Storm Resources Ltd. - Interim / Quarterly Report 2020

==> picture [545 x 92] intentionally omitted <==

Highlights

				Three Months Ended	Three Months Ended
Thousands of Cdn$, except volumetric and per-share amounts				March 31, 2020	March 31, 2019
FINANCIAL
Revenue from	product sales(1)			41,923	55,766
Funds flow				16,889	16,517
Per share - basic and diluted($)				0.14	0.14
Net income				10,512	607
Per share - basic and diluted($)				0.09	0.00
Cash return on capital			employed(“CROCE”)(2)	12%	20%
Return on capital		employed(“ROCE”)(2)		7%	8%
Capital expenditures				26,475	16,944
Debt includingworkingcapital deficiency(2)(3)				138,632	91,585
Common shares		(000s)
Weighted average - basic				121,557	121,557
Weighted average - diluted				121,557	121,853
Outstandingend of			period - basic	121,557	121,557
OPERATIONS
(Cdn$ per Boe)
Revenue from	product sales(1)			19.24	31.26
Transportation costs				(4.97)	(5.72)
Revenue net of transportation				14.27	25.54
Royalties				(0.97)	(2.61)
Production costs				(5.17)	(6.09)
Field operating netback(2)				8.13	16.84
Realized gain	(loss) on risk management contracts			1.26	(5.38)
General and administrative				(0.86)	(1.60)
Interest and finance costs				(0.74)	(0.61)
Decommissioningexpenditures				(0.04)	-
Funds flowper Boe				7.75	9.25
Barrels of oil equivalent per day (6:1)				23,946	19,823
Natural gas production
Thousand cubic feet per day				115,957	96,537
Price(Cdn$per Mcf)(1)				2.54	4.49
Condensate production
Barrels per	day			2,623	2,199
Price(Cdn$per barrel)(1)				60.66	62.77
NGL production
Barrels per	day			1,998	1,534
Price(Cdn$per barrel)(1)				3.27	31.43
Wells drilled (net)				1.0	5.0
Wells completed		(net)		3.5	-

(1) Excludes gains and losses on risk management contracts.

(2) Certain financial amounts shown above are non-GAAP measurements. See discussion of Non-GAAP Measurements on page 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.

PRESIDENT’S MESSAGE

2020 FIRST QUARTER HIGHLIGHTS

Funds flow was largely unchanged from the first quarter of last year with higher production and lower production costs offset by lower NGL and natural gas prices.

Production was 23,946 Boe per day, an increase of 7% from the previous quarter and an increase of 21% year over year. This was consistent with guidance (24,000 to 25,000 Boe per day) with the increase resulting from the start-up of the Nig Gas Plant plus a full quarter of production from a four-well pad at Nig.
Liquids production (field condensate plus gas plant NGL) totaled 4,621 barrels per day, an increase of 8% from the previous quarter and an increase of 24% year over year.
Production from the most recent four wells in the Nig area continue to meet expectations since start-up in November 2019 with the IP150 averaging approximately 1,500 Boe per day sales (8% field condensate) for the three upper/mid Montney wells and approximately 1,000 Boe per day sales (30% field condensate) for the lower Montney well.
Revenue net of transportation was $14.27 per Boe, a decline of $11.27 per Boe, or 44% from last year, mainly due to lower NGL and natural gas prices. The NGL price declined 90% as a result of lower propane prices and from larger pricing deductions during the current marketing year ending March 2020. The natural gas price declined 43% as a result of lower pricing in the Chicago and Sumas markets (60% of sales).
Liquids represented 19% of sales volumes and 36% of production revenue (versus 19% and 30% respectively in the prior year period).
Production, general and administrative, and interest and finance costs were $6.77 per Boe, a year-over-year decline of $1.53 per Boe. Production cost decreased $0.92 per Boe with start-up of the Nig Gas Plant and the previous year was higher due to an unplanned outage at the McMahon Gas Plant.
Hedging provided a realized gain of $2.7 million versus a realized loss of $9.6 million in the prior year. The gain was from contracts for Chicago natural gas and WTI oil while the prior year loss was mainly from contracts for Sumas natural gas that were entered into before a failure on the Enbridge T-south pipeline in October 2018.
Funds flow was $16.9 million or $0.14 per share which was largely unchanged from last year with higher production and lower costs offsetting lower commodity prices.
Net income was $10.5 million compared to $0.6 million in the prior year with the improvement primarily from a noncash hedging gain of $10.5 million on the mark-to-market value of future hedging contracts which was partially offset by the deferred income tax expense of $3.9 million.
Capital investment was $26.5 million (below guidance of $30 million) and included $11 million for the Nig Gas Plant project plus $9 million to complete and tie in a three-well pad at Umbach.
Total debt including working capital deficiency was $139 million or 2.1 times annualized quarterly funds flow and, including letters of credit, represents 73% utilization of the $205 million bank line.
Commodity price hedges have increased and during the remainder of 2020 protect approximately 42% of forecast production using the mid-point of guidance. Hedges provide floor prices of approximately Cdn$2.90 per Mcf (15% higher than the first quarter average price) and WTI Cdn$64.00 per barrel in 2020 with approximately half of the hedges being collars which provide exposure to higher prices.

OPERATIONS REVIEW

Umbach, Nig and Fireweed Areas, Northeast British Columbia

Storm's land position is prospective for liquids-rich natural gas from the Montney formation and totals 121,000 net acres (172 net sections) with 79 horizontal wells (74.4 net) drilled to date.

First quarter field activity was mainly focused on completing the Nig Gas Plant and associated sales gas and NGL pipelines with start-up occurring February 22. In addition, a three-well pad (3.0 net) was completed and pipeline connected on the west side of Umbach.

During the quarter, two new wells started production leaving an inventory at the end of the quarter of two (2.0 net) drilled Montney horizontal wells that had not started producing which included one (1.0 net) completed well.

At Umbach (100% working interest), produced raw natural gas contains 1.2% H2S with approximately 85% directed to the McMahon Gas Plant and 15% to the Stoddart Gas Plant where firm processing commitments total 80 Mmcf raw gas per day (65 Mmcf per day at McMahon and 15 Mmcf per day at Stoddart). There remains significant capacity for future growth with field compression capacity totaling 150 Mmcf per day raw gas while throughput in the first quarter averaged 103 Mmcf per day (including 28 Mmcf per day from the Nig area that has been redirected to the new gas plant). During the second half of 2020, three horizontal wells (3.0 net) will be drilled depending on commodity prices and forecast funds flow.

