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TSXV:SRX | TSX Venture | Common Stock |
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CALGARY, ALBERTA--(Marketwired - Mar 6, 2014) - Storm Resources Ltd. (TSX-VENTURE:SRX)
Storm has also filed its audited consolidated financial statements as at December 31, 2013 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, 2013, as well as reserve information at December 31, 2013, appears below and should be read in conjunction with the related financial statements and MD&A.
Highlights
Thousands of Cdn$, except volumetric and per share amounts | Three Months Ended December 31, 2013 | Three Months Ended December 31, 2012 | Year Ended December 31, 2013 | Year Ended December 31, 2012 | |||||
FINANCIAL | |||||||||
Gas sales | 7,807 | 3,416 | 21,019 | 8,054 | |||||
NGL sales | 4,483 | 1,597 | 13,124 | 4,466 | |||||
Oil sales | 3,090 | 5,399 | 15,435 | 19,793 | |||||
Revenue from product sales(1) | 15,380 | 10,412 | 49,578 | 32,313 | |||||
Funds from operations(2) | 7,501 | 5,016 | 21,949 | 13,387 | |||||
Per share - basic ($) | 0.09 | 0.08 | 0.30 | 0.24 | |||||
Per share - diluted ($) | 0.09 | 0.08 | 0.30 | 0.24 | |||||
Net loss | (25,174 | ) | (2,320 | ) | (26,203 | ) | (6,574 | ) | |
Per share - basic ($) | (0.34 | ) | (0.04 | ) | (0.36 | ) | (0.12 | ) | |
Per share - diluted ($) | (0.34 | ) | (0.04 | ) | (0.36 | ) | (0.12 | ) | |
Adjusted net income (loss) before reduction in carrying amount of property and equipment | 826 | (2,320 | ) | (203 | ) | (6,574 | ) | ||
Per share - basic and diluted ($) | 0.01 | (0.04 | ) | 0.00 | (0.12 | ) | |||
Operations capital expenditures | 11,380 | 10,016 | 67,410 | 26,868 | |||||
Acquisitions and dispositions | - | (1,239 | ) | (14,966 | ) | 139,208 | |||
Debt including working capital deficiency | 12,059 | 44,696 | 12,059 | 40,376 | |||||
Weighted average common shares outstanding (000s) | |||||||||
Basic | 81,994 | 61,824 | 73,391 | 56,067 | |||||
Diluted | 81,994 | 61,824 | 73,391 | 56,067 | |||||
Common shares outstanding (000s) | |||||||||
Basic | 87,483 | 61,824 | 87,483 | 61,824 | |||||
Fully diluted | 91,379 | 64,547 | 91,379 | 64,547 | |||||
OPERATIONS | |||||||||
Oil equivalent (6:1) | |||||||||
Barrels of oil equivalent (000s) | 439 | 259 | 1,328 | 825 | |||||
Barrels of oil equivalent per day | 4,773 | 2,815 | 3,637 | 2,254 | |||||
Average selling price (Cdn$ per Boe)(1) | 35.03 | 40.19 | 37.34 | 39.14 | |||||
Gas production | |||||||||
Thousand cubic feet (000s) | 2,015 | 987 | 5,783 | 3,053 | |||||
Thousand cubic feet per day | 21,898 | 10,728 | 15,843 | 8,342 | |||||
Average selling price (Cdn$ per Mcf) | 3.88 | 3.46 | 3.63 | 2.64 | |||||
NGL Production | |||||||||
Barrels (000s) | 64 | 25 | 187 | 67 | |||||
Barrels per day | 695 | 274 | 512 | 185 | |||||
Average selling price (Cdn$ per barrel) | 70.10 | 63.27 | 70.29 | 66.17 | |||||
Oil Production | |||||||||
Barrels (000s) | 39 | 69 | 177 | 249 | |||||
Barrels per day | 428 | 753 | 485 | 679 | |||||
Average selling price (Cdn$ per barrel)(1) | 78.47 | 77.93 | 87.16 | 79.53 | |||||
Wells drilled | |||||||||
Gross | 1.0 | 2.0 | 9.0 | 6.0 | |||||
Net | 1.0 | 1.2 | 8.6 | 4.4 | |||||
(1) Excludes hedging gains and losses.
