HIGHLIGHTS & OUTLOOK

 

HIGHLIGHTS – 2015 FOURTH QUARTER

  •  Production averaged 10,730 Boe per day (17% NGL), a per-share decrease of 2% from the previous year. During October and November, wells were shut in due to the low natural gas price at BC Station 2 (averaged $0.88 per GJ) which reduced production by approximately 2,700 Boe per day (production in December was 13,600 Boe per day).
  •  NGL production was 1,872 barrels per day, an increase of 17% from the previous year. The price was $33.50 per barrel which was 63% of the average Edmonton light oil price (57% of the NGL volume was higher value condensate and plant pentanes). 
  •  On December 1, 2015, Storm began flowing gas on the Alliance Pipeline to Chicago which improved the natural gas price in December by approximately $0.45 per Mcf over the equivalent BC Station 2 price.
  •  Activity was focused at Umbach where four horizontal wells were drilled, six horizontal wells were completed and three horizontal wells commenced production.
  •  At the end of the quarter, there was an inventory of six horizontal wells (6.0 net) that had not started producing (includes two completed wells).
  •  Montney horizontal well performance at Umbach has continued to improve as length and the number of frac stages are increased. The three most recent wells started producing in November and December, had 22 to 24 frac stages and averaged 6.5 Mmcf per day gross raw gas (1,150 Boe per day sales) over the first 90 calendar days, a 40% improvement from the average 2014 well.
  •  Controllable cash costs (operating, cash G&A, interest expense) were $8.82 per Boe, a year-over-year decrease of 12%.
  •  Funds from operations was $9.31 per Boe, a year-over-year decrease of $5.54 per Boe. Revenue declined by $15.32 per Boe which was partially offset by a hedging gain of $4.20 per Boe, royalties decreasing by $3.74 per Boe and operating costs declining by $1.39 per Boe.
  •  Net income was $1.9 million or $1.88 per Boe which reflects the year-over-year improvement in capital efficiency (notable given that revenue per Boe decreased by 51%).
  •  Debt including working capital deficiency was $61.7 million which is 1.7 times annualized fourth quarter funds flow. Storm’s bank credit facility is currently $140.0 million.

 

HIGHLIGHTS - 2015 YEAR END

  • Production for the year averaged 9,956 Boe per day (19% oil plus NGL), a year-over-year increase of 43%, or 33% on a per-share basis. Wells were shut in during the second half of the year as a result of a low natural gas price at BC Station 2 which reduced production for the year by approximately 1,400 Boe per day.  The yearly average was also reduced from the McMahon Gas Plant being shut in for 28 days in June for a loss of 550 Boe per day and properties in the Grande Prairie area producing 725 Boe per day were sold effective July 1, 2015.
  •  Controllable cash costs (operating, cash G&A, interest expense) were $10.13 per Boe, a decrease of 11% from last year.
  •  Funds from operations totaled $39.0 million, a year-over-year decrease of 14% which was mainly caused by revenue per Boe decreasing by 50% which exceeded production growth of 43%.
  •  Net capital investment was $71.5 million and included $23.6 million of proceeds from selling non-core properties in the Grande Prairie area of Alberta, $4.5 million to acquire undeveloped land at Umbach (12 net sections) and $36.0 million to expand infrastructure at Umbach.
  •  Infrastructure investment at Umbach included $18.5 million to increase field compression capacity to 80 Mmcf raw gas per day (from 45 Mmcf raw gas per day at the end of 2014), $5.3 million for 20 kilometers of pipeline, and $4.8 million to purchase major equipment for the third field compression facility.
  •  The one year FD&A cost (all-in) for reserve additions was $6.53 per Boe for PDP, $3.38 per Boe for 1P and $0.50 per Boe for 2P. The removal of reserves and associated FDC for a disposition and for economic factors reduced the 1P and 2P FD&A cost.  The one year F&D excluding acquisitions, dispositions and revisions (per NI51-101) is more representative and was $7.61 per Boe for 1P and $6.47 per Boe for 2P.
  •  The recycle ratio using the one year FD&A cost (all-in) and the funds from operations netback was 1.6X for PDP, 3.2X for 1P and 21.5X for 2P.
  •  Using fourth quarter production, the reserve life index was 5.3 years for PDP, 18.8 years for 1P and 25.7 years for 2P.
  •  Cost of production additions in 2015 improved to $11,000 per Boe per day using total capital investment and fourth quarter production of 6,500 Boe per day from wells that started production in 2015 (last year was $29,800 per Boe per day). This is reduced to $8,500 per Boe per day when land and property acquisitions/dispositions and investment in infrastructure are excluded (approximates the cost to maintain production levels).
  •  Storm’s enterprise value at year end plus FDC was equal to $10.29 per Boe on a 2P basis. Enterprise value was determined using the year-end closing share price of $3.62, 119.4 million shares outstanding, and after adding year-end debt including working capital deficiency.