At Nig (100% working interest), produced raw natural gas contains 0.1% H2S and is directed to the recently constructed 50 Mmcf per day sour gas plant that started up February 22. Total estimated cost of the Nig Gas Plant project is $84 million ($11 million in 2018, $61 million in 2019, $12 million in 2020) which is a reduction from the previous estimate of $86 million but higher than the initial estimate of $81 million. The project includes the facility, an eight-kilometre sales gas pipeline and a horizontal well for acid gas injection. At full capacity, incremental production versus processing at the McMahon Gas Plant is expected to be 1,500 Boe per day (50% propane, 20% butane, 5% condensate, 25% sales gas) as a result of higher NGL recovery and reduced gas shrinkage. In addition, eliminating third-party processing fees results in an operating cost of less than $2.00 per Boe which reduces the corporate operating cost. Propane will be sold at the Far East Asia Index price via the Altagas Ridley Island Export Terminal (RIPET). Since start-up, inlet volumes have gradually ramped up to 40 to 45 Mmcf per day raw and are expected to reach full capacity by the end of the third quarter. The plant has been ‘warmed up’ since mid-April to decrease NGL recovery (propane and butane) by approximately 8 Bbls per Mmcf sales as a result of current low liquids prices. Activity for the remainder of 2020 is expected to include drilling and completing four wells (4.0 net) this summer.

At Fireweed (50% working interest), first quarter activity included drilling two horizontal wells (1.0 net), completing one well (0.5 net), and starting site preparation for a 50 Mmcf per day field compression facility (expandable to 100 Mmcf per day). Further activity in 2020 has been deferred as a result of the rapid decline in oil prices. There are currently three standing wells (1.5 net) with two wells (1.0 net) having been completed with test results meeting expectations for the area (strong gas rates with higher condensate-gas ratios). Based on production history from offsetting horizontal wells, first year average field condensate-gas ratios are expected to be 30 to 70 barrels per Mmcf raw which is 100% to 400% higher than at Umbach. Investment in 2020 is expected to total $6 million net with all of this incurred in the first quarter.

A summary of horizontal well results at Nig and Umbach is provided below. IP90 and IP180 rates are less reliable indicators of relative longer-term performance since wells are initially rate restricted to manage fluid rates. Note that the 2019 wells at Nig in the upper/mid Montney were drilled on tighter inter-well spacing versus the 2018 wells (400 metres versus 465 metres) which may reduce longer-term rates and ultimate recovery.

	Frac	Completed
Year of Completion	Stages	Length	IP90 Cal Day	IP180 Cal Day	IP365 Cal Day
Umbach 2017 - 2018	34	1895 m	4.6 Mmcf/d(1)	4.4 Mmcf/d(1)	4.0 Mmcf/d(1)
19 hz’s			24 Bbls/Mmcf(2)	20 Bbls/Mmcf(2)	15 Bbls/Mmcf(2)
			19 hz’s	19 hz’s	19 hz’s
Nig 2018 upper	37	2180 m	8.1 Mmcf/d(1)	8.2 Mmcf/d(1)	7.5 Mmcf/d(1)
3 hz’s			29 Bbls/Mmcf(2)	25 Bbls/Mmcf(2)	21 Bbls/Mmcf(2)
			3 hz’s	3 hz’s	3 hz’s
Nig 2019 upper/mid	42	2240 m	8.1 Mmcf/d(1)
3 hz’s			20 Bbls/Mmcf(2)
			3 hz’s
Nig 2019 lower	42	2280 m	5.5 Mmcf/d(1)	(3)
1 hz			57 Bbls/Mmcf(2)
			1 hz

(1) Raw gas rate.

(2) Bbls/Mmcf is the condensate-gas ratio or barrels of field condensate per Mmcf raw.

(3) Shut in mid-April 2020 after 140 days of production as a result of the low condensate price.

Based on results from the 2017 and 2018 wells, Storm management is using 8 Bcf and 14 Bcf raw gas type curves (internal estimates) to forecast production at Umbach and Nig respectively. More detail on well performance and management’s type curve is available in the presentation on Storm’s website at www.stormresourcesltd.com.

HEDGING

Commodity price hedges are used to support longer-term growth by protecting pricing on up to 50% of current production for the next 18 months and up to 25% for 19 to 36 months forward (future production growth is not hedged). The current hedge position is shown below (excludes price differential contracts which are shown in the financial statements) with hedges for the remainder of 2020 protecting approximately 42% of forecast annual production using the mid-point of guidance. Hedges provide floor prices of approximately Cdn$2.90 per Mcf and WTI Cdn$64.00 per barrel in 2020 (half of the hedges are collars) and Cdn$3.10 per Mcf in 2021 (there are no WTI hedges in 2021).

Crude Oil	633 Bpd	WTI Cdn$66.79/Bbl floor, Cdn$77.08 ceiling
	822 Bpd	WTI Cdn$61.19/Bbl
Natural Gas	8,670 Mmbtu/d (7.5 Mmcf/d)	Chicago Cdn$3.33/Mmbtu
	2,200 Mmbtu/d (1.9 Mmcf/d)	Chicago US$1.54/Mmbtu floor, US$1.96 ceiling
	15,400 Mmbtu/d (13.3 Mmcf/d)	Chicago Cdn$2.48/Mmbtu floor, Cdn$3.01 ceiling
	6,300 Mmbtu/d (5.5 Mmcf/d)	NYMEX US$1.95/Mmbtu floor, US$2.48 ceiling
	2,500 Mmbtu/d (2.2 Mmcf/d)	NYMEX Cdn$2.75/Mmbtu floor, Cdn$3.26 ceiling
	2,560 Mmbtu/d (2.2 Mmcf/d)	NYMEX US$2.45/Mmbtu
	1,110 Mmbtu/d (1.0 Mmcf/d)	NYMEX Cdn$2.86/Mmbtu
	2,000 Mmbtu/d (1.7 Mmcf/d)	Sumas Cdn$3.07/Mmbtu
	10,400 GJ/d (8.5 Mmcf/d)	AECO Cdn$1.77/GJ
	2,000 GJ/d (1.6 Mmcf/d)	AECO Cdn$2.02/GJ floor, Cdn$2.49 ceiling
	9,200 GJ/d (7.5 Mmcf/d)	Station 2 Cdn$1.79/GJ
	1,550 GJ/d (1.2 Mmcf/d)	Station 2 Cdn$1.80/GJ floor, Cdn$2.47 ceiling

2021	Natural Gas	17,600 Mmbtu/d (15.2 Mmcf/d)	Chicago Cdn$3.20/Mmbtu
		3,620 Mmbtu/d (3.1 Mmcf/d)	Chicago Cdn$3.53/Mmbtu floor, Cdn$4.06 ceiling
		750 Mmbtu/d (0.6 Mmcf/d)	NYMEX US$2.40/Mmbtu floor, US$2.75 ceiling
		1,250 Mmbtu/d (1.1 Mmcf/d)	NYMEX Cdn$3.45/Mmbtu floor, Cdn$4.10 ceiling
		2,080 Mmbtu/d (1.8 Mmcf/d)	NYMEX US$2.32/Mmbtu
		6,460 Mmbtu/d (5.6 Mmcf/d)	NYMEX Cdn$3.35/Mmbtu
		7,670 GJ/d (6.3 Mmcf/d)	AECO Cdn$2.16/GJ
		2,250 GJ/d (1.8 Mmcf/d)	AECO Cdn$2.02/GJ floor, Cdn$2.49 ceiling
		21,670 GJ/d (17.8 Mmcf/d)	Station 2 Cdn$1.96/GJ
		1,750 GJ/d (1.4 Mmcf/d)	Station 2 Cdn$1.80/GJ floor, Cdn$2.47 ceiling

