Storm Exploration Inc. Is Pleased to Announce Its Financial and Operating Results for the Three and Six Months Ended June 30, 2009

CALGARY, ALBERTA--(Marketwire - Aug. 13, 2009) - Storm Exploration Inc. (TSX:SEO)

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Three Three Six Six
Highlights - Months Months Months Months
Thousands of $CDN, to to to to
except volumetric and June 30, June 30, June 30, June 30,
per share amounts 2009 2008 2009 2008
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Financial
Gas sales 14,026 29,547 (1) 35,633 55,788
NGL sales 2,028 3,239 3,904 5,628
Oil sales 3,097 (1) 5,906 5,972 (1) 11,051
Royalty income 47 196 114 395
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Production revenue 19,198 38,888 45,623 72,862
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Funds from operations (2) 8,460 23,250 22,180 42,768
Per share - basic ($) 0.18 0.52 0.48 0.96
Per share - diluted ($) 0.18 0.50 0.47 0.93

Net income (loss) (2,192) 9,465 (942) 15,889
Per share - basic ($) (0.05) 0.21 (0.02) 0.36
Per share - diluted ($) (0.05) 0.20 (0.02) 0.34

Capital expenditures, net of
dispositions 3,843 5,780 35,334 32,555

Debt, including working capital
deficiency 93,473 (3) 75,144 (3) 93,473 (3) 75,144

Weighted average common shares
outstanding (000s)
Basic 46,553 44,634 45,888 44,610
Diluted 47,637 46,179 46,959 46,101

Common shares outstanding
(000s)
Basic 46,554 44,657 46,554 44,657
Fully diluted 49,012 47,026 49,012 47,026

Operations
Oil equivalent (6:1)
Barrels of oil equivalent
(000s) 742 558 1,502 1,149
Barrels of oil equivalent per
day 8,153 6,130 8,296 6,315
Average selling price ($CDN
per BOE) 25.81 (1) 69.36 (1) 30.31 (1) 63.05

Gas production
Thousand cubic feet (000s) 3,839 2,893 7,752 5,943
Thousand cubic feet per day 42,185 31,786 42,831 32,656
Average selling price ($CDN
per mcf) 3.65 10.22 (1) 4.60 9.39

NGL Production
Barrels (000s) 49 28 97 59
Barrels per day 533 313 538 323
Average selling price ($CDN
per barrel) 41.77 113.64 40.11 95.69
Oil Production
Barrels (000s) 54 47 112 100
Barrels per day 589 519 620 549

Average selling price ($CDN
per barrel) 57.76 (1) 124.97 53.22 (1) 110.56

Wells drilled
Gross 0.0 0.0 4.0 11.0
Net 0.0 0.0 2.8 10.1

(1) Includes results of hedging activities
(2) Funds from operations and funds from operations per share are non-GAAP
measurements. See MD&A.
(3) Excludes unrealized liability related to financial instruments

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HIGHLIGHTS for the Quarter Ended June 30, 2009

- Production increased to 8,153 Boe per day, a 33% increase from production of 6,130 Boe per day in the same period one year ago. This is a per share increase of 28% using basic shares outstanding at quarter end. Approximately 600 Boe per day was shut-in or curtailed for economic reasons during the quarter and another 120 Boe per day was shut-in as a result of the scheduled maintenance turnaround of the Ft Nelson Gas Plant in June. Start-up of two new Montney horizontal wells at Parkland was delayed until later in the second quarter with both currently producing a total of 1,600 Boe per day (net).

- Activity during the quarter was low due to road use restrictions imposed every spring (road bans) that prevent mobilization of rigs until late June and, also as a result of reducing activity levels in response to the decline in natural gas prices which has reduced cash flow available for re-investment. No wells were drilled or completed in the second quarter.

- Cash flow for the quarter was $8.5 million or $0.18 per diluted share, a decrease of 64% from $0.50 per diluted share in the prior year second quarter. Not surprisingly, this was the result of lower commodity prices with the year-over-year decline of 65% in the per Boe sales price more than offsetting 28% growth in production per share.