 

HEDGING & TRANSPORTATION

The purpose of Storm’s commodity price hedges is to provide greater certainty regarding future cash flows and capital investment in order to support longer term growth plans.  A maximum of 50% of the most recent monthly production will be hedged; anticipated production growth is not hedged.  Although Storm has no oil production, approximately 80% of NGL production is priced in reference to WTI (condensate, plant pentane, and butane).

 A gain of $15.3 million was realized from commodity price hedging in 2015 and the fair market value of commodity price contracts for 2016 and 2017 was $8.0 million at year end.

 A summary of commodity price hedges for 2016 is provided below. 

 

Volume

Price

Crude Oil

500 Bopd

WTI Cdn$75.00 X Cdn$90.75/Bbl

Natural Gas

21,250 GJ/d (17,000 Mcf/d)

AECO Cdn$2.98/GJ ($3.72/Mcf)

 

11,000 GJ/d (8,800 Mcf/d)

BC Stn 2 price = AECO – Cdn$0.3375/GJ

 

33,000 Mmbtu/d (27,800 Mcf/d)

Chicago price = AECO + US$0.672/Mmbtu

 

Storm’s transportation commitments increase from 62 Mmcf per day in 2016 to 91 Mmcf per day in 2018 (interruptible capacity on the Alliance Pipeline adds up to 25% of contracted capacity or 11 Mmcf per day in 2016 and 13 Mmcf per day in 2018). 

2016

2017

2018

43.5 Mmcf/d (54,800 GJ/d)

Alliance Pipeline

Chicago – Cdn$1.35/GJ toll(1)(2)

48.0 Mmcf/d (60,500 GJ/d)

Alliance Pipeline

Chicago – Cdn$1.35/GJ toll(1)(2)

52.5 Mmcf/d (66,000 GJ/d)

Alliance Pipeline

Chicago – Cdn$1.35/GJ toll(1)

9.0 Mmcf/d (11,400 GJ/d)

Spectra T-north

BC Stn 2(3) – Cdn$0.16/GJ toll

 

24.0 Mmcf/d (30,200 GJ/d)

Spectra T-north

BC Stn 2(3) – Cdn$0.16/GJ toll

29.0 Mmcf/d (36,500 GJ/d)

Spectra T-north

BC Stn 2 – Cdn$0.16/GJ toll

 

 

9.8 Mmcf/d (12,400 GJ/d)

AECO - $0.68/GJ(1)

 

10.0 Mmcf/d (12,600 GJ/d)

Spectra T-north & TCPL

sale at AECO - $0.45/GJ toll

  • (1) Volumes sold at McMahon Gas Plant with pipeline tariff deducted from realized price.
  • (2) The Chicago – AECO differential has been fixed for 33,000 Mmbtu per day in 2016 at +US$0.672 per Mmbtu and for 35,000 Mmbtu per day in 2017 at +US$0.577 per Mmbtu.
  • (3) The AECO – BC Station 2 differential has been fixed for 11,000 GJ per day in 2016 at -$0.3375 per GJ and for 5,000 GJ per day in 2017 at -$0.445 per GJ.

