Storm has also filed its audited consolidated financial statements as at December 31, 2012 and for the three months and year then ended along with the 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, 2012, as well as reserve information at December 31, 2012, appears below and should be read in conjunction with the related financial statements and MD&A.
Highlights | |||||||||
Thousands of Cdn$, except volumetric and per share amounts | Three Months Ended December 31, 2012 |
Three Months Ended December 31, 2011 | Year Ended December 31, 2012 | Year Ended December 31, 2011 | |||||
FINANCIAL | |||||||||
Gas sales | 3,416 | 1,160 | 8,054 | 3,404 | |||||
NGL sales | 1,597 | 594 | 4,466 | 1,020 | |||||
Oil sales | 5,399 | 739 | 19,793 | 2,468 | |||||
Revenue from product sales(1) | 10,412 | 2,493 | 32,313 | 6,892 | |||||
Funds from operations(2) | 5,016 | 709 | 13,387 | 1,874 | |||||
Per share – basic ($) | 0.08 | 0.03 | 0.24 | 0.07 | |||||
Per share – diluted ($) | 0.08 | 0.03 | 0.24 | 0.07 | |||||
Net income (loss) | (2,320 | ) | (1,758 | ) | (6,574 | ) | (3,664 | ) | |
Per share – basic ($) | (0.04 | ) | (0.07 | ) | (0.12 | ) | (0.14 | ) | |
Per share – diluted ($) | (0.04 | ) | (0.07 | ) | (0.12 | ) | (0.14 | ) | |
Field capital expenditures, net of dispositions | 8,777 | 20,687 | 14,282 | 40,796 | |||||
Net debt/working capital | 44,696 | 15,171 | 44,696 | 15,171 | |||||
Weighted average common shares outstanding (000s) | |||||||||
Basic | 61,824 | 26,377 | 56,067 | 26,377 | |||||
Diluted | 61,824 | 26,377 | 56,067 | 26,377 | |||||
Common shares outstanding (000s) | |||||||||
Basic | 61,824 | 26,377 | 61,824 | 26,377 | |||||
Fully diluted | 64,547 | 28,355 | 64,547 | 28,355 | |||||
OPERATIONS | |||||||||
Oil equivalent (6:1) | |||||||||
Barrels of oil equivalent (000s) | 259 | 72 | 825 | 198 | |||||
Barrels of oil equivalent per day | 2,815 | 779 | 2,254 | 542 | |||||
Average selling price (Cdn$ per Boe)(1) | 40.19 | 34.78 | 39.14 | 34.86 | |||||
Gas production | |||||||||
Thousand cubic feet (000s) | 987 | 346 | 3,053 | 964 | |||||
Thousand cubic feet per day | 10,728 | 3,763 | 8,342 | 2,641 | |||||
Average selling price (Cdn$ per Mcf) | 3.46 | 3.35 | 2.64 | 3.53 | |||||
NGL Production | |||||||||
Barrels (000s) | 25 | 7 | 67 | 12 | |||||
Barrels per day | 274 | 72 | 185 | 32 | |||||
Average selling price (Cdn$ per barrel) | 63.27 | 89.95 | 66.17 | 87.36 | |||||
Oil Production | |||||||||
Barrels (000s) | 69 | 7 | 249 | 25 | |||||
Barrels per day | 753 | 80 | 679 | 69 | |||||
Average selling price (Cdn$ per barrel)(1) | 77.93 | 100.05 | 79.53 | 97.39 | |||||
Wells drilled | |||||||||
Gross | 2.0 | 1.0 | 6.0 | 4.0 | |||||
Net | 1.2 | 0.6 | 4.4 | 2.2 |
(1) | Excludes hedging gains. |
(2) | Funds from operations and funds from operations per share are non-GAAP measurements. See discussion of Non-GAAP Measurements on page 14 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 24 of the MD&A. |
President”s Message
2012 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 Horn River Basin (“HRB”) which have multi-year drilling upside.
