CALGARY, ALBERTA--(Marketwired - Feb. 25, 2016) - Storm Resources Ltd. (TSX VENTURE:SRX) ("Storm" or the "Company") -
Storm has also filed its audited consolidated financial statements as at December 31, 2015 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, 2015, as well as reserves information at December 31, 2015, appears below and should be read in conjunction with the related financial statements and MD&A.
Highlights
Thousands of Cdn$, except volumetric and per-share amounts | Three Months to Dec. 31, 2015 |
Three Months to Dec. 31, 2014 |
Year Ended Dec. 31, 2015 |
Year Ended Dec. 31, 2014 |
|||||
FINANCIAL | |||||||||
Revenue from product sales(1) | 14,480 | 28,070 | 67,736 | 95,480 | |||||
Funds from operations(2) | 9,182 | 13,892 | 39,046 | 45,412 | |||||
Per share - basic ($) | 0.08 | 0.13 | 0.34 | 0.42 | |||||
Per share - diluted ($) | 0.08 | 0.12 | 0.34 | 0.41 | |||||
Net income (loss) | 1,850 | (7,422 | ) | (6,867 | ) | 4,855 | |||
Per share - basic ($) | 0.02 | (0.07 | ) | (0.06 | ) | 0.04 | |||
Per share - diluted ($) | 0.02 | (0.07 | ) | (0.06 | ) | 0.04 | |||
Net capital invested | 31,081 | 20,095 | 71,509 | 194,555 | |||||
Operations capital expenditures | 26,700 | 20,219 | 90,685 | 106,604 | |||||
Land and property acquisitions/ (dispositions) | 4,381 | (124 | ) | (19,176 | ) | 87,951 | |||
Debt including working capital deficiency(3) | 61,721 | 63,080 | 61,721 | 63,080 | |||||
Common shares (000s) | |||||||||
Weighted average - basic | 119,388 | 111,305 | 115,821 | 108,172 | |||||
Weighted average - diluted | 119,388 | 112,850 | 115,821 | 109,981 | |||||
Outstanding end of period - basic | 119,467 | 111,322 | 119,467 | 111,322 | |||||
OPERATIONS | |||||||||
(Cdn$ per Boe) | |||||||||
Revenue | 14.67 | 29.99 | 18.64 | 37.48 | |||||
Royalties | 0.05 | (3.69 | ) | (0.82 | ) | (5.16 | ) | ||
Production | (7.01 | ) | (8.40 | ) | (8.00 | ) | (9.33 | ) | |
Transportation | (0.79 | ) | (1.91 | ) | (1.13 | ) | (1.80 | ) | |
Field operating netback | 6.92 | 15.99 | 8.69 | 21.19 | |||||
Hedging gains (losses) | 4.20 | 0.52 | 4.20 | (1.26 | ) | ||||
General and administrative | (1.27 | ) | (1.16 | ) | (1.51 | ) | (1.50 | ) | |
Interest and finance costs | (0.54 | ) | (0.50 | ) | (0.62 | ) | (0.60 | ) | |
Funds from operations - per Boe | 9.31 | 14.85 | 10.76 | 17.83 | |||||
Barrels of oil equivalent per day (6:1) | 10,730 | 10,173 | 9,956 | 6,980 | |||||
Gas Production | |||||||||
Thousand cubic feet per day | 53,147 | 49,094 | 48,656 | 33,067 | |||||
Price (Cdn$ per Mcf) | 1.78 | 3.85 | 2.39 | 4.58 | |||||
NGL production | |||||||||
Barrels per day | 1,872 | 1,605 | 1,667 | 1,064 | |||||
Price (Cdn$ per barrel) | 33.50 | 56.15 | 36.10 | 69.90 | |||||
Oil Production | |||||||||
Barrels per day | - | 385 | 179 | 405 | |||||
Price (Cdn$ per barrel) | - | 68.01 | 50.84 | 88.10 | |||||
Wells drilled | |||||||||
Gross | 4.0 | 2.0 | 10.0 | 17.0 | |||||
Net | 4.0 | 2.0 | 10.0 | 17.0 |
(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 37 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 29 of the MD&A. |
(3) | Excludes the fair value of commodity price contracts. |
PRESIDENT'S MESSAGE
2015 FOURTH QUARTER HIGHLIGHTS
2015 YEAR END HIGHLIGHTS
