Storm Resources Ltd. - Management Reports 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 and year ended December 31, 2019. It should be read in conjunction with (i) the Company’s audited consolidated financial statements for the years ended December 31, 2019 and 2018, (ii) each of the Company’s unaudited condensed interim consolidated financial statements for the three months ended March 31, June 30 and September 30, 2019, and (iii) the press release issued by the Company on February 27, 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 29, 2019 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 February 27, 2020.

See discussion related to “Forward-Looking Statements”, “Boe Presentation” and “Non-GAAP Measurements” on pages 38 to 40.

BASIS OF PRESENTATION

Financial data presented below have largely been derived from the Company’s audited consolidated financial statements for the year ended December 31, 2019 and the unaudited interim consolidated financial information for the three months ended December 31, 2019 (the “financial statements”), prepared in accordance with International Financial Reporting Standards (“IFRS”). Accounting policies adopted by the Company are referred to in Note 3 to the audited consolidated financial statements for the years ended December 31, 2019 and 2018. The reporting and the functional currency is the Canadian dollar.

Unless otherwise indicated, tabular financial amounts, other than per-share amounts, are in thousands. Comparative information is provided for the three months and year ended December 31, 2018.

OPERATIONAL AND FINANCIAL RESULTS

Overview

Year Ended December 31, 2019

Fiscal 2019 was defined by third-party outages (total of 43 days) and low commodity prices that reduced Storm’s production and funds flow. As previously disclosed, the McMahon gas plant, which processed the bulk of Storm’s natural gas production in 2019, was subject to six days of planned and 31 days of unplanned outages, for a total of 37 days during the year. In addition, production was restricted at times during the year in response to ongoing weakness in Western Canadian natural gas prices. As a result, production remained relatively flat for the first eleven months of the year before ramping up in December. Despite the AECO daily price averaging $1.67 per GJ and Station 2 averaging $0.96 per GJ in 2019, Storm’s realized natural gas price was $3.21 per Mcf for the year. This highlights the benefit of the Company’s diversified marketing strategy whereby 68% of the Company’s natural gas was sold into higher priced Chicago and Sumas markets which offset weaker pricing at Station 2 and AECO. As noted in the past, weakness in Western Canadian natural gas prices has been due to record supply levels, further exacerbated for Canadian producers by a lack of growth in egress to other markets, although showed improvement in the fourth quarter due to low storage levels and slowing supply growth.

When comparing to 2018, condensate and NGL prices were down 13% and 70%, respectively. Benchmark crude oil pricing decreased in 2019 compared to 2018 as a result of a lower oil demand forecast due to trade tensions between China and the US which continued to affect the global economy, tempered by supply levels that were reduced by output cuts and US sanctions on Iran and Venezuela. Elevated supply levels for NGL in Western Canada and constrained take-away capacity materially reduced Storm’s realized NGL price for the contract period that commenced in April 2019 and ends in March 2020. Storm’s NGL price averaged 14% of WTI in Canadian dollars in 2019, materially lower than the average of 43% of WTI in Canadian dollars that was realized in 2018.

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 33% to the Company’s top line revenue compared to 35% in the prior year, with relative strength in condensate prices helping to offset the weakness in natural gas prices over the course of the year. As the majority of Storm’s condensate and NGL revenue streams are based on crude oil reference prices, the crude oil market remains an important part of Storm’s business plan, particularly in light of the ability to focus drilling on areas where higher liquids recoveries are expected.

Adjustments to the near-term growth plan in the second half of 2019 resulted in capital expenditure guidance being amended by the Company as set out in the table below:

2019 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 13, 2018	$2.50	$1.25	$60.00	$128.0	$72.0 - $88.0	21,000 - 24,000
Feb 28, 2019	$2.60	$1.25	$55.00	$128.0	$67.0 - $79.0	21,000 - 24,000
May 14, 2019	$2.65	$1.20	$55.00	$128.0	$65.0 - $77.0	21,000 - 24,000
Aug 13, 2019	$2.45	$1.00	$55.00	$110.0	$55.0 - $61.0	20,000 - 22,000
Nov 12, 2019	$2.45	$0.90	$56.00	$105.0 - $110.0	$58.7 - $64.5	20,000 - 22,000
Actual 2019 Results	$2.42	$0.96	$57.03	$96.8	$59.5	20,182

Despite remaining at depressed levels, natural gas prices were relatively stable for the first half of the year as was the Company’s capital expenditure and production guidance. Storm continued to execute on construction of a 50 Mmcf per day sour gas plant to develop the Nig land block, which accounted for 63% of the capital expenditures in 2019. In August 2019, capital expenditure and production guidance were reduced in response to the ongoing decline in natural gas prices and the multiple outages experienced at the McMahon Gas Plant which reduced both production and forecasted funds flow. Capital expenditures in 2019 came in further below budget due to timing of expenditures for the Nig Gas Plant, with approximately $9.0 million of expenditures moving from the fourth quarter of 2019 to the first quarter of 2020 due to minor delays relating to equipment deliveries.

Year over year, total production was within previously updated guidance of 20,000 to 22,000 Boe per day and largely flat with 2018 levels as growth was inhibited by the aforementioned third party outages coupled with low commodity prices. Storm’s production increased to approximately 26,000 Boe per day in December 2019 following the tie-in of a new four well pad at Nig and has averaged approximately 24,000 Boe per day to date in 2020 based on field estimates. As always, Storm continues to manage its production base in response to ongoing volatility in crude oil and natural gas prices, while ensuring firm transportation and processing commitments are being met.

Debt including working capital deficiency at year end amounted to $129 million, or 1.7 times annualized fourth quarter 2019 funds flow, with $122 million drawn on the Company’s $205 million credit facility.

Year-over-year funds flow per Boe decreased 39% primarily due to a 22% decrease in realized pricing. Given the reduction in prices relative to 2018, Storm’s hedging program realized a hedging loss of $8.8 million compared to a hedging loss of $22.7 million in the prior year. Recall, a large component of the hedging loss in both 2019 and 2018 was due to hedges at Sumas that were added before the Enbridge T-south pipeline failure in October 2018 which resulted in materially higher pricing in the Sumas market.

Storm’s 2019 capital program was focused on the Nig property, with construction of the Nig Gas Plant along with drilling and completing an acid gas injection well and drilling and completing a four well pad that is evaluating different intervals in the Montney with two wells in the upper, one well in the mid and one well in the lower. The Company incurred net capital expenditures of $96.8 million, 70% of which was spent on infrastructure initiatives ($67.3 million) while 29% was spent on drilling and completions ($28.1 million). Six wells (100% working interest) were drilled in the year and five (5.0 net) wells were completed. Storm had an inventory of five horizontal wells (4.5 net) that had not started producing at the end of 2019, one (0.5 net) of which was completed.

Commodity prices and funds flow will continue to drive the Company’s capital program at Umbach, Nig and Fireweed in 2020. With strong well performance to date and moderating declines through 2019, Storm continues to project modest levels of maintenance capital on a go-forward basis. The capital program for 2020 of $75 million to $85 million is expected to largely be funded through estimated funds flow of $62 million to $69 million and unused capacity on the Company’s credit facility. The Company’s capital program is flexible and can be amended throughout the year as required. Storm’s longer-term business plan to continue growing funds flow and asset value per share will not change; what may change is timing of execution.

Quarter Ended December 31, 2019

Production was within previously updated guidance of 22,000 to 24,000 Boe per day, flat compared to the fourth quarter of 2018 and 20% higher compared to the third quarter of 2019. Revenue from product sales for the quarter was 35% lower than the prior year due to lower pricing or, alternatively, down 17% after factoring in realized hedging losses. Revenue per Boe decreased 35% compared to the fourth quarter of 2018 as lower natural gas and NGL prices were only partially offset by higher condensate prices. Revenue per Boe was 29% higher than the immediately preceding quarter. Production increased from just over 20,000 Boe per day for the month of October to just under 26,000 Boe per day for the month of December. Increased production in December 2019 was supported by strong natural gas prices in Western Canada along with strong condensate prices.

Funds flow for the quarter totaled $18.5 million, approximately 40% lower than the same period in the prior year and 54% higher than the third quarter of 2019. Increased funds flow over the preceding quarter resulted primarily from higher production levels and improved pricing. The improvement in pricing was partially offset by realized hedging losses of $1.6 million in the fourth quarter primarily due to losses on Sumas and Chicago positions. Using annualized funds flow for the fourth quarter, the ratio of year-end debt including working capital deficiency to funds flow amounted to 1.7 times.

Capital expenditures for the quarter totaled $23.9 million and were lower than previously announced guidance of $32.0 million to $37.0 million primarily due to timing of expenditures related to the Nig Gas Plant ($9.0 million moved from the fourth quarter of 2019 to the first quarter of 2020). Included in the $23.9 million are facility, equipping and gathering costs of $22.1 million which was predominantly related to the Nig gas plant and the associated sales pipeline plus the tie-in of the four well pad at Nig.

