Storm Resources Ltd. — Annual Report 2020

Mar 4, 2021

ANNUAL GENERAL MEETING

Given the ongoing uncertainty with respect to the COVID-19 pandemic, it is anticipated that the Annual General Meeting of shareholders will be held solely by means of remote communication via webcast and teleconference. However, in the event that circumstances change leading to relaxation of government restrictions, Storm will endeavor to arrange an inperson meeting. Updates will be posted on the Company's website at www.stormresourcesltd.com.

The Annual General Meeting is scheduled for 3:30 pm Calgary time on Thursday, May 13, 2021.

The ZOOM meeting information provided below is correct at time of printing; however, it is subject to change. ATTENDEES ARE ADVISED TO CHECK THE CORPORATION'S WEBSITE ONE WEEK PRIOR TO THE MEETING DATE FOR THE MOST CURRENT INFORMATION.

Webcast: https://us02web.zoom.us/j/89465204066

Teleconference: 1-855-703-8985 (Canada Toll Free) 1-888-475-4499 (U.S. Toll Free) Meeting ID 894 6520 4066

Highlights

Thousands of Cdn$, except volumetric andper-share amounts	Three Months toDec. 31, 2020	Three Months toDec. 31, 2019	Year EndedDec. 31, 2020	Year EndedDec. 31, 2019
FINANCIAL
Revenue from product sales(1)	52,941	48,671	155,065	173,422
Funds flow	22,350	18,469	56,824	59,549
Per share - basic and diluted ($)	0.18	0.15	0.47	0.49
Net income (loss)	17,873	2,906	(214)	11,313
Per share - basic and diluted ($)	0.15	0.02	(0.00)	0.09
Cash return on capital employed ("CROCE")(2)	12%	12%	12%	12%
Return on capital employed ("ROCE")(2)(4)	2%	4%	2%	4%
Capital expenditures	16,163	23,913	59,251	96,843
Debt including working capital deficiency/surplus(2)(3)	131,705	128,901	131,705	128,901
Common shares (000s)
Weighted average - basic	121,581	121,557	121,563	121,557
Weighted average - diluted	122,536	121,557	121,563	121,557
Outstanding end of period - basic	121,689	121,557	121,689	121,557
OPERATIONS
(Cdn$ per Boe)
Revenue from product sales(1)	22.15	23.64	18.25	23.54
Transportation costs	(4.81)	(5.20)	(5.36)	(5.66)
Revenue net of transportation	17.34	18.44	12.89	17.88
Royalties	(0.92)	(1.59)	(0.78)	(1.11)
Production costs	(4.13)	(5.67)	(4.64)	(5.87)
Field operating netback(2)Realized gain (loss) on risk management	12.29	11.18	7.47	10.90
contracts	(1.09)	(0.80)	0.89	(1.20)
General and administrative	(0.67)	(0.70)	(0.74)	(0.93)
Interest and finance costs	(0.96)	(0.71)	(0.85)	(0.68)
Decommissioning expenditures	(0.22)	-	(0.08)	-
Funds flow per Boe	9.35	8.97	6.69	8.09
Barrels of oil equivalent per day (6:1)	25,985	22,375	23,219	20,182
Natural gas production
Thousand cubic feet per dayPrice (Cdn$ per Mcf)(1)	124,9273.21	108,6793.28	111,7762.64	98,4583.21
Condensate production
Barrels per day	2,502	2,416	2,265	2,138
Price (Cdn$ per barrel)(1)	52.04	66.56	46.96	66.03
NGL production
Barrels per day	2,662	1,846	2,325	1,634
Price (Cdn$ per barrel)(1)	16.41	6.11	9.62	10.75
Wells drilled (net)	3.0	-	8.0	6.0
Wells completed (net)	4.0	-	7.5	5.0
Wells started production (net)	4.0	4.0	7.0	7.0

(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 38 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 $6.5 million for the year ended December 31, 2020 (December 31, 2019 – unrealized gain of $1.5 million).

PRESIDENT'S MESSAGE

2020 FOURTH QUARTER HIGHLIGHTS

Production benefitted from the start-up of four wells at Nig Creek in late October and cost structure continues to improve. Production costs decreased with increased volumes processed at the 100% working interest Nig Creek Gas Plant and transportation costs decreased with a higher proportion of natural gas sales into Western Canadian markets where pipeline tariffs are lower.

• Production was 25,985 Boe per day, a 37% increase from the previous quarter and a 16% increase year over year. This was consistent with guidance of 25,000 to 27,000 Boe per day.
• Liquids production (condensate plus NGL) totaled 5,164 barrels per day which was 20% of total production and 30% of total revenue. NGL production increased 44% from last year largely as a result of higher recoveries realized at the Nig Creek Gas Plant.
• At Nig Creek, sales from the gas plant averaged 9,930 Boe per day (27% increase from the previous quarter) with a production cost of $1.30 per Boe. Four new wells (4.0 net) in the upper Montney started producing in late October with the IP120 averaging 9.4 Mmcf raw per day which is 18% higher than earlier wells.
• Revenue net of transportation was $17.34 per Boe, a 6% decline from last year mainly as a result of a lower condensate price caused by the decline in the WTI crude oil price. The lower natural gas price was offset by a reduction in the transportation cost per Boe as less natural gas was sold into US markets where pipeline tariffs are higher.
• Production, general and administrative, and interest and finance costs totaled $5.76 per Boe, a year-over-year reduction of 19%. This was mainly driven by the start-up of the Nig Creek Gas Plant in February 2020 which reduced third-party processing fees and resulted in production costs per Boe declining by 27%.
• The realized hedging loss was $2.6 million, larger than the loss of $1.6 million in the previous year as a result of the rapid recovery in commodity prices in the second half of 2020.
• Funds flow was $22.4 million, or $0.18 per share, an increase of 21% from last year and the highest quarterly funds flow since the fourth quarter of 2018. This was largely the result of higher production given that lower production costs per Boe offset the decline in revenue net of transportation per Boe.
• Net income was $17.9 million and benefitted from an unrealized (non-cash) hedging gain of $14.9 million which represents the change in the value of future hedging contracts from the previous quarter.
• Capital investment was $16.2 million (versus guidance for $15 million) with the majority, or $12.5 million, directed to drilling three horizontal wells at Umbach and finishing the completions on four wells at Nig Creek.
• Total debt including working capital deficiency was $132 million which was 1.5X annualized fourth quarter funds flow. Compared to the previous quarter, this was a reduction of $6 million.
• The current commodity price hedge position protects revenue on approximately 44% of forecast production for 2021. At year end, the financial liability for future hedging contracts was $8 million.

2020 YEAR-END HIGHLIGHTS

As planned, capital investment during the year was approximately equal to funds flow which resulted in year-overyear production growth of 15% and a material improvement in the cost structure.

• Production averaged 23,219 Boe per day, a 15% increase from the previous year although this ended up being below initial guidance provided in November 2019 (24,000 to 26,000 Boe per day) as a result of reducing capital investment in May 2020 in response to lower commodity prices.
• The realized natural gas price at $2.64 per Mcf was higher than Western Canadian pricing (AECO daily index $2.11 per GJ and Station 2 $2.07 per GJ) as a result of diversified sales with 62% of sales into US markets.
• During 2020, seven horizontal wells started production and contributed approximately 2,850 Boe per day to average annual production and 7,160 Boe per day to fourth quarter production. Based on the fourth quarter addition, the implied corporate decline rate from Q4/19 to Q4/20 was 16%.
• Production, general and administrative, and interest and finance costs were $6.23 per Boe, a 17% decrease from the previous year which was mainly from the start-up of the Nig Creek Gas Plant which reduced production costs to $4.64 per Boe from $5.87 per Boe in 2019.
• The realized hedging gain was $8 million, a reversal from the previous year's loss of $9 million mainly as a result of gains realized from WTI crude oil price hedges.
• Funds flow was $57 million ($6.69 per Boe), a decline of 5% from the previous year with 15% production growth being more than offset by a large 22% reduction in revenue per Boe caused by lower condensate and natural gas prices.
• Net income was effectively nil ($0.00 per share) as compared to $11 million in the previous year with the decrease caused by a large decline in revenue and a reversal in the unrealized (non-cash) hedging gain or loss from a gain of $2 million in 2019 to a loss of $7 million in 2020.
• Capital investment was $59 million which included $12 million to complete the Nig Creek Gas Plant and $37 million to drill nine wells (8.0 net) and complete eight wells (7.5 net).
• Drilling plus completion costs at Umbach and Nig Creek averaged $4.5 million per well, a reduction of 18% from last year mainly as a result of both lower service costs and modifications to the wellbore design to increase pumping rates during fracture stimulation (well length was unchanged).
• Return on capital employed (ROCE) was 2% and cash return on capital employed (CROCE) was 12%. ROCE includes the effect of non-cash hedging gains or losses which can make it less meaningful as a way of measuring return on capital.
• Carbon taxes paid to the BC government which are included in production costs, totaled $5.6 million (direct and indirect), a decrease of $0.1 million from 2019.
• Fugitive emissions are estimated to total 2,187 tonnes CO2e from all of Storm's facilities and well sites based on the first survey that was completed in mid-2020 as part of complying with the BC Greenhouse Gas Industrial Reporting and Control Act which requires an independent party to determine emissions which are then audited/certified by an another independent party. This is approximately 1% of Storm's total direct and indirect GHG emissions in 2019. Low fugitive emissions are the result of all well sites being equipped with solar panels to operate controllers while Storm's facilities rely on compressed air to operate controllers with overhead vapors captured from all storage tanks. More details are available in the Environmental Performance section on Storm's website (under the Corporate Responsibility tab).

RESERVE EVALUATION HIGHLIGHTS

Increases in all reserves categories in 2020 were largely the result of step-out wells drilled and completed during the year, start-up of the Nig Creek Gas Plant, and positive technical revisions for well performance exceeding forecasts.

Reserves

	YOY Increase	2020	2019	2018
Proved Developed Producing ("PDP") (MBoe)	+13%	49,134	43,322	42,204
Total Proved ("1P") (Mboe)	+3%	160,496	156,118	149,905
Total Proved plus Probable ("2P") (MBoe)	+2%	199,077	195,483	182,370
PDP as % of 2P		25%	22%	23%
1P as a % of 2P		81%	80%	82%
Reserve Life Index	PDP	5.2	5.3	5.2
using fourth quarter production (years)	1P	16.9	19.1	18.3
	2P	21.0	23.9	22.3

All-in Finding, Development & Acquisition ("FD&A") Cost Including Change in Future Development Capital ("FDC")

	2020	2019	2018	3-Year Total
PDP ($/Boe)	$4.14	$11.43	$5.24	$6.19
1P ($/Boe)	$4.16	$3.90	$6.01	$5.41
2P ($/Boe)	$5.07	$3.16	$5.10	$4.68

Recycle Ratio Using All-in FD&A Cost

	2020	2019	2018	3-Year Total
Funds Flow (000s)	$56,824	$59,549	$100,092	$216,465
Funds Flow Netback ($/Boe)	$6.69	$8.09	$13.34	$9.27
PDP Recycle	1.6	0.7	2.5	1.5
1P Recycle	1.6	2.1	2.2	1.7
2P Recycle	1.3	2.6	2.6	2.0

• Three year total PDP FD&A at $6.19 per Boe includes $84 million invested in 2018 to 2020 for the Nig Creek Gas Plant project and is representative of full-cycle costs including infrastructure.

• PDP additions totaled 14,295 Mboe and largely came from seven new step-out wells plus the start-up of the Nig Creek Gas Plant.

• Reserve additions replaced 169% of annual production for PDP, 152% for 1P and 142% for 2P.
• On a per-share basis, PDP reserves increased by 13%, 1P increased by 3% and 2P increased by 2%.
• Material future upside remains in the Montney given that PDP and 2P reserves are recognized on 18.5 and 46.7 net sections which is approximately 11% and 27%, respectively, of the total Montney land position.

OPERATIONS REVIEW

Umbach, Nig Creek and Fireweed Areas of 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 (170 net sections) with 87 horizontal wells (81.9 net) drilled to the end of the fourth quarter.

Field activity in the fourth quarter included drilling three wells (3.0 net) at Umbach and finishing the completions and pipeline connections for four wells (4.0 net) at Nig Creek.

First quarter 2021 activity at Umbach will include completing and pipeline connecting three wells (3.0 net) and, at Fireweed, will include drilling three wells (1.5 net) plus constructing 19 kilometres of large diameter gathering and sales pipelines.

At the end of the fourth quarter, there were seven Montney horizontal wells (5.5 net) that had not started producing which included four wells (4.0 net) at Umbach and three wells (1.5 net) at Fireweed.

At Umbach (average 90% working interest), produced raw natural gas contains 1.2% H2S with field compression capacity totaling 150 Mmcf raw per day. Firm processing commitments total 80 Mmcf raw per day (65 Mmcf per day at McMahon Gas Plant and 15 Mmcf per day at Stoddart Gas Plant). Inlet volumes in the fourth quarter averaged 88 Mmcf per day. Activity in 2021 is expected to maintain production and includes drilling the remaining three wells (3.0 net) on a six-well pad and completing six wells (6.0 net) with three completions in Q1 and three completions in Q4.

At Nig Creek (100% working interest), produced raw natural gas contains up to 0.5% H2S and is directed to the 100% working interest sour gas plant that started up in February 2020. Gas plant inlet volumes in the fourth quarter averaged 50 Mmcf per day, sales were 9,930 Boe per day (46.2 Mmcf per day sales with total liquids of 48 barrels per Mmcf sales), and the production cost was $1.30 per Boe. Capacity of the gas plant is estimated to be 70 Mmcf raw per day at the current average H2S of 0.3% (versus design capacity of 50 Mmcf raw per day at 0.5% H2S). Future drilling is expected to include three to four wells each year to keep the gas plant full. Activity in 2021 will be focused on increasing volumes processed at the gas plant to 70 Mmcf raw per day which will come from adding inlet compression (expected to increase rates from existing wells by 10% to 30%) and from drilling and completing three to four wells (3.0 to 4.0 net) in the lower Montney where the H2S is below 0.1%.

Recent wells at Nig Creek continue to exceed expectations:

• The first well in the lower Montney started producing in December 2019 with the IP365 being 760 Boe per day sales with 33% liquids (180 barrels per day of condensate plus 70 barrels per day of NGL). The half-cycle cost to drill, complete and tie-in the well was $5.2 million which was paid out in approximately 13 months (cumulative field operating netback was $5.1 million to December 2020);
• The four most recent wells in the upper Montney started producing in late October 2020 with the average IP120 being 9.4 Mmcf raw per day which is an average of 1,940 Boe per day sales with 25% liquids (250 barrels per day of condensate plus 230 barrels per day of NGL).

At Fireweed (50% working interest), activity was restarted in the fourth quarter of 2020 after being deferred following the collapse in the WTI crude oil price in April 2020. Based on production history from offsetting horizontal wells, first year average field condensate-gas ratios are expected to be 30 to 70 barrels per Mmcf raw which is 100% to 400% higher than at Umbach and Nig Creek. There are currently three standing wells (1.5 net) with two completed wells (1.0 net). Activity in 2021 will include constructing a 50 Mmcf raw per day field compression facility with 19 kilometres of gathering and sales pipelines (50% working interest), drilling five wells (2.5 net), and completing three wells (1.5 net). First production is expected in the fourth quarter of 2021 from five wells (2.5 net).

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.

	2021	2022
Natural Gas Hedges
% Current Nat Gas Production(1)	48%	18%
	9,200 Mcf/d(2)	5,700 Mcf/d(2)
Collars	Floor Cdn$3.44 per Mcf(3)	Floor Cdn$3.77 per Mcf(3)
	Ceiling Cdn$4.10 per Mcf(3)	Ceiling Cdn$4.71 per Mcf(3)
	51,200 Mcf/d(2)	16,500 Mcf/d(2)
Fixed Price	Cdn$3.17 per Mcf(3)	Cdn$3.41 per Mcf(3)
Crude Oil Hedges
% Current Liquids Production(1)	41%	11%
	1,100 Bpd	400 Bpd
Collars	Floor WTI Cdn$52.44 per barrel(3)	Floor WTI Cdn$58.11 per barrel(3)
	Ceiling WTI Cdn$62.56 per barrel(3)	Ceiling WTI Cdn$68.79 per barrel(3)
	800 Bpd	150 Bpd
	WTI Cdn$53.41 per barrel	WTI Cdn$65.32 per barrel(3)
Fixed Price	225 Bpd Propane
	Cdn$42.84 per barrel(3)

(1) Using Q4 2020 actual production.

(2) Using corporate average heat content 1.23 GJ per Mcf and 1.17 Mmbtu per Mcf.

(3) Hedges in US$ are converted using an exchange rate of Cdn$1.27 per US$1.

OUTLOOK

Production in the first quarter of 2021 is forecast to average 25,000 to 27,000 Boe per day while capital investment is estimated to be $25 million (approximately 45% allocated to the Fireweed area). Capital investment includes $4 million for equipment deposits related to the Fireweed facility and for inlet compression at the Nig Creek Gas Plant.

First quarter natural gas prices will benefit from elevated spot prices that were realized in February. Approximately 60% of corporate sales are at the daily index or spot price which included 26 Mmcf per day (30,000 Mmbtu per day) of sales at Chicago in February at an average of approximately US$14 per Mmbtu.

Updated guidance for 2021 is provided below. Forecast pricing is updated to reflect estimated prices to the end of the first quarter with prices for the remainder of the year being unchanged from previous guidance except for the WTI price which was increased to US$50 per barrel from US$40.

2021 Guidance

	Initial	Current
	November 10, 2020	March 2, 2021
Cdn$/US$ exchange rate	0.76	0.79
Chicago daily natural gas - US$/Mmbtu(1)	$2.65	$3.50
AECO daily natural gas - Cdn$/GJ(1)	$2.50	$2.60
BC Station 2 daily natural gas - Cdn$/GJ	$2.50	$2.55
WTI - US$/Bbl	$40.00	$51.00
Edmonton condensate diff - US$/Bbl	($3.00)	($2.25)
Est transportation cost - $/Boe	not provided	$4.50 - $4.75
Est revenue net of transport (excl hedges) - $/Boe	$17.00 - $18.00	$19.50 - $20.50
Est royalty rate (% revenue net transportation)	7% - 8%	8% - 9%
Est production cost - $/Boe	$4.00 - $4.50	$4.00 - $4.50
Est mid-point field operating netback - $/Boe(2)	$11.95	$14.05
Est realized hedging gains or (losses) - $ million	($8.0 - $10.0)	($10.0 - $12.0)
Est cash G&A - $ million	$6.0 - $7.0	$6.0 - $7.0
Est interest expense - $ million	$7.0 - $8.0	$6.0 - $7.0
Est capital investment (excluding A&D) - $ million	$85.0 - $90.0	$85.0 - $90.0
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)	$90.0 - $99.0	$109.0 - $120.0
Horizontal wells drilled - gross	11 (9.0 net)	11 - 12 (8.5 - 9.5 net)
Horizontal wells completed - gross	11 (10.0 net)	11 - 12 (10.5 - 11.5 net)
Horizontal wells starting production - gross	13 (11.0 net)	14 - 15 (11.5 - 12.5 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	$40.00	$85.0 - $90.0	$90.0 - $99.0	26,000 - 28,000
Mar 2, 2021	$3.50	$2.55	$51.00	$85.0 - $90.0	$109.0 - $120.0	26,000 - 28,000

Total capital investment in 2021 is unchanged from previous guidance at $85 to $90 million with approximately 40% invested in the first half of the year. This is expected to increase average annual production by 16% (using mid-point of guidance) and will result in further reductions to the cost structure.

