HIGHLIGHTS & OUTLOOK

 

HIGHLIGHTS – 2016 FOURTH QUARTER

  • Production was 13,320 Boe per day (17% condensate and NGL), a year-over-year increase of 24% (23% on a per-share basis) and flat on a quarter-over-quarter basis. With the improvement in natural gas prices late in the quarter, two additional standing horizontal wells were turned on and production increased in December to 14,670 Boe per day. 
  • Condensate and NGL production increased 22% from the previous year to average 2,291 barrels per day. Condensate and NGL volumes are now being reported separately with condensate including field condensate plus pentane recovered at gas plants while NGL is the propane and butane recovered at gas plants.    
  • Montney horizontal well performance at Umbach continues to improve as the length and number of frac stages are increased. The first seven wells completed in 2016 with enough production history averaged 5.3 Mmcf per day gross raw gas over the first 90 calendar days, a 10% improvement from the average 2014 and 2015 wells. 
  • Controllable cash costs (production, general and administrative, interest and finance) were $8.64 per Boe. 
  • Funds flow was $12.0 million ($9.79 per Boe), an increase of 31% from a year ago and a 173% increase when realized gains and losses from hedging are excluded. The increase was driven by a 24% increase in production volumes.  
  • Net loss was $12.9 million which includes an unrealized mark to market hedging loss of $13.9 million (excluding the unrealized hedging loss, net profit was $1.0 million or $0.01 per share). 
  • Capital investment was $33.4 million including $11.8 million for construction of the third field compression facility at Umbach which was started up on January 12, 2017. In addition, five horizontal wells (5.0 net) were drilled and five horizontal wells (5.0 net) were completed. 
  • At the end of the quarter, there was an inventory of nine horizontal wells (9.0 net) that had not started producing (includes three completed wells). 
  • Debt including working capital deficiency was $89.8 million which is 1.9 times annualized fourth quarter funds flow (the bank credit facility is $130.0 million). 
  • Commodity price hedges continue to be layered in with approximately 40% of forecast 2017 production currently hedged.

 

HIGHLIGHTS – 2016 YEAR END

  • Production for the year averaged 13,219 Boe per day (17% condensate and NGL), a year-over-year increase of 34% on a per-share basis. 
  • During 2016, seven horizontal wells were turned on which offset declines and maintained production at approximately 13,000 Boe per day through November. Production in December increased to 14,670 Boe per day after two more horizontal wells were turned on. 
  • Controllable cash costs (production, general and administrative, interest and finance) averaged $8.56 per Boe for the year, a decrease of $1.57 per Boe or 15% from the previous year. Production costs declined to $6.78 per Boe, an improvement of 15%. 
  • Capital investment totaled $64.9 million with $22.4 million to drill 12.0 net horizontal wells, $18.5 million to complete 10.0 net horizontal wells and $23.1 million for infrastructure ($18.8 million or 29% of 2016 capital investment was for the third field compression facility at Umbach). 
  • The average cost to drill and complete a Montney horizontal well at Umbach in 2016 was $3.9 million, a decrease of 11% from 2015. 
  • Storm entered into a natural gas processing arrangement at Umbach with Spectra Energy (“Spectra”) which is effective January 1, 2017 and is expected to reduce corporate operating costs by approximately 15% to 20%. 
  • Proved developed producing (“PDP”) reserves increased 21% per share, additions replaced 195% of production and the all-in Finding, Development & Acquisition (“FD&A”) cost was $6.89 per Boe ($4.90 per Boe excluding $18.8 million for the third field compression facility at Umbach which started up in January 2017). 
  • Total proved (“1P”) reserves increased 4% per share, additions replaced 175% of production and the all-in FD&A cost was $4.97 per Boe. 
  • Total proved plus probable (“2P”) reserves increased 2% per share, additions replaced 172% of production and the all-in FD&A cost was $5.48 per Boe. 
  • All reserve additions in the 2016 evaluation were from Storm’s 100% working interest lands at Umbach. Wells completed in 2016 were assigned average 2P reserves of 5.8 Bcf gross raw gas with the actual drill and complete cost being $3.9 million.  The actual results were an improvement over what was recognized in last year’s evaluation where average 2P reserves of 4.7 Bcf were assigned to future drilling locations with an estimated drill and complete cost of $4.5 million. 
  • The corporate decline rate was approximately 33% in 2016 (December 2015 corporate production was 13,602 Boe per day with the same wells producing 9,210 Boe per day in December 2016). 
  • Cost of production additions in 2016 was $12,800 per Boe per day using total capital investment and fourth quarter production of 5,080 Boe per day from wells starting production in 2016 (last year was $11,000 per Boe per day). This is reduced to $9,100 per Boe per day when the $18.8 million invested in the third field compression facility is excluded (approximates the sustaining cost to maintain production).  