OUTLOOK

Production in the second quarter of 2020 is forecast to average 23,000 to 25,000 Boe per day with capital investment expected to be less than $3 million. Production in April was approximately 24,500 Boe per day based on field estimates and is expected to be lower in May and June as liquids production is being reduced as much as possible to avoid sales at very low prices after deducting transportation costs and price differentials (WTI has averaged approximately US$23.00 per barrel to date in May with the Edmonton condensate differential at -US$16.55 per barrel). Liquids production is being reduced by shutting in the lower Montney well at Nig (850 Boe per day sales, 37% liquids) and restricting wells with the highest condensate-gas ratios.

Updated guidance for 2020 is provided below. Forecast production includes the effect of a planned 25-day maintenance outage at the McMahon Gas Plant in September 2020 and from NGL recovery being reduced after ‘warming up’ the Nig Gas Plant. The ceiling for forecast fourth quarter production was reduced to 28,000 Boe per day from 30,000 Boe per day as a result of the deferral of activity at Fireweed. Capital investment is intended to be approximately equal to or less than forecast funds flow and is being reduced approximately $25 million by deferring activity at Fireweed for up to one year (first production in the second half of 2021 or in early 2022). Forecast pricing provided below reflects actual prices to date plus the approximate forward strip for the remainder of the year.

2020 Guidance

2020 Guidance
		Current
	February 27, 2020	May 12, 2020
Cdn$/US$ exchange rate	0.76	0.72
Chicago daily natural gas - US$/Mmbtu	$1.90	$2.05
Sumas monthly natural gas - US$/Mmbtu	$1.90	$2.20
AECO daily natural gas - Cdn$/GJ	$1.75	$2.20
Station 2 daily natural gas - Cdn$/GJ	$1.65	$2.15
WTI - US$/Bbl	$50.50	$30.50
Edmonton condensate diff - US$/Bbl	($4.00)	($4.50)
Est revenue net of transport (excl hedges) - $/Boe	$13.50 - $13.75	$12.00 - $13.00
Est production costs - $/Boe	$4.50 - $4.75	$4.50 - $4.75
Est royalty rate (% revenue net transportation)	5% - 7%	5% - 6%
Est mid-point field operating netback - $/Boe	$8.20	$7.20
Est realized hedging gains or (losses) - $ million	$5.0 - $6.0	$11.0 - $12.0
Est cash G&A - $ million	$6.0 - $7.0	$6.0 - $7.0

2020 Guidance (continued)

2020 Guidance (continued)
		Current
	February 27, 2020	May 12, 2020
Est interest expense - $ million	$7.0 - $8.0	$7.0 - $8.0
Est capital investment (excluding A&D) - $ million	$75.0 - $85.0	$52.0 - $60.0
	(Nig GP $14.0 million)	(Nig GP $12.0 million)
Forecast fourth quarter Boe/d	25,000 - 30,000	25,000 - 28,000
Forecast fourth quarter liquids Bbls/d	5,300 - 6,300	5,100 - 5,600
Forecast annual Boe/d	23,500 - 26,000	23,500 - 26,000
Forecast annual liquids Bbls/d	4,900 - 5,500	4,500 - 5,000
Est annual funds flow - $ million	$62.0 - $69.0(1)	$59.0 - $66.0(1)
Horizontal wells drilled - gross	6 - 10 (4.0 - 8.5 net)	6 - 9 (5.0 - 8.0 net)
Horizontal wells completed - gross	8 - 10 (6.5 - 8.5 net)	8 (7.5 net)
Horizontal wells starting production - gross	5 - 10 (5.0 - 8.5 net)	7 (7.0 net)

(1) Based on the range for forecast annual production and using the mid-point for each of the estimated field operating netback, estimated cash G&A, estimated hedging gain or loss and estimated interest expense.

Guidance History

							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

Capital investment in 2020 will be allocated as follows:

$6 million at Fireweed in the first quarter to drill two horizontal wells (1.0 net) and complete one well (0.5 net);
$36 million at Nig includes $12 million to complete the gas plant (100% working interest), drill four horizontal wells (4.0 net) and complete and pipeline connect four wells (4.0 net); and
$10 - $18 million at Umbach to complete and pipeline connect three horizontal wells (3.0 net) plus drill three horizontal wells (3.0) which are contingent on commodity prices and forecast funds flow.

Firm pipeline capacity and marketing arrangements will result in approximately 60% of forecast natural gas production in 2020 being sold into US markets and the remaining 40% in Western Canadian markets (52% directed to Chicago, 18% to BC Station 2, 17% to AECO, 8% to Sumas and 5% to Alliance ATP).

The recent, rapid decline in oil prices has materially reduced NGL and condensate prices. Based on the current forward strip, Storm’s revenue from condensate plus NGL is forecast to decline to approximately 15% of total revenue during the remainder of 2020 versus 36% in the first quarter. In response, liquids production has been reduced as much as possible while maximizing natural gas sales which includes reducing NGL recovery, storing condensate and reducing production from wells with higher condensate-gas ratios. Hedges will also mitigate the effect of low liquids prices during the remainder of 2020 with a floor of approximately WTI Cdn$64.00 per barrel on 1,450 barrels per day while the Edmonton condensate differential to WTI was fixed at -Cdn$7.24 per barrel on 730 barrels per day.

Partially offsetting the effect of lower oil prices is stronger natural gas prices which have strengthened significantly over the last two months in anticipation of declining associated gas production from US oil producers and from liquids-rich natural gas producers in Canada where growth has been largely subsidized by revenue from liquids production. With

the improvement in natural gas prices the hedge position was expanded and currently protects pricing during the remainder of 2020 on approximately 42% of forecast annual production versus 16% at the last update on February 27.

Previously, the emphasis was on growing liquids production to increase revenue and that was largely going to come from growth at Fireweed where condensate makes up a larger proportion of the sales volume than at Nig and Umbach. With the decline in the WTI oil price reducing expected rates of return and forecast funds flow for 2020, activity at Fireweed will be deferred by up to one year with an option to accelerate depending on commodity prices. Partially offsetting this, the improvement in the Station 2 natural gas price has improved rates of return at Umbach and three horizontal wells are being planned for drilling in the second half of 2020 depending on commodity prices and forecast funds flow (completions in early 2021).