	Total
	Investment	Infrastructure	Net Wells	Net Wells	Net Wells
	($million)	($million)	Drilled	Completed	Starting Production
Fireweed	$30 - $35	$19	2.5	1.5	2.5
Nig Creek	$28	$7	3.0 - 4.0	3.0 - 4.0	3.0 - 4.0
Umbach	$27		3.0	6.0	6.0
Total	$85 - $90

Based on forecast production, natural gas sales into Canadian markets will increase from approximately 35% in 2020 to 54% in 2021. The sales split in 2021 is expected to be 46% at Chicago, 36% at BC Station 2, 11% at AECO and 7% at Alliance ATP. The natural gas marketing strategy will continue to be based on diversifying sales as much as possible to mitigate regional price differences caused by supply/demand imbalances that are difficult to predict in terms of timing and duration. Diversification also includes an approximate 50/50 split between sales at daily spot pricing and at monthly index pricing (price is set at the start of each month).

NGL prices net of transportation for 2021 are expected to show a modest increase to 20% to 25% of WTI Cdn$ from 18% in 2020. Although marketing deductions which reflect the transportation cost to sales hubs are expected to increase for the next contract year (April 2021 to March 2022), this is expected to be offset by higher propane and butane pricing.

Cost structure on a per-Boe basis is expected to show further improvement in 2021 as production costs decline with rising throughput at the Nig Creek Gas Plant where capacity is estimated to be approximately 70 Mmcf per day and the production cost is $1.30 per Boe. In addition, transportation costs will continue to decline as a higher proportion of natural gas production is sold into Western Canadian markets which have lower pipeline tariffs.

Development at Fireweed is progressing with activity in the first quarter including drilling three horizontal wells, constructing 19 kilometers of large diameter gathering and sales pipelines, and ordering major equipment for the facility. First production of approximately 2,500 Boe per day net is expected in the fourth quarter of 2021.

The focus continues to be on growing asset value and funds flow per share. Near term (2021 to 2022), this is expected to come from:

• 1. Filling the Nig Creek Gas Plant where the production cost is $1.30 per Boe and liquids recovery is higher; and
• 1. Development at Fireweed where condensate is expected to be a higher proportion of total production.

'Free cash flow' in 2021 is estimated to be approximately $80 million using the mid-point for estimated annual funds flow in guidance (based on estimated capital investment required to maintain production being $33 million to drill, complete and tie-in 6.0 net wells). This will be directed to development at Fireweed ($30 to $35 million), growth from Umbach and Nig Creek ($22 million to drill and complete three wells plus install inlet compression), with the remainder initially used to reduce debt which increases financial flexibility. As always, capital investment will remain flexible and may be adjusted up or down depending on commodity prices.

The considerable efforts of everyone at Storm are much appreciated, especially over the last year which was complicated by having to manage the impacts of the COVID-19 pandemic at work and in everyone's personal lives. In addition, the advice, guidance and, most of all, the support of the Board of Directors has been invaluable.

We look forward to reporting on our progress during 2021 which is currently benefitting from a 'tailwind' with improving commodity prices.

Respectfully,

Brian Lavergne, President and Chief Executive Officer

March 2, 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 gas to one barrel of oil. Mboe means 1,000 Boe.

Crude Oil and Natural Gas Metrics - Crude oil and natural gas metrics, including FD&A, recycle ratio, FDC, and reserves life index or RLI, do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics have been included herein to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods.

Initial Production Rates - References to initial production rates, 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 March 2, 2021 for the three months and year ended December 31, 2020.

RESERVES AT DECEMBER 31, 2020

Storm's year-end reserve evaluation effective December 31, 2020 was prepared by InSite Petroleum Consultants Ltd. ("InSite") in a report dated February 23, 2021. InSite has evaluated all of Storm's natural gas and NGL reserves. The InSite price forecast at December 31, 2020 was used to determine estimates of net present value ("NPV"). Storm's Reserves Committee, which is made up of independent and appropriately qualified directors, has reviewed and approved the evaluation prepared by InSite, and the report of the Reserves Committee has been accepted by the Company's Board of Directors.

Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without including any royalty interests) unless noted otherwise. All reserves information has been prepared in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). In addition to the information disclosed in this report, more detailed information will be included in Storm's Annual Information Form for the year ended December 31, 2020 (the "AIF").

Summary

• Proved developed producing reserves ("PDP") increased to 49,134 Mboe during 2020, a 13% increase over the 2019 year-end PDP reserves of 43,322 Mboe. Total proved reserves ("1P") increased to 160,496 Mboe, a 3% increase over 2019 year-end 1P reserves of 156,118 Mboe. Total proved plus probable reserves ("2P") increased to 199,077 Mboe, a 2% increase over 2019 year-end 2P reserves of 195,482 Mboe.

• Reserve additions in 2020 replaced 169% of production for PDP reserves, 152% for 1P reserves and 142% for 2P reserves.

• Technical revisions increased PDP reserves by 1,981 Mboe (5%), reduced 1P reserves by 2,214 Mboe (-1%) and reduced 2P reserves by 5,611 Mboe (-2.9%). PDP revisions are largely the result of well performance exceeding expectations while 1P and 2P revisions are largely from forecast NGL yields being reduced by 7% from last year.

• Breaking down 2P reserves by area, 69% is at Umbach, 28% is at Nig Creek and 3% is at Fireweed.

• The all-in finding, development and acquisition ("FD&A") cost(1) to add reserves was $4.14 per Boe for PDP, $4.16 per Boe for 1P and $5.07 per Boe for 2P.

• Future development costs ("FDC") were $637 million for 1P and $677 million for 2P and are fully financed from forecast cash flow within four years which complies with the Canadian Oil and Gas Evaluation ("COGE") Handbook. For comparison, FDC last year was $642 million for 1P and $675 million for 2P.

• FDC includes $107 million net on a 2P basis for future infrastructure expansion at Umbach (last year was $114 million net) with $87 million allocated to future infrastructure expansion at Nig Creek and Umbach, and $20 million net for construction of a Fireweed compressor station (Storm working interest 50%).

• The estimated cost to drill and complete a future Montney horizontal well at Umbach and Nig Creek is $5.1 million compared to $5.5 million used in 2019 (versus the actual cost of $4.5 million in 2020).

• Wells drilled in 2020 were assigned an average of 11 Bcf gross raw gas on a 2P basis.

• At Umbach, Nig Creek and Fireweed there are 94.1 net 2P future horizontal drills assigned an average of 7.8 Bcf gross raw gas (last year was 86.6 net 2P locations with 8.1 Bcf gross raw gas). The reduction in gross raw gas per undeveloped drill is a function of the additional locations (9.5 net) recognized in the lower Montney at Nig Creek and upper Montney locations at Fireweed where the proportion of NGL is higher.

• Future drilling locations total 94.1 net wells including 73.6 net wells at Umbach, 17.0 net at Nig Creek and 3.5 net at Fireweed. This represents approximately five years of activity at forecast commodity prices and complies with the Canadian Oil & Gas Evaluation ("COGE") Handbook.

• Future 2P drilling locations include 6.0 net wells in the lower Montney at Nig Creek and 3.5 net wells in the upper Montney at Fireweed. Previously no future drilling locations had been recognized in either area.

• At Umbach, Nig Creek and Fireweed, 2P reserves were recognized on 46.7 net sections (an increase of 2.7 net sections from last year), 1P on 45.2 net sections and PDP on 18.5 net sections. DPIIP averages 52 Bcf gross raw gas per section in the Montney (total net DPIIP 2.43 Tcf on 46.7 net sections). Forecast recovery of DPIIP totals 52% for 2P reserves.

• The full corporate decommissioning liability for all wells and facilities was included in this year's evaluation and totaled $38.5 million on an undiscounted basis. The decommissioning liability for inactive wells totaled $10.6 million on an undiscounted basis adjusted for inflation.

• The PDP NPV discounted at 10% increased by 9% to $424.6 million mainly as a result of the 13% increase in PDP reserves. Using this year's price forecast in last year's evaluation, the NPV discounted at 10% increased 15% year over year.

• (1) The all-in calculation reflects the result of Storm's entire capital investment program as it takes into account the effect of acquisitions, dispositions and revisions, as well as the change in FDC.

INFORMATION REGARDING DISCLOSURE ON OIL AND GAS RESERVES AND RESOURCES

All amounts are stated in Canadian dollars unless otherwise specified. Where applicable, natural gas has been converted to barrels of oil equivalent ("Boe") based on 6 Mcf:1 Boe. The Boe rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not recognize a value equivalent at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value. Production volumes and revenues are reported on a company gross basis, before deduction of Crown and other royalties, unless otherwise stated. Unless otherwise specified, all reserves volumes are based on "company gross reserves" using forecast prices and costs. The oil and gas reserves statement for the year ended December 31, 2020, which will include complete disclosure of oil and gas reserves and other information in accordance with NI 51-101, will be contained within the AIF which will be available on SEDAR.

References to estimates of oil and gas classified as DPIIP are not, and should not be confused with, oil and gas reserves.

Gross Company Interest Reserves as at December 31, 2020 (Before deduction of royalties payable, not including royalties receivable)

	Sales Gas(Mmcf)	NGL(Mbbls)	6:1 OilEquivalent(Mboe)
Proved producing	235,474	9,888	49,134
Proved non-producing	2,512	91	509
Total proved developed	237,986	9,979	49,643
Proved undeveloped	536,859	21,376	110,853
Total proved	774,845	31,355	160,496
Probable additional	184,797	7,782	38,582
Total proved plus probable	959,642	39,137	199,077

Numbers in this table may not add due to rounding.

Gross Company Reserve Reconciliation for 2020 (Gross company interest reserves before deduction of royalties payable)

				6:1 Oil Equivalent (Mboe)
	ProvedDevelopedProducing	TotalProved	Probable	Proved plusProbable
December 31, 2019 – opening balance	43,322	156,118	39,365	195,482
Acquisitions	-	-	-	-
Discoveries	-	-	-	-
Extensions	12,314	15,077	2,617	17,695
Dispositions	-	-	-	-
Technical revisions	1,981	(2,214)	(3,397)	(5,611)
Economic factors	-	(1)	(3)	(4)
Production	(8,484)	(8,484)	-	(8,484)
December 31, 2020 – closing balance	49,134	160,496	38,582	199,077

Numbers in this table may not add due to rounding.

Reserve Life Index ("RLI") Using Fourth Quarter Production

(Years)	2020	2019	2018
PDP	5.2	5.3	5.2
1P	16.9	19.1	18.3
2P	21.0	23.9	22.3

Future Development Costs ("FDC")

	Proved ($M)	Proved Plus Probable ($M)
2021	79,738	91,588
2022	88,052	91,290
2023	152,159	157,517
2024	162,789	162,789
2025	154,008	173,925
Total FDC - undiscounted	636,745	677,109
Total FDC - discounted at 10%	491,281	522,790
($million)	2020	20192018
1P FDC	$ 637	$ 642$ 686
2P FDC	$ 677	$ 675$ 707

Note: InSite escalates capital costs at 2% per year after 2020.

All-in Finding, Development and Acquisition Costs ("FD&A") (including acquisitions, dispositions and revisions)

Proved Developed Producing FD&A Cost (All-in)	2020	2019	2018	3 Year Total
Net capital investment (000s)	$59,251	$96,843	$84,763	$240,857
Total capital including change in FDC (000s)	$59,251	$96,843	$83,641	$239,735
Total reserve additions (Mboe)	14,296	8,469	15,967	38,732
All-in PDP FD&A cost (per Boe)	$4.14	$11.43	$5.24	$6.19
Total Proved FD&A Cost (All-in)	2020	2019	2018	3 Year Total
Net capital investment (000s)	$59,251	$96,843	$84,763	$240,857
Change in FDC (000s)	(5,724)	(43,992)	274,814	225,098
Total capital including change in FDC (000s)	$53,527	$52,851	$359,577	$465,955
Total reserve additions (Mboe)	12,862	13,563	59,780	86,205
All-in 1P FD&A cost (per Boe)	$4.16	$3.90	$6.01	$5.41
Total Proved Plus Probable FD&A Cost (All-in)	2020	2019	2018	3 Year Total
Net capital investment (000s)	$59,251	$96,843	$84,763	$240,857
Change in FDC (000s)	2,022	(32,089)	226,058	195,991
Total capital including change in FDC (000s)	$61,273	$64,754	$310,821	$436,848
Total reserve additions (Mboe)	12,078	20,464	60,899	93,441
All-in 2P FD&A cost (per Boe)	$5.07	$3.16	$5.10	$4.68

Finding and Development Costs ("F&D") (excluding acquisitions, dispositions and revisions)

Total Proved F&D Cost	2020	2019	2018	3 Year Total
Capital expenditures excluding acquisitions
and dispositions (000s)	$59,251	$96,843	$84,763	$240,857
Change in FDC (000s)	(5,724)	(43,992)	274,814	225,098
Total capital including change in FDC (000s)	$53,527	$52,851	$359,577	$465,955
Reserve additions excluding acquisitions, dispositions,
and revisions (Mboe)	15,077	12,582	43,347	71,007
1P F&D cost (per Boe)	$3.55	$4.20	$8.30	$6.56

Total Proved Plus Probable F&D Cost	2020	2019	2018	3 Year Total
Capital expenditures excluding acquisitions
and dispositions (000s)	$59,251	$96,843	$84,763	$240,857
Change in FDC (000s)	2,022	(32,089)	226,058	195,991
Total capital including change in FDC (000s)	$61,273	$64,754	$310,821	$436,848
Reserve additions excluding acquisitions, dispositions,
and revisions (Mboe)	17,695	21,235	39,608	78,538
2P F&D cost (per Boe)	$3.46	$3.05	$7.85	$5.56

Net Present Value Summary (before tax) as at December 31, 2020

Benchmark oil and NGL prices used are adjusted for quality of oil or NGL produced and for transportation costs. The calculated NPV include a deduction for estimated future well abandonment costs. The NPV disclosed does not represent fair market value of reserves.

		Discounted at	Discounted at	Discounted at	Discounted at
(000s)	Undiscounted	5%	10%	15%	20%
Proved producing	605,499	500,522	424,596	369,626	328,689
Proved non-producing	3,274	2,011	1,234	735	402
Total proved developed	608,773	502,533	425,830	370,361	329,091
Proved undeveloped	1,062,800	673,371	444,030	300,504	206,216
Total proved	1,671,573	1,175,904	869,860	670,866	535,307
Probable additional	586,211	314,231	187,609	121,789	84,236
Total proved plus probable	2,257,783	1,490,135	1,057,469	792,655	619,542

Numbers in this table may not add due to rounding.

Net Present Value Summary (after tax) as at December 31, 2020

Benchmark oil and NGL prices used are adjusted for quality of oil or NGL produced and for transportation costs. The calculated NPV each include a deduction for estimated future well abandonment costs. The NPV disclosed does not represent fair market value of reserves.

		Discounted at	Discounted at	Discounted at	Discounted at
(000s)	Undiscounted	5%	10%	15%	20%
Proved producing	567,508	479,585	411,915	361,509	323,293
Proved non-producing	2,355	1,433	851	471	214
Total proved developed	569,863	481,018	412,766	361,980	323,507
Proved undeveloped	786,430	487,236	311,724	202,596	131,492
Total proved	1,356,293	968,255	724,491	564,577	455,000
Probable additional	435,636	232,832	138,381	89,396	61,528
Total proved plus probable	1,791,929	1,201,086	862,872	653,973	516,528

Numbers in this table may not add due to rounding.

InSite Escalating Price Forecast as at December 31, 2020

	ExchangeRate(US$/Cdn$)	WTICrude Oil(US$/Bbl)	Condensate(Cdn$/Bbl)	Henry HubNatural Gas(US$/Mmbtu)	AECONatural Gas(Cdn$/Mmbtu)	BCStation 2(Cdn$/Mmbtu)
2021	0.77	48.00	60.87	2.85	2.80	2.75
2022	0.77	51.00	64.56	2.91	2.71	2.66
2023	0.77	54.00	68.81	2.97	2.62	2.57
2024	0.77	55.08	70.78	3.02	2.67	2.62
2025	0.77	56.18	71.51	3.08	2.73	2.68

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 months and year ended December 31, 2020. It should be read in conjunction with (i) the Company's audited consolidated financial statements for the years ended December 31, 2020 and 2019, (ii) each of the Company's unaudited condensed interim consolidated financial statements for the three months ended March 31, June 30 and September 30, 2020, and (iii) the press release issued by the Company on March 2, 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 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 March 2, 2021.

See discussion related to "Forward-Looking Statements", "Boe Presentation" and "Non-GAAP Measurements" on pages 36 to 38.

BASIS OF PRESENTATION

Financial data presented below have largely been derived from the Company's audited consolidated financial statements for the year ended December 31, 2020 and the unaudited interim consolidated financial information for the three months ended December 31, 2020 (the "financial statements"), prepared in accordance 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 years ended December 31, 2020 and 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 months and year ended December 31, 2019.

OPERATIONAL AND FINANCIAL RESULTS

Overview

What started out as a typical year for Storm quickly morphed into uncharted territory with the emergence of COVID-19 in January followed by a rapid escalation through the first week of March 2020 before officially being declared a global pandemic. For Storm, the transition to operating in a COVID-19 environment has been relatively seamless with limited effect on the Company's operations. Not only was 2020 marked by COVID-19 and low commodity prices but also by third-party outages which further affected Storm's production and funds flow, the most significant of which was a planned event in the third quarter of 2020 (28-day turnaround at the McMahon Gas Plant).

Despite these challenges, the resiliency of Storm's business model was apparent with key highlights for the year including commissioning of the Nig Creek Gas Plant in February 2020, achieving record production of approximately 26,000 Boe per day in the fourth quarter of 2020, and maintaining a strong balance sheet with capital investment matching funds flow and leaving debt levels largely flat year over year.

The focus for Storm in 2020 was on managing through low commodity prices brought on by an extended period of supply growth that was further exacerbated by demand destruction from the economic shut-downs associated with the COVID-19 pandemic. Moving past the challenges of the first nine months of the year, a four-well pad at Nig Creek was completed in October and on production late in October to capitalize on higher winter pricing. Capital expenditures in the fourth quarter were largely consistent with the previously announced guidance of $15 million.

