Storm Exploration Inc.
TSX : SEO

Storm Exploration Inc.

November 12, 2009 22:27 ET

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

CALGARY, ALBERTA--(Marketwire - Nov. 12, 2009) - Storm Exploration Inc. (TSX:SEO)



Consolidated Highlights

Three Three Nine Nine
Thousands of Cdn$, except Months to Months to Months to Months to
volumetric and per share Sept. 30, Sept. 30, Sept. 30, Sept. 30,
amounts 2009 2008 2009 2008
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Financial
Gas sales 12,563 30,547 (1) 48,196 86,335(1)
NGL sales 2,416 3,612 6,320 9,240
Oil sales 4,428 (1) 5,835 9,308 (1) 16,886
Royalty income 29 221 143 616
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Production revenue 19,436 (1) 40,215 (1) 63,967 (1)113,077(1)
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Funds from operations (2) 8,618 24,290 30,798 67,058
Per share - basic ($) 0.18 0.54 0.67 1,50
Per share - diluted ($) 0.18 0.53 0.65 1.46
Net income (loss) (1,522) 12,829 (2,464) 28,718
Per share - basic ($) (0.03) 0.28 (0.05) 0.64
Per share - diluted ($) (0.03) 0.28 (0.05) 0.63
Capital expenditures, net of
dispositions 14,430 27,057 49,764 59,612
Debt, including working capital
deficiency 98,875 (3) 83,904 98,875 (3) 83,904
Weighted average common shares
outstanding (000s)
Basic 46,600 44,692 46,128 44,638
Diluted 47,812 46,001 47,230 45,873
Common shares outstanding (000s)
Basic 46,669 44,699 46,669 44,699
Fully diluted 49,775 47,015 49,775 47,015
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Operations

Oil equivalent (6:1)
Barrels of oil equivalent (000s) 739 654 2,240 1,803
Barrels of oil equivalent
per day 8,030 7,107 8,207 6,581
Average selling price
(Cdn$ per Boe) 24.56 (1) 61.17 (1) 28.41 (1) 62.37(1)
Gas production
Thousand cubic feet (000s) 3,809 3,409 11,561 9,352
Thousand cubic feet per day 41,399 37,050 42,349 34,131
Average selling price
(Cdn$ per Mcf) 3.30 8.96 (1) 4.17 9.23(1)
NGL Production
Barrels (000s) 54 37 151 95
Barrels per day 583 397 553 348
Average selling price
(Cdn$ per barrel) 45.06 98.90 41.87 96.92
Oil Production
Barrels (000s) 50 49 163 149
Barrels per day 547 535 596 545
Average selling price
(Cdn$ per barrel) 62.86 (1) 118.48 56.20 (1) 113.17
Wells drilled
Gross 4.0 9.0 8.0 20.0
Net 4.0 8.7 6.8 18.8
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(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.


PRESIDENT'S MESSAGE

THIRD QUARTER 2009 HIGHLIGHTS

- Production increased to 8,030 Boe per day, a 13% increase from production of 7,107 Boe per day in the same period one year ago. This is a per share increase of 8% using basic shares outstanding at quarter end. Approximately 450 Boe per day was shut in or curtailed for economic reasons during the quarter and another 100 Boe per day was shut in as a result of scheduled maintenance turnarounds at two gas plants in the Grande Prairie area.

- Drilled four gross wells (all 100% working interest) with 100% success resulting in four gas wells including one horizontal Montney development well at Parkland.

- Funds from operations for the quarter was $8.6 million, or $0.18 per diluted share, a decrease of 66% from $0.53 per diluted share in the prior year third quarter. A year-over-year decline of 61% in the per Boe sales price more than offset 8% growth in production per share.

- The third quarter cash flow netback of $11.67 per Boe represents a decline of 69% from the cash flow netback of $37.69 per Boe in the year earlier period. This was entirely due to the 61% decline in the per Boe sales price over the same period. Our cost structure improved with total cash costs including operating expense, interest expense, transportation costs, and general and administrative expense averaging $9.50 per Boe in the quarter, a decline of 9% from the year earlier period. Notably, operating costs were $5.30 per Boe in the quarter, a decline of 18% from the previous year.

