Highlights and Outlook 2020-02-28T16:54:29+00:00


2019 Year End Highlights

Production and funds flow were below initial guidance provided in November 2018 mainly as a result of unplanned outages, lower NGL pricing for the contract year starting April 2019, and from production curtailments due to low natural gas prices during the summer.  As forecast funds flow declined during 2019, capital investment was reduced which resulted in fewer Montney horizontal wells being drilled and completed (six drills and five completions versus initial guidance for eight drills and 11 completions).

  • Production averaged 20,182 Boe per day, a 2% decrease from the previous year, and was below initial guidance provided in November 2018 (21,000 to 24,000 Boe per day) mainly as a result of 31 days of unplanned outages at the McMahon Gas Plant and production curtailments during April to October due to low natural gas prices (Station 2 averaged $0.57 per GJ during this period).
  • The realized natural gas price at $3.21 per Mcf was materially higher than Western Canadian pricing (AECO daily index $1.67 per GJ and Station 2 $0.96 per GJ) as a result of diversified sales.
  • During 2019, seven horizontal wells started production and contributed approximately 2,600 Boe per day to average annual production and 4,700 Boe per day to fourth quarter production.
  • Production, general and administrative, and interest and finance costs were $7.48 per Boe, an increase of $0.59 per Boe, largely as a result of the year-over-year decline in production caused by unplanned outages. Also contributing to the increase is higher interest expense associated with higher debt levels to fund construction of the Nig Gas Plant and higher production cost with the inflation escalator increasing third-party gas processing fees.
  • Funds flow of $60 million ($8.09 per Boe) declined 40% from the previous year mainly from lower commodity prices reducing revenue per Boe by 22%.
  • Net income of $11 million ($1.55 per Boe) declined 72% from the previous year primarily as a result of the decline in funds flow.
  • Return on capital employed (ROCE) was 4% and cash return on capital employed (CROCE) was 12%. Non-cash hedging gains or losses will affect ROCE which is based on net income but does not affect CROCE which is based on funds flow.
  • Capital investment was $97 million with approximately $61 million, or 63%, directed to the Nig Gas Plant project (gas plant, sales pipeline and acid gas injection well) which is expected to increase liquids production and reduce production cost after start-up in the first quarter of 2020.

2019 Fourth Quarter Highlights

The start-up of a four well pad at Nig in late November increased production while funds flow benefitted from the increase in production and from an improvement in natural gas prices at AECO and Station 2.  Construction continued on the Nig Gas Plant which was completed and started up February 22, 2020 (previously expected to be in January 2020).

  • Production at 22,375 Boe per day was an increase of 20% from the previous quarter and was largely unchanged from the previous year. Production was reduced by approximately 500 Boe per day due to curtailments in October as a result of the low Station 2 price ($0.36 per GJ).
  • Liquids production (field condensate plus gas plant NGL) increased 2% from last year to total 4,262 barrels per day, represented 19% of total production and contributed 33% of production revenue.
  • A four well pad at Nig started production in late November with initial rates from the three wells in the upper/mid Montney being the same as earlier wells; however, longer-term rates are expected to be lower given tighter interwell spacing on the newest wells (400 metres versus 465 metres for earlier wells). The fourth well in the lower Montney has a higher condensate rate while the gas rate is lower (IP90 5.5 Mmcf per day raw gas plus 315 barrels per day field condensate).
  • Revenue was $23.64 per Boe, a decline of $12.60 per Boe or 35% from last year, mainly from lower NGL and natural gas prices. The NGL price declined 83% as a result of lower North American propane prices and a reduction in the contracted plant gate price for propane and butane during the current marketing period from April 2019 to March 2020.  The natural gas price declined 41% as a result of lower pricing in the Chicago and Sumas markets (66% of sales).
  • Production, general and administrative, and interest and finance costs were $7.08 per Boe, a year-over-year increase of $0.62 per Boe with interest expense increasing $0.26 per Boe (higher debt level associated with funding construction of the Nig Gas Plant) and production cost increasing $0.21 per Boe (inflation escalator increasing third-party gas processing fees plus the scheduled increase in BC carbon tax in April 2019).
  • Hedging loss of $1.6 million resulted from Sumas price hedges that were entered into before a failure on the Enbridge T-south pipeline in October 2018 which decreased throughput and increased the Sumas price (repairs completed late November 2019).
  • Funds flow was $18.5 million or $0.15 per share with the year-over-year decrease of 40% per share largely the result of revenue being reduced by lower commodity prices.
  • Net income was $2.9 million compared to $26.8 million in the prior year with the decline primarily attributable to lower commodity prices reducing revenue and funds flow.
  • Capital investment of $24 million included $19 million for the Nig Gas Plant project plus $3 million to pipeline connect a four well pad at Nig. Investment was less than guidance ($32 to $37 million) with $9 million for the construction of the Nig Gas Plant being shifted into the first quarter of 2020 as a result of delays in equipment deliveries (damage to a bridge south of Fort St. John in late November required loads to be rerouted).
  • Total debt including working capital deficiency was $129 million or 1.7 times annualized quarterly funds flow and represents 63% utilization of the $205 million bank line. The year-over-year increase in total debt is a result of the large investment in the Nig Gas Plant project in 2019 which totaled $61 million (63% of total investment).
  • Commodity price hedges currently protect approximately 29% of forecast production in the first half of 2020 and 7% in the second half of 2020.

