CALGARY, ALBERTA–(Marketwire – May 16, 2012) – Storm Resources Ltd. (TSX VENTURE:SRX)

Storm has also filed its unaudited consolidated condensed interim financial statements as at March 31, 2012 for the three 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 months ended March 31, 2012 appears below and should be read in conjunction with the related unaudited consolidated condensed interim financial statements and MD&A.

Thousands of Cdn$, except volumetric and per-share amounts Three Months Ended March 31, 2012 Three Months Ended March 31, 2011
Gas sales 1,155 401
NGL sales 576 97
Oil sales 1,659 483
Production revenue 3,390 981
Funds from operations(1)) (63 ) 59
Per share – basic ($) 0.00 0.00
Per share – diluted ($) 0.00 0.00
Net income (loss) (1,615 ) (321 )
Per share – basic ($) (0.04 ) (0.01 )
Per share – diluted ($) (0.04 ) (0.01 )
Field capital expenditures, net of dispositions 2,207 9,702
Net (debt)/working capital (50,300 ) 13,688
Weighted average common shares outstanding (000s)
Basic 38,670 26,377
Diluted 38,670 26,377
Common shares outstanding (000s)
Basic 61,824 26,377
Fully diluted 63,942 28,391
Oil equivalent (6:1)
Barrels of oil equivalent (000s) 112 25
Barrels of oil equivalent per day 1,229 276
Average selling price (Cdn$ per Boe) 30.31 39.53
Gas production
Thousand cubic feet (000s) 515 110
Thousand cubic feet per day 5,659 1,221
Average selling price (Cdn$ per Mcf) 2.24 3.65
NGL Production
Barrels (000s) 7 1
Barrels per day 77 13
Average selling price (Cdn$ per barrel) 81.96 83.68
Oil Production
Barrels (000s) 19 5
Barrels per day 208 59
Average selling price (Cdn$ per barrel) 87.44 90.59
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 15 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 15 of the MD&A.



  • The business combination with Bellamont Exploration Ltd. (“Bellamont”) closed on March 23rd and added 1,850 Boe per day of higher netback production (51% oil plus natural gas liquids) based on field estimates for April. Estimated April production was reduced by 50 Boe per day shut in due to low natural gas prices and 250 Boe per day shut in due to mechanical failures. Using the evaluation completed by InSite effective March 31, 2012, Storm acquired proved reserves totaling 4.6 Mmboe and proved plus probable reserves totaling 8.3 Mmboe. Total cost of the transaction was approximately $96.7 million which includes $37.0 million of total debt assumed by Storm, a cash component of $20.0 million, and the issuance of 16.7 million Storm shares to Bellamont shareholders.
  • The transaction with Bellamont was partly funded with a $23.6 million private placement of common shares of Storm at a price of $3.40 per Storm share resulting in the issuance of 6.9 million shares at closing on March 23rd. Management, directors and employees invested $8.4 million to subscribe for 2.5 million shares.
  • Production increased by 340% from the year ago period to average 1,229 Boe per day which included 285 barrels per day of oil plus natural gas liquids (“NGLs”) and 5.7 Mmcf per day of natural gas. This includes nine days of production from Bellamont’s properties.
  • There was limited activity in the quarter as a result of a focus on completing the Bellamont and Storm Gas Resource Corp. (“SGR”) transactions and integrating their properties into Storm’s operations. A vertical delineation well (100% working interest) was drilled and cased at Umbach on the southern block of land with log response across the Montney being similar to vertical wells further north which offset Storm’s three producing horizontal wells.
  • Funds used in operations was $63,000, the operating netback averaged $15.73 per Boe, and operating costs were $9.75 per Boe. Costs related to the Bellamont and SGR transactions reduced cash flow by $0.6 million.
  • Capital investment totaled $162.9 million in the quarter with $3.2 million invested in exploration and development activities, $160.7 million on acquisitions, and $1.0 million was received from the sale of non-core undeveloped lands.
  • At March 31, 2012, Storm’s debt and working capital deficiency was $50.3 million. After including the value of Storm’s investment in publicly listed companies ($8.3 million at March 31), net debt was $42.0 million. Storm’s bank line was increased to $70.0 million with the closing of the Bellamont transaction.
  • The acquisition of SGR, Storm’s partner in the Horn River Basin of north east British Columbia (“HRB”), was completed on January 12th. This added 2.1 Mmcf per day of natural gas sales (350 Boe per day) in the first quarter plus 81,400 net acres of undeveloped land including 58,400 net acres in the HRB. Proved reserves totaling 2.6 Mmboe and proved plus probable reserves totaling 6.8 Mmboe were acquired based on an evaluation completed by InSite Petroleum Consultants Ltd. (“InSite”) effective January 31, 2012. The cost to acquire SGR totaled $55.2 million after deducting the working capital surplus of $1.0 million and including 11.8 million Storm shares issued to SGR shareholders. With the best estimate DPIIP of 3.1 Tcf and contingent resources of 616 Bcf, consolidating ownership in the HRB provides a huge option on improving natural gas prices for Storm shareholders.


