CALGARY, ALBERTA–(Marketwired – Nov. 15, 2016) – Storm Resources Ltd. (TSX VENTURE:SRX) –
Storm has filed its unaudited condensed interim consolidated financial statements as at September 30, 2016 and for the three and nine months then ended along with Management’s Discussion and Analysis (“MD&A”) for the same period. 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 and nine months ended September 30, 2016 appears below and should be read in conjunction with the related financial statements and MD&A.
Highlights
| Thousands of Cdn$, except volumetric and per-share amounts | Three Months to Sept. 30, 2016 |
Three Months to Sept. 30, 2015 |
Nine Months to Sept. 30, 2016 | Nine Months to Sept. 30, 2015 |
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| FINANCIAL | |||||||||||||
| Revenue from product sales(1) | 21,047 | 16,283 | 51,038 | 53,256 | |||||||||
| Funds from operations(2) | 8,759 | 7,982 | 22,395 | 29,864 | |||||||||
| Per share – basic ($) | 0.07 | 0.07 | 0.19 | 0.26 | |||||||||
| Per share – diluted ($) | 0.07 | 0.07 | 0.19 | 0.26 | |||||||||
| Net loss | (85 | ) | (961 | ) | (25,562 | ) | (8,717 | ) | |||||
| Per share – basic ($) | (0.00 | ) | (0.01 | ) | (0.21 | ) | (0.08 | ) | |||||
| Per share – diluted ($) | (0.00 | ) | (0.01 | ) | (0.21 | ) | (0.08 | ) | |||||
| Net capital invested | 6,980 | (4,116 | ) | 31,539 | 40,428 | ||||||||
| Operations capital expenditures | 7,580 | 19,557 | 32,139 | 64,101 | |||||||||
| Land and property acquisitions (dispositions) | (600 | ) | (23,673 | ) | (600 | ) | (23,673 | ) | |||||
| Debt including working capital deficiency(3) | 69,303 | 39,994 | 69,303 | 39,994 | |||||||||
| Common shares (000s) | |||||||||||||
| Weighted average – basic | 120,195 | 119,355 | 119,907 | 114,618 | |||||||||
| Weighted average – diluted | 120,195 | 119,355 | 119,907 | 114,618 | |||||||||
| Outstanding end of period – basic | 120,283 | 119,355 | 120,283 | 119,355 | |||||||||
| OPERATIONS | |||||||||||||
| (Cdn$ per Boe) | |||||||||||||
| Revenue | 17.22 | 18.33 | 14.13 | 20.12 | |||||||||
| Royalties | (1.19 | ) | (1.28 | ) | (0.72 | ) | (1.15 | ) | |||||
| Production | (6.69 | ) | (7.89 | ) | (6.72 | ) | (8.37 | ) | |||||
| Transportation | (0.39 | ) | (0.94 | ) | (0.42 | ) | (1.26 | ) | |||||
| Field operating netback | 8.95 | 8.22 | 6.27 | 9.34 | |||||||||
| Realized hedging gains (losses) | (0.03 | ) | 2.22 | 1.74 | 4.20 | ||||||||
| General and administrative | (1.03 | ) | (1.07 | ) | (1.15 | ) | (1.60 | ) | |||||
| Interest and finance costs | (0.72 | ) | (0.39 | ) | (0.65 | ) | (0.65 | ) | |||||
| Funds from operations – per Boe | 7.17 | 8.98 | 6.21 | 11.29 | |||||||||
| Barrels of oil equivalent per day (6:1) | 13,285 | 9,654 | 13,185 | 9,695 | |||||||||
| Gas Production | |||||||||||||
| Thousand cubic feet per day | 65,914 | 47,325 | 65,245 | 47,142 | |||||||||
| Price (Cdn$ per Mcf) | 2.41 | 2.46 | 1.77 | 2.62 | |||||||||
| NGL production | |||||||||||||
| Barrels per day | 2,299 | 1,697 | 2,311 | 1,598 | |||||||||
| Price (Cdn$ per barrel) | 30.54 | 33.32 | 30.49 | 37.13 | |||||||||
| Oil Production | |||||||||||||
| Barrels per day | – | 70 | – | 240 | |||||||||
| Price (Cdn$ per barrel) | – | 55.93 | – | 50.84 | |||||||||
| Wells drilled (100% working interest) | – | – | 7.0 | 6.0 | |||||||||
| Wells completed (100% working interest) | 3.0 | 4.0 | 5.0 | 6.0 | |||||||||
| (1) Excludes hedging gains and losses. | |||||||||||||
| (2) Certain financial amounts shown above are non-GAAP measurements, including funds from operations and funds from operations per share, operations capital expenditures, debt including working capital deficiency and all measurements per Boe. See discussion of Non-GAAP Measurements on page 26 of the MD&A and the reconciliation of funds from operations to the most directly comparable measurement under GAAP, cash flows from operating activities, on page 18 of the MD&A. | |||||||||||||