- The second quarter cash flow netback of $11.40 per Boe represents a decline of 73% from the cash flow netback of $41.69 per Boe in the year earlier period and, again, this was due to the 63% decline in the per Boe sales price over the same period. Total cash costs including operating expense, interest expense, transportation costs, and general and administrative averaged $9.95 per Boe in the quarter representing a 22% decline from the year earlier period which did offset some of the commodity price decline. Notably, operating costs were $5.61 per Boe in the quarter, a decline of 21% from the previous year.

- Storm incurred a net loss for the quarter of $2.2 million, or a loss of $0.05 per diluted share which represents the first quarterly loss since we commenced operations five years ago. This has been and continues to be a challenging and very difficult business environment. Charges for depletion, depreciation and accretion at $14.43 per Boe were 16% lower year over year but, this improvement was more than offset by the decline in commodity prices over the same period.

- Capital investment totaled $3.8 million in the quarter, leaving bank debt and working capital deficiency at $93.5 million or 2.8 times annualized second quarter cash flow. Year over year, total debt has increased by 24% which is in proportion to production per share growth of 28%.

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.

CORE AREA REVIEW

Parkland/Fort St. John Area, North East British Columbia

This area includes our Montney discovery and is the largest of Storm's core areas, with net production averaging 6,016 Boe per day in the second quarter. During the quarter, approximately 500 Boe per day was shut in or curtailed due to low natural gas prices. Current production is approximately 6,100 Boe per day with 500 Boe per day shut in.

During the second quarter, two Montney horizontal wells at Parkland that were completed and tied in during the first quarter, began producing in mid-May and early June (both 100% working interest). Each is currently being produced at a restricted rate of approximately 4.5 Mmcf per day which represents 800 Boe per day of net sales per well. Planned activity at Parkland over the remainder of the year includes drilling three horizontal development wells (2.4 net) in our Montney discovery, three vertical Montney step-outs (3.0 net), and one exploratory Montney vertical well (1.0 net) to further evaluate a new pool Montney lead.

Development of our Montney discovery continues to progress as expected. We are currently producing about 27 Mmcf per day of gross raw gas from 14 horizontal Montney gas wells plus 3 Mmcf per day of gross raw gas from 11 Montney vertical wells. The first year average rate from our horizontal wells continues to be approximately 2.3 Mmcf per day of raw gas, which represents 400 Boe per day of sales gas per well.

Geological mapping suggests that our Montney discovery could be as large as 15 to 17 net sections. The 2008 year-end reserve evaluation completed by Paddock Lindstrom & Associates Ltd. recognized an areal extent of 11 sections (7,040 acres) based on 13 successful vertical Montney gas wells. This resulted in estimated Discovered Petroleum Initially in Place ("DPIIP") or gross Original Gas in Place(1) ("OGIP") for our Montney discovery to be 409 Bcf. Estimated DPIIP relies on a porosity cut-off of 6% on a sandstone scale which is somewhat conservative in comparison to what is being used by other reserve evaluators in the area. The areal extent of our discovery is likely to have increased by one to two net sections based on results from the one successful vertical Montney step-out we drilled in the first quarter and the recompletion of two suspended wells in the first and third quarters. During the remainder of 2009, three additional step-outs are planned in an effort to further expand the areal extent of our Montney discovery.

In 2009, a total of $16 million has been budgeted to expand our infrastructure at Parkland. In the first quarter, $4 million was invested in completing a second facility which is currently capable of processing 12 Mmcf per day and has been designed to be readily expandable to 50 Mmcf per day of capacity. Later this year, we plan to expand this facility to 25 Mmcf per day of capacity and a liquids extraction plant (refridge) will be added at an estimated cost of $12 million. We have started ordering and taking delivery of equipment and expect to start construction in late October, with completion expected by early December. The refridge plant is expected to result in liquids recoveries increasing from 16 to 45 barrels per Mmcf of sales gas which would increase liquids production by 400 to 600 barrels per day and will add two to three million barrels of natural gas liquids to our proven plus probable reserves (based on the DPIIP and recoverable raw gas recognized in the 2008 year-end reserve evaluation).

In the second quarter, the field netback realized at our Parkland property was $16.03 per Boe, production was 6,016 Boe per day (87.3% natural gas), and operating costs were $3.93 per Boe.

