CALGARY, ALBERTA–(Marketwired – Aug. 15, 2017) – Storm Resources Ltd. (TSX VENTURE:SRX)

Storm has also filed its unaudited condensed interim consolidated financial statements as at June 30, 2017 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, 2017 appears below and should be read in conjunction with the related financial statements and MD&A.


Thousands of Cdn$, except volumetric and
per-share amounts
Three Months to
June 30, 2017
Three Months to
June 30, 2016
Six Months to June 30, 2017 Six Months to
June 30, 2016
Revenue from product sales(1) 27,317 13,870 64,362 29,992
Funds flow 11,629 5,781 29,587 13,636
Per share – basic and diluted ($) 0.10 0.05 0.24 0.11
Net income (loss) 9,752 (20,493 ) 30,383 (25,477 )
Per share – basic and diluted ($) 0.08 (0.17 ) 0.25 (0.21 )
Operations capital expenditures(2) 4,307 613 31,664 24,559
Debt including working capital deficiency(2)(3) 90,582 71,254 90,582 71,254
Common shares (000s)
Weighted average – basic 121,557 119,929 121,500 119,761
Weighted average – diluted 121,682 119,929 121,702 119,761
Outstanding end of period – basic 121,557 120,179 121,557 120,179
(Cdn$ per Boe)
Revenue from product sales(1) 21.45 11.86 23.00 12.55
Royalties (1.47 ) (0.19 ) (1.69 ) (0.48 )
Production (6.74 ) (6.76 ) (6.25 ) (6.73 )
Transportation (1.08 ) (0.33 ) (0.86 ) (0.43 )
Field operating netback(2) 12.16 4.58 14.20 4.91
Realized (loss) gain on hedging (1.10 ) 2.24 (1.76 ) 2.64
General and administrative (1.17 ) (1.19 ) (1.13 ) (1.22 )
Interest and finance costs (0.76 ) (0.68 ) (0.73 ) (0.62 )
Funds flow per Boe 9.13 4.95 10.58 5.71
Barrels of oil equivalent per day (6:1) 13,991 12,852 15,461 13,135
Natural gas production
Thousand cubic feet per day 68,308 63,800 76,157 64,906
Price (Cdn$ per Mcf)(1) 2.81 1.28 3.04 1.45
Condensate production
Barrels per day 1,468 1,172 1,612 1,312
Price (Cdn$ per barrel)(1) 57.65 50.05 61.31 45.34
NGL production
Barrels per day 1,138 1,047 1,156 1,006
Price (Cdn$ per barrel)(1) 20.45 11.63 21.78 11.06
Wells drilled (100% working interest) 6.0 7.0
Wells completed (100% working interest) 4.0 2.0
(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 25 of the MD&A.
(3) Excludes the fair value of commodity price contracts.



  • Production averaged 13,991 Boe per day, a per-share increase of 8% from the second quarter of last year. The year-over-year increase was achieved in spite of approximately 80% of production being shut in for 25 days in June for a planned maintenance turnaround at the McMahon Gas Plant (April and May averaged 18,306 Boe per day).
  • Condensate and NGL production totaled 2,606 barrels per day which was 19% of total production and represented 36% of total revenue.
  • At the end of the quarter, there was an inventory of nine Montney horizontal wells (9.0 net) at Umbach that had not started producing which includes one completed well. One horizontal well (1.0 net) started production in the quarter and six horizontal wells (6.0 net) started production in the first half of the year.
  • To date in 2017, four Montney horizontal wells (4.0 net) have been completed and the three with enough production history have averaged 4.8 Mmcf per day gross raw gas plus 175 barrels per day of field condensate, or 960 Boe per day sales, over the first 90 calendar days (only 75 producing days as a result of the McMahon Gas Plant turnaround). These wells are approximately 25% longer than wells completed during 2014 to 2016 and are further south in the oil window which increases the field condensate rate (115% higher than the average from all of Storm’s wells at Umbach).
  • Controllable cash costs (production, general and administrative, interest and finance) were $8.67 per Boe which is an increase from $7.65 per Boe in the prior quarter. The increase is primarily due to production being reduced by the scheduled maintenance turnaround at the McMahon Gas Plant which increased production costs by $0.90 per Boe. Costs are expected to resume trending lower in the second half of 2017.
  • Funds flow was $11.6 million ($9.13 per Boe), an increase of 100% from a year ago. The increase was driven by an 81% increase in revenue per Boe and a 9% increase in production volumes which was partially offset by a realized hedging loss of $1.4 million, or $1.10 per Boe.
  • Net income was $9.8 million or $0.08 per share which includes an unrealized hedging gain of $9.5 million (mark to market non-cash gain). Hedging continues to have a significant recurring impact on quarterly earnings. Excluding the unrealized and realized hedging gains or losses, net income would be $1.7 million, or $0.01 per share.
  • Capital investment was $4.3 million with most of this being invested in infrastructure at Umbach (pipelined and equipped a second water disposal well and added a second fuel gas conditioning unit). This was less than the original forecast of $13 to $18 million as the planned completions of four to six wells were delayed by spring road bans being extended into mid-July.
  • Debt including working capital deficiency was reduced to $90.6 million from $97.9 million at the end of the prior quarter. This is 1.9 times annualized second quarter funds flow, an increase from 1.4 times at the end of the previous quarter as a result of production and funds flow being reduced by the McMahon Gas Plant turnaround. The bank credit facility is $165 million.
  • Commodity price hedges continue to be added and currently protect approximately 45% of forecast production for the second half of 2017.


