HIGHLIGHTS & OUTLOOK

 

HIGHLIGHTS – 2016 THIRD QUARTER

  • Production averaged 13,285 Boe per day (17% NGL), a year-over-year increase of 38% (37% on a per-share basis) and a quarter-over-quarter increase of 3%. Production increased compared to the previous quarter with two new wells beginning production in late August and in September as a result of the improvement in natural gas prices.
  • NGL production was 2,299 barrels per day, an increase of 35% from the previous year. At $30.54 per barrel, the price was 56% of the average Edmonton light oil price (53% of NGL’s are higher value condensate and plant pentanes).
  •  Through the first nine months of 2016, six new horizontal wells have been placed on stream which has maintained production between 12,500 and 13,800 Boe per day. At the end of the quarter, there was an inventory of seven horizontal wells (7.0 net) that had not started production which included one completed well.
  •  Montney horizontal well performance at Umbach continues to improve with the first two wells completed in 2016 averaging 5.7 Mmcf per day gross raw gas over the first 90 calendar days, a 20% improvement from the average 2014 and 2015 wells.
  •  Controllable cash costs (operating, cash G&A, interest expense) were $8.44 per Boe, a year-over-year decrease of 10%. Transportation cost is excluded given that the sales price for volumes shipped on the Alliance Pipeline includes a deduction for the pipeline tariff (artificially reduces the transportation cost).  
  •  Funds flow was $8.8 million ($7.17 per Boe), an increase of 10% from a year ago. Excluding hedging gains, the increase was 46%.  The year-over-year improvement resulted from production increasing 38% and controllable cash costs per Boe decreasing 10% which was partially offset by a 6% decrease in revenue per Boe.
  •    Net capital investment was $7.0 million which included completing three horizontal wells (3.0 net) and site preparation for the third field compression facility at Umbach.
  •  Debt including working capital deficiency was $69.3 million which is 2.0 times annualized third quarter funds flow and is a reduction of $2.0 million from the previous quarter. The bank credit facility remains at $130 million.
  •  Commodity price hedges for 2017 have increased to represent approximately 39% of current production (an increase from approximately 24% hedged when second quarter results were released August 15, 2016).
  •  On September 7, Storm announced that it had entered into a natural gas processing arrangement at Umbach with Spectra Energy (“Spectra”) that is expected to reduce operating costs by approximately 15% to 20% with the anticipated increase in funds flow being used to increase capital investment and accelerate growth in 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 monthly production for the next 12 months and 25% of most recent monthly production for 13 to 24 months forward.  Anticipated production growth is not hedged.  The WTI price is also hedged as approximately 80% of Storm’s NGL production is priced in reference to WTI (condensate, plant pentane and butane).  Hedges will be updated periodically in the presentation posted on Storm’s website.

 Storm’s commodity price hedges are summarized below.  For 2017, approximately 38% of current production or 30% of forecast 2017 production is hedged.

Q4 2016

Crude Oil

950 Bopd

WTI Cdn$68.86/Bbl floor, Cdn$78.48/Bbl ceiling

Natural Gas

43,670 GJ/d (34,900 Mcf/d)

AECO Cdn$2.38/GJ ($2.98/Mcf)

2017

Crude Oil

775 Bopd

WTI Cdn$64.11/Bbl floor, Cdn$69.24/Bbl ceiling

Natural Gas

30,340 GJ/d (24,300 Mcf/d)

AECO Cdn$2.62/GJ ($3.27/Mcf)

 

2,940 GJ/d (2,350 Mcf/d)

Chicago Cdn$3.90/GJ ($4.88/Mcf)

 

Storm’s strategy with respect to natural gas transportation commitments is to diversify natural gas sales by selling at multiple points including Chicago, AECO and BC Station 2.  Transportation commitments total 65 Mmcf per day in 2017 and increase to 95 Mmcf per day in 2018 (interruptible capacity on the Alliance Pipeline adds up to 14 Mmcf per day in 2017 and up to 15 Mmcf per day in 2018).  As production increases, additional firm transportation will be added.  A summary is provided below and further information on pipeline tariffs and price deductions is provided in the presentation on Storm’s website.