Regarding the COVID-19 pandemic, the impacts to date for Storm have been relatively minor. The health and safety of everyone working at Storm has always been and will continue to be a priority and since March 13, the majority of office employees transitioned to working remotely while field employees have adjusted procedures and travel arrangements to minimize contact with others. The efforts of everyone at Storm in managing the challenges caused by the pandemic are greatly appreciated.

The objective remains to increase asset value per share by converting resource into per-share growth of funds flow and reserves value. Commodity price volatility continues to be one of the biggest risks to manage with the recent reversal of oil and natural gas prices requiring that the near-term growth plan be changed to adapt to the ‘new normal’. Shifting the operational focus away from growing liquids revenue will take some time to execute and will be challenging given that liquids revenue was a big contributor to funding Storm’s growth over the last several years (and other producers to an even greater extent). However, Storm’s main competitive advantage has not changed and remains a large, high quality land position in the Montney fairway where significant longer-term upside remains given PDP reserves are recognized only in the upper Montney on approximately 8% of the total land position.

Respectfully,

==> picture [96 x 60] intentionally omitted <==

Brian Lavergne, President and Chief Executive Officer

May 12, 2020

Boe Presentation – For the purpose of calculating unit revenues and costs, natural gas is converted to a barrel of oil equivalent (“Boe”) using six thousand cubic feet (“Mcf”) of natural gas equal to one barrel of oil unless otherwise stated. Boe may be misleading, particularly if used in isolation. A Boe conversion ratio of six Mcf to one barrel (“Bbl”) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All Boe measurements and conversions in this report are derived by converting natural gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil. Mboe means 1,000 Boe.

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

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

Forward-Looking Statements – Such statements made in this report are subject to the limitations set out in Storm’s Management’s Discussion and Analysis dated May 12, 2020 for the three months ended March 31, 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.

==> picture [434 x 215] intentionally omitted <==

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

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
----- End of picture text -----

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%

==> picture [432 x 237] intentionally omitted <==

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

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)
----- End of picture text -----

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.

==> picture [434 x 216] intentionally omitted <==

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

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
----- End of picture text -----

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.

==> picture [433 x 215] intentionally omitted <==

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

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$
----- End of picture text -----

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.

==> picture [450 x 217] intentionally omitted <==

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

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
----- End of picture text -----

The field operating netback for the first quarter of 2020 decreased by 27% (10% decrease after hedging) compared to the fourth quarter of 2019.

==> picture [453 x 215] intentionally omitted <==

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

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
----- End of picture text -----

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.

==> picture [470 x 272] intentionally omitted <==

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

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
----- End of picture text -----

(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.

==> picture [470 x 266] intentionally omitted <==

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

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
----- End of picture text -----

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

Funds flow for the first 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.

(3) Excludes the fair value of risk management contracts, decommissioning liability and lease liability

CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS

Condensed Interim Consolidated Statements of Financial Position

(Canadian$000s) (unaudited)	Notes	March 31,2020	December 31,2019
ASSETS
Current
Accounts receivable	12	$ 20,494	$ 21,961
Prepaids and deposits		561	764
Risk management contracts	12	11,805	1,113
		32,860	23,838
Exploration and evaluation	3	99,360	99,737
Property and equipment	4	503,442	490,264
Right-of-use asset	7	2,548	2,657
		$638,210	$616,496

LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Accounts payable and accrued liabilities		$ 34,863	$ 30,018
Current portion of decommissioning liability	8	736	448
Current portion of lease liability	7	508	507
Risk management contracts	12	799	2,042
		36,906	33,015
Bank indebtedness	5	124,824	121,608
Risk management contracts	12	2,362	904
Lease liability	7	2,140	2,234
Decommissioning liability	8	26,064	27,667
Deferred income taxes		13,218	9,360
		205,514	194,788
Shareholders' equity
Share capital	9	391,444	391,444
Contributed surplus	10	18,081	17,605
Retained earnings		23,171	12,659
		432,696	421,708
Commitments	14
		$638,210	$616,496

See accompanying notes to the condensed interim consolidated financial statements.

On behalf of the Board:

==> picture [144 x 39] intentionally omitted <==

Director

==> picture [191 x 55] intentionally omitted <==

Director

Condensed Interim Consolidated Statements of Income and Comprehensive Income

		Three Months Ended	Three Months Ended
(Canadian$000s exceptper-share amounts) (unaudited)	Notes	March 31,2020	March 31,2019
Revenue
Revenue from product sales	6	$ 41,923	$ 55,766
Royalties		(2,107)	(4,657)
		39,816	$ 51,109
Realizedgain(loss)on risk management contracts	12	2,737	(9,593)
		$ 42,553	$ 41,516
Expenses
Production		11,259	10,862
Transportation		10,834	10,206
General and administrative		1,867	2,851
Share-based compensation	10	476	596
Depletion and depreciation	4, 7	12,005	9,746
Exploration and evaluation costs expensed	3	450	-
Accretion	8	105	129
Interest and finance costs		1,646	1,118
Unrealized (gain) loss on risk management contracts	12	(10,477)	4,808
Unrealized revaluation loss on investment		18	13
		28,183	40,329
Net income and comprehensive income		14,370	1,187
Deferred income tax expense		3,858	580
Net income and comprehensive income		$ 10,512	$ 607

Net income per share	11
- Basic and diluted		$ 0.09	$ 0.00

See accompanying notes to the condensed interim consolidated financial statements.

Condensed Interim Consolidated Statements of Changes in Shareholders’ Equity

(Canadian$000s) (unaudited)			Three	MonthsEndedMarch31,2020	MonthsEndedMarch31,2020
			Contributed	Retained
	Notes	Share Capital	Surplus	Earnings	Total Equity
Balance, beginning of period		$ 391,444	$ 17,605	$ 12,659	$ 421,708
Net income for the period		-	-	10,512	10,512
Share-based compensation	10	-	476	-	476
Balance, end of period		$ 391,444	$ 18,081	$ 23,171	$ 432,696

(Canadian$000s) (unaudited)			Three	Months Ended	March 31,2019
			Contributed	Retained
	Notes	Share Capital	Surplus	Earnings	Total Equity
Balance, beginning of period		$ 391,444	$ 15,141	$ 1,346	$ 407,931
Net income for the period		-	-	607	607
Share-based compensation	10	-	596	-	596
Balance, end of period		$ 391,444	$ 15,737	$ 1,953	$ 409,134

See accompanying notes to the condensed interim consolidated financial statements.