Umbach, Northeast British Columbia
Storm”s land position at Umbach totals 99 net sections (126 gross sections) or 69,000 net acres. Two project areas have been identified with one area consisting of 63 gross sections of jointly owned lands (36 net sections with an average Storm working interest of 57%) and the other area containing 63 sections of land at a 100% working interest. Fourth quarter production averaged 564 Boe per day (29% NGL) with NGL recovery being 67 Bbls per Mmcf of natural gas sales. NGL included 50% condensate plus pentanes recovered during processing, 24% butane, and 26% propane. The fourth quarter operating netback was $17.70 per Boe with revenue of $31.28 per Boe, a royalty rate of 12%, and operating costs were $9.80 per Boe.
Repeated outages and capacity constraints with third party field compression resulted in production from Umbach being reduced by 300 Boe per day in the fourth quarter. For most of the quarter, one to three horizontals were shut in and run time on the remaining horizontals was intermittent.
On the jointly owned lands, nine horizontal wells have been drilled all at a 60% working interest with seven of those having been completed and tied in. Initial production and flow test results from the last three horizontal wells that were drilled lower into the Montney formation and completed with larger water based fracture treatments are encouraging although additional uninterrupted production history is required to confirm the level of improvement. As production declines and as field compression capacity becomes available, the remaining two horizontal wells will be completed and tied in which is likely to be in the third and fourth quarters. From January 1st to February 25th, production has averaged 425 Boe per day net from one to four horizontal wells with third party field compression having been shut in for 17 days to complete repairs and modifications. Production is currently approximately 750 Boe per day net from four horizontal wells. Total sustainable productive capability of all seven horizontal wells is estimated at 1,500 Boe per day net to Storm. Production from the joint lands is expected to be restricted to 600 to 1,000 Boe per day net for the next three to six months.
On the 100% working interest lands, one horizontal well has been drilled and has been completed with first production expected early in the second quarter once an eight kilometre pipeline connection to an existing field compression facility is completed. Storm has entered into an agreement to acquire ownership in this existing facility for $4.5 million with available capacity being approximately 20 Mmcf per day. Production from horizontal wells connected to this facility will be directed to the McMahon Gas Plant for processing which will reduce NGL recovery to 37 Bbls per Mmcf sales; however, the field netback will increase by $2 per Boe at current commodity prices because eliminating third party fees for field compression will reduce operating costs by more than $3 per Boe. In the second half of 2013, it is expected that three to four more horizontal wells will be drilled on the 100% working interest lands and will be pipeline connected to this facility.
The gross cost to drill and complete the last two horizontal wells (the sixth and seventh) averaged $4.8 million which is a significant improvement from the average cost of $5.5 million for the first five horizontal wells. Both were drilled from existing pads. As the focus transitions from resource delineation to development in 2013, horizontal well costs are expected to decline as wells are drilled from common pads and further drilling and completion efficiencies are realized.
On the first four horizontal wells, first year average rates have been approximately 290 Boe per day (1.5 Mmcf raw gas per day) with estimated 2P reserves of 540 Mboe (2.8 Bcf gross raw gas) assigned to the Upper Montney formation only. This has generated a rate of return below Storm”s targeted threshold of 20% to 25%. Completion techniques on the most recent horizontal wells have been modified to access the Upper and Middle Montney intervals to improve the first year average rate which is expected to result in the rate of return improving to meet or exceed the minimum targeted level.
Grande Prairie Area, Northwest Alberta and Northeast British Columbia
Production in this area comes from properties acquired through the transaction with Bellamont which closed in the first quarter of 2012. Production in the fourth quarter averaged 1,884 Boe per day (46% oil plus NGL) at an operating netback of $25.40 per Boe. In early October, with natural gas prices at AECO recovering to $3.00 per GJ, shut-in natural gas wells were reactivated which added 455 Boe per day in the fourth quarter. The sale of the Mica property was completed on October 18th with net proceeds at closing totaling $13.3 million (145 Boe per day). During the first quarter of 2013, the Rycroft property was sold January 18th (30 Boe per day) and the Saddle Hills and Gold Creek properties were sold February 15th (275 Boe per day) with proceeds from both transactions totaling $20.1 million. Current production after the recent dispositions is approximately 1,500 Boe per day (41% liquids).