(2) Funds from operations and funds from operations per share are non-GAAP measurements. See discussion of Non-GAAP Measurements on page 16 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 26 of the MD&A.
President's Message
2013 FOURTH QUARTER AND YEAR-END HIGHLIGHTS
OPERATIONS REVIEW
Storm has a focused asset base with large land positions in resource plays at Umbach and in the HRB which have multi-year drilling upside while the Grande Prairie area, with its shallow decline, provides cash flow available for investment.
Umbach, Northeast British Columbia
Storm's land position at Umbach is prospective for liquids-rich natural gas from the Montney formation and currently totals 140 net sections (168 gross sections) or 98,000 net acres. There are three project areas at Umbach:
To date, Storm has been focused on exploiting the upper Montney although the middle and lower Montney may also be productive. Since entering the area in 2010, and including the lands acquired in January 2014, Storm has invested $108 million to acquire this land position ($2,750 per hectare or $1,100 per acre).
Production at Umbach grew to 3,262 net Boe per day (18% liquids) in the fourth quarter as a result of five Montney horizontal wells (4.6 net) that started production during August to November. Fourth quarter NGL recovery was 40 barrels per Mmcf sales or 629 barrels per day with approximately 60% being higher priced condensate plus pentanes. The operating netback in the fourth quarter was $21.74 per Boe with revenue, after deducting transportation costs, of $31.10 per Boe ($3.52 per Mcf sales and $67.49 per barrel of NGL), a royalty rate of 3%, and operating costs of $8.36 per Boe. Continuing production growth from the 100% working interest lands at Umbach South is expected to result in operating costs decreasing to approximately $7.00 per Boe in 2014.
Activity in the fourth quarter included converting a standing vertical well to a water disposal well, drilling one Montney horizontal well (1.0 net), completing one Montney horizontal well (1.0 net), and pipeline connecting two Montney horizontal wells (2.0 net) which started producing on October 19th and November 19th. To date in the first quarter, two Montney horizontal wells (2.0 net) have been drilled and two Montney horizontal wells have been completed with one starting production in late February.
A total of 18 horizontal wells have been drilled in the upper Montney at Umbach (14.4 net) and there are 14 producing horizontal wells (10.8 net). Production performance has continued to improve based on a comparison of operated day rates over the first 30 and 90 days (operated day rates exclude days where wells were shut in due to capacity constraints):
Start of Production | Frac Stages | 30-Day Average Mmcf Per Day | 90-Day Average Mmcf Per Day | 1st Year Average Mmcf Per Day | |||
Hz's 1 - 5 | 60% WI | Umbach North | Mar/11 - Oct/12 | 7 - 11 | 2.7 Mmcf/d 5 hz's | 2.1 Mmcf/d 5 hz's | 1.4 Mmcf/d 5 hz's |
Hz's 6 - 8 | 60% WI | Umbach North | Nov/12 - Aug/13 | 14 - 16 | 3.3 Mmcf/d 3 hz's | 2.8 Mmcf/d 3 hz's | not available |
Hz's 10 - 14 | 100% WI | Umbach South | Apr/13 - Nov/13 | 17 - 18 | 4.2 Mmcf/d 5 hz's | 3.7 Mmcf/d 3 hz's | not available |
Comparing operated day rates over 30 and 90 days and using the InSite Petroleum Consultant Ltd. ("InSite") 2P type curve used in the 2013 year-end reserve evaluation, Storm management estimates that the most recent horizontal wells (10 to 14) will average 2.4 Mmcf per day in the first year with ultimate recovery of 4.4 Bcf.
