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

Storm has also filed its unaudited consolidated condensed interim financial statements as at September 30, 2012 for the three and nine 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 nine months ended September 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$, except volumetric and per-share amounts Three Months to Sept. 30, 2012 Three Months to Sept. 30, 2011 Nine Months to Sept. 30, 2012 Nine Months to Sept. 30, 2011
Oil sales 6,702 498 15,318 1,729
Gas sales 1,841 831 4,653 2,243
NGL sales 1,088 153 3,869 427
Production revenue(2) 9,631 1,482 22,840 4,399
Funds from operations(1) 4,765 396 8,371 1,165
Per share – basic ($) 0.08 0.02 0.15 0.04
Per share – diluted ($) 0.08 0.02 0.15 0.04
Net income (loss) (3,586 ) (1,023 ) (4,254 ) (1,906 )
Per share – basic ($) (0.07 ) (0.04 ) (0.08 ) (0.07 )
Per share – diluted ($) (0.07 ) (0.04 ) (0.08 ) (0.07 )
Field capital expenditures, net of dispositions (3,925 ) 8,394 5,504 20,108
Net (debt)/working capital (42,511 ) 4,054 (42,511 ) 4,054
Weighted average common shares outstanding (000s)
Basic 61,824 26,377 54,134 26,377
Diluted 61,824 26,377 54,134 26,377
Common shares outstanding (000s)
Basic 61,824 26,377 61,824 26,377
Fully diluted 64,547 28,391 64,547 28,391
Oil equivalent (6:1)
Barrels of oil equivalent (000s) 219 47 566 126
Barrels of oil equivalent per day 2,380 511 2,065 462
Average selling price (Cdn$ per Boe)(2) 43.96 31.50 40.33 34.91
Oil Production
Barrels (000s) 77 5 179 18
Barrels per day 838 58 655 66
Average selling price (Cdn$ per barrel)(2) 86.75 92.66 85.31 96.30
Gas production
Thousand cubic feet (000s) 741 239 2,065 618
Thousand cubic feet per day 8,058 2,595 7,539 2,263
Average selling price (Cdn$ per Mcf) 2.49 3.48 2.25 3.63
NGL Production
Barrels (000s) 18 2 42 5
Barrels per day 199 20 154 19
Average selling price (Cdn$ per barrel) 59.44 81.44 67.90 84.00
Wells drilled
Gross 3.0 2.0 4.0 2.0
Net 2.2 1.2 3.2 1.2
(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 18 of the MD&A.
(2) Includes hedging gains.

President’s Message


  • Production increased by 365% from the year ago period to average 2,380 Boe per day which included 1,037 barrels per day of crude oil plus natural gas liquids (“NGL”) and 8.1 Mmcf per day of natural gas. The year-over-year improvement is due to production at Umbach increasing by 260 Boe per day, from the business combination with Bellamont Exploration Ltd. (“Bellamont”) which added 1,400 Boe per day, and from the acquisition of Storm Gas Resource Corp. which added 255 Boe per day.
  • Production in the quarter was reduced by 470 Boe per day as a result of natural gas wells shut in during early May due to the decline in the price of natural gas.
  • On a per-share basis, quarterly production of 39 Boe per day per million shares outstanding represents a year-over-year increase of 98%.
  • At Umbach, the fourth horizontal well (60% working interest) commenced production in late August and averaged 2.5 Mmcf per day gross raw gas in September, or 290 net Boe per day. The fifth and sixth horizontal wells (60% working interest) were drilled in the third quarter and both are expected to commence production by late November.
  • A horizontal well (100% working interest) was drilled into the Grande Prairie Dunvegan C oil pool and will commence production by mid-November.
  • Funds from operations totaled $4.8 million or $0.08 per basic share which is a 400% improvement from $0.02 per basic share in the year earlier period. This was mainly due to the transaction with Bellamont which increased the proportion of higher priced crude oil and NGL to 44% of total production and offset a 28% decline in natural gas prices.
  • Funds from operations was $21.73 per Boe which is an increase of $6.13 per Boe from the second quarter as a result of higher oil and natural gas prices plus a reduction in royalties, cash G&A and interest expense.
  • Capital investment of $11.7 million included $8.2 million for drilling and completions plus $1.1 million at Grimshaw to initiate a pilot waterflood.
  • Dispositions totaled $15.7 million including 20 Boe per day at Red Earth for $2.4 million and 145 Boe per day at Mica for $13.3 million.
  • During the quarter, Storm realized proceeds totaling $2.5 million from the sale of 1.5 million shares of Chinook Energy Inc. and 0.2 million shares of Bridge Energy ASA.
  • At quarter end, Storm’s debt and working capital deficiency was $42.5 million which is a reduction of $11.1 million from the previous quarter. After including the value of Storm’s investment in publicly listed companies ($6.4 million at September 30), net debt was $36.1 million or 1.9 times annualized third quarter cash flow. Storm’s bank line is $62.0 million.
  • A hedging gain of $0.6 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 an average of Cdn $104.95 per barrel until the end of December, 2012 and 300 barrels of oil per day at an average floor price of Cdn $93.10 per barrel for the first quarter of 2013.


