Storm Resources Ltd. — Interim / Quarterly Report 2020

Nov 11, 2020

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 nine months ended September 30, 2020. It should be read in conjunction with (i) the Company’s unaudited condensed interim consolidated financial statements for the three and nine months ended September 30, 2020, (ii) the Company’s MD&A and audited consolidated financial statements for the year ended December 31, 2019, and (iii) the press release issued by the Company on November 10, 2020, 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 30, 2020 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 November 10, 2020.

See discussion related to “Forward Looking Statements”, “Boe Presentation”, and “Non-GAAP Measurements” on pages 22 to 25.

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 nine months ended September 30, 2020, 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, 2019. 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 nine month periods ended September 30, 2019.

OPERATIONAL AND FINANCIAL RESULTS

Overview

A similar theme played out in the third quarter of 2020 compared to the same period in the prior year as third-party outages and low commodity prices reduced Storm’s production and funds flow, although the most significant of the three outages in the third quarter of 2020 was a planned event compared to the unplanned outages that affected the prior year. As previously communicated, the McMahon Gas Plant incurred a 28-day planned turnaround in September 2020 and, coupled with a concurrent 8-day turnaround at the Stoddart Gas Plant, reduced September 2020 production to approximately 13,400 Boe per day. Production levels in the third quarter of 2020 were also affected by a 6-day unplanned outage at the McMahon Gas Plant and unplanned outages on the Enbridge T-North system.

Similar to the second quarter of 2020, Storm focused on managing through low commodity prices brought on by an extended period of elevated supply levels that was further exacerbated by demand destruction from the economic shutdowns associated with the COVID-19 pandemic. In looking past the third quarter at significantly higher natural gas prices, a four-well pad at Nig Creek was drilled in the third quarter to capitalize on higher winter pricing with the four wells completed in October and on production in late October. Capital expenditures in the third quarter were consistent with the previously announced guidance range of $10 to $15 million.

While demand for crude oil has improved and WTI prices have stabilized around the US$40.00 per barrel level, the economic situation remains highly volatile with a second wave of COVID-19 well underway across the globe. As previously stated, the extent to which the ongoing presence of COVID-19 may affect the Company remains uncertain; 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. While

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

Subsequent to quarter end, the Company’s bank syndicate, upon completion of a mid-year review, confirmed Storm’s bank facility at $205 million. To reduce associated fees the Company voluntarily reduced its credit facility to $190 million. The credit facility was approximately 75% drawn at the end of the third quarter (including $13.4 million for outstanding letters of credit). With funds flow for the remainder of the year expected to exceed capital expenditures, low maintenance capital, a strong hedge portfolio, and approximately $40 million of unused credit capacity, Storm maintains adequate financial liquidity to manage through the ongoing volatility in commodity prices.

Production and Revenue

Average Daily Production

	Three Months to	Three Months to	Quarter-Over-Quarter	Nine Months to	Nine months to	Year-Over-Year
	Sept. 30,2020	Sept. 30,2019	Change	Sept. 30,2020	Sept. 30,2019	Change
Natural gas (Mcf/d)	91,526	91,053	1%	107,361	95,013	13%
Condensate (Bbls/d)	1,637	1,856	(12%)	2,186	2,044	7%
NGL (Bbls/d)	2,136	1,564	37%	2,211	1,563	41%
Total (Boe/d)	19,027	18,596	2%	22,291	19,443	15%
Natural gas weighting	80%	82%		80%	81%
Condensate weighting	9%	10%		10%	11%
NGL weighting	11%	8%		10%	8%

Production for natural gas, condensate and NGL for the third quarter of 2020 was 2% higher than the third quarter of 2019. The third quarter of 2020 was affected by 34 days of third-party outages at the McMahon Gas Plant which reduced production by approximately 3,600 Boe per day. Of the 34 days of outages, 28 days related to planned outages while the remaining six days of outages were unplanned. Comparatively, the third quarter of 2019 was affected by a third-party outage at the McMahon Gas Plant (14 days) in addition to the voluntary curtailment of production in response to the low natural gas price at Station 2.

Production for the first nine months of 2020 was 15% higher than the same period of 2019 primarily due to incremental production from new wells brought on production in late 2019 and in the first half of 2020. Furthermore, the Nig Creek Gas Plant was commissioned in February 2020 leading to incremental production from higher NGL recovery and reduced gas shrinkage.

The Company started production from three new 100% working interest horizontal wells at Umbach during the first nine months of 2020.

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Average Daily Production
30,000 220
25,000 200
180
20,000
160
15,000
140
10,000
120
5,000 100
- 80
Condensate and NGL Natural Gas Volumes per MM Shares O/S
Boe/d
Per MM Shares O/S
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Revenue from Product Sales[(1) ]

Revenue from Product Sales(1)
	Three Months to	Three Months to	Nine Months to	Nine Months to
	Sept. 30,2020	Sept. 30,2019	Sept. 30,2020	Sept. 30,2019
Natural gas	$ 20,813	$ 20,252	$ 70,998	$ 82,652
Condensate	7,046	10,836	26,961	36,726
NGL	2,151	329	4,165	5,373
Total	$ 30,010	$ 31,417	$ 102,124	$ 124,751
% of Total Revenue by Product Type
Natural gas	69%	64%	70%	66%
Condensate and NGL	31%	36%	30%	34%
Total	100%	100%	100%	100%

(1) Before realized gains and losses on risk management contracts and including natural gas purchased and sold to meet marketing commitments during outages.