Condensed Interim Consolidated Statements of Cash Flows

		Three Months Ended	Three Months Ended
(Canadian$000s) (unaudited)	Notes	March 31,2020	March 31,2019
Operating activities
Net income for the period		$ 10,512	$ 607
Non-cash items:
Unrealized (gain) loss on risk management	12	(10,477)	4,808
Depletion, depreciation and accretion	4, 7, 8	12,110	9,875
Share-based compensation	10	476	596
Lease interest	7	34	38
Exploration and evaluation costs expensed	3	450	-
Unrealized revaluation loss on investment		18	13
Deferred income tax expense		3,858	580
Decommissioning expenditures	8	(92)	-
Funds flow		16,889	16,517
Net change in non-cash working capital items	13	(472)	5,943
		16,417	22,460
Financing activities
Payment of lease liability	7	(127)	(125)
Increase in bank indebtedness		3,216	2,830
		3,089	2,705
Investing activities
Additions to property and equipment	4	(26,242)	(16,361)
Additions to exploration and evaluation assets	3	(233)	(583)
Net change in non-cash working capital items	13	6,969	(8,221)
		(19,506)	(25,165)
Change in cash during the period		-	-
Cash, beginning of period		-	-
Cash, end of period		$ -	$ -

See accompanying notes to the condensed interim consolidated financial statements.

NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS

As at March 31, 2020 and December 31, 2019 and for the three months ended March 31, 2020 and 2019

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

1. REPORTING ENTITY

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

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

2. BASIS OF PRESENTATION

Statement of Compliance

The financial statements have been prepared in accordance with International Accounting Standard (“IAS”) 34 “Interim Financial Reporting” using accounting policies consistent with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). Certain information and disclosures normally included in the notes to the consolidated financial statements have been condensed or have been disclosed on an annual basis only. Accordingly, these condensed interim consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements as at and for the year ended December 31, 2019. All financial information is reported in thousands of Canadian dollars, which is the functional currency of the Company.

These financial statements were authorized for issue by the Board of Directors on May 12, 2020.

Basis of Measurement

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

Significant Accounting Judgments, Estimates and Assumptions

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

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

Critical judgments applied by management to accounting policies that have the most significant effect on the amounts in the financial statements are described in Note 5 to the Company’s audited consolidated financial statements for the year ended December 31, 2019.

In March 2020, the World Health Organization declared the COVID-19 outbreak a global pandemic. The rapid outbreak and subsequent measures intended to limit the spread of COVID-19 have contributed to a significant increase in economic uncertainty, with more volatile commodity prices, currency exchange rates and interest rates. The duration and severity of the business disruptions and reduction in consumer activity internationally and the resulting financial effect is difficult to reliably estimate. The results of the economic downturn and any potential resulting direct or indirect

effect on the Company has been considered in management’s estimates at period end. However, there could be further prospective material effects in future periods.

3. EXPLORATION AND EVALUATION

3. EXPLORATION AND EVALUATION
	Three Months Ended	Year ended
	March 31,2020	December 31,2019
Balance, beginning of period	$ 99,737	$ 102,277
Additions	233	2,169
Dispositions	-	(1,083)
Expiries - exploration and evaluation costs expensed	(450)	(1,140)
Future decommissioning costs	(160)	178
Transfer topropertyand equipment	-	(2,664)
Balance, end ofperiod	$ 99,360	$ 99,737

As at March 31, 2020, the Company reviewed the carrying amounts of exploration and evaluation assets for indicators of potential impairment. As a result of this assessment, no indicators of impairment were identified.

4. PROPERTY AND EQUIPMENT

4. PROPERTY AND EQUIPMENT
	Three Months Ended	Year ended
	March31,2020	December31,2019
Cost
Balance, beginning of period	$ 746,515	$ 646,983
Additions	26,242	95,757
Future decommissioning costs	(1,168)	1,111
Transfer from exploration and evaluation assets	-	2,664
Balance, end ofperiod	$ 771,589	$ 746,515
Accumulated depletion and depreciation
Balance, beginning of period	$ (256,251)	$ (216,182)
Depletion and depreciation	(11,896)	(40,069)
Balance, end ofperiod	$(268,147)	$(256,251)
Net book value, beginning of period	$ 490,264	$ 430,801
Net book value, end ofperiod	$ 503,442	$ 490,264

As at March 31, 2020, the Company evaluated property and equipment for indicators of potential impairment. As a result of this assessment, no indicators were identified and no impairment was recorded on property and equipment.

As at December 31, 2019, the balance of assets under construction not subject to depreciation or depletion was $65.0 million and related to the construction of a gas plant at Nig, located in northeast British Columbia. During the first quarter of 2020, construction of the Nig Gas Plant was completed and the gas plant became operational on February 22, 2020 and will be depreciated on a straight-line basis over its estimated useful life of 35 years.

5. BANK INDEBTEDNESS

At March 31, 2020, debt including outstanding letters of credit amounted to $135.1 million, representing approximately 66% of the available credit facility.

6. REVENUE FROM PRODUCT SALES

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

	Three Months Ended	Three Months Ended
	March 31,2020	March 31,2019
Natural gas	$ 26,850	$ 39,005
Condensate	14,478	12,422
NGL	595	4,339
Total	$ 41,923	$ 55,766

Storm’s revenue was generated mostly in British Columbia where production was sold primarily to three major energy customers with investment grade credit ratings which accounted for 98% of the Company’s total revenue from product sales for the three months ended March 31, 2020 (March 31, 2019 – 81% from two major customers). The majority of revenue is derived from variable price contracts based on index prices at each sales point. Of total natural gas revenue for the three months ended March 31, 2020, 50% received Chicago pricing, 25% received Station 2 pricing, 10% received Sumas pricing, 7% received AECO pricing and the remaining 8% received ATP pricing.

7. RIGHT-OF-USE ASSET AND LEASE LIABILITY

Right-of-Use Asset

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

corporate office lease in Calgary:
	Three Months Ended	Year ended
	March31,2020	December31,2019
Cost
Balance, beginning of period	$ 3,094	$ 3,094
Additions	-	-
Balance, end ofperiod	$ 3,094	$ 3,094
Accumulated depreciation
Balance, beginning of period	$ (437)	$ -
Depreciation	(109)	(437)
Balance, end ofperiod	$(546)	$(437)
Net book value, beginning of period	$ 2,657	$ 3,094
Net book value, end ofperiod	$ 2,548	$ 2,657

As at March 31, 2020, the net book value of the right-of-use asset for the Company’s corporate office lease in Calgary is $2.5 million (December 31, 2019 - $2.7 million) with a remaining lease term to the year 2026.

Lease Liability

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

office lease in Calgary:
	Three Months Ended	Year Ended
	March31,2020	December31,2019
Balance, beginning of period	$ 2,741	$ 3,094
Lease payments	(127)	(500)
Lease interest	34	147
Balance, end of period	$ 2,648	$ 2,741
Less currentportion	508	507
Long-termportion	$ 2,140	$ 2,234

As at March 31, 2020, the total undiscounted amount of the estimated future cash flows to settle the Company’s lease liability over the remaining lease term is $3.1 million.

Short-term leases are leases with a lease term of twelve months or less. During the three months ended March 31, 2020, short-term lease costs of approximately $0.5 million (March 31, 2019 - $1.7 million) were incurred primarily relating to the lease of drilling equipment which was captured within property and equipment costs.