Cost to drill and complete horizontal wells in 2013 averaged $4.6 million with the drilling cost averaging $2.2 million and the completion cost averaging $2.4 million. Tie-in costs have been approximately $0.5 million per horizontal well, not including cost of longer gathering pipelines to connect multi-well pads to field compression facilities. A decrease in costs is anticipated in 2014 with a larger program and with more horizontal wells being drilled from common pads.
Total investment in infrastructure in 2013 at Umbach was approximately $12.6 million which included the acquisition of field compression for $4.5 million plus construction of 18 kilometres of larger diameter 8-inch and 10-inch field gathering pipelines. In 2014, an additional $19.0 million will be invested in infrastructure which includes $5.0 million for larger diameter gathering pipelines plus $14.0 million to construct a second field compression facility with an initial capacity of 24 Mmcf per day. Capacity of the new field compression facility is expandable to 48 Mmmcf per day for an additional investment of $9.0 million with this expected to occur in 2015.
At pricing of $3.50 per GJ for natural gas and Cdn$89.00 per barrel for Edmonton Par (WTI US$93.00/Bbl, FX Cdn$0.92), the estimated field netback is $21.00 per Boe. With this pricing held constant, Storm management estimates that horizontal wells have an unrisked half cycle rate of return of 37% (1.9 years to payout) based on a first year average rate of 2.4 Mmcf per day gross raw gas (430 Boe per day), ultimate recovery of 4.4 Bcf gross raw gas per horizontal well, NGL recovery of 35 barrels per Mmcf sales (10% shrinkage), and $5.0 million to drill, complete and tie in a horizontal well.
On January 31, 2014, Storm closed the acquisition of two producing Montney horizontal wells and 29 sections of undeveloped land for a total cost of $87.9 million. The allocation of the purchase price was $61.5 million for nine sections with production, reserves and 35 horizontal drilling locations, and $26.4 million for the remaining 20 sections ($4,700 per hectare or $1,880 per acre). Highlights of the acquisition are as follows:
Horn River Basin, Northeast British Columbia
Storm has a 100% working interest in 123 sections in the HRB (81,000 net acres) which is prospective for natural gas from the Muskwa, Otter Park and Evie/Klua shales. Fourth quarter production averaged 363 Boe per day at an operating netback of $11.59 per Boe. Wellsite compression was installed in November 2013 and production has increased to average 400 Boe per day to date in the first quarter of 2014. Production is from one horizontal well with 12 fracture stimulations which currently produces 2.7 Mmcf per day gross raw gas with cumulative production of 3.8 Bcf gross raw gas since start-up in March 2011. A second horizontal well was also drilled in 2011 and is awaiting completion with timing dependent on natural gas pricing.
A resource evaluation completed by InSite effective December 31, 2011 estimates that the best estimate of DPIIP in the core producing area is 3.1 Tcf gross raw gas with the best estimate of contingent resources being 616 Bcf. The evaluated area includes 30 sections at a 100% working interest and represents 22% of Storm's total land holdings in the HRB. Commerciality has been proven across the core producing area with a horizontal well that has been producing for 30 months plus two vertical wells that were completed and tested with final test rates of 900 Mcf per day over the final 24 hours of each flow test.
Grande Prairie Area, Northwest Alberta and Northeast British Columbia
Production in the fourth quarter averaged 1,147 Boe per day (44% oil plus NGL) at an operating netback of $21.65 per Boe. No capital was invested in this area in the fourth quarter and minimal activity is planned during 2014. Cash flow from this area will continue to be re-invested to grow production at Umbach.
HEDGING UPDATE
Current commodity price hedges for 2014 include 11,500 Mcf per day (14,000 GJ per day) of natural gas with an average floor price of approximately $4.12 per Mcf and an average ceiling price of $4.34 per Mcf (AECO monthly index $3.39 per GJ for floor and $3.57 per GJ for ceiling). In addition, an oil price of WTI Cdn$101.89 per barrel (WTI price in $US per barrel converted to $Cdn per barrel) has been fixed on 338 barrels per day. It is likely that this hedge position will be expanded with the objective of ensuring that a decrease in commodity prices does not have a significant impact on capital investment and growth over the next 12 to 18 months.