Revenue from product sales for the third quarter of 2020 decreased by 4% when compared to the third quarter of 2019 primarily as a result of a decrease in the Company’s realized condensate price and condensate production volumes, partially offset by an increase in the Company’s average realized price for NGL. For the nine month periods, revenue from product sales decreased by 18% year over year due to the Company’s average realized price decreasing by 29%, partially offset by production volumes increasing by 15%.

Average Selling Prices[(1) ]

Average Selling Prices(1)
	Three Months to	Three Months to	Nine Months to	Nine Months to
	Sept. 30,2020	Sept. 30,2019	Sept. 30,2020	Sept. 30,2019
Natural gas – Mcf	$ 2.47	$ 2.42	$ 2.41	$ 3.19
Condensate – Bbl	$ 46.79	$ 63.45	$ 45.01	$ 65.81
NGL – Bbl	$ 10.95	$ 2.29	$ 6.87	$ 12.59
Per Boe	$ 17.14	$ 18.36	$ 16.72	$ 23.50

(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 September 30, 2020 decreased compared to the same period of 2019, with the decrease driven by lower condensate pricing, partially offset by higher NGL and natural gas pricing. The decrease in condensate pricing is primarily due to a significant reduction in WTI benchmark pricing. The increase in realized natural gas pricing is primarily due to higher BC Station 2 and AECO index pricing, partially offset by a reduction in benchmark prices at Chicago and Sumas. The Company’s NGL price for the third quarter of 2020 was 20% of WTI, within the guidance range of 15% to 20% of WTI.

On a per-Boe basis, the Company’s average realized price for the first nine months of 2020 decreased by 29% when compared to the first nine months of 2019, driven by lower pricing across all product streams. The decrease in realized natural gas pricing is primarily due to lower Chicago and Sumas benchmark pricing, partially offset by higher BC Station 2 and AECO pricing. The decrease in realized condensate pricing is due primarily to lower WTI pricing and the decrease in the Company’s NGL price is primarily due to lower WTI and propane pricing.

Benchmark Prices

Benchmark Prices
	Three Months to	Three Months to	Nine Months to	Nine Months to
	Sept. 30,2020	Sept. 30,2019	Sept. 30,2020	Sept. 30,2019
Natural gas
Chicago monthly index (US$/Mmbtu)	1.87	2.03	1.82	2.60
Chicago daily index (US$/Mmbtu)	1.85	2.10	1.74	2.48
Sumas (US$/Mmbtu)	1.90	2.08	1.94	3.66
AECO monthly index (Cdn$/GJ)	2.04	0.99	1.96	1.32
AECO daily index (Cdn$/GJ)	2.12	0.87	1.98	1.44
BC Station 2(Cdn$/GJ)	2.14	0.63	1.96	0.81
Crude Oil
WTI (US$/Bbl)	40.93	56.45	38.32	57.06
WTI (Cdn$/Bbl)	54.50	74.57	51.88	75.84
Edmonton condensate (Cdn$/Bbl)	50.00	68.70	47.90	70.21
Exchange rate(US$/Cdn$)	0.75	0.76	0.74	0.75

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US natural gas prices trended lower in 2019, particularly in the latter half of the year, due to increasing supply and reduced demand through the summer and into shoulder season. US natural gas prices have been under further pressure in 2020 with higher storage levels at the end of last winter’s heating season. US natural gas production has decreased since the spring and LNG exports have rebounded since the summer of 2020. As a result, natural gas pricing has gained momentum into the fourth quarter of 2020 and 2021 with the expectation that supply/demand will be much tighter this winter.

BC Station 2 pricing increased in the third quarter of 2020 compared to the third quarter of 2019 due to the higher AECO price with the differential to AECO narrowing significantly with the decline in receipts onto the Enbridge T-north system following completion of the TC Energy North Montney pipeline in January 2020.

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, declined 27% from US$56.45 per barrel during the third quarter of 2019, to US$40.93 per barrel in the third quarter of 2020. The decline was the result of elevated supply levels and the onset of demand destruction from economic shut-downs associated with COVID-19. Offsetting the decrease in WTI was a narrowing of the condensate differential from a discount of US$4.44 per barrel in the third quarter of 2019 to a discount of US$3.38 per barrel in the third quarter of 2020.

The Company’s production during the third quarter was sold as follows:

	Three Months to	Three Months to	Nine Months to	Nine Months to
	Sept. 30,2020	Sept. 30,2019	Sept. 30,2020	Sept. 30,2019
Chicago monthly index price	39%	33%	32%	35%
Chicago daily index price	28%	29%	25%	23%
AECO index price	12%	10%	13%	11%
BC Station 2 index price	7%	17%	15%	18%
Sumas index price	10%	11%	10%	11%
Alliance Transfer Point(“ATP”)	4%	-	5%	2%
Total	100%	100%	100%	100%

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Storm Realized Natural Gas Price vs. Benchmark
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$6.00
$5.00
$4.00
$3.00
$2.00
$1.00
$0.00
Q4/18 Q1/19 Q2/19 Q3/19 Q4/19 Q1/20 Q2/20 Q3/20
Storm Realized Nat Gas Price ($/Mcf) Station 2 ($/GJ)
AECO Daily ($/GJ) Chicago Monthly (Cdn$/Mmbtu)
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In the third quarter of 2020, Storm’s realized natural gas price increased 2% from the third quarter of 2019, as significant increases in Station 2 and AECO pricing were partially offset by lower Chicago and Sumas pricing. The Company’s natural gas sales price largely tracks Chicago pricing given that 57% of year-to-date sales are at Chicago.