8 . DECOMMISSIONING LIABILITY

The Company provides for the future cost of decommissioning crude oil and natural gas production assets, including well sites, gathering systems and facilities. The total decommissioning liability is estimated based on the Company’s net ownership interest in wells and facilities, the estimated costs to abandon and reclaim the wells, gathering systems and facilities and the estimated timing of future costs. The total estimated inflated and undiscounted liability required to settle the Company’s decommissioning obligation is approximately $33.3 million (December 31, 2019 - $38.3 million), with the majority of payments being made in the years 2034 to 2054. A risk-free discount rate of 1.4% (December 31, 2019 – 1.7%) and an inflation rate of 0.8% (December 31, 2019 – 1.4%) was used to calculate the present value of the decommissioning obligation, amounting to $26.8 million at March 31, 2020.

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

	Three Months Ended	Year Ended
	March 31,2020	December 31,2019
Balance, beginning of period	$ 28,115	$ 26,334
Obligations incurred	127	2,706
Obligations settled	(92)	(246)
Change in estimates(1)	(1,455)	(1,171)
Accretion expense	105	492
Balance, end of period	$ 26,800	$ 28,115
Less currentportion	736	448
Long-termportion	$ 26,064	$ 27,667

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

9. SHARE CAPITAL

Authorized

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

Issued

Issued
						Number of Common Shares	Consideration
Balance as at December	31,	2019	and March	31,	2020	121,557	$ 391,444

For the period from January 1, 2020 to May 12, 2020 there were no common shares issued upon the exercise of stock options.

10. SHARE-BASED COMPENSATION

The Company has a stock option plan under which it may grant, at the Company’s discretion, options to purchase common shares to directors, officers and employees. Options are granted at the volume weighted average price of the shares on the TSX for the five trading days immediately preceding the date of grant, have a four-year term and vest in one-third tranches over three years. Under the stock option plan, at March 31, 2020, a total of 12,155,681 common shares were available for issuance, options in respect of 10,212,100 common shares were issued and outstanding and options in respect of 1,943,581 common shares were available for future issue.

At May 12, 2020, the date of this quarterly report, options in respect of 10,235,100 common shares were issued and outstanding and options in respect of 1,920,581 common shares are available for future issue.

Details of the options outstanding at March 31, 2020 are as follows:

		Weighted Average
	Number of Options(000s)	Exercise Price
Outstanding at December 31, 2019	10,188	$ 2.74
Granted duringtheperiod	24	$ 1.57
Outstandingat March 31, 2020	10,212	$ 2.74
Number exercisable at March 31, 2020	4,666	$ 3.82

Range of Exercise Price		OutstandingOptions		Exercisable	Options
	Number of	Weighted	Weighted	Number of	Weighted
	Options	Average	Average	Options	Average
	Outstanding	Remaining	Exercise	Outstanding	Exercise
	(000s)	Life(years)	Price	(000s)	Price
$1.36 - $2.85	5,502	3.2	$ 1.65	851	$ 1.83
$2.86 - $4.50	2,696	1.7	$ 3.00	1,801	$ 3.02
$4.51 - $5.50	2,014	0.7	$ 5.39	2,014	$ 5.39
Total	10,212	2.3	$ 2.74	4,666	$ 3.82

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

The weighted average inputs used in the Black-Scholes pricing model to determine the fair value of the options granted during the three months ended March 31, 2020 of $0.58 per share include the following:

	2020
Share price	$1.57
Exercise price	$1.57
Volatility	48%
Forfeiture rate	2%
Expected option life (years)	3.7
Risk-free interest rate	1.4%

Share-based compensation expense of $0.5 million was charged to the consolidated statement of income during the three months ended March 31, 2020 (March 31, 2019 - $0.6 million) with an equivalent offset to contributed surplus.

11. NET INCOME PER SHARE

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

Basic and diluted net income per share were calculated as follows:
	Three Months Ended	Three Months Ended
	March 31,2020	March 31,2019
Net income for theperiod	$ 10,512	$ 607
Weighted average number of common shares outstanding - basic
Common shares outstanding at beginning of period	121,557	121,557
Effect of shares issued	-	-
Weighted average number of common shares outstanding - basic	121,557	121,557
Dilutive effect of outstandingoptions(1)	-	296
Weighted average number of common shares outstanding- diluted	121,557	121,853
Net income per share
Basic and diluted	$ 0.09	$ 0.00

(1) Excludes effect of 10.2 million weighted average common shares related to stock options that were anti-dilutive for the three months ended March 31, 2020 (6.6 million weighted average common shares related to stock options for the three months ended March 31, 2019).

12. FINANCIAL INSTRUMENTS

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

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

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide continual and verifiable pricing information.
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities and interest rates, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.
Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.

The carrying value of bank indebtedness approximates its fair value as it bears interest at market rates. The fair value of the Company’s risk management contracts described below is based on forward prices of commodities and interest rates available in the marketplace and they are therefore classified as Level 2 financial instruments. The Company does not have any financial instruments classified as Level 3 and there were no transfers between levels within the fair value hierarchy for the three months ended March 31, 2020.

The Company’s risk management contracts are subject to master netting agreements that create a legally enforceable right to offset by counterparty the related financial assets and financial liabilities on the Company’s consolidated statements of financial position. The following is a summary of the Company’s financial assets and financial liabilities that are subject to offset as at March 31, 2020:

	Gross Amounts	Gross Amounts	Net Amounts
	Recognized as Financial	of Financial Assets	Recognized as Financial
	Assets(Liabilities)	(Liabilities)Offset	Assets(Liabilities)
Risk management contracts
Current asset	$ 15,951	$ (4,146)	$ 11,805
Long-term asset	-	-	-
Current liability	(4,945)	4,146	(799)
Long-term liability	(2,362)	-	(2,362)
Netposition	$ 8,644	$ -	$ 8,644

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

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

Accounts Receivable

The Company’s accounts receivable tend to be concentrated with a limited number of marketers of the Company’s production as well as joint venture partners and are subject to normal industry credit risk. Receivables from crude oil and natural gas marketers are typically collected on or about the 25[th] of the following month. The Company's production is sold to organizations whose credit worthiness is in part assessable from publicly available information. As at March 31, 2020, the Company’s three major energy customers with investment grade credit ratings, accounted for $10.4 million (March 31, 2019 - $19.0 million) of total receivables and 98% of total revenues (March 31, 2019 – 81% from two major customers). Where operations involve partners in a joint venture, the Company attempts to mitigate the risk from joint venture receivables by obtaining pre-approval and cash call deposits from its partners in advance of significant capital expenditures. Receivables from joint ventures are typically collected within one to three months of the joint venture bill being issued. As at March 31, 2020, there were no receivables outstanding for more than 60 days. No material default on outstanding receivables is anticipated as none of the Company’s outstanding receivables are considered past due at March 31, 2020.

