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

Storm has also filed its unaudited condensed interim consolidated financial statements as at March 31, 2017 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, 2017 appears below and should be read in conjunction with the related financial statements and MD&A.


Thousands of Cdn$, except volumetric and per-share amounts Three Months Ended
March 31, 2017
Three Months Ended
March 31, 2016
Revenue from product sales(1) 37,045 16,121
Funds flow 17,958 7,855
Per share – basic and diluted ($) 0.15 0.07
Net income (loss) 20,631 (4,984 )
Per share – basic and diluted ($) 0.17 (0.04 )
Operations capital expenditures(2) 27,357 23,946
Debt including working capital deficiency(2)(3) 97,864 77,162
Common shares (000s)
Weighted average – basic 121,442 119,591
Weighted average – diluted 121,720 119,591
Outstanding end of period – basic 121,557 119,742
(Cdn$ per Boe)
Revenue from product sales 24.29 13.20
Royalties (1.88 ) (0.76 )
Production (5.84 ) (6.71 )
Transportation (0.69 ) (0.53 )
Field operating netback(2) 15.88 5.20
Realized (losses) gains on hedging (2.31 ) 3.03
General and administrative (1.10 ) (1.25 )
Interest and finance costs (0.71 ) (0.56 )
Funds flow per Boe 11.76 6.42
Barrels of oil equivalent per day (6:1) 16,947 13,418
Gas production
Thousand cubic feet per day 84,093 66,012
Price (Cdn$ per Mcf) 3.23 1.62
Condensate production
Barrels per day 1,758 1,452
Price (Cdn$ per barrel) 64.40 41.54
NGL production
Barrels per day 1,174 964
Price (Cdn$ per barrel) 23.09 10.44
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 was a record 16,947 Boe per day (17% condensate and NGL), a per-share increase of 24% from the first quarter of last year and a per-share increase of 27% from the previous quarter. The increase was the result of the start-up of a third field compression facility at Umbach on January 12, 2017 plus five new horizontal wells (5.0 net) were turned on during the quarter.
  • Condensate and NGL production increased 21% from the first quarter of last year to average 2,932 barrels per day. Revenue from liquids was 34% of total revenue.
  • Montney horizontal well performance at Umbach continues to improve as length and the number of fracs are increased. The five wells completed in 2016 with enough production history averaged 4.8 Mmcf per day gross raw gas over the first 180 calendar days, a 14% improvement from the average 2015 wells. The four wells completed to date in 2017 are approximately 25% longer and three of them have been producing for 30 to 60 days with encouraging early data.
  • Controllable cash costs (production, general and administrative, interest and finance) were $7.65 per Boe, a decrease of 10% year over year. Production costs declined by 13% from the same period in 2016 and 16% from the fourth quarter of 2016 as a result of the new processing arrangement at Umbach which started on January 1, 2017.
  • Funds flow was $18.0 million ($11.76 per Boe), an increase of 129% from a year ago. The increase was driven by an 84% increase in revenue per Boe and a 26% increase in production volumes which was partially offset by a realized hedging loss of $3.5 million or $2.31 per Boe.
  • Net income was $20.6 million or $0.17 per share which includes an unrealized mark to market hedging gain of $16.1 million. Notably, excluding the effect of the unrealized hedging gain, net income was $4.5 million, or $0.04 per share.
  • Capital investment was $27.4 million including $19.0 million to drill six horizontal wells (6.0 net) and complete four horizontal wells (4.0 net) plus $1.5 million to complete the third field compression facility at Umbach.
  • At the end of the quarter, there was an inventory of ten horizontal wells (10.0 net) that had not started producing (includes two completed wells).
  • Debt including working capital deficiency was $97.9 million which is 1.4 times annualized first quarter funds flow. Subsequent to quarter end, the bank credit facility was increased to $165.0 million from $130.0 million.
  • Commodity price hedges continue to be layered in with approximately 43% of forecast 2017 production currently hedged.


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 first quarter of 2017 was 16,582 Boe per day and liquids recovery was 36 barrels per Mmcf sales with 60% being higher priced field condensate plus pentanes recovered at the gas plant. Compared to the previous quarter, production increased by 28% while liquids recovery was the same.

During the first quarter, six horizontal wells (6.0 net) were drilled, four horizontal wells (4.0 net) were completed and five horizontal wells (5.0 net) started production. At the end of the quarter, there was an inventory of ten horizontal wells (10.0 net) that had not started producing which included two completed wells.

