CALGARY, Alberta, March 01, 2018 (GLOBE NEWSWIRE) — Storm Resources Ltd. (TSX:SRX)
Storm has also filed its audited consolidated financial statements as at December 31, 2017 and for the three months and year then ended along with Management’s Discussion and Analysis (“MD&A”) for the same periods. This information appears on SEDAR at www.sedar.com and on Storm’s website at www.stormresourcesltd.com.
Selected financial and operating information for the three months and year ended December 31, 2017, as well as reserves information at December 31, 2017, appears below and should be read in conjunction with the related financial statements and MD&A.
Highlights
Thousands of Cdn$, except volumetric and per-share amounts |
Three Months to Dec. 31, 2017 |
Three Months to Dec.31, 2016 |
Year Ended Dec. 31, 2017 |
Year Ended Dec. 31, 2016 |
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FINANCIAL |
|||||||||
Revenue from product sales(1) | 34,844 | 26,244 | 123,306 | 77,283 | |||||
Funds flow | 21,323 | 11,985 | 64,080 | 34,380 | |||||
Per share – basic and diluted ($) | 0.18 | 0.10 | 0.53 | 0.29 | |||||
Net income (loss) | 8,624 | (12,898 | ) | 39,689 | (38,460 | ) | |||
Per share – basic and diluted ($) | 0.07 | (0.11 | ) | 0.33 | (0.32 | ) | |||
Operations capital expenditures(2) | 26,126 | 33,399 | 81,685 | 65,538 | |||||
Land and property acquisitions/(dispositions) | – | – | – | (600 | ) | ||||
Debt including working capital deficiency(2)(3) | 106,124 | 89,841 | 106,124 | 89,841 | |||||
Common shares (000s) | |||||||||
Weighted average – basic | 121,557 | 120,488 | 121,531 | 120,053 | |||||
Weighted average – diluted | 121,557 | 120,488 | 121,616 | 120,053 | |||||
Outstanding end of period – basic | 121,557 | 120,764 | 121,557 | 120,764 | |||||
OPERATIONS | |||||||||
(Cdn$ per Boe) | |||||||||
Revenue from product sales(1) | 21.12 | 21.42 | 21.09 | 15.97 | |||||
Royalties | (0.63 | ) | (0.99 | ) | (1.19 | ) | (0.79 | ) | |
Production | (5.68 | ) | (6.95 | ) | (6.04 | ) | (6.78 | ) | |
Transportation | (0.69 | ) | (0.55 | ) | (0.76 | ) | (0.45 | ) | |
Field operating netback(2) | 14.12 | 12.93 | 13.10 | 7.95 | |||||
Realized (loss) gain on hedging | 0.41 | (1.45 | ) | (0.40 | ) | 0.93 | |||
General and administrative | (0.94 | ) | (0.95 | ) | (1.05 | ) | (1.10 | ) | |
Interest and finance costs | (0.67 | ) | (0.74 | ) | (0.69 | ) | (0.68 | ) | |
Funds flow per Boe | 12.92 | 9.79 | 10.96 | 7.10 | |||||
Barrels of oil equivalent per day (6:1) | 17,936 |
13,320 |
16,017 |
13,219 |
|||||
Natural gas production | |||||||||
Thousand cubic feet per day | 87,375 | 66,173 | 78,521 | 65,478 | |||||
Price (Cdn$ per Mcf)(1) | 2.26 | 2.86 | 2.58 | 2.05 | |||||
Condensate production | |||||||||
Barrels per day | 1,914 | 1,381 | 1,685 | 1,303 | |||||
Price (Cdn$ per barrel)(1) | 69.53 | 57.17 | 61.80 | 49.34 | |||||
NGL production | |||||||||
Barrels per day | 1,460 | 910 | 1,245 | 1,003 | |||||
Price (Cdn$ per barrel)(1) | 33.29 | 18.64 | 25.15 | 12.51 | |||||
Wells drilled (100% working interest) | 7.0 | 5.0 | 16.0 | 12.0 | |||||
Wells completed (100% working interest) | 3.0 | 5.0 | 12.0 | 10.0 |
PRESIDENT’S MESSAGE
2017 FOURTH QUARTER HIGHLIGHTS
2017 YEAR-END HIGHLIGHTS
YEAR-END RESERVE EVALUATION HIGHLIGHTS
Reserves | Increase From | |||||||