COMPARISON OF 2013 RESULTS VERSUS GUIDANCE
Shown below is a comparison of Storm's actual 2013 results to guidance provided during 2013.
2013 Actual Results | 2013 Guidance November 14, 2013 | 2013 Guidance May 15, 2013 | 2013 Guidance February 28, 2013 | |||||
Year-end adjusted debt plus working capital deficiency(1) | $12.1 million | $40.0 million | $37.0 million | $44.0 million | ||||
Average operating costs | $10.86 per Boe | $10 - $11/Boe | $10 - $11/Boe | $10 - $11/Boe | ||||
Average royalty rate (on revenue before hedging) | 12.2 | % | 14 | % | 13% - 14 | % | 11% - 12 | % |
Operations capital | $67.5 million | $62.0 million | $62.0 million | $40.0 million | ||||
Asset dispositions | $19.5 million | $19.5 million | $19.5 million | $20.0 million | ||||
Asset acquisitions | $4.5 million | $4.5 million | $4.5 million | $4.5 million | ||||
Cash G&A | $4.0 million | not provided | $3.7 million | $3.9 million | ||||
Exit or fourth quarter average production | 4,773 Boe/d (24% oil + NGL | ) | 4,500-5,000 Boe/d (24% oil + NGL | ) | 4,500-5,000 Boe/d (25% oil + NGL | ) | 4,000-4,500 Boe/d (25% oil + NGL | ) |
(1) Includes value of publicly listed securities.
Actual operations capital investment in 2013 of $67.5 million was $5.5 million higher than most recent guidance of $62.0 million because of a casing failure during completion of a horizontal well at Umbach in the fourth quarter ($3.0 million) and because the drilling of one horizontal well at Umbach was advanced into the fourth quarter of 2013 instead of being drilled in 2014 ($2.5 million). Year-end adjusted debt was lower as the result of receiving net proceeds totaling $31.9 million from two equity financings that closed November 19, 2013.
OUTLOOK
Production in January and February averaged 4,970 Boe per day based on field estimates and first quarter production is forecast to be 5,000 Boe per day. Production is expected to be 5,000 to 5,500 Boe per day until September 2014 when the new facility at Umbach will be operational.
Storm's guidance for 2014 remains unchanged from what was provided on January 23, 2014 and is set forth below.
2014 Guidance | |||
Estimated year-end debt plus working capital deficiency(1) | $ | 50.0 million | |
Estimated average operating costs | $ | 8.00 - $9.00 per Boe | |
Estimated average royalty rate (on production revenue before hedging) | 14% - 15 | % | |
Estimated operations capital, excluding acquisitions & dispositions | $ | 78.0 million | |
Estimated acquisitions | $ | 87.9 million | |
Estimated cash G&A net of recoveries | $ | 4.0 million | |
Forecast fourth quarter average production | 7,500 - 7,900 Boe/d | ||
(20% oil + NGL | ) | ||
Forecast average annual production | 5,500 - 6,500 Boe/d | ||
(21% oil + NGL | ) |
(1) Includes value of publicly listed securities.
Major expenditures included in operations capital investment for 2014 include:
This level of investment is forecast to increase Storm's fourth quarter 2014 production to 7,500 to 7,900 Boe per day which represents 60% growth on a year-over-year basis.
Guidance for 2014 assumes an average natural gas price at AECO of $3.75 per GJ and an Edmonton Par oil price of Cdn$90 per barrel. This reflects estimated first quarter pricing of AECO $5.00 per GJ and Edmonton Par Cdn$98 per barrel. Adjusted net debt is forecasted to be $50.0 million at the end of 2014 (including public company investments), which would be approximately 1.0 times annualized funds from operations in the fourth quarter of 2014.