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Storm Condensate Price vs. Benchmark
$85.00
$75.00
$65.00
$55.00
$45.00
$35.00
$25.00
$15.00
Q4/18 Q1/19 Q2/19 Q3/19 Q4/19 Q1/20 Q2/20 Q3/20
Storm Condensate Price WTI Cdn$
Cdn$/Bbl
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Storm’s realized condensate price of $46.79 per barrel for the third quarter of 2020 decreased by 26% from the third quarter of 2019 primarily as a result of a decrease in the WTI price.

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Storm NGL Price vs. Benchmark
$60.00
50%
$50.00
40%
$40.00
30%
$30.00
$20.00 20%
$10.00 10%
$0.00 0%
Q4/18 Q1/19 Q2/19 Q3/19 Q4/19 Q1/20 Q2/20 Q3/20
Storm NGL Price Conway Propane
Mt. Belvieu Butane Storm NGL Price (% of WTI)
Cdn$/Bbl % of WTI Cdn$
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In the third quarter of 2020, Storm’s realized price for NGL, excluding condensate, increased relative to the same period of 2019 due to higher contracted prices with marketers and higher propane pricing, partially offset by lower WTI pricing.

Storm’s NGL price net of transportation is anticipated to be approximately 15% to 20% of WTI in Canadian dollar terms for the contract period that commenced in April 2020 and ends in March 2021.

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Realized Gain (Loss) on Risk Management

	Three Months to	Three Months to	Nine Months to	Nine Months to
	Sept. 30,2020	Sept. 30,2019	Sept. 30,2020	Sept. 30,2019
Natural gas	$ 201	$ 1,914	$ 3,584	$ (8,174)
Liquids(1)	697	897	6,564	985
Realized gain (loss) on risk management
contracts	$ 898	$2,811	$10,148	$ (7,189)
Per Boe	$ 0.51	$ 1.64	$ 1.66	$(1.35)

(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 consist of the portion of contracts that have settled during the reporting period. The realized gains for the three and nine months ended September 30, 2020 are due to lower WTI crude oil pricing combined with lower natural gas pricing at Chicago and Sumas.

Royalties

Royalties
	Three Months to	Three Months to	Nine Months to	Nine Months to
	Sept. 30,2020	Sept. 30,2019	Sept. 30,2020	Sept. 30,2019
Charge for period	$ 1,343	$ (332)	$ 4,399	$ 4,902
Percentage of revenue fromproduct sales	4.5%	(1.1%)	4.3%	3.9%
Per Boe	$ 0.77	$(0.19)	$ 0.72	$ 0.92

Royalties, as a percentage of revenue from product sales, increased in the third quarter of 2020 compared to the same period in 2019 primarily due to the receipt of infrastructure royalty credits of $1.9 million in 2019.

Royalties, as a percentage of revenue from product sales, increased in the nine months ended September 30, 2020 compared to the same period in 2019 primarily due to the receipt of infrastructure royalty credits of $3.5 million in 2019 versus no credits received to date in 2020. Lower commodity prices reduced the benefit from the BC Deep Well Royalty Program. The BC Deep Well Royalty Credit Program reduces the royalty rate on new horizontal wells to 6% for approximately one to three years depending on productivity and commodity prices.

Storm has remaining infrastructure royalty credits of $7.0 million that will reduce future royalties including credits of $6.2 million relating to the construction of the Nig Creek Gas Plant which came online in February 2020. Future royalty payments 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	Nine Months to	Nine Months to
	Sept. 30,2020	Sept. 30,2019	Sept. 30,2020	Sept. 30,2019
Charge forperiod	$ 8,471	$ 10,068	$ 29,522	$ 31,611
Per Boe	$ 4.84	$ 5.88	$ 4.83	$ 5.96

Total production costs for the third quarter and first nine months of 2020 decreased when compared to the same periods of 2019. The decrease in total production costs is primarily due to lower third-party gas processing costs as a result of the start-up of the Nig Creek Gas Plant in February 2020, partially offset by higher production volumes.

Production costs on a per-Boe basis in 2019 and 2020 were both affected by incurring fixed costs related to firm processing commitments during outages at the McMahon Gas Plant.

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. Storm pays carbon tax on fuel used in the Company’s own facilities as well as on natural

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gas volumes processed at third-party facilities. The following table outlines the total carbon taxes (direct and indirect) that are included within production costs.

that are included within production costs.
	Three Months to	Three Months to	Nine Months to	Nine Months to
	Sept. 30,2020	Sept. 30,2019	Sept. 30,2020	Sept. 30,2019
Charge forperiod	$ 1,420	$ 1,368	$ 4,591	$ 4,196
Per Boe	$ 0.81	$ 0.80	$ 0.75	$ 0.79

Transportation Costs

Transportation Costs
	Three Months to	Three Months to	Nine Months to	Nine Months to
	Sept. 30,2020	Sept. 30,2019	Sept. 30,2020	Sept. 30,2019
Charge forperiod	$ 11,248	$ 9,981	$ 34,064	$ 30,995
Per Boe	$ 6.43	$ 5.83	$ 5.58	$ 5.84

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 across North America have higher per-unit transportation costs, but obtain higher sales prices which offsets the higher pipeline tariffs.