Fiscal 2020 guidance was amended by the Company throughout the year as set out in the table below:

					Forecast
	Chicago	Station 2		Capital	Annual	Forecast Annual
	Daily	Daily	WTI	Investment	Funds Flow	Production
	(US$/Mmbtu)	(Cdn$/GJ)	(US$/Bbl)	($ million)	($ million)	(Boe/d)
Nov 12, 2019	$2.45	$1.60	$54.00	$75.0 - $90.0	not provided	24,000 - 26,000
Feb 27, 2020	$1.90	$1.65	$50.50	$75.0 - $85.0	$62.0 - $69.0	23,500 - 26,000
May 12, 2020	$2.05	$2.15	$30.50	$52.0 - $60.0	$59.0 - $66.0	23,500 - 26,000
Aug 13, 2020	$1.85	$1.95	$38.50	$52.0 - $60.0	$53.0 - $57.0	22,500 - 24,000
Nov 10, 2020	$1.90	$2.15	$38.50	$58.0	$55.0 - $57.0	23,000 - 23,500
Actual 2020 Results	$1.89	$2.07	$39.40	$59.3	$56.8	23,219

2020 Guidance History

In May 2020, capital expenditure guidance was reduced in response to the COVID-19 pandemic and the resulting drop in WTI prices, which in turn lowered production and funds flow guidance for the remainder of the year. Total production was within previously updated guidance of 23,000 to 23,500 Boe per day, while increasing 15% from 2019 levels. Storm's production increased to approximately 26,000 Boe per day in the fourth quarter of 2020 following the tie-in of the aforementioned four-well pad at Nig Creek and has averaged approximately 26,000 Boe per day to date in 2021 based on field estimates. As always, Storm continues to manage production in response to ongoing volatility in crude oil and natural gas prices, and in the context of firm transportation and processing commitments.

While demand for crude oil has improved and WTI prices have stabilized around the US$55.00 per barrel level, the economic situation remains highly volatile with a second wave of COVID-19 underway across the globe. As previously stated, predicting the extent to which the ongoing 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. 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 might need to be taken.

During the fourth quarter, 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 78% drawn at the end of the fourth quarter (including $13.7 million for outstanding letters of credit). With funds flow for 2021 expected to exceed capital expenditures, low maintenance capital, a balanced hedge portfolio, and unused credit capacity, Storm maintains adequate financial liquidity to manage through the ongoing volatility in commodity prices. The next annual review will take place prior to May 28, 2021.

Production and Revenue

Average Daily Production

	Three Months toDec. 31, 2020	Three Months toDec. 31, 2019	Quarter-Over-QuarterChange	Year EndedDec. 31, 2020	Year EndedDec. 31, 2019	Year-Over-YearChange
Natural gas (Mcf/d)	124,927	108,679	15%	111,776	98,458	14%
Condensate (Bbls/d)	2,502	2,416	4%	2,265	2,138	6%
NGL (Bbls/d)	2,662	1,846	44%	2,325	1,634	42%
Total (Boe/d)	25,985	22,375	16%	23,219	20,182	15%
Natural gas weighting	80%	81%		80%	81%
Condensate weighting	10%	11%		10%	11%
NGL weighting	10%	8%		10%	8%

Production for natural gas, condensate and NGL for the fourth quarter and year ended December 31, 2020 was higher than the comparable periods in 2019 primarily due to incremental production from new wells brought on production. Furthermore, the Nig Creek Gas Plant was commissioned in February 2020 leading to incremental production from higher NGL recovery and reduced gas shrinkage in 2020.

The Company started production from seven new 100% working interest horizontal wells in 2020.

Revenue from Product Sales(1)

	Three Months toDec. 31, 2020		Three Months toDec. 31, 2019		Year EndedDec. 31, 2020		Year EndedDec. 31, 2019
Natural gas	$	36,945	$	32,836	$	107,943	$115,488
Condensate		11,978		14,796		38,939	51,522
NGL		4,018		1,039		8,183	6,412
Total	$	52,941	$	48,671	$	155,065	$173,422
% of Total Revenue by Product Type
Natural gas		70%		67%		70%	67%
Condensate and NGL		30%		33%		30%	33%
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 fourth quarter of 2020 increased by 9% when compared to the fourth quarter of 2019 primarily as a result of a 16% increase in production volumes, partially offset by a 6% decrease in the Company's average realized prices. For the year ended December 31, 2020, revenue from product sales decreased by 11% year over year due to the Company's average realized price decreasing by 22%, partially offset by production volumes increasing by 15%.

Average Selling Prices(1)

	Three Months toDec. 31, 2020	Three Months toDec. 31, 2019	Year EndedDec. 31, 2020	Year EndedDec. 31, 2019
Natural gas – Mcf	$3.21	$3.28	$2.64	$	3.21
Condensate – Bbl	$52.04	$66.56	$46.96	$	66.03
NGL – Bbl	$16.41	$6.11	$9.62	$	10.75
Per Boe	$22.15	$23.64	$18.25	$	23.54

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

On a per-Boe basis, the Company's average realized price for the fourth quarter of 2020 decreased compared to the same period of 2019, with the decrease driven by lower condensate pricing, partially offset by higher NGL pricing. The decrease in condensate pricing is primarily due to a significant reduction in WTI benchmark pricing. The marginal decrease in realized natural gas pricing is primarily due to less volume sold at Sumas as well as lower Sumas prices, offset by higher sales volumes and pricing at AECO and BC Station 2. The Company's NGL price for the fourth quarter of 2020 was 30% of WTI, higher than the guidance range of 15% to 20% of WTI due to higher benchmark pricing for propane.

On a per-Boe basis, the Company's average realized price for 2020 decreased by 22% when compared to 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 and NGL pricing is due primarily to lower WTI pricing.

Benchmark Prices

	Three Months toDec. 31, 2020	Three Months toDec. 31, 2019	Year endedDec. 31, 2020	Year endedDec. 31, 2019
Natural gas
Chicago monthly index (US$/Mmbtu)	2.49	2.44	1.98	2.56
Chicago daily index (US$/Mmbtu)	2.33	2.21	1.89	2.42
Sumas (US$/Mmbtu)	3.55	4.20	2.34	3.80
AECO monthly index (Cdn$/GJ)	2.62	2.21	2.12	1.54
AECO daily index (Cdn$/GJ)	2.50	2.35	2.11	1.67
Station 2 (Cdn$/GJ)	2.41	1.41	2.07	0.96
Crude Oil
WTI (US$/Bbl)	42.66	56.96	39.40	57.03
WTI (Cdn$/Bbl)	55.59	75.27	52.85	75.70
Edmonton condensate (Cdn$/Bbl)	55.37	70.05	49.46	70.17
Exchange rate (US$/Cdn$)	0.77	0.76	0.75	0.75

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 were under further pressure early in 2020 with reduced winter demand resulting in higher storage levels at the end of last winter's heating season. US natural gas production has declined since 2019; however, the absence of winter weather in the fourth quarter of 2020 resulted in lower demand which moderated pricing.

BC Station 2 pricing increased in the fourth quarter of 2020 compared to the fourth quarter of 2019 due to the higher AECO price with the differential to AECO narrowing significantly resulting from the decline in receipts on 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 31% in 2020 compared to 2019. The decline was the result of elevated supply levels and the onset of demand destruction from economic shutdowns associated with COVID-19. Offsetting the decrease in WTI was a narrowing of the condensate differential from a discount of US$4.18 per barrel in 2019 to a discount of US$2.23 per barrel in 2020. Condensate differentials strengthened as crude oil prices recovered in the second half of the year which resulted in increased demand related to oil sands production.

The Company's production during the fourth quarter and year ended December 31, 2020 was sold as follows:

	Three Months toDec. 31, 2020	Three Months toDec. 31, 2019	Year endedDec. 31, 2020	Year endedDec. 31, 2019
Chicago monthly index price	27%	30%	30%	33%
Chicago daily index price	23%	25%	24%	24%
AECO index price	17%	11%	14%	11%
Station 2 index price	26%	20%	19%	19%
Sumas index price	3%	11%	8%	11%
Alliance Transfer Point ("ATP")	4%	3%	5%	2%
Total	100%	100%	100%	100%

In the fourth quarter of 2020, Storm's realized natural gas price decreased 2% from the fourth quarter of 2019 and decreased 18% for the year ended December 31, 2020 as compared to the prior year. The Company's natural gas sales price partially tracks Chicago pricing given that 54% of 2020 sales were into the Chicago market. Commencing in the fourth quarter of 2020, the Company had increased exposure to BC Station 2 pricing with the expiry of the Sumas marketing arrangement in October 2020. Approximately 26% of natural gas production was sold into the BC Station 2 market in the fourth quarter of 2020. BC Station 2 pricing increased 71% to $2.41 per GJ in the fourth quarter of 2020 when compared to the same period in 2019.

Storm's realized condensate price of $52.04 per barrel for the fourth quarter of 2020 decreased by 22% from the fourth quarter of 2019. For the year ended December 31, 2020, Storm's realized condensate price of $46.96 per barrel decreased by 29% from 2019. The decreases were primarily as a result of a decrease in the WTI price.

In the fourth quarter of 2020, Storm's realized price for NGL, excluding condensate, increased 169% relative to the same period of 2019 primarily due to higher contracted prices with marketers from a more balanced NGL market and higher propane pricing, partially offset by lower WTI pricing. For the year ended December 31, 2020, the realized price for NGL, excluding condensate, decreased by 11% year over year due to lower WTI pricing, partially offset by higher contracted prices with marketers.

Storm's NGL price net of transportation is anticipated to be approximately 30% of WTI in Canadian dollar terms for the remaining contract period that ends in March 2021.

Realized Gain (Loss) on Risk Management

	Three Months toDec. 31, 2020		Three Months toDec. 31, 2019	Year EndedDec. 31, 2020	Year EndedDec. 31, 2019
Natural gas	$	(2,659)	$(2,358)	$925	$	(10,532)
Liquids(1)		53	714	6,617		1,699
Realized gain (loss) on risk management
contracts	$	(2,606)	$(1,644)	$7,542	$	(8,833)
Per Boe	$	(1.09)	$(0.80)	$0.89	$	(1.20)

(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 gain for the year ended December 31, 2020 is primarily due to lower WTI crude oil pricing compared to the Company's financial risk management contracted prices on swaps and costless collars.

Royalties

	Three Months toDec. 31, 2020	Three Months toDec. 31, 2019	Year EndedDec. 31, 2020	Year EndedDec. 31, 2019
Charge for period	$2,190	$3,267	$6,589	$8,169
Percentage of revenue from product sales	4.1%	6.7%	4.2%	4.7%
Per Boe	$0.92	$1.59	$0.78	$1.11

Royalties, as a percentage of revenue from product sales, decreased in the fourth quarter of 2020 compared to the same period in 2019 primarily due to lower commodity prices and the receipt of infrastructure royalty credits of $0.7 million in 2020 compared to $0.2 million received in the fourth quarter of 2019.

Royalties, as a percentage of revenue from product sales, decreased for the year ended December 31, 2020 compared to the same period in 2019 primarily due to lower commodity prices which was partially offset by a reduction in infrastructure royalty credits. Infrastructure royalty credits of $3.7 million were received in 2019 compared to $0.7 million received in 2020.

Storm has remaining infrastructure royalty credits of $6.3 million that will reduce future royalties. 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

	Three Months toDec. 31, 2020	Three Months toDec. 31, 2019	Year EndedDec. 31, 2020	Year EndedDec. 31, 2019
Charge for period	$9,879	$11,663	$39,401	$43,274
Per Boe	$4.13	$5.67	$4.64	$5.87

Total production costs for the fourth quarter and year ended December 31, 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 Company's 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 gas volumes processed at third-party facilities. The following table outlines the total carbon taxes (direct and indirect) that are included within production costs.

	Three Months toDec. 31, 2020	Three Months toDec. 31, 2019		Year EndedDec. 31, 2020	Year EndedDec. 31, 2019
Charge for period	$1,013	$	1,521	$5,604	$	5,716
Per Boe	$0.42	$	0.74	$0.66	$	0.78

Transportation Costs

	Three Months toDec. 31, 2020		Three Months toDec. 31, 2019		Year EndedDec. 31, 2020		Year EndedDec. 31, 2019
Charge for period	$	11,502	$	10,708	$	45,566	$41,703
Condensate and NGL per barrel	$	2.41	$	2.62	$	2.82	$2.80
Natural gas per Mcf	$	0.90	$	0.97	$	1.00	$1.05
Per Boe	$	4.81	$	5.20	$	5.36	$5.66

Transportation costs include pipeline tariffs for natural gas sold at various 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 fourth quarter of 2020 increased by 7% when compared to the fourth quarter of 2019 primarily due to higher production volumes. On a per-Boe basis, transportation costs for the fourth quarter of 2020 decreased by 8% when compared to the fourth quarter of 2019 primarily due to a lower proportion of natural gas sales volumes transported on the Alliance Pipeline and sold at Chicago.

Transportation costs for the year ended December 31, 2020 increased by 9% when compared to the same period in 2019 primarily due to higher production volumes and incremental costs associated with transporting natural gas volumes from the Nig Creek Gas Plant to the Alliance Pipeline. Transportation costs for the year ended December 31, 2020 decreased by 5% on a per-Boe basis when compared to the same period of 2019, primarily due to selling a lower proportion of natural gas to Chicago.

Field Operating Netbacks

Details of field operating netbacks are as follows:

	Three Months to	Three Months to	Year Ended	Year Ended
($/Boe)	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2019
Revenue from product sales	22.15	23.64	18.25	23.54
Royalties	(0.92)	(1.59)	(0.78)	(1.11)
Production costs	(4.13)	(5.67)	(4.64)	(5.87)
Transportation costs	(4.81)	(5.20)	(5.36)	(5.66)
Field operating netback	12.29	11.18	7.47	10.90
Realized gain (loss) on risk management
contracts	(1.09)	(0.80)	0.89	(1.20)
Field operating netback including hedging	11.20	10.38	8.36	9.70

The 2020 field operating netback decreased by 14% after hedging compared to 2019.

General and Administrative Costs

	Three Months toDec. 31, 2020		Three Months toDec. 31, 2019		Year EndedDec. 31, 2020		Year EndedDec. 31, 2019
Charge for period – before recoveries	$	2,144	$	2,039	$	8,247	$8,870
Overhead recoveries		(533)		(594)		(1,938)	(1,987)
Charge for period – net of recoveries	$	1,611	$	1,445	$	6,309	$6,883
Per Boe	$	0.67	$	0.70	$	0.74	$0.93

General and administrative costs before recoveries for the fourth quarter of 2020 were largely unchanged when compared to the fourth quarter of 2019. General and administrative costs before recoveries for the year ended December 31, 2020 decreased by 7% compared to 2019 primarily due to the employee performance bonus for 2019 paid early in 2020 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 fourth quarter and year ended December 31, 2020 were lower compared to the same periods in 2019 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

	Three Months to		Three Months to		Year Ended		Year Ended
		Dec. 31, 2020		Dec. 31, 2019		Dec. 31, 2020	Dec. 31, 2019
Charge for period(1)	$	2,310	$	1,510	$	7,403	$5,158
Average interest rate(2)		6.5%		5.0%		5.6%	5.1%
Per Boe	$	0.97	$	0.73	$	0.87	$0.70

(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 fourth quarter and year ended December 31, 2020 increased by 53% and 44%, respectively, compared to the same periods of 2019 as a result of higher average bank borrowings which were used to partially 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 fourth quarter of 2020 increased from the fourth 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 2021, the expected increase in funds flow should result in stamping fees and interest expense being reduced.

Funds Flow

	Three Months to		Three Months to			Year Ended		Year Ended
	Dec. 31, 2020			Dec. 31, 2019		Dec. 31, 2020		Dec. 31, 2019
		Per		Per		Per		Per
		diluted		diluted		diluted		diluted
		share		share		share		share
Funds flow	$22,350	$0.18	$18,469	$0.15	$56,824	$0.47	$59,549	$0.49

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.

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

Higher production volumes and lower production costs were the predominant factors in the 21% increase in funds flow in the fourth quarter of 2020 versus the fourth 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/surplus), was 12% in 2020 and 2019.

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

Funds flow for 2020 decreased by 5% from 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 $8.8 million compared to a realized hedging gain in 2020 of $7.5 million.

Share-Based Compensation

	Three Months toDec. 31, 2020	Three Months toDec. 31, 2019	Year EndedDec. 31, 2020			Year EndedDec. 31, 2019
Charge for period	$430	$656	$	1,817	$	2,464
Per Boe	$0.18	$0.32	$	0.21	$	0.33

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 34% in the fourth quarter of 2020 compared to the fourth quarter of 2019 and by 26% in the year ended December 31, 2020 compared to the same period of 2019. The decrease in share-based compensation in both periods is primarily attributable to higher value stock options that were fully vested at the end of 2019.

Depletion and Depreciation

	Three Months toDec. 31, 2020		Three Months toDec. 31, 2019		Year EndedDec. 31, 2020		Year EndedDec. 31, 2019
Depletion	$	9,564	$	9,246	$	36,481	$32,742
Depreciation		2,663		2,010		10,097	7,764
Charge for period	$	12,227	$	11,256	$	46,578	$40,506
Per Boe	$	5.12	$	5.46	$	5.48	$5.50

Depletion and depreciation increased by 9% in the fourth quarter of 2020 compared to the fourth quarter of 2019, and by 15% when comparing the year ended December 31, 2020 with the same period in 2019, primarily due to an increase in production volumes and higher incremental depreciation associated with the commissioning of the Nig Creek Gas Plant in 2020. On a per-Boe basis, the decrease in depletion and depreciation in the fourth quarter of 2020 is due to lower finding and development costs.

Unrealized Gain (Loss) on Risk Management

	Three Months toDec. 31, 2020		Three Months toDec. 31, 2019	Year EndedDec. 31, 2020	Year EndedDec. 31, 2019
Natural gas	$	18,144	$2,439	$(3,489)	$	10,742
Liquids(1)		(3,458)	(4,574)	(2,174)		(9,226)
Interest rate		165	122	(855)		11
Unrealized gain (loss) on risk managementcontracts	$	14,851	$(2,013)	$(6,518)	$	1,527
Per Boe	$	6.21	$(0.98)	$(0.77)	$	0.21

(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

The Company did not incur any cash tax expense in the three months and year ended December 31, 2020, nor does it expect to pay any cash tax in 2021 or in 2022 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 months and year ended December 31, 2020, the Company recognized a deferred income tax expense of $6.8 million and $1.5 million, respectively, as a result of $24.7 million and $1.2 million of net income before taxes, respectively. As at December 31, 2020, the Company had a deferred income tax liability of $10.8 million.

Tax Pools	As at December 31, 2020	Maximum Annual Deduction
Canadian oil and gas property expense	$	39,00010%
Canadian development expense		106,00030%
Canadian exploration expense		14,000100%
Undepreciated capital cost		147,00020% – 100%
Operating losses		200,000100%
Total	$	506,000

Net Income (Loss)

The mark-to-market valuation of unrealized risk management contracts resulted in a distortion on reported net income and net loss for the three months and year ended December 31, 2020 relative to the comparable periods in 2019. For the three months ended December 31, 2020, the unrealized gain on risk management contracts amounted to $14.9 million and for the year ended December 31, 2020, the unrealized loss on risk management contracts was $6.5 million. This compared to an unrealized loss of $2.0 million for the three months ended December 31, 2019 and an unrealized gain of $1.5 million for the year ended December 31, 2019.