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 HRB which have multi-year drilling upside.

Umbach, North East British Columbia

Storm’s current land holdings at Umbach total 99 gross sections or 75 net sections (54,000 net undeveloped acres), all of which are prospective for liquids rich natural gas from the Montney formation. Production in the first quarter averaged 335 Boe per day (20% liquids) while the operating netback was $13.46 per Boe. Liquids recovery was 36 Bbls per Mmcf sales gas with approximately 60% being free condensate plus pentane.
During the first quarter, production was re-directed to the Stoddart Gas Plant on March 17th which is expected to result in liquids recoveries increasing to 45 to 55 barrels per Mmcf of sales gas (approximately 50% free condensate plus pentane) and will improve the operating netback by $3 to $5 per Boe using first quarter pricing.

A vertical delineation well (100% working interest) was drilled on the southern lands in the first quarter with log response across the Montney being similar to wells further north offsetting Storm’s producing horizontal wells. This well was cased so that it can be re-entered in the future to drill a horizontal wellbore.

Currently, three horizontal wells are producing from the Montney formation with production history for each horizontal provided in the presentation on Storm’s website, In order to reduce the completion cost, a packer system with frac ports was used for the completion of the last two horizontal wells with different fracture treatments conducted on each well in an attempt to improve productivity and reserves. After comparing results to other horizontal wells completed in the Montney in the area, further modifications are planned on future horizontal wells including increasing the sand tonnage and pumping rates in fracture treatments, going back to a perf and plug system with perf clusters, and possibly lowering the wellbore to access more of the Montney formation.

Storm’s activity in the remainder of 2012 will be focused on increasing the size of the resource in the Montney formation and improving horizontal well rates and reserves. The fourth horizontal well (0.6 net) that was drilled late last year will be completed and two more step-out horizontal wells (1.2 net) will be drilled and completed in the third quarter. Depending on results, two more horizontal wells (1.2 net) may be drilled in the fourth quarter with both being completed in the first quarter of 2013.

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. Based on field estimates, production in April was approximately 2,000 Boe per day (52% oil plus NGLs) with 50 Boe per day shut in due to low natural gas prices and 250 Boe per day shut in due to mechanical failures (pipeline failure and installation of artificial lift). The pipeline failure was repaired in early May which has restored 125 Boe per day from one well and artificial lift is expected to be installed in the other shut-in well during early June when road bans have been lifted. During May, an additional 450 Boe per day has been shut in as a result of low natural gas prices.

The Grande Prairie area is relatively mature with shallower declines (approximately 20% per year) and a higher proportion of oil and NGL production which results in a higher operating netback (more cash flow). Storm expects 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.

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 and initiating a waterflood plus drilling up to six vertical infill wells in a light oil pool at Mica.

During the remainder of 2012, a vertical well in a new pool Montney light oil discovery at Grimshaw will begin producing and three to five horizontals (all 100% working interest) will be drilled targeting light oil in the Montney, Dunvegan, and Doe Creek formations.

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 first quarter, production in the HRB averaged 574 Boe per day at an operating netback of $5.17 per Boe. On January 12, 2012, Storm completed the previously announced acquisition of SGR, its partner in the HRB, which increased production in the first quarter by 350 Boe per day. 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 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 14 months and two vertical wells which were completed and had final test rates of 950 and 870 Mmcf per day (final test rate is the average rate over the last 24 hours with cumulative gas production being 12 Mmcf and 7 Mmcf).

Production performance of the first horizontal well (100% Storm) with 12 fracture stimulations continues to exceed expectations with the current rate being approximately 3.7 Mmcf per day gross raw gas and cumulative production of 2.1 Bcf gross raw gas since production commenced on March 7, 2011. The raw gas gathering pipeline operates at a higher pressure which has resulted in the flow rate being restricted since compression has not been installed. Ultimate recovery for this well is forecast to be 9.6 Bcf gross raw gas which may increase given that the decline is continuing to flatten. The production decline is shallower in comparison to other shale plays because the Muskwa and Otter Park shales are very thick (92 metres thickness in the DPIIP area). 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 $8.2 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 second quarter is forecast to average 2,700 to 2,800 Boe per day (41% liquids). Since closing the transaction with Bellamont, 500 Mcf per day has been shut in due to low natural gas prices and an additional 2,500 Mcf per day has been shut in during early May (total 500 Boe per day). All of the shut-in production is from natural gas wells with high third party processing fees and won’t be re-started until natural gas prices at AECO are greater than $2.50 to $3.00 per GJ. Shutting in these wells will have no impact on cash flow. Mechanical failure has also impacted production (loss of 250 Boe per day in April from two wells) and we expect these to be resolved by early June.