Production in the first quarter of 2020 is forecast to average 24,000 to 25,000 Boe per day with capital investment estimated to be $30 million (approximately 40% allocated to the Nig Gas Plant project).

Updated guidance for 2020 is provided below.  Forecast production includes incremental production from the Nig gas Plant which started up in late February 2020 and the effect of a planned 25-day maintenance outage at the McMahon Gas Plant in September 2020.  First production from the Fireweed area is expected in late 2020 or early 2021 depending on the timing to construct infrastructure. Forecast pricing reflects actual prices to date plus the approximate forward strip for the remainder of the year.  Capital investment is intended to be approximately equal to funds flow.  Investment in the first half of the year is expected to be approximately $31 million and is largely committed at this point.  Capital investment for the second half of the year will be reviewed mid-year and may be adjusted depending on commodity prices and forecast funds flow.

2020 Guidance

November 12, 2019


February 27, 2020

Cdn$/US$ exchange rate 0.76 0.76
Chicago daily natural gas – US$/Mmbtu $2.45 $1.90
Sumas monthly natural gas – US$/Mmbtu not provided $1.90
AECO daily natural gas – Cdn$/GJ $1.85 $1.75
Station 2 daily natural gas – Cdn$/GJ $1.60 $1.65
WTI – US$/Bbl $54.00 $50.50
Edmonton condensate diff – US$/Bbl ($5.00) ($4.00)
Est revenue net of transport (excl hedges) – $/Boe not provided $13.50 – $13.75
Est operating costs – $/Boe not provided $4.50 – $4.75
Est royalty rate (% revenue net transportation) not provided 5% – 7%
Est mid-point field operating netback – $/Boe not provided $8.20
Est hedging gains or (losses) – $ million not provided $5.0 – $6.0
Est cash G&A  – $ million not provided $6.0 – $7.0
Est interest expense – $ million not provided $7.0 – $8.0
Est capital investment (excluding A&D) – $ million $75.0 – $90.0

(Nig GP $5.0 million)

$75.0 – $85.0

(Nig GP $14.0 million)

Forecast fourth quarter Boe/d

Forecast fourth quarter liquids Bbls/d

27,000 – 30,000

5,700 – 6,300

25,000 – 30,000

5,300 – 6,300

Forecast annual Boe/d

Forecast annual liquids Bbls/d

24,000 – 26,000

not provided

23,500 – 26,000

4,900 – 5,500

Est annual funds flow – $ million not provided $62 – $69(1)
Horizontal wells drilled – gross

Horizontal wells completed – gross

Horizontal wells starting production – gross

        8 – 12 (6.0 – 8.0 net)

6 – 14 (4.5 – 10.5 net)

not provided

6 – 10 (4.0 – 8.5 net)

