Core Area Review 2019-03-01T15:22:11+00:00



Umbach/Nig/Fireweed 121,000 net acres / 20,538 Boe/d*

Horn River Basin 80,000 net acres / 0 Boe/d*

*Average daily production year ending December 31, 2018

Storm’s land position is prospective for liquids-rich natural gas from the Montney formation and currently totals 121,000 net acres (172 net sections). During the fourth quarter, seven sections of land were acquired.

Most of the land position is delineated with existing vertical wells, the 75 horizontal wells (70.9 net) drilled to date by Storm, and multiple producing horizontal wells on adjacent lands.  The majority of the producing horizontal wells have been drilled in the upper part of the Montney formation.  Storm’s future drilling will also test the mid and lower Montney in certain areas where higher field condensate-gas ratios are expected based on offsetting well control.

Fourth quarter 2018 field activity included drilling four horizontal wells (4.0 net) and completing three horizontal wells (2.5 net), all at Umbach.  Three horizontal wells (3.0 net) started production in October and November and there remains an inventory of seven horizontal wells (6.5 net) that had not started producing at the end of the quarter which includes four completed wells (3.5 net).

First quarter 2019 field activity is expected to include drilling five horizontal wells (5.0 net).  Four wells will be drilled from a single pad at Nig (licensed for a total of eight wells) with two wells in the upper Montney, one in the mid and one in the lower.  Higher field condensate-gas ratios are expected from the wells in the mid and lower Montney.

At Umbach (100% working interest), investment of approximately $18 million is planned in 2019 with activity including the drilling of one well (1.0 net), the tie-in of a two-well pad (2.0 net) and the completion of a three-well pad (3.0 net).  Current field compression capacity totals 150 Mmcf per day raw gas and throughput in the fourth quarter averaged 124 Mmcf per day raw gas (includes 24 Mmcf per day raw from three wells at Nig).  Growth is largely contingent on the Station 2 price as incremental natural gas production would be directed to Station 2.  Produced raw natural gas is sour (1.2% H2S) with approximately 85% directed to the McMahon Gas Plant and 15% to the Stoddart Gas Plant.  Firm processing commitments are 65 Mmcf raw gas per day at McMahon (10 Mmcf per day ending 2022, 55 Mmcf per day ending 2031) and 15 Mmcf per day at Stoddart (1-year term).

At Nig (100% working interest), approximately $95 million will be invested in 2019 for construction of a sour gas plant, pipelines, drilling and completing an acid gas injection well (1.0 net), and drilling, completing, and equipping four horizontal wells (4.0 net).  The license application for the planned 50 Mmcf per day sour gas plant was submitted in September 2018 and, depending on when approvals are received, construction is expected to start in mid-2019 with start-up anticipated in late 2019 or early 2020.  Produced raw natural gas contains approximately 0.2% H2S.  Total cost for the sour gas plant is estimated to be $81 million ($11.4 million invested in 2018, remainder in 2019) which includes $73 million for the gas plant, $4 million for an acid gas injection well and $4 million for a sales pipeline.  The gas plant has a forecast operating cost of $2.00 per Boe which will reduce corporate operating costs to approximately $4.25 per Boe and is expected to add incremental production of approximately 1,500 Boe per day which primarily comes from improved liquids recovery (adds 1,100 barrels per day with 90% NGL while reducing process shrinkage by 5%).

The first three horizontal wells producing at Nig were completed in early 2018 and, to date, natural gas rates plus field condensate-gas ratios have been materially higher than at Umbach.  Calendar day rates over the first 180 days have averaged 8.2 Mmcf per day raw gas plus 205 barrels per day of field condensate (approximately 1,570 Boe per day with 23% liquids including liquids recovered at the gas plant).  The condensate-gas ratio during this period was approximately 50% higher than the average well at Umbach.  There has been very little decline to date with rates in February averaging 8.2 Mmcf per day raw gas plus 150 barrels per day of field condensate based on field estimates.

At Fireweed (50% working interest), approximately $15 million net will be invested in 2019 to drill and complete three horizontal wells (1.5 net) and for deposits to order longer lead time equipment for a field compression facility.  The license application for the 50 Mmcf per day field compression facility was submitted in January 2019 and, depending on when approvals are received, construction is expected to begin between late 2019 and early 2020 with start-up in the second half of 2020.  Total costs associated with the facility are $34 million gross and it is designed to be expandable to 100 Mmcf per day.  Preliminary planning for 2020 includes net investment of approximately $50 million to drill nine horizontal wells (4.5 net), complete six horizontal wells (3.0 net) and construct the field compression facility.  Development at Fireweed is expected to increase condensate as a proportion of total production based on production history from several offsetting horizontal wells where first year average field condensate-gas ratios were 30 to 70 barrels per Mmcf raw which is 100% to 400% higher than at Umbach.