(Mboe) | Last Year | 2017 | 2016 | 2015 | ||||
PDP | +33 | % | 33,729 | 25,395 | 20,810 | |||
1P | +27 | % | 97,617 | 77,097 | 73,434 | |||
2P | +24 | % | 128,963 | 104,192 | 100,722 | |||
PDP as % of 2P | 26 | % | 24 | % | 21 | % | ||
1P as a % of 2P | 76 | % | 74 | % | 73 | % |
Reserves Per Share Outstanding (Mboe per million shares) |
Increase From Last Year |
2017 |
2016 |
2015 |
|
PDP | +32 | % | 277 | 210 | 174 |
1P | +26 | % | 803 | 638 | 615 |
2P | +23 | % | 1,061 | 862 | 844 |
All-in FD&A Cost Including Change in FDC ($/Boe) |
2017 | 2016 | 2015 | 3 Year Total | ||||
PDP | $ | 5.76 | $ | 6.89 | $ | 6.53 | $ | 6.31 |
1P | $ | 3.06 | $ | 4.97 | $ | 3.38 | $ | 3.48 |
2P | $ | 1.27 | $ | 5.48 | $ | 0.50 | $ | 1.68 |
Recycle Ratio Using All-in FD&A Cost | 2017 | 2016 | 2015 | 3 Year Total | ||||
Funds Flow netback ($/Boe) | $ | 10.96 | $ | 7.10 | $ | 10.76 | $ | 9.60 |
PDP Recycle | 1.9 | 1.0 | 1.6 | 1.5 | ||||
1P Recycle | 3.6 | 1.4 | 3.2 | 2.8 | ||||
2P Recycle | 8.6 | 1.3 | 21.5 | 5.7 |
OPERATIONS REVIEW
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 69 horizontal wells (65.4 net).
Liquids recovery during the fourth quarter was 39 barrels per Mmcf sales (57% being higher priced condensate), an increase from 36 barrels per Mmcf sales last year.
Activity in the fourth quarter included completing three horizontal wells (3.0 net) and drilling seven horizontal wells (7.0 net). Notably, the horizontal drills had an average length of 2,090 metres, an increase of 57% from the average length of the wells drilled in 2014 to 2016. Five horizontal wells (5.0 net) started production which left an inventory of 12 horizontal wells (12.0 net) that had not started producing at the end of the quarter including two completed wells. During 2017, 13 horizontal wells (13.0 net) started producing with these wells adding 7,730 Boe per day in the fourth quarter.
With drilling focused in the south and to the northwest, the condensate-gas ratio on the 2017 wells is approximately 30% higher than on the 2014 to 2016 wells. This has resulted in corporate liquids production increasing at a higher rate than natural gas production.
Since 2013, approximately $100.0 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 fourth quarter was 93 Mmcf per day raw gas (December averaged 100 Mmcf per day). Capacity can be increased to 150 Mmcf per day by installing additional compression which was purchased and moved to site in the first quarter of 2018 at a cost of $5.0 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 81% directed to the McMahon Gas Plant in the fourth quarter and 19% directed to the Stoddart Gas Plant. Firm processing commitments total 65 Mmcf raw gas per day with terms of 5 to 15 years at McMahon and 15 Mmcf per day until April 2018 at Stoddart.
A summary of horizontal wells is provided below. The wells completed in 2017 are 38% longer than 2014 to 2016 wells while the drilling and completion cost per meter decreased by 16% from 2016. Results to date from the 2017 wells are very encouraging even though this is not apparent from IP90 and IP180 rates as the majority of wells are initially rate restricted to manage fluid rates. More information on well performance is available in the presentation on Storm’s website.