Transportation costs for the third quarter of 2020 increased by 13% when compared to the third quarter of 2019 primarily due to firm transportation commitments which were not used during the third-party gas plant outages in the current quarter. Also contributing to the quarter-over-quarter increase are incremental costs associated with transporting natural gas volumes from the Nig Creek Gas Plant to the Alliance Pipeline in the third quarter of 2020. On a per-Boe basis, transportation costs for the third quarter of 2020 increased by 10% when compared to the third quarter of 2019 primarily due to incurring fixed costs in the current quarter for unused firm transportation during the planned and unplanned outages.

Transportation costs for the first nine months of 2020 increased by 10% when compared to the same period in 2019 primarily due to higher production volumes in 2020 and from incremental costs associated with transporting natural gas volumes from the Nig Creek Gas Plant to the Alliance Pipeline. Transportation costs for the first nine months of 2020 decreased by 4% on a per-Boe basis when compared to the same period of 2019, primarily due to the fixed costs for unused firm transportation during outages having a lesser effect in 2020 (43 days of outages in 2019 compared to 34 days of outages in 2020).

Field Operating Netbacks

Details of field operating netbacks are as follows:

	Three Months to	Three Months to	Nine Months to	Nine Months to
($/Boe)	Sept. 30,2020	Sept. 30,2019	Sept. 30,2020	Sept. 30,2019
Revenue from product sales	17.14	18.36	16.72	23.50
Royalties	(0.77)	0.19	(0.72)	(0.92)
Production costs	(4.84)	(5.88)	(4.83)	(5.96)
Transportation costs	(6.43)	(5.83)	(5.58)	(5.84)
Field operating netback	5.10	6.84	5.59	10.78
Realized gain (loss) on risk management
contracts	0.51	1.64	1.66	(1.35)
Field operatingnetback includinghedging	5.61	8.48	7.25	9.43

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The field operating netback for the third quarter of 2020 decreased by 34% after hedging compared to the third quarter of 2019.

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Change in Quarterly Field Operating Netback Including Hedging: Q3/19 vs. Q3/20
$10.00
$8.48 ($1.22)
$8.00 ($0.96) $1.04 ($0.60)
($1.13)
$5.61
$6.00
$4.00
$2.00
$-
Q3 2019 Revenue Royalties Prod. Costs Transp. Realized Hedging Q3 2020
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The field operating netback for the first nine months of 2020 decreased by 23% after hedging compared to the first nine months of 2019. The increase in realized hedging is due to a realized hedging loss of $1.35 per Boe in the first nine months of 2019 compared to a realized gain of $1.66 per Boe in the first nine months of 2020.

The realized hedging gain partially offset decreases in revenue as a result of lower benchmark pricing for crude oil and natural gas.

Change in YTD Field Operating Netback Including Hedging: Q3/19 vs. Q3/20

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$12.00
$9.43 ($6.78)
$9.00
$3.01 $7.25
$6.00
$0.26
$1.13
$0.20
$3.00
$-
2019 Revenue Royalties Prod. Costs Transp. Realized Hedging 2020
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General and Administrative Costs

General and Administrative Costs
	Three Months to	Three Months to	Nine Months to	Nine Months to
	Sept. 30,2020	Sept. 30,2019	Sept. 30,2020	Sept. 30,2019
Charge for period – before recoveries	$ 1,806	$ 1,728	$ 6,103	$ 6,831
Overhead recoveries	(545)	(369)	(1,405)	(1,393)
Charge forperiod – net of recoveries	$ 1,261	$ 1,359	$ 4,698	$ 5,438
Per Boe	$ 0.72	$ 0.79	$ 0.77	$ 1.02

General and administrative costs before recoveries for the third quarter of 2020 were largely unchanged when compared to the third quarter of 2019. General and administrative costs before recoveries for the nine months ended September 30, 2020 decreased by 11% compared to the same period of 2019 primarily due to the employee performance bonus paid in early 2020 for 2019 performance being lower than what was paid in the previous year.

Fluctuations in overhead recoveries are generally related to the amount and type of field capital expenditures incurred.

Net general and administrative costs on a per-Boe measure for the third quarter of 2020 were lower by 9% compared to the third quarter of 2019 due to an increase in overhead recoveries. Net general and administrative costs on a perBoe basis decreased by 25% when comparing the first nine months of 2020 to the same period of 2019 due to the aforementioned decrease in the employee performance bonus and 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	Nine Months to	Nine Months to
	Sept. 30,2020	Sept. 30,2019	Sept. 30,2020	Sept. 30,2019
Charge for period(1)	$ 1,928	$ 1,215	$ 5,093	$ 3,648
Effective interest rate(2)	6.0%	5.0%	5.2%	5.1%
Per Boe	$ 1.10	$ 0.71	$ 0.83	$ 0.69

(1) Includes lease interest.

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

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 third quarter and first nine months of 2020 increased by 59% and 40%, respectively, compared to the same periods of 2019 as a result of higher average bank borrowings which were used to fund the construction of the Nig Creek Gas Plant combined with a higher effective interest rate due to a tightening of credit markets as a result of the COVID-19 pandemic. The effective interest rate for the third quarter of 2020 increased from the third quarter of 2019 due to higher fees from tightening of credit markets and an increase in the Company’s debt-to-funds-flow ratio resulting from funding the aforementioned gas plant construction. With an improved commodity price outlook for the fourth quarter of 2020 and for 2021, the expected increase in funds flow will result in stamping fees and interest expense being reduced.