The maximum exposure to credit risk at March 31, 2020 was the carrying amount of accounts receivable of $20.5 million and risk management contract assets of $11.8 million. No receivables were impaired at March 31, 2020.

Commodity Price Risk

The Company uses risk management contracts to manage its exposure to fluctuations in commodity prices, by fixing prices of future deliveries of crude oil and natural gas and thus providing stability of funds flow. Although the Company had no crude oil production at March 31, 2020, part of its condensate and NGL stream is sold at a price based on crude oil. Accordingly, a financial investment based on crude oil is used as a proxy for the Company’s condensate and NGL stream. At the date of this report, the Company had entered into the following outstanding financial risk management contracts in place to manage commodity price risk:

As at May 12, 2020	Daily Volume	Period Hedged	Average Price(Cdn$)
Natural Gas Swaps
NYMEX (US$)	2,000 Mmbtu	Apr 1, 2020 – Oct 31, 2020	US$2.42/Mmbtu
NYMEX (US$)	4,500 Mmbtu	Nov 1, 2020 – Dec 31, 2020	US$2.49/Mmbtu
NYMEX (US$)	2,500 Mmbtu	Jan 1, 2021 – Oct 31, 2021	US$2.32/Mmbtu
NYMEX	2,500 Mmbtu	Jul 1, 2020 – Oct 31, 2020	$2.86/Mmbtu
NYMEX	2,500 Mmbtu	Jan 1, 2021 – Mar 31, 2021	$3.69/Mmbtu
NYMEX	10,000 Mmbtu	Apr 1, 2021 – Oct 31, 2021	$3.32/Mmbtu
Chicago	20,000 Mmbtu	Apr 1, 2020 – Jun 30, 2020	$3.29/Mmbtu
Chicago	1,500 Mmbtu	Jul 1, 2020 – Oct 31, 2020	$3.29/Mmbtu
Chicago	6,000 Mmbtu	Nov 1, 2020 – Dec 31, 2020	$3.55/Mmbtu
Chicago	13,500 Mmbtu	Jan 1, 2021 – Mar 31, 2021	$3.65/Mmbtu
Chicago	22,000 Mmbtu	Apr 1, 2021 – Oct 31, 2021	$3.04/Mmbtu
Chicago	3,000 Mmbtu	Oct 1, 2021 – Dec 31, 2021	$3.45/Mmbtu
Chicago	4,500 Mmbtu	Nov 1, 2021 – Mar 31, 2022	$3.65/Mmbtu
Sumas	4,500 Mmbtu	Jul 1, 2020 – Oct 31, 2020	$3.08/Mmbtu
AECO	12,000 GJ	Apr 1, 2020 – Oct 31, 2020	$1.72/GJ
AECO	5,000 GJ	Nov 1, 2020 – Mar 31, 2021	$2.25/GJ
AECO	11,000 GJ	Apr 1, 2021 – Oct 31, 2021	$2.14/GJ
Station 2	5,000 GJ	Apr 1, 2020 – Oct 31, 2020	$1.57/GJ
Station 2	3,000 GJ	May 1, 2020 – Aug 31, 2020	$1.65/GJ
Station 2	18,000 GJ	Nov 1, 2020 – Mar 31, 2021	$2.05/GJ
Station 2	25,000 GJ	Apr 1, 2021 – Oct 31, 2021	$1.87/GJ
Station 2	15,500 GJ	Nov 1, 2021 – Mar 31, 2022	$2.31/GJ
Station 2	3,000 GJ	Apr 1,2022 – Oct 31,2022	$1.90/GJ

As at May 12, 2020	Daily Volume	Period Hedged	Average Price(Cdn$)
Natural Gas Collars
NYMEX (US$)	3,000 Mmbtu	Apr 1, 2020 – Jun 30, 2020	US$1.90 - $2.45/Mmbtu
NYMEX (US$)	13,000 Mmbtu	Jul 1, 2020 – Oct 31, 2020	US$1.92 - $2.41/Mmbtu
NYMEX (US$)	8,000 Mmbtu	Nov 1, 2020 – Dec 31, 2020	US$1.96 - $2.49/Mmbtu
NYMEX (US$)	3,000 Mmbtu	Jan 1, 2021 – Mar 31, 2021	US$2.40 - $2.75/Mmbtu
NYMEX	12,500 Mmbtu	Apr 1, 2020 – Jun 30, 2020	$2.74 - $3.22/Mmbtu
NYMEX	22,500 Mmbtu	Jul 1, 2020 – Sep 30, 2020	$2.78 - $3.30/Mmbtu
NYMEX	17,500 Mmbtu	Oct 1, 2020 – Oct 31, 2020	$2.74 - $3.31/Mmbtu
NYMEX	19,500 Mmbtu	Nov 1, 2020 – Dec 31, 2020	$2.81 - $3.36/Mmbtu
NYMEX	5,000 Mmbtu	Jan 1, 2021 – Mar 31, 2021	$3.45 - $4.10/Mmbtu
NYMEX	10,500 Mmbtu	Jan 1, 2021 – Mar 31, 2021	$3.46 - $3.96/Mmbtu
NYMEX	6,000 Mmbtu	Nov 1, 2021 – Mar 31, 2022	$3.53 - $4.13/Mmbtu
AECO	9,000 GJ	Nov 1, 2020 – Mar 31, 2021	$2.02 - $2.49/GJ
AECO	7,000 GJ	Nov 1,2020 – Mar 31,2021	$1.90 -$2.58/GJ
Natural Gas Differential Swaps
NYMEX:Chicago (US$)	12,500 Mmbtu	Apr 1, 2020 – Dec 31, 2020	NYMEX minus US$0.274/Mmbtu
NYMEX:Chicago (US$)	5,000 Mmbtu	Jul 1, 2020 – Oct 31, 2020	NYMEX minus US$0.315/Mmbtu
NYMEX:Chicago (US$)	12,500 Mmbtu	Jan 1, 2021 – Dec 31, 2021	NYMEX minus US$0.256/Mmbtu
NYMEX:Chicago	5,000 Mmbtu	Apr 1, 2020 – Jun 30, 2020	NYMEX minus $0.29/Mmbtu
NYMEX:Chicago	22,500 Mmbtu	Jul 1, 2020 – Sep 30, 2020	NYMEX minus $0.30/Mmbtu
NYMEX:Chicago	17,500 Mmbtu	Oct 1, 2020 – Oct 31, 2020	NYMEX minus $0.31/Mmbtu
NYMEX:Chicago	19,500 Mmbtu	Nov 1, 2020 – Dec 31, 2020	NYMEX minus $0.28/Mmbtu
NYMEX:Chicago	10,500 Mmbtu	Jan 1, 2021 – Mar 31, 2021	NYMEX plus $0.048/Mmbtu
NYMEX:Chicago	6,000 Mmbtu	Nov 1, 2021 – Mar 31, 2022	NYMEX plus $0.073/Mmbtu
AECO:Station 2	7,000 GJ	Nov 1,2020 – Mar 31,2021	AECO minus$0.10/GJ
Crude Oil Swaps
WTI	200 Bbls	Apr 2020	$31.90/Bbl
WTI	750 Bbls	May 2020	$33.80/Bbl
WTI	750 Bbls	Apr 1, 2020 – Jun 30, 2020	$71.92/Bbl
WTI	700 Bbls	Jul 1,2020 – Dec 31,2020	$61.72/Bbl
Crude Oil Collars
WTI	900 Bbls	Apr 1, 2020 – Jun 30, 2020	$70.89 - $80.89/Bbl
WTI	500 Bbls	Jul 1,2020 – Dec 31,2020	$63.10 -$73.66/Bbl
Crude Oil Differential Swaps
WTI:C5	400 Bbls	Apr 1, 2020 – Jun 30, 2020	WTI minus $4.25/Bbl
WTI:C5	600 Bbls	Apr 1,2020 – Dec 31,2020	WTI minus $7.90/Bbl

