• Production averaged 13,418 Boe per day (18% NGL), a per-share increase of 25% from the previous quarter and 27% from the previous year. Low natural gas prices resulted in production being reduced to meet firm processing and transportation commitments with approximately 800 Boe per day shut in at Umbach plus the startup of new horizontal wells was delayed.
  • NGL production was 2,416 barrels per day, an increase of 62% from the previous year. The price was $29.12 per barrel which was 71% of the average Edmonton light oil price (60% of the NGL volume was higher value condensate and plant pentanes).
  • NGL was 18% of total production but amounted to 40% of revenue from product sales versus 27% in the prior year period.
  • Activity was focused at Umbach where seven horizontal wells were drilled, two horizontal wells were completed and one horizontal well commenced production.
  • At the end of the quarter, there was an inventory of 12 horizontal wells (12.0 net) that had not started producing (includes three completed wells).
  • Montney horizontal well performance at Umbach continues to improve with the four most recent wells averaging 5.8 Mmcf per day gross raw gas over the first 90 calendar days, a 23% increase from the average 2014 and 2015 wells. As a result, the type curve used for forecasting future horizontal well performance is being increased to 7.0 Bcf raw from 6.3 Bcf raw.
  • Controllable cash costs (operating, cash G&A, interest expense) were $8.52 per Boe, a year-over-year decrease of 27%. Transportation cost is excluded given that the sales price for volumes sold on the Alliance Pipeline includes a deduction for the pipeline tariff (artificially reduces the transportation cost).
  • Funds from operations was $7.9 million which is a decrease of 42% from the previous year. Production growth of 37% was more than offset by a 45% decrease in revenue plus hedging gains per Boe.
  • With 67% of first quarter natural gas production being sold in the higher priced Chicago market, the natural gas price net of transportation was approximately 9% higher versus selling at BC Station 2.
  • Net loss was $5.0 million or $4.09 per Boe and reflects the extremely low first quarter commodity prices with funds from operations at $6.42 per Boe being less than the depletion and depreciation rate of $8.15 per Boe.
  • Net capital investment was $23.9 million and included $15.9 million for drilling and completions plus $6.1 million to purchase major equipment for the third field compression facility at Umbach.
  • Debt including working capital deficiency was $77.2 million, which is 2.4 times annualized first quarter funds flow. Subsequent to quarter end, the bank credit facility was set at $130.0 million after the annual review was completed (previously $140.0 million).



Commodity price hedges are used to support longer term growth by providing some certainty regarding future revenue and funds flow.  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, the WTI price is hedged as approximately 80% of NGL production is priced in reference to WTI (condensate, plant pentane and butane).  A summary for 2016 is provided below.




Crude Oil

500 Bopd

Collar - 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 strategy with respect to natural gas transportation commitments is to ensure natural gas sales are diversified by selling at Chicago, AECO and BC Station 2.  Current transportation commitments total 63 Mmcf per day in 2016 and increase to 92 Mmcf per day in 2018 (interruptible capacity on the Alliance Pipeline adds up to 11 Mmcf per day in 2016 and 13 Mmcf per day in 2018).  A summary is provided below.




44 Mmcf/d (55,000 GJ/d)(1)

sale at McMahon (Alliance Pipeline)

Chicago price - Cdn$1.30/GJ(2)

48 Mmcf/d (61,000 GJ/d)(1)

sale at McMahon (Alliance Pipeline)

Chicago price - Cdn$1.30/GJ(2)

53 Mmcf/d (67,000 GJ/d)(1)

sale at McMahon (Alliance Pipeline)

Chicago price - Cdn$1.30/GJ(2)

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

sale at BC Stn 2

-Cdn$0.15/GJ pipeline tariff


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

sale at BC Stn 2

-Cdn$0.15/GJ pipeline tariff

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

sale at BC Stn 2

-Cdn$0.15/GJ pipeline tariff



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

sale at McMahon

AECO - Cdn$0.68/GJ differential


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

sale at AECO

-Cdn$0.43/GJ pipeline tariffs

(1) Interruptible capacity on the Alliance Pipeline adds up to 25% of contracted capacity.
(2) The Alliance Pipeline tariff of $1.30 per GJ is determined assuming US$1 = Cdn$1.29, Chicago US$2.20 per Mmbtu and 5.25% shrinkage for fuel gas (fuel gas shrinkage adds $$0.14 per GJ).


Production in the second quarter is forecast to be approximately 12,500 Boe per day and, until the natural gas price improves, production will be maintained at this level which fulfills firm processing and transportation commitments.  Capital investment in the second quarter is expected to be under $2.0 million.