Year of Completion |
Frac Stages |
Completed Length |
Actual Drill & Complete Cost |
IP90 Cal Day Mmcf/d Raw |
IP180 Cal Day Mmcf/d Raw |
IP365 Cal Day Mmcf/d Raw |
2014 12 hz’s(1) |
19 | 1,170 m | $4.6 million $3,950 per meter |
4.9 Mmcf/d 12 hz’s |
4.4 Mmcf/d 12 hz’s |
3.5 Mmcf/d 12 hz’s |
2015 11 hz’s |
22 | 1,360 m | $4.5 million $3,300 per meter |
4.7 Mmcf/d 11 hz’s |
4.2 Mmcf/d 11 hz’s |
3.3 Mmcf/d 11 hz’s |
2016 10 hz’s |
25 | 1,300 m | $3.7 million $2,850 per meter |
5.1 Mmcf/d 10 hz’s |
4.2 Mmcf/d 10 hz’s |
3.5 Mmcf/d 7 hz’s |
2017 12 hz’s |
34 | 1,750 m | $4.2 million $2,400 per meter |
4.9 Mmcf/d 8 hz’s |
4.4 Mmcf/d 5 hz’s |
4.4 Mmcf/d 2 hz’s |
2018 3 hz’s |
37 | 2,090 m | $5.3 million $2,550 per meter |
HEDGING AND TRANSPORTATION
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 40% of forecast production for 2018 using the low end of guidance (20,000 Boe per day).
2018 | ||
Crude Oil | 1,362 Bpd | WTI Cdn$64.43/Bbl floor, Cdn$68.08/Bbl ceiling |
Propane | 300 Bpd | Conway Cdn$39.55/Bbl |
Natural Gas | 750 GJ/d (600 Mcf/d) | AECO Cdn$2.80/GJ |
34,200 Mmbtu/d (29,000 Mcf/d) | Chicago Cdn$3.81/Mmbtu(1) | |
2,200 Mmbtu/d (1,850 Mcf/d) | Chicago US$2.70/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 | |
2019 | ||
Crude Oil | 325 Bpd | WTI Cdn$67.28/Bbl floor, Cdn$71.14/Bbl ceiling |
Natural Gas | 4,000 Mmbtu/d (3,400 Mcf/d) | Chicago Cdn$3.50/Mmbtu(1) |
1,500 Mmbtu/d (1,275 Mcf/d) | Chicago US$2.65/Mmbtu(1) |
Total firm transportation capacity is currently 77 Mmcf per day and increases to 102 Mmcf per day in April 2018. Capacity on the Alliance Pipeline to Chicago increased by five Mmcf per day in December 2017 and currently totals 55 Mmcf per day. Natural gas production exceeding firm capacity is directed to Chicago and/or Station 2 using interruptible pipeline capacity (depending on which sales point offers a higher price). Using forecast production for 2018, firm transportation capacity will result in approximately 54% to 68% of natural gas sales at Chicago pricing, 11% at Sumas pricing less a marketing adjustment, 5% at ATP pricing, 3% to 17% at Station 2 pricing and 13% at AECO pricing. Note that natural gas marketing arrangements result in the cost of transportation on the Alliance Pipeline for sales in Chicago being deducted from revenue ($8.3 million deducted in the fourth quarter of 2017). Additional information is provided in the presentation on Storm’s website.
OUTLOOK
In the fourth quarter of 2017, actual production of 17,936 Boe per day was at the low end of guidance of 18,000 to 19,000 Boe per day. This was the result of the low Station 2 natural gas price in the quarter ($0.53/GJ) which resulted in the start-up of new wells being deferred until December when Alliance capacity was increased by an additional five Mmcf per day. During October and November, production was maintained at a level that fulfilled firm transportation commitments.
For the first quarter of 2018, production is forecast to be 19,500 to 20,500 Boe per day which represents year-over- year growth of 18% at the mid-point. Production to date in the first quarter has averaged 19,700 Boe per day based on field estimates. Capital investment is expected to be $23.0 million which includes completing three horizontal wells on the Nig land block at Umbach plus constructing a 13-kilometer gathering pipeline to the Nig land block.