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Funds Flow

Funds Flow
	Three Months to		Three Months to		Nine Months to		Nine Months to
	Sept.	30,2020	Sept. 30,2019		Sept.	30,2020	Sept.	30,2019
		Per		Per		Per		Per
		diluted		diluted		diluted		diluted
		share		share		share		share
Funds flow	$6,681	$0.05	$11,973	$0.10	$34,474	$0.28	$41,080	$0.34

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.

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Change in Quarterly Funds Flow ($M): Q3/19 vs. Q3/20
$728 ($2,135)
$11,973
$12,000
($1,675) $1,597 ($1,267)
($1,913)
$8,000 ($627)
$6,681
$4,000
$-
Q3 2019 Revenue - Revenue - Royalties Prod. Costs Transp. Realized Other (1) Q3 2020
Volume Price Hedging
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(1) Includes general and administrative cost, interest and finance costs and decommissioning expenditures and excludes lease interest.

Lower realized condensate prices, lower condensate production volumes, higher royalties and lower hedging gains were the predominant factors in the 44% decrease in funds flow in the third quarter of 2020 versus the third quarter of 2019.

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), was 11% in the third quarter of 2020 compared to 15% in the third quarter of 2019.

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Change in YTD Funds Flow ($M): Q3/19 vs. Q3/20
$18,788 ($41,415)
$60,000
$50,000
$41,080
$40,000
$17,337 ($839) $34,474
$30,000
$2,089 ($3,069)
$503
$20,000
$10,000
$-
2019 Revenue - Revenue - Royalties Prod. Costs Transp. Realized Other (1) 2020
Volume Price Hedging
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(1) Includes general and administrative cost, interest and finance costs and decommissioning expenditures and excludes lease interest.

Funds flow for the first nine months of 2020 decreased by 16% from the first nine months of 2019. Funds flow was negatively affected by weaker realized pricing across all products, partially offset by higher production volumes and realized hedging gains. The increase in realized hedging is due to a realized hedging loss in 2019 of $7.2 million compared to a realized hedging gain in the first nine months of 2020 of $10.1 million.

Share-Based Compensation

Share-Based Compensation
	Three Months to	Three Months to	Nine Months to	Nine Months to
	Sept. 30,2020	Sept. 30,2019	Sept. 30,2020	Sept. 30,2019
Charge forperiod	$ 483	$ 648	$ 1,387	$ 1,808
Per Boe	$ 0.28	$ 0.38	$ 0.23	$ 0.34

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 decreased by 25% in the third quarter of 2020 compared to the third quarter of 2019 and decreased by 23% when comparing the nine month periods. The decrease in sharebased compensation in both the three and nine month periods is primarily attributable to a lower stock option fair valuation associated with options granted during the fourth quarter of 2019.

Depletion and Depreciation

Depletion and Depreciation
	Three Months to	Three Months to	Nine Months to	Nine Months to
	Sept. 30,2020	Sept. 30,2019	Sept. 30,2020	Sept. 30,2019
Depletion	$ 7,878	$ 7,604	$ 26,917	$ 23,496
Depreciation	2,615	1,946	7,434	5,754
Charge forperiod	$ 10,493	$ 9,550	$ 34,351	$ 29,250
Per Boe	$ 5.99	$ 5.58	$ 5.62	$ 5.51

Depletion and depreciation increased by 10% in the third quarter of 2020 compared to the same quarter of 2019, and by 17% when comparing the nine month periods, primarily due to an increase in production volumes and higher incremental depreciation associated with the commissioning of the Nig Creek Gas Plant in 2020.

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Unrealized Gain (Loss) on Risk Management

	Three Months to	Three Months to	Nine Months to	Nine Months to
	Sept. 30,2020	Sept. 30,2019	Sept. 30,2020	Sept. 30,2019
Natural gas	$ (16,176)	$ (1,659)	$ (21,633)	$ 8,303
Liquids(1)	(1,997)	395	1,284	(4,652)
Interest rate	151	(13)	(1,020)	(111)
Unrealized gain (loss) on risk management
contracts	$ (18,022)	$ (1,277)	$ (21,369)	$3,540
Per Boe	$(10.30)	$(0.75)	$(3.50)	$ 0.67

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

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

Income Taxes

In May 2019, the Government of Alberta substantively enacted a reduction in the provincial corporate tax rate from 12% to 8% over a four-year period. In 2020, the time frame was revised and the rate was reduced to 8% effective July 1, 2020, although this revision has yet to be substantively enacted.

The Company did not incur any cash tax expense in the three and nine months ended September 30, 2020, nor does it expect to pay any cash tax in the remainder of 2020 or in 2021 based on current commodity prices, forecast taxable income, existing tax pools and planned capital expenditures.

Deferred income taxes arise from differences between the accounting and tax bases of the Company’s assets and liabilities. For the three and nine months ended September 30, 2020, the Company recognized a deferred income tax recovery of $5.5 million and $5.3 million, respectively, as a result of $22.4 million and $23.4 million of net loss before taxes, respectively. As at September 30, 2020, the Company had a deferred income tax liability of $4.0 million.

Net Income (Loss)

The mark-to-market valuation of risk management contracts resulted in a considerable distortion on reported net loss for the three and nine months ended September 30, 2020 relative to the comparable periods in 2019. For the three and nine months ended September 30, 2020, the unrealized loss on risk management contracts amounted to $18.0 million and $21.4 million, respectively, compared to an unrealized loss of $1.3 million for the three months ended September 30, 2019 and an unrealized gain of $3.5 million for the nine months ended September 30, 2019.

