CALGARY, ALBERTA–(Marketwire – Aug. 13, 2012) – Storm Resources Ltd. (TSX VENTURE:SRX)

Storm has also filed its unaudited consolidated condensed interim financial statements as at June 30, 2012 for the three and six months then ended along with the Management’s Discussion and Analysis (“MD&A”) for the same period. This information appears on SEDAR at and on Storm’s website at

Selected financial and operating information for the three and six months ended June 30, 2012 appears below and should be read in conjunction with the related unaudited consolidated condensed interim financial statements and MD&A.


Thousands of Cdn$, except volumetric and per-share amounts

Three Months to June 30, 2012 Three Months to June 30, 2011 Six Months to June 30, 2012 Six Months to June 30, 2011
Oil sales 6,954 748 8,613 1,231
Gas sales 1,648 1,011 2,803 1,412
NGL sales 1,205 177 1,781 274
Royalty income 12 12
Production revenue 9,819 1,936 13,209 2,917
Funds from operations(1) 3,669 710 3,606 769
Per share – basic ($) 0.07 0.03 0.07 0.03
Per share – diluted ($) 0.07 0.03 0.07 0.03
Net income (loss) 947 (562 ) (668 ) (883 )
Per share – basic ($) 0.03 (0.02 ) (0.01 ) (0.03 )
Per share – diluted ($) 0.03 (0.02 ) (0.01 ) (0.03 )
Field capital expenditures, net of dispositions 7,223 2,012 9,430 11,714
Net (debt)/working capital (53,667 ) 12,224 (53,667 ) 12,224
Weighted average common shares outstanding (000s)
Basic 61,824 26,377 50,247 26,377
Diluted 61,847 26,377 50,247 26,377
Common shares outstanding (000s)
Basic 61,824 26,377 61,824 26,377
Fully diluted 64,547 28,391 64,547 28,391
Oil equivalent (6:1)
Barrels of oil equivalent (000s) 235 54 347 79
Barrels of oil equivalent per day 2,584 595 1,906 436
Average selling price (Cdn$ per Boe) 41.71 35.74 38.03 36.93
Oil Production
Barrels (000s) 83 7 102 13
Barrels per day 915 80 562 69
Average selling price (Cdn$ per barrel) 83.48 103.20 84.22 97.85
Gas production
Thousand cubic feet (000s) 809 269 1,324 379
Thousand cubic feet per day 8,895 2,958 7,277 2,094
Average selling price (Cdn$ per Mcf) 2.04 3.76 2.12 3.72
NGL Production
Barrels (000s) 17 2 24 3
Barrels per day 186 22 132 18
Average selling price (Cdn$ per barrel) 71.22 86.53 74.38 85.50
Wells drilled
Gross 1.0
Net 1.0

(1) Funds from operations and funds from operations per share are non-GAAP measurements. See discussion of Non-GAAP Measurements on page 8 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 17 of the MD&A.



  • Production increased by 335% from the year ago period to average 2,584 Boe per day which included 1,101 barrels per day of oil plus natural gas liquids (“NGL”) and 8.9 Mmcf per day of natural gas. Natural gas wells shut in during early May due to the decline in the price of natural gas reduced quarterly production by 360 Boe per day. Production was also reduced by 220 Boe per day due to the failure of a pipeline plus numerous mechanical failures on wells in the Grande Prairie area.
  • As a result of the Bellamont Exploration Ltd. (“Bellamont”) transaction completed on March 23rd, crude oil and NGL production increased to 43% of the production mix from 17% in the second quarter of 2011.
  • On a per-share basis, quarterly production of 42 Boe per day per million shares outstanding is a year-over-year increase of 90%.
  • The fourth horizontal well at Umbach was completed in June, tested at an average rate of 3.8 Mmcf per day, plus 40 barrels per day of condensate, over a 41-hour flow period and is expected to commence production in late August after the four kilometer pipeline tie-in is completed.
  • Funds from operations totaled $3.7 million ($15.60 per Boe) or $0.07 per basic share which is a 415% improvement from the year earlier period where funds from operations was $0.7 million. This was primarily the result of the Bellamont transaction which increased total production and increased the proportion of higher priced crude oil and NGL production.
  • Revenue was $41.71 per Boe, an increase of 17% from the year ago period which was due to the higher proportion of crude oil and NGL production which more than offset a 46% decrease in the wellhead price of natural gas.
  • Field operating netback averaged $22.07 per Boe which includes a $1.60 per Boe hedging gain, operating costs of $11.56 per Boe, transportation costs of $2.97 per Boe and royalties of $5.16 per Boe (13% of total revenue).
  • Capital investment totaled $7.2 million with $3.9 million invested in exploration and development activities plus $2.7 million to acquire a gas plant at Grimshaw.
  • A hedging gain of $0.4 million was realized as a result of fixed price financial hedges that were put in place to protect the 2012 capital investment program. Commodity price hedges currently include 450 barrels of oil per day at Cdn $103.35 to $107.75 per barrel from April to December, 2012 and 4,500 GJ per day of natural gas (approximately 4 Mmcf per day) at $2.20 per GJ from July to September, 2012.
  • At June 30, 2012, Storm’s debt and working capital deficiency was $53.7 million. After including the value of Storm’s investment in publicly listed companies ($7.5 million at June 30), net debt was $46.2 million. Storm’s bank line is $70.0 million.