During the fourth quarter of 2019, the Company’s bank syndicate confirmed Storm’s credit facility at $205 million during the mid-year review, which was approximately 64% drawn at the end of the fourth quarter (including $10 million for letters of credit). The next annual review will take place prior to May 29, 2020.

Production and Revenue

Average Daily Production

	Three Months to	Three Months to	Year-Over-Year	Year Ended	Year Ended	Year-Over-Year
	Dec. 31,2019	Dec. 31,2018	Change	Dec. 31,2019	Dec. 31,2018	Change
Natural gas (Mcf/d)	108,679	109,520	(1%)	98,458	101,019	(3%)
Condensate (Bbls/d)	2,416	2,453	(1%)	2,138	2,141	-
NGL(Bbls/d)	1,846	1,726	7%	1,634	1,561	5%
Total(Boe/d)	22,375	22,432	-	20,182	20,538	(2%)
Natural gas weighting	81%	81%		81%	82%
Condensate weighting	11%	11%		11%	10%
NGL weighting	8%	8%		8%	8%

Production for natural gas, condensate and NGL for the fourth quarter of 2019 was comparable to the fourth quarter of 2018 and 2% lower when comparing the year ended December 31, 2019 to the same period of 2018, primarily due to 2019 being negatively affected by third-party outages which offset production increases in the year. Of the 43 days of outages, 12 days related to planned outages while the remaining 31 days of outages were unplanned. These

outages reduced production by approximately 2,000 Boe per day for the year ended December 31, 2019. In addition to the unplanned outages, production was voluntarily curtailed at times in response to weak natural gas pricing at Station 2.

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Daily production per million shares outstanding for the fourth quarter of 2019 averaged 184 Boe per day compared to 185 Boe per day for the fourth quarter of 2018. Daily production per million shares outstanding in 2019 averaged 166 Boe per day, compared to 169 Boe per day in 2018.

Revenue from Product Sales[(1)]

Revenue from Product Sales(1)
	Three Months to	Three Months to	Year Ended		Year Ended
	Dec. 31,2019	Dec. 31,2018	Dec. 31,2019		Dec. 31,2018
Natural gas	$ 32,836	$ 55,973	$	115,488	$	146,852
Condensate	14,796	13,256		51,522		59,071
NGL	1,039	5,570		6,412		20,335
Total	$ 48,671	$ 74,799	$	173,422	$	226,258
% of Total Revenue by Product Type
Natural gas	67%	75%		67%		65%
Condensate and NGL	33%	25%		33%		35%
Total	100%	100%		100%		100%

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

Revenue from product sales for the fourth quarter of 2019 decreased by 35% when compared to the fourth quarter of 2018 as a result of the Company’s average realized price decreasing by 35% as production volumes stayed flat. For the year ended December 31, 2019, revenue from product sales decreased 23% year over year due to the Company’s average realized price decreasing by 22%.

The contribution of condensate and NGL to total revenue from product sales was 33% for both the three months and year ended December 31, 2019 (three months and year ended December 31, 2018 – 25% and 35%, respectively). For the three months ended December 31, 2019, condensate and NGL revenue from product sales made up a larger proportion of total revenue versus the same period in 2018 as natural gas prices were 70% higher in the fourth quarter of 2018 and contributed a higher percentage of total revenue given Storm’s 81% natural gas weighting. For the year ended December 31, 2019 there was a more normalized distribution of revenue by product type as pricing was down across all revenue streams and averaged out over a full twelve months, reducing the effect of the significant increase in natural gas prices in the fourth quarter of 2018.

A reconciliation of year-over-year revenue changes for the three month period ending December 31, 2019 is as follows:

follows:
	Natural Gas	Condensate	NGL	Total
Revenue from product sales – Q4 2018	$ 55,973	$ 13,256	$ 5,570	$ 74,799
Effect of changes in production	(430)	(199)	387	(242)
Effect of changes in averageproductprices	(22,707)	1,739	(4,918)	(25,886)
Revenue fromproduct sales – Q4 2019	$ 32,836	$ 14,796	$ 1,039	$ 48,671

A reconciliation of year-over-year revenue changes for the year ended December 31, 2019 is as follows:

	Natural Gas	Condensate	NGL	Total
Revenue from product sales – 2018	$ 146,852	$ 59,071	$ 20,335	$ 226,258
Effect of changes in production	(3,723)	(72)	953	(2,842)
Effect of changes in averageproductprices	(27,641)	(7,477)	(14,876)	(49,994)
Revenue fromproduct sales – 2019	$ 115,488	$ 51,522	$ 6,412	$ 173,422

Average Selling Prices[(1)]

Average Selling Prices(1)
	Three Months to	Three Months to	Year Ended	Year Ended
	Dec. 31,2019	Dec. 31,2018	Dec. 31,2019	Dec. 31,2018
Natural gas – Mcf	$ 3.28	$ 5.56	$ 3.21	$ 3.98
Condensate – Bbl	$ 66.56	$ 58.74	$ 66.03	$ 75.61
NGL – Bbl	$ 6.11	$ 35.09	$ 10.75	$ 35.69
Per Boe	$ 23.64	$ 36.24	$ 23.54	$ 30.18

(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 December 31, 2019 decreased by 35% compared to the same period of 2018, with the decrease driven by lower natural gas and NGL pricing, partially offset by higher condensate 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 fourth quarter of 2019 was 8% of WTI which was in line with expectations. The decrease in natural gas pricing is primarily due to a reduction in prices at Chicago and Sumas.

On a per-Boe basis, the Company’s average realized price for the year ended December 31, 2019 decreased by 22% when compared to the same period of 2018, primarily driven by decreases in NGL, natural gas and condensate pricing.

Benchmark Prices

Benchmark Prices
	Three Months to	Three Months to	Year ended	Year ended
	Dec. 31,2019	Dec. 31,2018	Dec. 31,2019	Dec. 31,2018
Natural gas
Chicago monthly index (US$/Mmbtu)	2.44	3.62	2.56	3.06
Chicago daily index (US$/Mmbtu)	2.21	3.69	2.42	3.02
Sumas (US$/Mmbtu)	4.20	11.09	3.80	4.30
AECO monthly index (Cdn$/GJ)	2.21	1.80	1.54	1.45
AECO daily index (Cdn$/GJ)	2.35	1.48	1.67	1.42
Station 2(Cdn$/GJ)	1.41	0.64	0.96	1.19
Crude Oil
WTI (US$/Bbl)	56.96	58.81	57.03	64.77
WTI (Cdn$/Bbl)	75.27	77.76	75.70	83.94
Edmonton condensate (Cdn$/Bbl)	70.05	59.66	70.17	78.90
Exchange rate(US$/Cdn$)	0.76	0.76	0.75	0.77

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 had increased volatility in pricing for both Station 2 (lower) and Sumas (higher). During the fourth quarter of 2018, the monthly Sumas index price averaged US$11.09 per Mmbtu resulting in increased revenue for Storm which was offset by increased hedging losses on Storm’s sales at Sumas. In November 2019, the Enbridge T-south line returned to full capacity. Sumas pricing in the fourth quarter of 2019 averaged US$4.20 per Mmbtu with increased demand in the Pacific Northwest.

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 through the fourth quarter and into 2020, US natural gas prices have been under further pressure in 2020.

Western Canadian natural gas pricing (AECO and Station 2) increased in the fourth quarter compared to the fourth quarter of 2018 due to increased demand combined with low storage levels.

WTI crude oil pricing, on which a large part of the Company’s condensate and NGL revenue is based, declined 3% from US$58.81 per barrel during the fourth quarter of 2018 to US$56.96 per barrel for the fourth quarter of 2019 due to global trade tensions continuing to affect international economies and lower oil demand forecasts, partially offset by geopolitical tensions in the Middle East affecting the stability of oil supplies. Condensate pricing in the fourth quarter of 2019 increased as the decrease in WTI was more than offset by the narrowing of the Edmonton condensate differential from a discount of US$13.52 per barrel in the fourth quarter of 2018 to a discount of US$3.95 per barrel for the fourth quarter of 2019. The condensate differential continued to narrow in the first quarter of 2020 relative to 2019 and condensate prices are expected to settle at close to parity with WTI in US dollar terms in the first quarter of 2020.

The Company’s production during the fourth quarter and year ended December 31, 2019 was sold as follows:

	Three Months to	Three Months to	Year ended	Year ended
	Dec. 31,2019	Dec. 31,2018	Dec. 31,2019	Dec. 31,2018
Chicago monthly index price	30%	35%	33%	38%
Chicago daily index price	25%	28%	24%	25%
AECO index price	11%	11%	11%	6%
Station 2 index price	20%	10%	19%	14%
Sumas index price	11%	11%	11%	12%
Alliance Transfer Point(“ATP”)	3%	5%	2%	5%
Total	100%	100%	100%	100%

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As a result of the Company’s diversified marketing strategy, Storm’s realized natural gas price was approximately 120% higher than Station 2 pricing in the fourth quarter of 2019 and approximately 220% higher for the year ended December 31, 2019. A significant contributor to the increase in Storm’s realized natural gas price to $3.28 per Mcf in the fourth quarter of 2019 was selling approximately 66% of the Company’s natural gas into the Chicago and Sumas markets, which had higher relative pricing than AECO and Station 2.

