Highlights and Outlook 2018-03-23T15:04:48+00:00

HIGHLIGHTS & OUTLOOK

2017 Fourth Quarter Highlights

  • Production increased by 34% on a per-share basis from the prior year to a record high of 17,936 Boe per day which was consistent with the low end of guidance (18,000 to 19,000 Boe per day).
  • Liquids production (condensate plus NGL) increased 47% from the prior year to 3,374 barrels per day and exceeded the 32% increase in natural gas production as drilling has shifted to areas at Umbach where higher condensate-gas ratios are being realized. Liquids represented 48% of production revenue versus 34% last year.
  • At the end of the quarter, there was an inventory of 12 Montney horizontal wells (12.0 net) at Umbach that had not started producing which includes two completed wells. Five horizontal wells (5.0 net) started production in the quarter.
  • Montney horizontal well performance at Umbach continues to improve as length is increased. The three wells (3.0 net) from 2017 with the most history have an average length of 1,650 metres and averaged 4.0 Mmcf per day gross raw gas during their eleventh month which is approximately 50% better than the average well completed in 2014 to 2016.  Wells drilled in the fourth quarter averaged 2,090 metres which is expected to result in further improvements.
  • Revenue per Boe declined by 1% year over year with higher liquids production and pricing offsetting a 21% decrease in the natural gas price.
  • Natural gas sales continue to be maximized into the higher priced Chicago market with 70% of fourth quarter sales being at Chicago.
  • Controllable cash costs (production, general and administrative, interest and finance) decreased 16% year over year to $7.29 per Boe. This was mainly due to production costs declining 18% as a result of continuing production growth and a new processing arrangement.
  • Funds flow was $21.3 million ($12.92 per Boe) which was the highest quarterly funds flow achieved since inception and represents a per-share increase of 83% from a year ago. The improvement was largely the result of a 35% increase in production volumes and a 32% increase in the funds flow netback.
  • Net income was $8.6 million or $0.07 per share and a significant improvement from the net loss of $12.9 million in the prior year as net revenue increased more than expenses. Net revenue including hedging increased with production growth and with a $13.1 million reduction in the unrealized hedging loss.
  • Capital investment was $26.1 million with 82% being invested in drilling seven horizontal wells (7.0 net) and completing three horizontal wells (3.0 net). This was consistent with guidance at $26.0 million.
  • Total debt including working capital deficiency was $106.1 million which is 1.2 times annualized fourth quarter funds flow. The bank credit facility is $165.0 million.
  • Commodity price hedges continue to be added and currently protect approximately 40% of forecast production for 2018 using the low end of guidance (20,000 Boe per day).

2017 Year-End Highlights

  • Production was 16,017 Boe per day (18% condensate and NGL), a year-over-year increase of 20% on a per-share basis and consistent with guidance (16,200 Boe per day).
  • Liquids production (condensate plus NGL) was 2,930 barrels per day, an increase of 27% from last year and higher than the 20% increase in natural gas production.
  • The corporate decline rate was approximately 32% in 2017 (December 2016 corporate production was 14,666 Boe per day with the same wells producing 9,900 Boe per day in December 2017). The 13 horizontal wells that were turned on in 2017 produced 9,300 Boe per day in December 2017.
  • The 12 horizontal wells completed in 2017 had an average length of 1,750 metres which is 38% longer than wells completed in 2014 to 2016. The last seven wells that were drilled in 2017 averaged 2,090 metres (these wells will be completed in 2018).  Rates and reserves are expected to increase in proportion to the added length.
  • Controllable cash costs (production, general and administrative, interest and finance) averaged $7.78 per Boe for the year, a decrease of $0.78 per Boe, or 9%, from the previous year.
  • Funds flow was $64.1 million ($0.53 per share), a year-over-year increase of 83% on a per-share basis with the improvement coming from production growth combined with a 54% increase in the funds flow netback. The higher funds flow netback was mainly from higher commodity prices and a reduction in per-Boe controllable cash costs.
  • Net income improved to $39.7 million ($0.33 per share) from a net loss of $38.5 million in the prior year. This was primarily due to an unrealized hedging gain which was a $54.8 million improvement from last year plus increased production and higher realized commodity prices.

