HIGHLIGHTS & OUTLOOK

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).

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.

2021 Guidance
Initial

November 10, 2020

Current

March 2, 2021

Cdn$/US$ exchange rate 0.76 0.79
Chicago daily natural gas – US$/Mmbtu(1) $2.65 $3.50
AECO daily natural gas – Cdn$/GJ(1) $2.50 $2.60
BC Station 2 daily natural gas – Cdn$/GJ $2.50 $2.55
WTI – US$/Bbl $40.00 $51.00
Edmonton condensate diff – US$/Bbl ($3.00) ($2.25)
Est transportation cost – $/Boe not provided $4.50 – $4.75
Est revenue net of transport (excl hedges) – $/Boe $17.00 – $18.00 $19.50 – $20.50
Est royalty rate (% revenue net transportation) 7% – 8% 8% – 9%
Est production cost – $/Boe $4.00 – $4.50 $4.00 – $4.50
Est mid-point field operating netback – $/Boe(2) $11.95 $14.05
Est realized hedging gains or (losses) – $ million ($8.0 – $10.0) ($10.0 – $12.0)
Est cash G&A – $ million $6.0 – $7.0 $6.0 – $7.0
Est interest expense – $ million $7.0 – $8.0 $6.0 – $7.0
Est capital investment (excluding A&D) – $ million $85.0 – $90.0 $85.0 – $90.0
Forecast fourth quarter Boe/d

Forecast fourth quarter liquids Bbls/d

30,000 – 32,000

6,800 – 7,300

30,000 – 32,000

6,800 – 7,300

Forecast annual Boe/d

Forecast annual liquids Bbls/d

26,000 – 28,000

5,600 – 6,000

26,000 – 28,000

5,600 – 6,000

Est annual funds flow – $ million(3) $90.0 – $99.0 $109.0 – $120.0
Horizontal wells drilled – gross

Horizontal wells completed – gross

Horizontal wells starting production – gross

11 (9.0 net)

11 (10.0 net)

13 (11.0 net)

11 – 12 (8.5 – 9.5 net)

11 – 12 (10.5 – 11.5 net)

14 – 15 (11.5 – 12.5 net)

  • Approximately 50% of natural gas sales are at the daily or spot price and 50% at the monthly index price.
  • Based on the mid-point for each of revenue net of transportation, royalty rate and production costs.
  • 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

  Chicago

Daily

(US$/Mmbtu)

BC Station 2

Daily

(Cdn$/GJ)

WTI

(US$/Bbl)

Capital Investment

($ million)

Forecast

Annual

Funds Flow

($ million)

Forecast Annual

Production

(Boe/d)

Nov 10, 2020 $2.65 $2.50 $40.00 $85.0 – $90.0 $90.0 – $99.0 26,000 – 28,000
Mar 2, 2021 $3.50 $2.55 $51.00 $85.0 – $90.0 $109.0 – $120.0 26,000 – 28,000

Total capital investment in 2021 is unchanged from previous guidance at $85 to $90 million with approximately 40% invested in the first half of the year.  This is expected to increase average annual production by 16% (using mid-point of guidance) and will result in further reductions to the cost structure.

Total

Investment

($million)

Infrastructure

($million)

Net Wells

Drilled

Net Wells

Completed

Net Wells

Starting Production

Fireweed $30 – $35 $19 2.5 1.5 2.5
Nig Creek $28 $7 3.0 – 4.0 3.0 – 4.0 3.0 – 4.0
Umbach $27 3.0 6.0 6.0
Total $85 – $90

Based on forecast production, natural gas sales into Canadian markets will increase from approximately 35% in 2020 to 54% in 2021.  The sales split in 2021 is expected to be 46% at Chicago, 36% at BC Station 2, 11% at AECO and 7% at Alliance ATP.  The natural gas marketing strategy will continue to be based on diversifying sales as much as possible to mitigate regional price differences caused by supply/demand imbalances that are difficult to predict in terms of timing and duration.  Diversification also includes an approximate 50/50 split between sales at daily spot pricing and at monthly index pricing (price is set at the start of each month).

NGL prices net of transportation for 2021 are expected to show a modest increase to 20% to 25% of WTI Cdn$ from 18% in 2020.  Although marketing deductions which reflect the transportation cost to sales hubs are expected to increase for the next contract year (April 2021 to March 2022), this is expected to be offset by higher propane and butane pricing.

Cost structure on a per-Boe basis is expected to show further improvement in 2021 as production costs decline with rising throughput at the Nig Creek Gas Plant where capacity is estimated to be approximately 70 Mmcf per day and the production cost is $1.30 per Boe.  In addition, transportation costs will continue to decline as a higher proportion of natural gas production is sold into Western Canadian markets which have lower pipeline tariffs.

Development at Fireweed is progressing with activity in the first quarter including drilling three horizontal wells, constructing 19 kilometers of large diameter gathering and sales pipelines, and ordering major equipment for the facility.  First production of approximately 2,500 Boe per day net is expected in the fourth quarter of 2021.

The focus continues to be on growing asset value and funds flow per share.  Near term (2021 to 2022), this is expected to come from:

  • Filling the Nig Creek Gas Plant where the production cost is $1.30 per Boe and liquids recovery is higher; and
  • Development at Fireweed where condensate is expected to be a higher proportion of total production.

‘Free cash flow’ in 2021 is estimated to be approximately $80 million using the mid-point for estimated annual funds flow in guidance (based on estimated capital investment required to maintain production being $33 million to drill, complete and tie-in 6.0 net wells).  This will be directed to development at Fireweed ($30 to $35 million), growth from Umbach and Nig Creek ($22 million to drill and complete three wells plus install inlet compression), with the remainder initially used to reduce debt which increases financial flexibility.  As always, capital investment will remain flexible and may be adjusted up or down depending on commodity prices.

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