Storm has a focused asset base with an inventory of light oil exploitation opportunities in the Grande Prairie Area and large land positions in resource plays at Umbach and in the Horn River Basin (“HRB”) which have multi-year drilling upside.

Umbach, North East British Columbia

Storm’s current land holdings at Umbach total 103 gross sections, or 79 net sections, (57,000 net undeveloped acres) all of which are prospective for liquids rich natural gas from the Montney formation. Production in the second quarter averaged 313 Boe per day (27% liquids) at an operating netback of $14.16 per Boe. Liquids recovery was 61 Bbls per Mmcf with approximately 45% being produced condensate plus pentanes recovered during processing.

The fourth horizontal well was completed in the second quarter with ten 100-tonne fracture stimulations. The flow test was 41 hours in duration with the average rate being 3.8 Mmcf per day gross raw gas plus 40 barrels per day of condensate at a final wellhead flowing pressure of 915 psig (cumulative gas produced during the flow period was 6.5 Mmcf). The test rate and flow period is generally consistent with earlier horizontal wells, however, the final wellhead flowing pressure was higher.

Storm’s activity in 2012 is focused on drilling horizontal wells to continue delineating the areal extent of the resource in the Montney formation and to cost effectively increase rates and reserves per horizontal. Currently, three horizontal wells are producing from the Montney formation with production history for each horizontal being regularly updated and shown in the presentation on Storm’s website The fourth horizontal well is expected to begin producing in late August after construction of the 4 kilometer pipeline tie-in is completed. First year average rates are ranging from 0.7 to 1.6 Mmcf per day gross raw gas (145 to 330 Boe per day sales). To date, the gross cost to drill and complete each horizontal has averaged $5.3 million with tie-in costs averaging $0.6 million. Costs will decline on future horizontal wells as existing pads are used (reduces lease and pipeline construction costs) and as logged vertical pilot holes are eliminated. The fifth horizontal well (60% working interest) is currently being drilled and it is expected that a total of two to four horizontal wells (0.6 net to 1.8 net) will be drilled in the second half of 2012. Completion and tie-in of the fifth and sixth horizontal wells is planned for the second half of 2012 and, if additional horizontal wells are drilled, they would be completed in the first quarter of 2013. On the next horizontal wells, improvements in rates and reserves are expected from lowering the wellbore 10 to 15 metres to access more of the Montney formation and by increasing the intensity of the fracture stimulations (less sand tonnage on reduced spacing and a larger fluid volume by switching from emulsified CO2 to slickwater).

Grande Prairie Area, North West Alberta and North East British Columbia

Production in this area comes from the Mica property in North East British Columbia and from the properties acquired through the transaction with Bellamont which closed March 23rd. Second quarter production averaged 1,716 Boe per day (58% oil plus NGL) with the operating netback averaging $24.60 per Boe. Production in the second quarter was impacted by numerous mechanical failures (loss of 220 Boe per day) and by the shut-in of natural gas wells in early May producing 3.0 Mmcf per day (loss of 360 Boe per day for the quarter). Current production capability totals approximately 2,300 Boe per day (150 Boe per day from Mica) which includes shut-in volumes.

