CALGARY, Alberta, Aug. 14, 2018 (GLOBE NEWSWIRE) — Storm has also filed its unaudited condensed interim consolidated financial statements as at June 30, 2018 and for the three and six months then ended along with Management’s Discussion and Analysis (“MD&A”) for the same period. This information appears on SEDAR at and on Storm’s website at  Selected financial and operating information for the three and six months ended June 30, 2018 appears below and should be read in conjunction with the related financial statements and MD&A.


Thousands of Cdn$, except volumetric and
  per-share amounts
Three Months to
June 30, 2018
  Three Months to
June 30, 2017
  Six Months to
June 30, 2018
  Six Months to
June 30, 2017
Revenue from product sales(1) 48,104   33,262   100,206   77,654  
Funds flow 23,405   11,629   46,924   29,587  
  Per share – basic and diluted ($) 0.19   0.10   0.39   0.24  
Net income (loss) (2,815 ) 9,752   6,079   30,383  
  Per share – basic and diluted ($) (0.02 ) 0.08   0.05   0.25  
Capital expenditures(2) 2,918   4,307   25,818   31,664  
Debt including working capital deficiency(2)(3) 85,073   90,582   85,073   90,582  
Common shares (000s)        
  Weighted average – basic 121,557   121,557   121,557   121,500  
  Weighted average – diluted 121,557   121,682   121,557   121,702  
  Outstanding end of period – basic 121,557   121,557   121,557   121,557  
(Cdn$ per Boe)        
Revenue from product sales(1) 27.07   26.12   28.22   27.75  
Transportation costs (6.25 ) (5.75 ) (5.92 ) (5.61 )
Revenue net of transportation 20.82   20.37   22.30   22.14  
Royalties (1.11 ) (1.47 ) (1.41 ) (1.69 )
Production costs (5.46 ) (6.74 ) (5.51 ) (6.25 )
Field operating netback(2) 14.25   12.16   15.38   14.20  
Realized (loss) gain on hedging 0.31   (1.10 ) (0.44 ) (1.76 )
General and administrative (0.69 ) (1.17 ) (1.05 ) (1.13 )
Interest and finance costs (0.71 ) (0.76 ) (0.68 ) (0.73 )
Funds flow per Boe 13.16   9.13   13.21   10.58  
Barrels of oil equivalent per day (6:1) 19,529   13,991   19,618   15,461  
Natural gas production        
  Thousand cubic feet per day 96,426   68,308   96,248   76,157  
  Price (Cdn$ per Mcf)(1) 3.15   3.77   3.49   4.00  
Condensate production        
  Barrels per day 1,984   1,468   2,023   1,612  
  Price (Cdn$ per barrel)(1) 86.33   57.65   81.15   61.31  
NGL production        
  Barrels per day 1,473   1,138   1,554   1,156  
  Price (Cdn$ per barrel)(1) 36.43   20.45   34.66   21.78  
Wells drilled (100% working interest)       6.0  
Wells completed (100% working interest)     3.0   4.0  
  1. Excludes gains and losses on commodity price contracts.
  2. Certain financial amounts shown above are non-GAAP measurements including field operating netback, operations capital expenditures, debt including working capital deficiency and all measurements per Boe.  See discussion of Non-GAAP Measurements on page 24 of the MD&A.
  3. Excludes the fair value of commodity price contracts.



