HIGHLIGHTS & OUTLOOK

HIGHLIGHTS – 2017 FIRST QUARTER

  •  Production was a record 16,947 Boe per day (17% condensate and NGL), a per-share increase of 24% from the first quarter of last year and a per-share increase of 27% from the previous quarter. The increase was the result of the start-up of a third field compression facility at Umbach on January 12, 2017 plus five new horizontal wells (5.0 net) were turned on during the quarter.  
  • Condensate and NGL production increased 21% from the first quarter of last year to average 2,932 barrels per day. Revenue from liquids was 34% of total revenue.    
  • Montney horizontal well performance at Umbach continues to improve as length and the number of fracs are increased. The five wells completed in 2016 with enough production history averaged 4.8 Mmcf per day gross raw gas over the first 180 calendar days, a 14% improvement from the average 2015 wells.  The four wells completed to date in 2017 are approximately 25% longer and three of them have been producing for 30 to 60 days with encouraging early data.
  • Controllable cash costs (production, general and administrative, interest and finance) were $7.65 per Boe, a decrease of 10% year over year. Production costs declined by 13% from the same period in 2016 and 16% from the fourth quarter of 2016 as a result of the new processing arrangement at Umbach which started on January 1, 2017.  
  • Funds flow was $18.0 million ($11.76 per Boe), an increase of 129% from a year ago. The increase was driven by an 84% increase in revenue per Boe and a 26% increase in production volumes which was partially offset by a realized hedging loss of $3.5 million or $2.31 per Boe. 
  • Net income was $20.6 million or $0.17 per share which includes an unrealized mark to market hedging gain of $16.1 million. Notably, excluding the effect of the unrealized hedging gain, net income was $4.5 million, or $0.04 per share.
  • Capital investment was $27.4 million including $19.0 million to drill six horizontal wells (6.0 net) and complete four horizontal wells (4.0 net) plus $1.5 million to complete the third field compression facility at Umbach. 
  • At the end of the quarter, there was an inventory of ten horizontal wells (10.0 net) that had not started producing (includes two completed wells).
  • Debt including working capital deficiency was $97.9 million which is 1.4 times annualized first quarter funds flow. Subsequent to quarter end, the bank credit facility was increased to $165.0 million from $130.0 million.
  • Commodity price hedges continue to be layered in with approximately 43% of forecast 2017 production currently hedged.

 

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.  Approximately 43% of forecast 2017 production is currently hedged. 

Q2 – Q4 2017 Hedges

Crude Oil

1,050 Bopd

WTI Cdn$64.75/Bbl floor, Cdn$69.60/Bbl ceiling

Natural Gas

36,400 GJ/d (29,200 Mcf/d)

AECO Cdn$2.68/GJ ($3.34/Mcf)

 

11,500 Mmbtu/d (9,700 Mcf/d)

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

2018 Hedges

Crude Oil

410 Bopd

WTI Cdn$65.99/Bbl floor, Cdn$70.54/Bbl ceiling

Natural Gas

750 GJ/d (600 Mcf/d)

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

 

18,400 Mmbtu/d (15,500 Mcf/d)

Chicago Cdn$4.00/Mmbtu ($4.75/Mcf)(1)

  • Hedge price in Chicago doesn’t include the Alliance Pipeline tariff to Chicago which was Cdn$1.66 per Mcf in the first quarter including the cost of fuel.

 

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

The strategy with respect to natural gas transportation commitments is to mitigate risk by diversifying sales and selling at multiple points.  In the first quarter of 2017, 62% of natural gas sales were at Chicago, 32% at BC Station 2 and 6% at Alliance Transfer Point (“ATP”).  Approximately 82% of forecast natural gas production in 2017 is covered by firm transportation commitments with the remainder directed to Chicago and/or BC Station 2 using interruptible pipeline capacity (sales point depends on price).  Note that the cost of transportation to Chicago and ATP on the Alliance Pipeline is presented as a deduction from revenue with $7.3 million deducted from revenue in the first quarter of 2017.  Further information on pipeline tariffs and price deductions is provided in the presentation on Storm’s website.

2017 Firm Transportation

2018 Firm Transportation

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

T-north

16 Mmcf/d BC Station 2 price

T-north

29 Mmcf/d BC Station 2 price

 

 

 

 

T-north & TCPL

13 Mmcf/d AECO price

2017 Total 72 Mmcf per day

2018 Total 102 Mmcf per day

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

Commodity price hedges are used to support longer term growth by providing some certainty regarding future 

OUTLOOK

For the second quarter of 2017, production is anticipated to be 14,000 to 15,000 Boe per day which includes the effect of a maintenance turnaround at the McMahon Gas Plant which will result in approximately 75% of Storm’s production being shut in for 21 days.  Note that production in April averaged approximately 18,400 Boe per day based on field estimates.  Capital investment in the second quarter is expected to be approximately $13 to $18 million which includes completing four to six horizontal wells at Umbach.