1 When used in this press release, original gas in place ("OGIP") means Discovered Petroleum Initially in Place which is defined in the COGEH handbook as the quantity of hydrocarbons that are estimated to be in place within a known accumulation. OGIP is used here as it is a more commonly used industry term when referring to gas accumulations. Discovered Petroleum Initially in Place 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 Discovered Petroleum Initially in Place except for those portions identified as proved or probable reserves.

Grande Prairie Area, North West Alberta

Production from this area averaged 1,470 Boe per day in the second quarter which is a decline of 17% from production of 1,773 Boe per day in the year earlier period. Approximately 100 Boe per day was shut in during the quarter due to low natural gas prices. Current production is approximately 1,400 Boe per day with 100 Boe per day still shut in. Third quarter production from this area is expected to be reduced by approximately 100 Boe per day as result of planned facility maintenance turnarounds in September. Declines from this area continue to moderate which is indicative of the higher quality nature of this more mature asset.

In order to benefit from Alberta`s recently announced royalty incentive programs, we are planning to drill two locations (75% average working interest) in the fourth quarter. Additional wells are likely to be drilled in 2010 to further benefit from the royalty incentive programs. The locations are mainly lower risk infills or twins of existing wells and the royalty incentive programs will offset 50% to 75% of the cost to drill these wells.

Cabin-Kotcho-Junior Area, North East British Columbia

Net production from this area averaged 620 Boe per day in the second quarter, a decline of 36% from the year earlier period. Production during the quarter was affected by the scheduled 21 day maintenance shut-down of the Ft Nelson Gas Plant which reduced production by 120 Boe per day for the quarter. Current production is approximately 575 Boe per day and we have shut-in 150 Boe per day due to low natural gas prices.

We are currently finalizing plans for a winter drilling program involving two to four horizontal wells plus a small facility expansion to test the productivity of the Jean Marie formation in the Junior area. Based on mapping and proximity to offsetting producing Jean Marie horizontals, we have 33 net sections in the area which have the greatest potential for development with horizontal wells. Our estimated average cost to drill, complete, and tie-in a horizontal well is approximately $2.1 million. Based on offsetting wells in the immediate area, first year rates could average 800 to 1,400 Mcf per day and 1.0 to 1.5 Bcf of gross raw gas could be recovered with each horizontal well. Drilling density would be one horizontal well per section.

Horn River Basin ("HRB"), North East British Columbia

Since early 2008, Storm has jointly acquired 64 gross sections of undeveloped land in the HRB at a 40% working interest (16,400 net acres) prospective for Devonian shale gas. This land position has been acquired at an average cost of $400 per acre. The lands were purchased in partnership with Storm Gas Resource Corp. ("SGR") which owns the remaining 60% working interest. Combined with Storm's 22% ownership position in SGR, our exposure to this unconventional shale gas play is approximately 53%.

In the first quarter, two vertical wells (60% SGR, 40% Storm) were drilled in the HRB to prove the productivity of our lands. The first well was cored, completed and flow tested in the Muskwa and Otter Park shales. Results were encouraging but inconclusive in terms of determining the exploitation potential with multi-stage frac horizontal wells. Both of the vertical test wells are within a central project area encompassing 35 gross sections (14.0 net) containing an estimated 2.6 Tcf of gross DPIIP (internal estimate prepared by Storm Management). Our estimate of DPIIP is based on information and data from various sources including wells in the immediate area and assumes:

- average gross pay of 60 to 110 metres with 3.7% average porosity (both the Muskwa and Otter Park shales),

- average gas saturation of 80%,

- average reservoir pressure of 25,200 kPaa,

- average gas content of 40 to 80 scf per ton,

- the calculated adsorbed gas volume represents 45% of estimated DPIIP.

The Klua/Evie shale was not included in the DPIIP estimate because less information is available regarding the productivity of this shale in the area.