  • Production increased by 40% on a per-share basis from the prior year to 19,529 Boe per day which was consistent with guidance (19,500 to 20,500 Boe per day).  Production in the quarter was reduced by approximately 800 Boe per day as a result of a gas plant maintenance turnaround in June.  Note that production in the prior year quarter was reduced by approximately 4,000 Boe per day for a maintenance turnaround at the McMahon Gas Plant. 
  • Liquids production (condensate plus NGL) grew by 33% year over year with liquids representing 18% of total production and 43% of production revenue.
  • Over the last 12 months, Storm has increased production by 40% on a per-share basis with total capital expenditures being less than funds flow (debt has been reduced by $5.5 million).
  • At the end of the quarter, there was an inventory of seven Montney horizontal wells (7.0 net) at Umbach that had not started producing.  Three horizontal wells (3.0 net) started production in the quarter, all on the same pad at the Nig land block.
  • Horizontal well performance at Umbach continues to improve as length is increased.  Wells completed in 2017 are expected to have first year average rates 30% higher than wells completed in 2014 to 2016. The first well completed in 2018 (at the Nig land block) has averaged 7.1 Mmcf per day raw plus 230 barrels per day of field condensate over the first 90 calendar days which is approximately 1,400 Boe per day sales with 26% liquids (field condensate plus plant NGL).
  • Revenue net of transportation costs was $20.82 per Boe which is an increase of 2% from last year as higher liquids pricing more than offset a 16% decrease in the natural gas price.
  • The field operating netback was $14.25 per Boe, an improvement of 17% compared to last year.  The improvement was mainly from production costs declining by 19% to $5.46 per Boe as a result of continuing production growth in addition to the prior year quarter being impacted by the maintenance turnaround at the McMahon Gas Plant.
  • Funds flow increased to $23.4 million ($13.16 per Boe) or $0.19 per share, a year-over-year increase of 90% on a per-share basis.  The improvement was largely from higher production volumes (prior year was reduced by the McMahon Gas Plant maintenance turnaround) and lower production costs on a per-Boe basis.  Compared to the previous quarter, funds flow per share was unchanged with an 18% decrease in the natural gas price being offset by higher liquids pricing, lower G&A costs and a small hedging gain.
  • Capital investment was $2.9 million which was significantly less than funds flow of $23.4 million and was less than guidance of $6.0 million as horizontal well completions were deferred due to stronger than forecast well performance. 
  • The balance sheet remains strong with debt including the working capital deficiency being $85.1 million which is a quarter-over–quarter reduction of approximately $21 million and represents 0.9 times annualized quarterly funds flow. 
  • Commodity price hedges continue to be added and currently protect approximately 48% of forecast production for the remainder of 2018.


Umbach, Northeast British Columbia

Storm’s land position at Umbach is prospective for liquids-rich natural gas from the Montney formation and currently totals 112,000 net acres (159 net sections).  During the second quarter, two sections of land were acquired in the Nig area. 

There was minimal field activity in the second quarter.  Three horizontal wells (3.0 net) started production in the quarter which left an inventory of seven horizontal wells (7.0 net) that had not started producing at the end of the quarter.   

Initial rates from the new horizontal wells at the Nig land block have been very strong.  All three wells from the first pad are now producing with the first starting production on April 10th, the second on June 3rd and the last well on June 28th (approximately 8 Mmcf per day is currently shut in to free up enough facility capacity to be able to produce all three wells).  In July, all three wells were rate restricted with production totaling 26 Mmcf per day raw gas plus 735 barrels per day of field condensate which is an average of approximately 1,680 Boe per day sales per well with 24% liquids including NGL recovered at the gas plant.  The wells at Nig are 60% longer than the average well completed in 2014 to 2016 and 20% longer than the average well completed in 2017.    

Fourteen horizontal wells (12.5 net) will be drilled this winter starting early in the fourth quarter of 2018.  Drilling will target areas where gas-condensate ratios are expected to be higher with three wells at West Umbach, six wells at Nig, two wells at South Umbach and three wells at Fireweed.  Horizontal well lengths are planned to be approximately 2,400 metres.

Since 2013, approximately $111 million has been invested in building out infrastructure (pipelines and facilities) with current field compression capacity totaling 115 Mmcf per day raw gas.  Throughput in the second quarter averaged 102 Mmcf per day raw gas.  Capacity will increase to 150 Mmcf per day in the third quarter of 2018 with the installation of an additional compressor at a cost of approximately $2 million (compressor was previously purchased and delivered to site in the first quarter of 2018).  The increased compression capacity would support growth in corporate production to approximately 27,000 Boe per day.

