Storm Resources Ltd. - Interim / Quarterly Report 2020

MANAGEMENT’S DISCUSSION & ANALYSIS

INTRODUCTION

Set out below is management’s discussion and analysis ("MD&A") of financial and operating results for Storm Resources Ltd. (“Storm” or the “Company”) for the three months ended March 31, 2020. It should be read in conjunction with (i) the Company’s unaudited condensed interim consolidated financial statements for the three months ended March 31, 2020, (ii) the Company’s MD&A and audited consolidated financial statements for the year ended December 31, 2019, and (iii) the press release issued by the Company on May 12, 2020, and other operating and financial information included in this report. All of these documents as well as the Company’s Annual Information Form dated March 30, 2020 are filed on SEDAR (www.sedar.com) and appear on the Company’s website (www.stormresourcesltd.com.)

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

This MD&A is dated May 12, 2020.

See discussion related to “Forward-Looking Statements”, “Boe Presentation” and “Non-GAAP Measurements” on pages 26 to 29.

BASIS OF PRESENTATION

Financial data presented below have largely been derived from the Company’s unaudited condensed interim consolidated financial statements (the “financial statements”) for the three months ended March 31, 2020, prepared in accordance with International Accounting Standard (“IAS”) 34 “Interim Financial Reporting” using accounting policies consistent with International Financial Reporting Standards (“IFRS”). Accounting policies adopted by the Company are referred to in Note 3 to the audited consolidated financial statements for the year ended December 31, 2019. The reporting and the functional currency is the Canadian dollar.

Unless otherwise indicated, tabular financial amounts, other than per-share amounts, are in thousands. Comparative information is provided for the immediately prior three month period ended December 31, 2019 and for the three month period ended March 31, 2019.

OPERATIONAL AND FINANCIAL RESULTS

Overview

What started out as a typical quarter for Storm quickly morphed into uncharted territory with the emergence of COVID19 in January followed by a rapid escalation through the first week of March 2020 before officially being declared a global pandemic by the World Health Organization (“WHO”) on March 11. The pandemic, coupled with a crude oil price war between Saudi Arabia and Russia, created a perfect storm for crude oil prices that has led to a dramatic collapse in WTI with the May 2020 futures contract recently plunging into negative territory prior to expiration. While a deal by OPEC+ members was reached in mid-April 2020 for production cuts of 9.7 million barrels a day for May and June of this year, this pales in comparison to the unprecedented demand destruction from the shutdown of global economies as a result of COVID-19.

First and foremost, Storm’s priority has and will continue to be the health and safety of its employees, partners and the communities in which it operates. The Company took swift action to implement a remote work environment for office staff, while implementing social distancing requirements and other appropriate procedures at its field locations in northeast British Columbia as recommended by applicable health authorities.

While there has been little to no disruption to date to the Company’s operations, Storm’s liquids prices will be affected by the weakness in crude oil prices with the price of WTI dropping from US$50.54 per barrel in February to US$30.45 per barrel in March 2020 before collapsing even further in April and May. Fortunately for Storm, the Company has been somewhat insulated by virtue of its current production mix which consists of approximately 81% natural gas, while also benefitting from a reasonable hedge position.

With crude oil storage expected to hit capacity in the coming weeks, the effect of this on the North American crude oil market remains a significant unknown, although current speculation is that this will keep pricing extremely low in the near term and could lead to forced shut-ins. In the event of forced shut-ins, it could affect the Company’s wells and facilities and/or third-party facilities and pipelines used by the Company, namely with respect to marketing of the Company’s condensate volumes. At this time, the extent to which COVID-19 may affect the Company is uncertain; however, it is possible that COVID-19 may have further adverse effects on commodity prices, the Company’s business, results of operations and financial condition depending on the severity and duration of the pandemic. While Storm entered these challenging times in a position of strength, both from an operational and liquidity standpoint, management will continue to monitor this highly fluid situation to determine what, if any, additional measures might need to be taken.

As for the first quarter, natural gas prices faded relative to the fourth quarter of 2019 from a lack of winter weather, robust supply and elevated storage levels. Production of 23,946 Boe per day was consistent with the Company’s guidance range of 24,000 to 25,000 Boe per day and benefitted from start-up of the Nig Gas Plant on February 22, 2020. Comparability with the same period in the prior year is less meaningful in light of the McMahon Gas Plant outage in January 2019 which lasted for 17 days and reduced Storm’s corporate production by approximately 3,700 Boe per day in the period. Given the aforementioned market dynamics, natural gas prices in the first quarter of 2020 were materially lower than last year, with Storm’s realized price down 43% from the first quarter of 2019. With the decline in demand since the end of the winter heating season, strong production levels and elevated storage levels in the US, spot natural gas prices in the US remain under pressure. That said, the current forward strip for natural gas prices is looking constructive and has moved up markedly over the last six weeks for both US and Western Canadian markets in response to speculation of significantly lower levels of drilling activity due to the drop in liquids pricing and a corresponding decline in associated natural gas production in the US.

While representing only 19% of the Company’s total production base, condensate (includes field condensate and plant pentanes) and NGL (includes butane and propane) contributed 36% to the Company’s top line revenue in the first quarter, buoyed by reasonably strong WTI pricing in January and February and a tightening of the condensate differential relative to the fourth quarter of 2019. As the majority of Storm’s condensate and NGL revenue streams are based on crude oil reference prices, participation in the crude oil market has been an important contributor to Storm’s revenue, with the significant drop in WTI prices expected to drive materially lower realized condensate and NGL pricing for the second quarter of 2020 and remainder of the year, partially offset by increased hedging gains on crude oil contracts.

In the first quarter of 2020, Storm’s Boe-per-day production was up 7% over the immediately preceding quarter and up 21% year over year due to the effect of the McMahon Gas Plant outage in January 2019. Production was increased with the start-up of the Nig Gas Plant and in response to reasonably strong natural gas and condensate pricing. Storm’s production averaged approximately 24,500 Boe per day for April 2020 based on field estimates. In response to lower condensate and NGL prices, over the near term production may be reduced to avoid selling condensate and NGL at negative margins.

Field operating netback per Boe for the first quarter of 2020 amounted to $8.13, a decrease compared to $16.84 in the same period of 2019, while funds flow per Boe decreased to $7.75 from $9.25 in the same period in 2019. The significantly lower field operating netback versus the comparative period was primarily a result of lower realized natural gas and NGL pricing that was slightly offset by lower transportation, royalties and production costs. Lower natural gas and WTI pricing in the first quarter of 2020 was the main driver of the realized gain on risk management contracts, increasing per-Boe funds flow by $1.26 in the quarter. This compared to a realized loss on risk management contracts of $5.38 per Boe in the same period in 2019 largely due to higher natural gas pricing, just over half of which was related to Sumas price hedges. Recall, this was the result of a failure on the Enbridge T-south pipeline system on October 9, 2019 which materially reduced flows and increased the Sumas price to Cdn$9.06 per Mmbtu in the quarter versus the average hedged price of Cdn$3.35 per Mmbtu.

Capital expenditures for the first quarter of 2020 totaled $26.5 million and included $13.3 million to drill one net horizontal well at Fireweed and complete 3.5 net horizontal wells (3.0 net at Umbach, 0.5 net at Fireweed), $11.2 million for facilities (primarily the Nig Gas Plant), and $1.6 million for well equipping and pipelines. During the first quarter, two wells were brought on stream. At quarter-end, the Company had an inventory of five (3.5 net) standing horizontal wells, which included three (2.0 net) completed wells. Based on the current capital program, four (4.0 net) wells will be drilled

and completed at Nig in the second half of the year to capitalize on winter natural gas pricing and three (3.0 net) wells will be drilled at Umbach. Based on this level of activity, fourth quarter production is forecast to be consistent with previously announced production guidance with the range now tightened slightly to 25,000 to 28,000 Boe per day from 25,000 to 30,000 Boe per day due to deferral of activity at Fireweed.