The next step in advancing this play is drilling horizontal wells to obtain production data (initial rates, declines, estimates of potential recoverable reserves) as well as operational experience which we can then use in determining the economic viability of larger scale exploitation with multi-stage frac horizontal wells. We are currently estimating that the cost to drill a horizontal well is $4 million with the cost of a 10 frac completion being $10 million. The completions may be done in the summer of 2010 in order to eliminate the significant cost associated with storing large quantities of water in tanks and heating them during the winter. Cost of drilling and completing horizontal wells may be lower than this as part of a larger scale development program; however, the actual cost reduction is difficult to quantify at this time given that we have not yet drilled any horizontal wells in the HRB. The initial test horizontals would potentially be tied in and producing early in 2011. We are currently working with SGR to finalize plans for 2010 which will potentially include drilling and completing one to two horizontal wells, completing the second standing vertical well drilled last winter, drilling and coring one more vertical delineation well, recording 3-D seismic, and constructing associated roads, facilities, and pipelines. Initial estimates of the gross cost are between $35 and $45 million (incurred between early 2010 and early 2011) depending on the number of horizontal wells drilled and also completed. The potential economic returns associated with full scale development of the HRB shales are not expected to be known until after we have several months of production history from the horizontal wells which is likely to be up to two years in the future. This remains an early stage project with a high level of associated economic risk.

STORM GAS RESOURCE CORP.

Storm Gas Resource Corp was formed in June 2007, to pursue unconventional gas opportunities in the HRB and elsewhere. During 2008, SGR completed a private equity issue and raised $38.2 million (net of share issue costs) at a price of $6.50 per share. Storm's investment to date in SGR totals $6.2 million and our share ownership position is 2.05 million shares, representing 22% ownership of SGR. Currently, SGR's land position in the HRB totals 123 gross sections or 70 net sections.

Our investment in SGR and partnership in the HRB are at an early stage in terms of information and results and we don't expect to have an indication regarding upside potential for at least two to three years.

STORM VENTURES INTERNATIONAL INC.

Storm owns 4.5 million shares of Storm Ventures International Inc. ("SVI"), a Calgary based, private energy company focused on international exploration and exploitation opportunities. Our share position has a notional value of $28 million or $0.60 per fully diluted Storm share using the price of a rights offering completed in August 2008 which was $6.25 per share. At the end of 2008, SVI's independently reviewed proven plus probable reserves totaled 36.4 million Boe. SVI is primarily focused on advancing three major development projects including the Vulcan project in the North Sea with potentially 320 to 360 Bcf of original gas in place, the Remada Sud light oil discovery in Tunisia with Stock Tank Original Oil in Place ('STOOIP') independently estimated at 170 million barrels in the Ordovician formation, and the Cosmos fallow discovery offshore Tunisia with estimated STOOIP of 25 million barrels.

SVI's production averaged 12.9 Mmcf per day in the first quarter generating field cash flow of Cdn$7.4 million with field cash flow for 2009 estimated to be Cdn$26 million (before interest and general and administrative expenses). Estimated field cash flow for 2009 is supported by a hedge on 5.9 Mmcf per day with a floor price of $11.00 per Mcf. SVI ended the first quarter with cash of Cdn$38 million and with Cdn$36 million drawn on a loan facility with the Royal Bank of Scotland.

Early in the second quarter of 2009, SVI commenced an extended production test of an Ordovician light oil discovery at Remada Sud in Tunisia which had been drilled and completed early in 2008. Results to date are encouraging with the well flowing 225 barrels per day of light oil at a 3% watercut. SVI is applying to extend the test from 90 to 180 days and will submit a preliminary development plan before year end for execution in 2010. This plan is expected to include a 3-D seismic survey and two additional appraisal/development wells to assess the commercial potential of this discovery.

Three higher impact exploratory wells are expected to be drilled before the end of 2009 with SVI being the operator of all three wells. Two are in Tunisia with one being the Fushia prospect offshore in the Gulf of Hammamet targeting a 100 Mmbbl prospect (pay 38.75% and retain a 65% interest) and the other being onshore targeting a 25 Mmbbl prospect in the Silurian Acacus formation on the Jenein Centre block (pay 30% and retain a 65% interest). The third is the Coriander prospect in the North Sea, which is part of the Vulcan project area containing fallow discoveries and prospects with prospective gas in place totaling 1 Tcf.