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 2020 compared to 4% in 2019, although as mentioned above is distorted by unrealized gains and losses on the Company's risk management contracts.

	Three Months toDec. 31, 2020		Three Months toDec. 31, 2019		Year EndedDec. 31, 2020		Year EndedDec. 31, 2019
Net income (loss)	$	17,873	$	2,906	$	(214)	$	11,313
Per basic and diluted share	$	0.15	$	0.02	$	(0.00)	$	0.09

INVESTMENT AND FINANCING

Financial Resources and Liquidity

As at December 31, 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 proved developed 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 December 31, 2020, debt including working capital surplus amounted to $131.7 million. Bank debt including outstanding letters of credit represented approximately 78% utilization of the available credit facility.

As at December 31, 2020, the Company had issued letters of credit in the amount of $13.7 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 fourth quarter of 2020, the Company incurred capital expenditures of $16.2 million compared to $23.9 million in the fourth quarter of 2019.

During 2020, the Company incurred capital expenditures of $59.3 million (2019 - $96.8 million) primarily related to costs incurred for completion and start-up of the Nig Creek Gas Plant, drilling two horizontal wells (1.0 net) at Fireweed, three horizontal wells (3.0 net) at Umbach, and four horizontal wells (4.0 net) at Nig Creek, and completing one well (0.5 net) at Fireweed, three wells (3.0 net) at Umbach and four wells (4.0 net) at Nig Creek.

	Three Months toDec. 31, 2020	Three Months toDec. 31, 2019	Year EndedDec. 31, 2020	Year EndedDec. 31, 2019
Land and seismic	$199	$370	$745	$2,155
Drilling	6,172	208	18,693	14,639
Completions	6,317	991	17,901	13,474
Facilities	1,819	16,543	16,806	56,830
Equipping and pipelines	1,004	5,585	4,013	10,499
Recompletions and workovers	640	194	1,035	249
Property acquisition and administrative assets	12	22	58	80
Total field capital expenditures	$16,163	$23,913	$59,251	$97,926
Proceeds on disposition of undeveloped land	-	-	-	(1,083)
Total capital expenditures	$16,163	$23,913	$59,251	$96,843

Net capital investment was allocated as follows:

	Three Months toDec. 31, 2020		Three Months toDec. 31, 2019		Year EndedDec. 31, 2020		Year EndedDec. 31, 2019
Exploration and evaluation	$	200	$	370	$	746	$	1,086
Property and equipment		15,963		23,543		58,505		95,757
Total capital expenditures	$	16,163	$	23,913	$	59,251	$	96,843

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 December 31, 2020 corresponds to the Company's field capital expenditure program.

Decommissioning Liability

The Company's decommissioning liability of $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 December 31, 2020 was $40.5 million (December 31, 2019 - $38.3 million), with $1.9 million expected to be incurred in the next 12 months. The liability for currently inactive wells and facilities is approximately $10 million with approximately 70% of this expected to be incurred by 2025.

Share Capital

Details of share issuances from inception to December 31, 2020 are as follows:

		Number of	Price	Gross Proceeds(1)
		Shares (000s)	per Share	($000s)
June 8, 2010	Issued upon incorporation		$ 1.00	$-
August 17, 2010	Issued under the Arrangement	17,515	$ 3.28	57,600
August 17, 2010September 22, 2010	Issued under private placementIssued upon exercise of warrants	2,3006,562	$ 3.28$ 3.28	7,54421,522
		26,377		86,666
January 12, 2012	Issued on acquisition of SGR	11,761	$ 3.73	43,869
March 23, 2012	Issued under private placement	6,946	$ 3.40	23,615
March 23, 2012	Issued on acquisition of Bellamont	16,740	$ 2.37	39,674
		35,447		107,158
May 1, 2013	Issued under private placement	12,580	$ 1.88	23,650
May 1, 2013	Issued under insider private placement	3,000	$ 1.88	5,640
June 30, 2013	Shares cancelled	(21)	$ 2.37	(50)
November 19, 2013	Issued under private placement	9,000	$ 3.35	30,150
November 19, 2013	Issued under insider private placement	1,100	$ 3.35	3,685
		25,659		63,075
January 31, 2014	Issued pursuant to Umbach acquisition	13,629	$ 4.25	57,925
February 14, 2014	Issued under private placement	7,250	$ 4.10	29,725
February 14, 2014	Issued under insider private placement	1,250	$ 4.10	5,125
Year ended December 31, 2014	Stock option exercises	1,710	$ 3.26	5,580
		23,839		98,355
June 10, 2015	Issued under private placement	8,000	$ 4.55	36,400
Year ended December 31, 2015	Stock option exercises	145	$ 1.81	262
		8,145		36,662
Year ended December 31, 2016	Stock option exercises	1,297	$ 1.97	2,558
Year ended December 31, 2017	Stock option exercises	793	$ 1.83	1,456
Year ended December 31, 2020	Stock option exercises	132	$ 1.70	224
Total at December 31, 2020		121,689	$ 3.26	396,154

(1) Before cumulative share issue costs of $8.0 million and cumulative transfers from contributed surplus of $3.6 million.

There were no stock options exercised in 2019. During 2020, stock options were exercised at an average price of $1.70 per optioned share and 132,000 common shares were issued for proceeds of $224,000.

Issued and outstanding common shares at December 31, 2020, totaled 121,688,812 and at March 2, 2021, the date of this MD&A, totaled 121,712,812.

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 $4.1 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 $389 million.

QUARTERLY RESULTS

Summarized information by quarter for the two years ended December 31, 2020 appears below.

		2020
($000s unless otherwise stated)	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1
Revenue from product sales	52,941	30,010	30,191	41,923	48,671	31,417	37,568	55,766
Funds flow	22,350	6,681	10,904	16,889	18,469	11,973	12,590	16,517
Per share – basic and diluted ($)	0.18	0.05	0.09	0.14	0.15	0.10	0.10	0.14
Net income (loss)	17,873	(16,934)	(11,665)	10,512	2,906	(64)	7,864	607
Per share – basic and diluted ($)	0.15	(0.14)	(0.10)	0.09	0.02	(0.00)	0.06	0.00
Net capital expenditures	16,163	14,219	2,394	26,475	23,913	32,841	23,145	16,944
Average daily production (Boe)	25,985	19,027	23,935	23,946	22,375	18,596	19,923	19,823
Debt including working capitaldeficiency/surplus(1)	131,705	137,983	130,317	138,632	128,901	123,342	102,268	91,585

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

SELECTED ANNUAL FINANCIAL INFORMATION

($000s unless otherwise stated)	Year EndedDecember 31, 2020	Year EndedDecember 31, 2019	Year EndedDecember 31, 2018
Revenue from product sales	155,065	173,422	226,258
Funds flow	56,824	59,549	100,092
Per share – basic and diluted ($)	0.47	0.49	0.82
Net income (loss)	(214)	11,313	40,063
Per share – basic and diluted ($)	(0.00)	0.09	0.33
Total assets	630,270	616,496	565,534
Debt including working capital deficiency/surplus(1)	131,705	128,901	91,020
Average daily production (Boe)	23,219	20,182	20,538
Funds flow ($/Boe)	6.69	8.09	13.34

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

The trend in annual results represents execution of the Company's strategic plan in the face of a volatile commodity price environment. The cornerstone of the strategic plan is capital investment discipline and growing asset value on a per-share basis. Storm achieved production growth in 2020 despite lower capital spending in response to a decrease in commodity prices. Over the last three years, the Company has benefitted from a diversified marketing strategy whereby the Company's production has exposure to both Western Canada natural gas pricing and US based pricing. Debt in 2020 was largely flat with the prior year, however, has increased from 2018 due to the build out of the Nig Creek Gas Plant project, which benefitted 2020 results through lower production costs. Net income (loss) has also been affected by volatile commodity prices, although is subject to a high degree of variability due to unrealized gains and losses on risk management contracts. The Company reported a $6.5 million unrealized loss on risk management contracts for the year ended December 31, 2020, an unrealized gain on risk management contracts of $1.5 million for the year ended December 31, 2019 and an unrealized loss on risk management contracts of $5.8 million for the year ended December 31, 2018.

The increase in the Company's total assets reflects the ongoing development of the Company's Montney play at Umbach, Nig Creek and Fireweed. Capital expenditures in 2020 included the completion and start-up of the Nig Creek Gas Plant and drilling and completions activities at Umbach, Nig Creek and Fireweed.

Capital expenditures in 2019 were primarily directed towards construction of the 50 Mmcf per day Nig Creek Gas Plant and drilling and completion activities at Nig Creek. Capital expenditures in 2018 included drilling, completions and infrastructure expenditures including twinning of a third field compression facility at Umbach at a cost of approximately $7 million, which supports growth of corporate production from Umbach alone to approximately 27,000 Boe per day.

Share Trading

Set out below is share trading activity for Storm for 2020 and 2019.

		2020
	Q1	Q2	Q3	Q4	Year	Q1	Q2	Q3	Q4	Year
High ($)	1.74	1.59	2.13	2.44	2.44	2.46	2.56	1.79	1.68	2.56
Low ($)	0.85	0.90	1.41	1.84	0.85	1.51	1.63	1.14	1.16	1.14
Close ($)	1.01	1.45	2.08	2.18	2.18	2.38	1.81	1.32	1.64	1.64
Volume traded (000s)	10,830	7,414	12,614	7,717	38,576	8,405	4,930	10,035	17,012	40,383
Value traded ($000s)	12,772	9,502	23,796	16,771	62,841	16,883	9,292	13,417	24,244	63,836
Weighted average
trading price ($)	1.18	1.28	1.89	2.17	1.63	2.01	1.88	1.34	1.43	1.58

Note: Data obtained from the TMX website.

CRITICAL ACCOUNTING ESTIMATES

Financial amounts included in this MD&A and in the audited consolidated financial statements for the years ended December 31, 2020 and 2019 are based on accounting policies, estimates and judgments which reflect information available to management at the time of preparation. Certain amounts in the financial statements are derived from a fully completed transaction cycle, or are validated by events subsequent to the end of the reporting date, or are based on established and effective measurement and control systems. However, certain other amounts, as described below, are based on estimations made by management using information which involves an element of measurement uncertainty. The degree of uncertainty related to each of the following items will vary; further, it may change between reporting periods. Variations between amounts estimated and actual results could have a material effect on Storm's operating results and financial position.

Crude Oil and Natural Gas Reserves

Estimates of quantities of proven and probable reserves of natural gas and NGL (which includes condensate) are not a financial measurement. However, estimated future cash flows associated with reserves are used in impairment assessments for exploration and evaluation assets and property and equipment, the measurement of decommissioning obligations and depletion and depreciation of property and equipment. Such estimates of cash flows involve assumptions regarding future commodity prices, exchange rates, discount rates, inflation rates and future production and transportation costs and, of necessity, involve uncertainty. Reserve estimates are prepared annually by independent qualified reserve evaluators in accordance with independently established industry standards using, in part, data supplied by the Company. The results of the independent reserve evaluation are reviewed by the Reserves Committee of the Company's Board of Directors. In certain circumstances the Company will prepare internal estimates of reserves which may be used in accounting measurements applicable to interim reporting periods.

Accounts Receivable, Accounts Payable and Accrued Liabilities

At the end of each reporting period the Company estimates the amount receivable from product sales and from joint operations partners to the extent that these amounts are not determinable from purchaser statements or amounts invoiced to partners. In addition, the Company estimates the cost of services and materials provided by suppliers during the reporting period if these costs have not been invoiced to the Company by the reporting date. The Company estimates and recognizes such revenues and costs using well established measurement procedures. Nonetheless, such procedures reflect judgment by management and are thus subject to measurement uncertainty. In addition, estimates of services and materials not invoiced, either to or by the Company, relate in large part to the Company's capital expenditure programs, the level of which can vary considerably between reporting periods. As a result, the amount of accounts receivable, accounts payable and accrued liabilities subject to estimation will vary and in periods of high field activity the amount subject to estimation may be a large part of the total amount.

Risk Management Contracts

The Company periodically enters into contracts which fix a price or a price range for future periods for natural gas and crude oil. Each such contract is valued at the end of each reporting period, with the change in value of outstanding contracts being included in the measurement of income for the period. The period end value is based on option pricing models using estimates for future circumstances and is correspondingly subject to both mathematical and input uncertainty. Crude oil contracts are used as a proxy for condensate and NGL contracts, as part of the Company's condensate and NGL stream is priced with reference to crude oil index prices.

Exploration and Evaluation Assets

Costs incurred by the Company in the assessment phase of a property offering development potential are categorized as exploration and evaluation assets. Such costs are transferred to CGUs, generally when production commences or reserves are assigned, or are expensed if management determines that the costs incurred will yield no future economic benefit or if the lease associated with the property expires. The amounts transferred to property and equipment, or expensed, and the timing of the decisions relative to each, are subject to measurement uncertainty. Furthermore, the carrying amount of exploration and evaluation assets at the end of each reporting period represents an asset whose value can only be established in future periods. The carrying amount of exploration and evaluation assets is reviewed at the end of each reporting period for indicators of impairment. If such indicators exist the carrying amount will be measured against the estimated recoverable amount and, if necessary, reduced. This review involves estimates and judgments by management and thus involves a high degree of uncertainty.

Property and Equipment, and Depletion and Depreciation

Amounts transferred from exploration and evaluation assets to property and equipment represent the accumulated net costs associated with the property transferred. The timing and the measure of the amount to be transferred involves estimation and judgment by management and the estimates used could differ from similar estimates developed by other parties. In addition, acquired property and equipment is initially recorded at fair value as determined by management. Measurement of fair value includes estimation and judgment and is inherently subjective and uncertain.

Property and equipment is subject to depletion and depreciation, and charges for depletion and depreciation are based on estimates which may only be validated in future periods, if ever. Such charges involve estimates by management of the useful economic life for assets subject to depletion and depreciation, the quantities of crude oil and natural gas reserves used in the depletion calculation, the future prices at which such reserves may be sold, and future costs to develop and produce such reserves.

The carrying amounts of property and equipment are reviewed each reporting period to determine whether there are indicators of impairment. If there are such indicators, an impairment test per CGU is completed involving the calculation of an estimated recoverable amount; as a result adjustments to the carrying amount may be made. All of these involve assumptions regarding uncertain future events and circumstances.

Decommissioning Liability

Storm records as a liability the discounted estimated fair value of obligations associated with the decommissioning of field assets. The carrying amount of exploration and evaluation assets and property and equipment is increased by an amount equivalent to the liability. In summary, the decommissioning liability reflects the present value of estimated costs to complete the abandonment and reclamation of field assets as well as the estimated timing of incurrence of these costs. The liability is increased each reporting period to reflect the passage of time, with the charge for accretion included in earnings. The liability is also adjusted to reflect changes in the amount and timing of future retirement obligations as well as asset dispositions and is reduced by the amount of any costs incurred in the period. Adjustments are also made to the liability in response to changes in discount and inflation rates. The amount of future decommissioning costs, the timing of incurrence of such costs, the discount rate and, correspondingly, the charge for accretion, are subject to uncertainty of estimation. In addition, the decommissioning activities to which the estimates relate are likely to take place many years, potentially decades, in the future. The long timeline between incurrence and eventual satisfaction of the obligation will inevitably affect the accuracy of the estimation process.

Share-Based Compensation

To determine the charge for share-based compensation, the Company estimates the fair value of stock options at the time of issue using assumptions regarding the life of the option, dividend yields, interest rates and the volatility of the security under option. Although the assumptions used to value a specific option remain unchanged throughout the life of the option, assumptions may change with respect to subsequent option grants. In addition, the assumptions used may not properly represent the fair value of stock options at any time; as no alternative valuation model is applied, the difference between the Company's estimation of fair value and the actual value of the option is not measurable. Although the methodology used to measure the charge for share-based compensation is largely uniform across Storm's peers, inputs to the calculation, and thus the charge, may vary considerably.

Income Taxes

The measurement of Storm's tax pools, losses and deferred tax assets and liabilities requires interpretation of complex laws and regulations. All tax filings and compliance with tax regulations are subject to audit and reassessment, potentially several years after the initial filing. In addition, the amount and timing of use of tax pools may be affected by future legislation. Accordingly, the amounts of tax pools available for future use may differ significantly from the amounts estimated in the financial statements.

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 2021 and 2022, 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 2021, production volumes by commodity and production declines;
• capital investment intended to be less than funds flow in 2021 leading to a reduction in debt;
• planned capital expenditures in 2021 totaling $85 to $90 million, 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;
• Q1 2021 production of 25,000 to 27,000 Boe per day with capital investment of $25 million;
• 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 2021 capital program;
• the expectation that the Company's NGL price will be approximately 30% of WTI in Canadian dollar terms for Q1 2021 and 20% to 25% of WTI in Canadian dollar terms for 2021;
• 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;
• 'Free cash flow' in 2021 of approximately $80 million based on the mid-point for estimated annual funds flow in guidance and assuming capital investment of $33 million is required to maintain production;
• 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, 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 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 crude 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 governmentimposed 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 crude 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;

• 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 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 crude 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/surplus", "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. Non-GAAP 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.

	As At	As At	As At
($000s unless otherwise stated)	December 31, 2020	December 31, 2019	December 31, 2018
Accounts receivable	19,283	21,961	29,262
Prepaids and deposits	1,124	764	853
Less: Accounts payable and accrued liabilities	(17,721)	(30,018)	(34,359)
Working capital deficiency/surplus	(2,686)	7,293	4,244
Bank indebtedness	134,391	121,608	86,776
Debt including working capital deficiency/surplus	131,705	128,901	91,020

CROCE & ROCE

CROCE is a 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.

($000s unless otherwise stated)	Twelve Months EndedDecember 31, 2020	Twelve Months EndedDecember 31, 2019
Average debt including working capital deficiency/surplus(1)	130,303	109,960
Average shareholders' equity(1)	422,622	414,820
Average capital employed	552,925	524,780
Funds flow	56,824	59,549
Interest and finance costs	7,403	5,158
Funds flow plus interest and finance costs	64,227	64,707
CROCE	12%	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 a 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.

($000s unless otherwise stated)	Twelve Months EndedDecember 31, 2020	Twelve Months EndedDecember 31, 2019
Average debt including working capital deficiency/surplus(1)	130,303	109,960
Average shareholders' equity(1)	422,622	414,820
Average capital employed	552,925	524,780
Net income (loss)	(214)	11,313
Interest and finance costs	7,403	5,158
Deferred income tax expense	1,463	4,927
	8,652	21,398
ROCE	2%	4%

(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. The following reviews a number of the identifiable business risks faced by the Company. Business risks evolve constantly and additional risks emerge periodically. The risks below are those identified by management at the date of completion of this report, and may not describe all of the material business risks, identifiable or otherwise, faced by the Company.

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 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 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.

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, the outbreak of COVID-19 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 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 has 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.