                  Q4 2016

                  2017

                           2018

Alliance Pipeline(1)

46 Mmcf/d Chicago price

  5 Mmcf/d ATP price

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

9 Mmcf/d BC Stn 2 price

 

 

 

Spectra T-north

9 Mmcf/d BC Stn 2 price

 

 

 

Spectra T-north

22 Mmcf/d BC Stn 2 price

 

 

 

Marketing Arrangement

3 Mmcf/d AECO price -$0.68/GJ

 

Spectra T-north & TCPL

13 Mmcf/d AECO price

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

 

 OUTLOOK

Fourth quarter production is forecast to be approximately 13,000 to 14,000 Boe per day depending on commodity prices.  Production in October averaged 12,200 Boe per day and was impacted by a nine-day outage on the Alliance Pipeline plus an 11-day outage on the Spectra T-north Fort St. John lateral to BC Station 2.  Capital investment is expected to be $37 million and activity will include construction of the third field compression facility at Umbach ($11 million), drilling five horizontal wells ($10 million), and completing and equipping five horizontal wells ($11 million).

On September 7, 2016, Storm announced that it had entered into a natural gas processing arrangement with Spectra at Umbach with the expected increase in funds flow being used to increase capital investment and accelerate growth in 2017.  Expected service cost reductions are also supportive of accelerating growth.  Guidance for 2016 and 2017 is provided below and is unchanged from what was provided September 7th except for updating commodity prices.

2016 Guidance

 

September 7, 2016

November 15, 2016

Chicago natural gas price

US$2.40/Mmbtu(1)

US$2.45/Mmbtu(1)

AECO natural gas price

$1.95/GJ(1)

$2.00/GJ(1)

BC STN 2 natural gas price

$1.65/GJ(1)

$1.65/GJ(1)

Edmonton light oil price

Cdn$50/Bbl(1)

Cdn$52/Bbl(1)

Estimated average operating costs

$7.00/Boe

$7.00/Boe

Estimated average royalty rate

(% production revenue before hedging)

5% - 6%

5% - 6%

Estimated operations capital

(excluding acquisitions & dispositions)

$70.0 million

$65.0 - $70.0 million

Estimated cash G&A net of recoveries

$5.7 million

$1.20/Boe

$5.7 million

$1.20/Boe

Forecast fourth quarter production

13,000 – 14,000 Boe/d

(18% NGL)

13,000 – 14,000 Boe/d

(18% NGL)

Forecast annual production

12,500 – 13,500 Boe/d

(18% NGL)

12,500 – 13,500 Boe/d

(18% NGL)

Umbach horizontal wells drilled

Umbach horizontal wells completed

Umbach horizontal wells connected

12 gross (12.0 net)

10 gross (10.0 net)

10 gross (10.0 net)

12 gross (12.0 net)

10 gross (10.0 net)

11 gross (11.0 net)

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

2016 Guidance History

 

 

AECO

Natural gas

price

Estimated

 Operations

 Capital

Forecast

Fourth Quarter

Production

Forecast

Annual

Production

August 13, 2015

$2.80/GJ

$106.0 million

20,000 – 21,000 Boe/d

16,000 – 19,000 Boe/d

November 11, 2015

$2.50/GJ

$105.0 million

20,000 – 21,000 Boe/d

16,000 – 18,000 Boe/d

February 25, 2016

$2.00/GJ

$80.0 million

15,500 – 16,500 Boe/d

14,000 - 15,000 Boe/d

May 12, 2016

$1.60/GJ

$37.0 to $42.0 million

13,000 – 14,000 Boe/d

12,500 - 13,500 Boe/d

August 15, 2016

$1.95/GJ

$36.0 to $50.0 million

13,000 – 14,000 Boe/d

12,500 - 13,500 Boe/d

September 7, 2016

$1.95/GJ

$70.0 million

13,000 – 14,000 Boe/d

12,500 - 13,500 Boe/d

 

2017 Guidance

 

 

 September 7, 2016

 

