CALGARY, Alberta, May 15, 2018 (GLOBE NEWSWIRE) — Storm Resources Ltd. (TSX:SRX)

Storm has also filed its unaudited condensed interim consolidated financial statements as at March 31, 2018 and for the three 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 months ended March 31, 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 Ended
March 31, 2018
  Three Months Ended
March 31, 2017

Revenue from product sales(1)   52,102   44,392  
Funds flow   23,519   17,958  
Per share – basic and diluted ($)   0.19   0.15  
Net income   8,894   20,631  
Per share – basic and diluted ($)   0.07   0.17  
Operations capital expenditures(2)   22,900   27,357  
Debt including working capital deficiency(2)(3)   105,585   97,864  
Common shares (000s)          
Weighted average – basic   121,557   121,442  
Weighted average – diluted   121,557   121,720  
Outstanding end of period – basic   121,557   121,557  

(Cdn$ per Boe)          
Revenue from product sales(1)   29.37   29.10  
Transportation costs   (5.59 ) (5.50 )
Revenue net of transportation   23.78   23.60  
Royalties   (1.71 ) (1.88 )
Production costs   (5.55 ) (5.84 )
Field operating netback(2)   16.52   15.88  
Realized loss on hedging   (1.19 ) (2.31 )
General and administrative   (1.42 ) (1.10 )
Interest and finance costs   (0.64 ) (0.71 )
Funds flow per Boe   13.27   11.76  

Barrels of oil equivalent per day (6:1)

  19,708   16,947  
Natural gas production          
Thousand cubic feet per day   96,068   84,093  
Price (Cdn$ per Mcf)(1)   3.83   4.20  
Condensate production          
Barrels per day   2,062   1,758  
Price (Cdn$ per barrel)(1)   76.12   64.40  
NGL production          
Barrels per day   1,635   1,174  
Price (Cdn$ per barrel)(1)   33.05   23.09  
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 27 of the MD&A.
  3. Excludes the fair value of commodity price contracts.



  • Production increased by 16% on a per-share basis from the prior year to 19,708 Boe per day and was consistent with guidance (19,500 to 20,500 Boe per day).  Compared to the previous quarter, production increased by 10% on a per-share basis.
  • Liquids production (condensate plus NGL) grew by 26% year over year (versus 14% growth for natural gas) with liquids representing 19% of total production and 36% of production revenue.
  • At the end of the quarter, there was an inventory of 10 Montney horizontal wells (10.0 net) at Umbach that had not started producing which includes three completed wells.  Two horizontal wells (2.0 net) started production in the quarter.
  • Horizontal well performance at Umbach continues to improve as length is increased.  Compared to wells completed in 2014 to 2016, the wells completed in 2017 are 35% longer (1,750 metres versus 1,300 metres), declines have been flatter, and first year average rates are expected to be more than 15% higher based on production history to date.
  • A pad with three horizontal wells was completed on the Nig land block in the first quarter with lengths averaging 2,090 metres.  The first well started production on April 10th and has averaged 7.3 Mmcf per day raw gas plus 252 barrels per day of field condensate over the first 30 calendar days of production based on field estimates (approximately 1,480 Boe per day sales including 26% liquids).  Consistent with other new wells, the rate on this well has been restricted to manage initial fluid volumes.  
  • Revenue net of transportation costs was $23.78 per Boe which is an increase of 1% from last year as higher liquids pricing offset a 9% decrease in the natural gas price.
  • The operating netback was $16.52 per Boe, an improvement of 4% compared to last year with production costs declining by 5% to $5.55 per Boe as a result of continuing production growth. 
  • Funds flow increased to $23.5 million, or $13.27 per Boe, and was the highest quarterly funds flow achieved since inception.  On a per-share basis, funds flow increased to $0.19 per share which is a year-over-year increase of 27%.  The improvement was largely the result of increased production volumes.    
  • Net income was $8.9 million or $0.07 per share which is a decrease from $20.6 million last year.  The decrease was largely the result of an $18.2 million change in the unrealized gain (loss) on hedges which is a non-cash expense and represents the change in the fair market value of future hedges.
  • Capital investment was $22.9 million which was less than funds flow and was consistent with guidance ($23.0 million).  Investment included $8.9 million to complete a three well pad on the Nig land block and $12.8 million to expand infrastructure at Umbach (12-kilometre gathering pipeline to Nig plus purchase an additional compressor).
  • The balance sheet remains strong with debt including the working capital deficiency being $105.6 million which was 1.1 times annualized first quarter funds flow.  Subsequent to quarter end, the bank credit facility was increased to $180 million from $165 million.
  • Commodity price hedges continue to be added and currently protect approximately 47% 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 111,000 net acres (157 net sections).  During the first quarter, two sections of land were purchased at Crown land sales.  To date, Storm has drilled 69 horizontal wells (65.4 net).

