HIGHLIGHTS & OUTLOOK

HIGHLIGHTS – 2017 SECOND QUARTER

  • Production averaged 13,991 Boe per day, a per-share increase of 8% from the second quarter of last year. The year-over-year increase was achieved in spite of approximately 80% of production being shut in for 25 days in June for a planned maintenance turnaround at the McMahon Gas Plant (April and May averaged 18,306 Boe per day).  
  • Condensate and NGL production totaled 2,606 barrels per day which was 19% of total production and represented 36% of total revenue.  
  • At the end of the quarter, there was an inventory of nine Montney horizontal wells (9.0 net) at Umbach that had not started producing which includes one completed well. One horizontal well (1.0 net) started production in the quarter and six horizontal wells (6.0 net) started production in the first half of the year.
  • To date in 2017, four Montney horizontal wells (4.0 net) have been completed and the three with enough production history have averaged 4.8 Mmcf per day gross raw gas plus 175 barrels per day of field condensate, or 960 Boe per day sales, over the first 90 calendar days (only 75 producing days as a result of the McMahon Gas Plant turnaround).  These wells are approximately 25% longer than wells completed during 2014 to 2016 and are further south in the oil window which increases the field condensate rate (115% higher than the average from all of Storm’s wells at Umbach). 
  • Controllable cash costs (production, general and administrative, interest and finance) were $8.67 per Boe which is an increase from $7.65 per Boe in the prior quarter. The increase is primarily due to production being reduced by the scheduled maintenance turnaround at the McMahon Gas Plant which increased production costs by $0.90 per Boe.  Costs are expected to resume trending lower in the second half of 2017. 
  • Funds flow was $11.6 million ($9.13 per Boe), an increase of 100% from a year ago. The increase was driven by an 81% increase in revenue per Boe and a 9% increase in production volumes which was partially offset by a realized hedging loss of $1.4 million, or $1.10 per Boe. 
  • Net income was $9.8 million or $0.08 per share which includes an unrealized hedging gain of $9.5 million (mark to market non-cash gain). Hedging continues to have a significant recurring impact on quarterly earnings.  Excluding the unrealized and realized hedging gains or losses, net income would be $1.7 million, or $0.01 per share.
  • Capital investment was $4.3 million with most of this being invested in infrastructure at Umbach (pipelined and equipped a second water disposal well and added a second fuel gas conditioning unit). This was less than the original forecast of $13 to $18 million as the planned completions of four to six wells were delayed by spring road bans being extended into mid-July.
  • Debt including working capital deficiency was reduced to $90.6 million from $97.9 million at the end of the prior   This is 1.9 times annualized second quarter funds flow, an increase from 1.4 times at the end of the previous quarter as a result of production and funds flow being reduced by the McMahon Gas Plant turnaround.  The bank credit facility is $165 million. 
  • Commodity price hedges continue to be added and currently protect approximately 45% of forecast production for the second half of 2017.

  

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.  Note that WTI is hedged as approximately 80% of Storm’s liquids production is priced in reference to WTI.  The current hedge position is summarized below and approximately 45% of forecast production for the second half of 2017 is currently hedged. 

Q3 – Q4 2017

  

Crude Oil

1,200 Bopd

WTI Cdn$65.19/Bbl floor, Cdn$69.90/Bbl ceiling

Natural Gas

38,000 GJ/d (30,400 Mcf/d)

AECO Cdn$2.70/GJ ($3.37/Mcf)

 

12,800 Mmbtu/d (10,800 Mcf/d)

Chicago Cdn$4.17/Mmbtu ($4.94/Mcf)(1)

2018

Crude Oil

512 Bopd

WTI Cdn$66.45/Bbl floor, Cdn$70.11/Bbl ceiling

Natural Gas

750 GJ/d (600 Mcf/d)

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

 

18,425 Mmbtu/d (15,600 Mcf/d)

Chicago Cdn$4.01/Mmbtu ($4.75/Mcf)(1)

 

2,000 Mmbtu/d (1,700 Mcf/d)

Chicago US$2.98/Mmbtu


(1)  Hedge price in Chicago does not include the Alliance Pipeline tariff to Chicago which is approximately Cdn$1.35 per GJ including the cost of fuel.

The Company also has natural gas price differential hedges in place (Chicago – AECO and AECO – Station 2) with details provided in the notes to the condensed interim consolidated financial statements.

Firm transportation commitments are used to diversify sales points and mitigate pricing risk.  Firm transportation totals 72 Mmcf per day in 2017 and increases to 102 Mmcf per day in 2018.  In addition, preferential interruptible capacity on the Alliance Pipeline adds up to 14 Mmcf per day in 2017 and up to 15 Mmcf per day in 2018.  Natural gas production exceeding firm commitments is directed to Chicago and/or Station 2 using interruptible pipeline capacity (sales point depends on price).  Note that Storm’s natural gas marketing arrangements result in the cost of transportation on the Alliance Pipeline being deducted from revenue ($5.7 million deducted in the second quarter of 2017).  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

Enbridge T-North

16 Mmcf/d Station 2 price

Enbridge T-North

29 Mmcf/d Station 2 price

 

Enbridge T-North & TCPL NGTL

13 Mmcf/d AECO price

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

OUTLOOK

For the third quarter of 2017, production is anticipated to be 15,500 to 17,000 Boe per day which includes the effect of the maintenance turnaround at the McMahon Gas Plant from June 5 to July 14.  Approximately 80% of production was shut in for 14 days in the third quarter.  The duration of the turnaround was 39 days which was longer than the original expectation of 21 days.  Capital investment in the third quarter is expected to be $28 million and includes drilling four horizontal wells plus completing six horizontal wells at Umbach.

