873 (16,934) (11,665) 10,512 0.15 (0.14) (0.10) 0.09 16,163 14,219 2,394 26,475 25,985 19,027 23,935 23,946 131,705 137,983 130,317 138,632	48,671 31,417 18,469 11,973 0.15 0.10 2,906 (64) 0.02 (0.00) 23,913 32,841 22,375 18,596 128,901 123,342

(1) A non-GAAP measure as defined in the non-GAAP measurements section of this MD&A.

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LIMITATIONS

Forward-Looking Statements – Certain information and statements are set forth in this document, including management's assessment of Storm's future plans and operations specifically in relation to 2021, and contain forward-looking information within the meaning of applicable Canadian securities legislation. Such statements or information are generally identifiable by words such as "anticipate", "believe", "intend", "plan", "expect", "schedule", "indicate", "focus", "outlook", "propose", "target", "objective", "priority", "strategy", "estimate", "budget", "forecast", "would", "could", "will", "may", "future" or other similar words or expressions and include statements relating to or associated with individual wells, facilities, regions or projects as well as timing of any future event which may have an effect on the Company's operations and financial position. All statements and information concerning expectations or projections about the future and statements and information regarding the future business plan or strategy, timing or scheduling, production volumes with splits by commodity, production declines, expected and future activities and capital expenditures, commodity prices, costs, royalties, schedules, operating or financial results, future financing requirements, and the expected effect of future commitments are forward-looking statements.

Forward-looking statements include references to:

• future production volumes in 2021, production volumes by commodity and production declines;

• planned capital expenditures in 2021 totaling $110 million to $115 million, timing, allocations to specific areas, and the availability of financial resources to fund which includes funds flow and availability of committed credit facilities;

• expected treatment under government regulatory regimes;

• business plans and/or strategy;

• future guidance for 2021 including forecast commodity prices, exchange rates, transportation costs, royalties, production costs, cash G&A and interest expense;

• Q3 2021 production of 25,000 to 28,000 Boe per day with capital investment of $43 million to $48 million;

• the expectation that the Company’s NGL price will be approximately 25% to 30% of WTI in Canadian dollar terms for April 2021 to March 2022;

• the near-term growth plan for 2021 and 2022 which is expected to increase liquids as a proportion of total production and decrease per-Boe production costs and includes the estimated start date of production from the Fireweed area based on timing for completion of the field compression facility and timing for the drilling and completion of wells;

• existing or future contractual obligations including agreements pertaining to processing capacity, transportation and marketing of natural gas, condensate and NGL; and

• future tax liabilities and future use of tax pools and losses.

Forward-looking statements are based on expectations, forecasts, and assumptions made by the Company using information available at the time of the statement and historical trends which includes expectations and assumptions concerning:

• the accuracy of reserve estimates and valuations;

• performance characteristics of producing properties;

• access to third-party infrastructure;

• government policies and regulation;

• future production rates;

• accuracy of estimated capital expenditures;

• availability and cost of labour and services and owned or third-party infrastructure;

• royalties;

• development and execution of projects;

• the satisfaction by third parties of their obligations to the Company; and

• the receipt and timing for approvals from regulators and third parties.

The forward-looking statements are subject to known and unknown risks and uncertainties and other factors which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, but are not limited to:

• changes in general, market and business conditions including commodity prices, price differentials, interest rates and currency exchange;

• changes in supply and demand for the Company's products;

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• a global public health crisis including the outbreak of the novel coronavirus (COVID-19) which causes volatility and disruptions in the supply, demand and pricing for natural gas, crude oil and NGL, global supply chains and financial markets, as well as declining trade and market sentiment and reduced mobility of people;

• the ability to obtain regulatory, stakeholder and third-party approvals and satisfy any associated conditions that are not within the Company’s control;

• risks associated with exploration, development and production;

• risk that projects and opportunities may not achieve the expected results in the time anticipated or at all;

• • operational risks and uncertainties associated with crude oil and natural gas activities including reservoir performance, fires, blow-outs, equipment failures and other accidents, uncontrollable flows of natural gas and wellbore fluids, pollution and other environmental risks;

• changes in costs including transportation, production, royalty, general and administrative, and finance;

• adverse weather conditions which could disrupt production and affect drilling and completions resulting in increased costs and/or delay adding production;

• actions by government authorities including changes to laws and regulations, tax laws and policies, fees, royalties, duties and government-imposed compliance costs;

• counter-party risk with third parties to perform their obligations with whom the Company has material relationships;

• unplanned facility maintenance or outages or unavailability of third-party infrastructure which could reduce production or prevent the transportation of products to processing plants and sales markets;

• unexpected events such as fires (including wildfires) or equipment failures or similar events that would affect the Company's facilities or third-party infrastructure used by the Company;

• environmental risks (including climate change) and the cost of compliance with current and future environmental laws, including climate change laws along with risks relating to increased activism and opposition to fossil fuels;

• ability to access capital from internal and external sources to finance planned activities (including the credit facility);

• the potential for security breaches of the Company's information technology systems by malicious persons or entities, and the unavailability or failure of such systems to perform as anticipated as a result of such breaches;

• risks with transactions including property acquisitions or dispositions and the failure to realize anticipated benefits from any transaction;

• finding new crude oil and gas reserves that can be developed economically to replace reserves depleted by production;

• risk associated with commodity price hedging activities using derivatives and other financial instruments;

• risk with First Nations land claims and consultation requirements;

• risk that the Company may be subject to litigation;

• inability to secure labour, services or equipment on a timely basis or on favourable terms;

• increased competition from other industry participants for, among other things, capital, acquisitions of assets or undeveloped lands, and skilled personnel; and

• increased competition from companies that provide alternative sources of energy.

Statements relating to “reserves” or “resources” are forward-looking statements, including financial measurements such as net present value, as they involve the assessment, based on estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future.

Readers are advised that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on 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.

Readers are cautioned that the foregoing list of factors is not exhaustive. The forward-looking statements contained herein are expressly qualified by this cautionary statement.

Boe Presentation - 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 crude oil in the ratio of six thousand cubic feet of natural gas to one barrel of crude oil.

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Non-GAAP Measurements - Within this MD&A, references are made to terms which are not recognized under Generally Accepted Accounting Principles (“GAAP”). Specifically, “debt including working capital deficiency”, “field operating netbacks”, “field operating netbacks including hedging”, “CROCE”, “ROCE” and measurements “per commodity unit” and “per Boe” do not have any standardized meaning as prescribed by 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. NonGAAP terms are used to benchmark operations against prior periods and peer group companies and are widely used by investors, lenders, analysts and other parties.

Field Operating Netbacks

Field operating netbacks and field operating netbacks including hedging are common non-GAAP measurements applied in the crude oil and natural gas industry and are used by management to assess operational performance of assets. Field operating netbacks are calculated by deducting royalties, production and transportation expenses from revenue from product sales and are presented on a per-Boe basis.