| (3) Excludes the fair value of commodity price contracts. | |||||||||||||
PRESIDENT’S MESSAGE
2016 THIRD QUARTER
- Production averaged 13,285 Boe per day (17% NGL), a year-over-year increase of 38% (37% on a per-share basis) and a quarter-over-quarter increase of 3%. Production increased compared to the previous quarter with two new wells beginning production in late August and in September as a result of the improvement in natural gas prices.
- NGL production was 2,299 barrels per day, an increase of 35% from the previous year. At $30.54 per barrel, the price was 56% of the average Edmonton light oil price (53% of NGL’s are higher value condensate and plant pentanes).
- Through the first nine months of 2016, six new horizontal wells have been placed on stream which has maintained production between 12,500 and 13,800 Boe per day. At the end of the quarter, there was an inventory of seven horizontal wells (7.0 net) that had not started production which included one completed well.
- Montney horizontal well performance at Umbach continues to improve with the first two wells completed in 2016 averaging 5.7 Mmcf per day gross raw gas over the first 90 calendar days, a 20% improvement from the average 2014 and 2015 wells.
- Controllable cash costs (operating, cash G&A, interest expense) were $8.44 per Boe, a year-over-year decrease of 10%. Transportation cost is excluded given that the sales price for volumes shipped on the Alliance Pipeline includes a deduction for the pipeline tariff (artificially reduces the transportation cost).
- Funds flow was $8.8 million ($7.17 per Boe), an increase of 10% from a year ago. Excluding hedging gains, the increase was 46%. The year-over-year improvement resulted from production increasing 38% and controllable cash costs per Boe decreasing 10% which was partially offset by a 6% decrease in revenue per Boe.
- Net capital investment was $7.0 million which included completing three horizontal wells (3.0 net) and site preparation for the third field compression facility at Umbach.
- Debt including working capital deficiency was $69.3 million which is 2.0 times annualized third quarter funds flow and is a reduction of $2.0 million from the previous quarter. The bank credit facility remains at $130 million.
- Commodity price hedges for 2017 have increased to represent approximately 39% of current production (an increase from approximately 24% hedged when second quarter results were released August 15, 2016).
- On September 7, Storm announced that it had entered into a natural gas processing arrangement at Umbach with Spectra Energy (“Spectra”) that is expected to reduce operating costs by approximately 15% to 20% with the anticipated increase in funds flow being used to increase capital investment and accelerate growth in 2017.
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, 48 horizontal wells have been drilled (44.4 net) with 41 horizontal wells producing at the end of the third quarter (37.4 net). Over the last 12 months, the number of producing wells has increased by 9.0 net wells.
Production in the third quarter was 13,130 Boe per day and NGL recovery was 35 barrels per Mmcf sales with 53% being higher priced field condensate plus pentanes recovered at the gas plant.
During the third quarter, three horizontal wells were completed (3.0 net) and two horizontal wells (2.0 net) started production. At the end of the third quarter, there was an inventory of seven horizontal wells (7.0 net) that had not started producing which included one completed well. Activity in the fourth quarter will include drilling five horizontal wells (5.0 net) and completing five horizontal wells (5.0 net).