Capital expenditures in the first quarter of 2020 were in excess of funds flow, with this outlay representing approximately 50% of the total revised capital budget for 2020. In light of the collapse in WTI prices and the previously announced intention for capital expenditures to approximate funds flow, approximately $25 million of previously disclosed capital expenditures at Fireweed have been deferred for up to one year. This results in revised capital expenditures of $52 to $60 million from $75 to $85 million previously. Corresponding production growth from the Fireweed area will now be deferred for up to one year with first production now expected in late 2021 or early 2022 from previously announced expectation of late 2020 or early 2021. Based on current forecast commodity prices, it is anticipated that for the remainder of the year planned capital expenditures will be lower than funds flow with the excess funds flow expected to be used to pay down borrowings on the Company’s credit facility.

As at March 31, 2020, the Company had an extendible revolving credit facility in the amount of $205 million based on a bank determined borrowing base related to the Company’s producing reserves. The credit facility is available to the Company until May 29, 2020 and the annual review process is currently underway with completion expected on or before the aforementioned date. The credit facility was approximately 66% drawn at the end of the first quarter (including $10.3 million for outstanding letters of credit). With funds flow for the remainder of the year expected to be in excess of capital expenditures, low maintenance capital, a strong hedge portfolio, and approximately $70 million of unused credit capacity, Storm maintains adequate financial liquidity to manage through the current downturn in commodity prices.

Production and Revenue

Average Daily Production

Average Daily Production
	Three Months to	Three Months to	Quarter-Over-	Three Months to
	March 31,2020	March 31,2019	Quarter Change	December 31,2019
Natural gas (Mcf/d)	115,957	96,537	20%	108,679
Condensate (Bbls/d)	2,623	2,199	19%	2,416
NGL(Bbls/d)	1,998	1,534	30%	1,846
Total(Boe/d)	23,946	19,823	21%	22,375
Natural gas weighting	81%	81%		81%
Condensate weighting	11%	11%		11%
NGL weighting	8%	8%		8%

Production for natural gas, condensate and NGL in the first quarter of 2020 was 21% higher than the first quarter of 2019 primarily due to 2019 being negatively affected by third-party outages. The Company started production from two new 100% interest horizontal wells at Umbach during the first quarter of 2020.

The Nig Gas Plant was commissioned on February 22, 2020 leading to incremental production as a result of higher NGL recovery and reduced gas shrinkage.

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Average Daily Production
30,000 220
25,000 200
180
20,000
160
15,000
140
10,000
120
5,000 100
- 80
Condensate and NGL Natural Gas Volumes per MM Shares O/S
Boe/d
Per MM Shares O/S
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Daily production per million shares outstanding at the end of the first quarter of 2020 averaged 197 Boe per day, compared to 163 Boe per day for the first quarter of 2019, an increase of 21%, and 184 Boe per day for the fourth quarter of 2019, an increase of 7%.

Revenue from Product Sales[(1) ]

	Three Months Ended	Three Months Ended	Three Months Ended
	March 31,2020	March 31,2019	December 31,2019
Natural gas	$ 26,850	$ 39,005	$ 32,836
Condensate	14,478	12,422	14,796
NGL	595	4,339	1,039
Total	$ 41,923	$ 55,766	$ 48,671
% of Total Revenue by Product Type
Natural gas	64%	70%	67%
Condensate and NGL	36%	30%	33%
Total	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 first quarter of 2020 decreased by 25% when compared to the first quarter of 2019 primarily as a result of the Company’s average realized price decreasing by 38%,partially offset by production volumes increasing by 21%. Compared to the prior quarter, revenue from product sales decreased by 14% due the Company’s average realized price decreasing by 19%, partially offset by production volumes increasing by 7%.

A reconciliation of quarter-over-quarter revenue changes is as follows:

	NaturalGas	Condensate	NGL	Total
Revenue from product sales – Q1 2019	$ 39,005	$ 12,422	$ 4,339	$ 55,766
Effect of changes in production	8,367	2,558	1,373	12,298
Effect of changes in averageproductprices	(20,522)	(502)	(5,117)	(26,141)
Revenue fromproduct sales – Q1 2020	$26,850	$14,478	$595	$41,923
	Natural Gas	Condensate	NGL	Total
Revenue from product sales – Q4 2019	$ 32,836	$ 14,796	$ 1,039	$ 48,671
Effect of changes in production	1,818	1,090	73	2,981
Effect of changes in averageproductprices	(7,804)	(1,408)	(517)	(9,729)
Revenue fromproduct sales – Q1 2020	$26,850	$14,478	$595	$41,923

Average Selling Prices[(1)]

Average Selling Prices(1)
	Three Months Ended	Three Months Ended	Three Months Ended
	March 31,2020	March 31,2019	December 31,2019
Natural gas - Mcf	$ 2.54	$ 4.49	$ 3.28
Condensate - Bbl	$ 60.66	$ 62.77	$ 66.56
NGL - Bbl	$ 3.27	$ 31.43	$ 6.11
Per Boe	$ 19.24	$ 31.26	$ 23.64

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

On a per-Boe basis, the Company’s average realized price for the three months ended March 31, 2020 decreased by 38% compared to the same period of 2019, with the decrease driven primarily by lower natural gas and NGL pricing. As previously communicated, Storm’s NGL price for the April 2019 to March 2020 contract year was expected to be approximately 5% to 10% of WTI. The Company’s NGL price for the first quarter of 2020 was 5% of WTI which was in line with expectations. The decrease in realized natural gas pricing is primarily due to a reduction in benchmark prices at Chicago and Sumas partially offset by higher Station 2 and AECO monthly index pricing.

On a per-Boe basis, the Company’s average realized price for the first quarter of 2020 decreased by 19% when compared to the fourth quarter of 2019, primarily driven by decreases in natural gas, condensate and NGL pricing. The decrease in realized natural gas pricing is primarily due to lower Chicago and Sumas benchmark pricing partially offset by higher Station 2 pricing. The decrease in realized condensate pricing is due primarily to lower WTI pricing. The decrease in the Company’s NGL price from the prior quarter is primarily due to lower WTI and propane pricing.

Benchmark Prices

	Three Months Ended	Three Months Ended	Three Months Ended
	March 31,2020	March 31,2019	December 31,2019
Natural gas
Chicago monthly index (US$/Mmbtu)	1.95	3.32	2.44
Chicago daily index (US$/Mmbtu)	1.74	3.04	2.21
Sumas (US$/Mmbtu)	2.41	6.81	4.20
AECO monthly index (Cdn$/GJ)	2.03	1.84	2.21
AECO daily index (Cdn$/GJ)	1.93	2.49	2.35
Station 2(Cdn$/GJ)	1.88	1.24	1.41
Crude Oil
WTI (US$/Bbl)	46.17	54.90	56.96
WTI (Cdn$/Bbl)	62.08	72.98	75.27
Edmonton condensate (Cdn$/Bbl)	62.22	67.20	70.05
Exchange rate(US$/Cdn$)	0.74	0.75	0.76

Storm’s realized prices differ from market indices due to fluctuations in the foreign exchange rate and the higher heat content of the Company’s natural gas will increase the per-Mcf price.

In October 2018, a pipeline rupture occurred on the Enbridge T-south line which reduced pipeline capacity. This increased volatility in pricing for both Station 2 (lower) and Sumas (higher) until the Enbridge T-south line returned to full capacity in November 2019.

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. With moderate winter weather reducing demand through the fourth quarter and into 2020, US natural gas prices have been under further pressure in 2020.