Debt Including Working Capital Surplus or Deficiency

Debt including working capital deficiency/surplus is defined as bank indebtedness plus working capital surplus or deficiency excluding the mark-to-market value of risk management contracts, decommissioning liability and lease liability. Management believes this is a key measure to assess the Company’s liquidity and is used by the Company’s lenders to set corporate interest rates.

lenders to set corporate interest rates.
($000s unless otherwise stated)	As at June 30, 2021		As at June 30, 2020	As at June 30, 2019
Accounts receivable	26,323		10,788	10,982
Prepaids and deposits	708		634	387
Less: Accountspayable and accrued liabilities	(21,161)		(12,381)	(29,065)
Working capital deficiency/surplus	(5,870)		959	17,696
Bank indebtedness	107,582		129,358	84,572
Debt includingworkingcapital deficiency/surplus	101,712		130,317	102,268

CROCE & ROCE

CROCE is non-GAAP financial measure and does not have a standardized meaning under IFRS. CROCE is determined by taking funds flow plus interest and finance costs on a 12-month trailing basis, and dividing it by the average capital employed (shareholders’ equity plus debt including working capital deficiency/surplus) as presented in the following table.

table.
	Twelve Months Ended	Twelve Months Ended
($000s unless otherwise stated)	June 30, 2021	June 30, 2020
Average debt including working capital deficiency/surplus(1)	116,014	116,293
Average shareholders’ equity(1)	423,118	419,511
Average capital employed	539,132	535,804
Funds flow	93,465	58,235
Interest and finance costs	7,946	5,890
Funds flow plus interest and finance costs	101,411	64,125
CROCE	19%	12%

(1) The average debt including working capital deficiency/surplus and shareholders’ equity represent the average of the opening and ending balances as presented on the statement of financial position for the respective period.

ROCE is non-GAAP financial measure and does not have a standardized meaning under IFRS. ROCE is determined by taking net income plus interest and finance costs and deferred income tax expense on a 12-month trailing basis, and dividing it by the average capital employed (shareholders’ equity plus debt including working capital deficiency/surplus) as presented in the following table.

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	Twelve Months Ended	Twelve Months Ended
($000s unless otherwise stated)	June 30, 2021	June 30, 2020
Average debt including working capital deficiency/surplus(1)	116,014	116,293
Average shareholders’ equity(1)	423,118	419,511
Average capital employed	539,132	535,804
Net income	245	1,689
Interest and finance costs	7,946	5,890
Deferred income tax expense	1,713	1,958
	9,904	9,537
ROCE	2%	2%

(1) The average debt including working capital deficiency/surplus and shareholders’ equity represent the average of the opening and ending balances as presented on the statement of financial position for the respective period.

The CROCE and ROCE measures allow management and others to evaluate the Company’s capital efficiency and ability to generate profitable returns by measuring the Company's earnings (funds flow and net income) relative to the capital employed in the business.

BUSINESS RISKS

There are a number of risks facing participants in the Canadian crude oil and natural gas industry. Some risks are common to all businesses while others are specific to the industry. Information with respect to such risks is set out in Storm’s Annual Information Form dated March 31, 2021 for the year ended December 31, 2020 under the heading “Risk Factors” and in Storm’s MD&A for the period ended December 31, 2020 under the heading “Business Risks”.

Crude Oil and Natural Gas Prices and General Economic Conditions

The Company’s financial results are largely dependent on the prevailing prices of crude oil and natural gas. Crude oil and natural gas prices are subject to fluctuations in supply, demand, market uncertainty and other factors that are beyond the Company’s control. This can include but is not limited to: the global and domestic supply of and demand for crude oil and natural gas; global and North American economic conditions; the actions of OPEC or individual producing nations; government regulation; political stability; the ability to transport commodities to markets; developments related to the market for liquefied natural gas; the availability and prices of alternate fuel sources; and weather conditions. In addition, significant growth in crude oil and natural gas production in Western Canada and the United States has resulted in pressure on transportation and pipeline capacity which contributes to fluctuations in prices. All of these factors are beyond the Company’s control and can result in a high degree of price volatility.

Fluctuations in currency exchange rates further compound this volatility when commodity prices, which are generally set in US dollars, are stated in Canadian dollars. The Company’s financial performance also depends on revenues from the sale of commodities which differ in quality and location from underlying commodity prices quoted on financial exchanges.

Unexpected developments in financial markets, regulatory environments, or consumer behaviour may also have adverse effects on the Company’s results, business, financial condition or liquidity, for a substantial period of time.

Fluctuations in the price of commodities and associated price differentials affect the value of the Company’s assets and the Company’s ability to pursue its business objectives. Prolonged periods of low commodity prices and volatility may also affect the Company’s ability to meet guidance targets and its financial obligations as they come due. Any substantial and extended decline in the price of crude oil and natural gas could have an adverse effect on the Company’s reserves, borrowing capacity, revenues, profitability and funds flow and may have a material adverse effect on the Company’s business, financial condition, results of operations, prospects and the level of expenditures for the development of crude oil and natural gas reserves. This may include delay or cancellation of existing or future drilling or development programs or curtailment in production as the economics of producing from some wells may become impaired.

In addition, bank borrowings available to the Company are, in part, determined by the value of the Company’s assets. A sustained material decline in commodity prices from historical average prices could reduce the value of the Company’s assets, therefore reducing the bank credit available to the Company which could require that a portion, or all, of the Company’s bank debt be repaid, as well as curtailment of the Company’s investment programs.

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The Company conducts regular assessments of the carrying amount of its assets in accordance with IFRS. If crude oil and natural gas prices decline significantly and remain at low levels for an extended period of time, the carrying amount of the Company’s assets may be subject to impairment.

Market conditions which include global crude oil and natural gas supply and demand and global events including actions taken by OPEC, Russia’s withdrawal from OPEC, sanctions against Iran and Venezuela, slowing growth in China and emerging economies, weakening global relationships, isolationist and punitive trade policies, shale production in the United States, sovereign debt levels and political upheavals in various countries including growing anti-fossil fuel sentiment and the outbreak of COVID-19 have caused significant volatility in commodity prices. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks, including attacks on crude oil infrastructure in crude oil producing nations, in the United States or other countries could adversely affect the economies of Canada, the United States and other countries. These events and conditions have caused a significant reduction in the valuation of crude oil and natural gas companies and a decrease in confidence in the future of the crude oil and natural gas industry. In addition, the difficulties encountered by midstream proponents in Western Canada to obtain the necessary approvals on a timely basis to build pipelines, LNG plants and other facilities to provide better access to markets for the crude oil and natural gas industry have led to additional downward pressure on crude oil and natural gas prices which has further reduced confidence in the crude oil and natural gas industry in Western Canada.

Global Health Crises

The Company’s business, operations and financial condition could be materially adversely affected by the outbreak of epidemics or pandemics or other health crises (directly or indirectly). In December 2019, COVID-19 was reported to have surfaced; on January 30, 2020, the World Health Organization (“WHO”) declared the outbreak a global health emergency; and on March 11, 2020 the WHO declared the outbreak of COVID-19 a global pandemic. The spread of COVID-19 has led governments and companies to impose quarantines, travel restrictions and other public health safety measures. COVID-19 vaccinations have ramped up in 2021 which could restore economic activity; however, the timing remains uncertain. Global economies, financial markets and interest rates have been affected. The COVID-19 pandemic has caused business closures and resulted in ratings downgrades, credit deterioration and bankruptcies. It remains uncertain how the macroeconomic environment and societal and business norms will continue to be affected following the COVID-19 pandemic.

Public health crises can result in volatility and disruptions in the supply, demand and pricing for crude oil and natural gas, global supply chains and financial markets, as well as declining trade and market sentiment and reduced mobility of people, all of which could affect commodity prices, interest rates, credit ratings, credit risk and inflation. In particular, crude oil prices sustained a steep initial decline in response to the outbreak of COVID-19. The risks to the Company of such public health crises also include risks to employee health and safety and a slowdown or temporary suspension of operations in geographic locations affected by an outbreak. This could include the Company’s wells and facilities and/or third-party facilities and pipelines used by the Company. While there has been little to no disruption to date on the Company’s operations, the extent to which COVID-19 may affect the Company in the future is uncertain. Subsequent waves and variants of concern may cause further adverse effects on the economy, commodity prices and the Company’s operations and financial condition.