There was minimal activity in the fourth quarter. A horizontal well drilled and completed in the Grande Prairie Dunvegan C light oil pool in the third quarter, was produced for a short period of time in November, and is now shut in as the production rate was below economic limits. The poor production rate was the result of problems casing the well which resulted in an open hole completion instead of the planned multi-stage fracture treatment. At Grimshaw, water injection commenced into a horizontal well in the Montney A pool in late August which has resulted in a flattening of the pool decline over the last four months. Significant progress was made on operating cost reductions in 2012 with realized savings totaling $2.5 million per year from electrifying well sites, purchasing surface equipment to eliminate processing fees, shutting in or disposing of uneconomic wells, returning rental equipment and eliminating water trucking and disposal. Wells that were shut in or disposed had total cash flow of $50,000 from April 2011 to March 2012.
Horn River Basin, Northeast British Columbia
Storm”s undeveloped land position in the HRB totals 135 sections at a 100% working interest (87,700 net acres) and is prospective for natural gas from the Muskwa, Otter Park and Evie/Klua shales. The resource in the Muskwa and Otter Park shales is large with the best estimate of DPIIP in the 30 section core producing area being 3.1 Tcf gross raw gas (evaluated by InSite Petroleum Consultants Ltd. December 31, 2011). Productivity has been proven across the core producing area with one horizontal well that has been producing for 23 months plus two completed and tested vertical wells.
During the fourth quarter, production in the HRB averaged 367 Boe per day at an operating netback of $9.99 per Boe. All of Storm”s production is from a horizontal well with 12 fracture stimulations that is currently producing 2.7 Mmcf per day gross raw gas with cumulative production of 2.8 Bcf gross raw gas since production commenced in March 2011. Field compression has not been installed so the flow rate since inception has been restricted by the high flowing pressure in the raw gas gathering pipeline (1,000 psig). Significant improvements in productivity and reserves are expected on future horizontals by increasing fracture density (15 to 18 fracture stimulations per horizontal) and by installing field compression.
INVESTMENTS
At the end of the fourth quarter, Storm owned 3 million shares in Chinook Energy Inc., a TSX-listed oil and gas exploration and production company (symbol ”CKE”) based in Calgary with operations focused in Tunisia and western Canada. These shares had a value of $4.3 million at the end of 2012. During the fourth quarter of 2012, Storm sold its remaining shares in Bridge Energy ASA for proceeds totaling $1.8 million.
OUTLOOK
Results in 2012 were generally in line with guidance (year-end debt, operating costs, royalty rate, operations capital). Production in the fourth quarter of 2012 was below previous guidance (2,815 Boe per day versus previous guidance of 3,000 Boe per day) due to outages and capacity constraints with third party field compression at Umbach. Production in the first quarter of 2013 is expected to be 2,500 Boe per day and will increase to 3,000 Boe per day in the second quarter. This reflects the impact of the asset dispositions, continuing downtime with third party field compression at Umbach, and maintenance turnarounds at the Fort Nelson gas plant (HRB shut in for 28 days) and the Teepee gas plant (half of Grande Prairie area shut in for 15 days). Production growth is expected to resume in the second half of 2013 with additions at Umbach coming from expansion of the gathering system and as horizontal wells are drilled, completed and tied in on 100% working interest lands.