Umbach, Northeast British Columbia

Storm’s land position at Umbach is prospective for liquids-rich natural gas from the Montney formation and currently totals 109,000 net acres (155 net sections). To date, Storm has drilled 59 horizontal wells (55.4 net).

Production in the second quarter was 13,703 Boe per day and liquids recovery was 39 barrels per Mmcf sales with 56% being higher priced condensate.

Activity in the second quarter included pipelining and equipping a second water disposal well and adding a second fuel gas conditioning unit which is required for the future expansion of the third field compression facility. One horizontal well (1.0 net) started production. At the end of the quarter, there was an inventory of nine horizontal wells (9.0 net) that had not started producing which included one completed well.

There are three field compression facilities with current capacity totaling 115 Mmcf per day raw gas and throughput in the second quarter averaged 69 Mmcf per day raw gas (92 Mmcf per day in April and May). Capacity at the third facility can be increased by 35 Mmcf per day by adding a second compressor for $7 million. Delivery of the second compressor is scheduled for the fourth quarter of 2017 with installation planned for the first half of 2018, possibly as early as January depending on commodity prices and well results. This increases total field compression to 150 Mmcf per day and supports growth in corporate production to approximately 27,000 Boe per day.

Storm’s produced natural gas is sour (approximately 1.2% H2S) and is directed to the McMahon and Stoddart Gas Plants where firm processing commitments total 80 Mmcf per day raw gas for the second half of 2017. At the McMahon Gas Plant, a new processing arrangement began in January 2017 and has a commitment totaling 65 Mmcf per day of raw gas for 5 to 15 years. The arrangement reduced corporate production costs by approximately 15%, supports future growth with an option to add up to 35 Mmcf per day, and provides access to three sales pipelines. Most importantly, the arrangement will result in accelerated corporate growth as more capital can be directed to drilling and completing horizontal wells which offer a higher rate of return than building a sour gas plant.

A summary of horizontal well performance and costs is provided below. Calendar day rates for the 2016 and 2017 horizontal wells were reduced by the McMahon Gas Plant turnaround from June 5 to July 14. For example, the three 2017 wells produced for an average of 75 days out of the first 90 calendar days. Future horizontal wells will have completed lengths of 1,700 to 2,100 metres with 30 to 36 frac stages and the increased length is expected to improve production rates.