Storm’s two operated field compression facilities have total capacity of 80 Mmcf per day raw gas with actual throughput in the third quarter averaging 69 Mmcf per day raw gas. Construction has started on the third field compression facility with initial capacity of 35 Mmcf per day and start-up is planned for January 2017. The estimated total cost is unchanged at $25.0 million with $4.8 million incurred in 2015, $19.0 million in 2016, and the remainder planned for 2017. The third facility is expandable to 70 Mmcf per day raw gas for an additional investment of $7.0 million.
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. This includes the recently announced natural gas processing arrangement with Spectra which has an effective date of January 1, 2017 and a total commitment of 65 Mmcf per day of raw gas at terms ranging from 5 to 15 years. The arrangement with Spectra represents a significant step forward by reducing operating costs, supporting future growth with an option to increase contracted capacity, and provides for continued diversification of natural gas sales with access to three sales pipelines through the McMahon Gas Plant (Alliance Pipeline to Chicago, TransCanada NGTL system to AECO, Spectra T-north mainline to BC Station 2).
A summary of horizontal well performance and costs is provided below. On a per-stage basis, the drill and complete cost for 2016 wells has decreased by 25% from 2015.
| Year of Completion | Frac Stages |
Completed Length |
Actual Drill & Complete Cost | IP 90 Cal Day Mmcf/d Raw |
IP 180 Cal Day Mmcf/d Raw |
IP 365 Cal Day Mmcf/d Raw |
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| 20136 wells | 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 |
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| 201412 wells* | 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 |
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| 201511 wells | 22 | 1,360 m | $4.4 million $200 K/stage |
4.7 Mmcf/d 11 hz’s |
4.2 Mmcf/d 9 hz’s |
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| 20165 wells | 27 | 1,410 m | $4.0 million $148 K/stage |
5.7 Mmcf/d 2 hz’s |
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| * 2014 wells exclude a middle Montney well (comparing upper Montney wells only). | ||||||||||||
The majority of future horizontal wells are expected to have greater than 1,600 metres of completed length with more than 30 frac stages while the average 2014 and 2015 wells have a completed length of 1,265 metres and an average of 21 frac stages. More information on the type curve and well economics is provided in the presentation on Storm’s website.
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 was restarted during September as a result of an improvement in the BC Station 2 natural gas price and averaged 141 Boe per day in the third quarter (was shut in July 2015 due to the low natural gas price at BC Station 2). Cumulative production to date from this well is 5.1 Bcf raw.
HEDGING AND TRANSPORTATION
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 monthly production for the next 12 months and 25% of most recent monthly production for 13 to 24 months forward. Anticipated production growth is not hedged. The WTI price is also hedged as approximately 80% of Storm’s NGL production is priced in reference to WTI (condensate, plant pentane and butane). Hedges will be updated periodically in the presentation posted on Storm’s website.
Storm’s commodity price hedges are summarized below. For 2017, approximately 38% of current production or 30% of forecast 2017 production is hedged.
| Q4 2016 | ||||
| Crude Oil | 950 Bopd | WTI Cdn$68.86/Bbl floor, Cdn$78.48/Bbl ceiling | ||
| Natural Gas | 43,670 GJ/d (34,900 Mcf/d) | AECO Cdn$2.38/GJ ($2.98/Mcf) | ||
| 2017 | ||||
| Crude Oil | 775 Bopd | WTI Cdn$64.11/Bbl floor, Cdn$69.24/Bbl ceiling | ||
| Natural Gas | 30,340 GJ/d (24,300 Mcf/d) | AECO Cdn$2.62/GJ ($3.27/Mcf) | ||
| 2,940 GJ/d (2,350 Mcf/d) | Chicago Cdn$3.90/GJ ($4.88/Mcf) | |||
Storm’s strategy with respect to natural gas transportation commitments is to diversify natural gas sales by selling at multiple points including Chicago, AECO and BC Station 2. Transportation commitments total 65 Mmcf per day in 2017 and increase to 95 Mmcf per day in 2018 (interruptible capacity on the Alliance Pipeline adds up to 14 Mmcf per day in 2017 and up to 15 Mmcf per day in 2018). As production increases, additional firm transportation will be added. A summary is provided below and further information on pipeline tariffs and price deductions is provided in the presentation on Storm’s website.