Station 2 pricing increased in the first quarter of 2020 compared to the first quarter of 2019 due to a decline in industry production and stable demand combined with low storage levels.

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 16% from US$54.90 per barrel during the first quarter of 2019, and declined 19% from US$56.96 per barrel during the fourth quarter 2019, to US$46.17 per barrel in the first quarter of 2020. The decline was the result of elevated supply levels, the onset of demand destruction from COVID-19 and the price war between Saudi Arabia and Russia. Partially offsetting the decrease in WTI was the narrowing of the condensate differential from a discount of US$4.35 per barrel in the first

quarter of 2019 and a discount of US$3.95 per barrel in the fourth quarter of 2019 to a premium of US$0.10 per barrel in the first quarter of 2020.

The significant slowdown in the global economy and certain government imposed shelter-in-place mandates around the world due to the COVID-19 virus have depressed oil demand, further exacerbated by surplus oil supplies in the near-term from the world’s producers. WTI crude oil pricing dropped to US$30.45 per barrel in the month of March 2020 and further collapsed to US$16.70 per barrel in the month of April 2020. With the continuation of economic, political and social efforts around the globe to contain the virus’ spread, these extraordinary measures and actions may substantially affect oil demand and it is anticipated WTI pricing will remain depressed in the second quarter of 2020 with ongoing volatility in crude oil prices expected for the remainder of the year.

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

	Three Months Ended	Three Months Ended	Three Months Ended
	March 31,2020	March 31,2019	December 31,2019
Chicago monthly index price	18%	34%	30%
Chicago daily index price	32%	19%	25%
AECO daily index price	7%	13%	11%
Station 2 index price	25%	20%	20%
Sumas index price	10%	10%	11%
Alliance Transfer Point(“ATP”)	8%	4%	3%
Total	100%	100%	100%

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Storm Realized Natural Gas Price vs. Benchmark
$6.00
$5.00
$4.00
$3.00
$2.00
$1.00
$0.00
Q2/18 Q3/18 Q4/18 Q1/19 Q2/19 Q3/19 Q4/19 Q1/20
Storm Realized Nat Gas Price ($/Mcf) Station 2 ($/GJ)
AECO Daily ($/GJ) Chicago Monthly (Cdn$/Mmbtu)
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As a result of the Company’s diversified marketing strategy, Storm’s realized natural gas price was approximately 28% higher than Station 2 pricing in the first quarter of 2020. A contributor to the increase in Storm’s realized natural gas price to $2.54 per Mcf in the first quarter of 2020 was selling approximately 60% of the Company’s natural gas into the Chicago and Sumas markets, which had higher relative pricing than AECO and Station 2.

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Storm Condensate Price vs. Benchmark
$95.00
$85.00
$75.00
$65.00
$55.00
$45.00
$35.00
Q2/18 Q3/18 Q4/18 Q1/19 Q2/19 Q3/19 Q4/19 Q1/20
Storm Condensate Price WTI Cdn$
Cdn$/Bbl
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Storm’s realized condensate price of $60.66 per barrel for the first quarter of 2020 decreased by 3% from the first quarter of 2019 as a result of a 16% decrease in the WTI price, partially offset by narrowing of the WTI-condensate differential from a discount of US$4.35 per barrel in the first quarter of 2019 to a premium of US$0.10 per barrel in the first quarter of 2020.

When comparing the first quarter of 2020 to the previous quarter, Storm’s condensate price decreased 9% as a result of a 19% decrease in the WTI price, partially offset by narrowing of the WTI-condensate differential from a discount of US$3.95 per barrel in the fourth quarter of 2019 to a premium of US$0.10 per barrel in the first quarter of 2020.

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Storm NGL Price vs. Benchmark
$70.00
50%
$60.00
$50.00 40%
$40.00 30%
$30.00
20%
$20.00
10%
$10.00
$0.00 0%
Q2/18 Q3/18 Q4/18 Q1/19 Q2/19 Q3/19 Q4/19 Q1/20
Storm NGL Price Conway Propane
Mt. Belvieu Butane Storm NGL Price (% of WTI)
Cdn$/Bbl % of WTI Cdn$
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Storm’s realized price for NGL, excluding condensate, in the first quarter of 2020 decreased by 90% relative to the same period of 2019. The decrease in the realized NGL price was primarily due to lower contracted prices with marketers, lower propane pricing and weaker WTI pricing period over period.

When comparing the first quarter of 2020 to the fourth quarter of 2019, the realized price for NGL, excluding condensate, decreased by 46% quarter over quarter. The decrease in the realized price for NGL from the prior quarter is due to a decrease in WTI pricing and lower benchmark pricing for propane.

Storm’s NGL price net of transportation is now anticipated to be approximately 10% to 15% of WTI in Canadian dollar terms for the contract period that commenced in April 2020 and ends in March 2021. This is lower than the previously announced guidance of 20% of WTI in Canadian dollar terms as a result of further weakness in propane pricing (both Far East Asia Index and Conway).

Risk Management

Risk Management
		Three Months Ended				Three		Months Ended			Three Months Ended
			March	31,2020			March 31,2019				December 31,2019
	Realized Gain		Unrealized Gain		Realized Gain		Unrealized Gain			Realized Gain		Unrealized Gain
		(Loss)		(Loss)		(Loss)			(Loss)		(Loss)		(Loss)
Natural gas	$	1,724	$	(622)	$	(9,922)		$	2,282	$	(2,358)	$	2,439
Liquids(1)		1,012		12,273		329			(7,090)		714		(4,574)
Interest rate		1		(1,174)		-			-		-		122
Gain (loss) on risk
management contracts	$	2,737	$	10,477	$	(9,593)		$	(4,808)	$	(1,644)	$	(2,013)

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

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

The realized gains and losses on risk management contracts consists of the portion of contracts that have settled during the reporting period. The realized gain of $2.7 million for the three months ended March 31, 2020 is primarily due to lower natural gas pricing at Chicago and Sumas, combined with lower WTI crude oil pricing during the first quarter of 2020.

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.

Royalties

Royalties
	Three Months Ended	Three Months Ended	Three Months Ended
	March 31,2020	March 31,2019	December 31,2019
Charge for period	$ 2,107	$ 4,657	$ 3,267
Percentage of revenue fromproduct sales	5.0%	8.4%	6.7%
Per Boe	$ 0.97	$ 2.61	$ 1.59

Royalties, as a percentage of revenue from product sales, in the first quarter of 2020, decreased compared to the same period in 2019 primarily due to lower realized commodity prices. In the first quarter of 2020, 29 wells qualified for the minimum 6% royalty rate on new horizontal wells compared to 30 wells in the first quarter of 2019 and 28 wells in the fourth quarter of 2019. The BC Deep Well Royalty Credit Program reduces the royalty rate on new horizontal wells to 6% for approximately one to three years depending on productivity and commodity prices.

Royalties, as a percentage of revenue from product sales, decreased in the first quarter of 2020 from the fourth quarter of 2019 primarily due to a decrease in realized commodity prices, partially offset by the receipt of infrastructure royalty credits in the fourth quarter of 2019 ($0.2 million).

Storm has remaining infrastructure royalty credits of $7.0 million that will reduce future royalties including credits of $6.2 million relating to the construction of the Nig Gas Plant which came online in February 2020. Future royalty payments are dependent on commodity prices and production levels from individual wells and thus the timing to receive future royalty credits cannot be readily forecast; correspondingly, royalty rates reported in future quarters will vary as these credits are realized.

