Calgary, Alberta--(Newsfile Corp. - March 2, 2021) - Storm Resources Ltd. (TSX: SRX) ("Storm" or the "Company") has also filed its audited consolidated financial statements as at December 31, 2020 and for the three months and year then ended along with Management's Discussion and Analysis ("MD&A") for the same periods. This information appears on SEDAR at www.sedar.com and on Storm's website at www.stormresourcesltd.com.

Selected financial and operating information for the three months and year ended December 31, 2020, as well as reserves information at December 31, 2020, appears below and should be read in conjunction with the related financial statements and MD&A.

(1) Excludes gains and losses on risk management contracts.
(2) Certain financial amounts shown above are non-GAAP measurements. See discussion of Non-GAAP Measurements on page 38 of the MD&A. CROCE and ROCE are presented on a 12-month trailing basis.
(3) Excludes the fair value of risk management contracts, decommissioning liability and lease liability.
(4) Includes a non-cash unrealized loss on risk management contracts of $6.5 million for the year ended December 31, 2020 (December 31, 2019 - unrealized gain of $1.5 million).

PRESIDENT’S MESSAGE

2020 FOURTH QUARTER HIGHLIGHTS

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

• Production was 25,985 Boe per day, a 37% increase from the previous quarter and a 16% increase year over year. This was consistent with guidance of 25,000 to 27,000 Boe per day.

• Liquids production (condensate plus NGL) totaled 5,164 barrels per day which was 20% of total production and 30% of total revenue. NGL production increased 44% from last year largely as a result of higher recoveries realized at the Nig Creek Gas Plant.

• At Nig Creek, sales from the gas plant averaged 9,930 Boe per day (27% increase from the previous quarter) with a production cost of $1.30 per Boe. Four new wells (4.0 net) in the upper Montney started producing in late October with the IP120 averaging 9.4 Mmcf raw per day which is 18% higher than earlier wells.

• Revenue net of transportation was $17.34 per Boe, a 6% decline from last year mainly as a result of a lower condensate price caused by the decline in the WTI crude oil price. The lower natural gas price was offset by a reduction in the transportation cost per Boe as less natural gas was sold into US markets where pipeline tariffs are higher.

• Production, general and administrative, and interest and finance costs totaled $5.76 per Boe, a year-over-year reduction of 19%. This was mainly driven by the start-up of the Nig Creek Gas Plant in February 2020 which reduced third-party processing fees and resulted in production costs per Boe declining by 27%.

• The realized hedging loss was $2.6 million, larger than the loss of $1.6 million in the previous year as a result of the rapid recovery in commodity prices in the second half of 2020.

• Funds flow was $22.4 million, or $0.18 per share, an increase of 21% from last year and the highest quarterly funds flow since the fourth quarter of 2018. This was largely the result of higher production given that lower production costs per Boe offset the decline in revenue net of transportation per Boe.

• Net income was $17.9 million and benefitted from an unrealized (non-cash) hedging gain of $14.9 million which represents the change in the value of future hedging contracts from the previous quarter.

• Capital investment was $16.2 million (versus guidance for $15 million) with the majority, or $12.5 million, directed to drilling three horizontal wells at Umbach and finishing the completions on four wells at Nig Creek.

• Total debt including working capital deficiency was $132 million which was 1.5X annualized fourth quarter funds flow. Compared to the previous quarter, this was a reduction of $6 million.

• The current commodity price hedge position protects revenue on approximately 44% of forecast production for 2021. At year end, the financial liability for future hedging contracts was $8 million.

2020 YEAR-END HIGHLIGHTS

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

• Production averaged 23,219 Boe per day, a 15% increase from the previous year although this ended up being below initial guidance provided in November 2019 (24,000 to 26,000 Boe per day) as a result of reducing capital investment in May 2020 in response to lower commodity prices.

• The realized natural gas price at $2.64 per Mcf was higher than Western Canadian pricing (AECO daily index $2.11 per GJ and Station 2 $2.07 per GJ) as a result of diversified sales with 62% of sales into US markets.