- Storm incurred a net loss for the quarter of $1.5 million, or a loss of $0.03 per diluted share. This has been and continues to be a challenging and very difficult business environment. Charges for depletion, depreciation and accretion at $14.49 per Boe were 12% lower year over year, but this improvement was more than offset by the decline in commodity prices over the same period.

- Capital investment totaled $14.4 million in the quarter, leaving bank debt and working capital deficiency at $98.9 million or 2.9 times annualized third quarter funds from operations. Giving effect to the minor property disposition described below, pro forma debt at quarter end would approximate $82 million or 2.4 times annualized third quarter funds from operations. Our revolving bank credit facility was recently confirmed at $120 million. Year over year, total debt has increased by 18% which is in proportion to production growth of 13%.

- Entered into financial hedges to protect our winter capital program. Natural gas hedges include 28,000 GJ per day for November to December 2009 at an average price of $4.53 per GJ, or $5.40 per Mcf, and 24,500 GJ per day for January to June 2010 at an average price of $4.85 per GJ, or $5.77 per Mcf. Our crude oil hedge is for 450 barrels of oil per day at a price of Cdn $83.45 per barrel for January to June 2010.

- Subsequent to the end of the quarter, we entered into an agreement to dispose of non-core properties in the Grande Prairie area for proceeds totaling $17.15 million effective November 1, 2009 ($14 million cash plus 5.08 million shares of Bellamont Exploration Ltd. valued at $0.62 per share). Production from the properties being sold averaged 214 Boe per day in the third quarter.

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 6,130 Boe per day in the third quarter. During the quarter, approximately 240 Boe per day was shut in or curtailed due to low natural gas prices. Current production is approximately 6,000 Boe per day with no production shut in or curtailed.

During the third quarter, our Parkland activity was as follows:

- One Montney horizontal well was drilled, completed and tied in and is currently producing 4.0 Mmcf per day, which represents 725 Boe per day of net sales.

- Two vertical Montney step-outs (2.0 net) were drilled and cased, expanding the productive area of our Montney discovery. One of the verticals was completed and flow tested with a final rate of 700 Mcf per day.

- One vertical Montney exploratory well (1.0 net) was drilled and cased to evaluate a new pool Montney lead. Analysis of the wireline logs suggests the reservoir quality is poor and, as a result, completion and evaluation is being deferred.

- Construction started on the expansion of our second facility which will include installation of a natural gas liquids extraction (refridge) plant.

In the fourth quarter, we are planning to drill two horizontal development wells (2.0 net) in our Montney discovery and to complete the expansion of our second facility.

A total of $16 million has been budgeted in 2009 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. Construction has started on an expansion of this facility to 25 Mmcf per day of capacity and on the addition of a refridge plant. Total cost for this expansion is estimated to be $12 million with $4.2 million having been invested by the end of the third quarter. We expect the expansion to be operational by early December and should result in liquids recoveries increasing from 16 to 45 barrels per Mmcf of sales gas on volumes processed through this facility. Approximately one-third of Storm's current production at Parkland will continue to be processed at the McMahon gas plant where liquids recoveries will be unchanged from current levels. Natural gas liquids production at our Parkland property is expected to increase by 400 to 600 barrels per day and an estimated two to three million barrels of natural gas liquids should be added to our proven plus probable reserves (based on the Discovered Petroleum Initially in Place(1) ("DPIIP") and recoverable raw gas recognized in the 2008 year-end reserve evaluation).

Geological mapping completed by Storm 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. assigned proven and probable reserves to 11 net sections (7,040 acres) based on 13 successful vertical Montney gas wells. Estimated DPIIP in these 11 net sections was 409 Bcf. Estimated DPIIP relies on a sandstone scale porosity cut-off of approximately 6% which may be conservative in comparison to what is being used by other reserve evaluators in the area. The three successful vertical Montney step-outs we have drilled this year and the recompletion of two suspended wells in the first and third quarters will potentially result in proven and probable reserves being assigned to 13 to 14 net sections at year end. No further step-out drilling is planned for the fourth quarter.

(1) Discovered Petroleum Initially in Place is defined in the COGEH handbook as the quantity of hydrocarbons that are estimated to be in place within a known accumulation. 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.

Production from our Montney discovery currently totals 28 Mmcf per day of gross raw gas from 15 horizontal Montney gas wells and 11 Montney vertical wells. The first year rate from our horizontal wells is averaging approximately 2.4 Mmcf per day of raw gas, which represents a sales volume of 425 Boe per day per well.