 

COMPARISON OF 2015 RESULTS VERSUS GUIDANCE

Shown below is a comparison of Storm’s actual 2015 results to what was provided for guidance. 

 

2015 Guidance

Original Guidance

Nov 13, 2014

Last Update

Nov 11, 2015

Actual

 2015 Results

AECO natural gas price

$3.25 per GJ

$2.60 per GJ

$2.55 per GJ

BC Stn 2 natural gas price

$3.00 per GJ

$1.87 per GJ

$1.70 per GJ

Edmonton light oil price

Cdn$83 per Bbl

Cdn$58 per Bbl

Cdn$57 per Bbl

Estimated average operating costs

$7.50 - $8.00 per Boe

$7.75 - $8.00

$8.00 per Boe

Estimated average royalty rate

(% production revenue before hedging)

12% - 14%

6% - 7%

4%

Estimated operations capital

(excluding acquisitions & dispositions)

$110.0 million

$92.0 million

$90.7 million

Estimated land and property

acquisitions/(dispositions)

$0.0 million

($19.3 million)

($19.2 million)

Estimated cash G&A net of recoveries

$5.3 million

$5.3 million

$5.5 million

Forecast fourth quarter production

14,000 – 14,500 Boe/d

(18% oil + NGL)

10,000 – 12,000

(18% NGL)

10,730 Boe/d

(17% NGL)

Forecast annual production

11,500 – 12,700 Boe/d

(19% oil + NGL)

10,000 – 11,000

(19% oil + NGL)

9,956 Boe/d

(19% oil + NGL)

Umbach horizontal wells:

   Drilled

   Completed

   Starting production

 

9 gross (9.0 net)

14 gross (14.0 net)

16 gross (16.0 net)

 

10 gross (10.0 net)

13 gross (13.0 net)

13 gross (13.0 net)

 

10 gross (10.0 net)

13 gross (13.0 net)

12 gross (12.0 net)

 

Comparing actual 2015 results to original guidance:

  •  Forecast annual and fourth quarter production was lower as a result of wells shut in during the second half of 2015 due to the low BC Station 2 natural gas price (loss of 1,400 Boe per day during 2015), plus the mid-year disposal of Alberta properties (loss of 300 Boe).
  •  The royalty rate was lower as a result of receiving $2.0 million of infrastructure royalty credits and from lower commodity prices (royalty rate in British Columbia depends on well productivity and the natural gas price).
  •  Operations capital investment was less than forecast due to the third field compression facility at Umbach being deferred into 2016 from October 2015 ($25.0 million estimated total cost less $4.8 million paid in 2015 for major equipment and site preparation).

 

OUTLOOK

Production in the first quarter of 2016 is forecast to be 13,000 to 14,000 Boe per day and will largely depend on natural gas prices.  Production to date in the first quarter has averaged approximately 13,500 Boe per day based on field estimates.  Capital investment in the first quarter is expected to be $25.0 million.

  Guidance for 2016 is being revised due to the continuing decline in commodity prices which has reduced forecast funds flow.  Capital investment in 2016 will be reduced to $80 million which will result in fewer horizontal wells being drilled and completed plus the start-up of the third field compression facility at Umbach being delayed to the fourth quarter of 2016.  If commodity prices remain at current levels or continue to decline, capital investment would likely be further reduced in mid-May to approximately $45 million which would result in forecast production averaging 13,000 to 14,000 Boe per day in 2016 and the third field compression facility being delayed until 2017 (requires approximately seven horizontal wells starting production in 2016 to offset declines).  Revised guidance for 2016 is provided below with assumed commodity prices being approximately equal to the current forward strip. 