Property Exploitation

Storm's exploitation programs require sophisticated and scarce technical skills as well as capital and access to land and oilfield service equipment. Storm endeavours to minimize the associated risks by ensuring that:

• activity is focused in core regions where internal expertise and experience can be applied;
• prospects are internally generated;
• development drilling is in areas where there is immediate or near-term access to facilities, pipelines and markets or where construction of necessary infrastructure is within the Company's financial capacity;
• the Company seeks to act as operator and to maintain a 100% or high working interest. The Company can thus control the timing, cost and technical content of its exploration and development programs.

Nevertheless, drilling and completing a well may not result in the discovery of economic reserves, or a well may be rendered uneconomic by commodity price declines or an increasing cost structure.

In addition, the Company's investment program is currently focused on development of the Umbach, Nig Creek and Fireweed properties, resulting in asset concentration risk.

Commodity Price Fluctuations

When the Company identifies hydrocarbons of sufficient quantity and quality and successfully brings them on stream, it faces a pricing environment which is volatile and subject to a myriad of factors, largely out of the Company's control. Low prices for the Company's expected primary products will have a material effect on the Company's funds flow and profitability and thus re-investment capacity, and hence ultimate growth potential. Low prices also limit access to capital, both equity and debt. The Company in part mitigates the risk of pricing volatility through the use of risk management contracts, such as fixed priced sales, swaps, collars and similar contracts. However, access to such commodity price protection instruments may not be available in future periods, or available only at a cost considered to be uneconomic. Such risk management contracts tend to be for short periods and the pricing protection this provides has limited effect against medium and long term pricing trends. The Company may shut in production rather than sell it at prices considered by management to be unacceptably low. The Company's production base is almost entirely natural gas and associated liquids, a trend unlikely to change in future years, resulting in commodity concentration risk.

Adverse Well or Reservoir Performance

Changes in productivity in wells and areas developed by the Company could result in termination or limitation of production, or acceleration of decline rates, resulting in reduced overall corporate volumes and revenues. In addition, wells drilled by the Company tend to produce at high initial rates followed by rapid declines until a flattening decline profile emerges. There is a risk that the decline profile which eventually emerges for newly drilled wells is subeconomic. In addition, the Company's property in northeastern British Columbia is in the early stage of development and there is a risk that unforeseeable circumstances may emerge which will adversely affect reservoir performance.

Field Operations

Storm's current and future exploration, development and production activities involve the use of heavy equipment and the handling of volatile liquids and gases. Catastrophic events, regardless of cause or responsibility, such as well blowouts, explosions and fires within pipeline, gathering, or facility infrastructure, as well as failure of gathering systems or mechanical equipment, could lead to releases of liquids or gases, spills of contaminants, personal injuries and death, damage to the environment, as well as uncontrolled cost escalation. With support from suitably qualified external parties, the Company has developed and implemented policies and procedures to mitigate environmental, health and safety risks. These policies and procedures include the use of formal corporate policies, emergency response plans, and other policies and procedures reflecting what management considers to be best oilfield practices. These policies and procedures are subject to periodic review. Storm also manages environmental and safety risks by maintaining its operations to a high standard and complying with all provincial and federal environmental and safety regulations. Nevertheless, application of best practices to field operations serves only to mitigate, not eliminate, risk.

The Company's areas of activity are relatively undeveloped. In any new area of activity, property access and production require considerable early stage investment, for example, road construction, access to processing facilities, pipelines and other transportation arrangements, which is not necessarily applicable to more mature producing areas. In addition, supervision and maintenance of production facilities is likely to be more expensive than in existing and more accessible producing areas. In addition, the Company's property at HRB in northeast British Columbia, is in an area which is climatically and geographically hostile.

Storm maintains industry-specific insurance policies, including environmental damage and business interruption, on important owned and non-owned production and processing facilities. Although the Company believes its current insurance coverage corresponds to industry standards, there is no guarantee that such coverage will be available in the future, and if it is, at a cost acceptable to the Company, or that existing coverage will necessarily extend to all circumstances or incidents resulting in loss or liability.

Retention of Key Personnel

A loss in key personnel of Storm could delay the completion of certain projects or otherwise have a material adverse effect on the Company. Shareholders are dependent on Storm's management and staff in respect of the administration and management of all matters relating to the Company's assets.

Environmental

The Company's operations are subject to extensive environmental regulations which are addressed through formal policies and procedures and application of best field practices. Climate change policy is evolving at regional, national and international levels, and political and economic events may significantly affect the scope and timing of climate change initiatives ultimately put in place. Given the evolving nature of climate change discussions, the regulation of emissions of greenhouse gases ("GHG") and potential federal and provincial GHG commitments, the Company is unable to predict the effect on its operations and financial condition at this time. It is possible that the Company could face increases in operating and capital costs in order to comply with increased GHG emissions legislation.

The Company's development program in northeastern British Columbia involves horizontal drilling and fracturing applications. Fracturing involves the use of large quantities of liquids and chemicals, whose use and subsequent disposal has resulted in the emergence of environmental concerns, primarily in more heavily populated areas elsewhere in North America. In particular, much of the natural gas produced by the Company contains hydrogen sulfide, which is potentially lethal and has to be removed from the natural gas stream. This requires access to specialized processing facilities. Although the Company considers that access to such facilities is adequate for current and near-term production levels, this may not be the case in the future. In addition, future exploitation of shale gas in the HRB may cause management of carbon dioxide volumes produced concurrently with natural gas to become an operational issue.

The evolution of environmental regulation, in particular as it relates to fracturing applications, cannot be predicted at this stage. Nevertheless, it is reasonable to expect that management of environmental issues and related societal expectations will become an increasingly important part of the Company's business, with a corresponding effect on costs and economic returns.

Since the majority of the Company's operations are located British Columbia, the Company is subject to the British Columbia Carbon Tax Act, which initially set a carbon price of $30 per tonne. Beginning on April 1, 2018, the provincial carbon tax was increased by $5 per tonne, increased again by $5 per tonne on April 1, 2019, and additional $5 per tonne increases are expected in the future to reach the federal target carbon price of $50 per tonne. This will, of course, have a corresponding effect on costs and economic returns. In response to COVID-19, British Columbia's carbon tax rate will remain at its current level of $40 per tonne until March 31, 2021.

In addition to Company-specific environmental concerns, increasing public and political focus on climate change and its possible amelioration, may cause changes in demand for the Company's products and the introduction of regulations which may result in changes to the Company's operating practices as well as additional and unforeseeable costs and the incurrence of future liabilities, real or contingent. Changes in public policy in response to changes in government at federal and provincial levels over the next several years cannot be determined at this stage, but given that the Company is a producer of primary hydrocarbons it is likely that its business will be subject to increased regulation and potentially subject to additional taxes, costs and obligations.

Industry Capacity Constraints

The collapse in prices for crude oil and natural gas, in a historical context, has reduced field activity and thus concerns over access to equipment and services. Further, service costs have fallen in recent years and remain relatively stable. Nevertheless, periods of high field activity can result in shortages of services, products, equipment, or manpower in many or all of the components of the development cycle. Increased demand leads to higher land and service costs during peak activity periods. In addition, access to transportation and processing facilities may be difficult or expensive to secure. Storm's competitors include companies with far greater resources, including access to capital and the ability to secure oilfield services at more favourable prices and to build out operations on a scale which lowers the economic threshold for exploitation of a resource. Storm competes by maintaining a large inventory of self-generated exploration and development locations, by acting as operator where possible, and through facility access and ownership. Storm also seeks to carefully manage key supplier relationships. Declines in commodity prices should, in principle, result in lower service costs; however, this may be offset by service providers choosing to retire equipment rather than operate at sub-optimum prices, or ceasing business altogether.

Capital Programs

Capital expenditures are designed to accomplish two main objectives, being the generation of short and medium term funds flow from development activities, and expansion of future funds flow from the identification of or further development of reserves. The Company focuses its activity in core areas, which allows it to leverage its experience and knowledge, and acts as operator wherever possible. The Company may use farm-outs to minimize risk on plays it considers higher risk or where total capital invested exceeds an acceptable level. In addition, Storm may enter into risk management contracts in support of capital programs, and to manage future debt levels. Generally, capital programs are financed from funds flow and disciplined use of debt, and occasionally, equity. Failure to develop producing wells or to sell production at a reasonable price and thus maintain an acceptable level of funds flow, will result in the exhaustion of available financial resources and will require the Company to seek additional capital which may not be available, or only available on unacceptable terms, or terms highly dilutive to existing shareholders. In addition, credit availability from the Company's bankers is also necessary to support capital programs and any changes to credit arrangements may have an effect on both the size of the Company's future capital programs and the timing of expenditures. As the banking facility available to the Company is based on future funds flows from existing production, falling commodity prices will likely have an effect on borrowing availability.

Reserve Estimates

Estimates of economically recoverable crude oil and natural gas reserves and natural gas liquids, and related future net cash flows, are based upon a number of variable factors and assumptions. These include commodity prices, production, future operating, transportation, development and facility as well as decommissioning costs, access to market, and potential changes to the Company's operations or to reserve measurement protocols arising from regulatory or fiscal changes. All of these estimates may vary from actual circumstances, with the result that estimates of recoverable crude oil and natural gas reserves attributable to any property are subject to revision. In future, the Company's actual production, revenues, royalties, transportation, operating expenditures, finding, development, facility and decommissioning costs associated with its reserves may vary from such estimates, and such variances may be material.

Production

Production of crude oil and natural gas reserves at an acceptable level of profitability may not be possible during periods of low commodity prices. The Company will attempt to mitigate this risk by focusing on higher netback opportunities and will act as operator where possible, thus allowing the Company to manage costs, timing, method and marketing of production. Production risk is also addressed by concentrating field activity in regions where infrastructure is or will be Storm owned, or readily accessible at an acceptable cost. In periods of low commodity prices the Company will shut in production, either temporarily or permanently, if netbacks are sub-economic.

Production is also dependent in part on access to third-party facilities and pipelines with the result that production may be reduced by outages, accidents, maintenance programs, prorationing and similar interruptions outside of the Company's control. For example, a gas processing facility, to which a significant amount of the Company's gas production is directed, was closed for maintenance in the second and third quarters of 2017 for a period of 39 days. In addition, this same facility was shut down for a total of 37 days in 2019 and 28 days in 2020 due to a combination of planned and unplanned outages. Generally, this facility is closed for significant maintenance every three years.

Storm's contracted gas processing capacity at third-party facilities was approximately 55% of total raw gas production during December 2020 with the remaining portion processed at the Company's Nig Creek Gas Plant. Production in excess of approximately 140 Mmcf per day raw requires access to interruptible processing capacity at third-party facilities and there is a risk that the uncontracted, interruptible portion could be reduced or shut in if capacity available to Storm is allocated to other parties. Transportation of gas to processing facilities and to market is similarly exposed to the extent that the required capacity is not covered by contract. In addition, contracts for processing or pipeline access are for a fixed term and may not be renewed or may be renewed under more onerous terms.

Financial and Liquidity Risks

The Company faces a number of financial risks over which it has no control, such as commodity prices, exchange rates, interest rates, access to credit and capital markets, as well as changes to government regulations and tax and royalty policies. The Company uses the guidelines below to address financial exposure. Although these guidelines result in conservative management of the Company's finances, they cannot eliminate the financial risks the Company faces.

• Internal funds flow provides the initial source of funding on which the Company's capital expenditure program is based.
• Debt, if available, may be utilized to expand capital programs, including acquisitions, when it is deemed appropriate and where debt retirement can be controlled. The Company measures debt levels against current or near-term funds flow. If the debt-to-funds-flow ratio becomes unacceptably high, capital programs will be postponed, assets sold or farmed out or other measures taken to bring debt levels down.
• Interest rate contracts, if available, may be used to manage fluctuations in interest rate.
• Equity, if available on acceptable terms, may be raised to fund acquisitions and capital programs.
• Farm-outs of projects may be arranged if management considers that the capital requirements of a project are excessive in the context of the Company's resources, or where the project affects the Company's risk profile, or where the project is of lower priority.
• Risk management contracts, if available, may be used to manage commodity price volatility when the Company has capital programs, including acquisitions, whose cost exceeds near-term projected funds flow and where capital programs involve longer-term commitments.
• The Company will also sell assets at an acceptable price if the proceeds can be redeployed in properties offering a higher netback or greater development potential.

Marketing Risks

Markets for future production of crude oil and natural gas are outside the Company's capacity to control or influence and can be affected by events such as weather, climate change, regulation, regional, national and international supply and demand imbalances, facility and pipeline access, geopolitical events, currency fluctuation, introduction of new or termination of existing supply arrangements, as well as downtime due to maintenance or damage, either to owned or third-party facilities and pipelines. The Company will attempt to mitigate these risks as follows:

• Properties are developed in areas where there is access to processing and pipeline or other transportation infrastructure, and, where possible, owned by the Company.
• The Company will delay drilling or tie-in of new wells or shut in production if acceptable pricing cannot be realized.
• The Company constantly assesses the various markets into which production can be sold and if possible will direct production to markets offering the most attractive returns.
• The Company endeavours to secure access to facilities and pipelines under contracts setting volumes, prices and term.

Storm has contracted pipeline transportation capacity for approximately 127 Mmcf per day of natural gas sales volumes in 2021 with the remaining portion relying on access to interruptible capacity. There is a risk that the uncontracted, interruptible portion could be reduced or shut in during partial outages or if capacity is allocated to other parties.

The Company's product profile comprises a large and growing percentage of natural gas. Pricing and access to markets has been affected by the growth of domestic gas production in North America. When, if ever, access to historical markets in North America may improve, is not predictable. Further, development of certain natural gas reserves in Canada is to a degree underwritten by the expectation that new Pacific Rim export markets will be accessed through the establishment of LNG liquefaction facilities on Canada's west coast. While development of one such facility is underway, whether additional facilities will be completed, if ever, cannot be predicted.

Access to Debt and Equity

The Company's funds flow and borrowing capacity is sufficient to fund its existing capital budget. Nevertheless, funding is finite and investment must result in production being brought on stream, followed by the generation of funds flow and the identification of proved plus probable reserves. Bank financing, which for junior oil and gas companies like Storm, is conventionally a loan, renewable annually but subject to semi-annual review, is based on anticipated future funds flows. Thus, bank financing is short term only and availability is likely to be reduced in response to lower production or lower commodity prices. Banking arrangements are renewed in May each year and are subject to mid-year review.

Although equity is another source of financing, the Company is exposed to changes in the equity markets, which could result in equity not being available, or only available under conditions which are unacceptably dilutive to existing shareholders. The inability of the Company to develop profitable operations, with the consequent exclusion from debt and equity markets, may result in the Company curtailing or suspending operations.

Changes in Government Regulations, Royalties and Policies

In both Canada and the United States the energy industry is subject to scrutiny, frequently hostile, by political and environmental groups. This may lead to increased regulation and increased compliance costs. In particular, there is a risk that existing royalty incentive programs could be terminated or amended, royalty or income tax rates could be increased, rules and regulations around well licensing or surface access could be changed, horizontal drilling and hydraulic fracturing could be subject to increased oversight or regulation, First Nations consultation requirements may be changed and greenhouse gas (GHG) emissions targets may be changed which could affect carbon taxes. In December 2020, the Canadian federal government announced that the carbon tax will increase from its current $30 per tonne of GHG emissions to $170 per tonne in 2030, although this has yet to be made into law. The federal carbon tax is currently set to increase to $50 per tonne by 2023 and the recent announcement would see the carbon tax increase by $15 per tonne per year starting in 2023 until reaching $170 per tonne in 2030. In the event this is made into law this will, of course, have a corresponding effect on costs and economic returns.

Cyber-Security

The Company is dependent on information technology, such as computer hardware and software systems, in order to properly operate its business. These systems have the potential for information security risks, which could include potential breakdown, virus, invasion, cyber-attack, cyber-fraud, security breach and destruction or interruption of information technology systems by third parties or insiders. Unauthorized access to these systems could result in interruptions, delays, loss of critical and/or sensitive data or similar effects, which could have a material adverse effect on the protection of intellectual property and confidential and proprietary information, and on the Company's business, financial condition, results of operations and fund flow.

Extraordinary Circumstances

Storm's operations and its financial condition may be affected by uncontrollable, unpredictable and unforeseeable circumstances such as weather patterns, changes in contractual, regulatory or fiscal terms, actions by governments at various levels, both domestic and other, termination of access to third-party pipelines or facilities, actions by industry organizations, local communities, militant groups, exclusion from certain markets or other undeterminable events.

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. The outbreak has spread exponentially throughout the world and despite the development and early stage deployment of vaccines, a second wave is underway with numerous variants that have since emerged. 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 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 significantly weakened in 2020 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; 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. During the financial year end of the Company, the appropriate officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company's disclosure controls and procedures and have concluded that the Company's disclosure controls and procedures are effective as of December 31, 2020.

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. During the financial year end of the Company, the appropriate officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company's internal controls over financial reporting and concluded that the Company's internal controls over financial reporting are effective as of December 31, 2020. 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 December 31, 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 – 2nd Street S.W., Calgary, Alberta T2P 1M4.

QUARTERY SUMMARIES

Thousands of Cdn$, except volumetric andper-share amounts	Q42020	Q32020	Q22020	Q12020	Q42019	Q32019	Q22019	Q12019
FINANCIAL
Revenue from product sales(1)	52,941	30,010	30,191	41,923	48,671	31,417	37,568	55,766
Funds flow	22,350	6,681	10,904	16,889	18,469	11,973	12,590	16,517
Per share - basic and diluted ($)	0.18	0.05	0.09	0.14	0.15	0.10	0.10	0.14
Net income (loss)	17,873	(16,934)	(11,665)	10,512	2,906	(64)	7,864	607
Per share - basic and diluted ($)	0.15	(0.14)	(0.10)	0.09	0.02	(0.00)	0.06	0.00
Cash return on capital employed ("CROCE")(2)	12%	11%	12%	12%	12%	15%	18%	20%
Return on capital employed ("ROCE")(2)(4)	2%	(2%)	2%	7%	4%	9%	11%	8%
Capital expenditures	16,163	14,219	2,394	26,475	23,913	32,841	23,145	16,944
Debt including working capital deficiency/
surplus(2)(3)	131,705	137,983	130,317	138,632	128,901	123,342	102,268	91,585
Common shares (000s)
Weighted average - basic	121,581	121,557	121,557	121,557	121,557	121,557	121,557	121,557
Weighted average - diluted	121,536	121,557	121,557	121,557	121,557	121,557	121,557	121,853
Outstanding end of period - basic	121,689	121,557	121,557	121,557	121,557	121,557	121,557	121,557
OPERATIONS
(Cdn$ per Boe)
Revenue from product sales(1)	22.15	17.14	13.86	19.24	23.64	18.36	20.72	31.26
Transportation costs	(4.81)	(6.43)	(5.50)	(4.97)	(5.20)	(5.83)	(5.96)	(5.72)
Revenue net of transportation	17.34	10.71	8.36	14.27	18.44	12.53	14.76	25.54
Royalties	(0.92)	(0.77)	(0.44)	(0.97)	(1.59)	0.19	(0.32)	(2.61)
Production costs	(4.13)	(4.84)	(4.50)	(5.17)	(5.67)	(5.88)	(5.89)	(6.09)
Field operating netback(2)	12.29	5.10	3.42	8.13	11.18	6.84	8.55	16.84
Realized gain (loss) on risk managementcontracts	(1.09)	0.51	2.99	1.26	(0.80)	1.64	(0.22)	(5.38)
General and administrative	(0.67)	(0.72)	(0.72)	(0.86)	(0.70)	(0.79)	(0.68)	(1.60)
Interest and finance costs	(0.96)	(1.08)	(0.68)	(0.74)	(0.71)	(0.69)	(0.71)	(0.61)
Decommissioning expenditures	(0.22)	-	(0.01)	(0.04)	-	-	-	-
Funds flow per Boe	9.35	3.81	5.00	7.75	8.97	7.00	6.94	9.25
Barrels of oil equivalent per day (6:1)	25,985	19,027	23,935	23,946	22,375	18,596	19,923	19,823
Natural gas production
Thousand cubic feet per day	124,927	91,526	114,772	115,957	108,679	91,053	97,510	96,537
Price (Cdn$ per Mcf)(1)	3.21	2.47	2.23	2.54	3.28	2.42	2.64	4.49
Condensate production
Barrels per day	2,502	1,637	2,305	2,623	2,416	1,856	2,081	2,199
Price (Cdn$ per barrel)(1)	52.04	46.79	25.92	60.66	66.56	63.45	71.12	62.77
NGL production
Barrels per day	2,662	2,136	2,501	1,998	1,846	1,564	1,591	1,534
Price (Cdn$ per barrel)(1)	16.41	10.95	6.23	3.27	6.11	2.29	4.87	31.43
Wells drilled (net)	3.0	4.0	-	1.0	-	1.0	-	5.0
Wells completed (net)	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 38 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 $6.5 million for the year ended December 31, 2020 (December 31, 2019 – unrealized gain of $1.5 million).