8 – 10 (6.5 –  8.5 net)

5 – 10 (5.0 net – 8.5 net)

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

The majority of estimated capital investment in 2020 is being directed to growth from the Nig and Fireweed areas:

  • $36 million at Fireweed includes constructing a 50 Mmcf per day field compression facility (50% working interest), drilling four horizontal wells (2.0 net) and completing three wells (1.5 net);
  • $28 to $38 million at Nig includes $14 million to complete the gas plant (100% working interest), drilling two to four horizontal wells (2.0 to 4.0 net) and completing and pipeline connecting two to four wells (2.0 to 4.0 net); and
  • $11 million at Umbach includes completing and pipeline connecting three horizontal wells (3.0 net).

Firm pipeline transportation contracts in 2020 total approximately 115 Mmcf per day with 50% directed to Chicago, 16% to BC Station 2, 12% to AECO, 12% to Alliance ATP and 10% to Sumas.  Production exceeding firm contracts will generally be sold at Station 2 using interruptible capacity.  Approximately 60% of forecast natural gas production in 2020 will be sold into US markets and the remaining 40% in Western Canadian markets.

Natural gas prices at AECO and Station 2 have improved since last September as a result of declining supply and low storage levels.  In addition, the AECO – Station 2 price differential has improved to average -$0.09 per GJ to date in 2020 (versus -$0.70 per GJ in 2019) as a result of restoring capacity on the Enbridge T-south pipeline in late November 2019 after the completion of repairs and inspections following a failure in October 2018.  Also helping the differential is the start-up of the TC Energy North Montney extension on January 31st which will ultimately increase exports from NE BC by up to 1.5 Bcf per day (contracted capacity).  Although the pricing outlook has become more optimistic, that could reverse if supply growth restarts given the loss of market share in eastern markets (lower AECO price is required to incentivise higher exports from Western Canada to eastern markets).

Storm’s NGL price is expected to improve in 2020 based on indications for contracted plant gate pricing for butane and propane for the next contract year which starts in April.  The NGL price during the current contract period (April 2019 to March 2020) has averaged approximately 7% of WTI versus 42% of WTI in the previous contract period (April 2018 to March 2019).  This reduced 2019 funds flow by approximately $10 million.  Using the current forward strip, the price is expected to improve to approximately 20% of WTI for the next contract period (April 2020 to March 2021).  Also contributing to the lower NGL price in 2019 was weaker North American propane prices (Conway averaged US$0.47 per gallon in 2019 versus US$0.72 in 2018 and is currently approximately US$0.40).

The near-term growth plan is expected to increase liquids as a proportion of total production and decrease per-Boe operating costs.  Depending on capital investment and the number of wells drilled and completed in 2020, production is forecast to grow to 25,000 to 30,000 Boe per day by the fourth quarter of 2020.  At the mid-point, the year-over-year increase in fourth quarter total production is forecast to be 23% with liquids production increasing by 36%.  The start of production from Fireweed in late 2020 or early 2021 will further increase liquids production as a proportion of total production.  With capital investment intended to be approximately equal to funds flow, investment may be adjusted depending on commodity prices which would change the timing for growth.

Over the last three years, funds flow per share has been largely unchanged as a result of declining commodity prices, however, production has grown by 26% per share, PDP reserves have grown by 28% per share, the PDP recycle ratio has averaged 1.6 using the funds flow netback, and annual return on capital employed has been between 4% and 10%.  Capital investment decisions will continue to emphasize both per-share growth along with a return on invested capital.

The business plan continues to focus on increasing asset value per share by converting resource into per-share growth of funds flow and reserves value.  This has been challenging in the current price environment where commodity prices have been volatile and have trended lower over the last several years.  Success in this environment is expected to continue being dependent on improving capital efficiencies (better wells for the same or lower cost) and finding ways to offset the effect of declining commodity prices (reducing production costs and/or increasing liquids production to increase revenue).  With 2P reserves recognized only in the upper Montney on approximately 25% of the total land position, there remains significant longer-term upside.