A horizontal well was drilled into the Grande Prairie Dunvegan C light oil pool in July. It is expected that this well will be completed and tied in by the end of September.

At Grimshaw, a horizontal well was converted to an injector in the Montney in July and water injection will commence in late August once all regulatory approvals have been received. This will result in operating costs being reduced by approximately $0.5 million per year as produced water is re-injected instead of being trucked for disposal. The vertical well in the new Montney pool discovery drilled by Bellamont in late 2011 has averaged 18 barrels of oil per day since production began in mid-June. Solution gas conservation was initiated in early June which added 60 Boe per day at a cost of approximately $3 million to acquire a small gas plant and install a small choke plant to remove natural gas liquids.

The Grande Prairie area is relatively mature with shallower declines (approximately 20% per year) and a higher proportion of light oil and NGL production resulting in a higher operating netback. There is a large inventory of light oil opportunities in this area including 15 to 30 horizontal wells to be drilled targeting light oil in the Doe Creek, Dunvegan, Charlie Lake and Montney formations. There is additional upside associated with initiating waterfloods in the Montney formation at Grimshaw and in the Charlie Lake formation at Mica. Storm is planning to re-invest approximately 60% to 70% of cash flow from this area in maintaining production and the remaining ‘free cash flow’ will be directed to advancing exploitation of the Montney formation at Umbach, which is a larger scale growth opportunity. No further drilling activity is planned for this area in 2012. In 2013, drilling activity is expected to include four to six horizontal wells into the Montney at Grimshaw, the Montney I pool at Grande Prairie, and the Doe Creek and Charlie Lake formations at Saddle Hills.

Horn River Basin, North East 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. During the second quarter, production in the HRB averaged 525 Boe per day at an operating netback of $3.88 per Boe. The resource in the Muskwa and Otter Park shales is large with the best estimate of DPIIP in the core producing area being 3.1 Tcf gross raw gas (evaluated by InSite Petroleum Consultants Ltd. December 31, 2011). The core producing area is 30 gross sections in size (22% of Storm’s total land holdings in the HRB) and productivity has been proven across the area with one horizontal well that has been on production for 17 months and two vertical wells which were completed with each well having a final test rate of 0.9 Mmcf per day over the last 24 hours (flow test durations totaled 370 and 279 hours with respective gas production totaling 16 Mmcf and 9 Mmcf).

Production performance of the first horizontal well (100% Storm) with 12 fracture stimulations continues to exceed expectations with the current rate being 3.0 to 3.5 Mmcf per day gross raw gas and cumulative production to date of 2.5 Bcf gross raw gas since production commenced on March 7, 2011. The flow rate is restricted since the pressure in the raw gas gathering pipeline is high and compression has not yet been installed. 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.

Activity in the HRB is being deferred until natural gas prices improve.


At the end of first quarter, Storm had share ownership positions in two publicly traded companies. The value of the share positions in the two public companies totaled $7.5 million at the end of the quarter and these securities could possibly be sold in the future with the proceeds being used to finance the Company’s capital programs.

Chinook Energy Inc. (“Chinook”)

Storm holds 4.5 million shares of Chinook which is a TSX-listed oil and gas exploration and production company (symbol ‘CKE’) based in Calgary with operations focused in Tunisia and western Canada.

Bridge Energy ASA (“Bridge”)

Storm holds 1.05 million common shares of Bridge (symbol ‘Bridge’ on the Oslo Stock Exchange), a Norwegian-based exploration and production company with production of approximately 1,500 Boe per day (33% light oil) from the UK sector of the North Sea.