In the first half of 2018, capital investment is expected to be less than funds flow using forecast commodity prices which is expected to result in debt being reduced by approximately $10.0 million to $15.0 million.
Updated guidance for 2018 is provided in the table below and is largely unchanged except for updating forecast commodity prices to reflect pricing to date and approximately the current forward strip for the remainder of the year. A range has been provided for capital investment and for forecast production with both mainly contingent on the natural gas price at Station 2 which is where Storm’s incremental natural gas growth would be sold. The low end of forecast production for the year represents year-over-year growth of 25% with capital investment expected to be less than estimated funds flow. The production forecast uses a 7.5 Bcf type curve for future horizontal wells at Umbach (previously a 6.3 Bcf type curve was used which was based on the performance of shorter horizontal wells completed in 2014 to 2016).
2018 Guidance | Previous November 14, 2017 |
Current March 1, 2018 |
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$Cdn/$US exchange rate | 0.79 | 0.80 | ||
Chicago daily natural gas – US$/Mmbtu | $2.80 | $2.60 | ||
Sumas monthly natural gas – US$/Mmbtu | $2.40 | $1.90 | ||
AECO daily natural gas – Cdn$/GJ | $1.80 – $2.10 | $1.40 | ||
Station 2 daily natural gas – Cdn$/GJ | $1.30 – $1.70 | $1.05 | ||
WTI – US$/bbl | $52.00 | $56.00 | ||
Edmonton light oil – Cdn$/Bbl | $62.00 | $64.00 | ||
Est revenue net of transport (excl hedges) – $/Boe | $18.00 – $19.25 | $17.00 – $18.50 | ||
Est operating costs – $/Boe | $5.75 | $5.75 | ||
Est royalty rate (% revenue before hedging) | 6% – 9% | 6% – 8% | ||
Est operations capital investment (excl A&D) – $ million | $55.0 – $90.0 | $55.0 – $90.0 | ||
Est cash G&A – $ million | $6.0 – $7.0 | $6.0 – $7.0 | ||
– $/Boe | $0.70 – $0.95 | $0.70 – $0.95 | ||
Est interest expense – $ million | $4.5 – $5.5 | $4.5 – $5.5 | ||
Forecast fourth quarter production – Boe/d % liquids |
20,000 – 27,000 17% liquids |
20,000 – 27,000 18% liquids |
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Forecast annual production – Boe/d % liquids |
20,000 – 23,000 17% liquids |
20,000 – 23,000 18% liquids |
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Est annual funds flow at 20,000 Boe/d – $ million | $70.0 – $78.0 | |||
Umbach horizontal wells drilled – gross Umbach horizontal wells completed – gross Umbach horizontal wells connected – gross |
6 – 12 (6.0 – 12.0 net) 11 – 17 (11.0 – 17.0 net) 11 – 16 (11.0 – 16.0 net) |
3 – 12 (3.0 – 12.0 net) 11 – 17 (11.0 – 17.0 net) 11 – 16 (11.0 – 16.0 net) |
2018 Guidance History | ||||||||||
Chicago |
Station 2 |
AECO |
Estimated Operations Capital $ million |
Forecast Fourth Quarter Production Boe/d |
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 |
The continuing volatility in Western Canadian natural gas prices has been largely mitigated for Storm by increasing liquids production and through diversified natural gas sales. In 2017, liquids represented 40% of production revenue while only 34% of natural gas sales were at Western Canadian prices.