Activity in the second quarter of 2017 will include completing four to six horizontal wells (4.0 to 6.0 net).

Field compression totals 115 Mmcf per day raw gas after start-up of a third facility on January 12, 2017. Throughput in the first quarter averaged 88 Mmcf per day raw gas. The third facility had a final cost of $24.6 million for initial capacity of 35 Mmcf per day and will be expanded to 70 Mmcf per day by adding a second compressor for an additional $7.0 million. Preliminary timing for the expansion is the first half of 2018 and, once completed, total capacity will be 150 Mmcf per day which supports growth in corporate production to approximately 27,000 Boe per day.

Raw gas from Storm’s field compression facilities is sent to the McMahon and Stoddart Gas Plants where firm processing commitments average 75 Mmcf per day raw gas in 2017. On January 1, 2017, a new processing arrangement started at the McMahon Gas Plant which has a total commitment of 65 Mmcf per day of raw gas for 5 to 15 years and has reduced corporate production costs in the first quarter by 16% from the fourth quarter of 2016. The arrangement supports future growth with an option to increase contracted capacity and allows continued diversification of natural gas sales with access to three sales pipelines (Alliance Pipeline to Chicago, TCPL system to AECO, T-north to BC Station 2).

A summary of horizontal well performance and costs is provided below. Three of the wells completed in 2017 have started producing and have 30 to 60 days of history. The majority of wells are rate restricted when coming on production to control fluid rates and adding frac stages has increased ‘flush’ production, therefore, additional production data is required to get an indication as to longer term performance. Future horizontal wells are expected to have completed lengths of 1,700 to 2,100 metres with the newest ball drop completion systems allowing for up to 44 fracs within 4.5 inch casing.

Year of Completion Frac
Actual Drill &
Complete Cost
Cal Day
Mmcf/d Raw
Cal Day
Mmcf/d Raw
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*
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
11 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
10 hz’s
10 hz’s
25 1,300 m $3.8 million
$152 K/stage
5.1 Mmcf/d
10 hz’s
4.8 Mmcf/d
5 hz’s
4 hz’s
35 1,670 m $4.3 million
$123 K/stage

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

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 302 Boe per day in the first quarter (previous quarter averaged 310 Boe per day). Cumulative production to date from this well is 5.5 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. The WTI price is also hedged given that approximately 80% of Storm’s liquids production is priced in reference to WTI (condensate, plant pentane and butane). The hedge position is updated periodically in the presentation posted on Storm’s website. Approximately 43% of forecast 2017 production is currently hedged.

Q2 – Q4 2017 Hedges
Crude Oil 1,050 Bopd WTI Cdn$64.75/Bbl floor, Cdn$69.60/Bbl ceiling
Natural Gas 36,400 GJ/d (29,200 Mcf/d) AECO Cdn$2.68/GJ ($3.34/Mcf)
11,500 Mmbtu/d (9,700 Mcf/d) Chicago Cdn$4.17/Mmbtu ($4.94/Mcf)(1)
2018 Hedges
Crude Oil 410 Bopd WTI Cdn$65.99/Bbl floor, Cdn$70.54/Bbl ceiling
Natural Gas 750 GJ/d (600 Mcf/d) AECO Cdn$2.80/GJ ($3.50/Mcf)
18,400 Mmbtu/d (15,500 Mcf/d) Chicago Cdn$4.00/Mmbtu ($4.75/Mcf)(1)
(1) Hedge price in Chicago doesn’t include the Alliance Pipeline tariff to Chicago which was Cdn$1.66 per Mcf in the first quarter including the cost of fuel.

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

The strategy with respect to natural gas transportation commitments is to mitigate risk by diversifying sales and selling at multiple points. In the first quarter of 2017, 62% of natural gas sales were at Chicago, 32% at BC Station 2 and 6% at Alliance Transfer Point (“ATP”). Approximately 82% of forecast natural gas production in 2017 is covered by firm transportation commitments with the remainder directed to Chicago and/or BC Station 2 using interruptible pipeline capacity (sales point depends on price). Note that the cost of transportation to Chicago and ATP on the Alliance Pipeline is presented as a deduction from revenue with $7.3 million deducted from revenue in the first quarter of 2017. Further information on pipeline tariffs and price deductions is provided in the presentation on Storm’s website.