Indigenous Claims

Indigenous peoples have claimed Indigenous rights and title in portions of western Canada. Any claims made against sections of land where the Company leases the mineral or surface rights may have an adverse effect on the Company’s business, financial condition and results of operations. Currently, the Company is aware of a Judgement in the Supreme Court of British Columbia on June 29, 2021 with respect to a claim brought by the Blueberry River First Nation against the province of British Columbia asserting that the cumulative effects of industrial development have had significant adverse impacts on the meaningful exercise of treaty rights, breaching the Treaty and infringing their rights. The Judgement references the cumulative effects of all industrial development including forestry, oil and gas, agriculture, hydro-electricity development, mining operations and road development within the Blueberry Claim Area which comprises approximately 38,000 square kilometres (9,400,000 acres) of northeast British Columbia, including the cities of Fort St. John and Dawson Creek. All of the Company’s Montney lands in northeast British Columbia are within the ‘Blueberry Claim Area’ referenced in the Judgement. At this time, it is not expected that the Judgement will affect the Company’s forecast activity or production guidance for 2021 and it is not known if it will have longer term effects on the business. In addition, the process of addressing such claims, regardless of the outcome, could be extensive and time-consuming and could result in delays in the construction of infrastructure systems and facilities which may have a material effect on the Company’s business and financial results.

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Non-Government Organizations

The crude oil and natural gas exploration, development, and operating activities conducted by the Company may, at times, be subject to public opposition. Such public opposition could expose the Company to the risk of higher costs, delays, or even project cancellations due to increased pressure on governments and regulators by special interest groups including Indigenous groups, landowners, environmental interest groups (including those opposed to crude oil and natural gas production operations) and other non-government organizations, blockades, legal or regulatory actions or challenges, increased regulatory oversight, reduced support of the federal, provincial or municipal governments, delays in, challenges to, or the revocation of regulatory approvals, permits and/or licences, and direct legal challenges, including the possibility of climate-related litigation. There is no guarantee that the Company will be able to satisfy the concerns of the special interest groups and non-government organizations and attempting to address such concerns may require the Company to incur significant and unanticipated capital and operating expenditures.

FINANCIAL REPORTING UPDATE

Disclosure Controls and Internal Controls Over Financial Reporting

The Company has designed disclosure controls and procedures (“DCP”) to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company's Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation.

The Company has designed internal controls over financial reporting ("ICFR") to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. The Company is required to disclose herein any change in the Company's ICFR that occurred during the recent fiscal period that has materially affected, or is reasonably likely to materially affect, the Company’s ICFR.

No material changes in the Company's DCP and its ICFR were identified during the quarter ended June 30, 2021 that have materially affected, or are reasonably likely to materially affect, the Company's ICFR.

It should be noted that a control system, including the Company's disclosure and internal controls and procedures, no matter how well conceived, can provide only reasonable, but not absolute assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.

ADDITIONAL INFORMATION

Additional information relating to the Company can be viewed at www.sedar.com or on the Company’s website at www.stormresourcesltd.com. Information can also be obtained by contacting the Company at Storm Resources Ltd., Suite 600, 215 – 2[nd] Street S.W., Calgary, Alberta T2P 1M4.

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QUARTERY SUMMARIES

Thousands of Cdn$, except volumetric and	Thousands of Cdn$, except volumetric and	Thousands of Cdn$, except volumetric and	Q2	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3
per-share amounts			2021		2021	2020	2020	2020	2020	2019	2019
FINANCIAL
Revenue fromproduct sales(1)			65,554		73,674	52,941	30,010	30,191	41,923	48,671	31,417
Funds flow			27,902		36,532	22,350	6,681	10,904	16,889	18,469	11,973
Per share - basic and diluted($)			0.23		0.30	0.18	0.05	0.09	0.14	0.15	0.10
Net income (loss)			(11,843)		11,149	17,873	(16,934)	(11,665)	10,512	2,906	(64)
Per share - basic and diluted($)			(0.10)		0.09	0.15	(0.14)	(0.10)	0.09	0.02	(0.00)
Cash return on		capital employed(“CROCE”)(2)	19%		15%	12%	11%	12%	12%	12%	15%
Return on capital employed(“ROCE”)(2)(4)			2%		2%	2%	(2%)	2%	7%	4%	9%
Capital expenditures			10,017		24,852	16,163	14,219	2,394	26,475	23,913	32,841
Debt including working capital deficiency/
surplus(2)(3)			101,712		120,021	131,705	137,983	130,317	138,632	128,901	123,342
Common shares (000s)
Weighted	average - basic		121,892		121,713	121,581	121,557	121,557	121,557	121,557	121,557
Weighted	average - diluted		121,892		123,404	121,536	121,557	121,557	121,557	121,557	121,557
Outstanding		end of period - basic	122,042		121,769	121,689	121,557	121,557	121,557	121,557	121,557
OPERATIONS
(Cdn$ per Boe)
Revenue from product sales(1)			26.82		31.59	22.15	17.14	13.86	19.24	23.64	18.36
Transportation costs			(4.85)		(4.95)	(4.81)	(6.43)	(5.50)	(4.97)	(5.20)	(5.83)
Revenue net of		transportation	21.97		26.64	17.34	10.71	8.36	14.27	18.44	12.53
Royalties			(0.97)		(2.53)	(0.92)	(0.77)	(0.44)	(0.97)	(1.59)	0.19
Production costs			(4.64)		(4.28)	(4.13)	(4.84)	(4.50)	(5.17)	(5.67)	(5.88)
Field operating		netback(2)	16.36		19.83	12.29	5.10	3.42	8.13	11.18	6.84
Realized gain (loss) on risk management
contracts			(3.71)		(2.25)	(1.09)	0.51	2.99	1.26	(0.80)	1.64
General and	administrative		(0.50)		(0.78)	(0.67)	(0.72)	(0.72)	(0.86)	(0.70)	(0.79)
Interest and finance costs			(0.65)		(0.89)	(0.96)	(1.08)	(0.68)	(0.74)	(0.71)	(0.69)
Decommissioningexpenditures			(0.08)		(0.24)	(0.22)	-	(0.01)	(0.04)	-	-
Funds flow per Boe			11.42		15.67	9.35	3.81	5.00	7.75	8.97	7.00
Barrels of oil	equivalent per day (6:1)		26,862		25,910	25,985	19,027	23,935	23,946	22,375	18,596
Natural gas production
Thousand cubic feet per day			130,173		124,523	124,927	91,526	114,772	115,957	108,679	91,053
Price(Cdn$		per Mcf)(1)	3.58		4.62	3.21	2.47	2.23	2.54	3.28	2.42
Condensate	production
Barrels per day			2,434		2,405	2,502	1,637	2,305	2,623	2,416	1,856
Price(Cdn$		per barrel)(1)	78.53		70.54	52.04	46.79	25.92	60.66	66.56	63.45
NGL production
Barrels per day			2,732		2,752	2,662	2,136	2,501	1,998	1,846	1,564
Price(Cdn$		per barrel)(1)	23.28		26.79	16.41	10.95	6.23	3.27	6.11	2.29
Wells drilled	(net)		-		1.5	3.0	4.0	-	1.0	-	1.0
Wells completed (net)			-		3.0	4.0	-	-	3.5	-	5.0

(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 attached Management’s Discussion and Analysis. 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 $30.3 million for the three months ended June 30, 2021 (three months ended June 30, 2020 - unrealized loss of $13.8 million) and an unrealized loss of $39.0 million for the six months ended June 30, 2021 (six months ended June 30, 2020 - unrealized loss of $3.3 million).