2015 YEAR END RESERVE EVALUATION
Reserves | 2015 | 2014 | Change | |||
Proved Developed Producing or "PDP" (Mboe) | 20,810 | 13,487 | +54 | % | ||
Total Proved or "1P" (Mboe) | 73,434 | 59,551 | +23 | % | ||
Total Proved plus Probable or "2P" (Mboe) | 100,722 | 88,024 | +14 | % | ||
PDP as % of 2P | 21 | % | 15 | % | ||
1P as a % of 2P | 73 | % | 68 | % | ||
Reserves Per Share Outstanding at Year End | 2015 | 2014 | Change | |
PDP (Mboe per million shares) | 174 | 121 | +44 | % |
1P (Mboe per million shares) | 615 | 535 | +15 | % |
2P (Mboe per million shares) | 844 | 791 | +7 | % |
Future Development Capital ("FDC") | 2015 | 2014 | ||
1P ($M) | $ | 435,000 | $ | 448,000 |
2P ($M) | $ | 543,000 | $ | 607,000 |
FD&A Cost (all-in) | 2015 | 2014 | ||
PDP ($/Boe) | $ | 6.53 | $ | 23.01 |
1P ($/Boe) | $ | 3.38 | $ | 11.68 |
2P ($/Boe) | $ | 0.50 | $ | 9.64 |
Recycle Ratio Using FD&A Cost (all-in) | 2015 | 2014 | ||
Annual field operating netback excluding hedging | $ | 8.69 | $ | 21.19 |
PDP Recycle | 1.3X | 0.9X | ||
1P Recycle | 2.6X | 1.8X | ||
2P Recycle | 17.4X | 2.2X | ||
Net Present Value Discounted at 10% (before tax) | 2015 | 2014 | Change | |||
PDP ($M) | $ | 213,000 | $ | 199,000 | +7 | % |
1P ($M) | $ | 442,000 | $ | 493,000 | -10 | % |
2P ($M) | $ | 592,000 | $ | 684,000 | -13 | % |
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, a total of 40.4 net horizontal wells (44.0 gross) have been drilled into the Montney formation with 31.4 net being on production.
Fourth quarter production from Umbach was 10,729 Boe per day and represented 100% of corporate production in the quarter. NGL recovery was 35 barrels per Mmcf sales (57% of the NGL volume is higher priced field condensate plus pentanes recovered at the gas plant). Revenue was $14.72 per Boe ($1.78 per Mcf sales and $33.50 per barrel of NGL), transportation costs were $0.79 per Boe, royalties were $0.07 per Boe (1% of revenue), operating costs were $6.91 per Boe and the operating netback was $6.95 per Boe. The natural gas sales price in December was $0.45 per Mcf higher than what was realized in October and November.
Activity in the fourth quarter included drilling four horizontal wells (4.0 net), completing six horizontal wells (6.0 net) and pipeline connecting three horizontal wells (3.0 net). At year end, there was an inventory of six horizontal wells (6.0 net) that had not started producing (includes two completed wells).
In the first quarter of 2016, seven more horizontal wells (7.0 net) will be drilled and two horizontal wells (2.0 net) will be completed.
Storm's two operated field compression facilities (both 100% working interest) have total capacity of 80 Mmcf per day raw gas with actual throughput in December averaging 73 Mmcf per day raw gas. As a result of the low natural gas price at AECO and BC Station 2, timing to start up the third field compression facility with initial capacity of 35 Mmcf per day is being moved back to the fourth quarter of 2016 (was May 2016). The estimated total cost is unchanged at $25.0 million (expandable to 70 Mmcf per day raw gas for an additional $7.0 million). During 2015, $4.8 million was invested for site preparation and to purchase major equipment for the third facility.