Although Storm’s production in 2017 grew by 21% from 2016, growth in the second half of the year was less than expected primarily because of declining Western Canadian natural gas prices. From H1/17 to H2/17, the natural gas price declined by approximately 45% at AECO and by 70% at Station 2. This was mainly from production growing by 1 Bcf per day since the summer of 2017, storage levels that are relatively high, and export pipelines to other markets that are full (in general, too much supply and nowhere to take it). In addition, the price differential between Station 2 and AECO in H2/17 widened to -$0.80 per GJ as a result of maintenance on the Enbridge and TransCanada pipeline systems restricting takeaway out of northeast British Columbia (“NE BC”). Spot or daily natural gas prices have shown recent improvement with AECO averaging approximately $2.00 per GJ and Station 2 averaging approximately $1.75 per GJ to date in 2018 (increases of 34% and 157% respectively versus H2/17). The differential between Station 2 and AECO has narrowed with the completion of the TCPL Towerbirch expansion which increased flows out of NE BC. Spot or daily prices have been stronger than the forward strip with strong physical demand from a cold winter, rising oil sands demand, and higher electricity generation as coal plants are decommissioned. In addition, there has been a year-over-year decrease in rigs drilling for natural gas which likely will reduce supply later in 2018.
Incremental production growth above Storm’s firm transportation capacity (102 Mmcf per day sales or 20,000 to 21,000 Boe per day) is primarily directed to Station 2 and growth will continue to be contingent on the natural gas price at Station 2. Capital investment has been designed to be flexible where activity and production growth can be rapidly increased if supported by the natural gas price. At Umbach, additional compression can be installed quickly plus there are currently four completed horizontal wells that can be turned on and another five standing horizontal wells awaiting completion (all longer wells).
Storm’s business plan continues to be focused on adding value by converting the multi-year drilling inventory in the Montney into funds flow growth while generating reasonable risk-adjusted rates of return. Although the current forward strip for Western Canadian natural gas prices makes this challenging, the significant improvement in liquids prices over the last 12 months has resulted in several alternatives being identified for growing funds flow by increasing liquids production.
Liquids production will be increased by continuing to drill wells in areas where higher condensate-gas ratios can be realized (Nig and Fireweed land blocks) and can also come from adding infrastructure to increase plant NGL recoveries at Umbach. Current liquids recovery from the liquids-rich Montney is less than optimal and either adding or redirecting raw gas to access a shallow-cut refrigeration process is being evaluated which would increase NGL recovery from the raw gas by approximately 100% to 125%.
Partially mitigating the decline in Western Canadian natural gas prices, Storm’s capital efficiencies are expected to improve based on preliminary results from recent longer horizontal wells that are more than 2,000 meters in length (approximately 60% longer than wells completed in 2014 to 2016). Rates and reserves are expected to increase in proportion to the added length while the total well cost is increasing by 15% to 25%.
Maintaining production at current levels would also add value as debt would be reduced with maintenance capital being less than estimated funds flow at current strip pricing for 2018 and 2019. The estimated capital required to maintain production is $55.0 million to $60.0 million in 2018 and $35.0 million to $40.0 million in 2019. This option is less desirable as it adds value at a slower rate versus growing production and/or increasing liquids production.
Results from 2017 show that Storm’s business plan works at low natural gas prices. In addition, the large, higher quality, liquids-rich asset in the Montney at Umbach offers alternatives for growth that are less dependent on natural gas pricing. For 2018, production is expected to grow by a minimum of 25% year over year to average 20,000 Boe per day. Existing infrastructure will support further growth to 27,000 Boe per day with the timing to do so dependent on natural gas prices. For 2019, the focus will be to identify ways to grow funds flow by increasing liquids production which could come from adding infrastructure and/or drilling wells in areas with higher condensate-gas ratios.
In closing, I would like to thank Storm’s employees for their hard work which has resulted in record levels of production and significant growth in funds flow while continuing to improve capital efficiencies and reduce costs. In addition, the invaluable advice, guidance and support provided by Storm’s Board of Directors continues to be much appreciated.
Respectfully,
Brian Lavergne,
President and Chief Executive Officer
March 1, 2018
RESERVES AT DECEMBER 31, 2017
Storm’s year-end reserve evaluation effective December 31, 2017 was prepared by InSite Petroleum Consultants Ltd. (“InSite”) in a report dated February 23, 2018. InSite has evaluated all of Storm’s natural gas and NGL reserves. The InSite price forecast at December 31, 2017 was used to determine estimates of net present value (“NPV”). Storm’s Reserves Committee, which is made up of independent and appropriately qualified directors, has reviewed and approved the evaluation prepared by InSite, and the report of the Reserves Committee has been accepted by the Company’s Board of Directors.
Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without including any royalty interests) unless noted otherwise. All reserves information has been prepared in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). In addition to the information disclosed in this report, more detailed information will be included in Storm’s Annual Information Form for the year ended December 31, 2017 (the “AIF”).
Summary
(1) The all-in calculation reflects the result of Storm’s entire capital investment program as it takes into account the effect of acquisitions, dispositions and revisions, as well as the change in FDC.
INFORMATION REGARDING DISCLOSURE ON OIL AND GAS RESERVES AND RESOURCES
All amounts are stated in Canadian dollars unless otherwise specified. Where applicable, natural gas has been converted to barrels of oil equivalent (“Boe”) based on 6 Mcf:1 Boe. The Boe rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not recognize a value equivalent at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value. Production volumes and revenues are reported on a company gross basis, before deduction of Crown and other royalties, unless otherwise stated. Unless otherwise specified, all reserves volumes are based on “company gross reserves” using forecast prices and costs. The oil and gas reserves statement for the year ended December 31, 2017, which will include complete disclosure of oil and gas reserves and other information in accordance with NI 51-101, will be contained within the AIF which will be available on SEDAR.
References to estimates of oil and gas classified as DPIIP are not, and should not be confused with, oil and gas reserves.
Gross Company Interest Reserves as at December 31, 2017
(Before deduction of royalties payable, not including royalties receivable)
Sales Gas (Mmcf) |
NGL (Mbbls) |
6:1 Oil Equivalent (Mboe) |
||
Proved producing | 167,747 | 5,771 | 33,729 | |
Proved non-producing | 3,706 | 92 | 710 | |
Total proved developed | 171,453 | 5,863 | 34,439 | |
Proved undeveloped | 314,872 | 10,700 | 63,179 | |
Total proved | 486,325 | 16,563 | 97,617 | |
Probable additional | 156,390 | 5,281 | 31,346 | |
Total proved plus probable | 642,715 | 21,844 | 128,963 |
Numbers in this table may not add due to rounding.
Gross Company Reserve Reconciliation for 2017
(Gross company interest reserves before deduction of royalties payable)
6:1 Oil Equivalent (Mboe) | |||||||||
|
Proved Developed Producing |
Total Proved |
Probable | Proved plus Probable |
|||||
December 31, 2016 – opening balance | 25,395 | 77,097 | 27,096 | 104,192 | |||||
Acquisitions | – | – | – | – | |||||
Discoveries | – | – | – | – | |||||
Extensions | 11,132 | 16,690 | 2,945 | 19,635 | |||||
Category transfer | – | – | – | – | |||||
Dispositions | – | – | – | – | |||||
Technical revisions | 3,342 | 10,949 | 3,027 | 13,976 | |||||
Economic factors | (294 | ) | (1,271 | ) | (1,723 | ) | (2,994 | ) | |
Production | (5,846 | ) | (5,846 | ) | – | (5,846 | ) | ||
December 31, 2017 – closing balance | 33,729 | 97,617 | 31,346 | 128,963 |
Numbers in this table may not add due to rounding.
Reserve Life Index (“RLI”) Using Fourth Quarter Production
2017 | 2016 | 2015 | ||
PDP | 5.2 | 5.2 | 5.3 | |
1P | 14.9 | 15.9 | 18.8 | |
2P | 19.7 | 21.4 | 25.7 |
Future Development Costs (“FDC”)
Proved ($M) |
Proved Plus Probable ($M) |
|||||||||||
2018 | 60,050 | 64,300 | ||||||||||
2019 | 103,071 | 119,391 | ||||||||||
2020 | 179,781 | 207,352 | ||||||||||
2021 | 68,745 | 90,075 | ||||||||||
2022 | – | – | ||||||||||
Total FDC – undiscounted | 411,647 | 481,118 | ||||||||||
Total FDC – discounted at 10% | 340,908 | 395,976 | ||||||||||
($million) | 2017 | 2016 | 2015 | |||||||||
1P FDC | $ | 412 | $ | 413 | $ | 435 | ||||||
2P FDC | $ | 481 | $ | 524 | $ | 543 |
Note: InSite escalates capital costs at 2% per year after 2018.
