HIGHLIGHTS & OUTLOOK

2020 Third Quarter Highlights

Production, pricing and funds flow for the quarter were reduced by planned turnarounds at two third-party gas plants and a pipeline outage which reduced natural gas sales into higher priced Canadian markets.  Cost structure continues to improve with lower production costs being realized following start-up of the Nig Creek Gas Plant in February 2020 while record low drilling and completion costs were realized for the four wells at Nig Creek.  To date, the COVID-19 pandemic has had no direct impact on Storm’s operations.

  • Production was 19,027 Boe per day, a decrease of 20% from the previous quarter and an increase of 2% year over year. This was consistent with guidance of 19,000 to 21,000 Boe per day.  Approximately 40% of corporate production was shut in during September for planned turnarounds at third-party gas plants.
  • Liquids production (condensate plus NGL) totaled 3,773 barrels per day and represented 20% of total production and 31% of total revenue. NGL production increased 37% from last year as a result of higher recoveries that are realized at the Nig Creek Gas Plant.
  • Capacity of the 100% working interest Nig Creek Gas Plant is now estimated to be 60 to 70 Mmcf raw per day based on throughput in September when several wells were redirected from Umbach during the third-party gas plant turnarounds. Design capacity was 50 Mmcf raw per day.
  • Nig Creek area sales averaged 7,845 Boe per day (41% of corporate production) at a production cost of $1.21 per Boe. Well productivity continues to meet or exceed expectations and results from the first well in the lower Montney (840 Boe per day sales with 33% liquids over the first 9 months) indicate that there is a second layer to develop.  Four new wells (4.0 net) were recently drilled and completed and started producing in late October.
  • Drilling and completion costs for the four most recent wells at Nig Creek averaged $4.1 million based on field estimates which is a reduction of approximately 25% from last year’s average cost.
  • Revenue net of transportation was $10.71 per Boe, a 15% decline from last year mainly due to a lower condensate price and an increase in the transportation cost per Boe due to the third-party gas plant turnarounds which resulted in approximately $1.0 million of unused firm transportation. The realized natural gas price did not reflect the recent improvement in AECO and BC Station 2 prices given that 67% of sales were into the lower priced Chicago market, an increase from previous quarters as a result of an outage in September on Spectra’s T-north Fort St. John lateral to BC Station 2 (coincided with the third-party gas plant turnarounds).
  • Production, general and administrative, and interest and finance costs totaled $6.64 per Boe, a reduction of 10% year over year. Production costs per Boe declined 18% as a result of reduced third-party processing fees following start-up of the Nig Creek Gas Plant in February.  The reduction would have been larger if not for the third-party gas plant turnarounds which reduced production resulting in approximately $1.2 million of unused firm processing.
  • Funds flow was $6.7 million, or $0.05 per share, a reduction from $12.0 million last year. With production largely unchanged, the reduction in production costs per Boe was more than offset by lower revenue net of transportation, an increase in royalties related to the timing of infrastructure royalty credits, and a reduced hedging gain.
  • Net loss was $16.9 million with the largest contributor to the loss being an unrealized (non-cash) hedging loss of $18.0 million which represents the change in the value of future hedging contracts from the previous quarter.
  • Capital investment was $14.2 million (within guidance of $10 to $15 million) with the majority, or $10.1 million, directed to drilling and starting the completions of four wells at Nig Creek.
  • Total debt including working capital deficiency was $138 million. With capital investment in 2020 being approximately equal to funds flow, debt is forecast to be approximately $130 million at year end which will represent 2.2 times forecast annual funds flow.
  • Hedges protect revenue on approximately 47% of forecast production for the fourth quarter of 2020 and 40% for 2021. The financial liability for future hedging contracts was $23.2 million, an $18.0 million increase from the previous quarter as a result of the recent improvement in the forward strip for commodity prices.

Production in the fourth quarter of 2020 is forecast to average 25,000 to 27,000 Boe per day with capital investment of approximately $15 million to finish the completion of a four-well (4.0 net) pad at Nig Creek and to drill two or three wells (2.0 or 3.0 net) at Umbach on a six-well pad.

Updated guidance for 2020 is provided below.  Capital investment is expected to be approximately equal to or less than forecast funds flow.  Forecast pricing reflects actual prices to date plus the approximate forward strip for the remainder of the year.

2020 Guidance
Current

August 13, 2020

Current

November 10, 2020

Cdn$/US$ exchange rate 0.74 0.75
Chicago daily natural gas – US$/Mmbtu $1.85 $1.90
AECO daily natural gas – Cdn$/GJ $2.00 $2.15
BC Station 2 daily natural gas – Cdn$/GJ $1.95 $2.15
WTI – US$/Bbl $38.50 $38.50
Edmonton condensate diff – US$/Bbl ($3.50) ($2.25)
Est revenue net of transport (excl hedges) – $/Boe $12.00 – $12.50 $12.75 – $13.00
Est production costs – $/Boe $4.50 – $4.75 $4.50 – $4.75
Est royalty rate (% revenue net transportation) 5% – 6% 7%
Est mid-point field operating netback – $/Boe(1) $6.70 $7.35
Est realized hedging gains or (losses) – $ million $10.0 – $11.0 $6.5 – $7.5
Est cash G&A – $ million $6.0 – $7.0 $6.0 – $6.5
Est interest expense – $ million $7.0 – $8.0 $7.0 – $7.5
Est capital investment (excluding A&D) – $ million $52.0 – $60.0

(Nig Crk GP $12.0 million)

$58.0

(Nig Crk GP $12.0 million)

Forecast fourth quarter Boe/d

Forecast fourth quarter liquids Bbls/d

25,000 – 28,000

5,100 – 5,600

25,000 – 27,000

5,100 – 5,500

Forecast annual Boe/d

Forecast annual liquids Bbls/d

22,500 – 24,000

4,300 – 4,800

23,000 – 23,500

4,600 – 4,700

Est annual funds flow – $ million(2) $53.0 – $57.0(2) $55.0 – $57.0
Horizontal wells drilled – gross

Horizontal wells completed – gross

Horizontal wells starting production – gross

6 – 9 (5.0 – 8.0 net)

8 (7.5 net)

7 (7.0 net)

8 (7.0 net)

8 (7.5 net)

7 (7.0 net)

  • 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.