Storm’s produced raw natural gas is sour (approximately 1.2% H2S) with 86% directed to the McMahon Gas Plant and 14% directed to the Stoddart Gas Plant in the second quarter.  Firm processing commitments are 65 Mmcf raw gas per day at McMahon (5 to 15 year terms) and 15 Mmcf per day at Stoddart (1 year term). 

A summary of horizontal wells is provided below.  The primary focus since late 2016 has been to drill longer wells to improve rates and reserves (future wells will increase to approximately 2,400 metres long).  The majority of wells are initially rate restricted to manage fluid rates and, as a result, the IP90 and IP180 rates are not indicative of longer term performance.  More information on well performance is available in the presentation on Storm’s website.

Year of Completion Frac
Actual Drill &
Complete Cost
IP90 Cal Day
Mmcf/d Raw
IP180 Cal Day
Mmcf/d Raw
IP365 Cal Day
Mmcf/d Raw
2014 – 16
33 hz’s(1)
22 1,270 m $4.3 million
$3,400 per metre
4.9 Mmcf/d
12 hz’s
4.3 Mmcf/d
12 hz’s
3.4 Mmcf/d
12 hz’s
12 hz’s
34 1,750 m $4.2 million
$2,400 per metre
5.0 Mmcf/d
12 hz’s
4.6 Mmcf/d
11 hz’s
4.2 Mmcf/d
5 hz’s
3 hz’s
37 2,090 m $5.4 million
$2,600 per metre
7.1 Mmcf/d
1 hz
  1. 2014 wells exclude a middle Montney well (this table provides analysis of upper Montney wells only).


Commodity price hedges are used to support longer-term growth by continually layering in hedges to protect pricing on 50% of current production for the next 12 months and 25% for 13 to 24 months forward.  Anticipated production growth is not hedged.  Note that approximately 80% of Storm’s liquids production is priced in reference to WTI.  The current hedge position is summarized below and protects approximately 48% of forecast production for the second half of 2018.

2018 Q3 – Q4
Crude Oil 1,500 Bpd WTI Cdn$66.26/Bbl floor, Cdn$71.73/Bbl ceiling
Propane 300 Bpd Conway Cdn$39.55/Bbl
Natural Gas 45,500 Mmbtu/d (38,400 Mcf/d) Chicago Cdn$3.42/Mmbtu
  11,500 Mmbtu/d (9,700 Mcf/d) Sumas Cdn$2.92/Mmbtu
  3,000 GJ/d (2,400 Mcf/d) Station 2 – AECO basis -$0.345/GJ
Crude Oil 1,050 Bpd WTI Cdn$71.31/Bbl floor, Cdn$79.58/Bbl ceiling
Natural Gas


33,500 Mmbtu/d (28,300 Mcf/d) Chicago Cdn$3.25/Mmbtu
  4,500 Mmbtu/d (3,800 Mcf/d) Sumas Cdn$2.55/Mmbtu

Firm transportation capacity totals 102 Mmcf per day and provides diversification for natural gas sales and avoids overexposure to any single market.  Firm capacity on the Alliance Pipeline to Chicago totals 55 Mmcf per day with preferential interruptible capacity increasing this by 14 Mmcf per day (increasing total transportation capacity to 116 Mmcf per day sales).  Using firm capacity of 102 Mmcf per day sales, approximately 54% to 68% of natural gas will be sold at Chicago pricing, 11% at Sumas pricing less a marketing adjustment, 5% at ATP pricing, and 16% to 30% at Station 2 or AECO pricing.  During the second quarter, 69% of natural gas production was sold in Chicago.  Natural gas production exceeding firm capacity would be directed to Chicago and/or Station 2 using interruptible pipeline capacity (depending on which sales point offers a higher price net of transportation tariffs). 


For the third quarter of 2018, production is forecast to be 19,500 to 20,500 Boe per day with production to date in the third quarter averaging 20,200 Boe per day based on field estimates.  Capital investment is expected to be $25 million which includes $10 million for the sour gas plant at Nig (further details provided below). 