All-in Finding, Development and Acquisition Costs (“FD&A”)
(including acquisitions, dispositions and revisions)
Proved Developed Producing FD&A Cost (All-in) | 2017 | 2016 | 2015 | 3 Year Total | ||||||||
Net capital investment (000s) | $ | 81,685 | $ | 64,938 | $ | 71,509 | $ | 218,130 | ||||
Total capital | $ | 81,685 | $ | 64,938 | $ | 71,509 | $ | 218,130 | ||||
Total reserve additions (Mboe) | 14,180 | 9,424 | 10,956 | 34,560 | ||||||||
All-in PDP FD&A cost (per Boe) | $ | 5.76 | $ | 6.89 | $ | 6.53 | $ | 6.31 | ||||
Total Proved FD&A Cost (All-in) | 2017 | 2016 | 2015 | 3 Year Total | ||||||||
Net capital investment (000s) | $ | 81,685 | $ | 64,938 | $ | 71,509 | $ | 218,130 | ||||
Change in FDC (000s) | (1,127 | ) | (22,669 | ) | (12,275 | ) | (36,071 | ) | ||||
Total capital including change in FDC (000s) | $ | 80,558 | $ | 42,269 | $ | 59,234 | $ | 182,059 | ||||
Total reserve additions (Mboe) | 26,366 | 8,501 | 17,517 | 52,384 | ||||||||
All-in 1P FD&A cost (per Boe) | $ | 3.06 | $ | 4.97 | $ | 3.38 | $ | 3.48 | ||||
|
||||||||||||
Total Proved Plus Probable FD&A Cost (All-in) | 2017 | 2016 | 2015 | 3 Year Total | ||||||||
Net capital investment (000s) | $ | 81,685 | $ | 64,938 | $ | 71,509 | $ | 218,130 | ||||
Change in FDC (000s) | (42,755 | ) | (19,395 | ) | (63,288 | ) | (125,438 | ) | ||||
Total capital including change in FDC (000s) | $ | 38,930 | $ | 45,543 | $ | 8,221 | $ | 92,692 | ||||
Total reserve additions (Mboe) | 30,617 | 8,308 | 16,332 | 55,257 | ||||||||
All-in 2P FD&A cost (per Boe) | $ | 1.27 | $ | 5.48 | $ | 0.50 | $ | 1.68 | ||||
Finding and Development Costs (“F&D”)
(excluding acquisitions, dispositions and revisions)
Total Proved F&D Cost | 2017 | 2016 | 2015 | 3 Year Total | ||||||||
Capital expenditures excluding acquisitions | ||||||||||||
and dispositions (000s) | $ | 81,685 | $ | 64,938 | $ | 95,099 | $ | 241,720 | ||||
Change in FDC (000s) | (1,127 | ) | (22,669 | ) | 18,604 | (5,192 | ) | |||||
Total capital including change in FDC (000s) | $ | 80,558 | $ | 42,269 | $ | 113,703 | $ | 236,528 | ||||
Reserve additions excluding acquisitions, dispositions, | ||||||||||||
and revisions (Mboe) | 16,669 | 5,182 | 14,950 | 36,801 | ||||||||
1P F&D cost (per Boe) | $ | 4.83 | $ | 8.16 | $ | 7.61 | $ | 6.43 | ||||
Total Proved Plus Probable F&D Cost | 2017 | 2016 | 2015 | 3 Year Total | ||||||||
Capital expenditures excluding acquisitions | ||||||||||||
and dispositions (000s) | $ | 81,685 | $ | 64,938 | $ | 95,099 | $ | 241,720 | ||||
Change in FDC (000s) | (42,755 | ) | (19,395 | ) | 30,717 | (31,433 | ) | |||||
Total capital including change in FDC (000s) | $ | 38,930 | $ | 45,543 | $ | 125,816 | $ | 210,287 | ||||
Reserve additions excluding acquisitions, dispositions, | ||||||||||||
and revisions (Mboe) | 19,615 | 4,890 | 19,457 | 43,962 | ||||||||
2P F&D cost (per Boe) | $ | 1.98 | $ | 9.31 | $ | 6.47 | $ | 4.78 |
Net Present Value Summary (before tax) as at December 31, 2017
Benchmark oil and NGL prices used are adjusted for quality of oil or NGL produced and for transportation costs. The calculated NPV include a deduction for estimated future well abandonment costs. The NPV disclosed does not represent fair market value of reserves.