FINANCIALS

MANAGEMENT'S REPORT

To the Shareholders of Storm Resources Ltd.

The financial statements of Storm Resources Ltd. were prepared by management in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board. Management has used estimates and careful judgment, particularly in those circumstances where transactions affecting current periods are dependent on information not known for certain until a future period. The financial and operational information contained in this year-end report is consistent with that reported in the financial statements.

Management is responsible for the integrity of the financial and operational information contained in this report. The Company has designed and maintains internal controls to provide reasonable assurance that assets are properly safeguarded and that the financial records are well maintained and provide relevant, timely and reliable information to management. The financial statements have been prepared within reasonable limits of materiality and within the framework of the significant accounting policies summarized in the notes to the financial statements.

External auditors appointed by the shareholders have conducted an independent examination of the corporate and accounting records in order to express their opinion on the financial statements. The Audit Committee has met with the external auditors and management in order to determine if management has fulfilled its responsibilities in the preparation of the financial statements. The Board of Directors has approved the financial statements on the recommendation of the Audit Committee.

Michael J. Hearn Chief Financial Officer

Emily Wignes Vice President, Finance

March 2, 2021

INDEPENDENT AUDITORS' REPORT

To the Shareholders of Storm Resources Ltd.

Opinion

We have audited the consolidated financial statements of Storm Resources Ltd. and its subsidiaries ("Storm"), which comprise the consolidated statements of financial position as at December 31, 2020 and 2019, and the consolidated statements of income and comprehensive income, consolidated statements of changes in shareholders equity and consolidated statements of cash flows for the years then ended, and notes to the consolidated financial statements, including a summary of significant accounting policies.

In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the consolidated financial position of Storm as at December 31, 2020 and 2019, and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards (IFRSs).

Basis for Opinion

We conducted our audit in accordance with Canadian generally accepted auditing standards. Our responsibilities under those standards are further described in the Auditor's Responsibilities for the Audit of the Consolidated Financial Statements section of our report. We are independent of Storm in accordance with the ethical requirements that are relevant to our audit of the consolidated financial statements in Canada, and we have fulfilled our other ethical responsibilities in accordance with these requirements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.

Key Audit Matters

Key audit matters are those matters that, in our professional judgment, were of most significance in the audit of the consolidated financial statements of the current period. These matters were addressed in the context of the audit of the consolidated financial statements as a whole, and in forming the auditor's opinion thereon, and we do not provide a separate opinion on these matters. For each matter below, our description of how our audit addressed the matter is provided in that context.

We have fulfilled the responsibilities described in the Auditor's responsibilities for the audit of the consolidated financial statements section of our report, including in relation to these matters. Accordingly, our audit included the performance of procedures designed to respond to our assessment of the risks of material misstatement of the consolidated financial statements. The results of our audit procedures, including the procedures performed to address the matters below, provide the basis for our audit opinion on the accompanying consolidated financial statements.

Impairment of non-financial assets

The Company's balance sheet includes $509 million in property and equipment, and $99 million in exploration and evaluation assets. Note 3 of the consolidated financial statements describes the Company's accounting policy for impairment. Note 6 of the consolidated financial statements includes the Company's impairment disclosures. The Company performs an assessment of each cash-generating unit ("CGU") comprising this amount for indicators of impairment at each reporting date. Where indicators of impairment are identified, a detailed analysis to quantify the recoverable amount is required. Significant judgment is required in assessing the existence or non-existence of impairment indicators, and in performing the impairment test when indicators are identified, and therefore we have identified this as a key audit matter.

The Company concluded that indicators of impairment were present for the Umbach CGU due to the market capitalization of the Company being less than its net asset value, and therefore an impairment test was performed. The recoverable amounts used in the impairment test were estimated based on the fair value less costs of disposal ("FVLCD") method. Through our risk assessment procedures, we identified three key assumptions in the impairment test: the discount rate, long-term forecast commodity prices, and reserve estimates.

Among other procedures, we involved our internal valuations specialists to assess the methodology applied and the discount rate used to determine the recoverable amount by referencing current industry, economic, and comparable company information. We recalculated the recoverable amount and agreed inputs to applicable sources. We compared the forecast commodity prices relative to other third-party published forecast prices. We performed procedures to assess the competence, capability, and objectivity of the Company's external reserve engineer as a specialist. We assessed key reserve report figures for reasonability through comparison to historical results, third party sources, and the Company's budget. We assessed the completeness and accuracy of the Company's impairment disclosures in note 6 of the consolidated financial statements.

Other Information

Management is responsible for the other information. The other information comprises:

• Management's Discussion & Analysis
• The information, other than the consolidated financial statements and our auditor's report thereon, in the Annual Report

Our opinion on the consolidated financial statements does not cover the other information and we do not express any form of assurance conclusion thereon.

In connection with our audit of the consolidated financial statements, our responsibility is to read the other information, and in doing so, consider whether the other information is materially inconsistent with the consolidated financial statements or our knowledge obtained in the audit or otherwise appears to be materially misstated.

We obtained Management's Discussion & Analysis prior to the date of this auditor's report. If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are required to report that fact. We have nothing to report in this regard.

The Annual Report is expected to be made available to us after the date of the auditor's report. If based on the work we will perform on this other information, we conclude there is a material misstatement of other information, we are required to report that fact to those charged with governance.

Responsibilities of Management and Those Charged with Governance for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with IFRSs, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

In preparing the consolidated financial statements, management is responsible for assessing Storm's ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless management either intends to liquidate Storm or to cease operations, or has no realistic alternative but to do so.

Those charged with governance are responsible for overseeing Storm's financial reporting process.

Auditor's Responsibilities for the Audit of the Consolidated Financial Statements

Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor's report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with Canadian generally accepted auditing standards will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of these consolidated financial statements.

As part of an audit in accordance with Canadian generally accepted auditing standards, we exercise professional judgment and maintain professional skepticism throughout the audit. We also:

• Identify and assess the risks of material misstatement of the consolidated financial statements, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control.

• Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of Storm's internal control.
• Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by management.
• Conclude on the appropriateness of management's use of the going concern basis of accounting and, based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on Storm's ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw attention in our auditor's report to the related disclosures in the consolidated financial statements or, if such disclosures are inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor's report. However, future events or conditions may cause Storm to cease to continue as a going concern.
• Evaluate the overall presentation, structure and content of the consolidated financial statements, including the disclosures, and whether the consolidated financial statements represent the underlying transactions and events in a manner that achieves fair presentation.
• Obtain sufficient appropriate audit evidence regarding the financial information of the entities or business activities within Storm to express an opinion on the financial statements. We are responsible for the direction, supervision, and performance of Storm's audit. We remain solely responsible for our audit opinion.

We communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit.

We also provide those charged with governance with a statement that we have complied with relevant ethical requirements regarding independence, and to communicate with them all relationships and other matters that may reasonably be thought to bear on our independence, and where applicable, related safeguards.

The engagement partner on the audit resulting in this independent auditor's report is Ryan MacDonald.

Chartered Professional Accountants Calgary, Alberta

March 2, 2021

Consolidated Statements of Financial Position

(Canadian $000s)	Notes	December 31, 2020		December 31, 2019
ASSETS
Current
Accounts receivable	15	$	19,283	$	21,961
Prepaids and deposits			1,124		764
Risk management contracts	15		-		1,113
			20,407		23,838
Risk management contracts	15		233		-
Exploration and evaluation	5		98,886		99,737
Property and equipment	6		508,524		490,264
Right-of-use asset	9		2,220		2,657
		$	630,270	$	616,496
LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Accounts payable and accrued liabilities	15	$	17,721	$	30,018
Current portion of decommissioning liability	10		1,939		448
Current portion of lease liability	9		512		507
Risk management contracts	15		8,483		2,042
			28,655		33,015
Bank indebtedness	7, 15		134,391		121,608
Risk management contracts	15		101		904
Lease liability	9		1,850		2,234
Decommissioning liability	10		30,915		27,667
Deferred income taxes	11		10,823		9,360
			206,735		194,788
Shareholders' equity
Share capital	12		391,752		391,444
Contributed surplus	13		19,338		17,605
Retained earnings			12,445		12,659
			423,535		421,708
Commitments	19
		$	630,270	$	616,496

See accompanying notes to the consolidated financial statements.

On behalf of the Board:

Director

Director

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

(Canadian $000s except per-share amounts)	Notes	Year EndedDecember 31, 2020	Year EndedDecember 31, 2019
Revenue
Revenue from product sales	8	$155,065	$	173,422
Royalties		(6,589)		(8,169)
		$148,476	$	165,253
Realized gain (loss) on risk management contracts	15	7,542		(8,833)
		$156,018	$	156,420
Expenses
Production		39,401		43,274
Transportation		45,566		41,703
General and administrative		6,309		6,883
Share-based compensation	13	1,817		2,464
Depletion and depreciation	6, 9	46,578		40,506
Exploration and evaluation costs expensed	5	745		1,140
Accretion	10	338		492
Interest and finance costs		7,403		5,158
Unrealized (gain) loss on risk management contracts	15	6,518		(1,527)
Unrealized revaluation loss on investment		94		87
		154,769		140,180
Net income (loss) and comprehensive income (loss) before income taxes		1,249		16,240
Deferred income tax expense	11	1,463		4,927
Net income (loss) and comprehensive income (loss)		$(214)	$	11,313
Net income (loss) per share – basic and diluted	14	$(0.00)	$	0.09

See accompanying notes to the consolidated financial statements.

Consolidated Statements of Changes in Shareholders' Equity

(Canadian $000s)				Year Ended December 31, 2020
			Contributed	Retained
	Notes	Share Capital	Surplus	Earnings	Total Equity
Balance, beginning of year		$ 391,444	$ 17,605	$ 12,659	$ 421,708
Net loss for the year		-	-	(214)	(214)
Issue of common shares	12	224	-	-	224
Share-based compensation	13	-	1,817	-	1,817
Share-based compensation onstock options exercised	12	84	(84)	-	-
Balance, end of year		$ 391,752	$ 19,338	$ 12,445	$ 423,535

(Canadian $000s)				Year Ended December 31, 2019
	Notes	Share Capital	ContributedSurplus	RetainedEarnings	Total Equity
Balance, beginning of year		$ 391,444	$ 15,141	$1,346	$ 407,931
Net income for the year		-	-	11,313	11,313
Share-based compensation	13	-	2,464	-	2,464
Balance, end of year		$ 391,444	$ 17,605	$ 12,659	$ 421,708

See accompanying notes to the consolidated financial statements.

Consolidated Statements of Cash Flows

(Canadian $000s)	Notes	Year EndedDecember 31, 2020	Year EndedDecember 31, 2019
Operating activities
Net income (loss) for the year		$(214)	$11,313
Non-cash items:
Unrealized (gain) loss on risk management	15	6,518	(1,527)
Depletion, depreciation and accretion	6, 9, 10	46,916	40,998
Share-based compensation	13	1,817	2,464
Lease interest	9	128	147
Exploration and evaluation costs expensed	5	745	1,140
Unrealized revaluation loss on investment		94	87
Deferred income tax expense	11	1,463	4,927
Decommissioning expenditures	10	(643)	-
Funds flow		56,824	59,549
Net change in non-cash working capital items	18	(4,165)	8,957
		52,659	68,506
Financing activities
Payment on lease liability	9	(507)	(500)
Proceeds from issue of common shares	12	224	-
Increase in bank indebtedness		12,783	34,832
		12,500	34,332
Investing activities
Additions to property and equipment	6	(58,505)	(95,757)
Additions to exploration and evaluation assets	5	(746)	(2,169)
Disposition of exploration and evaluation assets	5	-	1,083
Net change in non-cash working capital items	18	(5,908)	(5,995)
		(65,159)	(102,838)
Change in cash during the year		-	-
Cash, beginning of year		-	-
Cash, end of year		$-	$-

See accompanying notes to the consolidated financial statements.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at and for years ended December 31, 2020 and 2019

Tabular amounts in thousands of Canadian dollars, except per share amounts

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 – 2nd Street S.W., Calgary, Alberta T2P 1M4. The Company became a reporting issuer in August 2010.

These audited 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 Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB"). 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 March 2, 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 15.

3. SUMMARY OF ACCOUNTING POLICIES

Exploration and Evaluation Expenditures

Exploration and evaluation ("E&E") expenditures are accounted for in accordance with IFRS 6 - Exploration for and Evaluation of Mineral Resources, whereby costs associated with the exploration for and evaluation of crude oil and gas reserves are accumulated on an area-by-area basis and are capitalized as E&E assets when incurred. Future decommissioning costs relating to E&E activities are also included. Costs incurred in advance of land acquisition are charged to the consolidated statement of income in the period in which they are incurred.

E&E costs are not subject to depletion or depreciation until they are reclassified from E&E to property and equipment ("P&E"). E&E costs are accumulated by field or exploration area pending determination of technical feasibility and commercial viability. Technical feasibility and commercial viability is typically considered to be achieved when proved reserves are determined to exist. Once reserves are assigned to specific lands, the associated E&E assets are tested for impairment and the lesser of cost and the estimated recoverable amount is reclassified to P&E.

Property and Equipment

P&E represents both intangible and tangible costs incurred in developing crude oil and natural gas reserves and maintaining or enhancing production from such reserves. Future decommissioning costs, related to producing assets, are also capitalized. P&E is carried at cost, less accumulated depletion and depreciation and accumulated impairment losses. Gains and losses on disposal of P&E are determined as the difference between proceeds from disposal and the carrying amount of the asset sold and are recognized in the consolidated statement of income.

Depletion and Depreciation

The net carrying amount of intangible crude oil and natural gas assets, categorized as P&E, is depleted using the unitof-production method based on estimated proved plus probable reserves, taking into account the future development costs required to produce the reserves.

Year-end proved plus probable reserves are determined by independent engineers in accordance with Canadian National Instrument 51-101. Production and reserves of natural gas are converted to equivalent barrels of crude oil on the basis of six thousand cubic feet of natural gas to one barrel of crude oil. Changes in estimates used in prior periods, such as proved plus probable reserves, that affect the unit-of-production calculations, do not give rise to prior year adjustments and are dealt with prospectively. Proved plus probable reserves at the end of each interim reporting period are based on reserves determined at the immediately prior year end, adjusted for production and internal estimates of changes to reserves since the prior year end.

Tangible costs, such as processing facilities and well equipment, are depreciated on a straight-line basis over the estimated useful life of the facilities and equipment. Where facilities and equipment includes major components having different useful lives, they are depreciated separately.

Depreciation rates, useful lives and residual values are reviewed at each reporting date.

Impairment of Non-Financial Assets

The carrying amounts of P&E and E&E assets are reviewed separately at each reporting date to determine whether there is any indication of impairment. If such an indication exists, the estimated recoverable amount is calculated.

For the purpose of impairment testing, assets are grouped together into the smallest group of assets that generates cash inflows that are largely independent of the cash flows of other assets or group of assets (the "cash generating unit" or "CGU"). CGU's are determined by similar geological formation and proximity, shared infrastructure, product type and similar exposure to market risks. The recoverable amount of an asset or CGU is the greater of its value in use and its fair value less costs of disposal. E&E assets are assessed for impairment at the operating segment level.

In assessing value in use, the estimated future cash flows are adjusted for the risks specific to the CGU and are discounted to their present value using a discount rate and future commodity prices that reflect current market assumptions. Fair value less costs of disposal ("FVLCD") is the amount obtainable from the sale of an asset or CGU in an arm's length transaction between knowledgeable, willing parties, less the costs of disposal. The Company calculates FVLCD by reference to the after-tax future cash flows expected to be derived from production of proved plus probable reserves less estimated selling costs. The estimated after-tax cash flows are discounted to their present value using a discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. An impairment loss is recognized in the consolidated statement of income if the carrying amount of an asset or CGU exceeds its estimated recoverable amount.

Impairment losses previously recognized are assessed at each reporting date for indications that the loss has decreased or no longer exists. If there has been an increase in the estimate of the recoverable amount an impairment loss is reversed to the extent that the asset's new carrying amount does not exceed the original carrying amount, net of related accumulated depletion and depreciation.

Lease Liabilities and Right-of-Use Assets

A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. At the lease commencement date, a lease liability is recognized at the present value of future lease payments, using the Company's incremental borrowing rate when the rate implicit in the lease is not readily available. A corresponding right-of-use asset is recognized at the amount of the lease liability, adjusted for lease incentives received and initial direct costs. The Company has elected not to recognize leases with a term of twelve months or less, or leases for low-value assets. Payments are applied against the lease liability and interest expense is recognized on the lease liability using the effective interest rate method. Depreciation is recognized on the right-of-use asset over the lease term.

Decommissioning Liability

Decommissioning liabilities are measured as the present value of management's best estimate of the expenditure required to settle the future decommissioning liability at the reporting date using a risk-free discount rate. This estimate is recognized when a legal or constructive obligation arises and is capitalized as part of E&E assets or P&E as appropriate. The amount capitalized to P&E is amortized on a unit-of-production basis consistent with the measurement of depletion. The obligation is adjusted at the end of each reporting period to reflect the passage of time and changes in the estimated future costs underlying the obligation. The increase in the obligation due to the passage of time is recognized as accretion expense in the consolidated statement of income whereas increases or decreases due to changes in the estimated future costs are capitalized. Actual costs incurred upon settlement of decommissioning obligations are charged against the liability; if actual costs exceed the liability recorded, the difference is charged to the consolidated statement of income.