In addition to the unrealized gains and losses on risk management contracts, the increase in net loss in the three and nine months ended September 30, 2020 compared to the same periods of 2019 is primarily attributable to the weakened commodity pricing environment driving decreased revenue.

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), was negative 2% in the third quarter of 2020 compared to 9% in the third quarter of 2019, although as mentioned above is distorted by unrealized gains and losses on the Company’s risk management contracts.

	Three Months to Sept. 30,2020 Three Months to Sept. 30,2019	Nine Months to Sept. 30,2020 Nine Months to Sept. 30,2019
Net income(loss)	$(16,934) $(64)	$(18,087) $ 8,407
Per basic and diluted share	$(0.14) $(0.00)	$(0.15) $ 0.07

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INVESTMENT AND FINANCING

Financial Resources and Liquidity

As at September 30, 2020, the Company had an extendible revolving credit facility in the amount of $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 28, 2021, 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. 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 September 30, 2020, debt including working capital deficiency amounted to $138 million. Bank debt including outstanding letters of credit represented approximately 75% utilization of the available credit facility.

As at September 30, 2020, the Company had issued letters of credit in the amount of $13.4 million (December 31, 2019 - $10.0 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 third quarter of 2020, the Company incurred capital expenditures of $14.2 million compared to $32.8 million in the third quarter of 2019.

In the first nine months of 2020, the Company incurred capital expenditures of $43.1 million (first nine months of 2019 - $72.9 million) primarily related to costs incurred for completion and start-up of the Nig Creek Gas Plant ($12.2 million), drilling two horizontal wells (1.0 net) at Fireweed and four horizontal wells (4.0 net) at Nig Creek, completing one well (0.5 net) at Fireweed, and completion, tie-in and equipping activities on three wells (3.0 net) at Umbach.

	Three Months to	Three Months to	Nine Months to	Nine Months to
	Sept. 30,2020	Sept. 30,2019	Sept. 30,2020	Sept. 30,2019
Land and seismic	$ 212	$ 250	$ 546	$ 1,785
Drilling	8,518	3,123	12,521	14,431
Completions	1,618	4,529	11,584	12,483
Facilities	2,018	22,420	14,987	40,287
Equipping and pipelines	1,541	3,585	3,009	4,914
Recompletions and workovers	310	6	395	55
Propertyacquisition and administrative assets	2	11	46	58
Total field capital expenditures	$ 14,219	$ 33,924	$ 43,088	$ 74,013
Proceeds on disposition of undeveloped land	-	(1,083)	-	(1,083)
Total capital expenditures	$ 14,219	$ 32,841	$ 43,088	$ 72,930

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Net capital investment was allocated as follows:

	Three Months to	Three Months to	Nine Months to	Nine Months to
	Sept. 30,2020	Sept. 30,2019	Sept. 30,2020	Sept. 30,2019
Exploration and evaluation	$ 212	$ (819)	$ 546	$ 716
Propertyand equipment	14,007	33,660	42,542	72,214
Total capital expenditures	$ 14,219	$ 32,841	$ 43,088	$ 72,930

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 September 30, 2020 corresponds to the Company’s limited field program.

Decommissioning Liability

The Company’s decommissioning liability of $32.3 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 September 30, 2020 was $38.8 million (December 31, 2019 - $38.3 million), with $1.6 million expected to be incurred in the next 12 months. The liability for currently inactive wells and facilities is approximately $10 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 $4.3 million over five years. In addition, as at the date of this report, the Company has transportation and processing commitments valued at a total of approximately $393 million.

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QUARTERLY RESULTS

Summarized information by quarter for the two years ended September 30, 2020 appears below.

Summarized information by quarter for the two years ended September 30, 2020 appears below.	Summarized information by quarter for the two years ended September 30, 2020 appears below.	Summarized information by quarter for the two years ended September 30, 2020 appears below.	Summarized information by quarter for the two years ended September 30, 2020 appears below.
2020 2019 2018
($000s unless otherwise stated)	Q3 Q2 Q1	Q4 Q3 Q2 Q1	Q4
Revenue from product sales Funds flow Per share – basic and diluted ($) Net income (loss) Per share – basic and diluted ($) Net capital expenditures Average daily production (Boe) Debt including working capital deficiency(1)	30,010 30,191 41,923 6,681 10,904 16,889 0.05 0.09 0.14 (16,934) (11,665) 10,512 (0.14) (0.10) 0.09 14,219 2,394 26,475 19,027 23,935 23,946 137,983 130,317 138,632	48,671 31,417 37,568 55,766 18,469 11,973 12,590 16,517 0.15 0.10 0.10 0.14 2,906 (64) 7,864 607 0.02 (0.00) 0.06 0.00 23,913 32,841 23,145 16,944 22,375 18,596 19,923 19,823 128,901 123,342 102,268 91,585	74,799 30,941 0.25 26,810 0.22 37,100 22,432 91,020

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

LIMITATIONS

Forward-Looking Statements – Certain forward-looking information and statements are set forth in this document, including management’s assessment of Storm’s future plans and operations specifically in relation to 2020 and 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. 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. 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 2020 and 2021, production volumes by commodity and production declines;

• capital investment intended to be approximately equal to funds flow in 2020 and less than funds flow in 2021;