27

CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS

Condensed Interim Consolidated Statements of Financial Position

(Canadian$000s) (unaudited)	Notes	June 30,2021	December 31,2020
ASSETS
Current
Accounts receivable	12	$ 26,323	$ 19,283
Prepaids and deposits		708	1,124
		27,031	20,407
Risk management contracts	12	-	233
Exploration and evaluation	3	98,786	98,886
Property and equipment	4	516,921	508,524
Right-of-use asset	7	2,002	2,220
		$ 644,740	$ 630,270
LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Accounts payable and accrued liabilities		$ 21,161	$ 17,721
Current portion of decommissioning liability	8	1,291	1,939
Current portion of lease liability	7	516	512
Risk management contracts	12	42,781	8,483
		65,749	28,655
Bank indebtedness	5	107,582	134,391
Risk management contracts	12	4,541	101
Lease liability	7	1,648	1,850
Decommissioning liability	8	29,212	30,915
Deferred income taxes		11,233	10,823
		$219,965	$206,735
Shareholders' equity
Share capital	9	392,684	391,752
Contributed surplus	10	20,340	19,338
Retained earnings		11,751	12,445
		$ 424,775	$ 423,535
Commitments	14
		$644,740	$630,270

See accompanying notes to the condensed interim consolidated financial statements.

On behalf of the Board:

==> picture [147 x 46] intentionally omitted <==

Director

==> picture [208 x 65] intentionally omitted <==

Director

28

Condensed Interim Consolidated Statements of Income (Loss) and Comprehensive Income (Loss)

		Three Months	Ended June 30	Ended June 30	Six Months	Ended June 30	Ended June 30
(Canadian$000s exceptper-share amounts) (unaudited)	Notes	2021		2020	2021		2020
Revenue
Revenue from product sales	6	$ 65,554		$ 30,191	$ 139,228		$ 72,114
Royalties		(2,381)		(949)	(8,288)		(3,056)
		63,173		29,242	130,940		69,058
Realized gain (loss) on risk management contracts	12	(9,074)		6,513	(14,330)		9,250
		54,099		35,755	116,610		78,308
Expenses
Production		11,346		9,792	21,327		21,051
Transportation		11,844		11,982	23,397		22,816
General and administrative		1,227		1,570	3,043		3,437
Share-based compensation	10	625		428	1,251		904
Depletion and depreciation	4, 7	12,579		11,853	24,645		23,858
Exploration and evaluation costs expensed	3	-		-	331		450
Accretion	8	129		81	221		186
Interest and finance costs		1,609		1,519	3,708		3,165
Unrealized loss on risk management contracts	12	30,318		13,824	38,971		3,347
Unrealized revaluation loss on investment		-		69	-		87
		69,677		51,118	116,894		79,301
Net loss and comprehensive loss		(15,578)		(15,363)	(284)		(993)
Deferred income tax expense (recovery)		(3,735)		(3,698)	410		160
Net loss and comprehensive loss		$ (11,843)		$ (11,665)	$ (694)		$ (1,153)
Net loss per share	11
- Basic and diluted		$ (0.10)		$ (0.10)	$ (0.01)		$ (0.01)

See accompanying notes to the condensed interim consolidated financial statements.

29

Condensed Interim Consolidated Statements of Changes in Shareholders’ Equity

(Canadian $000s) (unaudited)				Six Months to June 30, 2021
	Notes	Share Capital	Contributed Surplus	Retained Earnings Total Equity
Balance, beginning of period		$ 391,752	$ 19,338	$ 12,445 $ 423,535
Net loss for the period		-	-	(694) (694)
Issue of common shares	9	683	-	- 683
Share-based compensation	10	-	1,251	- 1,251
Share-based compensation on stock options exercised	9	249	(249)	- -
Balance, end ofperiod		$ 392,684	$ 20,340	$ 11,751 $ 424,775

(Canadian $000s) (unaudited)				Six Months to June 30, 2020	Six Months to June 30, 2020
			Contributed	Retained
	Notes	Share Capital	Surplus	Earnings	Total Equity
Balance, beginning of period		$ 391,444	$ 17,605	$ 12,659	$ 421,708
Net loss for the period		-	-	(1,153)	(1,153)
Share-based compensation	10	-	904	-	904
Balance, end of period		$ 391,444	$ 18,509	$ 11,506	$ 421,459

See accompanying notes to the condensed interim consolidated financial statements.

30

Condensed Interim Consolidated Statements of Cash Flows

		Three Months Ended June 30	Three Months Ended June 30	Three Months Ended June 30	Six Months	Six Months	Ended June 30
(Canadian$000s) (unaudited)	Notes	2021		2020	2021		2020
Operating activities
Net loss for the period		$ (11,843)		$ (11,665)	$ (694)		$ (1,153)
Non-cash items:
Unrealized loss on risk management	12	30,318		13,824	38,971		3,347
Depletion, depreciation and accretion	4, 7, 8	12,708		11,934	24,866		24,044
Share-based compensation	10	625		428	1,251		904
Lease interest	7	28		33	57		67
Exploration and evaluation costs expensed	3	-		-	331		450
Unrealized revaluation loss on investment		-		69	-		87
Deferred income tax expense (recovery)		(3,735)		(3,698)	410		160
Decommissioning expenditures	8	(199)		(21)	(758)		(113)
Funds flow		27,902		10,904	64,434		27,793
Net change in non-cash working capital items	13	(5,541)		2,636	(3,644)		2,164
		22,361		13,540	60,790		29,957
Financing activities
Payment on lease liability	7	(127)		(126)	(255)		(253)
Proceeds on issue of common shares	9	551		-	683		-
Increase (decrease) in bank indebtedness		(9,027)		4,534	(26,809)		7,750
		(8,603)		4,408	(26,381)		7,497
Investing activities
Additions to property and equipment	4	(9,921)		(2,293)	(34,529)		(28,535)
Additions to exploration and evaluation assets	3	(96)		(101)	(340)		(334)
Net change in non-cash working capital items	13	(3,741)		(15,554)	460		(8,585)
		(13,758)		(17,948)	(34,409)		(37,454)
Change in cash during the period		-		-	-		-
Cash, beginning of period		-		-	-		-
Cash, end of period		$ -		$ -	$ -		$ -

See accompanying notes to the condensed interim consolidated financial statements.

31

NOTES TO THE CONDENSED INTERIM

CONSOLIDATED FINANCIAL STATEMENTS

As at June 30, 2021 and December 31, 2020 and for the three and six months ended June 30, 2021 and 2020

Tabular amounts in thousands of Canadian dollars, except per-share amounts (unaudited)

1. REPORTING ENTITY

Storm Resources Ltd. (the “Company” or "Storm"), is a crude oil and natural gas exploration and development company incorporated in the province of Alberta, Canada on June 8, 2010 and is listed on the TSX under the symbol “SRX”. The Company operates primarily in the province of British Columbia and its head office is located at Suite 600, 215 – 2[nd] Street S.W., Calgary, Alberta T2P 1M4. The Company became a reporting issuer in August 2010.

These unaudited condensed interim consolidated financial statements (the “financial statements”) include the accounts of Storm and its wholly owned subsidiary, Storm Gas Resource Corp. All inter-entity transactions have been eliminated upon consolidation. Storm’s operations are viewed as a single operating segment by the chief decision maker of the Company for the purpose of resource allocation and assessing asset performance.