Natural gas prices remain weak with April daily spot prices averaging US$1.92 per Mmbtu at Chicago and $1.04 per GJ at AECO.  Forward strip pricing for natural gas for the remainder of 2016 is not materially different from pricing realized in the first quarter where the operating netback excluding hedging gains was $5.20 per Boe.  This is less than the cost of adding reserves (the 2015 all-in PDP FD&A cost was $6.53 per Boe) and, as a result, producing more than what’s required to fulfill firm processing and transportation commitments is not economically justifiable.  As a result, capital investment in 2016 will be reduced to between $37.0 and $42.0 million with the startup of the third facility at Umbach deferred to April 2017 when the forward strip is supportive of production growth.  With the benefit of commodity price hedges and with the majority of natural gas production being sold in Chicago at a higher price than at BC Station 2, forecast funds flow in 2016 is expected to provide most of the capital required to maintain production at current levels.  Revised guidance is provided below with assumed commodity prices being approximately equal to realized prices to date and the current forward strip.


2016 Guidance

Original Guidance

 Nov 11, 2015


Feb 25, 2016


May 12, 2016

Chicago natural gas price


US$2.20 per Mmbtu

US$2.20 per Mmbtu

AECO natural gas price

$2.50 per GJ

$2.00 per GJ

$1.60 per GJ

BC STN 2 natural gas price

$1.90 per GJ

$1.45 per GJ

$1.25 per GJ

Edmonton light oil price

Cdn$57 per Bbl

Cdn$46 per Bbl

Cdn$50 per Bbl

Estimated average operating costs

$7.00 - $7.50 per Boe

$7.00 per Boe

$7.00 per Boe

Estimated average royalty rate

(% production revenue before hedging)

7% - 8%

5% - 6%

5% - 6%

Estimated operations capital

(excluding acquisitions & dispositions)

$105.0 million

$80.0 million

$37.0 - $42.0 million

Estimated cash G&A net of recoveries

$5.0 million

$0.80 per Boe

$5.0 million

$0.95 per Boe

$5.7 million

$1.20 per Boe

Estimated funds flow


$39.0 million

$31.0 million

Forecast fourth quarter production

20,000 – 21,000 Boe/d

(17% NGL)

15,500 – 16,500 Boe/d

(18% NGL)

13,000 – 14,000 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)

12,500 – 13,500 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)

8 gross (8.0 net)

6 gross (6.0 net)

8 gross (8.0 net)


With respect to the revised guidance, estimated cash G&A net of recoveries for 2016 has increased as a result of lower overhead recoveries associated with lower capital investment (no change to gross G&A excluding overhead recoveries).  As well, capital investment in 2016 includes $6.1 million incurred in the first quarter to purchase major equipment for the third field compression facility. 

The AECO - BC Station 2 price differential was -$0.41 per GJ in the first quarter, an improvement from -$0.85 per GJ in 2015 and closer to historical levels (-$0.20 per GJ for 2010 to 2014).  Although the low AECO price in the first quarter ($1.74 per GJ) has more than offset the improvement, having the differential return to historical levels is supportive of Storm’s future production growth given that incremental production would be sold at BC Station 2. 

Reducing cash costs and improving capital efficiency has always been a focus at the current and predecessor ‘Storm’ companies.  Further improvements are expected in 2016 with the largest being the transition to drilling longer horizontal wells with more frac stages which is expected to result in a reduction of the cost to add reserves.  Cash costs are also expected to decrease by reducing third party processing fees and through initiatives to reduce field level operating expenses.

Further weakening of natural gas prices in North America over the last three months is the result of reduced demand from a warmer than normal winter combined with continued growth in natural gas production.  At current pricing, the business is ‘broken’ for natural gas producers in Western Canada as funds flow excluding hedges fails to generate sufficient capital to offset declines; as well, rates of return are too low to justify growing production on a full-cycle basis (including the cost of expanding infrastructure).  Pricing will improve once the oversupply of natural gas is reduced through natural declines and shut-ins.  Not knowing when the natural gas price will improve, Storm’s primary objective in 2016 is to maintain a strong balance sheet by ensuring capital investment is approximately equal to funds flow and thus avoid increasing debt.  This will preserve the ability to accelerate growth when the price does improve. 

Although Storm is reducing capital investment in 2016 as a result of deterioration in the price of natural gas, annual average production in 2016 is still forecast to increase by 30% on a year-over-year basis.

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.