2017 Firm Transportation 2018 Firm Transportation
Alliance Pipeline(1)

51 Mmcf/d Chicago price
Alliance Pipeline(1)

55 Mmcf/d Chicago price
5 Mmcf/d ATP price 5 Mmcf/d ATP price
16 Mmcf/d BC Station 2 price
29 Mmcf/d BC Station 2 price
T-north & TCPL
13 Mmcf/d AECO price
2017 Total 72 Mmcf per day 2018 Total 102 Mmcf per day
(1) Interruptible capacity on the Alliance Pipeline adds up to 25% of contracted capacity.


On May 16, 2017, Mr. Michael Hearn will assume the role of Chief Financial Officer and will replace Mr. Donald McLean who has been associated with Storm and its predecessor companies for 17 years. Mr. Hearn is a Chartered Accountant with 14 years of experience and joined Storm on November 1, 2016 after six years with an independent energy investment bank with his last position being equity research analyst. Prior to that, Mr. Hearn was employed at a junior international producer and also spent six years at a multi-national accounting firm.

On May 16, 2017, Ms. Emily Wignes will assume the role of Vice President, Finance and will replace Mr. John Devlin who has been associated with Storm and its predecessor companies for 13 years. Ms. Wignes is a Chartered Accountant with 15 years of experience and joined Storm on December 1, 2016 after two years at an intermediate producer where her most recent position was Manager, Financial Reporting. Prior to that, Ms. Wignes was employed at other intermediate and large producers and prior thereto at a multi-national accounting firm.

Both Mr. Donald McLean and Mr. John Devlin will continue to provide advisory services on an as needed basis in the near term. Their contributions to Storm and its predecessor companies have been significant and much appreciated.


For the second quarter of 2017, production is anticipated to be 14,000 to 15,000 Boe per day which includes the effect of a maintenance turnaround at the McMahon Gas Plant which will result in approximately 75% of Storm’s production being shut in for 21 days. Note that production in April averaged approximately 18,400 Boe per day based on field estimates. Capital investment in the second quarter is expected to be approximately $13 to $18 million which includes completing four to six horizontal wells at Umbach.

Guidance for 2017 includes an increase to forecast production as a result of well performance exceeding expectations and a reduction to forecast royalty rates. As well, forecast commodity prices are updated to reflect actual first quarter pricing.

2017 Guidance Updated
November 15, 2016
March 2, 2017
May 15, 2017
$Cdn/$US exchange rate 0.77 0.77 0.75
Chicago spot natural gas (US$/Mmbtu) $3.00 $3.00 $3.00
AECO spot natural gas (Cdn$/GJ) $2.65 $2.50 $2.50
BC Stn 2 spot natural gas (Cdn$/GJ) $2.20 $2.00 $2.10
Edmonton light oil (Cdn$/bbl) $55.00 $59.00 $62.00
Estimated average operating costs ($/Boe) $5.50 – $5.75 $5.50 – $6.00 $5.50 – $6.00
Estimated average royalty rate (% production revenue before hedging) 9% – 11 % 9% – 11 % 7% – 10 %
Estimated operations capital ($ million) (excluding acquisitions & dispositions) $75.0 – $80.0 $75.0 – $80.0 $75.0 – $80.0
Estimated cash G&A
– $ million $5.3 $5.3 $5.3
– $/Boe $0.85 $0.85 $0.85
Forecast fourth quarter production (Boe/d) 18,000 – 20,000 18,000 – 20,000 19,000 – 21,000
% condensate and NGL 17 % 17 % 17 %
Forecast annual production (Boe/d) 16,500 – 18,000 16,500 – 18,000 17,000 – 18,000
% condensate and NGL 17 % 17 % 17 %
Umbach horizontal wells drilled 12 gross (12.0 net ) 12 gross (12.0 net ) 12 gross (12.0 net )
Umbach horizontal wells completed 14 gross (14.0 net ) 14 gross (14.0 net ) 14 gross (14.0 net )
Umbach horizontal wells connected 15 gross (15.0 net ) 15 gross (15.0 net ) 15 gross (15.0 net )

2017 Guidance History

BC 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

There is flexibility to adjust 2017 capital investment depending on commodity prices and funds flow which may affect forecast production. The current hedge position will provide some cushion in the event of a material decline in commodity prices. Note that some cost inflation is expected based on 2017 first quarter results and capital investment assumes the cost to drill and complete a horizontal well at Umbach is $4.3 million, an increase of 13% from the 2016 actual cost.