In the fourth quarter of 2017, actual production of 17,936 Boe per day was at the low end of guidance of 18,000 to 19,000 Boe per day.  This was the result of the low Station 2 natural gas price in the quarter ($0.53/GJ) which resulted in the start-up of new wells being deferred until December when Alliance capacity was increased by an additional five Mmcf per day.  During October and November, production was maintained at a level that fulfilled firm transportation commitments.

For the first quarter of 2018, production is forecast to be 19,500 to 20,500 Boe per day which represents year-over- year growth of 18% at the mid-point.  Production to date in the first quarter has averaged 19,700 Boe per day based on field estimates.  Capital investment is expected to be $23.0 million which includes completing three horizontal wells on the Nig land block at Umbach plus constructing a 13-kilometer gathering pipeline to the Nig land block.

In the first half of 2018, capital investment is expected to be less than funds flow using forecast commodity prices which is expected to result in debt being reduced by approximately $10.0 million to $15.0 million.

Updated guidance for 2018 is provided in the table below and is largely unchanged except for updating forecast commodity prices to reflect pricing to date and approximately the current forward strip for the remainder of the year.  A range has been provided for capital investment and for forecast production with both mainly contingent on the natural gas price at Station 2 which is where Storm’s incremental natural gas growth would be sold.  The low end of forecast production for the year represents year-over-year growth of 25% with capital investment expected to be less than estimated funds flow.  The production forecast uses a 7.5 Bcf type curve for future horizontal wells at Umbach (previously a 6.3 Bcf type curve was used which was based on the performance of shorter horizontal wells completed in 2014 to 2016).

 2018 Guidance Previous

November 14, 2017

Current

March 1, 2018

$Cdn/$US exchange rate 0.79 0.80
Chicago daily natural gas – US$/Mmbtu $2.80 $2.60
Sumas monthly natural gas – US$/Mmbtu $2.40 $1.90
AECO daily natural gas – Cdn$/GJ $1.80 – $2.10 $1.40
Station 2 daily natural gas – Cdn$/GJ $1.30 – $1.70 $1.05
WTI – US$/bbl $52.00 $56.00
Edmonton light oil – Cdn$/Bbl $62.00 $64.00
Est revenue net of transport (excl hedges) – $/Boe $18.00 – $19.25 $17.00 – $18.50
Est operating costs – $/Boe $5.75 $5.75
Est royalty rate (% revenue before hedging) 6% – 9% 6% – 8%
Est operations capital investment (excl A&D) – $ million $55.0 – $90.0 $55.0 – $90.0
Est cash G&A  – $ million $6.0 – $7.0 $6.0 – $7.0
                         – $/Boe $0.70 – $0.95 $0.70 – $0.95
Est interest expense – $ million $4.5 – $5.5 $4.5 – $5.5
Forecast fourth quarter production – Boe/d

% liquids

20,000 – 27,000

17% liquids

20,000 – 27,000

18% liquids

Forecast annual production – Boe/d

% liquids

20,000 – 23,000

17% liquids

20,000 – 23,000

18% liquids

Est annual funds flow at 20,000 Boe/d – $ million $70.0 – $78.0
Umbach horizontal wells drilled – gross

Umbach horizontal wells completed – gross

Umbach horizontal wells connected – gross

6 – 12 (6.0 – 12.0 net)

11 – 17 (11.0 – 17.0 net)

11 – 16 (11.0 – 16.0 net)

3 – 12 (3.0 – 12.0 net)

11 – 17 (11.0 – 17.0 net)

11 – 16 (11.0 – 16.0 net)

2018 Guidance History
  Chicago

Daily

US$/Mmbtu

Station 2

Daily

Cdn$/GJ

AECO

Daily

Cdn$/GJ

Estimated Operations

Capital

$ million

Forecast

Fourth Quarter

Production

Boe/d

Forecast Annual

Production

Boe/d

Nov 14, 2017 $2.80 $1.30 – $1.70 $1.80 – $2.10 $55.0 – $90.0 20,000 – 27,000 20,000 – 23,000
Mar 1, 2018 $2.60 $1.05   $1.40 $55.0 – $90.0 20,000 – 27,000 20,000 – 23,000

The continuing volatility in Western Canadian natural gas prices has been largely mitigated for Storm by increasing liquids production and through diversified natural gas sales.  In 2017, liquids represented 40% of production revenue while only 34% of natural gas sales were at Western Canadian prices.