| Q4 2016 | 2017 | 2018 | ||
| Alliance Pipeline(1) 46 Mmcf/d Chicago price 5 Mmcf/d ATP price |
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 |
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| Spectra T-north 9 Mmcf/d BC Stn 2 price |
Spectra T-north 9 Mmcf/d BC Stn 2 price |
Spectra T-north 22 Mmcf/d BC Stn 2 price |
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| Marketing Arrangement 3 Mmcf/d AECO price -$0.68/GJ |
Spectra T-north & TCPL 13 Mmcf/d AECO price |
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| (1) Interruptible capacity on the Alliance Pipeline adds up to 25% of contracted capacity. | ||||
ORGANIZATIONAL UPDATE
Mr. Donald McLean, Chief Financial Officer, has announced he will be retiring in mid-2017. Mr. McLean joined the ‘first’ Storm in 2001 and has been involved in all four Storm companies. In addition, Mr. John Devlin, Vice President, Finance, has also announced he will be retiring in mid-2017. Mr. Devlin joined the ‘third’ Storm in 2005 and has been involved in the last two Storm companies. Each of Mr. McLean and Mr. Devlin has provided valuable contributions to the success of Storm. Successors to both will be identified through an internal process.
OUTLOOK
Fourth quarter production is forecast to be approximately 13,000 to 14,000 Boe per day depending on commodity prices. Production in October averaged 12,200 Boe per day and was impacted by a nine-day outage on the Alliance Pipeline plus an 11-day outage on the Spectra T-north Fort St. John lateral to BC Station 2. Capital investment is expected to be $37 million and activity will include construction of the third field compression facility at Umbach ($11 million), drilling five horizontal wells ($10 million), and completing and equipping five horizontal wells ($11 million).
On September 7, 2016, Storm announced that it had entered into a natural gas processing arrangement with Spectra at Umbach with the expected increase in funds flow being used to increase capital investment and accelerate growth in 2017. Expected service cost reductions are also supportive of accelerating growth. Guidance for 2016 and 2017 is provided below and is unchanged from what was provided September 7th except for updating commodity prices.
2016 Guidance
| September 7, 2016 | November 15, 2016 | |||
| Chicago natural gas price | US$2.40/Mmbtu(1) | US$2.45/Mmbtu(1) | ||
| AECO natural gas price | $1.95/GJ(1) | $2.00/GJ(1) | ||
| BC STN 2 natural gas price | $1.65/GJ(1) | $1.65/GJ(1) | ||
| Edmonton light oil price | Cdn$50/Bbl(1) | Cdn$52/Bbl(1) | ||
| Estimated average operating costs | $7.00/Boe | $7.00/Boe | ||
| Estimated average royalty rate (% production revenue before hedging) |
5% – 6% | 5% – 6% | ||
| Estimated operations capital (excluding acquisitions & dispositions) |
$70.0 million | $65.0 – $70.0 million | ||
| Estimated cash G&A net of recoveries | $5.7 million $1.20/Boe |
$5.7 million $1.20/Boe |
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| Forecast fourth quarter production | 13,000 – 14,000 Boe/d (18% NGL) |
13,000 – 14,000 Boe/d (18% NGL) |
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| Forecast annual production | 12,500 – 13,500 Boe/d (18% NGL) |
12,500 – 13,500 Boe/d (18% NGL) |
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| Umbach horizontal wells drilled Umbach horizontal wells completed Umbach horizontal wells connected |