Recently, the Province of British Columbia announced an oil and gas stimulus package which reduced the qualifying depth for the Deep Well Credit program to 1,900 metres of true vertical depth and also increased the available royalty credits by 15%. The majority of the horizontal wells drilled in our Montney discovery at Parkland will qualify for this program which provides for a benefit of approximately $900,000 per horizontal well. The stimulus package also includes a 2% royalty rate for the first year of production from all natural gas wells drilled between September 1, 2009 and June 30, 2010 and commencing production before December 31, 2010. The benefit offered by the 2% royalty rate will be dependent on natural gas prices.

In the third quarter, the field netback realized at our Parkland property was $15.85 per Boe, production was 6,028 Boe per day (87.6% natural gas), and operating costs were $3.64 per Boe.

Grande Prairie Area, North West Alberta

Production from this area averaged 1,332 Boe per day in the third quarter with approximately 160 Boe per day shut in during the quarter due to low natural gas prices and scheduled maintenance turnarounds. Current production is approximately 1,400 Boe per day with no wells shut in or curtailed.

We have postponed drilling two locations (75% average working interest) planned for the fourth quarter that were twins of existing wells targeting bypassed pay in a shallower formation. The natural gas price is still relatively depressed and this has reduced the discretionary capital we have available for lower impact projects.

We recently entered into an agreement to dispose of non-core properties at Saddle Hills, Sinclair, and Valhalla for proceeds totaling $17.15 million which is comprised of $14 million cash plus 5.08 million shares of Bellamont Exploration Ltd. valued at $0.62 per share. The effective date of the sale is November 1, 2009 and closing is expected on or before December 1, 2009. Production from the properties being sold averaged 214 Boe per day (24% natural gas) in the third quarter. At the end of 2008, proven and probable reserves assigned to these properties totaled 1.176 million Boe (1.11 million Boe adjusted for production to November 1) with future development capital of $3.8 million.

Cabin-Kotcho-Junior Area, North East British Columbia

Net production from this area averaged 519 Boe per day in the third quarter with current production at approximately 525 Boe per day. During the third quarter, 150 Boe per day was shut in due to low natural gas prices. Currently, no wells are shut in or curtailed.

This winter, we plan to drill two horizontal wells plus install compression at an existing facility 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. The estimated cost to drill, complete, and tie in a horizontal well is approximately $2.1 million. Another $2.7 million will be invested in pipelining both wells plus installing compression (37% Q1, 63% Q2). 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 initially be one horizontal well per section.

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

Storm's undeveloped land position in the HRB is prospective for Devonian shale gas and currently totals 66 gross sections at a 40% working interest (16,900 net acres) 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 test the productivity and quality of the Muskwa and Otter Park shales on 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:

- 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; and

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

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

In the first quarter of 2010, the second vertical well will be completed and tested in both the Muskwa/Otter Park intervals and in the Evie/Klua interval, a third vertical delineation well will be drilled and cored, 3-D seismic will be recorded, and an all-season road will be constructed. In the third and fourth quarters, two horizontal wells are planned with the estimated cost of each well totaling $14 million gross including $4 million for drilling each horizontal and $10 million for each 10-frac completion. In total, Storm will invest approximately $37.5 million gross or $15 million net to our 40% working interest to advance the HRB shale project during 2010.

The horizontal wells scheduled to be drilled next summer are a critical part of advancing this play towards commerciality. The production data (initial rates, declines, estimates of potential recoverable reserves) and the operational experience we gain will be used to determine the economic viability of larger scale exploitation with multi-stage frac horizontal wells. It is likely to be mid-2011 before we have an opinion as to the commerciality of the HRB shales in our lands. Although the HRB has attracted a lot of attention and excitement recently, 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. In October 2009, SGR completed a private equity issue and raised $12.4 million (net of share issue costs) at a price of $6.50 per share. Storm participated in this equity issue and acquired an additional 0.45 million shares at $6.50 per share. Storm's investment to date in SGR totals $9.1 million and our share ownership position totals 2.5 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 by SVI in August 2008, which was at $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 1,893 Boe per day in the second quarter generating funds from operations of Cdn $8.0 million which included a derivatives (hedging) gain of $6.96 million. SVI ended the second quarter with cash of Cdn $19.3 million and with Cdn $36.4 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. The well flows at a stable rate of 209 barrels per day of light oil, at a 0.3% water cut. SVI has received approval to extend the test until a cumulative volume of 90,000 barrels has been produced. A 3-D seismic survey and two additional appraisal/development wells will be drilled in the first half of 2010 to assess the commercial potential of this discovery.