At Umbach, Storm is still in the early stages of delineating a large, higher quality, liquids-rich resource in the Montney formation. NGL recovery increases revenue and the relatively shallow depth (1,400 to 1,600 metres) results in a lower drilling and completion cost with both providing Storm with a competitive advantage. Significant future reserve growth is expected given 2P reserves have been assigned to the upper Montney on only 8% of Storm's land position at Umbach. In addition, showing that the middle and lower Montney are also productive and sustained improvements in horizontal well productivity would also lead to reserve additions. With a strong balance sheet and a plan in place to further expand owned and operated infrastructure, continued rapid growth is expected from Umbach during 2014 and 2015.
Storm's land position in the HRB continues to be a core, long-term asset with significant leverage to higher natural gas prices.
Capital investment will be reviewed mid-year and, should natural gas prices remain elevated and horizontal well performance at Umbach continue to meet or exceed expectations, it is likely that capital investment would be increased in the second half of 2014 and forecast fourth quarter production would also be increased.
In closing, I would like to thank Storm's employees for their effort and hard work in 2013 and Storm's Directors for their advice and guidance. A lot was accomplished in 2013 and we look forward to providing updates on our progress throughout 2014.
Respectfully,
Brian Lavergne, President and Chief Executive Officer
March 6, 2014
Discovered-Petroleum-Initially-in-Place ("DPIIP") - is defined in the Canadian Oil and Gas Evaluation Handbook ("COGEH") as the quantity of hydrocarbons that are estimated to be in place within a known accumulation. DPIIP is divided into recoverable and unrecoverable portions, with the estimated future recoverable portion classified as reserves and contingent resources. There is no certainty that it will be economically viable or technically feasible to produce any portion of this DPIIP except for those portions identified as proved or probable reserves.
Contingent Resources - are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project at an early stage of development. Estimates of contingent resources are estimates only; the actual resources may be higher or lower than those calculated in the independent evaluation. There is no certainty that the resources described in the evaluation will be commercially produced.
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.
Reserves at December 31, 2013
Storm's year-end reserve evaluation effective December 31, 2013 was prepared by InSite Petroleum Consultants Ltd. ("InSite") under date of February 24, 2014. InSite has evaluated all of Storm's crude oil, NGL and natural gas reserves. The InSite price forecast at December 31, 2013 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 future development costs.
(2) Debt adjusted calculation increases 2013 year-end debt from $12.1 million to $44.7 million to equal the 2012 year-end debt by buying back 8 million shares at $4.05 per share (Storm's December 31, 2013 closing share price).
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, 2013, 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, 2013 | ||||
(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 | 1,123 | 32,719 | 1,003 | 7,579 |
Proved non-producing | - | 123 | 2 | 22 |
Total proved developed | 1,123 | 32,842 | 1,005 | 7,601 |
Proved undeveloped | 300 | 65,758 | 1,903 | 13,163 |
Total proved | 1,423 | 98,600 | 2,908 | 20,764 |
Probable additional | 870 | 99,177 | 2,378 | 19,777 |