 

2016 Guidance

Original Guidance

 Nov 11, 2015

Revised

Feb 25, 2016

Chicago natural gas price

 

US$2.20 per mmbtu

AECO natural gas price

$2.50 per GJ

$2.00 per GJ

BC STN 2 natural gas price

$1.90 per GJ

$1.45 per GJ

Edmonton light oil price

Cdn$57 per Bbl

Cdn$46 per Bbl

Estimated average operating costs

$7.00 - $7.50 per Boe

$7.00 per Boe

Estimated average royalty rate

(% production revenue before hedging)

7% - 8%

5% - 6%

Estimated operations capital

(excluding acquisitions & dispositions)

$105.0 million

$80.0 million

Estimated land and property

acquisitions/(dispositions)

 

 

Estimated cash G&A net of recoveries

$5.0 million

$5.0 million

Estimated funds flow

 

$39.0 million

Forecast fourth quarter production

20,000 – 21,000 Boe/d

(17% NGL)

15,500 – 16,500 Boe/d

(18% NGL)

Forecast annual production

16,000 – 18,000 Boe/d

(17% oil + NGL)

14,000 – 15,000 Boe/d

(18% oil + NGL)

Umbach horizontal wells drilled

Umbach horizontal wells completed

Umbach horizontal wells connected

14 gross (14.0 net)

14 gross (14.0 net)

16 gross (16.0 net)

12 gross (12.0 net)

10 gross (10.0 net)

12 gross (12.0 net)

 

Capital investment in 2016 will be directed entirely to Umbach and will include $48 million for drilling and completions plus $24 million for infrastructure (includes remaining $21 million for the third field compression facility).  Infrastructure expansion is being funded with debt which is an investment in a long life asset (value doesn't decline with time).

 Natural gas sales will be more diversified going forward with Storm’s contracted capacity on the Alliance Pipeline for delivery to Chicago.  Using forecasted natural gas production in 2016, approximately 22% will be sold at Chicago pricing, 65% sold at an AECO price less a fixed differential and the remaining 13% at the Chicago or BC Station 2 price (whichever is higher).  This is much different from 2015 where approximately 50% received the BC Station 2 price which reduced the realized natural gas price and operating netback in the second half of the year.   

 The high quality and competitive advantages of Storm’s Montney land position at Umbach (shallow depth and liquids rich) are reflected in the 2015 all-in PDP FD&A cost of $6.53 per Boe which resulted in a recycle ratio of 1.6X using the 2015 funds flow netback. This is a significant achievement given the low netback in 2015 and reflects Storm’s sustainability in the current low commodity price environment.  An important objective in 2016 is to achieve further reductions in the PDP FD&A cost in order to remain competitive.  For evaluating capital efficiency, PDP FD&A has become a better metric than 1P or 2P FD&A given that it isn’t influenced by the accuracy of estimates for future development capital (including required infrastructure).

 Storm is still in the early stages of delineating the large liquids rich resource in the Montney formation at Umbach.  At the end of 2015, only 20% of Storm’s land position was assigned 2P reserves (31 net sections of 155 net sections) which leaves room for significant future reserve growth from the remaining lands which appear to be highly prospective given horizontal well results on offsetting acreage.  Over time, data from the wells that have been drilled on offsetting lands is likely to result in reserve additions on Storm’s lands.

Storm’s results in 2015 reflect a focus on converting Montney resource at Umbach into production and cash flow plus reducing the cost structure (both controllable cash costs and cost of PDP reserve additions).  Looking ahead to 2016, the business environment for oil and gas producers continues to become more challenging with the ongoing decline in commodity prices.  Storm plans to weather the storm by continuing to build a business for the longer term with a focus on operational excellence which will include: 

  • further improving capital efficiency by reducing PDP FD&A costs (add length and frac stages on horizontal wells at Umbach;
  • increasing the funds flow netback by decreasing controllable cash costs;
  • identifying and capturing opportunities that increase future net asset value; and
  • maintaining a strong balance sheet so that growth can be accelerated when commodity prices improve.

 

Storm’s land position in the Horn River Basin continues to be a core, long-term asset with significant leverage to higher natural gas prices.

 In closing, I would like to thank Storm’s employees for their efforts in 2015 which resulted in record levels of production and significant improvements in capital efficiency.  In addition, the invaluable advice, guidance, and support provided by Storm’s Directors continues to be very much appreciated.