Preliminary 2013 guidance provided November 13, 2012 is being revised to reflect the recent asset dispositions that closed in the first quarter of 2013 (total proceeds $20.1 million) and an increase in activity levels at Umbach. Net of acquisitions and dispositions, total capital investment is expected to be $25 million. Updated guidance is provided below:
2013 Guidance | 2012 Actual | |||
Year-end adjusted debt plus working capital deficiency (1) | $44.0 million | $40.4 million | ||
Average operating costs | $10 – $11 per Boe | $11.48 per Boe | ||
Average royalty rate (on production revenue before hedging) | 11% – 12 | % | 11.1 | % |
Operations capital, excluding dispositions | $40.0 million | $26.9 million | ||
Property dispositions(2) | $20.0 million | $15.7 million | ||
Corporate or property acquisitions | $4.5 million | $154.9 million | ||
Cash G&A | $3.9 million | $3.7 million | ||
Exit or fourth quarter average production | 4,000 – 4,500 Boe per day | 2,815 Boe per day | ||
(25% oil + NGL | ) | (36% oil + NGL | ) |
(1) | Includes value of publicly listed securities. |
(2) | Dispositions closed in February 2013. |
The 2013 capital investment program will be focused on developing the resource in the Montney formation at Umbach. Major expenditures will include:
With a 2013 natural gas price at AECO of $3 per GJ and an Edmonton Par oil price of $87 per barrel, this program will be funded with cash flow, the sale of non-core assets, and with bank debt. Adjusted net debt is forecast to be unchanged at $45 million at the end of 2013 (including public company investments) which is within Storm”s current bank line of $52 million and approximately two times forecast 2013 funds from operations.
Over the last year, Storm has gained critical mass and cash flow through two corporate transactions. Activity in 2012 was focused on drilling horizontal wells at Umbach to continue delineating the large, liquids-rich natural gas resource in the Montney formation. To date, Storm has delineated approximately 40% of its land position at Umbach with reserves assigned to only the Upper Montney formation on 11% of the land base. Well control confirms that there is a significant inventory of undrilled horizontal wells in the Upper and Middle Montney intervals. As a result, in 2013, the focus will transition to developing the resource and growing production and cash flow. NGL recovery of 67 barrels per Mmcf sales through a shallow-cut gas plant greatly improves the netback and economics at current natural gas prices. Modifications to the completion technique are expected to improve first year average rates and result in a rate of return meeting or exceeding 20% to 25% at current commodity prices. If results at Umbach are supportive of doing so, development may be accelerated with funding being provided by additional asset sales.
Regarding the HRB property, the optionality of Storm”s land position is confirmed by recent transactions involving major land positions either in the HRB or other large scale, gas-prone resource plays in British Columbia and Alberta. The HRB continues to offer significant leverage to improving natural gas prices and remains a long term, core asset for Storm.
I would like to thank Storm”s employees for their effort and hard work in 2012 and our directors for their guidance and continued support. Our goal continues to be accretive growth in net asset value which will be achieved through development of the larger scale, liquids-rich resource in the Montney formation at Umbach. We look forward to providing updates on our progress throughout 2013.
Respectfully,
Brian Lavergne, President and Chief Executive Officer
February 28, 2013
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, 2012
Storm”s year-end reserve evaluation effective December 31, 2012 was prepared by InSite Petroleum Consultants Ltd. (“InSite”) under date of February 15, 2013. InSite has evaluated all of Storm”s crude oil, NGL and natural gas reserves. The InSite price forecast at December 31, 2012 was used to determine all estimates of future net revenue (also referred to as net present value or NPV). Storm”s Reserves Committee, comprised 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.