The effect of the higher realized natural gas price on the Company’s funds flow is partially offset by higher transportation costs.

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Storm’s realized condensate price for the fourth quarter of 2019 increased by 13% from the fourth quarter of 2018 as a result of a narrowing of the WTI-Edmonton condensate differential from the fourth quarter of 2018 to the fourth quarter of 2019, offset by a slight decrease in the WTI price. The fourth quarter of 2018 was significantly affected by pipeline constraints and refinery outages which reduced demand for diluent blending.

In 2019, Storm’s condensate price decreased 13% compared to 2018 primarily as a result of a decrease in the WTI price while the WTI-Edmonton condensate differential was relatively stable year over year.

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Storm’s realized price for NGL, excluding condensate, in the fourth quarter of 2019 decreased by 83% relative to the same period of 2018. For the year ended December 31, 2019, the realized price for NGL, excluding condensate, decreased by 70% year over year. The decrease in realized NGL prices for both of the aforementioned periods was primarily due to lower contracted butane pricing as a result of elevated supply levels, lower propane pricing and weaker WTI pricing period over period.

Storm’s NGL price net of transportation is anticipated to be approximately 5% to 10% of WTI in Canadian dollar terms for the contract period that commenced in April 2019 and ends in March 2020.

Risk Management

Risk Management
		Three Months	to Dec.	31,2019		Three Months	to Dec.	31,2018
	Realized Gain		Unrealized Gain		Realized Gain		Unrealized Gain
		(Loss)		(Loss)		(Loss)		(Loss)
Natural gas	$	(2,358)	$	2,439	$	(16,774)	$	(4,212)
Liquids(1)		714		(4,574)		(1,087)		16,497
Interest rate		-		122		-		-
Gain(loss)on risk management contracts	$	(1,644)	$	(2,013)	$	(17,861)	$	12,285

		Year	Ended Dec.	31, 2019		Year	Ended Dec.	31, 2018
	Realized Gain		Unrealized Gain		Realized Gain		Unrealized Gain
		(Loss)		(Loss)		(Loss)		(Loss)
Natural gas	$	(10,532)	$	10,742	$	(14,687)	$	(16,741)
Liquids(1)		1,698		(9,226)		(7,990)		10,908
Interest rate		1		11		-		-
Gain(loss)on risk management contracts	$	(8,833)	$	1,527	$	(22,677)	$	(5,833)

(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 in cash during the reporting period. The realized loss of $8.8 million for the year ended December 31, 2019 is primarily due to higher pricing at Chicago and Sumas which also benefitted the Company’s natural gas revenues during the first quarter of 2019.

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 to	Three Months to	Year Ended	Year Ended
	Dec. 31,2019	Dec. 31,2018	Dec. 31,2019	Dec. 31,2018
Charge for period	$ 3,267	$ 1,189	$ 8,169	$ 8,127
Percentage of revenue fromproduct sales	6.7%	1.6%	4.7%	3.6%
Per Boe	$ 1.59	$ 0.58	$ 1.11	$ 1.08

Royalties, as a percentage of revenue from product sales, increased in the fourth quarter of 2019 compared to the same period in 2018 primarily due to receipt of $0.2 million in infrastructure royalty credits in the fourth quarter of 2019 compared to $3.9 million received in the fourth quarter of 2018 and a decrease in wells benefitting from the BC Deep Well Royalty Program, partially offset by lower commodity prices. Storm receives royalty credits on qualifying wells through the BC Deep Well Royalty Credit Program which reduces the royalty rate on new horizontal wells to 6% for approximately two years. In the fourth quarter of 2019, 28 wells qualified for the 6% royalty rate compared to 37 wells in the fourth quarter of 2018.

Royalties, as a percentage of revenue from product sales, increased in 2019 compared to 2018 primarily due to receipt of infrastructure royalty credits of $3.7 million in 2019 compared to credits of $5.3 million received in 2018 and a decrease in the number of wells benefitting from the BC Deep Well Royalty Program, partially offset by a decrease in commodity prices.

Storm has remaining infrastructure royalty credits of $7.0 million that will reduce future royalties, which includes 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 to	Three Months to	Year Ended	Year Ended
	Dec. 31,2019	Dec. 31,2018	Dec. 31,2019	Dec. 31,2018
Charge forperiod	$ 11,663	$ 11,270	$ 43,274	$ 41,242
Per Boe	$ 5.67	$ 5.46	$ 5.87	$ 5.50

Total production costs for the fourth quarter of 2019 increased 3% when compared to the fourth quarter of 2018. Total production costs increased by 5% for the year ended December 31, 2019 when compared to the same period of 2018. The increase in total production costs for the fourth quarter of 2019 compared to the fourth quarter of 2018 is due to higher third-party gas processing costs as a result of an annual inflation escalator and an increase in BC carbon tax effective April 1, 2019. The increase in total production costs for the year ended December 31, 2019 compared to the same period of 2018 was primarily due to fixed costs incurred during unplanned outages at the McMahon Gas Plant and an increase in the BC carbon tax.

On a per-Boe basis, production costs increased by 4% and 7% in the three months and year ended December 31, 2019 compared to the same periods of 2018, primarily due to incurring fixed costs and lower production during unplanned outages at the McMahon Gas Plant.

Carbon Tax

With the majority of the Company’s operations located in British Columbia, the Company is subject to the British Columbia Carbon Tax Act. Storm pays carbon tax on fuel used in the Company’s own facilities as well as on natural gas volumes processed at third-party facilities. The following table outlines the total carbon taxes (direct and indirect) that are included as a component of the aforementioned production costs.

	Three Months to	Three Months to	Year Ended	Year Ended
	Dec. 31,2019	Dec. 31,2018	Dec. 31,2019	Dec. 31,2018
Charge forperiod	$ 1,521	$ 1,368	$ 5,716	$ 5,217
Per Boe	$ 0.74	$ 0.66	$ 0.78	$ 0.70

Transportation Costs

Transportation Costs
	Three Months to	Three Months to	Year Ended	Year Ended
	Dec. 31,2019	Dec. 31,2018	Dec. 31,2019	Dec. 31,2018
Charge forperiod	$ 10,708	$ 11,487	$ 41,703	$ 43,764
Per Boe	$ 5.20	$ 5.57	$ 5.66	$ 5.84

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.

Transportation costs for the fourth quarter of 2019 and on a per-Boe basis decreased by 7% when compared to the fourth quarter of 2018, primarily due to a lower proportion of natural gas sales volumes transported on the Alliance Pipeline and sold at Chicago. Transportation costs for the year ended December 31, 2019 decreased by 5% and by 3% on a per-Boe basis when compared to the same period of 2018 due to selling less natural gas to Chicago, partially offset by incurring fixed costs for unused firm transportation during outages.

Field Netbacks

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

		Three Months Ended December 31, 2019	Three Months Ended December 31, 2019
	Natural Gas(1) ($/Mcf)	Condensate(2) ($/Bbl)	NGL ($/Bbl) Total ($/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

		Three	Months Ended December	31, 2018
	Natural Gas(1)	Condensate(2)	NGL	Total
	($/Mcf)	($/Bbl)	($/Bbl)	($/Boe)
Revenue from product sales	$ 5.56	$ 58.74	$ 35.09	$ 36.24
Royalties	0.03	(4.52)	(3.24)	(0.58)
Production costs	(1.12)	-	-	(5.46)
Transportation costs	(1.02)	(5.49)	-	(5.57)
Field operating netback	$ 3.45	$ 48.73	$ 31.85	$ 24.63
Realizedgain(loss)on risk management contracts	(1.66)	(4.98)	0.23	(8.65)
Field operatingnetback includinghedging	$ 1.79	$ 43.75	$ 32.08	$ 15.98

			Year Ended December	31, 2019
	Natural Gas(1)	Condensate(2)	NGL	Total
	($/Mcf)	($/Bbl)	($/Bbl)	($/Boe)
Revenue from product sales	$ 3.21	$ 66.03	$ 10.75	$ 23.54
Royalties	(0.03)	(8.02)	(1.44)	(1.11)
Production costs	(1.20)	-	-	(5.87)
Transportation costs	(1.05)	(4.90)	(0.06)	(5.66)
Field operating netback	$ 0.93	$ 53.11	$ 9.25	$ 10.90
Realizedgain(loss)on risk management contracts	(0.29)	0.63	2.02	(1.20)
Field operatingnetback includinghedging	$ 0.64	$ 53.74	$ 11.27	$ 9.70

			Year EndedDecember	31,2018
	Natural Gas(1)	Condensate(2)	NGL	Total
	($/Mcf)	($/Bbl)	($/Bbl)	($/Boe)
Revenue from product sales	$ 3.98	$ 75.61	$ 35.69	$ 30.18
Royalties	(0.03)	(6.50)	(3.29)	(1.08)
Production costs	(1.12)	-	-	(5.50)
Transportation costs	(1.08)	(5.24)	-	(5.84)
Field operating netback	$ 1.75	$ 63.87	$ 32.40	$ 17.76
Realizedgain(loss)on risk management contracts	(0.40)	(10.27)	0.05	(3.03)
Field operatingnetback includinghedging	$ 1.35	$ 53.60	$ 32.45	$ 14.73

(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 fourth quarter of 2019 decreased by 55% (35% decrease after hedging) compared to the fourth quarter of 2018.