Raw gas from Storm's field compression facilities is sent to the McMahon and Stoddart Gas Plants where Storm has firm processing commitments totaling 65 Mmcf per day raw gas in 2016.
Shown below is a summary of horizontal well performance and costs. On a per-stage basis, the 2015 drill and complete cost decreased by 15% from 2014 with cost reductions coming from pad drilling, improved water management practices and lower service costs. Performance to date of the 2015 wells does not fully reflect the increased level of stimulation because calendar day rates were reduced by the downtime experienced in the second half of 2015. The three most recent 2015 wells with 22 to 24 frac stages averaged 6.5 Mmcf per day gross raw gas over the first 90 calendar days, an improvement of 40% from the average 2014 horizontal well.
Year of Completion | Avg Frac Stages |
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 |
2010 - 12 7 wells |
11 | 1.9 Mmcf/d 7 hz's |
1.4 Mmcf/d 7 hz's |
1.3 Mmcf/d 7 hz's |
|
2013 6 wells |
17 | $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 |
2014 13 wells |
19 | $4.6 million ($240 K/stage) |
4.6 Mmcf/d 13 hz's |
4.2 Mmcf/d 13 hz's |
3.3 Mmcf/d 11 hz's |
2015 11 wells |
22 | $4.5 million ($205 K/stage) |
5.0 Mmcf/d 9 hz's |
3.7 Mmcf/d 3 hz's |
|
2016 4 wells |
29 |
Based on the performance of the 2014 and 2015 horizontal wells, Storm management uses a 6.3 Bcf raw gas type curve for internal budgeting purposes (type curve has the same decline profile as the type curves used by InSite in the 2015 reserve evaluation). The first year average rate is 3.6 Mmcf per day raw gas which is 640 Boe per day sales (10% shrinkage and 32 barrels of NGL per Mmcf sales). Using the actual cost of $4.8 million to drill, complete and tie in a horizontal well in 2015, the payout is approximately 32 months and the rate of return is 26% based on $2.60 per GJ at AECO, $2.10 per GJ at BC Station 2 and Cdn $53.00 per barrel for Edmonton light oil (expected longer term commodity prices with pricing held flat for the life of the well). See the presentation on Storm's website for further details.
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. The one horizontal well producing 280 Boe per day was shut in during July 2015 due to the low natural gas price at BC Station 2.
Grande Prairie Area, Northwest Alberta
Storm's remaining Alberta property at Valhalla was shut in during August 2015 as a result of the decline in the natural gas price (capable of producing 300 Boe per day).
HEDGING AND TRANSPORTATION
The purpose of Storm's commodity price hedges is to provide greater certainty regarding future cash flows and capital investment in order to support longer term growth plans. A maximum of 50% of the most recent monthly production will be hedged; anticipated production growth is not hedged. Although Storm has no oil production, approximately 80% of NGL production is priced in reference to WTI (condensate, plant pentane, and butane).
A gain of $15.3 million was realized from commodity price hedging in 2015 and the fair market value of commodity price contracts for 2016 and 2017 was $8.0 million at year end.
A summary of commodity price hedges for 2016 is provided below.
Volume | Price | ||
Crude Oil | 500 Bopd | WTI Cdn$75.00 X Cdn$90.75/Bbl | |
Natural Gas | 21,250 GJ/d (17,000 Mcf/d) 11,000 GJ/d (8,800 Mcf/d) 33,000 Mmbtu/d (27,800 Mcf/d) |
|
AECO Cdn$2.98/GJ ($3.72/Mcf) BC Stn 2 price = AECO - Cdn$0.3375/GJ Chicago price = AECO + US$0.672/Mmbtu |
Storm's transportation commitments increase from 62 Mmcf per day in 2016 to 91 Mmcf per day in 2018 (interruptible capacity on the Alliance Pipeline adds up to 25% of contracted capacity or 11 Mmcf per day in 2016 and 13 Mmcf per day in 2018).