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 that are prospective for liquids rich natural gas in the Montney formation total 105 gross sections, or 81 net sections (58,000 net undeveloped acres). Production in the third quarter averaged 414 Boe per day (27% liquids) at an operating netback of $15.80 per Boe which is a 33% increase from production in the second quarter. Liquids recovery was 61 Bbls per Mmcf with 46% being produced condensate plus pentanes recovered during processing, 25% butane and 29% propane.

During the third quarter, the fourth horizontal well (60% working interest) commenced production August 22nd and averaged 2.5 Mmcf per day gross raw gas in September with the current rate being 2.0 Mmcf per day gross raw gas (235 net Boe per day). Performance to date is consistent with earlier horizontal wells. Also in the third quarter, the fifth and sixth horizontal wells (60% working interest) were drilled and cased with both being drilled approximately 20 metres lower in the Montney formation. Both have been completed with larger slickwater fracture treatments and are expected to be tied in and producing by late November.

In the fourth quarter, two more horizontal wells will be drilled (1.2 net) with completion and tie-in of both planned for the first quarter of 2013.

Storm’s activity in 2012 has been focused on drilling horizontal wells to continue expanding the areal extent of the resource in the Montney formation and to modify completion techniques to improve horizontal well flow rates and reserves. On the fifth and sixth horizontal wells, the wellbores were drilled lower in the Montney formation and the completions were modified by switching to larger slickwater fracture stimulations with reduced spacing between fracture treatments. Currently, four horizontal wells are producing from the Montney formation with production history for each horizontal being periodically updated and shown in the presentation on Storm’s website To date, the gross cost to drill and complete each horizontal has averaged $5.3 million. As the focus transitions from resource delineation to development in 2013, horizontal well costs are expected to decline by drilling wells from common pads and by eliminating logged, vertical pilot holes.

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

Other than production from the since disposed of Mica property, production in this area comes from properties acquired through the transaction with Bellamont which closed March 23rd. Third quarter production averaged 1,540 Boe per day (60% oil plus NGL) at an operating netback of $31.15 per Boe. Production in the third quarter was reduced by 100 Boe per day due to numerous mechanical failures in July and by 470 Boe per day associated with natural gas wells that were shut in during May due to low natural gas prices. The sale of the Mica property was completed on October 18th with net proceeds at closing totaling $13.3 million (averaged 145 Boe per day in the third quarter). Excluding the Mica property, current production has increased to approximately 2,100 Boe per day as a result of reactivating the shut-in natural gas wells in early October and from re-equipping wells to reduce downtime caused by equipment failures.

Third quarter activity included drilling and completing a horizontal well in the Grande Prairie Dunvegan C light oil pool which is expected to begin producing in mid-November. At Grimshaw, water injection commenced into a horizontal well in the Montney A pool in late August. In July, downhole equipment failures were experienced on seven producing wells with all of them being re-equipped with different pumping systems. Significant progress was made in the quarter on operating cost reductions with realized savings now totaling approximately $2 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. No activity is planned for this area in the fourth quarter of 2012.

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 30 horizontal wells to be drilled targeting light oil in the Doe Creek, Dunvegan and Montney formations. Additional upside is associated with initiating a waterflood in the Montney formation at Grimshaw. The majority of cash flow from this area will be directed to advancing exploitation of the Montney formation at Umbach, which is a larger scale growth opportunity.

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. 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 producing for 20 months plus two completed and tested vertical wells.