Production Costs

Production Costs
	Three Months Ended	Three Months Ended	Three Months Ended
	March 31,2020	March 31,2019	December 31,2019
Charge forperiod	$ 11,259	$ 10,862	$ 11,663
Per Boe	$ 5.17	$ 6.09	$ 5.67

Total production costs for the first quarter of 2020 increased 4% when compared to the first quarter of 2019 and decreased 3% when compared to the fourth quarter of 2019. The increase in total production costs for the first quarter of 2020 compared to the first quarter of 2019 is primarily due to higher production volumes, partially offset by lower third-party gas processing costs as a result of the start-up of the Nig Gas Plant in February 2020 while production costs in the first quarter of 2019 were higher due to incurring fixed costs during the McMahon Gas Plant outage in January 2019. The decrease in total production costs for the first quarter of 2020 compared to the fourth quarter of 2019 was primarily due to incurring lower third-party gas processing costs as a result of the start-up of the Nig Gas Plant in the first quarter of 2020.

On a per-Boe basis, production costs decreased by 15% when compared to the first quarter of 2019 and by 9% when compared to the fourth quarter of 2019 due to the aforementioned start-up of the Nig Gas Plant in the first quarter of 2020.

Carbon Tax

With the majority of the Company’s operations located in British Columbia, the Company is subject to the British Columbia Carbon Tax Act. 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.

that are included within production costs.
	Three Months Ended	Three Months Ended	Three Months Ended
	March 31,2020	March 31,2019	December 31,2019
Charge forperiod	$ 1,659	$ 1,351	$ 1,521
Per Boe	$ 0.76	$ 0.76	$ 0.74

Transportation Costs

Transportation Costs
	Three Months Ended	Three Months Ended	Three Months Ended
	March 31,2020	March 31,2019	December 31,2019
Charge forperiod	$ 10,834	$ 10,206	$ 10,708
Per Boe	$ 4.97	$ 5.72	$ 5.20

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

On a per-Boe basis, transportation costs for the first quarter of 2020 decreased by 13% when compared to the first quarter of 2019, primarily due to incurring fixed costs in the prior year for unused firm transportation during the McMahon Gas Plant outage in January 2019. Transportation costs for the first quarter of 2020 decreased by 4% on a per-Boe basis 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.

Field Operating Netbacks

Details of field netbacks, measured per commodity unit sold, are as follows:

		Three Months Ended March 31, 2020	Three Months Ended March 31, 2020	Three Months Ended March 31, 2020
	Natural Gas(1)	Condensate(2)	NGL	Total
	($/Mcf)	($/Bbl)	($/Bbl)	($/Boe)
Revenue from product sales	$ 2.54	$ 60.66	$ 3.27	$ 19.24
Royalties	(0.06)	(6.03)	(0.37)	(0.97)
Production costs	(1.07)	-	-	(5.17)
Transportation costs	(0.91)	(4.81)	(0.53)	(4.97)
Field operating netback	$ 0.50	$ 49.82	$ 2.37	$ 8.13
Realizedgain(loss)on risk management contracts	0.16	4.24	-	1.26
Field operatingnetback includinghedging	$ 0.66	$ 54.06	$ 2.37	$ 9.39

		Three Months Ended March 31, 2019	Three Months Ended March 31, 2019	Three Months Ended March 31, 2019
	Natural Gas(1)	Condensate(2)	NGL	Total
	($/Mcf)	($/Bbl)	($/Bbl)	($/Boe)
Revenue from product sales	$ 4.49	$ 62.77	$ 31.43	$ 31.26
Royalties	(0.29)	(7.81)	(4.41)	(2.61)
Production costs	(1.25)	-	-	(6.09)
Transportation costs	(1.06)	(5.08)	-	(5.72)
Field operating netback	$ 1.89	$ 49.88	$ 27.02	$ 16.84
Realizedgain(loss)on risk management contracts	(1.14)	0.70	1.38	(5.38)
Field operatingnetback includinghedging	$ 0.75	$ 50.58	$ 28.40	$ 11.46
		Three Months Ended December 31, 2019
	Natural Gas(1)	Condensate(2)	NGL	Total
	($/Mcf)	($/Bbl)	($/Bbl)	($/Boe)
Revenue from product sales	$ 3.28	$ 66.56	$ 6.11	$ 23.64
Royalties	(0.13)	(8.44)	(0.79)	(1.59)
Production costs	(1.17)	-	-	(5.67)
Transportation costs	(0.97)	(4.62)	-	(5.20)
Field operating netback	$ 1.01	$ 53.50	$ 5.32	$ 11.18
Realizedgain(loss)on risk management contracts	(0.24)	1.81	1.83	(0.80)
Field operatingnetback includinghedging	$ 0.77	$ 55.31	$ 7.15	$ 10.38

(1) Production costs of condensate and NGL are included within natural gas costs.

(2) Realized gains and losses on crude oil contracts are included within the condensate netback.

The field operating netback for the first quarter of 2020 decreased by 52% (18% decrease after hedging) compared to the first quarter of 2019. The increase in realized hedging is due to a realized hedging loss of $5.38 per Boe in the first quarter of 2019 compared to a realized gain of $1.26 per Boe in the first quarter of 2020.

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Change in Field Operating Netback Including Hedging: Q1/19 vs. Q1/20
$14.00
$11.46 $(12.02)
$12.00
$10.00 $6.64 $9.39
$8.00
$6.00
$4.00
$0.75
$0.92
$2.00 $1.64
$-
$(2.00)
Q1 2019 Revenue Royalties Prod. Costs Transp. Realized Q1 2020
Hedging
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The field operating netback for the first quarter of 2020 decreased by 27% (10% decrease after hedging) compared to the fourth quarter of 2019.

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Change in Field Operating Netback Including Hedging: Q4/19 vs. Q1/20
$14.00
$12.00
$10.38 ($4.40)
$10.00 $2.06 $9.39
$8.00 $0.50 $0.23
$0.62
$6.00
$4.00
$2.00
$-
Q4 2019 Revenue Royalties Prod. Costs Transp. Realized Hedging Q1 2020
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General and Administrative Costs

General and Administrative Costs
	Three Months Ended	Three Months Ended	Three Months Ended
	March 31,2020	March 31,2019	December 31,2019
Charge for period – before recoveries	$ 2,567	$ 3,246	$ 2,039
Overhead recoveries	(700)	(395)	(594)
Charge forperiod – net of recoveries	$ 1,867	$ 2,851	$ 1,445
Per Boe	$ 0.86	$ 1.60	$ 0.70

General and administrative costs before recoveries for the first quarter of 2020 decreased by 21% when compared to the first quarter of 2019 and increased by 26% compared to the fourth quarter of 2019. The decrease in general and administrative costs for the first quarter of 2020 relative to the same period in 2019 is primarily attributable to a lower annual employee performance bonus after year-end results were finalized. The increase in general and administrative costs for the first quarter of 2020 compared to the immediately preceding quarter is primarily due to the payout of the annual employee performance bonus.

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

Net general and administrative costs on a per-Boe measure for the first quarter of 2020 decreased by 46% compared to the first quarter of 2019, and increased by 23% compared to the fourth quarter of 2019. General and administrative costs for the first quarter tend to be higher due to the employee annual performance bonus payout, if earned. Generally, the Company’s general and administrative cost structure is predictable year to year and variability in per-Boe metrics is due to changes in production volumes.

Interest and Finance Costs

Interest and Finance Costs
	Three Months Ended	Three Months Ended	Three Months Ended
	March 31,2020	March 31,2019	December 31,2019
Charge for period(1)	$ 1,646	$ 1,118	$ 1,510
Average interest rate(2)	5.2%	4.6%	5.0%
Per Boe	$ 0.76	$ 0.63	$ 0.73

(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 first quarter of 2020 increased by 47% compared to the same quarter of 2019, and by 9% when compared to the fourth quarter of 2019, as a result of higher average bank borrowings which were used to fund construction of the Nig Gas Plant.