2016 | 2017 | 2018 | ||
43.5 Mmcf/d (54,800 GJ/d) Alliance Pipeline Chicago - Cdn$1.35/GJ toll(1)(2) |
48.0 Mmcf/d (60,500 GJ/d) Alliance Pipeline Chicago - Cdn$1.35/GJ toll(1)(2) |
52.5 Mmcf/d (66,000 GJ/d) Alliance Pipeline Chicago - Cdn$1.35/GJ toll(1) |
||
9.0 Mmcf/d (11,400 GJ/d) Spectra T-north BC Stn 2(3) - Cdn$0.16/GJ toll |
24.0 Mmcf/d (30,200 GJ/d) Spectra T-north BC Stn 2(3) - Cdn$0.16/GJ toll |
29.0 Mmcf/d (36,500 GJ/d) Spectra T-north BC Stn 2 - Cdn$0.16/GJ toll |
||
9.8 Mmcf/d (12,400 GJ/d) AECO - $0.68/GJ(1) |
10.0 Mmcf/d (12,600 GJ/d) Spectra T-north & TCPL sale at AECO - $0.45/GJ toll |
(1) | Volumes sold at McMahon Gas Plant with pipeline tariff deducted from realized price. |
(2) | The Chicago - AECO differential has been fixed for 33,000 Mmbtu per day in 2016 at +US$0.672 per Mmbtu and for 35,000 Mmbtu per day in 2017 at +US$0.577 per Mmbtu. |
(3) | The AECO - BC Station 2 differential has been fixed for 11,000 GJ per day in 2016 at -$0.3375 per GJ and for 5,000 GJ per day in 2017 at -$0.445 per GJ. |
COMPARISON OF 2015 RESULTS VERSUS GUIDANCE
Shown below is a comparison of Storm's actual 2015 results to what was provided for guidance.
2015 Guidance |
Original Guidance Nov 13, 2014 |
Last Update Nov 11, 2015 |
Actual 2015 Results |
||||
AECO natural gas price | $3.25 per GJ | $2.60 per GJ | $2.55 per GJ | ||||
BC Stn 2 natural gas price | $3.00 per GJ | $1.87 per GJ | $1.70 per GJ | ||||
Edmonton light oil price | Cdn$83 per Bbl | Cdn$58 per Bbl | Cdn$57 per Bbl | ||||
Estimated average operating costs | $7.50 - $8.00 per Boe | $7.75 - $8.00 | $8.00 per Boe | ||||
Estimated average royalty rate (% production revenue before hedging) | 12% - 14 | % | 6% - 7 | % | 4 | % | |
Estimated operations capital (excluding acquisitions & dispositions) | $110.0 million | $92.0 million | $90.7 million | ||||
Estimated land and property acquisitions/(dispositions) | $0.0 million | ($19.3 million | ) | ($19.2 million | ) | ||
Estimated cash G&A net of recoveries | $5.3 million | $5.3 million | $5.5 million | ||||
Forecast fourth quarter production | 14,000 - 14,500 Boe/d (18% oil + NGL |
) | 10,000 - 12,000 (18% NGL |
) | 10,730 Boe/d (17% NGL |
) | |
Forecast annual production | 11,500 - 12,700 Boe/d (19% oil + NGL |
) | 10,000 - 11,000 (19% oil + NGL |
) | 9,956 Boe/d (19% oil + NGL |
) | |
Umbach horizontal wells: | |||||||
Drilled | 9 gross (9.0 net | ) | 10 gross (10.0 net | ) | 10 gross (10.0 net | ) | |
Completed | 14 gross (14.0 net | ) | 13 gross (13.0 net | ) | 13 gross (13.0 net | ) | |
Starting production | 16 gross (16.0 net | ) | 13 gross (13.0 net | ) | 12 gross (12.0 net | ) |
Comparing actual 2015 results to original guidance:
OUTLOOK
Production in the first quarter of 2016 is forecast to be 13,000 to 14,000 Boe per day and will largely depend on natural gas prices. Production to date in the first quarter has averaged approximately 13,500 Boe per day based on field estimates. Capital investment in the first quarter is expected to be $25.0 million.