Revenue Recognition

Revenue recognition from the sale of commodities is calculated by reference to consideration specified in contracts with customers and recognized when control of the product is transferred to the buyer. This is generally at the time the customer obtains legal title to the product and when it is physically transferred to the delivery mechanism agreed with the customer, often pipelines or other transportation methods.

The Company sells its production pursuant primarily to variable price contracts. The transaction price for variable priced contracts is based on the commodity price, adjusted for quality, location or other factors depending on the contract terms. Under its contracts, the Company is required to deliver volumes of natural gas, condensate and NGL to the contract counterparty. The amount of revenue recognized is based on the agreed transaction price, whereby any variability in revenue relates specifically to fluctuations in commodity prices. Natural gas, condensate and NGL are mostly sold under contracts of varying price and volume terms. Revenues are typically collected on the 25th day of the month following production.

The Company evaluates its arrangements with third parties and partners to determine if the Company acts as the principal or as an agent. In making this evaluation, management considers if the Company obtains control of the product delivered, which is indicated by the Company having the primary responsibility for the delivery of the product, having the ability to establish prices or having inventory risk. If the Company acts in the capacity of an agent rather than as a principal in a transaction, then the revenue is recognized on a net basis, only reflecting the fee, if any, realized by the Company from the transaction.

Transportation

Transportation expenses include costs incurred by the Company to transport natural gas and condensate from the wellhead to the point of title transfer.

Share-Based Compensation

The Company has a stock option plan, performance award incentive plan and a director share award plan (collectively, the "Plans"). Stock options are issued to directors, officers and employees. Performance awards can be issued to officers, employees, consultants and other service providers while director share awards are issued solely to directors.

Stock options are accounted for using the fair-value method which estimates the value of the options at the date of the grant using the Black-Scholes option pricing model. The fair value of the performance awards and director share awards is calculated based on the volume weighted average trading price over the five trading days immediately preceding the date of grant. Awards granted under the performance and director share awards plans may be settled in cash or in common shares purchased on the open market at the sole discretion of the Company. The total fair value associated with the Plans is recognized over the service period using graded vesting as share-based compensation expense with an equivalent increase to contributed surplus. An estimated forfeiture rate is applied to the total fair value at the grant date and is subsequently adjusted to reflect the actual number of options and share awards that vest. A performance multiplier is applied to grants under the performance award incentive plan and is estimated on the date of grant to reflect the number of performance awards that are expected to vest. The performance multiplier is based on an assessment of the Company's achievement of predefined corporate performance measures, as approved by the Board of Directors of the Company. At the time at which options and share awards vest, the previously recognized fair value in contributed surplus is transferred to share capital. Consideration received by the Company on the exercise of options is recorded as an increase to share capital.

Government Grants

Government grants are recognized when there is reasonable assurance that the Company will comply with the conditions attached to them and the grants will be received. When the conditions of a grant relate to income or expenses, it is recognized in the consolidated statement of income in the period in which the expenditures are incurred or income is earned. When the conditions of a grant relate to an underlying asset, it is recognized as a reduction to the carrying amount of the related asset and amortized into income on a systematic basis over the expected useful life of the underlying asset through reduced depletion and depreciation expense.

Financial Instruments

Financial assets and liabilities are recognized when the Company becomes a party to the contractual provisions of the instrument. Financial assets are de-recognized when the rights to receive cash flows from the instruments have expired, or when the Company has transferred substantially all risks and rewards of ownership.

Financial instruments are measured at fair value upon initial recognition. Measurement in subsequent periods is dependent on the financial instrument's classification, as described below:

• Fair value through profit or loss ("FVTPL") Financial assets and liabilities designated at fair value through profit or loss are initially recognized and subsequently measured at fair value with subsequent changes in fair value charged to the consolidated statement of income. The Company classifies its risk management contracts as FVTPL financial instruments.
• Amortized cost Certain financial assets and liabilities are initially recognized at fair value, net of directly attributable transaction costs, and subsequently measured at amortized cost using the effective interest rate method, net of any impairment. The Company includes accounts receivable, accounts payable and accrued liabilities and bank indebtedness within the amortized cost category.
• Fair value through other comprehensive income ("FVTOCI") Financial assets designated at fair value through other comprehensive income are measured at fair value with changes in fair value recognized in other comprehensive income, net of tax. The Company does not currently have any financial assets classified as FVTOCI.

Financial assets and liabilities are offset and the net amount reported in the consolidated statement of financial position when there is a legally enforceable right to offset the recognized amounts, and there is an intention to settle on a net basis, or realize the asset and settle the liability simultaneously.

Any subsequent reclassification of financial assets and liabilities from their initial recognition will be reclassified on the first day of the reporting period.

Impairment of financial assets

Impairment of financial assets is determined by measuring the assets' expected credit losses ("ECLs"). Due to the nature of its financial assets, the Company measures loss allowances at an amount equal to expected lifetime ECLs. Lifetime ECLs are the anticipated ECLs that result from all possible default events over the expected life of a financial asset. ECLs are a probability-weighted estimate of credit losses. Credit losses are measured as the present value of all cash shortfalls, which is measured as the difference between the present value of the cash flows due to the Company and the cash flows that the Company expects to receive. In making an assessment as to whether financial assets are credit impaired, the Company considers historically realized bad debts, evidence of a deterioration of a debtor's financial condition, evidence that a debtor will enter bankruptcy, increase in the number of days the debtor is past due and changes in economic condition that could correlate to increased risk of default. ECLs are discounted at the effective interest rate of the related financial asset. The Company does not have any financial assets that contain a financing component since accounts receivable are due within one year or less.

Risk management contracts

Risk management contracts may be used by the Company to manage exposure to market risks related to commodity prices, exchange rates and interest rates. Storm does not use derivative contracts for speculative purposes. The Company does not designate its derivative contracts as hedges and, as such, does not apply hedge accounting. All derivative contracts are classified as fair value through profit and loss financial instruments.

Income Tax

Income tax comprises current and deferred taxes. Income tax is recognized in the consolidated statement of income except to the extent that it relates to items recognized directly in other comprehensive income or elsewhere in shareholders' equity, in which case the related income tax expense or recovery is similarly recognized in the appropriate account.

Current tax expense is the expected cash tax payable on the taxable income for the year, using tax rates enacted, or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

In general, deferred income tax expense and the related liability is recognized in respect of temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the financial statements. Deferred income tax is determined on a non-discounted basis using tax rates and laws that have been enacted or substantively enacted at the reporting date and are expected to continue to apply when the deferred tax asset or liability is settled. Deferred tax assets are recognized to the extent that it is probable that the assets can be recovered. Deferred income tax assets and liabilities are presented as non-current on the consolidated statement of financial position.

Joint Arrangements

Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights and obligations of the parties to the arrangement. Joint operations arise when the Company has rights to the assets and obligations for the liabilities of the arrangement. Certain of the Company's exploration and production activities are conducted through joint operations and, accordingly, the financial statements reflect the Company's share of these assets, liabilities, revenues and expenses. Joint control exists for contractual arrangements governing the Company's assets whereby the Company has less than 100% working interest, all of the partners have control of the arrangement collectively, and spending on the project requires unanimous consent of all parties that collectively control the arrangement and share the associated risks.

Share Capital

Proceeds from the issuance of common shares are classified as shareholders' equity. Costs directly attributable to the issuance of shares are recognized as a deduction from shareholders' equity.

Per-Share Amounts

Basic net income (loss) per share is calculated by dividing the net income (loss) attributable to equity owners for the reporting period by the weighted average number of common shares outstanding during the reporting period.

Diluted net income (loss) per share is calculated by adjusting the weighted average number of common shares outstanding for dilutive instruments. The Company's potentially dilutive instruments comprise stock options granted to directors, officers and employees. The number of shares included with respect to options is computed using the treasury stock method, which assumes that proceeds received from the exercise of in-the-money stock options are used to purchase common shares at average market prices during the period.

4. 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.

In March 2020, the World Health Organization declared the COVID-19 outbreak a global pandemic. The rapid outbreak and subsequent measures intended to limit the spread of COVID-19 have contributed to a significant increase in economic uncertainty, with more volatile commodity prices, currency exchange rates and interest rates. The duration and severity of the business disruptions and 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.

Critical judgments applied by management to accounting policies that have the most significant effect on the amounts in the financial statements are as follows:

Classification and Carrying Amount of Exploration and Evaluation Assets

Each reporting period, E&E assets are subject to an internally conducted impairment review. Factors brought into the consideration of impairment include the Company's future plans for the property, lease expiries, drilling and development results on proximate or analogous properties, facility and pipeline access, views as to future commodity prices, operating and development costs and availability of capital for exploration and development programs. Judgment is required to determine the level at which E&E is assessed for impairment. E&E assets are assessed for impairment at the operating segment level. An impairment assessment is also completed when the costs of E&E assets are transferred to P&E on a specific identification basis.

Carrying Amount of Property and Equipment

Each reporting period, P&E is subject to an impairment review applied at the CGU level. The impairment review gives recognition to changes in geological interpretation or development plans, drilling results, development costs, changes to reserve estimates and values, future commodity prices, facility and pipeline access, operating results, operating and future development costs, industry activity in the area, access to markets and availability of development capital.

Depletion, Impairment and Reserves

The amounts recorded for depletion and impairment testing are based on estimates of proved plus probable reserves. Significant judgment and estimates are required to calculate the recoverable amount on non-financial assets. The Company estimates the recoverable amount of non-financial assets, including P&E and E&E, based on its FVLCD, calculated using the after-tax future cash flows expected to be derived from production of proved plus probable crude oil and natural gas reserves, less estimated selling costs, discounted using market-based rates to reflect a market participant's view of the risks associated with the assets.

Assumptions that are valid at the time of reserve estimation may change materially as new information becomes available. Reserves estimates are based on engineering data, forward price estimates, production and future development costs, recovery rates or decommissioning costs, all of which may change the economic status of reserves and may ultimately result in reserves used for measurement purposes being removed from similar calculations in future reporting periods. Reserves have been evaluated at December 31, 2020 and 2019 by the Company's independent qualified reserves evaluator.

Decommissioning Liability

Measurement of the Company's decommissioning liability involves estimates as to the cost and timing of incurrence of future decommissioning programs. It also involves assessment of appropriate discount rates, rates of inflation applicable to future costs and the rate used to measure the accretion charge for each reporting period. Measurement of the liability also reflects current engineering methodologies as well as current and expected future environmental legislation and standards.

Measurement and Utilization of Tax Assets

The Company has tax pools which may be applied in reduction of future income. The amount of such pools is subject to audit by taxing authorities, possibly several years after the initial measurement. In addition, future changes to tax laws may result in the loss or limitation of use of such pools.

Measurement of Share-Based Compensation

The charge for share-based compensation involves the estimate of the fair value of stock options at time of issue. The estimate involves assumptions regarding the life of the option, dividend yields, interest rates, and volatility of the security subject to the option. The charge is measured using the Black-Scholes option pricing model, which could be replaced by a pricing model producing different results.

Carrying Amounts of Financial Instruments

Financial instruments are subject to valuation at the end of each reporting period. Generally the valuation is based on active and efficient markets. However, certain financial instruments may not be traded on an efficient market, or the market may disappear or be subject to circumstances or controls that impede the efficiency of the market.

5. EXPLORATION AND EVALUATION

	Year EndedDecember 31, 2020	Year EndedDecember 31, 2019
Balance, beginning of year	$99,737	$	102,277
Additions	746		2,169
Dispositions	-		(1,083)
Expiries - exploration and evaluation costs expensed	(745)		(1,140)
Future decommissioning costs	35		178
Transfer to property and equipment	(887)		(2,664)
Balance, end of year	$98,886	$	99,737

For the year ended December 31, 2020, the Company determined certain of its E&E assets to be technically feasible and commercially viable and they were, therefore, transferred to P&E. An impairment test was conducted prior to the transfer (determined using the same methodology outlined in Note 6 – Property and Equipment), but no impairment was recognized as the recoverable amount of these assets exceeded the carrying value.

As at December 31, 2020, management reviewed the carrying amounts of the remaining assets in E&E for indicators of potential impairment and concluded that there are no indicators of potential impairment.

6. PROPERTY AND EQUIPMENT

	Year Ended	Year Ended
	December 31, 2020		December 31, 2019
Cost
Balance, beginning of year	$746,515	$	646,983
Additions	58,505		95,757
Future decommissioning costs	5,009		1,111
Transfer from exploration and evaluation assets	887		2,664
Balance, end of year	$810,916	$	746,515
Accumulated depletion and depreciation
Balance, beginning of year	$(256,251)	$	(216,182)
Depletion and depreciation	(46,141)		(40,069)
Balance, end of year	$(302,392)	$	(256,251)
Net book value, beginning of year	$490,264	$	430,801
Net book value, end of year	$508,524	$	490,264

Future capital costs required to develop proved plus probable reserves in the amount of $504.9 million (December 31, 2019 - $566.2 million) are included in the depletion calculation.

As at December 31, 2019, the balance of assets under construction not subject to depreciation or depletion was $65.0 million and related to construction of the Nig Creek Gas Plant located in northeast British Columbia. In February 2020, construction of the Nig Creek Gas Plant was completed and the gas plant is being depreciated on a straight-line basis over its estimated useful life of 35 years.

Impairment Assessment and Testing

In accordance with IFRS, an impairment test is performed if the Company identifies an indicator of impairment. At December 31, 2020, the Company determined that an indicator of impairment existed for its material producing CGU at Umbach as the market capitalization of the Company was less than the net asset value.

Given the ongoing changes in the overall business environment and current uncertainties in commodity markets, the Company reviewed externally available forward commodity prices and noted specifically a decline in WTI crude oil prices. Although there was a decline in crude oil prices, the Company earns revenues through a diversified marketing strategy including approximately 80% of production attracting natural gas pricing.

An impairment is recognized if the carrying value of an asset exceeds the recoverable amount. The Company determines the recoverable amount by using discounted future cash flows of proved plus probable reserves using forecast prices and costs.

Forecast future prices, as prepared by an independent qualified reserve evaluator, used in the impairment evaluation as at December 31, 2020, reflect the benchmark prices set forth in the table below, adjusted for basis differentials to determine local reference prices, transportation costs and tariffs, heat content and quality.

	2021	2022	2023	2024	2025	2026	2027(1)
WTI Cushing Oklahoma (US$/Bbl)	48.00	51.00	54.00	55.08	56.18	57.31	58.45
NYMEX Henry Hub (US$/Mmbtu)	2.85	2.91	2.97	3.02	3.08	3.15	3.21
AECO-C Spot (Cdn$/Mmbtu)	2.80	2.71	2.62	2.67	2.73	2.78	2.84
Station 2 (Cdn$/Mmbtu)	2.75	2.66	2.57	2.62	2.68	2.73	2.79
Exchange rate (US$/Cdn$)	0.77	0.77	0.77	0.77	0.77	0.77	0.77

(1) Prices escalate at 2% thereafter.

Recoverable amounts were estimated based on a fair value less costs of disposal ("FVLCD") methodology, using the present value of the CGUs expected after-tax future cash flows. The cash flow information was derived from a report on the Company's crude oil and natural gas reserves which was prepared by an independent qualified reserve evaluator. The projected cash flows used in the FVLCD calculation reflect market assessments of key assumptions as at December 31, 2020, including long-term forecasts of commodity prices, inflation rates and foreign exchange rates (Level 3 fair value inputs as described in Note 15). Future cash flow estimates are discounted using after-tax risk-adjusted discount rates. The after-tax discount rate applied in the impairment calculation as at December 31, 2020 was 10%. All else being equal, a 1% increase in the assumed discount rate or a 10% decrease in future planned funds flows would not result in an impairment for the year ended December 31, 2020.

As at December 31, 2020, the Company determined that there was no impairment to P&E.

7. BANK INDEBTEDNESS

As at December 31, 2020, the Company had an extendible revolving credit facility in the amount of $190 million (December 31, 2019 - $205 million) based on a bank determined borrowing base related to the Company's producing reserves. Although the borrowing base was set at $205 million, the Company voluntarily reduced the credit facility amount to $190 million in order to reduce the associated fees. 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.

As at December 31, 2020, the Company had issued letters of credit in the amount of $13.7 million (December 31, 2019 - $10.0 million) in support of future natural gas transportation and processing obligations.

At December 31, 2020, bank debt including outstanding letters of credit amounted to $148.1 million, representing approximately 78% of the available credit facility.

8. REVENUE FROM PRODUCT SALES

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

		Year Ended	Year Ended
	December 31, 2020		December 31, 2019
Natural gas	$	107,943	$	115,488
Condensate		38,939		51,522
NGL		8,183		6,412
Total	$	155,065	$	173,422

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 91% and 92% of the Company's total revenue from product sales for the three months and year ended December 31, 2020, respectively (December 31, 2019 - 80% and 81%, respectively, from two major customers). 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 year ended December 31, 2020, 54% received Chicago pricing, 19% received BC Station 2 pricing, 14% received AECO pricing, 8% received Sumas pricing and the remaining 5% received ATP pricing.

9. 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:

	Year EndedDecember 31, 2020	Year EndedDecember 31, 2019
Cost
Balance, beginning of year	$3,094	$	3,094
Additions	-		-
Balance, end of year	$3,094	$	3,094
Accumulated depreciation
Balance, beginning of year	$(437)	$	-
Depreciation	(437)		(437)
Balance, end of year	$(874)	$	(437)
Net book value, beginning of year	$2,657	$	3,094
Net book value, end of year	$2,220	$	2,657

As at December 31, 2020, the net book value of the right-of-use asset for the Company's corporate office lease in Calgary is $2.2 million (December 31, 2019 - $2.7 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:

	Year EndedDecember 31, 2020		Year EndedDecember 31, 2019
Balance, beginning of year	$	2,741	$3,094
Lease payments		(507)	(500)
Lease interest		128	147
Balance, end of year	$	2,362	$2,741
Less current portion		512	507
Long-term portion	$	1,850	$2,234

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%.

As at December 31, 2020, the total undiscounted amount of the estimated future cash flows to settle the Company's lease liability over the remaining lease term is $2.7 million.

Short-term leases are leases with a lease term of twelve months or less. During the year ended December 31, 2020, short-term lease costs of approximately $2.2 million (December 31, 2019 - $1.7 million) were incurred primarily relating to the lease of drilling equipment which was captured within property and equipment costs.

10. 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 $40.5 million (December 31, 2019 - $38.3 million), with the majority of payments being made in the years 2034 to 2054. A risk-free discount rate of 1.2% (December 31, 2019 – 1.7%) and an inflation rate of 1.5% (December 31, 2019 – 1.4%) was used to calculate the present value of the decommissioning obligation, amounting to $32.9 million at December 31, 2020.

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

	Year Ended	Year Ended
	December 31, 2020		December 31, 2019
Balance, beginning of year	$28,115	$	26,334
Obligations incurred	1,282		2,706
Obligations settled	(643)		(246)
Change in estimates(1)	3,762		(1,171)
Accretion expense	338		492
Balance, end of year	$32,854	$	28,115
Less current portion	1,939		448
Long-term portion	$30,915	$	27,667

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

11. DEFERRED INCOME TAXES

Deferred income tax assets and liabilities are based on the differences between the accounting amounts and the related tax bases of the Company's E&E and P&E assets, risk management contracts, decommissioning liability and unrealized gains and losses on investments.