Funds Flow

Funds Flow
	Three Months Ended		Three Months Ended		Three Months Ended
	March 31,2020		March 31,2019		December 31,2019
		Per		Per		Per
		diluted		diluted		diluted
		share		share		share
Funds flow	$ 16,889	$ 0.14	$ 16,517	$ 0.14	$ 18,469	$ 0.15

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

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Change in Funds Flow ($M): Q1/19 vs. Q1/20
$30,000 $12,298 ($26,141)
$25,000
$20,000
$360
$16,517 $12,330 $16,889
$15,000
$10,000
$2,550 ($397) ($628)
$5,000
$-
Q1 2019 Revenue - Revenue - Royalties Prod. Costs Transp. Realized Other (1) Q1 2020
Volume Price Hedging
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(1) Includes general and administrative cost, interest and finance costs and decommissioning expenditures and excludes lease interest.

Higher production volumes and hedging gains partially offset by lower realized prices were the predominant factors in the 2% increase in funds flow in the first quarter of 2020 versus the first quarter of 2019.

The cash return on capital employed (“CROCE”) over the last 12 months, which is a measurement of the Company’s cash profitability as a proportion of the funding utilized to generate it (shareholders’ equity plus debt including working capital deficiency), was 12% in the first quarter of 2020 compared to 20% in the first quarter of 2019 and 12% in the fourth quarter of 2019.

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Change in Funds Flow ($M): Q4/19 vs. Q1/20
$25,000
$2,981 ($9,729)
$20,000 $18,469
$4,381 ($651) $16,889
$15,000
$1,160 $404 ($126)
$10,000
$5,000
$-
Q4 2019 Revenue - Revenue - Royalties Prod. Costs Transp. Realized Other (1) Q1 2020
Volume Price Hedging
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(1) Includes general and administrative cost, interest and finance costs and decommissioning expenditures and excludes lease interest.

Funds flow for the first quarter of 2020 decreased by 9% from the fourth quarter of 2019. Funds flow was negatively affected by weaker realized pricing.

Share-Based Compensation

Share-Based Compensation
	Three Months Ended	Three Months Ended	Three Months Ended
	March 31,2020	March 31,2019	December 31,2019
Charge forperiod	$ 476	$ 596	$ 656
Per Boe	$ 0.22	$ 0.33	$ 0.32

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 20% in the first quarter of 2020 compared to the first quarter of 2019 and decreased by 27% when compared to the fourth quarter of 2019. The decrease in share-based compensation in both periods is primarily attributable to a lower stock option fair valuation associated with stock options granted during 2019.

Depletion and Depreciation

	Three Months Ended	Three Months Ended	Three Months Ended
	March 31,2020	March 31,2019	December 31,2019
Depletion	$ 9,779	$ 7,852	$ 9,246
Depreciation	2,226	1,894	2,010
Charge forperiod	$ 12,005	$ 9,746	$ 11,256
Per Boe	$ 5.51	$ 5.46	$ 5.46

Depletion and depreciation increased by 23% in the first quarter of 2020 compared to the same quarter of 2019 and increased 7% when compared to the fourth quarter of 2019 primarily due to an increase in production volumes.

Income Taxes

In May 2019, the Government of Alberta substantively enacted a reduction in the provincial corporate tax rate from 12% to 8% over a four-year period.

The Company did not incur any cash tax expense in the three months ended March 31, 2020, nor does it expect to pay any cash tax for the remainder of 2020 or in 2021 based on current commodity prices, forecast taxable income, existing tax pools and planned capital expenditures.

Deferred income taxes arise from differences between the accounting and tax bases of the Company’s assets and liabilities. For the three months ended March 31, 2020, the Company recognized a deferred income tax expense of $3.9 million as a result of $14.4 million of net income before taxes. As at March 31, 2020, the Company had a deferred income tax liability of $13.2 million.

income tax liability of $13.2 million.
Tax Pools	As at March 31, 2020	Maximum Annual Deduction
Canadian oil and gas property expense	$ 42,000	10%
Canadian development expense	116,000	30%
Canadian exploration expense	14,000	100%
Undepreciated capital cost	141,000	20% - 100%
Operatinglosses	200,000	100%
Total	$ 513,000

Net Income

The mark-to-market valuation of risk management contracts resulted in a considerable distortion on reported net income for both the first quarter of 2020 relative to the same period in 2019 and to the fourth quarter of 2019. For the first quarter of 2020, the unrealized gain on risk management contracts amounted to $10.5 million compared to an unrealized loss in the first quarter of 2019 of $4.8 million and an unrealized loss of $2.0 million in the fourth quarter of 2019.

Excluding unrealized gains and losses on risk management contracts, the decrease in net income in the first quarter of 2020 compared to the same period in 2019 is primarily attributable to the weakened commodity price environment driving decreased revenue.

The return on capital employed (“ROCE”) over the last 12 months, which is a measurement of the Company’s income profitability as a proportion of the funding utilized to generate it (shareholders’ equity plus debt including working capital deficiency), was 7% in the first quarter of 2020 compared to 8% in the first quarter of 2019, although as mentioned above is distorted by unrealized gains and losses on the Company’s risk management contracts.

	Three Months Ended	Three Months Ended	Three Months Ended
	March 31,2020	March 31,2019	December 31,2019
Net income	$ 10,512	$ 607	$ 2,906
Per basic and diluted share	$ 0.09	$ 0.00	$ 0.02

Corporate Netbacks

Corporate Netbacks
	Three Months Ended	Three Months Ended	Three Months Ended
($/Boe)	March 31,2020	March 31,2019	December 31,2019
Revenue from product sales	19.24	31.26	23.64
Realized gain (loss) on risk management contracts	1.26	(5.38)	(0.80)
Royalties	(0.97)	(2.61)	(1.59)
Production	(5.17)	(6.09)	(5.67)
Transportation	(4.97)	(5.72)	(5.20)
General and administrative	(0.86)	(1.60)	(0.70)
Interest and finance costs	(0.74)	(0.61)	(0.71)
Decommissioning expenditures	(0.04)	-	-
Funds flow	7.75	9.25	8.97
Share-based compensation	(0.22)	(0.33)	(0.32)
Depletion, depreciation and accretion	(5.56)	(5.54)	(5.52)
Lease interest	(0.02)	(0.02)	(0.02)
Exploration and evaluation costs expensed	(0.21)	-	(0.01)
Unrealized revaluation gain (loss) on investments	(0.01)	(0.01)	0.01
Unrealized gain (loss) on risk management contracts	4.81	(2.69)	(0.98)
Decommissioning expenditures	0.04	-	-
Deferred income tax expense	(1.77)	(0.33)	(0.72)
Net income	4.81	0.33	1.41

INVESTMENT AND FINANCING

Financial Resources and Liquidity

As at March 31, 2020, the Company had an extendible revolving credit facility in the amount of $205 million (December 31, 2019 – $205 million) based on a bank determined borrowing base related to the Company’s producing reserves. The credit facility is available to the Company until May 29, 2020 and the annual review process is currently underway with completion expected on or before the aforementioned date. 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 March 31, 2020, debt including outstanding letters of credit amounted to $135.1 million, representing approximately 66% of the available credit facility.