OUTLOOK

Storm's capital investment plan for 2009 is being reduced to reflect lower than budgeted cash flow. Capital investment for the year will be reduced to $67 million which still includes $16 million to be invested in expanding our infrastructure at Parkland. This will be funded primarily with cash flow which is expected to total $45 to $50 million assuming average 2009 prices of $4.00 per GJ at AECO for natural gas and $56.00 per barrel for oil at Edmonton. The equity issue completed in March funds the remainder, which allowed us to complete the first quarter acquisition of a gross overriding royalty at Parkland for $9 million and has also provided certainty on being able to fund the addition of a refridge plant at Parkland to increase recovery of higher value natural gas liquids. Our 2009 drilling program will now total 13 gross wells (10.7 net). In the second half of 2009, we plan to drill three Montney horizontal wells (2.4 net) at Parkland, four Montney verticals (4.0 net), and two wells (1.5 net) in the Grande Prairie area.

Guidance will be impacted by the reduction to capital investment and we now expect exit production or production for the final quarter of 2009 to be approximately 8,400 to 8,600 Boe per day, an increase of 5% over 2008 fourth quarter production. This results in year over year production growth of 15% to 20% (average 2008 production was 6,975 Boe per day). Operating costs for the remainder of 2009 are forecast to be $5.50 per Boe which is somewhat lower than previous guidance as a result of shutting in higher cost wells and increased production from our Parkland property. General and administrative costs for the year are still expected to be $1.25 per Boe (unchanged) and the corporate royalty rate, giving effect to the New Royalty Framework's effect on Alberta production, is expected to average 19% in 2009 (down from our previous estimate of 21%).

Our capital is expected to go a little further through the remainder of this year with the cost of drilling and completing wells potentially declining by 10% to 15% based on information available at this time. This is primarily the result of lower steel costs, reductions in day rates for drilling rigs and reduced bid levels on fracture treatments.

Corporate production is currently approximately 8,100 Boe per day with 750 Boe per day shut in as a result of low natural gas prices. At current natural gas prices, we expect to maintain corporate production at this level through the third quarter.

In the current depressed natural gas price environment, our focus remains on accretive growth in net asset value which will be accomplished by:

- shutting in higher cost wells or properties so that reserves are not produced at a loss.

- drilling fewer horizontal Montney gas wells given that the increase in forward strip pricing encourages us to defer drilling wells with high initial rates and steep initial declines.

- continuing to drill Montney vertical step-outs which add horizontal locations and new reserves but do not have a meaningful impact on production.

- advancing our knowledge of the HRB Devonian shale play by drilling multi-stage frac horizontal wells as well as additional vertical delineation wells.

- testing the development potential of the Jean Marie formation on our large land position in the Junior area.

This will impact production growth in the near term. Production growth will remain subdued until natural gas prices recover to a level where an acceptable economic return can be generated and where our cash flow is large enough to support funding both a development program as well as growth initiatives (approximately $5 per GJ at AECO). Given our control of infrastructure at Parkland and inventory of horizontal Montney development locations which have been defined with vertical well control, we expect to be able to rapidly increase corporate production when the price of natural gas inevitably recovers.

At Parkland, considerable upside potential remains associated with:

- expanding the areal extent of our Montney discovery which could cover as many as 15 to 17 net sections with up to 54 undrilled horizontal locations (four horizontal wells per section) representing potential future production additions of as much as 21,600 Boe per day.

- separate, new pool Montney leads on the 72 net sections of Montney rights that we own which will be further tested with at least one vertical well this year and we will also monitor the progress of competitors in the immediate area.

- recognizing a higher recovery factor and/or a lower porosity cut-off which would increase DPIIP (gas in place) on our existing lands and potentially add to the inventory of horizontal locations.

- Additional facility expansions to further increase recovery of natural gas liquids ('NGLs').

Although reserves at Parkland have increased significantly over the last two years, this is far from being a mature asset.

On August 6th, the Province of British Columbia announced an oil and gas stimulus package to boost investment which included four royalty initiatives. Three of these initiatives are expected to provide an immediate benefit to Storm including:

- The two percent Royalty Relief Program which applies to the first 12 months of production for wells spudded before the end of June 2010.

- The 15% increase in the royalty deductions available to wells that qualify for the Deep Well Credit program.

- The qualification of horizontal wells drilled between 1,900 and 2,300 metres of true vertical depth into the Deep Well Credit program which would include most of the horizontal wells drilled in the Montney at Parkland.