Total proved plus probable | 2,293 | 197,777 | 5,286 | 40,541 |
Gross Company Reserve Reconciliation for 2013 | ||||||
(Gross company interest reserves before deduction of royalties payable) | ||||||
6:1 Oil Equivalent (Mboe) | ||||||
Total Proved | Probable | Proved plus Probable | ||||
December 31, 2012 - opening balance | 13,822 | 13,509 | 27,331 | |||
Acquisitions | - | - | - | |||
Discoveries | - | - | - | |||
Extensions | 10,356 | 8,467 | 18,823 | |||
Dispositions | (859 | ) | (278 | ) | (1,137 | ) |
Technical revisions | (78 | ) | (226 | ) | (304 | ) |
Economic factors | (1,149 | ) | (1,695 | ) | (2,844 | ) |
Production | (1,328 | ) | - | (1,328 | ) | |
December 31, 2013 - closing balance | 20,764 | 19,777 | 40,541 | |||
Future Development Costs ("FDC") | |||
Proved | |||
HRB | 2.0 net horizontals plus infrastructure | $ | 34.9 million |
Umbach | 20.6 net horizontals plus infrastructure | $ | 117.0 million |
Grande Prairie | 3.0 net horizontals at Grimshaw | $ | 7.6 million |
Total | $ | 159.5 million | |
Proved Plus Probable Additional | |||
HRB | 5.0 net horizontals plus infrastructure | $ | 83.8 million |
Umbach | 36.0 net horizontals plus infrastructure | $ | 197.9 million |
Grande Prairie | 5.0 net horizontals at Grimshaw; 5.0 net horizontals at GP Montney; and 1.0 net horizontal at GP Dunvegan | $ 37.2 million | |
Total | $ | 318.9 million | |
Proved Expenditures | Proved Plus Probable Additional Expenditures | |||
2014 | $ | 62,950 | $ | 67,800 |
2015 | $ | 13,107 | $ | 75,888 |
2016 | $ | 48,472 | $ | 63,454 |
2017 | $ | 34,946 | $ | 78,572 |
2018 | $ | - | $ | 33,155 |
2019 | $ | - | $ | - |
Total FDC - undiscounted | $ | 159,475 | $ | 318,869 |
Total FDC - discounted at 10% | $ | 134,383 | $ | 259,220 |
Note: InSite escalates capital costs at 2% per year after 2014.
NI 51-101 Finding and Development Costs
Total Proved Finding and Development Cost | 2013 | 2012 | 2011 | 3 Year Total | ||||
Capital expenditures excluding acquisitions and dispositions (000s) | $ | 67,450 | $ | 26,868 | $ | 25,360 | $ | 119,768 |
Net change in FDC (000s) | 77,282 | 30,863 | 25,541 | 133,686 | ||||
Total capital including the net change in future capital (000s) | $ | 144,732 | $ | 57,731 | $ | 50,901 | $ | 253,364 |
Reserve additions excluding acquisitions, dispositions, revisions and economic factors (Mboe) | 10,356 | 4,067 | 2,505 | 16,928 | ||||
Total proved finding and development costs (per Boe) | $ | 13.98 | $ | 14.20 | $ | 20.32 | $ | 14.97 |
Total Proved Plus Probable Finding and Development Cost | 2013 | 2012 | 2011 | 3 Year Total | ||||
Capital expenditures excluding acquisitions and dispositions (000s) | $ | 67,450 | $ | 26,868 | $ | 25,360 | $ | 119,678 |
Net change in FDC (000s) | 134,903 | 40,341 | 51,725 | 226,969 | ||||
Total capital including the net change in future capital (000s) | $ | 202,353 | $ | 67,209 | $ | 77,085 | $ | 346,647 |
Reserve additions excluding acquisitions, dispositions, revisions and economic factors (Mboe) | 18,823 | 5,514 | 5,278 | 29,615 | ||||
Total proved plus probable finding and development costs (per Boe) | $ | 10.75 | $ | 12.19 | $ | 14.60 | $ | 11.71 |
All-In Finding, Development and Acquisition Costs
Total Proved All-In Finding, Development and Acquisition Cost including FDC, Acquisitions, Dispositions, Revisions | 2013 | 2012 | 2011 | 3 Year Total | ||||
Capital expenditures including acquisitions and dispositions (000s) | $ | 52,444 | $ | 166,076 | $ | 40,795 | $ | 259,315 |
Net change in FDC (000s) | 56,600 | 72,655 | 25,541 | 154,796 | ||||
Total capital including the net change in future capital (000s) | $ | 109,044 | $ | 238,731 | $ | 66,336 | $ | 414,111 |