Guidance for 2016 is being revised due to the continuing decline in commodity prices which has reduced forecast funds flow. Capital investment in 2016 will be reduced to $80 million which will result in fewer horizontal wells being drilled and completed plus the start-up of the third field compression facility at Umbach being delayed to the fourth quarter of 2016. If commodity prices remain at current levels or continue to decline, capital investment would likely be further reduced in mid-May to approximately $45 million which would result in forecast production averaging 13,000 to 14,000 Boe per day in 2016 and the third field compression facility being delayed until 2017 (requires approximately seven horizontal wells starting production in 2016 to offset declines). Revised guidance for 2016 is provided below with assumed commodity prices being approximately equal to the current forward strip.
2016 Guidance |
Original Guidance Nov 11, 2015 |
Revised Feb 25, 2016 |
||
Chicago natural gas price | US$2.20 per mmbtu | |||
AECO natural gas price | $2.50 per GJ | $2.00 per GJ | ||
BC STN 2 natural gas price | $1.90 per GJ | $1.45 per GJ | ||
Edmonton light oil price | Cdn$57 per Bbl | Cdn$46 per Bbl | ||
Estimated average operating costs | $7.00 - $7.50 per Boe | $7.00 per Boe | ||
Estimated average royalty rate (% production revenue before hedging) | 7% - 8 | % | 5% - 6 | % |
Estimated operations capital (excluding acquisitions & dispositions) | $105.0 million | $80.0 million | ||
Estimated land and property acquisitions/ (dispositions) | ||||
Estimated cash G&A net of recoveries | $5.0 million | $5.0 million | ||
Estimated funds flow | $39.0 million | |||
Forecast fourth quarter production | 20,000 - 21,000 Boe/d (17% NGL |
) | 15,500 - 16,500 Boe/d (18% NGL |
) |
Forecast annual production | 16,000 - 18,000 Boe/d (17% oil + NGL |
) | 14,000 - 15,000 Boe/d (18% oil + NGL |
) |
Umbach horizontal wells drilled | 14 gross (14.0 net | ) | 12 gross (12.0 net | ) |
Umbach horizontal wells completed | 14 gross (14.0 net | ) | 10 gross (10.0 net | ) |
Umbach horizontal wells connected | 16 gross (16.0 net | ) | 12 gross (12.0 net | ) |
Capital investment in 2016 will be directed entirely to Umbach and will include $48 million for drilling and completions plus $24 million for infrastructure (includes remaining $21 million for the third field compression facility). Infrastructure expansion is being funded with debt which is an investment in a long life asset (value doesn't decline with time).
Natural gas sales will be more diversified going forward with Storm's contracted capacity on the Alliance Pipeline for delivery to Chicago. Using forecasted natural gas production in 2016, approximately 22% will be sold at Chicago pricing, 65% sold at an AECO price less a fixed differential and the remaining 13% at the Chicago or BC Station 2 price (whichever is higher). This is much different from 2015 where approximately 50% received the BC Station 2 price which reduced the realized natural gas price and operating netback in the second half of the year.
The high quality and competitive advantages of Storm's Montney land position at Umbach (shallow depth and liquids rich) are reflected in the 2015 all-in PDP FD&A cost of $6.53 per Boe which resulted in a recycle ratio of 1.6X using the 2015 funds flow netback. This is a significant achievement given the low netback in 2015 and reflects Storm's sustainability in the current low commodity price environment. An important objective in 2016 is to achieve further reductions in the PDP FD&A cost in order to remain competitive. For evaluating capital efficiency, PDP FD&A has become a better metric than 1P or 2P FD&A given that it isn't influenced by the accuracy of estimates for future development capital (including required infrastructure).
Storm is still in the early stages of delineating the large liquids rich resource in the Montney formation at Umbach. At the end of 2015, only 20% of Storm's land position was assigned 2P reserves (31 net sections of 155 net sections) which leaves room for significant future reserve growth from the remaining lands which appear to be highly prospective given horizontal well results on offsetting acreage. Over time, data from the wells that have been drilled on offsetting lands is likely to result in reserve additions on Storm's lands.