Year of
Actual Drill & Complete Cost IP90 Cal Day
Mmcf/d Raw
IP180 Cal Day
Mmcf/d Raw
IP365 Cal Day
Mmcf/d Raw
6 hz’s
17 1,190 m $4.6 million
$270 K/stage
3.5 Mmcf/d
6 hz’s
2.9 Mmcf/d
6 hz’s
2.2 Mmcf/d
6 hz’s
12 hz’s(1)
19 1,170 m $4.6 million
$240 K/stage
4.9 Mmcf/d
12 hz’s
4.4 Mmcf/d
12 hz’s
3.5 Mmcf/d
12 hz’s
22 1,360 m $4.4 million
$200 K/stage
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
$148 K/stage
5.1 Mmcf/d
10 hz’s
4.2 Mmcf/d
10 hz’s
3.7 Mmcf/d
2 hz’s
4 hz’s
35 1,670 m $4.3 million
$123 K/stage
4.8 Mmcf/d(2)

3 hz’s
(1) 2014 wells exclude a middle Montney well (this table provides analysis of upper Montney wells only).
(2) Wells produced for an average of 75 days due to the McMahon maintenance turnaround June 5 to July 14.

Horn River Basin, Northeast British Columbia

Storm has a 100% working interest in 119 sections in the Horn River Basin (78,000 net acres) which are prospective for natural gas from the Muskwa, Otter Park and Evie/Klua shales. Storm’s one horizontal well averaged 230 Boe per day in the second quarter and cumulative production to date from this well is 5.7 Bcf raw.


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. Note that WTI is hedged as approximately 80% of Storm’s liquids production is priced in reference to WTI. The current hedge position is summarized below and approximately 45% of forecast production for the second half of 2017 is currently hedged.

Q3 – Q4 2017
Crude Oil 1,200 Bopd WTI Cdn$65.19/Bbl floor, Cdn$69.90/Bbl ceiling
Natural Gas 38,000 GJ/d (30,400 Mcf/d) AECO Cdn$2.70/GJ ($3.37/Mcf)
12,800 Mmbtu/d (10,800 Mcf/d) Chicago Cdn$4.17/Mmbtu ($4.94/Mcf)(1)
Crude Oil 512 Bopd WTI Cdn$66.45/Bbl floor, Cdn$70.11/Bbl ceiling
Natural Gas 750 GJ/d (600 Mcf/d) AECO Cdn$2.80/GJ ($3.50/Mcf)
18,425 Mmbtu/d (15,600 Mcf/d) Chicago Cdn$4.01/Mmbtu ($4.75/Mcf)(1)
2,000 Mmbtu/d (1,700 Mcf/d) Chicago US$2.98/Mmbtu
(1) Hedge price in Chicago does not include the Alliance Pipeline tariff to Chicago which is approximately Cdn$1.35 per GJ including the cost of fuel.

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

Firm transportation commitments are used to diversify sales points and mitigate pricing risk. Firm transportation totals 72 Mmcf per day in 2017 and increases to 102 Mmcf per day in 2018. In addition, preferential interruptible capacity on the Alliance Pipeline adds up to 14 Mmcf per day in 2017 and up to 15 Mmcf per day in 2018. Natural gas production exceeding firm commitments is directed to Chicago and/or Station 2 using interruptible pipeline capacity (sales point depends on price). Note that Storm’s natural gas marketing arrangements result in the cost of transportation on the Alliance Pipeline being deducted from revenue ($5.7 million deducted in the second quarter of 2017). Further information on pipeline tariffs and price deductions is provided in the presentation on Storm’s website.

2017 2018
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
Enbridge T-North
16 Mmcf/d Station 2 price
Enbridge T-North
29 Mmcf/d Station 2 price
Enbridge T-North & TCPL NGTL
13 Mmcf/d AECO price
(1) Interruptible capacity on the Alliance Pipeline adds up to 25% of contracted capacity.


For the third quarter of 2017, production is anticipated to be 15,500 to 17,000 Boe per day which includes the effect of the maintenance turnaround at the McMahon Gas Plant from June 5 to July 14. Approximately 80% of production was shut in for 14 days in the third quarter. The duration of the turnaround was 39 days which was longer than the original expectation of 21 days. Capital investment in the third quarter is expected to be $28 million and includes drilling four horizontal wells plus completing six horizontal wells at Umbach.