Physical Delivery Sales Contracts

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

	DailyVolume	Contract Price
Natural Gas
Apr 2020 – Oct 2020	14,028 Mmbtu at Station 2	Sumas less US$0.69/Mmbtu
Apr 2020 – Oct 2020	6,000 GJ at Station 2	AECO 7A less Cdn$0.295/GJ
Nov 2020 – Oct 2021	5,000 GJ at Station 2	AECO 7A less Cdn$0.125/GJ
Apr 2020 – Mar 2021	6,000 GJ at ATP	AECO 5Aplus Cdn$0.09/GJ

Interest Rate Risk

The Company may enter into interest rate swap contracts to manage the uncertainty of variable interest rates by fixing the variable component of a portion of the interest paid on the Company’s revolving bank facility. As at March 31, 2020, the Company had the following outstanding financial risk management contracts in place to manage interest rate risk:

			Notional		Fixed
Index	Effective	Date	Principal	RemainingTerm	Contract Rate
One-month bankers’ acceptance - CDOR(1)	May	2019	$25 million	Apr 2020 – May 2022	1.949%
One-month bankers’ acceptance - CDOR(1)	Jan	2020	$10 million	Apr 2020 – Jan 2023	1.943%
One-month bankers’ acceptance - CDOR(1)	Jan	2020	$15 million	Apr 2020 – Jan 2021	1.985%

(1) Canadian Dollar Offered Rate.

Risk Management

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

The fair market value of these risk management contracts at March 31, 2020 was a net asset position of $8.6 million (December 31, 2019 – net liability position of $1.8 million) and is included on the balance sheet as either a risk management asset or liability and is classified as current or non-current based on the contractual terms specific to the instruments. For the three months ended March 31, 2020, this resulted in an unrealized mark-to-market gain of $10.5 million (March 31, 2019 - unrealized mark-to-market loss of $4.8 million) when measured against the fair market value at the end of the preceding reporting period. These amounts are recognized in the consolidated statement of income and comprehensive income.

The Company realized a gain from risk management price contracts in place in the amount of $2.7 million for the three months ended March 31, 2020 (March 31, 2019 – realized loss of $9.6 million).

Sensitivities

The following table summarizes the effects of movement in commodity prices and interest rates on net income due to changes in the fair value of risk management contracts in place at March 31, 2020. Changes in the fair value generally cannot be extrapolated because the relationship of a change in an assumption to the change in fair value may not be linear.

linear.
	ThreeMonthsEndedMarch31,2020
Factor	Gain/(Loss)
Increase of US$10.00/Bbl in the price of WTI(1)	$ (7,045)
Decrease of US$10.00/Bbl in the price of WTI(1)	$ 7,045
Increase of US$0.10/Mmbtu in the price of NYMEX natural gas	$ (5,845)
Decrease of US$0.10/Mmbtu in the price of NYMEX natural gas	$ 5,845
Increase of 100 basis points (1%) in interest rates	$ 951
Decrease of 100 basispoints(1%)in interest rates	$(951)

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

13. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in non-cash working capital

Changes in non-cash working capital
	Three Months Ended	Three Months Ended
	March 31,2020	March 31,2019
Accounts receivable	$ 1,449	$ 6,028
Prepaids and deposits	203	265
Accountspayable and accrued liabilities	4,845	(8,571)
Change in non-cash workingcapital	$ 6,497	$(2,278)
Relating to:
Operating activities	$ (472)	$ 5,943
Investingactivities	6,969	(8,221)
Change in non-cash workingcapital	$ 6,497	$(2,278)
Interestpaid duringtheperiod	$ 1,569	$ 1,037
Income taxespaid duringtheperiod	$ -	$ -

14. COMMITMENTS

At March 31, 2020, the Company has the following long-term commitments over the next five years and thereafter:

	2020	2021	2022	2023	2024	Thereafter	Total
Transportation and processing commitments	$ 47,980	$ 63,499	$ 51,012	$ 27,677	$ 27,812	$ 209,074	$ 427,054
Office lease(1)	267	356	356	356	356	385	2,076
Total	$ 48,247	$ 63,855	$ 51,368	$ 28,033	$ 28,168	$ 209,459	$ 429,130

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

CORPORATE INFORMATION

Officers

Brian Lavergne President & Chief Executive Officer

Robert S. Tiberio Chief Operating Officer

Michael J. Hearn Chief Financial Officer

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

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

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_ab547302-e005-46f1-9fc3-0890eab5761a.pdf

Highlights

2020 FIRST QUARTER HIGHLIGHTS

Umbach, Nig and Fireweed Areas, Northeast British Columbia

HEDGING

OUTLOOK

2020 Guidance (continued)

Guidance History

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

Condensed Interim Consolidated Statements of Financial Position

Condensed Interim Consolidated Statements of Income and Comprehensive Income

Condensed Interim Consolidated Statements of Changes in Shareholders’ Equity

Condensed Interim Consolidated Statements of Cash Flows

NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS

1. REPORTING ENTITY

2. BASIS OF PRESENTATION

Statement of Compliance

Basis of Measurement

Significant Accounting Judgments, Estimates and Assumptions

3. EXPLORATION AND EVALUATION

4. PROPERTY AND EQUIPMENT

5. BANK INDEBTEDNESS

6. REVENUE FROM PRODUCT SALES

7. RIGHT-OF-USE ASSET AND LEASE LIABILITY

Right-of-Use Asset

Lease Liability

8 . DECOMMISSIONING LIABILITY

9. SHARE CAPITAL

Authorized

Issued

10. SHARE-BASED COMPENSATION

11. NET INCOME PER SHARE

12. FINANCIAL INSTRUMENTS

Accounts Receivable

Commodity Price Risk

Interest Rate Risk

Risk Management

Storm Resources Ltd. Interim / Quarterly Report 2020