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The 2019 field operating netback decreased by 39% (34% decrease after hedging) compared to 2018.

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General and Administrative Costs

General and Administrative Costs
	Three Months to	Three Months to	Year Ended	Year Ended
	Dec. 31,2019	Dec. 31,2018	Dec. 31,2019	Dec. 31,2018
Charge for period – before recoveries	$ 2,039	$ 2,061	$ 8,870	$ 8,155
Overhead recoveries	(594)	(933)	(1,987)	(2,043)
Charge forperiod – net of recoveries	$ 1,445	$ 1,128	$ 6,883	$ 6,112
Per Boe	$ 0.70	$ 0.55	$ 0.93	$ 0.82

General and administrative costs before recoveries for the fourth quarter of 2019 were broadly in line with the fourth quarter of 2018. General and administrative costs before recoveries for the year ended December 31, 2019 increased by 9% compared to 2018 due to higher compensation costs and the payout of the employee annual performance bonus after year-end results were finalized.

As a result of the change in lease accounting effective January 1, 2019, general and administrative costs are lower by $0.1 million in the fourth quarter of 2019 and lower by $0.5 for the year ended December 31, 2019 related to the office lease.

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 fourth quarter of 2019 were 27% higher than the fourth quarter of 2018 due to lower overhead recoveries as a result of lower capital expenditures in the fourth quarter of 2019. Net general and administrative costs on a per-Boe basis for 2019 were 13% higher when compared to 2018. Generally, the Company’s general and administrative cost structure is predictable year to year and variability in per-Boe metrics is due to changes in production volumes.

Interest and Finance Costs

Interest and Finance Costs
	Three Months to	Three Months to	Year Ended	Year Ended
	Dec. 31,2019	Dec. 31,2018	Dec. 31,2019	Dec. 31,2018
Charge for period(1)	$ 1,510	$ 923	$ 5,158	$ 4,244
Average interest rate(2)	5.0%	4.6%	5.1%	4.8%
Per Boe	$ 0.73	$ 0.45	$ 0.70	$ 0.57

(1) Includes lease interest.

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

The interest rate on the Company’s bank facility is based on bankers’ acceptance rates plus a stamping fee which is amended each quarter in response to changes in the Company’s debt to funds flow ratio.

Interest costs for the fourth quarter of 2019 increased by 64% compared to the fourth quarter of 2018 as a result of higher average bank borrowings. Interest costs for 2019 increased by 22% compared to 2018 as a result of higher market interest rates combined with higher average bank borrowings which are used to fund capital expenditures.

Funds Flow

Funds Flow
	Three Months to		Three Months to		Year Ended		Year Ended
	Dec. 31,2019		Dec. 31,2018		Dec. 31,2019		Dec. 31,2018
		Per		Per		Per		Per
		diluted		diluted		diluted		diluted
		share		share		share		share
Funds flow	$18,469	$0.15	$30,941	$0.25	$59,549	$0.49	$100,092	$0.82

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

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(1) Excludes lease interest.

Lower realized prices was the predominant factor in the 40% decrease in funds flow in the fourth quarter of 2019 versus the fourth quarter of 2018.

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 fourth quarter of 2019 compared to 21% in the fourth quarter of 2018.

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(1) Excludes lease interest.

Funds flow for 2019 decreased by 41% from 2018. Funds flow was negatively affected by weaker realized pricing.

Share-Based Compensation

Share-Based Compensation
	Three Months to	Three Months to	Year Ended	Year Ended
	Dec. 31,2019	Dec. 31,2018	Dec. 31,2019	Dec. 31,2018
Charge forperiod	$ 656	$ 838	$ 2,464	$ 3,127
Per Boe	$ 0.32	$ 0.41	$ 0.33	$ 0.42

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 22% in the fourth quarter of 2019 compared to the fourth quarter in 2018 and by 21% in the year ended December 31, 2019 compared to the same period of 2018. The decrease in share-based compensation in both periods is primarily attributable to a lower option fair valuation associated with options granted during 2018.

Depletion and Depreciation

Depletion and Depreciation
	Three Months to	Three Months to	Year Ended	Year Ended
	Dec. 31,2019	Dec. 31,2018	Dec. 31,2019	Dec. 31,2018
Depletion	$ 9,246	$ 9,027	$ 32,742	$ 38,845
Depreciation	2,010	1,772	7,764	6,772
Charge forperiod	$ 11,256	$ 10,799	$ 40,506	$ 45,617
Per Boe	$ 5.46	$ 5.23	$ 5.50	$ 6.09

Depletion and depreciation increased by 4% in the fourth quarter of 2019 compared to the same quarter of 2018. Comparing the year ended December 31, 2019 with the same period in 2018, depletion and depreciation decreased by 11%. The year-to-date per-Boe decrease in depletion corresponds to lower finding and development costs.

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 and year ended December 31, 2019, nor does it expect to pay any cash tax in 2020 or 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 and year ended December 31, 2019, the Company recognized a deferred income tax expense of $1.5 million and $4.9 million, respectively, as a result of $4.4 million and $16.2 million of net income before taxes, respectively. As at December 31, 2019, the Corporation had a deferred income tax liability of $9.4 million.

before taxes, respectively. As at December 31, million.	2019, the Corporation had a deferred	income tax liability of $9.4
Tax Pools	As at December 31, 2019	Maximum Annual Deduction
Canadian oil and gas property expense	$ 43,000	10%
Canadian development expense	110,000	30%
Canadian exploration expense	14,000	100%
Undepreciated capital cost	137,000	20% – 100%
Operatinglosses	199,000	100%
Total	$ 503,000

Net Income

The mark-to-market valuation of risk management contracts resulted in a considerable distortion on reported net income for the three months and year ended December 31, 2019 relative to the comparable periods in 2018. The mark-to-market valuation of risk management contracts amounted to an unrealized loss of $2.0 million for the three months ended December 31, 2019 and an unrealized gain of $1.5 million for the year ended December 31, 2019. This compares to an unrealized gain of $12.3 million for the three months ended December 31, 2018 and an unrealized loss of $5.8 million for the year ended December 31, 2018.

Excluding unrealized gains and losses on risk management contracts, the decrease in net income in the three months and year ended December 31, 2019 compared to the same periods of 2018 is primarily attributable to the weakened commodity pricing environment driving decreased revenue.

The return on capital employed (“ROCE”) over the last 12 months, which is a measurement of the Company’s income profitability as a proportion of the funding utilized to generate it (shareholders’ equity plus debt including working capital deficiency), was 4% in the fourth quarter of 2019 compared to 10% in the fourth quarter of 2018, although as mentioned above is distorted by unrealized gains and losses on the Company’s risk management contracts.

	Three Months to	Three Months to	Year Ended	Year Ended
	Dec. 31,2019	Dec. 31,2018	Dec. 31,2019	Dec. 31,2018
Net income	$ 2,906	$ 26,810	$ 11,313	$ 40,063
Per basic and diluted share	$ 0.02	$ 0.22	$ 0.09	$ 0.33

Corporate Netbacks

Corporate Netbacks
	Three Months to	Three Months to	Year Ended	Year Ended
($/Boe)	Dec. 31,2019	Dec. 31,2018	Dec. 31,2019	Dec. 31,2018
Revenue from product sales	23.64	36.24	23.54	30.18
Realized gain (loss) on risk management
contracts	(0.80)	(8.65)	(1.20)	(3.03)
Royalties	(1.59)	(0.58)	(1.11)	(1.08)
Production	(5.67)	(5.46)	(5.87)	(5.50)
Transportation	(5.20)	(5.57)	(5.66)	(5.84)
General and administrative	(0.70)	(0.55)	(0.93)	(0.82)
Interest and finance costs	(0.71)	(0.45)	(0.68)	(0.57)
Funds flow	8.97	14.98	8.09	13.34
Share-based compensation	(0.32)	(0.41)	(0.33)	(0.42)
Depletion, depreciation and accretion	(5.52)	(5.29)	(5.57)	(6.16)
Lease interest	(0.02)	-	(0.02)	-
Exploration and evaluation costs expensed	(0.01)	-	(0.15)	(0.04)
Unrealized revaluation gain (loss) on
investments	0.01	(0.11)	(0.01)	(0.03)
Unrealized gain (loss) on risk management
contracts	(0.98)	5.96	0.21	(0.78)
Deferred income tax expense	(0.72)	(2.15)	(0.67)	(0.59)
Net income	1.41	12.98	1.55	5.32

INVESTMENT AND FINANCING

Financial Resources and Liquidity

As at December 31, 2019, the Company had an extendible revolving credit facility in the amount of $205 million (December 31, 2018 – $180 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, at which time the borrowing base amount will be reviewed and in the ordinary course of business the Company will have the option to extend the facility for an additional year. If the credit facility is not extended, the facility moves into a term phase whereby the outstanding loan amount is to be repaid in full one year later. In the event that the lenders reduce the borrowing base below the amount drawn, the Company would have 90 days to eliminate any borrowing base shortfall by repaying the amount drawn in excess of the re-determined borrowing base or by providing additional security or other consideration satisfactory to the lenders. Repayments of principal are not required provided that the borrowings under the credit facility do not exceed the authorized borrowing amount. Interest is paid on the utilized portion of the credit facility at bankers’ acceptance rates, plus a stamping fee. Collateral comprises a floating charge demand debenture on the assets of the Company.