Storm's results in 2015 reflect a focus on converting Montney resource at Umbach into production and cash flow plus reducing the cost structure (both controllable cash costs and cost of PDP reserve additions). Looking ahead to 2016, the business environment for oil and gas producers continues to become more challenging with the ongoing decline in commodity prices. Storm plans to weather the storm by continuing to build a business for the longer term with a focus on operational excellence which will include:
Storm's land position in the Horn River Basin continues to be a core, long-term asset with significant leverage to higher natural gas prices.
In closing, I would like to thank Storm's employees for their efforts in 2015 which resulted in record levels of production and significant improvements in capital efficiency. In addition, the invaluable advice, guidance, and support provided by Storm's Directors continues to be very much appreciated.
Respectfully,
Brian Lavergne, President and Chief Executive Officer
February 25, 2016
RESERVES AT DECEMBER 31, 2015
Storm's year-end reserve evaluation effective December 31, 2015 was prepared by InSite Petroleum Consultants Ltd. ("InSite") under date of February 16, 2016. InSite has evaluated all of Storm's crude oil, NGL and natural gas reserves. The InSite price forecast at December 31, 2015 was used to determine all estimates of future net revenue (also referred to as net present value or 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 ("NI") 51-101. In addition to the information disclosed in this report, more detailed information will be included in Storm's Annual Information Form.
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, 2015, which will include complete disclosure of oil and gas reserves and other information in accordance with NI 51-101, will be contained within the Annual Information Form 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, 2015
(Before deduction of royalties payable, not including royalties receivable)
Light Crude Oil (Mbbls) |
Sales Gas (Mmcf) |
NGL (Mbbls) |
6:1 Oil Equivalent (Mboe) |
|
Proved producing | - | 104,004 | 3,476 | 20,810 |
Proved non-producing | - | 5,926 | 196 | 1,183 |
Total proved developed | - | 109,930 | 3,672 | 21,993 |
Proved undeveloped | - | 258,552 | 8,349 | 51,441 |
Total proved | - | 368,483 | 12,020 | 73,434 |
Probable additional | - | 138,588 | 4,190 | 27,288 |
Total proved plus probable | - | 507,071 | 16,210 | 100,722 |
Numbers in this table may not add due to rounding.
Reserve Life Index ("RLI") Using Fourth Quarter Production
2015 | 2014 | 2013 | |
PDP | 5 years | 4 years | 4 years |
1P | 19 years | 16 years | 12 years |
2P | 26 years | 24 years | 23 years |
Gross Company Reserve Reconciliation for 2015
(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, 2014 - opening balance | 13,487 | 59,551 | 28,473 | 88,024 | ||||
Acquisitions | - | - | - | - | ||||
Discoveries | - | - | - | - | ||||
Extensions | 1,714 | 14,950 | 4,507 | 19,457 | ||||
Category transfer | 9,471 | - | - | - | ||||
Dispositions | (1,450 | ) | (1,768 | ) | (2,377 | ) | (4,145 | ) |
Technical revisions | 1,221 | 6,700 | (1,218 | ) | 5,482 | |||
Economic factors | - | (2,364 | ) | (2,098 | ) | (4,462 | ) | |
Production | (3,634 | ) | (3,634 | ) | - | (3,634 | ) | |
December 31, 2015 - closing balance | 20,810 | 73,434 | 27,288 | 100,722 |
Numbers in this table may not add due to rounding.
Future Development Costs ("FDC")
Undiscounted Proved Expenditures ($M) |
Undiscounted Proved Plus Probable Expenditures (M$) |
|
2016 | 41,300 | 41,300 |
2017 | 98,379 | 98,379 |
2018 | 109,627 | 118,262 |
2019 | 83,591 | 119,343 |
2020 | 79,591 | 136,072 |
2021 | 22,954 | 29,909 |
Total FDC - undiscounted | 435,442 | 543,266 |
Total FDC - discounted at 10% | 340,521 | 413,996 |
HRB | $12.3 million | $28.9 million |
Umbach | $423.1 million | $514.4 million |
Note: InSite escalates capital costs at 2% per year after 2016.