 

HEDGING & TRANSPORTATION

Commodity price hedges are used to support longer term growth by providing some certainty regarding future revenue and funds flow.  The objective is to hedge 50% of most recent quarterly or monthly production for the next 12 months and 25% for 13 to 24 months forward.  Anticipated production growth is not hedged.  The WTI price is also hedged given that approximately 80% of Storm’s liquids production is priced in reference to WTI (condensate, plant pentane and butane).  The hedge position is updated periodically in the presentation posted on Storm’s website.  For 2017, approximately 40% of forecast production is currently hedged. 

2017

Crude Oil

875 Bopd

WTI Cdn$64.57/Bbl floor, Cdn$69.55/Bbl ceiling

Natural Gas

34,100 GJ/d (27,200 Mcf/d)

AECO Cdn$2.66/GJ ($3.32/Mcf)

 

9,200 Mmbtu/d (7,750 Mcf/d)

Chicago Cdn$4.17/Mmbtu ($4.93/Mcf)

2018

Crude Oil

260 Bopd

WTI Cdn$63.38/Bbl floor, Cdn$70.53/Bbl ceiling

Natural Gas

750 GJ/d (600 Mcf/d)

AECO Cdn$2.80/GJ ($3.50/Mcf)

 

10,900 Mmbtu/d (9,200 Mcf/d)

Chicago Cdn$4.00/Mmbtu ($4.73/Mcf)

 

The Company also has natural gas price differential hedges in place (Chicago – AECO and AECO – BC Station 2) with details provided in Note 14 to the financial statements.

 Storm’s strategy with respect to natural gas transportation commitments is to mitigate risk by diversifying sales and selling at multiple points including Chicago, AECO and BC Station 2.  As per the summary below, transportation commitments total 72 Mmcf per day in 2017 and increase to 102 Mmcf per day in 2018 (in addition to this firm capacity, interruptible capacity on the Alliance Pipeline adds up to 14 Mmcf per day in 2017 and up to 15 Mmcf per day in 2018).  During the fourth quarter, the deduction from revenue for Alliance transportation was $6.6 million.  Further information on pipeline tariffs and price deductions is provided in the presentation on Storm’s website. 

2017

2018

Alliance Pipeline(1)

51 Mmcf/d Chicago price

  5 Mmcf/d ATP price

Alliance Pipeline(1)

55 Mmcf/d Chicago price

  5 Mmcf/d ATP price

Spectra T-north

16 Mmcf/d BC Stn 2 price

Spectra T-north

29 Mmcf/d BC Stn 2 price

 

 

 

 

Spectra T-north & TCPL

13 Mmcf/d AECO price

  • (1) Interruptible capacity on the Alliance Pipeline adds up to 25% of contracted capacity.

 

 OUTLOOK

Production in the first quarter of 2017 is forecast to be 16,000 to 17,000 Boe per day (January and February averaged 16,500 Boe per day based on field estimates).  Capital investment in the first quarter is expected to be approximately $30.0 million and will include drilling six horizontal wells, completing four horizontal wells and $8.0 million for pipelines plus a second fuel gas conditioning unit at Umbach (back-up to avoid downtime associated with equipment failures).

Guidance for 2017 is largely unchanged from what was previously provided except for updating commodity prices.

2017 Guidance

 

 

 

Initial Guidance

September 7, 2016

 

Updated

November 15, 2016

 

Updated

March 2, 2017

Chicago natural gas (US$/Mmbtu)

$3.00

$3.00

$3.00(1)

AECO natural gas (Cdn$/GJ)

$2.65

$2.65

$2.50(1)

BC Stn 2 natural gas (Cdn$/GJ)

$2.25

$2.20

$2.00(1)

Edmonton light oil (Cdn$/bbl)

$55

$55

$59(1)

Estimated average operating costs ($/Boe)

$5.50 - $5.75

$5.50 - $5.75

$5.50 - $6.00

Estimated average royalty rate

(% production revenue before hedging)

9% - 11%

 

9% - 11%

 

9% - 11%

 

Estimated operations capital ($ million)

(excluding acquisitions & dispositions)

$75.0 - $80.0

 

$75.0 - $80.0

 

$75.0 - $80.0

 

Estimated cash G&A  - $ million      

$5.3

$5.3

$5.3

                                   - $/Boe

$0.85

$0.85

$0.85

Forecast fourth quarter production (Boe/d)

 % condensate and NGL

18,000 – 20,000

17%

18,000 – 20,000

17%

18,000 – 20,000

17%

Forecast annual production (Boe/d)

% condensate and NGL

16,500 – 18,000

17%

16,500 – 18,000

17%

16,500 – 18,000

17%

Umbach horizontal wells drilled

Umbach horizontal wells completed

Umbach horizontal wells connected

   12 gross (12.0 net)  

   13 gross (13.0 net)

   15 gross (15.0 net)

12 gross (12.0 net)

14 gross (14.0 net)

15 gross (15.0 net)

12 gross (12.0 net)

14 gross (14.0 net)

15 gross (15.0 net)

         
  • (1) Assumed commodity prices are approximately equal to realized prices to date and the current forward strip.