At December 31, 2019, debt including working capital deficiency amounted to $128.9 million, representing approximately 63% of the available credit facility.

As at December 31, 2019, the Company had issued letters of credit in the amount of $10.0 million (December 31, 2018 - $7.6 million) in support of future natural gas transportation and processing obligations. Availability under the Company’s credit facility is reduced by a like amount.

In quarters of high field activity, Storm operates with a working capital deficit, which will be reduced in quarters of lower field activity. The Company's capital expenditure budget is set by management at the beginning of the calendar year and approved by the Board of Directors. It is updated regularly with changes subject to approval by the Board of Directors. Management is accountable to the Board of Directors for the execution of the business plan represented by the budget and updates the Board on progress at least four times a year.

Capital Expenditures

In the fourth quarter of 2019, the Company incurred capital expenditures of $23.9 million compared to $37.1 million in the fourth quarter of 2018.

During 2019, the Company incurred capital expenditures of $96.8 million (2018 - $84.8 million) primarily related to costs incurred in constructing the Nig Gas Plant, as well as drilling and completion activities on a four well pad at Nig.

	Three Months to	Three Months to	Year Ended	Year Ended
	Dec. 31,2019	Dec. 31,2018	Dec. 31,2019	Dec. 31,2018
Land and seismic	$ 370	$ 1,043	$ 2,155	$ 3,846
Drilling	208	14,613	14,639	14,902
Completions	991	10,664	13,474	30,517
Facilities	16,543	8,859	56,830	19,552
Equipping and pipelines	5,585	1,766	10,499	14,365
Recompletions and workovers	194	131	249	903
Propertyacquisition and administrative assets	22	24	80	678
Total field capital expenditures	$ 23,913	$ 37,100	$ 97,926	$ 84,763
Proceeds on disposition of undeveloped land	-	-	(1,083)	-
Total capital expenditures	$ 23,913	$ 37,100	$ 96,843	$ 84,763

Net capital investment was allocated as follows:

	Three Months to	Three Months to	Year Ended	Year Ended
	Dec. 31,2019	Dec. 31,2018	Dec. 31,2019	Dec. 31,2018
Exploration and evaluation	$ 370	$ 1,043	$ 1,086	$ 4,034
Propertyand equipment	23,543	36,057	95,757	80,729
Total capital expenditures	$ 23,913	$ 37,100	$ 96,843	$ 84,763

Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities include operating, general and administrative and capital costs payable. When appropriate, net payables in respect of cash calls issued to partners regarding capital projects and estimates of amounts owing but not yet invoiced to the Company are included in accounts payable. The level of accounts payable and accrued liabilities at December 31, 2019 corresponds to the active field program at Umbach.

Decommissioning Liability

The Company’s decommissioning liability of $28.1 million represents the present value of estimated future costs to be incurred to abandon and reclaim wells and facilities, drilled, constructed or purchased by Storm. The undiscounted and inflated amount of the liability at December 31, 2019 was $38.3 million (December 31, 2018 - $43.2 million).

Share Capital

Details of share issuances from inception to December 31, 2019 are as follows:

		Number of	Price	Gross Proceeds(1)
		Shares(000s)	per Share	($000s)
June 8, 2010	Issued upon incorporation		$ 1.00	$ -
August 17, 2010	Issued under the Arrangement	17,515	$ 3.28	57,600
August 17, 2010	Issued under private placement	2,300	$ 3.28	7,544
September 22, 2010	Issued upon exercise of warrants	6,562	$ 3.28	21,522
		26,377		86,666
January 12, 2012	Issued on acquisition of SGR	11,761	$ 3.73	43,869
March 23, 2012	Issued under private placement	6,946	$ 3.40	23,615
March 23, 2012	Issued on acquisition of Bellamont	16,740	$ 2.37	39,674
		35,447		107,158
May 1, 2013	Issued under private placement	12,580	$ 1.88	23,650
May 1, 2013	Issued under insider private placement	3,000	$ 1.88	5,640
June 30, 2013	Shares cancelled	(21)	$ 2.37	(50)
November 19, 2013	Issued under private placement	9,000	$ 3.35	30,150
November 19, 2013	Issued under insiderprivateplacement	1,100	$ 3.35	3,685
		25,659		63,075
January 31, 2014	Issued pursuant to Umbach acquisition	13,629	$ 4.25	57,925
February 14, 2014	Issued under private placement	7,250	$ 4.10	29,725
February 14, 2014	Issued under insider private placement	1,250	$ 4.10	5,125
Year ended December 31, 2014	Stock option exercises	1,710	$ 3.26	5,580
		23,839		98,355
June 10, 2015	Issued under private placement	8,000	$ 4.55	36,400
Year ended December 31, 2015	Stock option exercises	145	$ 1.81	262
		8,145		36,662
Year ended December 31, 2016	Stock option exercises	1,297	$ 1.97	2,558
Year ended December 31, 2017	Stock option exercises	793	$ 1.83	1,456
Total at December 31, 2018 and	2019	121,557	$ 3.26	$ 395,930

(1) Before share issue costs and transfers from contributed surplus.

There were no stock options exercised in 2018 or 2019.

Issued and outstanding common shares at December 31, 2019 and at February 27, 2020, the date of this MD&A, totaled 121,556,812.

CONTRACTUAL OBLIGATIONS

In the course of its business, Storm enters into various contractual obligations, including the following:

purchase of services;
royalty agreements;
operating agreements;
processing and transportation agreements;
right of way agreements;
lease obligations for office space and field equipment;
rental obligations for accommodation, office equipment and automotive equipment;
banking agreements; and
risk management contracts.

All such contractual obligations reflect market conditions at the time of contract and do not involve related parties. In the first quarter of 2018, the Company entered into an office lease agreement commencing on October 1, 2018. The remaining aggregate commitment approximates $4.9 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 $473 million.

QUARTERLY RESULTS

Summarized information by quarter for the two years ended December 31, 2019 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.

the quarter of $18.5 million. Debt including working capital deficiency increased to $128.9 million.	the quarter of $18.5 million. Debt including working capital deficiency increased to $128.9 million.	the quarter of $18.5 million. Debt including working capital deficiency increased to $128.9 million.
2019 2018
($000s unless otherwise stated)	Q4 Q3 Q2 Q1	Q4 Q3 Q2 Q1
Revenue from product sales Funds flow Per share – basic and diluted ($) Net income (loss) Per share – basic and diluted ($) Net capital expenditures Average daily production (Boe) Debt including working capital deficiency(1)	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 52,102 30,941 22,227 23,405 23,519 0.25 0.18 0.19 0.19 26,810 7,174 (2,815) 8,894 0.22 0.06 (0.02) 0.07 37,100 21,845 2,918 22,900 22,432 20,455 19,529 19,708 91,020 84,648 85,073 105,585

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

SELECTED ANNUAL FINANCIAL INFORMATION

	Year Ended	Year Ended	Year Ended
($000s unless otherwise stated)	December 31, 2019	December 31, 2018	December 31, 2017
Revenue from product sales	173,422	226,258	152,880
Funds flow	59,549	100,092	64,080
Per share – basic and diluted ($)	0.49	0.82	0.53
Net income	11,313	40,063	39,689
Per share – basic and diluted ($)	0.09	0.33	0.33
Total assets	616,496	565,534	515,563
Debt including working capital deficiency(1)	128,901	91,020	106,124
Average daily production (Boe)	20,182	20,538	16,017
Funds flow($/Boe)	8.09	13.34	10.96

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

The trend in annual results represents execution of the Company’s strategic plan in the face of a volatile commodity price environment. The cornerstone of the strategic plan is capital investment discipline and growing asset value on a per-share basis. Storm achieved positive production and funds flow growth in 2018 relative to 2017 on the back of improved commodity prices, although funds flow generation was down in 2019 due to third party outages and a decrease in commodity prices. Over the last three years, the Company has benefitted from a diversified marketing strategy whereby a significant portion of the Company’s production receives US based pricing. Prudent capital spending enabled the Company to increase funds flow 56% in 2018 from 2017 while debt decreased by 14% over the same period. This trend reversed in 2019 due to the aforementioned third-party outages and lower commodity prices, while debt increased due to the build out of the Nig Gas Plant project, which will benefit 2020 results. Net income has also been affected by volatile commodity prices, although is also subject to a high degree of variability due to unrealized gains and losses on risk management contracts. The Company reported a $1.5 million unrealized gain on risk management contracts for the year ended December 31, 2019, an unrealized loss on risk management contracts of $5.8 million for the year ended December 31, 2018 and an unrealized gain on risk management contracts of $24.6 million for the year ended December 31, 2017.