Field activity in the first quarter included completing the first three horizontal wells (3.0 net) on the Nig land block and constructing a 12-kilometre gathering pipeline to connect the Nig wells back to the field compression facility. Two horizontal wells (2.0 net) started production in the quarter which left an inventory of 10 horizontal wells (10.0 net) that had not started producing at the end of the quarter including three completed wells.   

Preliminary indications from the wells at Nig are encouraging.  One well has started production with the rate being restricted to average 7.3 Mmcf per day raw gas plus 252 barrels per day of free condensate over the first 30 calendar days since start-up on April 10th (approximately 1,480 Boe per day sales including 26% liquids). The remaining two wells will start production over the next three months.  The wells at Nig have average completed lengths of 2,090 metres which is 60% longer than the average well completed in 2014 to 2016 and 20% longer than the average well completed in 2017. 

Drilling in the second half of 2018 is expected to be focused on the Nig land block or at South Umbach where condensate-gas ratios are higher.  In addition, horizontal well lengths will be further increased to approximately 2,400 metres.

Since 2013, approximately $111.0 million has been invested in building out infrastructure (pipelines and facilities) with current capacity totaling 115 Mmcf per day raw gas from three field compression facilities.  Throughput in the first quarter averaged 102 Mmcf per day raw gas.  Capacity can be increased to 150 Mmcf per day with the installation of an additional compressor which was purchased and moved to site in the first quarter of 2018 at a cost of $4.7 million (requires additional $2.0 million for installation).  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 in the first quarter and 14% directed to the Stoddart Gas Plant.  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 improve rates and reserves by drilling longer wells (future wells will be 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 may not be indicative of longer term performance.  More information on well performance is available in the presentation on Storm’s website.

Year of
Actual Drill &
Complete Cost
IP90 Cal Day
Mmcf/d Raw
IP180 Cal Day 
Mmcf/d Raw
IP365 Cal Day
Mmcf/d Raw
12 hz’s(1)
19 1,170 m $4.6 million
$3,950 per metre
4.9 Mmcf/d
12 hz’s
4.4 Mmcf/d
12 hz’s
3.5 Mmcf/d
12 hz’s
11 hz’s
22 1,360 m $4.5 million
$3,300 per metre
4.7 Mmcf/d
11 hz’s
4.2 Mmcf/d
11 hz’s
3.3 Mmcf/d
11 hz’s
10 hz’s
25  1,300 m $3.7 million
$2,850 per metre
5.1 Mmcf/d
10 hz’s
4.2 Mmcf/d
10 hz’s
3.5 Mmcf/d
10 hz’s
12 hz’s
34 1,750 m $4.2 million
$2,400 per metre
5.0 Mmcf/d
11 hz’s
4.4 Mmcf/d
8 hz’s
3.9 Mmcf/d
3 hz’s
3 hz’s
37 2,090 m $5.4 million
$2,580 per metre
  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 47% of forecast production for 2018.

2018 Q2 – Q4
Crude Oil 1,500 Bpd WTI Cdn$65.78/Bbl floor, Cdn$70.64/Bbl ceiling
Propane 300 Bpd Conway Cdn$39.55/Bbl
Natural Gas 44,100 Mmbtu/d (37,200 Mcf/d) Chicago Cdn$3.60/Mmbtu(1)
  9,000 Mmbtu/d (7,600 Mcf/d) Sumas Cdn$3.02/Mmbtu
3,000 GJ/d (2,400 Mcf/d) Station 2 – AECO basis -$0.345/GJ
Crude Oil 700 Bpd WTI Cdn$68.81/Bbl floor, Cdn$75.34/Bbl ceiling
Natural Gas 24,300 Mmbtu/d (20,500 Mcf/d) Chicago Cdn$3.25/Mmbtu(1)
  1. The Alliance Pipeline tariff to Chicago is approximately Cdn$1.20 per Mmbtu including the cost of fuel.

Total firm transportation capacity increased to 102 Mmcf per day in April 2018 with the addition of 13 Mmcf per day of capacity to AECO.  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 first quarter, 64% 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 second quarter of 2018, production is forecast to be 19,500 to 20,500 Boe per day with production to date in the second quarter averaging 20,200 Boe per day based on field estimates.  Capital investment is expected to be $6.0 million which is forecast to be less than funds flow using forecast commodity prices and will result in debt being reduced by approximately $15.0 million.