2020 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 12, 2019 $2.45 $1.60 $54.00 $75.0 – $90.0 not provided 24,000 – 26,000
Feb 27, 2020 $1.90 $1.65 $50.50 $75.0 – $85.0 $62.0 – $69.0 23,500 – 26,000
May 12, 2020 $2.05 $2.15 $30.50 $52.0 – $60.0 $59.0 – $66.0 23,500 – 26,000
Aug 13, 2020 $1.85 $1.95 $38.50 $52.0 – $60.0 $53.0 – $57.0 22,500 – 24,000
Nov 10, 2020 $1.90 $2.15 $38.50 $58.0 $55.0 – $57.0 23,000 – 23,500

Initial guidance for 2021 is provided below. Capital investment is intended to be less than forecast funds flow.  Comparing to the current forward strip, Storm’s forecast pricing is approximately 5% lower for the WTI oil price and for natural gas pricing.

2021 Guidance
Initial

November 10, 2020

Cdn$/US$ exchange rate 0.76
Chicago daily natural gas – US$/Mmbtu $2.65
AECO daily natural gas – Cdn$/GJ $2.50
BC Station 2 daily natural gas – Cdn$/GJ $2.50
WTI – US$/Bbl $40.00
Edmonton condensate diff – US$/Bbl ($3.00)
Est revenue net of transport (excl hedges) – $/Boe $17.00 – $18.00
Est production costs – $/Boe $4.00 – $4.50
Est royalty rate (% revenue net transportation) 7% – 8%
Est mid-point field operating netback – $/Boe(1) $11.95
Est realized hedging gains or (losses) – $ million ($8.0 – $10.0)
Est cash G&A – $ million $6.0 – $7.0
Est interest expense – $ million $7.0 – $8.0
Est capital investment (excluding A&D) – $ million $85.0 – $90.0
Forecast fourth quarter Boe/d(2)

Forecast fourth quarter liquids Bbls/d

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

Est annual funds flow – $ million(3) $90.0 – $99.0
Horizontal well drilled – gross

Horizontal wells completed – gross

Horizontal wells starting production – gross

11 (9.0 net)

11 (10.0 net)

13 (11.0 net)

  • Based on the mid-point for each of revenue net of transportation, royalty rate and production costs.
  • Assuming first production from the Fireweed area in October 2021.
  • 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.

Capital investment for 2021 is expected to be allocated as follows:

  • up to $35 million at Fireweed to drill four horizontal wells (2.0 net), complete two wells (1.0 net), and to construct a 50 Mmcf raw per day field compression facility with associated pipelines (50% working interest);
  • $28 million at Nig Creek which includes $7 million to add a low pressure inlet with compression at the gas plant (100% working interest) and to drill, complete and pipeline connect three horizontal wells (3.0 net); and
  • $27 million at Umbach to drill, complete and pipeline connect six horizontal wells (6.0 net).

Development at Fireweed was previously paused for up to one year, however, the recent improvement in the WTI oil price and BC Station 2 natural gas price supports the restart of development.  Planned activity levels for 2021 are not expected to be finalized until the end of 2020 with preliminary plans including net capital investment of up to $35 million with first production in October 2021.

Based on forecast production, natural gas sales in 2021 are expected to be 46% at Chicago, 36% at BC Station 2, 11% at AECO and 7% at Alliance ATP.  Sales into Canadian markets will increase from approximately 35% in 2020 to 54% in 2021 as a result of the expiry of a sales commitment in October 2020 for 12 Mmcf per day at Sumas and as incremental production growth is directed to BC Station 2.  Sales into Chicago use contracted capacity on the Alliance Pipeline which currently totals 57 Mmcf per day with Storm having the option to renew any portion or all of the capacity on an annual basis.  Storm’s natural gas price for the first nine months of 2020 declined by 25% year over year largely as a result of 67% of sales being into US markets at Chicago and Sumas where prices declined by an average of 40% (as compared to the average increase of 75% for Canadian prices at AECO and BC Station 2).  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.

At Nig Creek, results from the first well targeting the lower Montney show that there is a second layer to develop with rates of return expected to be comparable to development at Umbach depending on the WTI oil price.  With production having a higher proportion of condensate (average 840 Boe per day sales including 200 barrels per day of condensate over the first 9 months), the timing for follow-up wells is largely dependent on the WTI oil price.

Financial results are expected to improve significantly in the fourth quarter of 2020 and into 2021 with higher forward strip commodity prices, increased natural gas sales into Canadian markets, and with production growth from the Nig Creek area where production costs are materially lower ($1.29 per Boe year to date) than the corporate average and where liquids recoveries are the highest (22% liquids year to date).

As always, capital investment will remain flexible and may be adjusted up or down depending on commodity prices.  In 2020, capital investment is expected to be equal to or less than funds flow with forecast annual production increasing by 15% from last year.  For 2021, the intent is to improve financial flexibility with capital investment expected to be less than funds flow while forecast annual production increases by a further 18%.

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