2. BASIS OF PRESENTATION

Statement of Compliance

The financial statements have been prepared in accordance with International Accounting Standard (“IAS”) 34 “Interim Financial Reporting” using accounting policies consistent with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). Certain information and disclosures normally included in the notes to the consolidated financial statements have been condensed or have been disclosed on an annual basis only. Accordingly, these condensed interim consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements as at and for the year ended December 31, 2020. All financial information is reported in thousands of Canadian dollars, which is the functional currency of the Company.

These financial statements were authorized for issue by the Board of Directors on August 11, 2021.

Basis of Measurement

The Company’s financial statements have been prepared on a going concern basis consistent with prior years, and follow the historical cost convention, except for certain financial assets and financial liabilities, which are measured at fair value, as explained in Note 12.

Significant Accounting Judgments, Estimates and Assumptions

The preparation of the financial statements in accordance with IFRS requires management to make judgments, estimates and assumptions that affect the reported amounts of assets, liabilities, shareholders' equity, revenue and expenses. Actual results may differ from these estimates.

Estimates and underlying assumptions are continuously reviewed with the financial statement effect being recognized in the reporting period that the changes to estimates are made.

Critical judgments applied by management to accounting policies that have the most significant effect on the amounts in the financial statements are described in Note 4 to the Company’s audited consolidated financial statements for the year ended December 31, 2020.

The continued global impact of the COVID-19 pandemic contributes to economic uncertainty, with more volatile commodity prices, currency exchange rates and interest rates. The duration and severity of the business disruptions and continued reduction in consumer activity internationally and the resulting financial effect is difficult to reliably estimate. The results of the economic downturn and any potential resulting direct or indirect effect on the Company has been considered in management’s estimates at period end. However, there could be further prospective material effects in future periods.

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3. EXPLORATION AND EVALUATION

3. EXPLORATION AND EVALUATION
	Six Months Ended	Year ended
	June 30, 2021	December 31, 2020
Balance, beginning of period	$ 98,886	$ 99,737
Additions	340	746
Expiries - exploration and evaluation costs expensed	(331)	(745)
Future decommissioning costs	(109)	35
Transfer topropertyand equipment	-	(887)
Balance, end ofperiod	$ 98,786	$ 98,886

As at June 30, 2021, the Company reviewed the carrying amounts of exploration and evaluation assets for indicators of potential impairment. As a result of this assessment, no indicators of impairment were identified.

4. PROPERTY AND EQUIPMENT

4. PROPERTY AND EQUIPMENT
	Six Months Ended		Year ended
	June 30, 2021		December 31, 2020
Cost
Balance, beginning of period	$ 810,916		$ 746,515
Additions	34,529		58,505
Future decommissioning costs	(1,705)		5,009
Transfer from exploration and evaluation assets	-		887
Balance,end ofperiod	$ 843,740		$ 810,916
Accumulated depletion and depreciation
Balance, beginning of period	$ (302,392)		$ (256,251)
Depletion and depreciation	(24,427)		(46,141)
Balance,end ofperiod	$(326,819)		$(302,392)
Net book value, beginning of period	$ 508,524		$ 490,264
Net book value, end ofperiod	$ 516,921		$ 508,524

As at June 30, 2021, the Company evaluated property and equipment for indicators of potential impairment. As a result of this assessment, no indicators of impairment were identified and no impairment was recorded on property and equipment.

5. BANK INDEBTEDNESS

As at June 30, 2021, the Company had an extendible revolving credit facility in the amount of $190 million (December 31, 2020 - $190 million) based on a bank determined borrowing base related to the Company’s producing reserves. The credit facility is available to the Company until May 27, 2022, at which time the borrowing base amount will be reviewed and in the ordinary course of business the Company will have the option to extend the facility for an additional year subject to approval by the lenders. If the credit facility is not extended, the facility moves into a term phase whereby the outstanding loan amount is to be repaid in full one year later. In the event that the lenders reduce the borrowing base below the amount drawn, the Company would have 90 days to eliminate any borrowing base shortfall by repaying the amount drawn in excess of the re-determined borrowing base or by providing additional security or other consideration satisfactory to the lenders. Repayments of principal are not required provided that the borrowings under the credit facility do not exceed the authorized borrowing amount. Interest is paid on the utilized portion of the credit facility at bankers’ acceptance rates, plus a stamping fee. Collateral comprises a floating charge demand debenture on the assets of the Company.

As at June 30, 2021, the Company had issued letters of credit in the amount of $14.1 million (December 31, 2020 - $13.7 million) primarily in support of future natural gas transportation and processing obligations.

At June 30, 2021, debt including outstanding letters of credit amounted to $121.7 million, representing approximately 64% of the available credit facility.

33

6. REVENUE FROM PRODUCT SALES

The following table presents the Company’s revenue from product sales disaggregated by revenue source:

	Three Months Ended	Three Months Ended	Six Months Ended	Six Months Ended
	June 30,2021	June 30,2020	June 30,2021	June 30,2020
Natural gas	$ 42,372	$ 23,335	$ 94,143	$ 50,185
Condensate	17,395	5,437	32,663	19,915
NGL	5,787	1,419	12,422	2,014
Total	$ 65,554	$ 30,191	$ 139,228	$ 72,114

Storm’s revenue was generated mostly in British Columbia where production was sold primarily to three major energy customers with investment grade credit ratings which accounted for 89% of the Company’s total revenue from product sales for the three and six months ended June 30, 2021 (three and six months ended June 30, 2020 - 90% and 95%, respectively). The majority of revenue is derived from variable price contracts based on index prices at each sales point. Of total natural gas revenue for the six months ended June 30, 2021, 47% received Chicago pricing, 32% received BC Station 2 pricing, 17% received AECO pricing and the remaining 4% received ATP pricing.

7. RIGHT-OF-USE ASSET AND LEASE LIABILITY

Right-of-Use Asset

The following table provides a reconciliation of the carrying amount of the right-of-use asset pertaining to the Company’s corporate office lease in Calgary:

corporate office lease in Calgary:
	Six Months Ended		Year Ended
	June 30, 2021		December 31, 2020
Cost
Balance, beginning of period	$ 3,094		$ 3,094
Additions	-		-
Balance,end ofperiod	$ 3,094		$ 3,094
Accumulated depreciation
Balance, beginning of period	$ (874)		$ (437)
Depreciation	(218)		(437)
Balance,end ofperiod	$(1,092)		$(874)
Net book value, beginning of period	$ 2,220		$ 2,657
Net book value, end ofperiod	$ 2,002		$ 2,220

As at June 30, 2021, the net book value of the right-of-use asset for the Company’s corporate office lease in Calgary is $2.0 million (December 31, 2020 - $2.2 million) with a remaining lease term to the year 2026.

Lease Liability

The following table provides a reconciliation of the carrying amount of the liability pertaining to the Company’s corporate office lease in Calgary:

office lease in Calgary:
	Six Months Ended	Year Ended
	June 30, 2021	December 31, 2020
Balance, beginning of period	$ 2,362	$ 2,741
Lease payments	(255)	(507)
Lease interest	57	128
Balance, end of period	$ 2,164	$ 2,362
Less currentportion	516	512
Long-termportion	$ 1,648	$ 1,850

The lease liability was measured at the present value of the remaining lease payments discounted at the Company’s weighted average incremental borrowing rate of 5%.