Numbers in this table may not add due to rounding.
All-In Finding, Development and Acquisition Costs ("FD&A")
(including acquisitions, dispositions and revisions)
Proved Developed Producing FD&A Cost (All-In) | 2015 | 2014 | 2013 | 3 Year Total | |||||||
Net capital investment (000s) | $ | 71,509 | $ | 194,555 | $ | 52,444 | $ | 318,508 | |||
Total capital | $ | 71,509 | $ | 194,555 | $ | 52,444 | $ | 318,508 | |||
Total reserve additions (Mboe) | 10,956 | 8,456 | 3,047 | 22,457 | |||||||
All-in PDP FD&A cost | $ | 6.53 | $ | 23.01 | $ | 17.21 | $ | 14.18 | |||
Total Proved FD&A Cost (All-In) | 2015 | 2014 | 2013 | 3 Year Total | |||||||
Net capital investment (000s) | $ | 71,509 | $ | 194,555 | $ | 52,444 | $ | 318,508 | |||
Change in FDC (000s) | (12,275 | ) | 288,242 | 56,600 | 332,567 | ||||||
Total capital including change in FDC (000s) | $ | 59,234 | $ | 482,797 | $ | 109,044 | $ | 651,075 | |||
Total reserve additions (Mboe) | 17,517 | 41,334 | 8,270 | 67,121 | |||||||
All-in 1P FD&A cost (per Boe) | $ | 3.38 | $ | 11.68 | $ | 13.19 | $ | 9.70 | |||
Total Proved Plus Probable FD&A Cost (All-In) | 2015 | 2014 | 2013 | 3 Year Total | |||||||
Net capital investment (000s) | $ | 71,509 | $ | 194,555 | $ | 52,444 | $ | 318,508 | |||
Change in FDC (000s) | (63,288 | ) | 287,686 | 89,829 | 314,227 | ||||||
Total capital including change in FDC (000s) | $ | 8,221 | $ | 482,241 | $ | 142,273 | $ | 632,735 | |||
Total reserve additions (Mboe) | 16,332 | 50,030 | 14,538 | 80,900 | |||||||
All-In 2P FD&A cost (per Boe) | $ | 0.50 | $ | 9.64 | $ | 9.79 | $ | 7.82 | |||
Recycle Ratio | |||||||||||
Operating netback per Boe excluding hedging | $ | 8.68 | $ | 21.19 | $ | 20.43 | $ | 15.00 | |||
Recycle ratio for all-in PDP FD&A cost | 1.3 | 0.9 | 1.2 | 1.1 | |||||||
Recycle ratio for all-in 1P FD&A cost | 2.6 | 1.8 | 1.5 | 1.5 | |||||||
Recycle ratio for all-in 2P FD&A cost | 17.4 | 2.2 | 2.1 | 1.9 |
NI 51-101 Finding and Development Costs ("F&D")
(excluding acquisitions, dispositions, revisions)
Total Proved F&D Cost | 2015 | 2014 | 2013 | 3 Year Total |
||||
Capital expenditures excluding acquisitions and dispositions (000s) | $ | 95,099 | $ | 106,604 | $ | 67,450 | $ | 269,153 |
Change in FDC (000s) | 18,604 | 288,242 | 77,282 | 384,128 | ||||
Total capital including change in FDC (000s) | $ | 113,703 | $ | 394,846 | $ | 144,732 | $ | 653,281 |
Reserve additions excluding acquisitions, dispositions, and revisions (Mboe) | 14,950 | 38,707 | 10,356 | 64,013 | ||||
1P F&D cost (per Boe) | $ | 7.61 | $ | 10.20 | $ | 13.98 | $ | 10.21 |
Total Proved Plus Probable F&D Cost | 2015 | 2014 | 2013 | 3 Year Total |
||||
Capital expenditures excluding acquisitions and dispositions (000s) | $ | 95,099 | $ | 106,604 | $ | 67,450 | $ | 269,153 |
Change in FDC (000s) | 30,717 | 287,686 | 134,903 | 453,306 | ||||
Total capital including change in FDC (000s) | $ | 125,816 | $ | 394,290 | $ | 202,353 | $ | 722,459 |
Reserve additions excluding acquisitions, dispositions, and revisions (Mboe) | 19,457 | 45,001 | 18,823 | 83,281 | ||||
2P F&D cost | $ | 6.47 | $ | 8.76 | $ | 10.75 | $ | 8.67 |
Net Present Value Summary (before tax) as at December 31, 2015
Benchmark oil and NGL prices used are adjusted for quality of oil or NGL produced and for transportation costs. The calculated NPVs include a deduction for estimated future well abandonment costs.