Summary
Gross Company Interest Reserves as at December 31, 2012 | ||||
(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 | 2,049 | 19,535 | 555 | 5,860 |
Proved non-producing | – | 397 | 8 | 74 |
Total proved developed | 2,049 | 19,932 | 563 | 5,934 |
Proved undeveloped | 300 | 39,068 | 1,077 | 7,888 |
Total proved | 2,349 | 59,000 | 1,640 | 13,822 |
Probable additional | 1,265 | 66,600 | 1,144 | 13,509 |
Total proved plus probable | 3,614 | 125,600 | 2,784 | 27,331 |
Gross Company Reserve Reconciliation for 2012 | ||||||
(Gross company interest reserves before deduction of royalties payable) | ||||||
6:1 Oil Equivalent (Mboe) | ||||||
Total Proved |
Probable | Proved plus Probable |
||||
December 31, 2011 – opening balance | 3,714 | 4,608 | 8,322 | |||
Acquisitions | 7,361 | 7,348 | 14,709 | |||
Discoveries | – | – | – | |||
Extensions | 4,067 | 1,447 | 5,514 | |||
Dispositions | (626 | ) | (109 | ) | (735 | ) |
Technical revisions | 126 | 216 | 342 | |||
Production | (819 | ) | – | (819 | ) | |
December 31, 2012 – closing balance | 13,823 | 13,510 | 27,333 |
Future Development Costs | |||
Proved | |||
HRB | 3.0 net horizontals plus infrastructure | $ 55.5 million | |
Umbach | 8.4 net horizontals | $ 39.8 million | |
Grande Prairie | 3.0 net horizontals | $ 7.5 million | |
Total | $ 102.8 million | ||
Proved Plus Probable Additional | |||
HRB | 7.0 net horizontals plus infrastructure | $ 125.1 million | |
Umbach | 12.6 net horizontals | $ 63.6 million | |
Grande Prairie | 11.0 net horizontals | $ 40.2 million | |
Total | $ 229.0 million | ||
Proved Expenditures | Proved Plus Probable Additional Expenditures | ||
2013 | $ 29.3 million | $ 37.7 million | |
2014 | $ 18.0 million | $ 33.2 million | |
2015 | $ 18.6 million | $ 59.4 million | |
2016 | $ 34.9 million | $ 43.0 million | |
2017 | $ 2.1 million | $ 41.8 million | |
2018 | $ – | $ 13.9 million | |
NI 51-101 Finding and Development Costs | ||||
Total Proved Finding and Development Cost | 2012 | 2011 | 2010 | 3 Year Average |
Capital expenditures excluding acquisitions and dispositions (000s) | $ 26,868 | $ 25,360 | $ 16,800 | $ 69,028 |
Net change in FDC (000s) | 30,863 | 25,541 | 4,679 | 61,083 |
Total capital including the net change in future capital (000s) | $ 57,731 | $ 50,901 | $ 21,479 | $ 130,111 |
Reserve additions excluding acquisitions, dispositions and revisions (Mboe) | 4,067 | 2,505 | 738 | 7,310 |
Total proved finding and development costs (per Boe) | $ 14.20 | $ 20.32 | $ 29.10 | $ 17.80 |
Total Proved Plus Probable Finding and Development Cost | 2012 | 2011 | 2010 | 3 Year Average |
Capital expenditures excluding acquisitions and dispositions (000s) | $ 26,868 | $ 25,360 | $ 16,800 | $ 69,028 |
Net change in FDC (000s) | 40,341 | 51,725 | 21,057 | 113,123 |
Total capital including the net change in future capital (000s) | $ 67,209 | $ 77,085 | $ 37,857 | $ 182,151 |
Reserve additions excluding acquisitions, dispositions and revisions (Mboe) | 5,514 | 5,278 | 2,512 | 13,304 |
Total proved plus probable finding and development costs (per Boe) | $ 12.19 | $ 14.60 | $ 15.07 | $ 13.69 |
All-In Finding, Development and Acquisition Costs | ||||
Total Proved All-In Finding, Development and Acquisition Cost including FDC, Acquisitions, Dispositions, Revisions |