As at March 31, 2020, the Company had issued letters of credit in the amount of $10.3 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 first quarter of 2020, the Company incurred capital expenditures of $26.5 million compared to $16.9 million in the first quarter of 2019 and $23.9 million in the fourth quarter of 2019. Capital expenditures in the first quarter of 2020 were primarily related to costs incurred for completion and start-up of the Nig Gas Plant, as well as drilling two horizontal wells (1.0 net) and completing one well (0.5 net) at Fireweed, and completion, tie-in and equipping activities on three wells (3.0 net) at Umbach.

wells (3.0 net) at Umbach.
	Three Months Ended	Three Months Ended	Three Months Ended
	March 31,2020	March 31,2019	December 31,2019
Land and seismic	$ 233	$ 583	$ 370
Drilling	3,679	11,308	208
Completions	9,676	23	991
Facilities	11,209	3,981	16,543
Equipping and pipelines	1,553	958	5,585
Recompletions and workovers	87	45	194
Propertyacquisition and administrative assets	38	46	22
Total field capital expenditures	$ 26,475	$ 16,944	$ 23,913

Net capital investment was allocated as follows:

Net capital investment was allocated as follows:
	Three Months Ended	Three Months Ended	Three Months Ended
	March 31,2020	March 31,2019	December 31,2019
Exploration and evaluation	$ 233	$ 583	$ 370
Propertyand equipment	26,242	16,361	23,543
Total capital expenditures	$ 26,475	$ 16,944	$ 23,913

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 March 31, 2020 corresponds to the Company’s active field program.

Decommissioning Liability

The Company’s decommissioning liability of $26.8 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 March 31, 2020 was $33.3 million (December 31, 2019 - $38.3 million), with $0.7 million expected to be incurred in the next 12 months.

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 office lease commitment approximates $4.7 million over six years. In addition, as at the date of this report, the Company has transportation and processing commitments valued at a total of approximately $427 million.

QUARTERLY RESULTS

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

Apart from minimal capital expenditures in the second quarter of 2018, the first and third quarter results for 2018 were relatively consistent in terms of capital expenditures, production and funds flow, supported by stable Chicago natural gas prices and materially stronger liquids pricing. Capital expenditures were increased in the fourth quarter of 2018 primarily to include deposits on long-lead-time equipment for the sour gas plant at Nig. In response to strong US based pricing, production was increased in the fourth quarter leading to strong funds flow generation in the period. With funds flow outpacing capital expenditures, debt including working capital was reduced by approximately $15 million over the course of the year.

An unplanned outage in the first quarter of 2019 resulted in approximately 19,500 Boe per day of the Company’s production being shut in for 17 days. This had a notable effect on revenue, costs, funds flow and net income for the period. Capital expenditures in the first quarter of 2019 approximated funds flow resulting in marginal movement in debt including working capital deficiency.

In the second quarter of 2019, weaker pricing across all products resulted in lower revenue, while a planned Alliance Pipeline outage resulted in increased costs as fixed transportation tolls were incurred without associated revenue. Debt including working capital deficiency increased to $102.3 million as spending on the Nig Gas Plant progressed.

The third quarter of 2019 was affected negatively by an unplanned 14-day outage at the McMahon Gas Plant resulting in lower revenues. The debt including working capital deficiency rose to $123.3 million as construction of the Nig Gas Plant continued as planned.

During the fourth quarter of 2019, the Company continued with construction of the Nig Gas Plant and ramped up production in December in response to improved commodity prices for all product streams, generating funds flow for the quarter of $18.5 million. Debt including working capital deficiency increased to $128.9 million.

In the first quarter of 2020, the Company completed construction of the Nig Gas Plant with the plant starting up in late February. Commodity prices for all product streams continued to weaken which resulted in funds flow of $16.9 million.

In the first quarter of 2020, the Company completed construction of the Nig Gas Plant with the plant starting up in late February. Commodity prices for all product streams continued to weaken which resulted in funds flow of $16.9 million.	In the first quarter of 2020, the Company completed construction of the Nig Gas Plant with the plant starting up in late February. Commodity prices for all product streams continued to weaken which resulted in funds flow of $16.9 million.	In the first quarter of 2020, the Company completed construction of the Nig Gas Plant with the plant starting up in late February. Commodity prices for all product streams continued to weaken which resulted in funds flow of $16.9 million.	In the first quarter of 2020, the Company completed construction of the Nig Gas Plant with the plant starting up in late February. Commodity prices for all product streams continued to weaken which resulted in funds flow of $16.9 million.
2020 2019 2018
($000s unless otherwise stated)	Q1	Q4 Q3 Q2 Q1	Q4 Q3 Q2
Revenue from product sales Funds flow Per share – basic and diluted ($) Net income (loss) Per share – basic and diluted ($) Net capital expenditures Average daily production (Boe) Debt including working capital deficiency(1)	41,923	48,671 31,417 37,568 55,766 18,469 11,973 12,590 16,517 0.15 0.10 0.10 0.14 2,906 (64) 7,864 607 0.02 (0.00) 0.06 0.00 23,913 32,841 23,145 16,944 22,375 18,596 19,923 19,823 128,901 123,342 102,268 91,585	74,799 51,253 48,104 30,941 22,227 23,405 0.25 0.18 0.19 26,810 7,174 (2,815) 0.22 0.06 (0.02) 37,100 21,845 2,918 22,432 20,455 19,529 91,020 84,648 85,073
	16,889
	0.14
	10,512
	0.09
	26,475
	23,946
	138,632

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

LIMITATIONS

Forward-Looking Statements – Certain forward-looking information and statements are set forth in this document, including management’s assessment of Storm’s future plans and operations specifically in relation to 2020 and 2021, and contain forward-looking information within the meaning of applicable Canadian securities legislation. Such statements or information are generally identifiable by words such as “anticipate”, “believe”, “intend”, “plan”, “expect”, “schedule”, “indicate”, “focus”, “outlook”, “propose”, “target”, “objective”, “priority”, “strategy”, “estimate”, “budget”, “forecast”, “would”, “could”, “will”, “may”, “future” or other similar words or expressions and include statements relating to or associated with individual wells, facilities, regions or projects as well as timing of any future event which may have an effect on the Company’s operations and financial position. Forward-looking statements are based on expectations, forecasts, and assumptions made by the Company using information available at the time of the statement and historical trends which includes expectations and assumptions concerning: the accuracy of reserve estimates and valuations; performance characteristics of producing properties; access to third-party infrastructure; government policies and regulation; future production rates; accuracy of estimated capital expenditures; availability and cost of labour and services and owned or third-party infrastructure; royalties; development and execution of projects; the satisfaction by third parties of their obligations to the Company; and the receipt and timing for approvals from regulators and third parties. All statements and information concerning expectations or projections about the future and statements and information regarding the future business plan or strategy, timing or scheduling, production volumes with splits by commodity, production declines, expected and future activities and capital expenditures, commodity prices, costs, royalties, schedules, operating or financial results, future financing requirements, and the expected effect of future commitments are forward-looking statements.

Forward-looking statements include references to:

future production volumes in 2020 and 2021, production volumes by commodity and production declines;
capital investment intended to be approximately equal to funds flow;
planned capital expenditures in 2020 totaling $52 to $60 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;
future capital expenditures and their allocation to specific activities or periods, particularly with respect to estimated capital investment required to maintain production and number of wells to be drilled and completed as part of the 2020 capital program;
the expected improvement in the Company’s NGL price in 2020;
the near-term growth plan for 2020 and 2021 which is expected to increase liquids as a proportion of total production and decrease per-Boe production costs and includes the estimated start date of production from the Fireweed area based on timing for completion of the field compression facility and timing for the drilling and completion of wells;
future tax liabilities and future use of tax pools and losses;
estimates of ultimate recovery from wells including management’s references to type curves; and
existing or future contractual obligations including agreements pertaining to processing capacity, transportation and marketing of natural gas, condensate and NGL.