Storm has finalized a growth plan which will result in the construction of a 50 Mmcf per day sour gas plant to develop the Nig land block and the construction of a 50 Mmcf per day field compression facility to develop the Fireweed land block.  This is expected to result in corporate production growing to more than 30,000 Boe per day in the second half of 2020 while increasing liquids production and lowering operating costs.  In addition, installation of additional compression at Umbach in the third quarter of 2018 provides the option to further accelerate growth by completing additional standing wells if supported by commodity prices.  Further details are provided below:

  1. On the Nig land block, a 50 Mmcf per day sour gas plant will be built with start-up expected to be between October 2019 and March 2020 depending on the timing for regulatory approvals and for field construction.  The gas plant will be filled with the three existing producing wells (3.0 net) at Nig plus an additional six horizontal wells (6.0 net) will be drilled at Nig this winter and completed in 2019.  The gas plant is expected to reduce corporate operating costs by approximately $1.50 per Boe (plant operating cost $2.00 per Boe) and increase liquids production by approximately 1,100 barrels per day (90% NGL, 10% plant condensate). Total cost is estimated to be approximately $81 million which includes the facility, a horizontal acid gas disposal well and a sales gas pipeline.  Corporate production is forecast to increase from current levels to approximately 25,000 to 26,000 Boe per day with 20% liquids when the gas plant is completed and with the additional wells being drilled and completed at Nig.    
  2. In the Fireweed area, Storm has agreed to pool and jointly develop existing undeveloped lands with offsetting lands owned by a private company (no change to Storm’s net land position).  Storm is contributing 26 net sections to the pooling and will be the operator with a 50% working interest.  Preliminary planning is underway to construct a 50 Mmcf per day field compression facility with start-up expected in mid-2020 depending on timing for regulatory approvals and for field construction.  Preliminary planning also includes drilling and completing twelve horizontal wells in 2019 and 2020.  Based on offsetting well results, condensate production at Fireweed is expected to be higher than Umbach by approximately 25 barrels per Mmcf.  When the facility is completed, net forecast production additions are expected to be 4,000 to 5,000 Boe per day with 25% liquids.
  3. At Umbach, additional compression (35 Mmcf per day) will be installed in the third quarter of 2018 at a cost of approximately $2 million which will allow for the completion of standing horizontal wells to accelerate production growth if supported by the Station 2 price (greater than $1.50 to $1.75 per GJ).  The additional compression will increase sales capacity by approximately 7,000 Boe per day.

The reduction in operating costs associated with the sour gas plant at Nig is expected to mitigate the impact of commodity price volatility and low Western Canadian natural gas prices.

Incremental natural gas produced from Nig and Fireweed will be sold at Station 2.  Full cycle rates of return from both projects are expected to be very attractive at Station 2 $1.25 per GJ, WTI US$60 per barrel, and Edmonton light oil Cdn$68 per barrel (Cdn$1 = US$0.78, differential –US$7 per barrel). 

Updated guidance for 2018 is provided below with capital investment increased to $80 million (from $55 to $65 million) with approximately $14 million of the increase being directed to the sour gas plant at Nig (primarily deposits for equipment) and the remainder to accelerate drilling.  Forecast commodity prices have been updated to reflect pricing to date and the approximate forward strip for the remainder of the year.  Estimated funds flow has increased by approximately $10 million as a result of commodity prices to date being higher than initially forecast.