• • planned capital expenditures in 2020 totaling $58 million and $85 to $90 million in 2021, timing, allocations to specific areas, and the availability of financial resources to fund which includes cash and cash equivalents, funds flow, and availability of committed credit facilities;

• future capital expenditures and their allocation to specific activities or periods, particularly with respect to estimated capital investment required to achieve forecasted production levels and number of wells to be drilled and completed as part of the 2020 and 2021 capital programs;

• the expected improvement in the Company’s NGL price in 2020 and that it will be approximately 15% to 20% of WTI in Canadian dollar terms;

• the near-term growth plan for 2020 and 2021 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;

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

• estimates of ultimate recovery from wells including management’s references to type curves; and

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

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, interest rates and currency exchange;

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

• a global public health crisis including the recent outbreak of the novel coronavirus (COVID-19) which causes volatility and disruptions in the supply, demand and pricing for natural gas, 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 for exploration and development activities and projects;

• successful and timely implementation of capital expenditures;

• risks associated with the development and execution of major projects;

• risk that projects and opportunities intended to grow funds flow and/or reduce costs may not achieve the expected results in the time anticipated or at all;

• access to third-party pipelines and facilities and access to sales markets;

• volatility of commodity prices and the related effects of changing price differentials;

• the Company’s ability to operate and run its facilities to meet forecast production;

• the output of newly commissioned facilities which may be difficult to accurately predict at an early stage;

• operational risks and uncertainties associated with oil and gas activities including unexpected formations or pressures, 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 production, royalty, transportation, general and administrative, and finance;

• ability to finance planned activities including infrastructure expansions which are required to meet future growth targets;

• 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 taxes, fees, royalties, duties and government-imposed compliance costs;

• changes to laws and government policies including environmental (and climate change), royalty, and tax laws and policies;

• 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;

• a major outage or environmental incident or unexpected event such as fires (including forest fires) 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 (including the credit facility);

• the risk that competing business objectives may exceed Storm’s capacity to adapt and implement change;

• • 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 closing an asset or property acquisition or disposition and the failure to realize anticipated benefits from any transaction;

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

• the accuracy of estimating reserves and future production and the future value of reserves;

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

• maintaining debt levels at a reasonable multiple of funds flow;

• risk with First Nations land claims and consultation requirements;

• risk that the Company may be subject to litigation;

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• the accuracy of cost estimates, some of which are provided at an early stage and before detailed engineering has been completed;

• risk associated with partner or joint venture arrangements to which the Company is a party;

• 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.

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 Deficiency

Debt including working capital deficiency 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.

($000s unless otherwise stated)	As at Sept. 30, 2020	As at Sept. 30, 2019	As at Sept. 30, 2018
Accounts receivable	7,455	14,514	15,100
Prepaids and deposits	821	577	845
Less: Accountspayable and accrued liabilities	(17,691)	(30,969)	(21,848)
Working capital deficiency (surplus)	9,415	15,878	5,903
Bank indebtedness	128,568	107,464	78,745
Debt includingworkingcapital deficiency	137,983	123,342	84,648

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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) as presented in the following table.

	Twelve Months Ended	Twelve Months Ended
($000s unless otherwise stated)	September 30, 2020	September 30, 2019
Average debt including working capital deficiency(1)	130,663	103,995
Average shareholders’ equity(1)	411,577	399,215
Average capital employed	542,240	503,210
Funds flow	52,943	72,021
Interest and finance costs	6,603	4,571
Funds flow plus interest and finance costs	59,546	76,592
CROCE	11%	15%

(1) The average debt including working capital deficiency 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) as presented in the following table.

presented in the following table.
	Twelve Months Ended	Twelve Months Ended
($000s unless otherwise stated)	September 30, 2020	September 30, 2019
Average debt including working capital deficiency(1)	130,663	103,995
Average shareholders’ equity(1)	411,577	399,215
Average capital employed	542,240	503,210
Net income (loss)	(15,181)	35,217
Interest and finance costs	6,603	4,571
Deferred income tax expense	(3,845)	7,887
	(12,423)	47,675
ROCE	(2%)	9%

(1) The average debt including working capital deficiency 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 30, 2020 for the year ended December 31, 2019 under the heading “Risk Factors” and in Storm’s MD&A for the period ended December 31, 2019 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

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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 U.S. 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.

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 oil and 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 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.

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 oil and natural gas supply and demand and recent events including actions taken by OPEC, Russia’s recent 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, curtailment of production of crude oil by the Government of Alberta, the outbreak of COVID19 and the price war between Saudi Arabia and Russia 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 oil infrastructure in 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 oil and natural gas companies and a decrease in confidence in the future of the 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 oil and natural gas industry has led to additional downward pressure on oil and natural gas prices which has further reduced confidence in the 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. In December 2019, COVID-19 was reported to have surfaced in Wuhan, China; on January 30, 2020, the WHO declared the outbreak a global health emergency; and on March 11, 2020 the WHO declared the outbreak of COVID-19 a global pandemic. In China, reactions to the spread of COVID-19 have led to, among other things, significant restrictions on travel within China, temporary business closures, quarantines and a general reduction in consumer activity. The outbreak has spread throughout Canada, the United States, Europe and the Middle East with cases of COVID-19 increasing around the world. The spread of COVID-19 has led companies and various jurisdictions to impose restrictions such as quarantines, business closures and domestic and international travel restrictions. The duration of the business disruptions internationally and related financial effect cannot be reasonably estimated at this time. Similarly, the Company cannot estimate whether or to what extent this pandemic and the potential financial effect may extend to countries outside of those currently affected.