34

As at June 30, 2021, the total undiscounted amount of the estimated future cash flows to settle the Company’s lease liability over the remaining lease term is $2.4 million.

8 . DECOMMISSIONING LIABILITY

The Company provides for the future cost of decommissioning crude oil and natural gas production assets, including well sites, gathering systems and facilities. The total decommissioning liability is estimated based on the Company’s net ownership interest in wells and facilities, the estimated costs to abandon and reclaim the wells, gathering systems and facilities and the estimated timing of future costs. The total estimated inflated and undiscounted liability required to settle the Company’s decommissioning obligation is approximately $43.1 million (December 31, 2020 - $40.5 million), with the majority of payments being made in the years 2034 to 2054. A risk-free discount rate of 1.8% (December 31, 2020 - 1.2%) and an inflation rate of 1.7% (December 31, 2020 - 1.5%) was used to calculate the present value of the decommissioning obligation, amounting to $30.5 million at June 30, 2021.

The following table provides a reconciliation of the carrying amount of the obligation:

	Six Months Ended	Year Ended
	June 30, 2021	December31,2020
Balance, beginning of period	$ 32,854	$ 28,115
Obligations incurred	210	1,282
Obligations settled	(758)	(643)
Change in estimates(1)	(2,024)	3,762
Accretion expense	221	338
Balance, end of period	$ 30,503	$ 32,854
Less currentportion	1,291	1,939
Long-termportion	$ 29,212	$ 30,915

(1) Relates to changes in risk-free discount rates, inflation rates and estimated settlement dates.

9. SHARE CAPITAL

Authorized

An unlimited number of voting common shares without nominal or par value An unlimited number of first preferred shares without nominal or par value

Issued

Issued
	Number of Common Shares	Consideration
Balance as at December 31, 2020	121,688,812	$ 391,752,000
Shares issued on stock option exercises	353,200	932,000
Balance as at June 30, 2021	122,042,012	$ 392,684,000

During the first six months of 2021 , 353,200 common shares were issued upon the exercise of stock options for proceeds of $683,000 and related prior period share-based compensation of $249,000 was transferred to share capital from contributed surplus.

For the period from July 1, 2021 to August 11, 2021, the date of this report, there were 90,000 common shares issued upon the exercise of stock options for proceeds of $257,000.

10. SHARE-BASED COMPENSATION

Stock Options

The Company has a stock option plan under which it may grant, at the Company’s discretion, options to purchase common shares to directors, officers and employees. Options are granted at the volume weighted average price of the shares on the TSX for the five trading days immediately preceding the date of grant, have a four-year term and vest in one-third tranches over three years. Under the stock option plan, at June 30, 2021, a total of 12,204,201 common shares were available for issuance. At June 30, 2021, options in respect of 9,600,130 common shares were issued and outstanding and options in respect of 2,604,071 common shares were available for future issue.

35

At August 11, 2021, the date of this quarterly report, options in respect of 9,562,630 common shares were issued and outstanding and options in respect of 2,650,571 common shares are available for future issue.

Details of the options outstanding at June 30, 2021 are as follows:

		Weighted Average
	Number of Options	Exercise Price
Outstanding at December 31, 2020	10,192,330	$ 2.09
Granted during the period	99,000	$ 2.20
Exercised during the period	(353,200)	$ 1.93
Cancelled/forfeited during the period	(88,000)	$ 2.86
Expired duringtheperiod	(250,000)	$ 4.33
Outstandingat June 30,2021	9,600,130	$ 2.03
Number exercisable at June 30, 2021	4,502,529	$ 2.27

Range of Exercise Price		Outstanding Options	Outstanding Options	Exercisable Options	Exercisable Options
		Weighted	Weighted		Weighted
	Number of	Average	Average	Number of	Average
	Options	Remaining	Exercise	Options	Exercise
	Outstanding	Life (years)	Price	Outstanding	Price
$1.11 - $1.70	2,830,700	2.5	$ 1.47	868,896	$ 1.47
$1.71 - $2.13	4,377,230	2.5	$ 1.94	1,382,333	$ 1.81
$2.14 - $4.10	2,392,200	0.7	$ 2.84	2,251,300	$ 2.87
Total	9,600,130	2.0	$ 2.03	4,502,529	$ 2.27

The fair value of employee stock options is measured using the Black-Scholes option pricing model. Measurement inputs include the share price on measurement date, exercise price of the instrument, expected volatility, forfeiture rate, weighted average expected life of the instruments (based on historical experience and general option holder behaviour), expected dividends and the risk-free interest rate (based on government bonds).

The weighted average inputs used in the Black-Scholes pricing model to determine the fair value of the options granted during the six months ended June 30, 2021 of $0.78 per share include the following:

	2021
Share price	$2.13 - $2.35
Exercise price	$2.13 - $2.35
Volatility	48%
Forfeiture rate	2%
Expected option life (years)	3.7
Risk-freeinterestrate	0.2% to 0.3%

Performance Awards and Director Share Awards

The Company has a performance award incentive plan which authorizes the Board of Directors to grant performance awards to officers, employees, consultants or other service providers. Each performance award entitles the holder to an award value equal to the number of shares designated in the performance award grant, multiplied by a payout multiplier ranging from 0 to 1.5X which is dependent on the performance of the Company relative to predefined corporate performance measures for a particular period. The Company also has a director share award plan where each director share award entitles an eligible director to receive an award value equal to the number of shares designated in the director award grant. Performance awards and director share awards vest one-half on the second anniversary of the grant date and the remaining one-half on the third anniversary of the grant date. The Company, at its sole and absolute discretion, shall have the option of settling vested awards with common shares acquired in the market or by payment of the award value in cash, or by a combination thereof. The value of performance awards and director share awards is determined at the grant date based on the volume weighted average price of the shares on the TSX for the five trading days immediately preceding the date of grant.

36

Details of the performance awards and director share awards outstanding at June 30, 2021 are as follows:

	Number of Performance Awards	Number of Director Share Awards
Outstanding at December 31, 2020	623,770	82,250
Granted duringtheperiod	33,000	-
Outstandingat June 30, 2021	656,770	82,250

Share-Based Compensation Expense

Share-based compensation expense of $0.6 million and $1.3 million was charged to the consolidated statement of income (loss) during the three and six months to June 30, 2021, respectively (2020 - $0.4 million and $0.9 million, respectively) with an equivalent offset to contributed surplus.

11. NET LOSS PER SHARE

Basic and diluted net loss per share were calculated as follows:

	Three Months ended	Three Months ended	Three Months ended	Six Months ended	Six Months ended	Six Months ended
	June 30, 2021		June 30, 2020	June 30, 2021		June 30, 2020
Net loss for theperiod($000s)	$(11,843)		$(11,665)	$(694)		$(1,153)
Common shares outstanding at
beginning of period	121,769,312		121,556,812	121,688,812		121,556,812
Effect of shares issued	123,027		-	114,876		-
Weighted average number of common
shares outstanding– basic & diluted	121,892,339		121,556,812	121,803,688		121,556,812
Net loss per share
Basic & diluted	$(0.10)		$(0.10)	$(0.01)		$(0.01)

• (1) For the three and six months ended June 30, 2021 and June 30, 2020, the Company incurred net losses and therefore there were no dilutive effects of stock options.

12. FINANCIAL INSTRUMENTS

The Company’s financial instruments include accounts receivable, prepaids and deposits, accounts payable and accrued liabilities, bank indebtedness and risk management contracts.

Storm classifies the fair value of financial instruments according to the following hierarchy based on the amount of observable inputs used to value the instrument.

• Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide continual and verifiable pricing information.

• Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities and interest rates, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.

• Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.

The carrying value of bank indebtedness approximates its fair value as it bears interest at market rates. The fair value of the Company’s risk management contracts described below is based on forward prices of commodities and interest rates available in the marketplace and they are therefore classified as Level 2 financial instruments. The Company does not have any financial instruments classified as Level 3 and there were no transfers between levels within the fair value hierarchy for the three and six months ended June 30, 2021.

The Company’s risk management contracts are subject to master netting agreements that create a legally enforceable right to offset by counterparty the related financial assets and financial liabilities on the Company’s consolidated statements of financial position. The following is a summary of the Company’s financial assets and financial liabilities that are subject to offset as at June 30, 2021:

37

	Gross Amounts	Gross Amounts	Net Amounts
	Recognized as Financial	of Financial Assets	Recognized as Financial
	Assets (Liabilities)	(Liabilities) Offset	Liabilities
Risk management contracts
Current asset	$ 978	$ (978)	$ -
Long-term asset	828	(828)	-
Current liability	(43,759)	978	(42,781)
Long-term liability	(5,369)	828	(4,541)
Netposition	$(47,322)	$ -	$(47,322)

The following is a summary of the Company’s financial assets and financial liabilities that were subject to offset as at December 31, 2020:

December 31, 2020:
	Gross Amounts	Gross Amounts	Net Amounts
	Recognized as Financial	of Financial Assets	Recognized as Financial
	Assets (Liabilities)	(Liabilities) Offset	Assets (Liabilities)
Risk management contracts
Current asset	$ 3,518	$ (3,518)	$ -
Long-term asset	1,511	(1,278)	233
Current liability	(12,001)	3,518	(8,483)
Long-term liability	(1,379)	1,278	(101)
Netposition	$(8,351)	$ -	$(8,351)

Accounts Receivable

The Company’s accounts receivable tend to be concentrated with a limited number of marketers of the Company’s production as well as joint operation partners and are subject to normal industry credit risk. Receivables from crude oil and natural gas marketers are typically collected on or about the 25[th] of the following month. The Company's production is sold to organizations whose credit worthiness is in part assessable from publicly available information. As at June 30, 2021, the Company’s three major energy customers with investment grade credit ratings accounted for $20.9 million of total receivables (June 30, 2020 - $9.5 million) and 89% of total revenues for the three and six months ended June 30, 2021 (three and six months ended June 30, 2020 - 90% and 95%, respectively). Where operations involve partners in a joint operation, the Company attempts to mitigate the risk from joint operation receivables by obtaining pre-approval from its partners in advance of significant capital expenditures. Receivables from joint operations are typically collected within one to three months of the joint operator bill being issued. As at June 30, 2021, there were no receivables outstanding for more than 60 days. No material default on outstanding receivables is anticipated as none of the Company’s outstanding receivables are considered past due at June 30, 2021.

The maximum exposure to credit risk at June 30, 2021 was the carrying amount of accounts receivable of $26.3 million. No receivables were impaired at June 30, 2021.

Commodity Price Risk

The Company uses risk management contracts to manage its exposure to fluctuations in commodity prices, by fixing prices of future deliveries of crude oil and natural gas and thus providing stability of funds flow. Although the Company had no crude oil production at June 30, 2021, part of its condensate and NGL stream is sold at a price based on crude oil. Accordingly, a financial investment based on crude oil is used as a proxy for the Company’s condensate and NGL stream.

Fair values for risk management contracts are based on quotes received from financial institution counterparties and are calculated using current market rates and prices and option pricing models using forward pricing curves and implied volatility.

At the date of this report, the Company had entered into the following outstanding financial risk management contracts in place to manage commodity price risk:

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As at August 11, 2021		2021	2022	2023
Natural Gas
NYMEX swap	Mmbtu/d	3,495	-	-
	US$/Mmbtu	$2.62	-	-
NYMEX swap	Mmbtu/d	7,348	-	-
	Cdn$/Mmbtu	$3.34	-	-
NYMEX collar	Mmbtu/d	1,000	1,008	493
	US$/Mmbtu	$2.70 - $3.25	$2.40 - $3.60	$2.40 - $3.60
NYMEX collar	Mmbtu/d	700	-	-
	Cdn$/Mmbtu	$3.60 - $3.78	-	-
Chicago swap	Mmbtu/d	1,492	18,722	-
	US$/Mmbtu	$2.98	$2.49	-
Chicago swap	Mmbtu/d	18,274	2,282	-
	Cdn$/Mmbtu	$3.14	$3.29	-
Chicago collar(1)	Mmbtu/d	700	5,186	1,973
	US$/Mmbtu	$2.84 - $3.47	$2.68 - $3.33	$2.70 - $3.25
Chicago collar(1)	Mmbtu/d	2,000	2,219	-
	Cdn$/Mmbtu	$3.60 - $4.20	$3.58 - $4.19	-
AECO swap	GJ/d	7,195	1,360	-
	Cdn$/GJ	$2.30	$2.80	-
AECO collar	GJ/d	995	1,618	-
	Cdn$/GJ	$2.63 - $3.80	$2.37 - $3.20	-
BC Station 2 swap	GJ/d	29,799	19,675	-
	Cdn$/GJ	$2.13	$2.27	-
BC Station 2 collar(2)	GJ/d	-	2,244	-
	Cdn$/GJ	-	$2.18 -$3.04	-
Natural Gas Differential Swaps
NYMEX:Chicago	Mmbtu/d	12,500
	US$/Mmbtu	($0.26)
Crude Oil
WTI swap	Bbls/d	-	150	-
	US$/Bbl	-	$51.43	-
WTI swap	Bbls/d	650	-	-
	Cdn$/Bbl	$54.33	-	-
WTI collar	Bbls/d	1,050	597	-
	Cdn$/Bbl	$53.19 - $63.67	$60.66 - $74.14	-
WTI collar	Bbls/d	200	549	-
	US$/Bbl	$44.00 -$54.23	$49.41 -$61.20	-
Crude Oil Differential Swaps
WTI:C5	Bbls/d	1,100	545	-
	Cdn$/Bbl	($3.61)	($1.92)	-
Propane
Conway swap	Bbls/d	200	49	-
	Cdn$/Bbl	$44.66	$54.89	-
Argus Far East Index swap	Bbls/d	100	-	-
	Cdn$/Bbl	$46.31	-	-
Argus Far East Index swap	Bbls/d	133	25	-
	US$/Bbl	$41.50	$52.50	-

(1) Includes NYMEX collar and a NYMEX-Chicago basis differential.

(2) Includes AECO collar and an AECO-BC Station 2 basis differential.

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Physical Delivery Sales Contracts

The Company also enters into physical delivery sales contracts from time to time to manage commodity price risk. These contracts are considered normal executory contracts and are not recognized in the consolidated statement of income (loss) and comprehensive income (loss) until volumes are delivered.