Updated guidance for 2018 is provided in the table below.  Forecast commodity prices have been updated to reflect pricing to date and the approximate forward strip for the remainder of the year (changes daily).  Capital investment has been reduced to the lower end of what was provided in previous guidance given that any incremental growth in natural gas production would be sold at Station 2 and the natural gas price at Station 2 remains below what is required to justify growing production.  A Station 2 price greater than $1.50 to $1.75 per GJ is required to provide reasonable full-cycle rates of return and justify growth. Forecast production is based on a 7.5 Bcf type curve for future horizontal wells at Umbach.

2018 Guidance    
March 1, 2018
May 15, 2018
Cdn$/US$ exchange rate   0.80   0.79
Chicago daily natural gas – US$/Mmbtu $ 2.60 $ 2.60
Sumas monthly natural gas – US$/Mmbtu $ 1.90 $ 1.95
AECO daily natural gas – Cdn$/GJ $ 1.40 $ 1.35
Station 2 daily natural gas – Cdn$/GJ $ 1.05 $ 1.20
WTI – US$/Bbl $ 56.00 $ 64.00
Edmonton light oil – Cdn$/Bbl $ 64.00 $ 73.00
Est revenue net of transport (excl hedges) – $/Boe $ 17.00 – $18.50 $ 19.00 – $19.50
Est operating costs – $/Boe $ 5.75 $ 5.75
Est royalty rate (% revenue before hedging) 6% – 8% 6% – 8%
Est operations capital investment (excl A&D) – $ million $ 55.0 – $90.0 $ 55.0 – $65.0
Est cash G&A  – $ million  $ 6.0 – $7.0 $ 6.0 – $7.0
   – $/Boe $ 0.70 – $0.95 $ 0.78 – $0.95
Est interest expense – $ million $4.5 – $5.5 $ 4.0
Forecast fourth quarter production – Boe/d
% liquids
20,000 – 27,000
18% liquids
20,000 – 21,000
18% liquids
Forecast annual production – Boe/d
% liquids
20,000 – 23,000
18% liquids
20,000 – 21,000
18% liquids
Est annual funds flow at 20,000 Boe/d – $ million $ 70.0 – $78.0 $ 76.0 – $80.0
Umbach horizontal wells drilled – gross
Umbach horizontal wells completed – gross
Umbach horizontal wells connected – gross
3 – 12 (3.0 – 12.0 net)
11 – 17 (11.0 – 17.0 net)
11 – 16 (11.0 – 16.0 net)
3 – 6 (3.0 – 6.0 net)
8 – 11 (8 – 11.0 net)
10 (10.0 net)

Guidance History

Station 2
Estimated Operations
($ 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

Although Western Canadian natural gas prices were reasonably strong in the first quarter, second quarter prices have weakened with recent maintenance restrictions on TCPL’s NGTL system and Enbridge’s T-south pipeline that have restricted exports from Western Canada.  Daily prices to date in the second quarter have averaged $1.07 per GJ at AECO and $1.11 per GJ at Station 2 (versus $1.97 per GJ and $1.81 per GJ respectively in the first quarter).  The effect of the maintenance restrictions has been exacerbated by year-over-year production growth of approximately 1.0 Bcf per day.  Production is likely to decline at current prices given the reduction in the gas directed rig count and the reduced level of capital investment announced by several larger gas weighted producers.  However, without production declines, it is going to be a volatile summer for Western Canadian natural gas prices given additional maintenance restrictions planned by both TCPL and Enbridge through to the end of September.  The impact on Storm will be partially mitigated by increasing liquids production and with diversified natural gas sales where 65% to 79% of forecast production is being sold in the US at Chicago and Sumas. 

Natural gas prices in the US have been stable with the Chicago daily price averaging US$2.95 per Mmbtu in the first quarter and US$2.73 per Mmbtu to date in the second quarter.  Data from the US EIA for the first two months of 2018 shows a large year-over-year increase in demand for natural gas at 13.1 Bcf per day (majority from electric power generation and residential) plus net exports have increased by 0.9 Bcf per day year-over-year.  The growth in demand has more than offset year-over-year growth in dry gas production which has been a robust 7.0 Bcf per day.  This has resulted in a steep decline in natural gas storage levels which are 863 Bcf below last year for the week ended May 4th.  Over the summer, demand for natural gas to refill storage is likely to be supportive of US natural gas prices.   

For 2018, production is expected to remain at 20,000 to 21,000 Boe per day unless there is an improvement in the natural gas price at Station 2.  This represents year-over-year production growth of 25%.  Production can be increased relatively quickly given the current inventory of standing wells and existing field compression capacity at Umbach which supports growth to 27,000 Boe per day.  Planning for 2019 is underway with the focus being to continue growing production and funds flow by increasing liquids production.

With a large, multi-year drilling inventory in the higher quality and liquids-rich Montney formation at Umbach, 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

May 15, 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 May 15, 2018 for the period ended March 31, 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 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 May 15, 2018 for the period ended March 31, 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