SVI recently entered into two property acquisition agreements at Cobra (UKCS gas) and Adam (onshore Tunisian oil) which should add 750 Boe per day of production and 3 million Boe of proven plus probable reserves at a cost of USD $23 million. Both acquisitions are expected to close in the fourth quarter.

Offshore Tunisia, in the Gulf of Hammamet, SVI is planning to spud its first exploration well at Fushia, with SVI paying 38% of the cost while retaining a 65% working interest. Target is light oil in the Birsa sandstone, with estimated DPIIP being 40 to 100 millions barrels of oil in place. With respect to Cosmos, SVI is in the process of sourcing a partner (maintaining 40% operated working interest), has finalized the FPSO selection, agreed to participation terms with ETAP and is planning for first oil in mid-2011. Cosmos South was discovered in 1986, with two tested wells and DPIIP is potentially 25 million barrels of oil in place with another 12 million barrels of oil in place associated with the adjacent terraces.

OUTLOOK

Storm's guidance for 2009 remains largely unchanged from our last update on August 13, 2009:

- Capital investment for the year is expected to be $68 million including $16 million to be invested in expanding our infrastructure at Parkland and $9 million for the acquisition of a gross overriding royalty at Parkland, which was completed in the first quarter. This does not include the impact of the recently announced disposition of non-core properties in the Grande Prairie area for gross proceeds totaling $17.15 million ($14 million cash plus 5.08 million Bellamont Exploration Ltd. Shares, valued at $0.62 per share), which is not expected to close until December 1, 2009.

- The drilling program includes 11 gross wells (8.9 net) including four Montney horizontal wells (4.0 net) at Parkland.

- Exit production or production for the final quarter of 2009 should approximate 8,200 to 8,300 Boe per day which will result in year-over-year production growth of 18%. This is slightly lower than our most recent guidance of 8,400 to 8,600 Boe per day due to a weather related delay in the completion and tie in of a recent horizontal well at Parkland, the disposition of 214 Boe per day in the Grande Prairie area effective November 1, 2009 and increasing gathering system pressures at Parkland (this will not be an issue once the facility expansion is completed).

- Operating costs for the year are forecast to decline to $5.50 per Boe as a result of shutting in higher cost wells and increased production from our lower cost Parkland property.

- General and administrative costs for the year are expected to be $1.40 per Boe.

- The corporate royalty rate, giving effect to the New Royalty Framework's effect on Alberta production, is expected to average 17% which is lower than earlier estimates, due to natural gas prices being lower than forecast.

Cash flow is expected to total $45 million in 2009, assuming average 2009 prices of $3.80 per GJ at AECO for natural gas and Cdn $67.00 per barrel for oil at Edmonton. This results in debt and working capital deficiency at year end being approximately $92 million.

Our preliminary estimate as to guidance for 2010 is as follows:

- Capital investment totaling $80 to $85 million, which will include drilling 21 gross wells (17.0 net) including nine Montney horizontal wells (8.4 net) at Parkland, two Jean Marie horizontal wells (2.0 net) in the Junior area, and two HRB shale horizontals (0.8 net). This also includes the expenditure of $15 to $20 million in the HRB to advance the development of our shale gas project. No major infrastructure expenditures are contemplated at this time.

- Exit production or production for the final quarter of 2010 should approximate 9,500 to 10,000 Boe per day.

- Operating costs for the year are forecast to be $4.50 to $5.00 per Boe.

- General and administrative costs for the year are expected to be $1.10 per Boe

- The corporate royalty rate is expected to average 20% and this does not include the impact of British Columbia's royalty incentives.

We expect to fund the 2010 capital investment program entirely with cash flow, which is expected to total $85 to $90 million, assuming average prices of $5.25 per GJ at AECO for natural gas and Cdn $88.00 per barrel for oil at Edmonton.

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.

- Increasing DPIIP (gas in place) and/or the recovery factor through increased knowledge and understanding of the Montney formation which will come with more production history on our existing horizontal wells as well as from trying new ideas, including horizontal wells targeting the lower part of the upper Montney.