Reserve additions including acquisitions, dispositions revisions and economic factors (Mboe) | 8,270 | 10,927 | 3,178 | 22,375 | ||||
All-in total proved finding and development costs (per Boe) | $ | 13.19 | $ | 21.85 | $ | 20.87 | $ | 18.51 |
Total Proved Plus Probable All-In Finding, Development and Acquisition Cost including FDC, Acquisitions, Dispositions, Revisions | 2013 | 2012 | 2011 | 3 Year Total | ||||
Capital expenditures including acquisitions and dispositions (000s) | $ | 52,444 | $ | 166,076 | $ | 40,795 | $ | 259,315 |
Net change in FDC (000s) | 89,829 | 156,258 | 51,725 | 297,812 | ||||
Total capital including the net change in future capital (000s) | $ | 142,273 | $ | 322,334 | $ | 92,520 | $ | 557,127 |
Reserve additions including acquisitions, dispositions revisions and economic factors (Mboe) | 14,538 | 19,828 | 6,012 | 40,378 | ||||
All-In total proved plus probable finding and development costs (per Boe) | $ | 9.79 | $ | 16.26 | $ | 15.39 | $ | 13.80 |
Operating netback per Boe excluding hedging | $ | 20.43 | $ | 21.22 | $ | 22.81 | ||
Recycle ratio based on operating netback (excluding hedging gains or losses | ||||||||
Proved plus probable | 2.1 | 1.3 | 1.5 | |||||
Net Present Value Summary (before tax) as at December 31, 2013
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 | $ | 184,439 | $ | 146,816 | $ | 122,247 | $ | 105,198 | $ | 92,774 |
Proved non-producing | 92 | 87 | 82 | 78 | 74 | |||||
Total proved developed | $ | 184,531 | $ | 146,903 | $ | 122,329 | $ | 105,276 | $ | 92,848 |
Proved undeveloped | 184,537 | 107,293 | 62,108 | 34,079 | 15,855 | |||||
Total proved | $ | 369,068 | $ | 254,196 | $ | 184,438 | $ | 139,355 | $ | 108,704 |
Probable additional | 364,989 | 197,446 | 113,383 | 67,039 | 39,544 | |||||
Total proved plus probable | $ | 734,058 | $ | 451,643 | $ | 297,821 | $ | 206,393 | $ | 148,248 |
Numbers in this table may not add due to rounding.
Net Present Value Summary (after tax) as at December 31, 2013
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 | 184,439 | 146,816 | 122,247 | 105,198 | 92,774 |
Proved non-producing | 92 | 87 | 82 | 78 | 74 |
Total proved developed | 184,531 | 146,903 | 122,329 | 105,276 | 92,848 |
Proved undeveloped | 162,353 | 95,685 | 55,755 | 30,462 | 13,725 |
Total proved | 346,884 | 242,588 | 178,084 | 135,738 | 106,574 |
Probable additional | 274,236 | 146,917 | 82,937 | 47,569 | 26,517 |
Total proved plus probable | 621,121 | 389,504 | 261,021 | 183,308 | 133,091 |
Numbers in this table may not add due to rounding.
InSite Escalating Price Forecast as at December 31, 2013
WTI Crude Oil (US$/Bbl) | Edmonton Light Crude Oil (Cdn$/Bbl) | Henry Hub Natural Gas (US$/Mmbtu) | AECO Natural Gas (Cdn$/Mmbtu) | Propane (Cdn$/Bbl) | Butane (Cdn$/Bbl) | |
2014 | 96.00 | 96.05 | 4.25 | 3.99 | 48.03 | 76.84 |
2015 | 95.00 | 97.50 | 4.40 | 4.14 | 53.63 | 78.00 |
2016 | 95.00 | 97.45 | 4.75 | 4.50 | 53.60 | 77.96 |
2017 | 95.00 | 97.40 | 5.00 | 4.75 | 53.57 | 77.92 |
2018 | 96.00 | 98.40 | 5.25 | 5.01 | 54.12 | 78.72 |
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 plans; reserve volumes; capital expenditures; royalties; financing; commodity prices; and production, operating and general and administrative costs.
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, 2013.
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.
Storm Resources Ltd.Brian LavergnePresident & Chief Executive Officer(403) 817-6145Storm Resources Ltd.Donald McLeanChief Financial Officer(403) 817-6145Storm Resources Ltd.Carol KnudsenManager, Corporate Affairs(403) 817-6145www.stormresourcesltd.com
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