2018 Guidance    
May 15, 2018
August 14, 2018
Cdn$/US$ exchange rate   0.79   0.78
Chicago daily natural gas – US$/Mmbtu $2.60 $2.70
Sumas monthly natural gas – US$/Mmbtu $1.95 $2.05
AECO daily natural gas – Cdn$/GJ $1.35 $1.45
Station 2 daily natural gas – Cdn$/GJ $1.20 $1.35
WTI – US$/Bbl $64.00 $66.00
Edmonton light oil – Cdn$/Bbl $73.00 $76.00
Est revenue net of transport (excl hedges) – $/Boe $19.00 – $19.50 $20.50 – $21.50
Est operating costs – $/Boe $5.75 $5.75
Est royalty rate (% revenue before hedging) 6% – 8% 5% – 7%
Est capital investment (excl A&D) – $ million $55.0 – $65.0 $80.0
Est cash G&A  – $ million    $6.0 – $7.0 $6.0 – $7.0
   – $/Boe $0.78 – $0.95 $0.78 – $0.95
Est interest expense – $ million $4.0 $4.0
May 15, 2018
August 14, 2018
Forecast fourth quarter production – Boe/d
% liquids
20,000 – 21,000
18% liquids
20,000 – 21,000
18% liquids
Forecast annual production – Boe/d
% liquids
20,000 – 21,000
18% liquids
20,000 – 20,500
18% liquids
Est annual funds flow at 20,000 Boe/d – $ million $76.0 – $80.0 $85.0 – $90.0
Umbach horizontal wells drilled – gross
Umbach horizontal wells completed – gross
Umbach horizontal wells connected – gross
3 – 6 (3.0 – 6.0 net)
8 – 11 (8.0 – 11.0 net)
10 (10.0 net)
5 (5.0 net)
10 (10.0 net)
8 (8.0 net)

Guidance History
Station 2
($ million)
Fourth Quarter
Forecast Annual
Nov 14, 2017 $2.80 $1.30 – $1.70 $1.80 – $2.10 $55.0 – $90.0 20,000 – 27,000 20,000 – 23,000
Mar 1, 2018 $2.60 $1.05 $1.40 $55.0 – $90.0 20,000 – 27,000 20,000 – 23,000
May 15, 2018 $2.60 $1.20 $1.35 $55.0 – $65.0 20,000 – 21,000 20,000 – 21,000
Aug 14, 2018 $2.70 $1.35 $1.45 $80.0 20,000 – 21,000 20,000 – 20,500

Preliminary guidance for 2019 includes capital investment of $125 million which includes approximately $67 million for the sour gas plant at Nig and $15 million at Fireweed.  It is anticipated that a total of 10 horizontal wells will be drilled (8.5 net), 11 horizontal wells will be completed (9.0 net) and 10 horizontal wells (10.0 net) would start production.  This is expected to result in production averaging 21,000 to 23,000 Boe per day.

Capital investment required to maintain production at approximately 20,000 Boe per day is estimated to be $60 million in 2018 (versus forecast funds flow of $85 – $90 million) and $20 million in 2019.  This is likely to decrease given improved performance from the horizontal wells at the Nig land block.  

Growth will be funded with debt plus free funds flow.  The significant improvement in performance of the 2017 and 2018 horizontal wells has resulted in forecast funds flow exceeding capital investment required to maintain production and the resulting free funds flow is expected to provide most of the funding for the sour gas plant at Nig.  Using current forward strip pricing results in forecast total debt peaking at approximately 80% of the current bank credit facility in the quarter before the start-up of the sour gas plant at Nig.  If necessary, capital investment and production growth will be reduced to ensure debt does not exceed this level.

Storm’s ongoing hedging program, diversified natural gas sales and liquids production mitigate commodity price volatility.  Although natural gas prices declined from the first quarter to the second quarter of 2018, funds flow was unchanged as the price decrease was offset by gains on natural gas hedging and higher liquids prices.  In addition, Storm’s diversified natural gas sales resulted in only 13% being sold in the second quarter at Western Canadian pricing which showed the most weakness quarter over quarter with AECO declining 43% to average $1.12 per GJ and Station 2 declining 42% to average $1.05 per GJ.  Since last fall, AECO and Station 2 prices have been weak relative to US prices as supply growth in Alberta and British Columbia has exceeded contracted takeaway capacity on the TCPL/NGTL system.  The majority of Storm natural gas sales (69%) were at Chicago where the price declined by 8% quarter over quarter to average US$2.66 per Mmbtu.

With a large, multi-year drilling inventory in the Montney in an area that is liquids-rich and higher quality, Storm’s business plan continues to be focused on adding value by converting resource into debt adjusted funds flow growth on a per-share basis. 