Due to a further decrease in forecast cash flow caused by the continuing decline in natural gas prices, capital investment in operations will be reduced to $28 million from previous guidance of $34 million. This will include $20 million for drilling and completions and $8 million for land, seismic and facilities. Drilling and completion activity in 2012 will now include one vertical delineation well (1.0 net) at Umbach, two horizontal wells (1.2 net) at Umbach, completing one standing horizontal well (0.6 net) at Umbach, and three to five horizontals or verticals (all 100% working interest) targeting light oil opportunities in the Grande Prairie area. Fourth quarter or exit production is forecast to average 3,100 to 3,400 Boe per day (43% liquids) which assumes 500 Boe per day remains shut in due to low natural gas prices. Storm is currently assuming commodity prices in 2012 average $2.05 per GJ at AECO for natural gas and Cdn $92.00 per barrel Edmonton Par for oil. 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 may result in capital investment being adjusted higher or lower depending on actual commodity prices.

Updated 2012 Guidance
Forecast Q2 production after deducting 5% for unplanned outages 2,700 to 2,800 Boe per day
(41% 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 $28.0 million
2012 cash G&A(1) $3.8 million
2012 exit or fourth quarter average production 3,100 to 3,400 Boe per day
(43% oil + NGLs
(1) Excludes transaction costs associated with the SGR acquisition and Bellamont combination which are required to be expensed under IFRS.

During and after the end of the first quarter, we entered into hedges on a portion of our oil production in order to protect our capital investment program in 2012. The total hedged volume is 450 barrels per day of oil, terms are from May to December 2012, and the average price is Cdn $104.95 per barrel.

Significant reductions in operating costs ($2.0 to $2.5 million per year) will be realized on the properties acquired from Bellamont by the end of the second quarter. Investment in infrastructure projects will result in more than $1.0 million per year of savings which includes converting a well to salt water disposal to reduce trucking, acquiring and modifying a small gas plant to eliminate processing fees, eliminating equipment rentals and electrifying well sites. As well, 100 Boe per day (87% natural gas) that was cash flow negative in 2011 will be permanently shut in (associated operating costs total $1.0 million per year).

Storm’s focus over the remainder of 2012 will be to:
  • Offset declines by drilling three to five horizontals in the Grande Prairie area targeting light oil;
  • Integrate Bellamont’s properties and implement operating cost reductions; and
  • Use ‘free cash flow’ plus a limited amount of debt to further expand the liquids rich Montney gas resource at Umbach by completing the fourth horizontal well (0.6 net) and drilling and completing two additional horizontal wells (1.2 net).

Although the decline in natural gas prices over the last four months has affected our share price and caused many challenges in terms of budgeting, we do expect that natural gas prices will recover because of simple economics. The majority of producers that grew natural gas production in 2011 spent more than cash flow and funded the gap with equity issues, debt, asset sales, or by using cash flow from oil assets. With prices in 2011 averaging $3.40 per GJ at AECO, longer-term prices need to be higher in order to attract capital investment required to maintain current production levels (cash out can’t be greater than cash in for extended periods of time). Timing of the recovery is difficult to predict but investment generating very low or no economic return cannot continue indefinitely.

Storm is a somewhat unique junior producer that has accumulated large land positions over the last four years in two large-scale resource plays offering multi-year drilling upside. Although there have been many challenges associated with integrating the Bellamont properties, it adds higher netback, light oil production and an inventory of horizontal light oil wells that can be drilled to offset declines. As well, the relatively shallow production decline provides us with ‘free cash flow’ for reinvestment into our resource plays. Near term, this allows us to continue exploitation of liquids rich natural gas in the Montney at Umbach where horizontal wells are expected to generate a 20% to 25% rate of return using current forward strip pricing for crude oil and natural gas. Longer term, significant leverage to an improvement in natural gas prices is offered by the large DPIIP in the Muskwa and Otter Park shales of the HRB. With a talented and motivated group of employees at Storm and higher levels of cash flow from a larger, oilier asset base, we are well positioned for continued growth in 2012 and beyond.


Brian Lavergne, President and Chief Executive Officer

May 16, 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 months ended March 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.

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.