12 gross (12.0 net) 10 gross (10.0 net) 10 gross (10.0 net) |
12 gross (12.0 net) 10 gross (10.0 net) 11 gross (11.0 net) |
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| (1) Assumed commodity prices are approximately equal to realized prices to date and the current forward strip. | ||||
2016 Guidance History
| AECO Natural gas price |
Estimated Operations Capital |
Forecast Fourth Quarter Production |
Forecast Annual Production |
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| August 13, 2015 | $2.80/GJ | $106.0 million | 20,000 – 21,000 Boe/d | 16,000 – 19,000 Boe/d | ||||
| November 11, 2015 | $2.50/GJ | $105.0 million | 20,000 – 21,000 Boe/d | 16,000 – 18,000 Boe/d | ||||
| February 25, 2016 | $2.00/GJ | $80.0 million | 15,500 – 16,500 Boe/d | 14,000 – 15,000 Boe/d | ||||
| May 12, 2016 | $1.60/GJ | $37.0 to $42.0 million | 13,000 – 14,000 Boe/d | 12,500 – 13,500 Boe/d | ||||
| August 15, 2016 | $1.95/GJ | $36.0 to $50.0 million | 13,000 – 14,000 Boe/d | 12,500 – 13,500 Boe/d | ||||
| September 7, 2016 | $1.95/GJ | $70.0 million | 13,000 – 14,000 Boe/d | 12,500 – 13,500 Boe/d |
2017 Guidance
| September 7, 2016 | November 15, 2016 | |||
| Chicago natural gas price | US$3.00 per Mmbtu | US$3.00 per Mmbtu | ||
| AECO natural gas price | $2.65 per GJ | $2.65 per GJ | ||
| BC STN 2 natural gas price | $2.25 per GJ | $2.20 per GJ | ||
| Edmonton light oil price | Cdn$55 per Bbl | Cdn$55 per Bbl | ||
| Estimated average operating costs | $5.50 – $5.75/Boe | $5.50 – $5.75/Boe | ||
| Estimated average royalty rate (% production revenue before hedging) |
9% – 11% | 9% – 11% | ||
| Estimated operations capital (excluding acquisitions & dispositions) |
$75.0 – $80.0 million | $75.0 – $80.0 million | ||
| Estimated cash G&A net of recoveries | $5.3 million $0.85/Boe |
$5.3 million $0.85/Boe |
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| Forecast fourth quarter production | 18,000 – 20,000 Boe/d (17% NGL) |
18,000 – 20,000 Boe/d (17% NGL) |
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| Forecast annual production | 16,500 – 18,000 Boe/d (17% NGL) |
16,500 – 18,000 Boe/d (17% NGL) |
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| Umbach horizontal wells drilled Umbach horizontal wells completed Umbach horizontal wells connected |
12 gross (12.0 net) 13 gross (13.0 net) 15 gross (15.0 net) |
12 gross (12.0 net) 14 gross (14.0 net) 15 gross (15.0 net) |
Capital investment in 2016 includes $19 million for the third field compression facility which is expected to be operational in January 2017. Initial capacity will be 35 Mmcf per day which can be expanded to 70 Mmcf per day for an additional investment of $7 million. Once the expansion is completed, capacity from Storm’s three field compression facilities will exceed 150 Mmcf per day of raw gas which supports growth in corporate production to 25,000 to 27,000 Boe per day.
Capital investment in 2017 assumes a cost of $4.1 million to drill and complete a horizontal well at Umbach plus a total of $14.0 million for infrastructure expansion at Umbach which includes gathering pipelines and the remaining equipment at the third field compression facility.
Forecast production for 2017 is dependent on capital investment which may be adjusted up or down depending on commodity prices and funds flow. Hedges will continue to be layered in for 2017 and 2018 in support of planned growth which increases certainty on future funds flow.