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

Although reserves at Parkland have increased significantly over the last two years, there still remains significant upside associated with this asset.

Natural gas prices are currently above $4 per GJ at AECO, which is a significant improvement from the depressed pricing of $2.75 to $3.25 per GJ at AECO that we experienced in the last two quarters. We currently have no production shut in or curtailed given that all of our properties are profitable with natural gas prices above $4 per GJ at AECO. With our low cost structure, a natural gas price of $5 per GJ at AECO in 2010 provides sufficient cash flow to allow us to fund 15% growth in production as well as invest $15 to $20 million in the HRB to advance our shale gas project. In order to provide price support and provide enough cash flow to meet these objectives, we have entered into short-term financial hedges on both our natural gas and liquids production, with specifics provided in management's discussion and analysis and in the financial statements. These hedges, combined with the disposition of non-core properties in the Grande Prairie area, ensure that we have the financial capacity to execute our 2010 plans.

Our focus on accretively growing net asset value has not changed. We look at potential reserve additions from a project and also the expected operating netback, which then provides an estimate of financial return (similar to recycle ratio, but we use our estimate of the ultimate reserve potential instead of what is immediately recognized for reserves). Although we have reviewed several acquisition and farm-in opportunities this year, very few have offered us the potential for accretive growth in net asset value. In general, despite the depressed business environment, higher quality assets and undeveloped land are still too costly in relation to the potential upside and associated risk. We can afford to be patient in our hunt for new opportunities given the future growth potential offered by our existing asset base which includes several years of low-risk development opportunities as well as exposure to what could potentially be a very high impact shale gas project in the HRB.

In closing, we are saddened to announce that one of our long standing directors, Henry Lawrie, passed away recently. Henry had been a director of Storm since inception in July 2004 and he provided invaluable guidance and advice to management, the Board and its Audit and Reserve Committees, which won't be easily replaced. Henry's focus on practicality and clarity in disclosure of information and financial results was particularly refreshing in the current environment where disclosure and financial reporting have become more complicated and confusing. The time and effort that Henry invested in helping us at Storm over the last five years has been greatly appreciated and we will truly miss his enthusiasm and support.

Sincerely,

Brian Lavergne, President and Chief Executive Officer

November 12, 2009

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL AND OPERATING RESULTS FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 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 nine months ended September 30, 2009. It should be read in conjunction with the unaudited consolidated financial statements for the three and nine months ended September 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 November 11, 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 nine months ended September 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 nine months ended September 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 revenues or costs or revenues or costs per commodity unit;

-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 or time periods by which certain capital 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" and "Royalties"; under "Field Netbacks", "Interest", "General and Administrative Costs" and "Future Income Taxes"; under the "Investment and Financing" section hereof, under the headings "Working Capital", "Bank Debt, Liquidity and Capital Resources", "Future Income Taxes", "Asset Retirement Obligation", "Share Capital" and "Contractual Obligations"; industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and external sources, as described either in this document or in the Company's MD&A contained in its annual report for the year ended December 31, 2008. All of these caveats should be considered in the context of current economic conditions, in particular reduced commodity prices and the condition of financial institutions and markets, each of which is outside the control of the Company. Readers are advised that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Storm's actual results, performance or achievement, could differ materially from those expressed in, or implied by, these forward-looking statements. Storm disclaims any intention or obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required under securities law. References to forward-looking information are made in the press release dated November 12, 2009 this MD&A forms part of. The forward-looking statements contained herein are expressly qualified by this cautionary statement.

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.

Non-GAAP Measurements - Within management's discussion and analysis, references are made to terms which are not recognized under GAAP in Canada. Specifically, "funds from operations", "funds from operations per share", and "netbacks" do not have any standardized meaning as prescribed by GAAP in Canada and are regarded as non-GAAP measures. It is likely that these non-GAAP measurements may not be comparable to the calculation of similar amounts for other entities. In particular, funds from operations is not intended to represent, or be equivalent to, cash flow from operating activities calculated in accordance with Canadian GAAP which appears on the Company's consolidated statements of cash flows. Funds from operations and similar non-GAAP terms are used to benchmark operations against prior periods and peer group companies. Funds from operations is also used to determine leverage for the purposes of establishing interest costs under the Company's banking agreement.