Storm was not required to pay income taxes in the current or prior year as the Company had sufficient income tax deductions available to shelter taxable income. The Company has tax pools associated with E&E and P&E of approximately $306 million as well as non-capital losses of approximately $200 million. The non-capital losses begin to expire in 2027.

The provision for deferred income taxes is different from the amount computed by applying the combined statutory Canadian federal and provincial tax rates to pre-tax income for the year. The differences are as follows:

	Year EndedDecember 31, 2020	Year EndedDecember 31, 2019
Net income before income taxes	$1,249	$16,240
Statutory combined federal and provincial income tax rate	26.3%	26.8%
Expected income tax expense	$328	$4,353
Add (deduct) the income tax effect of:
Share-based compensation	477	660
Change in estimated tax pool balances	305	-
Change in corporate tax rate	(152)	(471)
Other	505	385
Deferred income tax expense	$1,463	$4,927

The components of the deferred income tax assets and liabilities are as follows:

	As at	As at
	December 31, 2020	December 31, 2019
Deferred tax assets:
Non-capital losses	$51,193	$50,494
Decommissioning liability	8,388	7,145
Fair value of risk management contracts	2,132	466
Investments	-	283
Deferred tax liabilities:
Property and equipment in excess of tax basis	$(72,536)	$(67,748)
Deferred income tax asset (liability)	$(10,823)	$(9,360)

12. 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

	Number of Common Shares (000s)	Consideration
Balance as at December 31, 2019	121,557	$391,444
Shares issued on stock option exercises	132	308
Balance as at December 31, 2020	121,689	$391,752

During 2020, 132,000 common shares were issued upon the exercise of stock options for proceeds of $224,000 and related prior period share-based compensation of $84,000 was transferred to share capital from contributed surplus.

For the period from January 1, 2021 to March 2, 2021, the date of this report, 24,000 common shares were issued upon the exercise of stock options for proceeds of $34,320.

13. 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 December 31, 2020, a total of 12,168,881 common shares were available for issuance, options in respect of 10,192,330 common shares were issued and outstanding and options in respect of 1,976,551 common shares were available for future issue.

At March 2, 2021, the date of this report, options in respect of 10,034,330 common shares are issued and outstanding and options in respect of 2,136,951 common shares are available for future issue.

Details of the options outstanding at December 31, 2020 and 2019 are as follows:

		Weighted Average
	Number of Options (000s)	Exercise Price
Outstanding at December 31, 2018	9,088	$	3.29
Granted during the year	3,017	$	1.52
Cancelled/forfeited during the year	(184)	$	3.34
Expired during the year	(1,733)	$	3.38
Outstanding at December 31, 2019	10,188	$	2.74
Granted during the year	2,435	$	2.00
Exercised during the year	(132)	$	1.70
Cancelled/forfeited during the year	(325)	$	2.16
Expired during the year	(1,974)	$	5.39
Outstanding at December 31, 2020	10,192	$	2.09
Number exercisable at December 31, 2020	4,346	$	2.30

Range of Exercise Price	Outstanding Options				Exercisable Options
	Number of	Weighted	Weighted	Number of	Weighted
	Options	Average	Average	Options	Average
	Outstanding	Remaining	Exercise	Outstanding	Exercise
	(000s)	Life (years)	Price	(000s)	Price
$1.11 - $1.70	2,942	3.0	$1.47	901	$1.49
$1.71 - $2.13	4,472	2.9	$1.94	1,535	$1.81
$2.14 - $5.27	2,778	1.0	$2.98	1,910	$3.07
Total	10,192	2.4	$2.09	4,346	$2.30

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 year ended December 31, 2020 of $0.72 per share (2019 - $0.56 per share) include the following:

	2020	2019
Share price	$1.11 - $2.20	$1.36 - $2.35
Exercise price	$1.11 - $2.20	$1.36 - $2.35
Volatility	48%	48%
Forfeiture rate	2%	2%
Expected option life (years)	3.7	3.7
Risk-free interest rate	0.3% - 1.4%	1.4% - 1.7%

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 fair 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.

Details of the performance awards and director share awards outstanding at December 31, 2020 and 2019 are as follows:

	Number of PerformanceAwards (000s)	Number of DirectorShare Awards (000s)
Outstanding at December 31, 2019 and December 31, 2018	-	-
Granted during the year	624	82
Outstanding at December 31, 2020	624	82

Share-Based Compensation Expense

Share-based compensation expense of $1.8 million was charged to the consolidated statement of income (loss) during the year ended December 31, 2020 (2019 - $2.5 million) with an equivalent offset to contributed surplus.

14. NET INCOME (LOSS) PER SHARE

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

	Year Ended	Year Ended
	December 31, 2020	December 31, 2019
Net income (loss) for the year	$(214)	$11,313
Weighted average number of common shares outstanding – basic
Common shares outstanding at beginning of year	121,557	121,557
Effect of shares issued	6	-
Weighted average number of common shares outstanding – basic	121,563	121,557
Dilutive effect of outstanding share-based awards(1)	-	-
Weighted average number of common shares outstanding - diluted	121,563	121,557
Net income (loss) per share
Basic and diluted	$(0.00)	$0.09

(1) For the year ended December 31, 2020, the Company incurred a net loss and therefore there was no dilutive effect of stock options. For the year ended December 31, 2019, 9.2 million weighted average common shares related to stock options were anti-dilutive.

15. 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 years ended December 31, 2020 and December 31, 2019.

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 December 31, 2020:

	Gross AmountsRecognized as FinancialAssets (Liabilities)		Gross Amountsof Financial Assets(Liabilities) Offset		Recognized as Financial	Net AmountsAssets (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)
Net position	$	(8,351)	$	-	$	(8,351)

The following is a summary of the Company's financial assets and financial liabilities that are subject to offset as at December 31, 2019:

	Recognized as Financial	Gross AmountsAssets (Liabilities)	of Financial Assets	Gross Amounts(Liabilities) Offset	Recognized as Financial	Net AmountsAssets (Liabilities)
Risk management contracts
Current asset	$	1,805	$	(692)	$	1,113
Long-term asset		-		-		-
Current liability		(2,734)		692		(2,042)
Long-term liability		(904)		-		(904)
Net position	$	(1,833)	$	-	$	(1,833)

Financial Risk Management

The Company's activities expose it to a variety of financial risks that arise as a result of its exploration, development, production, marketing and financing activities such as:

• credit risk;
• market risk; and
• liquidity risk.

Management has primary responsibility for monitoring and managing financial risks under direction from the Board of Directors, which has overall responsibility for establishing the Company's risk management framework.

Credit Risk

Credit risk is the risk of financial loss to the Company if a customer, joint operations partner or counterparty to a financial instrument fails to meet its contractual obligations.

Cash

When the Company has a cash surplus, it limits its exposure to credit risk by only investing in liquid securities and only with counterparties that have an acceptable credit rating or are supported by provincial government guarantees.

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 25th 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 December 31, 2020, the Company's three major energy customers with investment grade credit ratings accounted for $16.9 million of total receivables (December 31, 2019 - $17.0 million from two major customers) and 92% of total revenues (December 31, 2019 - 81%). 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 December 31, 2020 and 2019, 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 December 31, 2020.

The maximum exposure to credit risk at December 31, 2020 was the carrying amount of accounts receivable of $19.3 million and risk management contract assets of $0.2 million. No receivables were impaired at December 31, 2020.

Risk Management Contracts

The Company enters into derivative risk management contracts with counterparties with an acceptable credit rating and with a demonstrated capability to execute such contracts. The contracts, individually and in aggregate, are subject to controls established by the Board of Directors and limitations set out in the Company's banking agreement.

Market Risk

Market risk is the risk that changes in market prices will affect the Company's income or the value of its financial instruments. The objective of market risk management is to manage and control market risk exposures within acceptable parameters, while optimizing the return.

Market risks are as follows and are largely outside the control of the Company:

• commodity prices;
• interest rates; and
• foreign currency exchange rates.

Commodity Price Risk

Commodity price risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for crude oil, natural gas, condensate and natural gas liquids are affected by many known and unknown factors such as demand and supply imbalances, market access, the relationship between the Canadian and United States dollar as well as national and international economic and geopolitical events.

The Company is exposed to the risk of declining prices for production resulting in a corresponding reduction in projected funds flow. Reduced funds flow may result in lower levels of capital being available for field activity, thus compromising the Company's capacity to grow total production while at the same time replacing continuous production declines from existing properties. Bank financing available to the Company is in the form of a reserves based loan, which is reviewed semi-annually, and is based on future funds flows and commodity price expectations. Changes to commodity prices will have an effect on credit available to the Company under its banking agreement.

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 December 31, 2020, 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.

As at March 2, 2021		2021	2022
Natural Gas
NYMEX swap	Mmbtu/d	3,000	-
	US$/Mmbtu	$2.51	-
NYMEX swap	Mmbtu/d	6,814	-
	Cdn$/Mmbtu	$3.36	-
NYMEX collar	Mmbtu/d	1,575	2,589
	US$/Mmbtu	$2.57 - $3.04	$2.78 - $3.51
NYMEX collar	Mmbtu/d	5,159	2,219
	Cdn$/Mmbtu	$3.48 - $4.02	$3.53 - $4.14
Chicago swap	Mmbtu/d	752	8,448
	US$/Mmbtu	$3.11	$2.56
Chicago swap	Mmbtu/d	18,026	1,110
	Cdn$/Mmbtu	$3.20	$3.65
AECO swap	GJ/d	9,107	986
	Cdn$/GJ	$2.25	$2.91
AECO collar	GJ/d	4,279	1,981
	Cdn$/GJ	$2.03 - $2.58	$2.32 - $3.14
BC Station 2 swap	GJ/d	23,778	9,297
	Cdn$/GJ	$2.04	$2.36

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:

As at March 2, 2021		2021	2022
Natural Gas Differential Swaps
NYMEX:Chicago	Mmbtu/d	13,697	2,589
	US$/Mmbtu	($0.23)	$0.04
NYMEX:Chicago	Mmbtu/d	2,729	2,219
	Cdn$/Mmbtu	$0.05	$0.05
AECO:BC Station 2	GJ/d	1,726	1,488
	Cdn$/GJ	($0.10)	($0.01)
Crude Oil
WTI swap	Bbls/d	-	149
	US$/Bbl	-	$51.43
WTI swap	Bbls/d	800	-
	Cdn$/Bbl	$53.41	-
WTI collar	Bbls/d	976	298
	Cdn$/Bbl	$52.09 - $61.91	$58.00 - $68.33
WTI collar	Bbls/d	100	100
	US$/Bbl	$44.00 - $54.23	$46.00 - $55.25
Crude Oil Differential Swaps
WTI:C5	Bbls/d	1,100	-
	Cdn$/Bbl	($3.83)	-
Propane
Conway swap	Bbls/d	50	-
	Cdn$/Bbl	$27.30	-
Argus Far East Index swap	Bbld/d	88	-
	Cdn$/Bbl	$46.31	-
Argus Far East Index swap	Bbls/d	88	-
	US$/Bbl	$37.91	-

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.

	Daily Volume	Contract Price
Natural Gas
Jan 2021 – Oct 2021	5,000 GJ at Station 2	AECO 7A less Cdn$0.125/GJ
Jan 2021 – Mar 2021	6,000 GJ at ATP	AECO 5A plus Cdn$0.09/GJ
Apr 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 7A plus Cdn$0.115/GJ

Interest Rate Risk

Interest on the Company's revolving bank facility varies with changes in market interest rates and is most commonly based on bankers acceptances issued by the Company's banks, plus a stamping fee. The stamping fee may change based on the Company's debt-to-funds-flow ratio for the previous quarter. The Company is thus exposed to increased borrowing costs during periods of increasing interest rates, with a corresponding reduction in both funds flows and project economics. In addition, a higher debt-to-cash-flow ratio will mean an increase in stamping fees, and correspondingly, interest rates.

The Company is exposed to interest rate risk in relation to interest expense on its revolving credit facility. If interest rates applicable to floating rate debt were to have increased by 100 basis points (1%) it is estimated that the Company's net income for the year ended December 31, 2020 would have decreased by $0.9 million. A decrease in interest rates by 1% would result in an increase in net income by an equivalent amount.

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. Interest rate swaps are classified as derivative financial assets and liabilities 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. This interest rate swap is included on the balance sheet as either a risk management contract asset or liability and is classified as current or non-current based on the contractual terms specific to the instrument. As at December 31, 2020, 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	Jan 2021 – May 2022	1.949%
One-month bankers' acceptance - CDOR(1)	Jan 2020	$10 million	Jan 2021 – Jan 2023	1.943%
One-month bankers' acceptance - CDOR(1)	Jan 2020	$15 million	Jan 2021 – Jan 2021	1.985%

(1) Canadian Dollar Offered Rate.

Subsequent to December 31, 2020, the Company entered into the following interest rate swap contract to manage interest rate risk:

		Notional		Fixed
Index	Effective Date	Principal	Remaining Term	Contract Rate
One-month bankers' acceptance - CDOR(1)	Jan 2021	$15 million	Feb 2021 – Jan 2024	0.66%

(1) Canadian Dollar Offered Rate.

Foreign Currency Exchange Rate Risk

Prices for crude oil are determined in global markets and generally denominated in US dollars. Natural gas prices are largely influenced by both US and Canadian supply and demand structures. Changes in the Canadian dollar relative to the US dollar affect the Company's natural gas revenue, some of which is sold at a US$ price; therefore, variation in the Canadian-US dollar exchange rate will affect Canadian dollar prices for the Company's production. In addition, costs of imported materials used in the Company's operations will be affected by the Canadian-US dollar exchange 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 December 31, 2020 was a net liability position of $8.4 million (December 31, 2019 - net liability position of $1.8 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 year ended December 31, 2020, this resulted in an unrealized mark-to-market loss of $6.5 million (December 31, 2019 - an unrealized mark-to-market gain of $1.5 million) 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 a gain from risk management contracts in place in the amount of $7.5 million for the year ended December 31, 2020 (December 31, 2019 - realized loss of $8.8 million).

Sensitivities

The following table summarizes the effects of movement in commodity prices and interest rates on net income (loss) due to changes in the fair value of risk management contracts in place at December 31, 2020. 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.

	Year Ended December 31, 2020
Factor		Gain/(Loss)
Increase of US$5.00/Bbl in the price of WTI(1)	$	(2,570)
Decrease of US$5.00/Bbl in the price of WTI(1)	$	2,570
Increase of US$0.10/Mmbtu in the price of NYMEX natural gas	$	(3,763)
Decrease of US$0.10/Mmbtu in the price of NYMEX natural gas	$	3,763
Increase of 100 basis points (1%) in interest rates	$	575
Decrease of 100 basis points (1%) in interest rates	$	(575)

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

Liquidity Risk

Liquidity difficulties would emerge if the Company is unable to establish or maintain a profitable production base and thus generate sufficient funds flow to cover both operating and capital requirements. This may be the consequence of insufficient funds flows resulting from low product prices, production interruptions, operating or capital cost increases, unsuccessful investment programs, limitations in the Company's access to markets, or delays in bringing on stream new wells or facilities. These risks cannot be eliminated; however, the Company uses the following guidelines to address financial exposure:

• internal funds flow provides the initial source of funding on which the Company's capital expenditure program is based;
• debt, if available, may be utilized to expand capital programs, including acquisitions, when it is deemed appropriate and where debt retirement can be controlled;
• equity, if available on acceptable terms, may be raised to fund acquisitions and exploration expenditures;
• farm-outs of projects may be arranged if management concludes that a project requires too much capital or where the project affects the Company's investment risk profile.

The timing of cash flows related to financial liabilities as at December 31, 2020 is as follows:

	Less than 1 year	2-3 years	Total
Accounts payable and accrued liabilities	$17,721	$-	$17,721
Risk management contracts	8,483	101	8,584
Bank indebtedness(1)	-	134,391	134,391
Total financial liabilities	$26,204	$134,492	$160,696

(1) Bank indebtedness is based on a revolving credit facility, which is reviewed annually. At renewal, the Company has the option to extend the facility for an additional year. If the revolving facility is not extended, the facility converts to a non-revolving facility payable in one year.

16. CAPITAL MANAGEMENT

The Company's capital structure comprises shareholders' equity and bank indebtedness. The Company's objective when managing capital is to maintain financial flexibility to support capital programs that will replace production sold as well as production declines and provide a base for future growth in production. Capital management involves the preparation of an annual budget, which is implemented after approval by the Company's Board of Directors. As the Company's business evolves throughout the year, the budget will be amended; however, any changes are again subject to approval by the Board of Directors.

Funds flow, bank financing and potential proceeds from the issue of equity and the sale of assets will be invested in exploration and development operations with the intent of growing short and medium term operating funds flow. Growing funds flow enables the Company to increase bank or other debt financing, thus expanding capital available for investment. It may be that capital currently available to the Company is insufficient to adequately grow funds flow, thus requiring additional capital which may be available only on terms dilutive to existing shareholders, if available at all.

17. RELATED PARTY TRANSACTIONS

The remuneration of the key management personnel of the Company, which includes directors and officers, is set out below in aggregate:

	Year EndedDecember 31, 2020	December 31, 2019	Year Ended
Salaries and short-term benefits	$3,170	$	3,293
Share-based compensation	975		1,381
Total compensation	$4,145	$	4,674

18. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in non-cash working capital

	Year Ended	Year Ended
	December 31, 2020	December 31, 2019
Accounts receivable	$2,584	$7,214
Prepaids and deposits	(360)	89
Accounts payable and accrued liabilities	(12,297)	(4,341)
Change in non-cash working capital	$(10,073)	$2,962
Relating to:
Operating activities	$(4,165)	$8,957
Investing activities	(5,908)	(5,995)
Change in non-cash working capital	$(10,073)	$2,962
Interest paid during the year	$6,974	$5,087
Income taxes paid during the year	$-	$-

19. COMMITMENTS

At December 31, 2020, 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	$ 64,289	$ 60,398	$ 28,212	$ 28,332	$ 28,037	$ 179,815	$ 389,083
Office lease(1)	356	356	356	356	356	30	1,810
Total	$ 64,645	$ 60,754	$ 28,568	$ 28,688	$ 28,393	$ 179,845	$ 390,893

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

CORPORATE INFORMATION

Officers

Brian Lavergne President & Chief Executive Officer

Robert S. Tiberio Chief Operating Officer

Michael J. Hearn Chief Financial Officer & Corporate Secretary

Emily Wignes Vice President, Finance Jamie P. Conboy Vice President, Geology

H. Darren Evans Vice President, Exploitation

Bret A. Kimpton Vice President, Production

Directors

Matthew J. Brister (2)(3)

John A. Brussa

Mark A. Butler (1)(3)

Stuart G. Clark (1) Chairman

Brian Lavergne President & Chief Executive Officer Sheila A. Leggett (2) Gregory G. Turnbull (2) P. Grant Wierzba (2)(3) James K. Wilson (1)

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

Abbreviations

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

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

www.stormresourcesltd.com