During the third quarter, production in the HRB averaged 426 Boe per day at an operating netback of $6.08 per Boe. The first horizontal well (100% Storm) with 12 fracture stimulations is currently producing 3 Mmcf per day gross raw gas with cumulative production since March 2011 being 2.7 Bcf gross raw gas. The flow rate has been restricted by high pressure in the raw gas gathering pipeline (field compression has not 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.

With six years of remaining land tenure for the majority of Storm’s lands not yet proven to be productive, activity in the HRB is being deferred until natural gas prices improve.


At the end of third quarter, Storm had share ownership positions in two publicly traded companies. The value of the share positions in the two public companies totaled $6.4 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 3.0 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 0.9 million common shares of Bridge (symbol ‘Bridge’ on the Oslo Stock Exchange and ‘BRDG’ on the AIM Exchange, London), a Norwegian-based exploration and production company.


Storm’s 2012 guidance remains largely unchanged. Production in the fourth quarter is forecast to be approximately 3,000 Boe per day (35% liquids) which is an increase from prior guidance of 2,400 to 2,600 Boe per day (41% liquids). In mid-October, the sale of the Mica property closed (145 Boe per day) and shut-in natural gas wells at Grande Prairie were re-started adding 470 Boe per day. Based on field estimates, production in October increased to 2,800 Boe per day. Production will increase further in November with the tie-in of the fifth and sixth horizontal wells at Umbach (60% working interest). Dispositions will result in adjusted debt plus the working capital deficiency being reduced to approximately $38 million at the end of 2012 from prior guidance of $50 million (including the value of the publicly listed securities owned by Storm). There is no change to capital investment in operations, estimated royalties, operating costs and cash G&A.

2012 Guidance
Bank credit facility $62.0 million
2012 year end adjusted debt plus working capital deficiency (1) $38.0 million
2012 average operating costs $11 per Boe
2012 average royalty rate 12 %
2012 operations capital, excluding dispositions $28.0 million
2012 net property dispositions $12.0 million
2012 corporate acquisitions $151.6 million
2012 cash G&A(2) $3.6 million
2012 exit or fourth quarter average production 3,000 Boe per day
(35% oil + NGL )
(1) Includes value of publicly listed securities.
(2) Excludes $0.6 million of transaction costs which are required to be expensed under IFRS.

Looking ahead to 2013, preliminary guidance includes capital spending of $36 million to drill 6 horizontal development wells (4.4 net) at Umbach and to complete two horizontal wells (60% working interest) at Umbach that are being drilled in the fourth quarter of 2012. Production in the fourth quarter of 2013 is forecast to increase to 4,000 to 4,300 Boe per day. With a 2013 natural gas price at AECO of $3.25 per GJ and an Edmonton Par oil price of $84 per barrel, this program would be funded with cash flow and the sale of non-core assets. With forecast debt of $38 million at the end of 2012 (including public company investments) and a bank line of $62 million, Storm retains the financial flexibility to increase 2013 capital investment if supported by improved drilling results or higher commodity prices.

Production performance of the properties acquired with the Bellamont transaction that closed on March 23rd has improved significantly over the last three months. This is primarily the result of operational improvements and re-equipping wells in the second and third quarters to eliminate downtime caused by multiple equipment failures. With relatively shallow declines and higher netbacks from a higher proportion of crude oil and NGL production, the properties acquired with the Bellamont transaction provide Storm with the ‘free cash flow’ to continue funding exploitation of the large resource in the Montney formation at Umbach.

Although declining commodity prices resulted in less drilling activity and lower growth in 2012 than what was initially expected, Storm has continued to advance exploitation of the liquids rich Montney natural gas resource on its large land position at Umbach. Liquids recoveries are exceeding 60 barrels per Mmcf sales through a shallow-cut gas plant which greatly improves the netback and economics at current low natural gas prices. Results continue to be encouraging and are expected to improve on future horizontal wells as a result of modifying the completions to use larger, slickwater fracture stimulations with tighter spacing between fractures. If results at Umbach are supportive of doing so, development may be accelerated with funding being provided by additional asset sales or from unused capacity on the bank line. Longer term, Storm continues to retain significant leverage to an improvement in natural gas prices through our position in the Muskwa and Otter Park shales of the HRB.


Brian Lavergne, President and Chief Executive Officer

November 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 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”, “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 and nine months ended September 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.