The increase in the Company’s total assets reflects the ongoing development of the Company’s Montney play at Umbach, Nig and Fireweed. Capital expenditures in 2019 were primarily directed towards construction of the 50 Mmcf per day Nig Gas Plant and drilling and completion activities at Nig. Capital expenditures in 2018 included drilling, completions and infrastructure expenditures including twinning of a third field compression facility at Umbach at a cost of approximately $7 million, which supports growth of corporate production from Umbach alone to approximately 27,000 Boe per day. While 2017 capital expenditures were largely directed to drilling and completions, the Company commissioned the first phase of the aforementioned third field compression facility, which increased Storm’s compression capacity by one-third and resulted in a considerable increase in production in 2017.

Share Trading

Set out below is share trading activity for Storm for 2019 and 2018.

Set out below is share trading activity for Storm for 2019 and 2018.	Set out below is share trading activity for Storm for 2019 and 2018.	Set out below is share trading activity for Storm for 2019 and 2018.
2019 2018
	Q1 Q2 Q3 Q4 Year	Q1 Q2 Q3 Q4 Year
High ($) Low ($) Close ($) Volume traded (000s) Value traded ($000s) Weighted average trading price($)	2.46 2.56 1.79 1.68 2.56 1.51 1.63 1.14 1.16 1.14 2.38 1.81 1.32 1.64 1.64 8,405 4,930 10,035 17,012 40,383 16,883 9,292 13,417 24,244 63,836 2.01 1.88 1.34 1.43 1.58	2.86 3.30 3.24 3.16 3.30 1.75 1.99 2.30 1.43 1.43 2.10 3.12 2.74 1.74 1.74 5,971 8,077 3,464 5,666 23,178 12,727 22,612 9,891 11,930 57,160 2.13 2.80 2.86 2.11 2.47

Note: Data obtained from the TMX website.

CRITICAL ACCOUNTING ESTIMATES

Financial amounts included in this MD&A and in the audited consolidated financial statements for the years ended December 31, 2019 and 2018 are based on accounting policies, estimates and judgments which reflect information available to management at the time of preparation. Certain amounts in the financial statements are derived from a fully completed transaction cycle, or are validated by events subsequent to the end of the reporting date, or are based on established and effective measurement and control systems. However, certain other amounts, as described below, are based on estimations made by management using information which involves an element of measurement uncertainty. The degree of uncertainty related to each of the following items will vary; further, it may change between reporting periods. Variations between amounts estimated and actual results could have a material effect on Storm’s operating results and financial position.

Oil and Gas Reserves

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

Accounts Receivable, Accounts Payable and Accrued Liabilities

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

Risk Management Contracts

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

Exploration and Evaluation Assets

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

Property and Equipment, and Depletion and Depreciation

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

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

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

Decommissioning Liability

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

Share-Based Compensation

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

Income Taxes

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

LIMITATIONS

Forward-Looking Statements – Certain information set forth in this document, including management’s assessment of Storm’s future plans and operations, as outlined in Storm’s February 27, 2020 press release, contains 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”, “estimate”, “budget”, “outlook”, “forecast” or other similar words and include statements relating to or associated with individual or groups of wells, facilities, regions or projects as well as timing of any future event which may have an effect on the Company’s operations or financial position. Without limitation, any statements regarding the following are forwardlooking statements:

future commodity prices in each market in which production is sold including prices as outlined in 2020 guidance;
future average production volumes in the fourth quarter of 2020 and annual production for 2020, along with production volumes by commodity;
future revenues and production costs (including royalties) and revenues and production costs per commodity unit as outlined in 2020 guidance;
future reduction to corporate operating costs with the start-up of the Nig Gas Plant, along with the forecast operating cost for the Nig Gas Plant of less than $2.00 per Boe and incremental production from the Nig Gas Plant of approximately 1,500 Boe per day (70% liquids);
future value of unrealized risk management contracts including the estimated hedging gain as outlined in 2020 guidance;
future capital expenditures and their allocation to specific projects, activities or periods as outlined in the 2020 capital expenditure program including 2020 capital investment of $75 to $85 million and total cost of approximately $86 million for the Nig Gas Plant;
first quarter 2020 production of 24,000 to 25,000 Boe per day, first quarter capital investment of $30 million and capital investment of $31 million for the first half of the year;
future expansion plans at Fireweed including expansion of the compression facility to 100 Mmcf per day, and 2020 net capital expenditures of $36 million;
future growth plans through 2020 and 2021 including timing for the start-up of the Fireweed field compression facility;
future cost of the Fireweed compression facility, including access road and sales pipeline, of $38 million gross along with field condensate-gas ratios that are forecast to be significantly higher than Umbach;
future production levels of 25,000 to 30,000 Boe per day (5,300 to 6,300 barrels per day of liquids) in the fourth quarter of 2020, representing a year-over-year increase of 23% (using the mid-point) with liquids production increasing approximately 36%;
future facility access, acquisition, construction and entry in service and timing thereof;
future earnings or losses, including per-share amounts;
future funds flow, including the amounts outlined in 2020 guidance and per-share amounts;
2020 capital investment being approximately equal to funds flow;
future availability of financing;
future asset acquisitions or dispositions;
future sources of funding for capital expenditure programs and future availability of such sources;
drilling rigs, field service providers and completion and tie-in equipment being available as required, with costs of securing these services not materially exceeding expectations;
development plans for Storm’s properties;
estimates regarding the carrying amount of exploration and evaluation assets;
estimates regarding the carrying amount of property and equipment;
considerations regarding asset impairment;
future levels of debt including working capital deficiency;
availability and use of credit facilities including approximately $70 million of unused credit capacity at quarter end;
future decommissioning costs, inflation rates and discount rates used to determine the net present value of such costs;
future amounts and use of tax pools and losses along with the expectation to not pay any cash tax in 2020 or 2021;
measurement and recoverability of reserves or contingent resources including estimates of DPIIP and timing of such recoverability;
estimates of ultimate recovery from drilling longer wells, specifically management’s estimated 8 and 14 Bcf raw gas type curves for wells;

future finding and development costs;
estimates of the future life of depreciable assets;
future transportation, general and administrative and interest costs in total and by commodity unit as outlined in 2020 guidance;
effect of existing and future agreements with respect to processing, transportation and marketing of natural gas, condensate and NGL, specifically the anticipated sales allocation in 2020 to Chicago, Sumas, Station 2 and AECO markets and the forecasted NGL price net of transport being approximately 20% of WTI in Cdn$ for the next contract period starting in April 2020;
future provisions for depletion and depreciation and accretion;
future share-based compensation charges;
future interest rates and interest and financing costs;
estimates on a per-share basis and per-Boe basis;
dates or time periods by which wells will be drilled, completed and tied in, facility and pipeline construction completed and brought into service, geographical areas developed, facilities and pipelines accessed;
future effect of regulatory regimes and tax and royalty laws, including incentive programs;
effect of existing or future contractual obligations;
references to the intentions of management or the Company; and
changes to any of the foregoing.

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

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 the material uncertainties and risks described or incorporated by reference in this MD&A under “Critical Accounting Estimates”; “Business Risks”; “Financial Reporting Update”; and the material assumptions and observations described under the headings “Overview”; “Production and Revenue”; “Risk Management”; “Royalties”; “Production Costs”; “Transportation Costs”; “Field Netbacks”; “General and Administrative Costs”; “Interest and Finance Costs”; “Funds Flow”; “Share-Based Compensation”; “Depletion and Depreciation”; “Accretion”; Income Taxes”; “Net Income”; “Financial Resources and Liquidity”; “Capital Expenditures”; “Accounts Payable and Accrued Liabilities”; “Decommissioning Liability”; “Share Capital”; “Contractual Obligations”; industry conditions including commodity prices, facility and pipeline capacity constraints and access to processing facilities and to market for production; the occurrence of an extended operational outage, a major safety or environmental incident, or unexpected events such as fires (including forest fires); currency fluctuations; imprecision of reserve estimates and related costs including future royalties, production and transportation costs and future development costs; environmental risks; increased competition from other industry participants or from companies that provide alternative sources of energy; the lack of availability of qualified personnel or management; the potential for security breaches of Storm’s information technology and infrastructure by malicious persons or entities, and the unavailability or failure of such systems to perform as anticipated as a result of such breaches; stock market volatility; ability to access sufficient capital from internal and external sources; the risk that competing business objectives may exceed Storm’s capacity to adapt and implement change; risks and uncertainties associated with obtaining regulatory, third party and stakeholder approvals outside of Storm’s control for the Company’s operations, projects, initiatives and exploration and development activities and the satisfaction of any conditions to approvals; and the ability of the Company to realize value from its properties. All of these caveats should be considered in the context of current economic conditions, in particular low, in a historical context, prices for all commodities produced by the Company, increased supply resulting from evolving exploitation methods, the attitude of lenders and investors towards corporations in the energy industry, potential changes to royalty and taxation regimes and to environmental (including climate change) and other government regulations, the condition of financial markets generally, as well as the stability of joint venture and other business partners, all of which are outside the control of the Company. Also to be considered are increased levels of political uncertainty and possible changes to existing domestic and international trading agreements and relationships, the cost of compliance with current and future environmental laws, including climate change laws, and risks relating to increased activism and public opposition to fossil fuels. Legal challenges to asset ownership, limitations to rights of access and adequacy of pipelines or alternative methods of getting production to market may also have a significant effect on the Company’s business. 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’s actual results, performance or achievement, could differ materially from those expressed in, or implied by, these forwardlooking 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 therein 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.