Approximately 74% of forecast natural gas production in 2017 is covered by firm transportation agreements with the majority being capacity on the Alliance Pipeline (65% of forecast 2017 production). Including ‘priority interruptible transportation service’ (PITS) on the Alliance Pipeline, 90% of forecast 2017 production is covered. Storm’s capacity on the Alliance Pipeline reduces exposure to widening natural gas price differentials between markets in Canada and the United States (Chicago – AECO differential -US$0.54 per Mmbtu in December 2015 widened to -US$1.03 per Mmbtu in September 2016). Differentials have widened as a result of growth in western Canadian production and exceed the pipeline transportation cost which is unusual but unlikely to change until production declines or export pipeline capacity is added.
Natural gas prices in North America were very low in the first half of 2016 (AECO $1.53/GJ, NYMEX US$2.12/Mmbtu) as a result of very high levels of natural gas in storage following a warmer winter which reduced residential and commercial heating demand. However, prices have improved significantly since mid-2016 as a result of the supply/demand balance tightening in the United States. In August, the year-over-year supply/demand balance was tighter by 7 Bcf per day with natural gas production down 2 Bcf per day while demand was up 5.3 Bcf per day (notably electric power generation was +4.1 Bcf per day and LNG exports plus exports to Mexico were +1.7 Bcf per day). Most of the growth in natural gas production in the United States over the last two to three years has been from the Marcellus/Utica shales and re-initiating growth likely requires higher natural gas prices given many Marcellus/Utica producers have high cost structures plus sell natural gas at discounted prices (reflecting the higher pipeline tariffs to move natural gas to Chicago or the Gulf Coast). Recently, the warm start to the winter heating season has caused a decline in natural gas prices but the tighter supply/demand balance means it is unlikely to be a repeat of last winter where high storage levels at the end of March depressed prices. The longer term outlook appears increasingly bullish with LNG export capacity of more than 9 Bcf per day currently operating or under construction on the US Gulf Coast plus US exports to Mexico are expected to continue increasing as multiple new export pipelines and interconnections are completed over the next two years.
With 155 net sections at Umbach, there remains room for significant future growth with producing horizontal wells on only 6% of the lands (9 net sections) and proved plus probable reserves assigned on only 20% of the lands (31 net sections). The focus remains on converting this large resource into per-share growth in production and cash flow while preserving balance sheet flexibility.
Respectfully,
Brian Lavergne,
President and Chief Executive Officer
November 15, 2016
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 “funds from operations”, “funds from operations per share”, “netbacks”, “field netbacks”, “field operating income”, “total operating income”, “cash costs”, and measurements “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. In particular, funds from operations is not intended to represent, or be equivalent to, cash flow from operating activities calculated in accordance with GAAP, which is measured on the Company’s consolidated statements of cash flows. Funds from operations and similar 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, including the reconciliation between funds from operations and cash flow from operating activities, can be found in the MD&A.
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”, “expect”, “anticipate”, “intend”, “believe”, “plan”, “potential”, “outlook”, “forecast”, “estimate” 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; capacity of facilities; timing and construction of a third field compression facility and the purchase of equipment in connection therewith; hedging; 2016 and 2017 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 land and property acquisition costs, estimated general and administrative costs, estimated fourth quarter production, estimated annual production, estimated number of Umbach horizontal wells drilled, completed and starting production and estimated debt in 2016 and 2017; reserve volumes; commodity prices; production, operating and general and administrative costs; anticipated lower costs for services; anticipated higher level of run rate cash flow associated with a larger production base; natural gas sales; and improvement on controllable cash costs. 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: 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; environmental risks; competition; ability to access sufficient capital from internal and external sources; 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 MD&A for the three and nine months ended September 30, 2016.
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.
NEITHER THE TSX VENTURE EXCHANGE NOR ITS REGULATION SERVICES PROVIDER (AS THAT TERM IS DEFINED IN THE POLICIES OF THE TSX VENTURE EXCHANGE) ACCEPTS RESPONSIBILITY FOR THE ADEQUACY OR ACCURACY OF THIS PRESS RELEASE.
President & Chief Executive Officer
Donald McLean
Chief Financial Officer
Carol Knudsen
Manager, Corporate Affairs
(403) 817-6145
www.stormresourcesltd.com