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

changes in general, market and business conditions including commodity prices, interest rates and currency exchange;
changes in supply and demand for the Company’s products;
a global public health crisis including the recent outbreak of the novel coronavirus (COVID-19) which causes volatility and disruptions in the supply, demand and pricing for natural gas, oil and NGL, global supply chains and financial markets, as well as declining trade and market sentiment and reduced mobility of people;
the ability to obtain regulatory, stakeholder and third-party approvals and satisfy any associated conditions that are not within the Company’s control for exploration and development activities and projects;
successful and timely implementation of capital expenditures;
risks associated with the development and execution of major projects;
risk that projects and opportunities intended to grow funds flow and/or reduce costs may not achieve the expected results in the time anticipated or at all;
access to third-party pipelines and facilities and access to sales markets;
• volatility of commodity prices and the related effects of changing price differentials;

the Company’s ability to operate and run its facilities to meet forecast production;
the output of newly commissioned facilities which may be difficult to accurately predict at an early stage;
• operational risks and uncertainties associated with oil and gas activities including unexpected formations or pressures, reservoir performance, fires, blow-outs, equipment failures and other accidents, uncontrollable flows of natural gas and wellbore fluids, pollution and other environmental risks;
changes in costs including production, royalty, transportation, general and administrative, and finance;
ability to finance planned activities including infrastructure expansions which are required to meet future growth targets;
adverse weather conditions which could disrupt production and affect drilling and completions resulting in increased costs and/or delay adding production;
actions by government authorities including changes to taxes, fees, royalties, duties and government-imposed compliance costs;
changes to laws and government policies including environmental (and climate change), royalty, and tax laws and policies;
counter-party risk with third parties to perform their obligations with whom the Company has material relationships;
unplanned facility maintenance or outages or unavailability of third-party infrastructure which could reduce production or prevent the transportation of products to processing plants and sales markets;
a major outage or environmental incident or unexpected event such as fires (including forest fires) or equipment failures or similar events that would affect the Company’s facilities or third-party infrastructure used by the Company;
environmental risks (including climate change) and the cost of compliance with current and future environmental laws, including climate change laws along with risks relating to increased activism and opposition to fossil fuels;
ability to access capital from internal and external sources (including the credit facility);
the risk that competing business objectives may exceed Storm’s capacity to adapt and implement change;
the potential for security breaches of the Company’s information technology systems by malicious persons or entities, and the unavailability or failure of such systems to perform as anticipated as a result of such breaches;
• risks with transactions including closing an asset or property acquisition or disposition and the failure to realize anticipated benefits from any transaction;
finding new oil and gas reserves that can be developed economically to replace reserves depleted by production;
the accuracy of estimating reserves and future production and the future value of reserves;
risk associated with commodity price hedging activities using derivatives and other financial instruments;
maintaining debt levels at a reasonable multiple of funds flow;
risk with First Nations land claims and consultation requirements;
risk that the Company may be subject to litigation;
the accuracy of cost estimates, some of which are provided at an early stage and before detailed engineering has been completed;
risk associated with partner or joint venture arrangements to which the Company is a party;
inability to secure labour, services or equipment on a timely basis or on favourable terms;
increased competition from other industry participants for, among other things, capital, acquisitions of assets or undeveloped lands, and skilled personnel; and
increased competition from companies that provide alternative sources of energy.

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

Readers are advised that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Storm disclaims any intention or obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required under securities law.

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

Boe Presentation - Natural gas is converted to a barrel of oil equivalent (“Boe”) using six thousand cubic feet (“Mcf”) of natural gas equal to one barrel of oil unless otherwise stated. Boe may be misleading, particularly if used in isolation. A Boe conversion ratio of six Mcf to one barrel (“Bbl”) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All Boe measurements and conversions in this report are derived by converting natural gas to crude oil in the ratio of six thousand cubic feet of natural gas to one barrel of crude oil.

Non-GAAP Measurements - Within this MD&A, references are made to terms which are not recognized under Generally Accepted Accounting Principles (“GAAP”). Specifically, “debt including working capital deficiency”, “field operating netbacks”, “field operating netbacks including hedging”, “CROCE”, “ROCE” and measurements “per commodity unit” and “per Boe” do not have any standardized meaning as prescribed by GAAP and are regarded as non-GAAP measures. These non-GAAP measures may not be comparable to the calculation of similar amounts for other entities and readers are cautioned that use of such measures to compare enterprises may not be valid. NonGAAP terms are used to benchmark operations against prior periods and peer group companies and are widely used by investors, lenders, analysts and other parties.

Field Operating Netbacks

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

Debt Including Working Capital Deficiency

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

	As at	As at	As at
($000s unless otherwise stated)	March 31,2020	March 31,2019	March 31,2018
Accounts receivable	20,494	23,221	12,251
Prepaids and deposits	561	588	663
Less: Accountspayable and accrued liabilities	(34,863)	(25,788)	(19,142)
Working capital deficiency	13,808	1,979	6,228
Bank indebtedness	124,824	89,606	99,357
Debt includingworkingcapital deficiency	138,632	91,585	105,585

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) as presented in the following table.

following table.
	Twelve Months Ended	Twelve Months Ended
($000s unless otherwise stated)	March 31, 2020	March 31, 2019
Average debt including working capital deficiency(1)	115,109	98,585
Average shareholders’ equity(1)	420,915	391,732
Average capital employed	536,024	490,317
Funds flow	59,921	93,090
Interest and finance costs	5,686	4,220
Funds flow plus interest and finance costs	65,607	97,310
CROCE	12%	20%

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

ROCE is 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) as presented in the following table.

presented in the following table.
	Twelve Months Ended	Twelve Months Ended
($000s unless otherwise stated)	March 31, 2020	March 31, 2019
Average debt including working capital deficiency(1)	115,109	98,585
Average shareholders’ equity(1)	420,915	391,732
Average capital employed	536,024	490,317
Net income	21,218	31,776
Interest and finance costs	5,686	4,220
Deferred income tax expense	8,205	5,013
	35,109	41,009
ROCE	7%	8%

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

BUSINESS RISKS

There are a number of risks facing participants in the Canadian crude oil and natural gas industry. Some risks are common to all businesses while others are specific to the industry. Information with respect to such risks is set out in Storm’s Annual Information Form dated March 30, 2020 for the year ended December 31, 2019 under the heading “Risk Factors” and in Storm’s MD&A for the period ended December 31, 2019 under the heading “Business Risks”.

Crude Oil and Natural Gas Prices and General Economic Conditions

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

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

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

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

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

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

Global Health Crises

The Company’s business, operations and financial condition could be materially adversely affected by the outbreak of epidemics or pandemics or other health crises. In December 2019, COVID-19 was reported to have surfaced in Wuhan, China; on January 30, 2020, the WHO declared the outbreak a global health emergency; and on March 11, 2020 the WHO declared the outbreak of COVID-19 a global pandemic. In China, reactions to the spread of COVID-19 have led to, among other things, significant restrictions on travel within China, temporary business closures, quarantines and a general reduction in consumer activity. The outbreak has spread throughout Canada, the United States, Europe and the Middle East with cases of COVID-19 increasing around the world. The spread of COVID-19 has led companies and various jurisdictions to impose restrictions such as quarantines, business closures and domestic and international travel restrictions. The duration of the business disruptions internationally and related financial effect cannot be reasonably estimated at this time. Similarly, the Company cannot estimate whether or to what extent this pandemic and the potential financial effect may extend to countries outside of those currently affected.

Such public health crises can result in volatility and disruptions in the supply, demand and pricing for oil and natural gas, global supply chains and financial markets, as well as declining trade and market sentiment and reduced mobility of people, all of which could affect commodity prices, interest rates, credit ratings, credit risk and inflation. In particular, crude oil prices have significantly weakened in response to the outbreak of COVID-19. The risks to the Company of such public health crises also include risks to employee health and safety and a slowdown or temporary suspension of operations in geographic locations effected by an outbreak. This could include the Company’s wells and facilities and/or third-party facilities and pipelines used by the Company. At this point, the extent to which COVID-19 may affect the Company is uncertain; however, it is possible that COVID-19 may have a material adverse effect on the Company’s business, results of operations and financial condition.