The third quarter has seen Western Canadian natural gas prices weaken as a result of continued production growth and maintenance restrictions on the TCPL NGTL system and the Enbridge T-South pipeline. To date in the third quarter, AECO daily has averaged $1.59 per GJ (versus $2.64 per GJ in the second quarter) while Station 2 daily has averaged $1.06 per GJ (versus $2.21 per GJ in the second quarter). The weakness is likely to continue until September for AECO and October for Station 2 when the maintenance restrictions are expected to end. Based on field estimates, Storm’s production in July was 12,200 Boe per day and to date in August has averaged 17,300 Boe per day. Until the Station 2 price improves, production will not be increased and volumes sold at Station 2 will be minimized to meet firm transportation commitments. Approximately 20% of current natural gas sales are at Station 2.

Updated guidance for 2017 is summarized below. Operations capital is forecast to be $75 to $95 million (previously $75 to $80 million) depending on both well results and commodity prices meeting Storm’s forecast for the second half of 2017. Capital investment at the high end of the range ($95 million) would accelerate growth in 2018 by drilling and completing additional wells in the fourth quarter of 2017 (minimal impact on forecast production for 2017). This includes installing a second compressor at the third Umbach facility in January 2018. Should commodity prices be lower than forecast, capital investment would be reduced to the low end of the range ($75 million) by deferring the additional activity. Forecast commodity prices reflect actual year-to-date pricing plus the approximate forward strip for the remainder of 2017.

2017 Guidance

May 15, 2017 Updated
August 15, 2017
$Cdn/$US exchange rate 0.75 0.775
Chicago daily natural gas (US$/Mmbtu) $3.00 $2.90
AECO daily natural gas (Cdn$/GJ) $2.50 $2.45
Station 2 daily natural gas (Cdn$/GJ) $2.10 $2.00
Edmonton light oil (Cdn$/bbl) $62.00 $60.00
Estimated average operating costs ($/Boe) $5.50 – $6.00 $5.75 – $6.00
Estimated average royalty rate
(% production revenue before hedging)
7% – 10% 6% – 8%
Estimated operations capital ($ million)
(excluding acquisitions & dispositions)
$75.0 – $80.0 $75.0 – $95.0
Estimated cash G&A – $ million $5.3 $6.0 – $6.5
– $/Boe $0.85 $0.95 – $1.05
Forecast fourth quarter production (Boe/d)
% condensate and NGL
19,000 – 21,000
19,000 – 21,000
Forecast annual production (Boe/d)
% condensate and NGL
17,000 – 18,000
16,500 – 18,000
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 – 15 gross (12.0 – 15.0 net)
10 – 16 gross (10.0 – 16.0 net)
13 – 16 gross (13.0 – 16.0 net)

2017 Guidance History

Station 2
($ million)
Fourth Quarter
Forecast Annual
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
August 15, 2017 $2.90 $2.00 $2.45 $75.0 – $95.0 19,000 – 21,000 16,500 – 18,000

Capital investment assumes the cost to drill and complete a horizontal well at Umbach is $4.7 million, an increase of 27% from the actual cost in 2016 with half of the increase from adding length and frac stages and half of the increase as a result of service cost inflation.

Planned growth through 2018 is supported by forecast commodity prices as well as the expected improvement in rates, reserves, and capital efficiencies from future Montney horizontal wells at Umbach which are planned to be approximately 50% longer than the 2014 to 2016 wells. In 2017, average production is forecast to increase by approximately 30% year over year by investing $75 to $95 million which will result in year-end net debt of approximately $100 to $120 million. For 2018, assuming commodity prices are approximately equal to forecast prices for 2017, the preliminary plan is to invest $95 to $110 million for a further 30% to 40% increase in production with forecast fourth quarter production of 25,000 to 27,000 Boe per day. Growth in 2018 requires an investment of $7 million in infrastructure at Umbach to add field compression which is planned for as early as January 2018 and can also be delayed depending on commodity prices.

Although the upper end of the range for capital investment was increased to provide the option to accelerate growth in expectation of improving well results, growth will not be accelerated to the detriment of the balance sheet. Correspondingly, capital investment has been designed to be flexible and activity can be adjusted quickly in response to changes in commodity prices.

With a large liquids-rich 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.


Brian Lavergne,
President and Chief Executive Officer

August 15, 2017

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 most recent MD&A 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 and the MD&A.

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.


Contact Information:

Brian Lavergne
President & Chief Executive Officer

Michael J. Hearn
Chief Financial Officer

Carol Knudsen
Manager, Corporate Affairs

(403) 817-6145