Storm Resources Ltd. — Management Reports 2021

Mar 4, 2021

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 to		Three Months to		Year Ended		Year Ended
	Dec. 31, 2020		Dec. 31, 2019		Dec. 31, 2020		Dec. 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 to	Three Months to	Year ended	Year ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2020	Dec. 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.

		20202019
($000s unless otherwise stated)	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1
Revenue from product sales	52,941	30,010	30,191	41,923	48,671	31,417	37,568	55,766
Funds flow	22,350	6,681	10,904	16,889	18,469	11,973	12,590	16,517
Per share – basic and diluted ($)	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						2019
	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.

	Twelve Months EndedDecember 31, 2020	Twelve Months EndedDecember 31, 2019
($000s unless otherwise stated)
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).

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