The third quarter has seen Western Canadian natural gas prices weaken as a result of continued production growth and maintenance restrictions on the TCPL NGTL system and the Enbridge T-South pipeline.  To date in the third quarter, AECO daily has averaged $1.59 per GJ (versus $2.64 per GJ in the second quarter) while Station 2 daily has averaged $1.06 per GJ (versus $2.21 per GJ in the second quarter).  The weakness is likely to continue until September for AECO and October for Station 2 when the maintenance restrictions are expected to end.  Based on field estimates, Storm’s production in July was 12,200 Boe per day and to date in August has averaged 17,300 Boe per day.  Until the Station 2 price improves, production will not be increased and volumes sold at Station 2 will be minimized to meet firm transportation commitments.  Approximately 20% of current natural gas sales are at Station 2.

Updated guidance for 2017 is summarized below.  Operations capital is forecast to be $75 to $95 million (previously $75 to $80 million) depending on both well results and commodity prices meeting Storm’s forecast for the second half of 2017.  Capital investment at the high end of the range ($95 million) would accelerate growth in 2018 by drilling and completing additional wells in the fourth quarter of 2017 (minimal impact on forecast production for 2017).  This includes installing a second compressor at the third Umbach facility in January 2018.  Should commodity prices be lower than forecast, capital investment would be reduced to the low end of the range ($75 million) by deferring the additional activity.  Forecast commodity prices reflect actual year-to-date pricing plus the approximate forward strip for the remainder of 2017.

2017 Guidance

 

May 15, 2017

 Updated

August 15, 2017

$Cdn/$US exchange rate

0.75

0.775

Chicago daily natural gas (US$/Mmbtu)

$3.00

$2.90

AECO daily natural gas (Cdn$/GJ)

$2.50

$2.45

Station 2 daily natural gas (Cdn$/GJ)

$2.10

$2.00

Edmonton light oil (Cdn$/bbl)

$62.00

$60.00

Estimated average operating costs ($/Boe)

$5.50 - $6.00

$5.75 - $6.00

Estimated average royalty rate

(% production revenue before hedging)

7% - 10%

 

6% - 8%

 

Estimated operations capital ($ million)

(excluding acquisitions & dispositions)

$75.0 - $80.0

 

$75.0 - $95.0

 

Estimated cash G&A  - $ million      

$5.3

$6.0 - $6.5

                                   - $/Boe

$0.85

$0.95 - $1.05

Forecast fourth quarter production (Boe/d)

 % condensate and NGL

19,000 - 21,000

17%

19,000 - 21,000

17%

Forecast annual production (Boe/d)

% condensate and NGL

17,000 - 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)

14 gross (14.0 net)

15 gross (15.0 net)

12 – 15 gross (12.0 – 15.0 net)

10 – 16 gross (10.0 – 16.0 net)

13 – 16 gross (13.0 – 16.0 net)

 

2017 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)

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

May 15, 2017

$3.00

$2.10

$2.50

$75.0 - $80.0

19,000 - 21,000

17,000 - 18,000

August 15, 2017

 

$2.90                                 

$2.00

$2.45

$75.0 - $95.0

19,000 - 21,000

16,500 - 18,000

 

Capital investment assumes the cost to drill and complete a horizontal well at Umbach is $4.7 million, an increase of 27% from the actual cost in 2016 with half of the increase from adding length and frac stages and half of the increase as a result of service cost inflation.    

Planned growth through 2018 is supported by forecast commodity prices as well as the expected improvement in rates, reserves, and capital efficiencies from future Montney horizontal wells at Umbach which are planned to be approximately 50% longer than the 2014 to 2016 wells.  In 2017, average production is forecast to increase by approximately 30% year over year by investing $75 to $95 million which will result in year-end net debt of approximately $100 to $120 million.  For 2018, assuming commodity prices are approximately equal to forecast prices for 2017, the preliminary plan is to invest $95 to $110 million for a further 30% to 40% increase in production with forecast fourth quarter production of 25,000 to 27,000 Boe per day.  Growth in 2018 requires an investment of $7 million in infrastructure at Umbach to add field compression which is planned for as early as January 2018 and can also be delayed depending on commodity prices.

Although the upper end of the range for capital investment was increased to provide the option to accelerate growth in expectation of improving well results, growth will not be accelerated to the detriment of the balance sheet. Correspondingly, capital investment has been designed to be flexible and activity can be adjusted quickly in response to changes in commodity prices.

With a large liquids-rich resource in the Montney at Umbach offering multiple years of drilling inventory, the objective remains to grow net asset value for shareholders by converting the resource into production and funds flow growth on a per-share basis.