Undiscounted (000s) |
Discounted at 5% (000s) |
Discounted at 10% (000s) |
Discounted at 15% (000s) |
Discounted at 20% (000s) |
|
Proved producing | 341,642 | 263,305 | 213,054 | 178,793 | 154,232 |
Proved non-producing | 17,777 | 13,009 | 10,051 | 8,092 | 6,724 |
Total proved developed | 359,419 | 276,314 | 223,105 | 186,885 | 160,956 |
Proved undeveloped | 627,336 | 367,602 | 218,610 | 128,126 | 70,612 |
Total proved | 986,755 | 643,916 | 441,715 | 315,012 | 231,567 |
Probable additional | 516,188 | 266,667 | 150,273 | 90,456 | 57,169 |
Total proved plus probable | 1,502,943 | 910,582 | 591,989 | 405,467 | 288,736 |
Numbers in this table may not add due to rounding.
Net Present Value Summary (after tax) as at December 31, 2015
Benchmark oil and NGL prices used are adjusted for quality of oil or NGL produced and for transportation costs. The calculated NPVs each include a deduction for estimated future well abandonment costs.
Undiscounted (000s) |
Discounted at 5% (000s) |
Discounted at 10% (000s) |
Discounted at 15% (000s) |
Discounted at 20% (000s) |
|
Proved producing | 341,642 | 263,305 | 213,054 | 178,793 | 154,232 |
Proved non-producing | 17,777 | 13,009 | 10,051 | 8,092 | 6,724 |
Total proved developed | 359,419 | 276,314 | 223,105 | 186,885 | 160,956 |
Proved undeveloped | 480,971 | 280,602 | 164,057 | 92,379 | 46,319 |
Total proved | 840,390 | 556,916 | 387,162 | 279,264 | 207,275 |
Probable additional | 382,688 | 195,748 | 108,701 | 64,148 | 39,522 |
Total proved plus probable | 1,223,078 | 752,663 | 495,863 | 343,412 | 246,797 |
Numbers in this table may not add due to rounding.
InSite Escalating Price Forecast as at December 31, 2015
WTI Crude Oil (US$/Bbl) |
Edmonton Par Crude Oil (Cdn$/Bbl) |
Henry Hub Natural Gas (US$/Mmbtu) |
AECO Natural Gas (Cdn$/Mmbtu) |
|
2016 | 45.00 | 55.64 | 2.50 | 2.71 |
2017 | 55.00 | 68.33 | 3.00 | 3.27 |
2018 | 65.00 | 78.23 | 3.50 | 3.74 |
2019 | 70.00 | 81.22 | 3.75 | 3.87 |
2020 | 75.00 | 85.06 | 4.00 | 4.05 |
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", "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; the effect on the Company of the operations capital expenditures being reduced in 2016; hedging; 2015 and 2016 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 acquisitions costs, estimated general and administrative costs, estimated first quarter production, estimated annual production, estimated number of Umbach horizontal wells drilled, completed and starting production and estimated debt in 2015 and 2016; reserve volumes; capital expenditures; royalties; financing; commodity prices; anticipated lower costs for services; natural gas sales; improvement on controllable cash costs; and production, operating and general and administrative 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 months and year ended December 31, 2015.
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.
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