2012 | 2011 | 2010 | 3 Year Average |
Capital expenditures including acquisitions and dispositions (000s) | $ 166,076 | $ 40,795 | $ 16,800 | $ 223,671 |
Net change in FDC (000s) | 72,655 | 25,541 | 4,679 | 102,875 |
Total capital including the net change in future capital (000s) | $ 238,731 | $ 66,336 | $ 21,479 | $ 326,546 |
Reserve additions including acquisitions,dispositions and revisions (Mboe) | 10,927 | 3,178 | 738 | 14,843 |
All-in total proved finding and development costs (per Boe) | $ 21.85 | $ 20.87 | $ 29.10 | $ 22.00 |
Total Proved Plus Probable All-In Finding, Development and Acquisition Cost including FDC, Acquisitions, Dispositions, Revisions | 2012 | 2011 | 2010 | 3 Year Average |
Capital expenditures including acquisitions and dispositions (000s) | $ 166,076 | $ 40,795 | $ 16,800 | $ 223,671 |
Net change in FDC (000s) | 156,258 | 51,725 | 21,057 | 229,040 |
Total capital including the net change in future capital (000s) | $ 322,334 | $ 92,520 | $ 37,857 | $ 452,711 |
Reserve additions including acquisitions,dispositions and revisions (Mboe) | 19,828 | 6,012 | 2,512 | 28,352 |
All-In total proved plus probable finding and development costs (per Boe) | $ 16.26 | $ 15.39 | $ 15.07 | $ 15.97 |
Net Present Value Summary (before tax) as at December 31, 2012
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 | $ 164,695 | $ 125,620 | $ 101,403 | $ 85,241 | $ 73,808 |
Proved non-producing | 416 | 382 | 353 | 328 | 306 |
Total proved developed | $ 165,111 | $ 126,002 | $ 101,756 | $ 85,569 | $ 74,114 |
Proved undeveloped | 91,890 | 49,156 | 24,643 | 9,763 | 328 |
Total proved | $ 257,002 | $ 175,159 | $ 126,399 | $ 95,333 | $ 74,442 |
Probable additional | 226,565 | 113,694 | 59,667 | 31,173 | 15,027 |
Total proved plus probable | $ 483,566 | $ 788,852 | $ 186,066 | $ 126,506 | $ 89,469 |
Numbers in this table may not add due to rounding. |
Net Present Value Summary (after tax) as at December 31, 2012
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 | $ 164,696 | $ 125,620 | $ 101,403 | $ 85,241 | $ 73,808 |
Proved non-producing | 416 | 383 | 354 | 328 | 306 |
Total proved developed | $ 165,112 | $ 126,003 | $ 101,757 | $ 85,569 | $ 74,114 |
Proved undeveloped | 89,076 | 48,030 | 24,169 | 9,555 | 232 |
Total proved | $ 254,188 | $ 174,033 | $ 125,926 | $ 95,124 | $ 74,347 |
Probable additional | 170,535 | 85,623 | 44,517 | 22,510 | 9,841 |
Total proved plus probable | $ 424,723 | $ 259,656 | $ 170,442 | $ 117,635 | $ 84,188 |
Numbers in this table may not add due to rounding. |
InSite Escalating Price Forecast as at December 31, 2012 | ||||||
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) |
|
2013 | 92.00 | 90.00 | 3.75 | 3.34 | 36.00 | 76.50 |
2014 | 94.00 | 91.96 | 4.25 | 3.83 | 45.98 | 78.17 |
2015 | 96.00 | 93.92 | 4.75 | 4.33 | 56.35 | 79.83 |
2016 | 98.00 | 95.88 | 5.20 | 4.77 | 57.53 | 81.50 |
2017 | 100.00 | 97.84 | 5.55 | 5.11 | 58.70 | 83.16 |
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, 2012.
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.
Storm Resources Ltd.
Brian Lavergne
President & CEO
(403) 817-6145
Storm Resources Ltd.
Donald McLean
Chief Financial Officer
(403) 817-6145
Storm Resources Ltd.
Carol Knudsen
Manager, Corporate Affairs
(403) 817-6145
www.stormresourcesltd.com