Such public health crises can result in volatility and disruptions in the supply, demand and pricing for 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 have significantly weakened 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. At this point, the extent to which COVID-19 may affect the

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Company is uncertain; however, it is possible that COVID-19 may have a material adverse effect on the Company’s business, results of operations and financial condition.

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 September 30, 2020 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	Q3	Q2	Q1	Q4	Q3	Q2	Q1	Q4
per-share amounts		2020	2020	2020	2019	2019	2019	2019	2018
FINANCIAL
Revenue fromproduct sales(1)		30,010	30,191	41,923	48,671	31,417	37,568	55,766	74,799
Funds flow		6,681	10,904	16,889	18,469	11,973	12,590	16,517	30,941
Per share - basic and diluted ($)		0.05	0.09	0.14	0.15	0.10	0.10	0.14	0.25
Net income (loss)		(16,934)	(11,665)	10,512	2,906	(64)	7,864	607	26,810
Per share - basic and diluted ($)		(0.14)	(0.10)	0.09	0.02	(0.00)	0.06	0.00	0.22
Cash return on capital employed (“CROCE”)(2)		11%	12%	12%	12%	15%	18%	20%	21%
Return on capital employed (“ROCE”)(2)		(2%)	2%	7%	4%	9%	11%	8%	10%
Capital expenditures		14,219	2,394	26,475	23,913	32,841	23,145	16,944	37,100
Debt including working capital deficiency(2)(3)		137,983	130,317	138,632	128,901	123,342	102,268	91,585	91,020
Common shares (000s)
Weighted	average - basic	121,557	121,557	121,557	121,557	121,557	121,557	121,557	121,557
Weighted	average - diluted	121,557	121,557	121,557	121,557	121,557	121,557	121,853	121,649
Outstanding end of period - basic		121,557	121,557	121,557	121,557	121,557	121,557	121,557	121,557
OPERATIONS
(Cdn$ per Boe)
Revenue from product sales(1)		17.14	13.86	19.24	23.64	18.36	20.72	31.26	36.24
Transportation costs		(6.43)	(5.50)	(4.97)	(5.20)	(5.83)	(5.96)	(5.72)	(5.57)
Revenue net	of transportation	10.71	8.36	14.27	18.44	12.53	14.76	25.54	30.67
Royalties		(0.77)	(0.44)	(0.97)	(1.59)	0.19	(0.32)	(2.61)	(0.58)
Production costs		(4.84)	(4.50)	(5.17)	(5.67)	(5.88)	(5.89)	(6.09)	(5.46)
Field operating netback(2)		5.10	3.42	8.13	11.18	6.84	8.55	16.84	24.63
Realized gain (loss) on risk management
contracts		0.51	2.99	1.26	(0.80)	1.64	(0.22)	(5.38)	(8.65)
General and	administrative	(0.72)	(0.72)	(0.86)	(0.70)	(0.79)	(0.68)	(1.60)	(0.55)
Interest and finance costs		(1.08)	(0.68)	(0.74)	(0.71)	(0.69)	(0.71)	(0.61)	(0.45)
Decommissioning expenditures		-	(0.01)	(0.04)	-	-	-	-	-
Funds flow per Boe		3.81	5.00	7.75	8.97	7.00	6.94	9.25	14.98
Barrels of oil	equivalentper day (6:1)	19,027	23,935	23,946	22,375	18,596	19,923	19,823	22,432
Natural gas production
Thousand cubic feet per day		91,526	114,772	115,957	108,679	91,053	97,510	96,537	109,520
Price (Cdn$ per Mcf)(1)		2.47	2.23	2.54	3.28	2.42	2.64	4.49	5.56
Condensate	production
Barrels per day		1,637	2,305	2,623	2,416	1,856	2,081	2,199	2,453
Price (Cdn$ per barrel)(1)		46.79	25.92	60.66	66.56	63.45	71.12	62.77	58.74
NGL production
Barrels per day		2,136	2,501	1,998	1,846	1,564	1,591	1,534	1,726
Price (Cdn$ per barrel)(1)		10.95	6.23	3.27	6.11	2.29	4.87	31.43	35.09
Wells drilled	(net)	4.0	-	1.0	-	1.0	-	5.0	4.0
Wells completed (net)		-	-	3.5	-	5.0	-	-	2.5

(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.

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1)Office lease commitment includes the operating cost component of the office lease cost 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 Bbls Bbls/d Bcf Boe Boe/d Bopd Btu Cdn$ CGU DPIIP GJ GJ/d kPa LNG	Alliance Transfer Point Barrels of oil or natural gas liquids Barrels per day Billions of cubic feet Barrels of oil equivalent Barrels of oil equivalent per day Barrels of oil per day British thermal unit Canadian dollar Cash generating unit Discovered Petroleum Initially in Place Gigajoules Gigajoules per day Kilopascal Liquefied natural gas	Mbbl Mboe Mcf Mcf/d Mmbtu Mmbtu/d Mmcf Mmcf/d NGL NYMEX OPEC PDP TSX US US$ WTI	Thousands of barrels Thousands of barrels of oil equivalent Thousands of cubic feet Thousands of cubic feet per day Millions of British Thermal Units Millions of British Thermal Units per day Millions of cubic feet Millions of cubic feet per day Natural gas liquids New York Mercantile Exchange Organization of Petroleum Exporting Countries Proved developed producing (reserves) Toronto Stock Exchange United States United States dollar 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