Brian Lavergne,
President and Chief Executive Officer

August 14, 2018

Boe Presentation For the purpose of calculating unit revenues and costs, natural gas is converted to a barrel of oil equivalent (“Boe”) using six thousand cubic feet (“Mcf”) of natural gas equal to one barrel of oil unless otherwise stated. Boe may be misleading, particularly if used in isolation. A Boe conversion ratio of six Mcf to one barrel (“Bbl”) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All Boe measurements and conversions in this report are derived by converting natural gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil. Mboe means 1,000 Boe.

Non-GAAP Measures – This document may refer to the terms “debt including working capital deficiency”, “field operating netbacks”, “field operating netbacks including hedging”, the terms “cash” and “non-cash”, “cash costs”, and measurements “per commodity unit” and “per Boe” which are not recognized under Generally Accepted Accounting Principles (“GAAP”) and are regarded as non-GAAP measures. These non-GAAP measures may not be comparable to the calculation of similar amounts for other entities and readers are cautioned that use of such measures to compare enterprises may not be valid. Non-GAAP terms are used to benchmark operations against prior periods and peer group companies and are widely used by investors, analysts and other parties.  Additional information relating to certain of these non-GAAP measures can be found in Storm’s MD&A dated August 14, 2018 for the period ended June 30, 2018 which is available on Storm’s SEDAR profile at and on Storm’s website at

Initial Production Rates – Initial production rates (“IP”) provided refer to actual raw natural gas rates reported to the British Columbia government.  IP rates are not necessarily indicative of long-term performance or of ultimate recovery.

Forward-Looking Information – This press release contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words “will”, “would”, “expect”, “anticipate”, “intend”, “believe”, “plan”, “potential”, “outlook”, “forecast”, “estimate”, “budget” and similar expressions are intended to identify forward-looking statements or information. More particularly, and without limitation, this press release contains forward-looking statements and information concerning: current and future years’ guidance in respect of certain operational and financial metrics, including, but not limited to, commodity pricing, estimated average operating costs, estimated average royalty rate, estimated operations capital, estimated general and administrative costs, estimated quarterly and annual production and estimated number of Umbach, Nig and Fireweed horizontal wells drilled, completed and connected, capital investment plans, infrastructure plans, anticipated United States exports, pipeline capacity, price volatility mitigation strategy and cost reductions. Statements of “reserves” are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

The forward-looking statements and information in this press release are based on certain key expectations and assumptions made by Storm, including: prevailing commodity prices and exchange rates; applicable royalty rates and tax laws; future well production rates; reserve and resource volumes; the performance of existing wells; success to be expected in drilling new wells; the adequacy of budgeted capital expenditures to carrying out planned activities; the availability and cost of services; and the receipt, in a timely manner, of regulatory and other required approvals. Although the Company believes that the expectations and assumptions on which such forward-looking statements and information are based are reasonable, undue reliance should not be placed on these forward-looking statements and information because of their inherent uncertainty. In particular, there is no assurance that exploitation of the Company’s undeveloped lands and prospects will result in the emergence of profitable operations.

Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to the risks associated with the oil and gas industry in general such as: general economic conditions in Canada, the United States and internationally; operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to reserves, production, costs and expenses; health, safety and environmental risks; commodity price and exchange rate fluctuations; marketing and transportation of petroleum and natural gas and loss of markets; competition; ability to access sufficient capital from internal and external sources; geopolitical risk; stock market volatility; and changes in legislation, including but not limited to tax laws, royalty rates and environmental regulations.

Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect the operations or financial results of the Company are included or are incorporated by reference in the Company’s Annual Information Form dated March 29, 2018 and the MD&A dated August 14, 2018 for the period ended June 30, 2018 which are available on Storm’s SEDAR profile at and on Storm’s website at

The forward-looking statements and information contained in this press release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

For further information please contact:

Brian Lavergne
President & Chief Executive Officer

Michael J. Hearn
Chief Financial Officer

Carol Knudsen
Manager, Corporate Affairs

(403) 817-6145