The total benefit of all three initiatives amounts to approximately $1.0 to $1.2 million per Montney horizontal at Parkland using natural gas prices of $5.30 per GJ (2010 futures price) to $6.15 per GJ (2011 futures price). This should increase Storm's cash flow in both the short term (two percent Royalty Relief Program) and long term (Deep Well Credit Program) which should correspondingly allow us to increase our planned level of expenditures in British Columbia. For example, instead of drilling nine horizontals at Parkland in 2010 (preliminary plan), we should be able to fund the drilling of eleven horizontal wells. Any additional wells we drill should increase employment in the short term and should result in incremental growth in our natural gas production which, longer term, provides the Province with additional royalty revenue. Thankfully, British Columbia is willing to be realistic in their assessment of industry conditions and is trying to ensure that their fiscal regime is fair and will also encourage investment during the current difficult and challenging business environment. Ultimately, we expect this to result in increased prosperity for British Columbians as additional capital is invested in the Province with some of this capital coming from the equity markets (investors will direct additional capital into companies active in British Columbia) and some being attracted away from areas with less favorable fiscal regimes (Alberta).

Natural gas prices remain at relatively depressed levels making it challenging for us to fund growth in production from cash flow while also making a significant investment in infrastructure at Parkland. Although production growth is deferred in the short term, the additional investment in our infrastructure at Parkland provides an immediate benefit in the form of increased production and is also a key step in our efforts to maximize the future economic value of this important asset. Despite the current difficult environment, we are very optimistic about our future growth potential given the high quality of our asset base, which contains several years of low risk development opportunities as well as exposure to what could potentially be a very high impact gas project in the HRB. Our low cost structure does leave us with more flexibility than most and we do expect to show accretive growth in net asset value this year.

Sincerely,

Brian Lavergne, President and Chief Executive Officer

August 13, 2009

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL AND OPERATING RESULTS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2009

Set out below is management's discussion and analysis ("MD&A") of financial and operating results for Storm Exploration Inc. ("Storm" or the "Company") for the three and six months ended June 30, 2009. It should be read in conjunction with the unaudited consolidated financial statements for the three and six months ended June 30, 2009, the audited consolidated statements for the year ended December 31, 2008 and other operating and financial information included in this press release. In addition, readers are directed to the discussion below regarding Forward-Looking Statements, Boe Presentation and Non-GAAP Measurements.

This management's discussion and analysis is dated August 13, 2009.

Introduction and Limitations:

Basis of Presentation - Financial data presented below have largely been derived from the Company's unaudited consolidated financial statements for the three and six months ended June 30, 2009, prepared in accordance with Canadian Generally Accepted Accounting Principles ("GAAP"). Accounting policies adopted by the Company are set out in footnote 2 to the unaudited consolidated financial statements for the three and six months ended June 30, 2009 and in footnote 2 to the Company's audited consolidated financial statements for the year ended December 31, 2008. The reporting and the measurement currency is the Canadian dollar. Unless otherwise indicated, tabular financial amounts, other than per share and per Boe amounts, are in thousands.

Forward-Looking Statements - Certain information set forth in this document, including management's assessment of Storm's future plans and operations, contains forward-looking information (within the meaning of applicable Canadian securities legislation). Such statements or information are generally identifiable by words such as "anticipate", "believe", "intend", "plan", "expect", "estimate", "budget", "outlook", "forecast" or other similar words and include statements relating to or associated with individual wells, regions or projects. Any statements regarding the following are forward-looking statements:

- future crude oil or natural gas prices;

- future production levels;

- future capital expenditures and their allocation to exploration and development activities;

- future drilling of new wells;

- future earnings;

- future asset acquisitions or dispositions;

- future sources of funding for capital program;

- future debt levels;

- availability of committed credit facilities;

- development plans;

- ultimate recoverability of reserves or resources;

- expected finding and development costs and operating costs;

- estimates on a per share basis;

- dates by which certain areas will be developed; and

- changes to any of the foregoing.

Statements relating to "reserves" or "resources" are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future.

The forward-looking statements are subject to known and unknown risks and uncertainties and other factors which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include the material risks described in Storm's Annual Information Form and this MD&A under "Risk Assessment" and the material assumptions disclosed in the "Production and Revenue" section hereof under the headings "Production Profile and Per Unit Prices"