 November 15, 2016

Chicago natural gas price

US$3.00 per Mmbtu

US$3.00 per Mmbtu

AECO natural gas price

$2.65 per GJ

$2.65 per GJ

BC STN 2 natural gas price

$2.25 per GJ

$2.20 per GJ

Edmonton light oil price

Cdn$55 per Bbl

Cdn$55 per Bbl

Estimated average operating costs

$5.50 - $5.75/Boe

$5.50 - $5.75/Boe

Estimated average royalty rate

(% production revenue before hedging)

9% - 11%

9% - 11%

Estimated operations capital

(excluding acquisitions & dispositions)

$75.0 - $80.0 million

$75.0 - $80.0 million

Estimated cash G&A net of recoveries

$5.3 million

$0.85/Boe

$5.3 million

$0.85/Boe

Forecast fourth quarter production

18,000 – 20,000 Boe/d

(17% NGL)

18,000 – 20,000 Boe/d

(17% NGL)

Forecast annual production

16,500 – 18,000 Boe/d

(17% NGL)

16,500 – 18,000 Boe/d

(17% NGL)

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)

 

Capital investment in 2016 includes $19 million for the third field compression facility which is expected to be operational in January 2017.  Initial capacity will be 35 Mmcf per day which can be expanded to 70 Mmcf per day for an additional investment of $7 million.  Once the expansion is completed, capacity from Storm’s three field compression facilities will exceed 150 Mmcf per day of raw gas which supports growth in corporate production to 25,000 to 27,000 Boe per day.

Capital investment in 2017 assumes a cost of $4.1 million to drill and complete a horizontal well at Umbach plus a total of $14.0 million for infrastructure expansion at Umbach which includes gathering pipelines and the remaining equipment at the third field compression facility.

Forecast production for 2017 is dependent on capital investment which may be adjusted up or down depending on commodity prices and funds flow.  Hedges will continue to be layered in for 2017 and 2018 in support of planned growth which increases certainty on future funds flow.

Approximately 74% of forecast natural gas production in 2017 is covered by firm transportation agreements with the majority being capacity on the Alliance Pipeline (65% of forecast 2017 production).  Including ’priority interruptible transportation service’ (PITS) on the Alliance Pipeline, 90% of forecast 2017 production is covered.  Storm’s capacity on the Alliance Pipeline reduces exposure to widening natural gas price differentials between markets in Canada and the United States (Chicago – AECO differential -US$0.54 per Mmbtu in December 2015 widened to -US$1.03 per Mmbtu in September 2016).  Differentials have widened as a result of growth in western Canadian production and exceed the pipeline transportation cost which is unusual but unlikely to change until production declines or export pipeline capacity is added.

Natural gas prices in North America were very low in the first half of 2016 (AECO $1.53/GJ, NYMEX US$2.12/Mmbtu) as a result of very high levels of natural gas in storage following a warmer winter which reduced residential and commercial heating demand.  However, prices have improved significantly since mid-2016 as a result of the supply/demand balance tightening in the United States.  In August, the year-over-year supply/demand balance was tighter by 7 Bcf per day with natural gas production down 2 Bcf per day while demand was up 5.3 Bcf per day (notably electric power generation was +4.1 Bcf per day and LNG exports plus exports to Mexico were +1.7 Bcf per day).  Most of the growth in natural gas production in the United States over the last two to three years has been from the Marcellus/Utica shales and re-initiating growth likely requires higher natural gas prices given many Marcellus/Utica producers have high cost structures plus sell natural gas at discounted prices (reflecting the higher pipeline tariffs to move natural gas to Chicago or the Gulf Coast).  Recently, the warm start to the winter heating season has caused a decline in natural gas prices but the tighter supply/demand balance means it is unlikely to be a repeat of last winter where high storage levels at the end of March depressed prices.  The longer term outlook appears increasingly bullish with LNG export capacity of more than 9 Bcf per day currently operating or under construction on the US Gulf Coast plus US exports to Mexico are expected to continue increasing as multiple new export pipelines and interconnections are completed over the next two years.

With 155 net sections at Umbach, there remains room for significant future growth with producing horizontal wells on only 6% of the lands (9 net sections) and proved plus probable reserves assigned on only 20% of the lands (31 net sections).  The focus remains on converting this large resource into per-share growth in production and cash flow while preserving balance sheet flexibility.