The first horizontal well (0.5 net) at Fireweed was completed in the fourth quarter of 2018 with encouraging results.  The C-74-G/94-A-13 well has a completed length of 1,520 metres and, after flowing on a six-day cleanup, rates over the last 12 hours averaged 10.9 Mmcf per day raw gas, 660 barrels per day of field condensate, and 1,140 barrels per day of frac water with a final flowing casing pressure of 4,800 kPa. The well is expected to remain shut in until the field compression facility is completed.

The licensing process was recently changed (July 2018) and applications for wells, facilities, roads and pipelines at Nig, Umbach and Fireweed are subject to the BC Oil and Gas Commission’s ‘New Interim Measures Applied to Oil and Gas Applications’.  Storm’s lands are within Area 2 where the objective is restricted new surface disturbance.  Some of Storm’s license applications will result in new disturbance and have been referred for additional review which is extending the time required to obtain licenses.  This would include pipelines and the gas plant at Nig plus pipelines, the facility and drilling at Fireweed.  The additional time required for review is not currently quantifiable (the licensing process generally required five to six months before the new measures were implemented).

A summary of horizontal well results at Nig and Umbach is provided below.  Note that IP90 and IP180 rates are not meaningful indicators of relative performance as wells after 2016 are initially rate restricted to manage fluid rates (for as long as nine months).  In addition, the 2018 horizontal wells were affected by the 17 day outage at the McMahon Gas Plant in January 2019.

Year of Completion Frac





IP90 Cal Day


IP180 Cal Day


IP365 Cal Day

Umbach 2014 – 2016

33 hz’s(1)

22 1350 m 4.9 Mmcf/d(2)

19 Bbls/Mmcf(3)

33 hz’s

4.3 Mmcf/d(2)

16 Bbls/Mmcf(3)

33 hz’s

3.4 Mmcf/d(2)

13 Bbls/Mmcf(3)

33 hz’s

Umbach 2017

12 hz’s

34 1830 m 5.0 Mmcf/d(2)

24 Bbls/Mmcf(3)

12 hz’s

4.5 Mmcf/d(2)

20 Bbls/Mmcf(3)

12 hz’s

4.3 Mmcf/d(2)

14 Bbls/Mmcf(3)

12 hz’s

Umbach 2018

5 hz’s

31 1850 m 3.5 Mmcf/d(2)

23 Bbls/Mmcf(3)

4 hz’s

Nig 2018

3 hz’s

37 2180 m 8.1 Mmcf/d(2)

29 Bbls/Mmcf(3)

3 hz’s

8.2 Mmcf/d(2)

25 Bbls/Mmcf(3)

3 hz’s

(1)  2014 – 2016 wells exclude a middle Montney well (this table provides analysis of upper Montney wells only).

(2)  Raw gas rate.

(3)  Bbls/Mmcf is the condensate-gas ratio or barrels of field condensate per Mmcf raw.

Based on results from the 2017 and 2018 wells, Storm management is using an 11 Bcf raw gas type curve (internal estimate) to forecast production which represents an average of the expected result at Umbach and Nig.  Future wells will be longer (2300 to 2400 metres) and have more fracture stages (41 to 47) which is expected to result in further improvement to rates and reserves.  More detail on well performance and management’s type curve is available in the presentation on Storm’s website at

Through a predecessor company Storm began acquiring undeveloped land in the Horn River Basin of northeast British Columbia in 2008. As at December 2017, Storm had 100% working interest in 80,000 acres (119 net sections) which are prospective for natural gas from the Muskwa, Otter Park and Evie/Klua shales. Storm has one producing horizontal well in this area with cumulative production of 5.8 Bcf raw. A core area totaling 30 sections has been proven to be productive through drilling of this well plus two vertical wells that were completed with final test rates of 900 Mcf per day over the final 24 hours of each flow test. Lands within the 30 section area have been continued through drilling and are not subject to expiry. The remaining 89 sections may be subject to expiry over a period of several years beginning in 2020. Storm has no plans for additional activity in the area until there is evidence of a substantial and sustainable increase in natural gas prices.


The majority of the properties in this area were sold on July 15, 2015 and there remains only one property.  Production in 2017 averaged approximately 60 Boe per day. No capital was invested on this property by Storm in 2017 or 2018 and no activity is planned for 2019.