to set corporate interest rates.
	As At	As At	As At
($000s unless otherwise stated)	December 31, 2019	December 31, 2018	December 31, 2017
Accounts receivable	21,961	29,262	15,104
Prepaids and deposits	764	853	4,542
Less: Accountspayable and accrued liabilities	(30,018)	(34,359)	(24,777)
Working capital deficiency	7,293	4,244	5,131
Bank indebtedness	121,608	86,776	100,993
Debt includingworkingcapital deficiency	128,901	91,020	106,124

CROCE & ROCE

CROCE is non-GAAP financial measure and does not have a standardized meaning under IFRS. CROCE is determined by taking funds flow plus interest and finance costs on a 12-month trailing basis, and dividing it by the average capital employed (shareholders’ equity plus debt including working capital deficiency) as presented in the following table.

following table.
	Year Ended	Year Ended
($000s unless otherwise stated)	December 31, 2019	December 31, 2018
Average debt including working capital deficiency(1)	109,960	98,572
Average shareholders’ equity(1)	414,820	386,336
Average capital employed	524,780	484,908
Funds flow	59,549	100,092
Interest and finance costs	5,158	4,244
Funds flow plus interest and finance costs	64,707	104,336
CROCE	12%	21%

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

ROCE is non-GAAP financial measure and does not have a standardized meaning under IFRS. ROCE is determined by taking net income plus interest and finance costs and deferred income tax expense on a 12-month trailing basis, and dividing it by the average capital employed (shareholders’ equity plus debt including working capital deficiency) as presented in the table below.

as presented in the table below.
	Year Ended	Year Ended
($000s unless otherwise stated)	December 31, 2019	December 31, 2018
Average debt including working capital deficiency(1)	109,960	98,572
Average shareholders’ equity (1)	414,820	386,336
Average capital employed	524,780	484,908
Net income	11,313	40,063
Interest and finance costs	5,158	4,244
Deferred income tax expense	4,927	4,433
	21,398	48,740
ROCE	4%	10%

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

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

BUSINESS RISKS

There are a number of risks facing participants in the Canadian crude oil and natural gas industry. Some risks are common to all businesses while others are specific to the industry. The following reviews a number of the identifiable business risks faced by the Company. Business risks evolve constantly and additional risks emerge periodically. The risks below are those identified by management at the date of completion of this report, and may not describe all of the material business risks, identifiable or otherwise, faced by the Company.

Property Exploitation

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

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

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

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

Commodity Price Fluctuations

When the Company identifies hydrocarbons of sufficient quantity and quality and successfully brings them on stream, it faces a pricing environment which is volatile and subject to a myriad of factors, largely out of the Company’s control. Low prices for the Company’s expected primary products will have a material effect on the Company’s funds flow and profitability and thus re-investment capacity, and hence ultimate growth potential. Low prices also limit access to capital, both equity and debt. The Company in part mitigates the risk of pricing volatility through the use of risk management contracts, such as fixed priced sales, swaps, collars and similar contracts. However, access to such commodity price protection instruments may not be available in future periods, or available only at a cost considered to be uneconomic. Such risk management contracts tend to be for short periods and the pricing

protection this provides has limited effect against medium and long term pricing trends. The Company may shut in production rather than sell it at prices considered by management to be unacceptably low. The Company’s production base is almost entirely natural gas and associated liquids, a trend unlikely to change in future years, resulting in commodity concentration risk.

Adverse Well or Reservoir Performance

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

Field Operations

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

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

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

Retention of Key Personnel

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

Environmental

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

The Company’s development program in northeastern British Columbia involves horizontal drilling and fracturing applications. Fracturing involves the use of large quantities of liquids and chemicals, whose use and subsequent disposal has resulted in the emergence of environmental concerns, primarily in more heavily populated areas elsewhere in North America. In particular, much of the natural gas produced by the Company contains hydrogen

sulfide, which is potentially lethal and has to be removed from the natural gas stream. This requires access to specialized processing facilities. Although the Company considers that access to such facilities is adequate for current and near-term production levels, this may not be the case in the future. In addition, future exploitation of shale gas in the HRB may cause management of carbon dioxide volumes produced concurrently with natural gas to become an operational issue.

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

Since the majority of the Company’s operations are located British Columbia, the Company is subject to the British Columbia Carbon Tax Act, which initially set a carbon price of $30 per tonne. Beginning on April 1, 2018, the provincial carbon tax was increased by $5 per tonne, increased again by $5 per tonne on April 1, 2019, and additional $5 per tonne increases are expected per year reaching the federal target carbon price of $50 per tonne on April 1, 2021. This will, of course, have a corresponding effect on costs and economic returns.

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

Industry Capacity Constraints

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

Capital Programs

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

Reserve Estimates

Estimates of economically recoverable oil and natural gas reserves and natural gas liquids, and related future net cash flows, are based upon a number of variable factors and assumptions. These include commodity prices, production, future operating, transportation, development and facility as well as decommissioning costs, access to

market, and potential changes to the Company’s operations or to reserve measurement protocols arising from regulatory or fiscal changes. All of these estimates may vary from actual circumstances, with the result that estimates of recoverable oil and natural gas reserves attributable to any property are subject to revision. In future, the Company’s actual production, revenues, royalties, transportation, operating expenditures, finding, development, facility and decommissioning costs associated with its reserves may vary from such estimates, and such variances may be material.

Production

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

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

Storm’s contracted gas processing capacity at third-party facilities was approximately 60% of total raw gas production during December 2019 with the remaining portion relying on access to interruptible capacity. There is a risk that the uncontracted, interruptible portion could be reduced or shut in if capacity available to Storm is allocated to other parties. Transportation of gas to processing facilities and to market is similarly exposed to the extent that the required capacity is not covered by contract. In addition, contracts for processing or pipeline access are for a fixed term and may not be renewed or may be renewed under more onerous terms.

Financial and Liquidity Risks

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

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

Marketing Risks

Markets for future production of crude oil and natural gas are outside the Company’s capacity to control or influence and can be affected by events such as weather, climate change, regulation, regional, national and international supply and demand imbalances, facility and pipeline access, geopolitical events, currency fluctuation, introduction of

new or termination of existing supply arrangements, as well as downtime due to maintenance or damage, either to owned or third-party facilities and pipelines. The Company will attempt to mitigate these risks as follows:

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

Storm has contracted pipeline transportation capacity for approximately 111 Mmcf per day of natural gas sales volumes in the first quarter of 2020 with the remaining portion relying on access to interruptible capacity. There is a risk that the uncontracted, interruptible portion could be reduced or shut in during partial outages or if capacity is allocated to other parties.

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

Access to Debt and Equity

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

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

Changes in Government Regulations, Royalties and Policies

In both Canada and the United States the energy industry is subject to scrutiny, frequently hostile, by political and environmental groups. This may lead to increased regulation and increased compliance costs. In particular, there is a risk that existing royalty incentive programs could be terminated or amended, royalty or income tax rates could be increased, rules and regulations around well licensing or surface access could be changed, horizontal drilling and hydraulic fracturing could be subject to increased oversight or regulation, First Nations consultation requirements may be changed and GHG emissions targets may be changed which could affect carbon taxes. In 2018, the governments of Canada, the United States and Mexico entered into the Canada-United States-Mexico Agreement (“CUSMA”). CUSMA will become effective in 90 days upon ratification by the legislature of each country. To date the United States and Mexico have ratified CUSMA while Canada has recently begun the process of ratifying the new trade agreement. The United States remains a primary market for the Company’s products and the pending adoption of CUSMA has created uncertainty with regard to market access, commodity prices, exchange rates and other factors, each of which may have an effect on the Company’s ability to profitably grow its production.

Cyber-Security

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

effect on the protection of intellectual property and confidential and proprietary information, and on the Company’s business, financial condition, results of operations and fund flow.

Extraordinary Circumstances

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

FINANCIAL REPORTING UPDATE

Changes in Accounting Policies

IFRS 16 Leases

In January 2016, the IASB issued IFRS 16 Leases which is effective January 1, 2019 and replaces IAS 17 Leases . Under IFRS 16, a single recognition and measurement model will apply for lessees, which requires lessees to recognize assets and liabilities for essentially all leases previously classified as operating leases. Short-term leases and leases for low-value assets are exempt from recognition and will continue to be treated as operating leases.