 

2017 Guidance History

 

 

 

Chicago

(US$/mmbtu)

 

BC

 Station 2

(Cdn$/GJ)

 

 

AECO

(Cdn$/GJ)

Estimated

 Operations

 Capital

($ million)

Forecast

Fourth Quarter

Production

(Boe/d)

 

Forecast Annual

Production

(Boe/d)

September 7, 2016

$3.00

$2.25

$2.65

$75.0 - $80.0

18,000 - 20,000

16,500 - 18,000

November 15, 2016

$3.00

$2.20

$2.65

$75.0 - $80.0

18,000 - 20,000

16,500 - 18,000

March 2, 2017

$3.00

$2.00

$2.50

$75.0 - $80.0

18,000 - 20,000

16,500 - 18,000

 

Capital investment in 2017 will be directed entirely to Umbach and will include $55.0 million for drilling and completions plus $21.0 million for infrastructure (pipelines, wellsite equipping, facilities).  Approximately 55% will be invested in the first half of 2017.  A cost of $4.2 million is assumed for drilling and completing a horizontal well at Umbach, an increase of 8% from the 2016 actual cost.  There is flexibility in the capital program and investment may be adjusted up or down depending on commodity prices and funds flow which will affect forecast production.  Commodity price hedges will partially mitigate potential declines in pricing.

Storm’s infrastructure plan at Umbach will support growth to 27,000 Boe per day which is approximately double average production in the fourth quarter of 2016.  Depending on natural gas pricing and funds flow, preliminary planning would see this achieved in the second half of 2018.

An effort has been made to diversify natural gas sales which will mitigate the effect of the recent widening of price differentials with US markets.  Approximately 84% of forecast natural gas production in 2017 is covered by firm transportation agreements with 60% to be sold at Chicago, 18% at BC Station 2 and 6% at Alliance Transfer Point (“ATP”).  The remainder will be sold at BC Station 2 and/or Chicago using interruptible pipeline capacity.  For January 2017, approximately 66% of production was sold at Chicago, 27% at BC Station 2 and 7% at ATP.    

The outlook for natural gas prices remains positive as a result of a tighter supply/demand balance in the United States.  Data from the Energy Information Administration (“EIA”) shows that 2016 production declined by 1.6 Bcf per day while 2016 demand increased by 0.5 Bcf per day, a year-over-year deficit of 2.1 Bcf per day.  Based on the EIA Short Term Energy Outlook February 2017, exports are forecast to increase a further 1.3 Bcf per day in 2017 (primarily LNG and Mexico) which increases the deficit to 3.4 Bcf per day if production doesn’t decline any further.  Over the last five years, almost all of the growth in US production has come from the Marcellus/Utica region and increasing production to meet higher demand will require higher natural gas prices as many producers in the Marcellus/Utica have higher cost structures and receive lower prices after pipeline tariffs are deducted.  Longer term, the outlook is increasingly bullish with demand continuing to increase as a result of five LNG export facilities currently operating or under construction on the US Gulf Coast, plus US pipeline capacity to Mexico is expected to increase by more than 6 Bcf per day by the end of 2018 from six new pipelines. 

Western Canadian natural gas prices relative to US markets have weakened with the NYMEX – AECO price differential widening to -US$1.08 per Mmbtu in January 2017 from -US$0.56 per Mmbtu in January 2016.  This is the result of production growth exceeding demand growth which has mostly been from the Alberta oilsands as export pipelines to the US are fully contracted and eastern Canada demand has been flat to declining.  Storm’s exposure to Western Canadian pricing is primarily at BC Station 2 where prices can be volatile because it’s a smaller market in terms of trading volumes, especially if there are outages or restrictions on the TCPL system which causes more natural gas to be directed to BC Station 2 (more than 50% of NE BC production is directed onto TCPL to AECO).  Price volatility will be mitigated by using interruptible capacity to maximize sales onto the Alliance Pipeline, hedging the AECO – BC Station 2 price differential and by reducing production growth if the price is too low to generate an acceptable rate of return.    

Storm is still in the early stages of delineating the large and high quality resource in the Montney formation at Umbach.  The relatively shallow depth results in a lower cost to drill and complete horizontal wells (12 days to drill and case a well) while liquids recovery increases revenue (36% of revenue in 2016 was from condensate and NGL).  With 154 net sections, there remains room for significant future growth with producing horizontal wells on only 7% of the lands (10 net sections) and proved plus probable reserves assigned on only 21% of the lands (33 net sections).  Most of this land position is expected to be economically exploitable given results from Storm’s wells and encouraging results achieved by other operators on adjacent lands. 

With multiple years of drilling inventory in the Montney at Umbach, the focus continues to be on increasing net asset value per share by converting resource into per-share growth in production and funds flow.  At current forward strip commodity prices, annual average and fourth quarter production is forecast to increase by more than 30% in 2017 and the preliminary plan is for a further 25% to 35% increase in 2018.  Reducing costs is also important (in all price environments) and further improvement is expected in 2017 as operating costs decline from the new processing arrangement with Spectra while the cost of adding PDP reserves will decline by drilling longer horizontal wells to increase rates and reserves.