Although Storm’s production in 2017 grew by 21% from 2016, growth in the second half of the year was less than expected primarily because of declining Western Canadian natural gas prices.  From H1/17 to H2/17, the natural gas price declined by approximately 45% at AECO and by 70% at Station 2.  This was mainly from production growing by 1 Bcf per day since the summer of 2017, storage levels that are relatively high, and export pipelines to other markets that are full (in general, too much supply and nowhere to take it).  In addition, the price differential between Station 2 and AECO in H2/17 widened to -$0.80 per GJ as a result of maintenance on the Enbridge and TransCanada pipeline systems restricting takeaway out of northeast British Columbia (“NE BC”).  Spot or daily natural gas prices have shown recent improvement with AECO averaging approximately $2.00 per GJ and Station 2 averaging approximately $1.75 per GJ to date in 2018 (increases of 34% and 157% respectively versus H2/17).  The differential between Station 2 and AECO has narrowed with the completion of the TCPL Towerbirch expansion which increased flows out of NE BC.  Spot or daily prices have been stronger than the forward strip with strong physical demand from a cold winter, rising oil sands demand, and higher electricity generation as coal plants are decommissioned.  In addition, there has been a year-over-year decrease in rigs drilling for natural gas which likely will reduce supply later in 2018.

Incremental production growth above Storm’s firm transportation capacity (102 Mmcf per day sales or 20,000 to 21,000 Boe per day) is primarily directed to Station 2 and growth will continue to be contingent on the natural gas price at Station 2.  Capital investment has been designed to be flexible where activity and production growth can be rapidly increased if supported by the natural gas price.  At Umbach, additional compression can be installed quickly plus there are currently four completed horizontal wells that can be turned on and another five standing horizontal wells awaiting completion (all longer wells).

Storm’s business plan continues to be focused on adding value by converting the multi-year drilling inventory in the Montney into funds flow growth while generating reasonable risk-adjusted rates of return.  Although the current forward strip for Western Canadian natural gas prices makes this challenging, the significant improvement in liquids prices over the last 12 months has resulted in several alternatives being identified for growing funds flow by increasing liquids production.

Liquids production will be increased by continuing to drill wells in areas where higher condensate-gas ratios can be realized (Nig and Fireweed land blocks) and can also come from adding infrastructure to increase plant NGL recoveries at Umbach.  Current liquids recovery from the liquids-rich Montney is less than optimal and either adding or redirecting raw gas to access a shallow-cut refrigeration process is being evaluated which would increase NGL recovery from the raw gas by approximately 100% to 125%.

Partially mitigating the decline in Western Canadian natural gas prices, Storm’s capital efficiencies are expected to improve based on preliminary results from recent longer horizontal wells that are more than 2,000 meters in length (approximately 60% longer than wells completed in 2014 to 2016).  Rates and reserves are expected to increase in proportion to the added length while the total well cost is increasing by 15% to 25%.

Maintaining production at current levels would also add value as debt would be reduced with maintenance capital being less than estimated funds flow at current strip pricing for 2018 and 2019.  The estimated capital required to maintain production is $55.0 million to $60.0 million in 2018 and $35.0 million to $40.0 million in 2019.  This option is less desirable as it adds value at a slower rate versus growing production and/or increasing liquids production.

Results from 2017 show that Storm’s business plan works at low natural gas prices.  In addition, the large, higher quality, liquids-rich asset in the Montney at Umbach offers alternatives for growth that are less dependent on natural gas pricing.  For 2018, production is expected to grow by a minimum of 25% year over year to average 20,000 Boe per day.  Existing infrastructure will support further growth to 27,000 Boe per day with the timing to do so dependent on natural gas prices.  For 2019, the focus will be to identify ways to grow funds flow by increasing liquids production which could come from adding infrastructure and/or drilling wells in areas with higher condensate-gas ratios.

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