Production in the third quarter is forecast to average 2,400 to 2,600 Boe per day (43% liquids) and this assumes 3 Mmcf per day of natural gas at Grande Prairie remains shut in until natural gas prices at AECO are greater than $2.75 to $3.00 per GJ. On July 25th, the sale of a 20% working interest in two producing wells at Red Earth (17 barrels per day light oil) was closed for proceeds totaling $2.4 million. Debt plus the working capital deficiency is targeted to be approximately $50 million at the end of 2012 (including the value of the publicly listed securities owned by Storm) which will result in capital investment being adjusted higher or lower depending on actual commodity prices and asset dispositions. Planned capital investment in 2012 is unchanged at approximately $28 million, however, due to unexpected capital expenditures on the properties acquired from Bellamont, drilling activity is being reduced to four to seven gross wells (3.2 to 5.4 net) from six to eight gross wells (5.2 to 7.2 net). Activity will now include one vertical delineation well (1.0 net) at Umbach, two to four horizontal wells (1.2 to 2.4 net) at Umbach, completing one standing horizontal well (0.6 net) at Umbach, and one to two horizontal wells (all 100% working interest) targeting light oil opportunities in the Grande Prairie Area. The reduction in drilling activity results in a reduction to fourth quarter production rates which are now forecast to average 2,600 to 2,800 Boe per day (41% liquids). This assumes 500 Boe per day remains shut in due to low natural gas prices and that the fifth and sixth horizontal wells at Umbach are completed and tied in before year end. Storm is currently forecasting commodity prices in 2012 average $2.20 per GJ at AECO for natural gas and Cdn $85.00 per barrel Edmonton Par for crude oil.

Updated 2012 Guidance
Forecast Q3 production after deducting 5% for unplanned outages 2,400 to 2,600 Boe per day (43% oil + NGLs)
Bank credit facility $70.0 million
2012 average operating costs $10 to $12 per Boe
2012 average royalty rate 12% to 15%
2012 operations capital, excluding dispositions $28.0 million
2012 cash G&A(1) $3.5 to $3.8 million
2012 exit or fourth quarter average production 2,600 to 2,800 Boe per day (41% oil + NGLs)

(1) Excludes transaction costs which are required to be expensed under IFRS.

Hedging will be done on a more regular basis going forward in order to smooth out commodity price volatility and protect capital investment. Early in the second quarter, Storm entered into financial hedges on 450 barrels of oil per day for April to December 2012 and on 4,500 GJ per day of natural gas for July to September 2012. It’s unlikely that any further hedging will be done for 2012 volumes. In general, Storm’s hedges will be done on a financial basis (won’t require physical delivery), will be shorter term at 9 to 18 months duration and will cover 40% to 45% of current production.

During the second quarter, significant time and effort was expended on assimilating the properties acquired with the Bellamont transaction that closed on March 23rd. Numerous operational problems were encountered in the second quarter on the Bellamont properties which resulted in significant downtime and reduced production. The additional unplanned capital expenditures to fix the problems have impacted debt by approximately $10 million (assumed debt at closing was $4 million higher than expected plus $6 million has been spent to date on operational problems). In order to offset the financial impact of the incremental spending on the Bellamont properties, drilling activity has been reduced which will impact Storm’s production growth in 2012. Offsetting this are operating cost reductions totaling $1.8 million per year that have been realized to date on the Bellamont properties as a result of a greater focus on cost control and profitability.

Although there have been many challenges associated with integrating the Bellamont properties, the addition of higher netback, light oil production with a relatively shallow decline provides us with the ‘free cash flow’ to continue delineation of the liquids rich Montney resource on Storm’s large land position at Umbach. Initial results at Umbach have been very encouraging and improvement is expected on future horizontal wells by lowering the wellbore to access a thicker interval and by increasing the intensity of the fracture stimulation in the completions. With a 25% improvement in the first year average rate, horizontal wells are expected to generate a 20% to 25% rate of return using current forward strip pricing for oil and natural gas (approximately $3 per GJ at AECO and $85 per barrel Edmonton Par).

Near term, Storm is focused on advancing the Montney at Umbach which could generate significant economic growth in production at the current forward strip for crude oil and natural gas prices given liquids recovery of 60 barrels per Mmcf and lower capital costs associated with a shift to development drilling. Longer term, significant leverage to an improvement in natural gas prices is offered by the very large DPIIP in the Muskwa and Otter Park shales of the HRB. The hard work and effort of Storm’s employees and the continued patience of Storm’s shareholders is greatly appreciated and we look forward to providing updates on our progress over the remainder of this year and into 2013.


Brian Lavergne, President and Chief Executive Officer

August 13, 2012

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 described herein 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.

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”, “expects”, “believe”, “plans”, “potential” 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; and production 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 and six months ended June 30, 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.

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.