(000s) | Undiscounted | Discounted at 5% |
Discounted at 10% |
Discounted at 15% |
Discounted at 20% |
Proved producing | 613,055 | 476,124 | 389,466 | 330,863 | 289,021 |
Proved non-producing | 7,396 | 4,839 | 3,341 | 2,395 | 1,763 |
Total proved developed | 620,451 | 480,963 | 392,806 | 333,258 | 290,784 |
Proved undeveloped | 915,449 | 590,662 | 399,234 | 278,439 | 198,009 |
Total proved | 1,535,899 | 1,071,625 | 792,040 | 611,697 | 488,792 |
Probable additional | 658,780 | 357,091 | 215,918 | 141,347 | 97,907 |
Total proved plus probable | 2,194,678 | 1,428,716 | 1,007,958 | 753,044 | 586,700 |
Numbers in this table may not add due to rounding.
Net Present Value Summary (after tax) as at December 31, 2017
Benchmark oil and NGL prices used are adjusted for quality of oil or NGL produced and for transportation costs. The calculated NPV each include a deduction for estimated future well abandonment costs. The NPV disclosed does not represent fair market value of reserves.
(000s) | Undiscounted | Discounted at 5% |
Discounted at 10% |
Discounted at 15% |
Discounted at 20% |
Proved producing | 576,702 | 455,976 | 377,775 | 323,808 | 284,617 |
Proved non-producing | 5,476 | 3,661 | 2,585 | 1,893 | 1,419 |
Total proved developed | 582,178 | 459,637 | 380,360 | 325,701 | 286,036 |
Proved undeveloped | 677,095 | 430,687 | 285,517 | 194,069 | 133,346 |
Total proved | 1,259,272 | 890,324 | 665,877 | 519,770 | 419,382 |
Probable additional | 488,035 | 263,033 | 157,653 | 102,008 | 69,645 |
Total proved plus probable | 1,747,307 | 1,153,356 | 823,530 | 621,778 | 489,027 |
Numbers in this table may not add due to rounding.
InSite Escalating Price Forecast as at December 31, 2017
|
WTI Crude Oil (US$/Bbl) |
Edmonton Par Crude Oil (Cdn$/Bbl) |
Henry Hub Natural Gas (US$/Mmbtu) |
AECO Natural Gas (Cdn$/Mmbtu) |
2018 | 60.00 | 71.36 | 3.10 | 2.52 |
2019 | 62.50 | 73.44 | 3.30 | 2.93 |
2020 | 65.00 | 75.47 | 3.50 | 3.22 |
2021 | 70.00 | 80.49 | 3.70 | 3.51 |
2022 | 72.50 | 82.38 | 3.90 | 3.75 |
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 March 1, 2018 for the period ended December 31, 2017 which is available on Storm’s SEDAR profile at www.sedar.com and on Storm’s website at www.stormresourcesltd.com.
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 31, 2017 and the MD&A dated March 1, 2018 for the period ended December 31, 2017 which are available on Storm’s SEDAR profile at www.sedar.com and on Storm’s website at www.stormresourcesltd.com.
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
www.stormresourcesltd.com