FINANCIAL REPORTING UPDATE

Disclosure Controls and Internal Controls Over Financial Reporting

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

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

No material changes in the Company's DCP and its ICFR were identified during the quarter ended March 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 – 2[nd] Street S.W., Calgary, Alberta T2P 1M4.

QUARTERY SUMMARIES

Thousands of Cdn$, except volumetric and	Thousands of Cdn$, except volumetric and	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2
per-share amounts		2020	2019	2019	2019	2019	2018	2018	2018
FINANCIAL
Revenue fromproduct sales(1)		41,923	48,671	31,417	37,568	55,766	74,799	51,253	48,104
Funds flow		16,889	18,469	11,973	12,590	16,517	30,941	22,227	23,405
Per share - basic and diluted ($)		0.14	0.15	0.10	0.10	0.14	0.25	0.18	0.19
Net income (loss)		10,512	2,906	(64)	7,864	607	26,810	7,174	(2,815)
Per share - basic and diluted ($)		0.09	0.02	(0.00)	0.06	0.00	0.22	0.06	(0.02)
Cash return on capital employed (“CROCE”)(2)		12%	12%	15%	18%	20%	21%	21%	19%
Return on capital employed (“ROCE”)(2)		7%	4%	9%	11%	8%	10%	6%	4%
Capital expenditures		26,475	23,913	32,841	23,145	16,944	37,100	21,845	2,918
Debt including working capital deficiency(2)(3)		138,632	128,901	123,342	102,268	91,585	91,020	84,648	85,073
Common shares (000s)
Weighted	average - basic	121,557	121,557	121,557	121,557	121,557	121,557	121,557	121,557
Weighted	average - diluted	121,557	121,557	121,557	121,557	121,853	121,649	121,557	121,557
Outstanding end of period - basic		121,557	121,557	121,557	121,557	121,557	121,557	121,557	121,557
OPERATIONS
(Cdn$ per Boe)
Revenue from product sales(1)		19.24	23.64	18.36	20.72	31.26	36.24	27.24	27.07
Transportation costs		(4.97)	(5.20)	(5.83)	(5.96)	(5.72)	(5.57)	(5.98)	(6.25)
Revenue net	of transportation	14.27	18.44	12.53	14.76	25.54	30.67	21.26	20.82
Royalties		(0.97)	(1.59)	0.19	(0.32)	(2.61)	(0.58)	(1.03)	(1.11)
Production costs		(5.17)	(5.67)	(5.88)	(5.89)	(6.09)	(5.46)	(5.54)	(5.46)
Field operating netback(2)		8.13	11.18	6.84	8.55	16.84	24.63	14.69	14.25
Realized gain (loss) on risk management
contracts		1.26	(0.80)	1.64	(0.22)	(5.38)	(8.65)	(1.73)	0.31
General and	administrative	(0.86)	(0.70)	(0.79)	(0.68)	(1.60)	(0.55)	(0.66)	(0.69)
Interest and finance costs		(0.74)	(0.71)	(0.69)	(0.71)	(0.61)	(0.45)	(0.49)	(0.71)
Decommissioning expenditures		(0.04)	-	-	-	-	-	-	-
Funds flow per Boe		7.75	8.97	7.00	6.94	9.25	14.98	11.81	13.16
Barrels ofoil	equivalent perday (6:1)	23,946	22,375	18,596	19,923	19,823	22,432	20,455	19,529
Natural gas production
Thousand cubic feet per day		115,957	108,679	91,053	97,510	96,537	109,520	101,905	96,426
Price (Cdn$ per Mcf)(1)		2.54	3.28	2.42	2.64	4.49	5.56	3.21	3.15
Condensate	production
Barrels per day		2,623	2,416	1,856	2,081	2,199	2,453	2,059	1,984
Price (Cdn$ per barrel)(1)		60.66	66.56	63.45	71.12	62.77	58.74	84.97	86.33
NGL production
Barrels per day		1,998	1,846	1,564	1,591	1,534	1,726	1,412	1,473
Price (Cdn$ per barrel)(1)		3.27	6.11	2.29	4.87	31.43	35.09	38.64	36.43
Wells drilled	(net)	1.0	-	1.0	-	5.0	4.0	-	-
Wells completed (net)		3.5	-	5.0	-	-	2.5	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 28 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

CORPORATE INFORMATION

Officers

Brian Lavergne President & Chief Executive Officer

Robert S. Tiberio Chief Operating Officer

Michael J. Hearn Chief Financial Officer

Jamie P. Conboy Vice President, Geology

H. Darren Evans Vice President, Exploitation

Bret A. Kimpton Vice President, Production

Emily Wignes Vice President, Finance

Directors

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

John A. Brussa

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

Stuart G. Clark[(1)] Chairman

Sheila A. Leggett[(2)]

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

James K. Wilson[(1) ]

Brian Lavergne President & Chief Executive Officer

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

Stock Exchange Listing

Toronto Stock Exchange Trading Symbol “SRX”

Solicitors

Stikeman Elliott LLP Burnet Duckworth & Palmer LLP Calgary, Alberta

Auditors

Ernst & Young LLP Calgary, Alberta

Registrar & Transfer Agent

Alliance Trust Company Calgary, Alberta

Bankers

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

Executive Offices

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

Abbreviations

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

Mbbl	Thousands of barrels
Mboe	Thousands of barrels of oil equivalent
Mcf	Thousands of cubic feet
Mcf/d	Thousands of cubic feet per day
Mmbtu	Millions of British Thermal Units
Mmbtu/d	Millions of British Thermal Units per day
Mmcf	Millions of cubic feet
Mmcf/d	Millions of cubic feet per day
NGL	Natural gas liquids
OPEC	Organization of Petroleum Exporting Countries
TSX	Toronto Stock Exchange
US	United States
US$	United States dollar
WTI	West Texas Intermediate

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Storm Resources Ltd.

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

AI assistant

Storm Resources Ltd. — Interim / Quarterly Report 2020

46632_rns_2020-05-13_69b4e220-169c-4419-a2b1-5b5ebf2979ad.pdf

MANAGEMENT’S DISCUSSION & ANALYSIS

INTRODUCTION

BASIS OF PRESENTATION

OPERATIONAL AND FINANCIAL RESULTS

Overview

Production and Revenue

Average Daily Production

Revenue from Product Sales[(1) ]

Average Selling Prices[(1)]

Benchmark Prices

Risk Management

Royalties

Production Costs

Carbon Tax

Transportation Costs

Field Operating Netbacks

General and Administrative Costs

Interest and Finance Costs

Funds Flow

Share-Based Compensation

Depletion and Depreciation

Income Taxes

Net Income

Corporate Netbacks

INVESTMENT AND FINANCING

Financial Resources and Liquidity

Capital Expenditures

Accounts Payable and Accrued Liabilities

Decommissioning Liability

CONTRACTUAL OBLIGATIONS

QUARTERLY RESULTS

LIMITATIONS

Field Operating Netbacks

Debt Including Working Capital Deficiency

CROCE & ROCE

BUSINESS RISKS

Crude Oil and Natural Gas Prices and General Economic Conditions

Global Health Crises

FINANCIAL REPORTING UPDATE

Disclosure Controls and Internal Controls Over Financial Reporting

ADDITIONAL INFORMATION

QUARTERY SUMMARIES

Officers

Directors

Stock Exchange Listing

Solicitors

Auditors

Registrar & Transfer Agent

Bankers

Executive Offices

Abbreviations

More from Storm Resources Ltd.

Storm Resources Ltd. Interim / Quarterly Report 2020