Effective January 1, 2019, the Company adopted IFRS 16 Leases using the modified retrospective approach, whereby the cumulative effect of initially applying the standard resulted in the initial recognition of a $3.1 million “Right-of-use asset” with a corresponding increase to “Lease liability” primarily relating to the Company’s corporate office lease in Calgary. The modified retrospective approach does not require restatement of prior period comparative financial information and is applied prospectively.

The lease liability was measured at the present value of the remaining lease payments, discounted using the Company’s weighted average incremental borrowing rate of approximately 5% on January 1, 2019. The right-of-use asset was measured at amounts equal to the lease liability.

On adoption, the Company used the following practical expedients permitted by the standard:

accounted for leases with a remaining term of less than twelve months as at January 1, 2019 as short-term leases; and
accounted for lease payments as an expense for leases for low-value assets.

The following table provides a reconciliation of the commitments as at December 31, 2018 to the Company’s lease liability as at January 1, 2019:

	Total
Transportation and processing commitments	$ 384,707
Office lease	5,773
Commitments as at December 31, 2018	390,480
Less:
Agreements that do not contain a lease	(384,707)
Non-lease components	(2,082)
Lease liability commitments as at December 31, 2018	3,691
Discountingat incremental borrowingrate of 5%	(597)
Lease liabilityas at January1, 2019	$ 3,094

Policy Applicable Before January 1, 2019

Leases in which substantially all of the risks and rewards of ownership are retained by the lessor are classified as operating leases. Operating lease payments are recognized as an expense on a straight-line basis over the lease term. Leases where the Company assumes substantially all the risks and rewards of ownership are classified as finance leases. At inception, a leased asset within P&E and a corresponding lease obligation are recognized. The leased asset is depreciated over the shorter of the estimated useful life of the asset or the lease term. All of the

Company’s leases are operating leases, which are not recognized on the consolidated statement of financial position. Rather, these payments in respect of operating leases are recognized in the consolidated statement of income.

Policy Applicable From January 1, 2019

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

Disclosure Controls and Internal Controls Over Financial Reporting

The Company has designed disclosure controls and procedures (“DCP”) to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company's Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation. During the financial year end of the Company, the appropriate officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company’s disclosure controls and procedures and have concluded that the Company’s disclosure controls and procedures are effective as of December 31, 2019.

The Company has designed internal controls over financial reporting ("ICFR") to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. During the financial year end of the Company, the appropriate officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company’s internal controls over financial reporting and concluded that the Company’s internal controls over financial reporting are effective as of December 31, 2019. The Company is required to disclose herein any change in the Company's ICFR that occurred during the recent fiscal period that has materially affected, or is reasonably likely to materially affect, the Company’s ICFR.

No material changes in the Company's DCP and its ICFR were identified during the quarter ended December 31, 2019 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	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1
per-share amounts		2019	2019	2019	2019	2018	2018	2018	2018
FINANCIAL
Revenue fromproduct sales(1)		48,671	31,417	37,568	55,766	74,799	51,253	48,104	52,102
Funds flow		18,469	11,973	12,590	16,517	30,941	22,227	23,405	23,519
Per share - basic and diluted ($)		0.15	0.10	0.10	0.14	0.25	0.18	0.19	0.19
Net income (loss)		2,906	(64)	7,864	607	26,810	7,174	(2,815)	8,894
Per share - basic and diluted ($)		0.02	(0.00)	0.06	0.00	0.22	0.06	(0.02)	0.07
Cash return on capital employed (“CROCE”)(2)		12%	15%	18%	20%	21%	21%	19%	16%
Return on capital employed (“ROCE”)(2)		4%	9%	11%	8%	10%	6%	4%	7%
Capital expenditures		23,913	32,841	23,145	16,944	37,100	21,845	2,918	22,900
Debt including working capital deficiency(2)(3)		128,901	123,342	102,268	91,585	91,020	84,648	85,073	105,585
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	121,853	121,649	121,557	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)		23.64	18.36	20.72	31.26	36.24	27.24	27.07	29.37
Transportation costs		(5.20)	(5.83)	(5.96)	(5.72)	(5.57)	(5.98)	(6.25)	(5.59)
Revenue net	of transportation	18.44	12.53	14.76	25.54	30.67	21.26	20.82	23.78
Royalties		(1.59)	0.19	(0.32)	(2.61)	(0.58)	(1.03)	(1.11)	(1.71)
Production costs		(5.67)	(5.88)	(5.89)	(6.09)	(5.46)	(5.54)	(5.46)	(5.55)
Field operating netback(2)		11.18	6.84	8.55	16.84	24.63	14.69	14.25	16.52
Realized gain (loss) on risk management
contracts		(0.80)	1.64	(0.22)	(5.38)	(8.65)	(1.73)	0.31	(1.19)
General and	administrative	(0.70)	(0.79)	(0.68)	(1.60)	(0.55)	(0.66)	(0.69)	(1.42)
Interest and finance costs		(0.71)	(0.69)	(0.71)	(0.61)	(0.45)	(0.49)	(0.71)	(0.64)
Funds flow per Boe		8.97	7.00	6.94	9.25	14.98	11.81	13.16	13.27
Barrels of oil	equivalentper day (6:1)	22,375	18,596	19,923	19,823	22,432	20,455	19,529	19,708
Natural gas production
Thousand cubic feet per day		108,679	91,053	97,510	96,537	109,520	101,905	96,426	96,068
Price (Cdn$ per Mcf)(1)		3.28	2.42	2.64	4.49	5.56	3.21	3.15	3.83
Condensate	production
Barrels per day		2,416	1,856	2,081	2,199	2,453	2,059	1,984	2,062
Price (Cdn$ per barrel)(1)		66.56	63.45	71.12	62.77	58.74	84.97	86.33	76.12
NGL production
Barrels per day		1,846	1,564	1,591	1,534	1,726	1,412	1,473	1,635
Price (Cdn$ per barrel)(1)		6.11	2.29	4.87	31.43	35.09	38.64	36.43	33.05
Wells drilled	(net)	-	1.0	-	5.0	4.0	-	-	-
Wells completed (net)		-	5.0	-	-	2.5	5.0	-	3.0

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

(2) Certain financial amounts shown above are non-GAAP measurements. See discussion of Non-GAAP Measurements on page 40 of the attached Management’s Discussion and Analysis. CROCE and ROCE are presented on a 12-month trailing basis.

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

CORPORATE INFORMATION

Officers

Brian Lavergne President & Chief Executive Officer

Robert S. Tiberio Chief Operating Officer

Michael J. Hearn Chief Financial Officer

Jamie P. Conboy Vice President, Geology

H. Darren Evans Vice President, Exploitation

Bret A. Kimpton Vice President, Production

Emily Wignes Vice President, Finance

Directors

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

John A. Brussa

Mark A. Butler[(1)(3)] Stuart G. Clark[(1)] Chairman

Sheila A. Leggett[(2)]

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

James K. Wilson[(1) ]

Brian Lavergne President & Chief Executive Officer

(1) Member, Audit Committee (2) Member, Reserves 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 Cash generating unit DPIIP 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 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. — Management Reports 2020

46632_rns_2020-02-28_92c4af6b-5614-4377-9cae-5714c0d931d5.pdf

INTRODUCTION

BASIS OF PRESENTATION

OPERATIONAL AND FINANCIAL RESULTS

Overview

Year Ended December 31, 2019

Quarter Ended December 31, 2019

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 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

Share Capital

CONTRACTUAL OBLIGATIONS

QUARTERLY RESULTS

SELECTED ANNUAL FINANCIAL INFORMATION

Share Trading

CRITICAL ACCOUNTING ESTIMATES

Oil and Gas Reserves

Accounts Receivable, Accounts Payable and Accrued Liabilities

Risk Management Contracts

Exploration and Evaluation Assets

Property and Equipment, and Depletion and Depreciation

Decommissioning Liability

Share-Based Compensation

Income Taxes

LIMITATIONS

Field Operating Netbacks

Debt Including Working Capital Deficiency

CROCE & ROCE

BUSINESS RISKS

Property Exploitation

Commodity Price Fluctuations

Adverse Well or Reservoir Performance

Field Operations

Retention of Key Personnel

Environmental

Industry Capacity Constraints

Capital Programs

Reserve Estimates

Production

Financial and Liquidity Risks

Marketing Risks

Access to Debt and Equity

Changes in Government Regulations, Royalties and Policies

Cyber-Security

Extraordinary Circumstances

FINANCIAL REPORTING UPDATE

Changes in Accounting Policies

IFRS 16 Leases

Policy Applicable Before January 1, 2019

Disclosure Controls and Internal Controls Over Financial Reporting

ADDITIONAL INFORMATION

QUARTERY SUMMARIES

CORPORATE INFORMATION

Officers

Directors

Stock Exchange Listing

Solicitors

Storm Resources Ltd. Management Reports 2020