The outlook for natural gas prices remains positive as a result of a growing supply/demand deficit in the United States. Data from the Energy Information Administration (“EIA”) shows 2016 demand (consumption) exceeded supply (dry gas production plus net imports) by 0.9 Bcf per day. So far in 2017, January and February supply is 1.1 Bcf per day lower than the 2016 average which further widens the deficit. Longer term, demand continues to increase as a result of five LNG export facilities currently operating or under construction on the US Gulf Coast. In addition, US pipeline capacity to Mexico is expected to increase by more than 6 Bcf per day by the end of 2018 from six new pipelines.

Most of Storm’s firm transportation commitments have been added over the last two years with the intent of reducing risk by diversifying natural gas sales (not betting for or against pricing in any single market). A good example supporting the diversification of sales is the continued narrowing of the AECO – BC Station 2 price differential which is contrary to the consensus view that the differential would widen with continued production growth from northeast British Columbia (“NE BC”). Since late 2015, the differential has narrowed to average -$0.19 per GJ in the first quarter of 2017 versus -$0.41 per GJ in 2016 and -$0.85 per GJ in 2015. Although production growth has continued, the differential has not been impacted as most of the growth has been directed onto the TCPL system to AECO (the differential can be temporarily affected by outages and/or constraints on the TCPL system or Alliance Pipeline where more natural gas is redirected to BC Station 2). Also helping was the Alliance Pipeline re-contracting in late 2015 where most of the capacity was taken up by producers instead of marketers. TCPL is planning to further increase capacity out of NE BC with the North Montney extension which adds 1.5 Bcf per day of takeaway in early 2019 if a variance application is approved by the National Energy Board (“NEB”). It is unlikely that production can grow this much over the next two years, so some of the incremental volume for this expansion is likely to be sourced from natural gas redirected away from BC Station 2 which further supports a narrower differential. In the first quarter of 2017, approximately 32% of Storm’s natural gas sales benefitted from the narrowing differential.

There continues to be an effort directed toward reducing Storm’s cost structure to improve competitiveness in the continuing lower price environment. Production costs per Boe have decreased by 16% from the fourth quarter of 2016 with the new processing arrangement at Umbach. Further reductions in per-Boe costs are expected with continued production growth at Umbach. Reserve addition costs are being reduced with longer horizontal wells that access more gas in place plus adding fracs on tighter spacing is increasing recovery. Recent results from longer 2017 wells are encouraging and further improvement is expected as longer wells are drilled and brought on production.

Current commodity prices are supportive of the near-term plan to grow average 2017 production by more than 30% from 2016 levels by investing $75 to $80 million which will result in year-end net debt of approximately $95 to $100 million, a year-over-year increase of 5% to 10%. The preliminary plan for 2018 is for a further 25% to 35% increase in production volumes. Growth in 2017 and 2018 is further supported by firm transportation commitments, hedging and the infrastructure at Umbach which supports growth to 27,000 Boe per day (after adding a second compressor at the third field compression facility).

With a large 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

May 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 contains 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. These measurements are also used by lenders to measure compliance with debt covenants and thus set interest costs. Additional information relating to certain of these non-GAAP measures can be found in Storm’s MD&A for the three months ended March 31, 2017, which is available on Storm’s SEDAR profile at and on Storm’s website at

Oil and Gas Metrics – This press release may contain a number of oil and gas metrics, including FD&A, recycle ratio, FDC, and reserves life index or RLI, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics have been included herein to provide readers with additional measures to evaluate the Company’s performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods.

Initial Production Rates – References in this press release to initial production rates, and other short-term production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. Additionally, such rates may also include recovered “load oil” fluids used in well completion stimulation. Readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, the Company cautions that the test results should be considered to be preliminary.

DPIIP – Original Oil in Place (OOIP) is the equivalent to Discovered Petroleum Initially In Place (DPIIP) for the purposes of this press release. DPIIP is defined as quantity of hydrocarbons that are estimated to be in place within a known accumulation. There is no certainty that it will be commercially viable to produce any portion of the resources. A recovery project cannot be defined for this volume of DPIIP at this time, and as such it cannot be further sub-categorized.

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: production; drilling and completion plans; the third field compression facility and expansion plans in connection therewith; the January 2017 transportation arrangement; hedging; transportation; organizational and personnel changes; 2017 and 2018 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:

Storm Resources Ltd.
Brian Lavergne
President & Chief Executive Officer
(403) 817-6145

Storm Resources Ltd.
Carol Knudsen
Manager, Corporate Affairs
(403) 817-6145