• During 2020, seven horizontal wells started production and contributed approximately 2,850 Boe per day to average annual production and 7,160 Boe per day to fourth quarter production. Based on the fourth quarter addition, the implied corporate decline rate from Q4/19 to Q4/20 was 16%.

• Production, general and administrative, and interest and finance costs were $6.23 per Boe, a 17% decrease from the previous year which was mainly from the start-up of the Nig Creek Gas Plant which reduced production costs to $4.64 per Boe from $5.87 per Boe in 2019.

• The realized hedging gain was $8 million, a reversal from the previous year's loss of $9 million mainly as a result of gains realized from WTI crude oil price hedges.

• Funds flow was $57 million ($6.69 per Boe), a decline of 5% from the previous year with 15% production growth being more than offset by a large 22% reduction in revenue per Boe caused by lower condensate and natural gas prices.

• Net income was effectively nil ($0.00 per share) as compared to $11 million in the previous year with the decrease caused by a large decline in revenue and a reversal in the unrealized (non-cash) hedging gain or loss from a gain of $2 million in 2019 to a loss of $7 million in 2020.

• Capital investment was $59 million which included $12 million to complete the Nig Creek Gas Plant and $37 million to drill nine wells (8.0 net) and complete eight wells (7.5 net).

• Drilling plus completion costs at Umbach and Nig Creek averaged $4.5 million per well, a reduction of 18% from last year mainly as a result of both lower service costs and modifications to the wellbore design to increase pumping rates during fracture stimulation (well length was unchanged).

• Return on capital employed (ROCE) was 2% and cash return on capital employed (CROCE) was 12%. ROCE includes the effect of non-cash hedging gains or losses which can make it less meaningful as a way of measuring return on capital.

• Carbon taxes paid to the BC government which are included in production costs, totaled $5.6 million (direct and indirect), a decrease of $0.1 million from 2019.

• Fugitive emissions are estimated to total 2,187 tonnes CO₂e from all of Storm's facilities and well sites based on the first survey that was completed in mid-2020 as part of complying with the BC Greenhouse Gas Industrial Reporting and Control Act which requires an independent party to determine emissions which are then audited/certified by an another independent party. This is approximately 1% of Storm's total direct and indirect GHG emissions in 2019. Low fugitive emissions are the result of all well sites being equipped with solar panels to operate controllers while Storm's facilities rely on compressed air to operate controllers with overhead vapors captured from all storage tanks. More details are available in the Environmental Performance section on Storm's website (under the Corporate Responsibility tab).

RESERVE EVALUATION HIGHLIGHTS

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

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

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

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

• On a per-share basis, PDP reserves increased by 13%, 1P increased by 3% and 2P increased by 2%.

• Material future upside remains in the Montney given that PDP and 2P reserves are recognized on 18.5 and 46.7 net sections which is approximately 11% and 27%, respectively, of the total Montney land position.

OPERATIONS REVIEW

Umbach, Nig Creek and Fireweed Areas of Northeast British Columbia

Storm's land position is prospective for liquids-rich natural gas from the Montney formation and totals approximately 120,000 net acres (170 net sections) with 87 horizontal wells (81.9 net) drilled to the end of the fourth quarter.

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

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

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

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

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

Recent wells at Nig Creek continue to exceed expectations:

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

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

HEDGING

The objective of the commodity price hedging program is to support longer-term growth by protecting revenue on up to 50% of current production for the next 18 months and up to 25% for 19 to 36 months forward. The current hedge position is shown below (excludes price differential contracts which are shown in the financial statements). Future production growth is not hedged.

 
OUTLOOK

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

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

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

 
(1) Approximately 50% of natural gas sales are at the daily or spot price and 50% at the monthly index price.

(2) Based on the mid-point for each of revenue net of transportation, royalty rate and production costs.

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

2021 Guidance History