Guidance for 2017 includes an increase to forecast production as a result of well performance exceeding expectations and a reduction to forecast royalty rates.  As well, forecast commodity prices are updated to reflect actual first quarter pricing.

2017 Guidance

 

 Updated

November 15, 2016

 Updated

March 2, 2017

 Updated

May 15, 2017

$Cdn/$US exchange rate

0.77

0.77

0.75

Chicago spot natural gas (US$/Mmbtu)

$3.00

$3.00

$3.00

AECO spot natural gas (Cdn$/GJ)

$2.65

$2.50

$2.50

BC Stn 2 spot natural gas (Cdn$/GJ)

$2.20

$2.00

$2.10

Edmonton light oil (Cdn$/bbl)

$55.00

$59.00

$62.00

Estimated average operating costs ($/Boe)

$5.50 - $5.75

$5.50 - $6.00

$5.50 - $6.00

Estimated average royalty rate

(% production revenue before hedging)

9% - 11%

 

9% - 11%

 

7% - 10%

 

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%

19,000 - 21,000

17%

Forecast annual production (Boe/d)

% condensate and NGL

16,500 - 18,000

17%

16,500 - 18,000

17%

17,000 - 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 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)

         

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

May 15, 2017

$3.00

$2.10

$2.50

$75.0 - $80.0

19,000 - 21,000

17,000 - 18,000

 

There is flexibility to adjust 2017 capital investment depending on commodity prices and funds flow which may affect forecast production.  The current hedge position will provide some cushion in the event of a material decline in commodity prices.  Note that some cost inflation is expected based on 2017 first quarter results and capital investment assumes the cost to drill and complete a horizontal well at Umbach is $4.3 million, an increase of 13% from the 2016 actual cost.   

The outlook for natural gas prices remains positive as a result of a growing supply/demand deficit in the United States.  Data from the Energy Information Administration (“EIA”) shows 2016 demand (consumption) exceeded supply (dry gas production plus net imports) by 0.9 Bcf per day.  So far in 2017, January and February supply is 1.1 Bcf per day lower than the 2016 average which further widens the deficit.  Longer term, demand continues to increase as a result of five LNG export facilities currently operating or under construction on the US Gulf Coast.  In addition, 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. 

Most of Storm’s firm transportation commitments have been added over the last two years with the intent of reducing risk by diversifying natural gas sales (not betting for or against pricing in any single market).  A good example supporting the diversification of sales is the continued narrowing of the AECO – BC Station 2 price differential which is contrary to the consensus view that the differential would widen with continued production growth from northeast British Columbia (“NE BC”).  Since late 2015, the differential has narrowed to average -$0.19 per GJ in the first quarter of 2017 versus  -$0.41 per GJ in 2016 and -$0.85 per GJ in 2015.  Although production growth has continued, the differential has not been impacted as most of the growth has been directed onto the TCPL system to AECO (the differential can be temporarily affected by outages and/or constraints on the TCPL system or Alliance Pipeline where more natural gas is redirected to BC Station 2).  Also helping was the Alliance Pipeline re-contracting in late 2015 where most of the capacity was taken up by producers instead of marketers.  TCPL is planning to further increase capacity out of NE BC with the North Montney extension which adds 1.5 Bcf per day of takeaway in early 2019 if a variance application is approved by the National Energy Board (“NEB”).  It is unlikely that production can grow this much over the next two years, so some of the incremental volume for this expansion is likely to be sourced from natural gas redirected away from BC Station 2 which further supports a narrower differential.  In the first quarter of 2017, approximately 32% of Storm’s natural gas sales benefitted from the narrowing differential.

There continues to be an effort directed toward reducing Storm’s cost structure to improve competitiveness in the continuing lower price environment.  Production costs per Boe have decreased by 16% from the fourth quarter of 2016 with the new processing arrangement at Umbach.  Further reductions in per-Boe costs are expected with continued production growth at Umbach.  Reserve addition costs are being reduced with longer horizontal wells that access more gas in place plus adding fracs on tighter spacing is increasing recovery.  Recent results from longer 2017 wells are encouraging and further improvement is expected as longer wells are drilled and brought on production.

Current commodity prices are supportive of the near-term plan to grow average 2017 production by more than 30% from 2016 levels by investing $75 to $80 million which will result in year-end net debt of approximately $95 to $100 million, a year-over-year increase of 5% to 10%.  The preliminary plan for 2018 is for a further 25% to 35% increase in production volumes.  Growth in 2017 and 2018 is further supported by firm transportation commitments, hedging and the infrastructure at Umbach which supports growth to 27,000 Boe per day (after adding a second compressor at the third field compression facility).

With a large 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.