	DailyVolume	Contract Price
Natural Gas
Jul 2021 - Oct 2021	5,000 GJ at BC Station 2	AECO 7A less Cdn$0.125/GJ
Jul 2021 - Oct 2021	6,000 GJ at ATP	AECO 7A plus Cdn$0.00/GJ
Nov 2021 - Oct 2022	6,000 GJ at ATP	AECO 7Aplus Cdn$0.115/GJ

Interest Rate Risk

The Company may enter into interest rate swap contracts to manage the uncertainty of variable interest rates by fixing the variable component of a portion of the interest paid on the Company’s revolving bank facility. As at June 30, 2021, the Company had the following outstanding financial risk management contracts in place to manage interest rate risk:

			Notional		Fixed
Index	Effective	Date	Principal	Remaining Term	Contract Rate
One-month bankers’ acceptance - CDOR(1)	May	2019	$25 million	Jul 2021 - May 2022	1.949%
One-month bankers’ acceptance - CDOR(1)	Jan	2020	$10 million	Jul 2021 - Jan 2023	1.943%
One-month bankers’ acceptance - CDOR(1)	Jan	2021	$15 million	Jul 2021 - Jan 2024	0.660%

(1) Canadian Dollar Offered Rate.

Risk Management

Risk management contracts may be used by the Company to manage exposure to market risks related to commodity prices, exchange rates and interest rates. The use of financial risk management contracts is governed by Storm’s Board of Directors and follows guidelines and limits approved by the Board. Storm does not use derivative contracts for speculative purposes. All derivative contracts are classified at fair value through profit and loss and measured at fair value, with gains and losses on re-measurement included as a component of unrealized risk management contracts in the period in which they arise.

The fair market value of these risk management contracts at June 30, 2021 was a net liability position of $47.3 million (December 31, 2020 - net liability position of $8.4 million) and is included in current and non-current assets or current and non-current liabilities based on the contractual terms specific to the instruments. For the three and six months ended June 30, 2021, this resulted in unrealized mark-to-market losses of $30.3 million and $39.0 million, respectively, (June 30, 2020 - unrealized mark-to-market losses of $13.8 million and $3.3 million, respectively) when measured against the fair market value at the end of the preceding reporting period. These amounts are recognized in the consolidated statement of income (loss) and comprehensive income (loss).

The Company realized losses from risk management price contracts in place in the amount of $9.1 million and $14.3 million, respectively, for the three and six months ended June 30, 2021 (June 30, 2020 - realized gains of $6.5 million and $9.3 million, respectively).

Sensitivities

The following table summarizes the effects of movement in commodity prices and interest rates on net loss due to changes in the fair value of risk management contracts in place at June 30, 2021. Changes in the fair value generally cannot be extrapolated because the relationship of a change in an assumption to the change in fair value may not be linear.

linear.
	Six Months Ended June 30, 2021
Factor	Gain/(Loss)
Increase of US$5.00/Bbl in the price of WTI(1)	$ (4,299)
Decrease of US$5.00/Bbl in the price of WTI(1)	$ 4,299
Increase of US$0.10/Mmbtu in the price of NYMEX natural gas	$ (3,606)
Decrease of US$0.10/Mmbtu in the price of NYMEX natural gas	$ 3,606
Increase of 100 basis points (1%) in interest rates	$ 777
Decrease of 100 basispoints(1%)in interest rates	$(777)

(1) A portion of the Company’s condensate and NGL production is sold at a price based on WTI.

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13. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in non-cash working capital

	Three Months ended	Three Months ended	Three Months ended	Six Months ended	Six Months ended	Six Months ended
	June 30,2021		June 30,2020	June 30,2021		June 30,2020
Accounts receivable	$ 1,007		$ 9,637	$ (7,040)		$ 11,086
Prepaids and deposits	1,862		(73)	416		130
Accountspayable and accrued liabilities	(12,151)		(22,482)	3,440		(17,637)
Change in non-cash workingcapital	$(9,282)		$(12,918)	$(3,184)		$(6,421)
Relating to:
Operating activities	$ (5,541)		$ 2,636	$ (3,644)		$ 2,164
Investingactivities	(3,741)		(15,554)	460		(8,585)
Change in non-cash workingcapital	$(9,282)		$(12,918)	$(3,184)		$(6,421)
Interestpaid duringtheperiod	$ 1,578		$ 1,566	$ 3,462		$ 3,135
Income taxespaid duringtheperiod	$ -		$ -	$ -		$ -

14. COMMITMENTS

At June 30, 2021, the Company has the following long-term commitments over the next five years and thereafter:

	2021	2022	2023	2024	2025	Thereafter	Total
Transportation and processing commitments	$ 32,482	$ 59,960	$ 28,030	$ 28,153	$ 27,871	$177,933	$354,429
Office lease(1)	178	356	356	356	356	30	1,632
Total	$ 32,660	$ 60,316	$ 28,386	$ 28,509	$ 28,227	$177,963	$356,061

(1) Office lease commitment includes the operating cost component of the office lease costs.

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CORPORATE INFORMATION

Officers

Brian Lavergne President & Chief Executive Officer

Robert S. Tiberio Chief Operating Officer

Michael J. Hearn Chief Financial Officer

Jamie P. Conboy Vice President, Geology

H. Darren Evans Vice President, Exploitation

Bret A. Kimpton Vice President, Production

Emily Wignes Vice President, Finance

Directors

Matthew J. Brister[(2)(3)]

John A. Brussa

Mark A. Butler[(1)(3)]

Stuart G. Clark[(1)] Chairman

Sheila A. Leggett[(2) ]

Gregory G. Turnbull[(2)] P. Grant Wierzba[(2)(3)]

James K. Wilson[(1) ]

Brian Lavergne President & Chief Executive Officer

(1) Member, Audit Committee (2) Member, Reserves, Environment, Health and Safety Committee (3) Member, Compensation, Governance and Nomination Committee

Stock Exchange Listing

Toronto Stock Exchange Trading Symbol “SRX”

Solicitors

Stikeman Elliott LLP Burnet Duckworth & Palmer LLP Calgary, Alberta

Auditors

Ernst & Young LLP Calgary, Alberta

Registrar & Transfer Agent

Alliance Trust Company Calgary, Alberta

Bankers

ATB Financial Canadian Imperial Bank of Commerce Royal Bank of Canada Canadian Western Bank Calgary, Alberta

Executive Offices

Suite 600, 215 – 2[nd] Street S.W. Calgary, Alberta, T2P 1M4 Canada Tel: (403) 817-6145 Fax: (403) 817-6146 www.stormresourcesltd.com

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Abbreviations

ATP	Alliance Transfer Point
Bbls	Barrels of oil or natural gas liquids
Bbls/d	Barrels per day
Bcf	Billions of cubic feet
Boe	Barrels of oil equivalent
Boe/d	Barrels of oil equivalent per day
Bopd	Barrels of oil per day
Btu	British thermal unit
Cdn$	Canadian dollar
CGU DPIIP	Cash generating unit Discovered Petroleum Initially in Place
GJ	Gigajoules
GJ/d	Gigajoules per day
IP	Initial production rates
kPa	Kilopascal
LNG	Liquefied natural gas

Mbbl	Thousands of barrels
Mboe	Thousands of barrels of oil equivalent
Mcf	Thousands of cubic feet
Mcf/d	Thousands of cubic feet per day
Mmbtu	Millions of British Thermal Units
Mmbtu/d	Millions of British Thermal Units per day
Mmcf	Millions of cubic feet
Mmcf/d	Millions of cubic feet per day
NGL	Natural gas liquids
NYMEX	New York Mercantile Exchange
OPEC	Organization of Petroleum Exporting Countries
PDP	Proved developed producing (reserves)
TSX	Toronto Stock Exchange
US	United States
US$	United States dollar
WTI	West Texas Intermediate

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==> picture [122 x 47] intentionally omitted <==

Storm Resources Ltd.

Suite 600, 215 – 2[nd] Street S.W., Calgary, Alberta T2P 1M4 Phone: (403) 817-6145 Fax: (403) 817-6146

www.stormresourcesltd.com