A reconciliation of funds from operations to cash flows from operating activities is as follows:



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Three Three Nine Nine
Months Months Months Months
to to to to
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2009 2008 2009 2008
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Cash flow from operating
activities $8,483 $24,131 $32,208 $65,901
Net change in non-cash working
capital items 135 159 (1,410) 1,157
----------------------------------------
Funds from operations $8,618 $24,290 $30,798 $67,058
----------------------------------------------------------------------------
----------------------------------------------------------------------------


OPERATIONAL AND FINANCIAL RESULTS

Production and Revenue

Average Daily Production

----------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
to to to to
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Natural gas (Mcf/d) 41,399 37,050 42,349 34,131
Natural gas liquids (Bbls/d) 583 397 553 348
Crude oil (Bbls/d) 547 535 596 545
----------------------------------------
Total (Boe/d) 8,030 7,107 8,207 6,581
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Total Boe production in the third quarter of 2009 increased by 13% when compared to the same quarter in 2008 and fell by 2% when compared to the second quarter of 2009. The year-over-year production increase is largely attributable to increased gas production from the Company's core Parkland area. Within the Parkland area, Montney gas production approximated 5,000 Boe per day in the third quarter of 2009, compared to 2,000 Boe per day in the same quarter of 2008.

In 2009, production has not grown quarter over quarter. The primary area for production growth within the Company's opportunity inventory is its Montney natural gas property at Parkland, British Columbia. Horizontal wells in the Montney tend to be characterized by very high initial deliverability, followed by rapid production declines for a period of several months; thereafter, production declines tend to slow. Production growth from drilling horizontal wells at Parkland would have resulted in the Company selling volumes produced at high initial rates into a depressed market for natural gas. As a result, drilling activity in this area has been reduced which has impacted quarterly production growth.

Production, averaging 450 Boe per day, was shut in or curtailed during the third quarter of 2009 due to continuing low natural gas prices. Year to date, production shut in has averaged 500 Boe per day.

Production per million shares outstanding in the third quarter of 2009 averaged 172 Boe per day, compared to 159 Boe per day for the third quarter of 2008, an increase of 8%.

For the nine months ended September 30, 2009 production increased by 25% when compared to the equivalent period in 2008, or an increase of 21% per million shares outstanding for each period.



Production Profile and Per-Unit Prices

----------------------------------------------------------------------------
Three Months to Three Months to
September 30, 2009 September 30, 2008
----------------------------------------------------------------------------
Average Average
Selling Price Selling Price
Percentage Before Percentage Before
of Total Boe Transportation of Total Boe Transportation
Production Costs Production Costs
----------------------------------------------------------------------------
Natural gas - Mcf 86% $3.30 87% $9.37
Natural gas
liquids - Bbl 7% $45.06 6% $98.90
Crude oil - Bbl 7% $69.17 7% $118.48
-----------------------------------------------------------
Per Boe $24.99 $63.29
----------------------------------------------------------------------------
----------------------------------------------------------------------------



----------------------------------------------------------------------------
Nine Months to Nine Months to
September 30, 2009 September 30, 2008
----------------------------------------------------------------------------
Average Average
Selling Price Selling Price
Percentage Before Percentage Before
of Total Boe Transportation of Total Boe Transportation
Production Costs Production Costs
----------------------------------------------------------------------------
Natural gas - Mcf 86% $4.17 87% $9.47
Natural gas
liquids - Bbl 7% $41.87 5% $96.92
Crude oil - Bbl 7% $60.41 8% $113.17
-----------------------------------------------------------
Per Boe $28.72 $63.58
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Per-unit prices do not include adjustments for hedging gains or losses.

Storm's production base is largely natural gas and associated liquids. In addition, Storm's prospect inventory is largely focused on natural gas and, based on exploitation of the Company's existing asset base, in the short and medium term crude oil will not materially increase as a percentage of Boe production.

Storm's gas production in Alberta and British Columbia is sold at prices which reflect both the benchmark AECO daily index pricing and Station 2 daily index pricing. The widely recognized benchmark average AECO daily index price for the third quarter of 2009 was $2.78 per GJ, compared to $7.45 per GJ for the third quarter of 2008, a year-over-year reduction of 63%. The AECO daily index price for the third quarter of 2009 was the lowest quarterly price since the second quarter of 1999. Compared to an AECO index price of $3.27 per GJ for the second quarter of 2009, third quarter pricing was lower by 15%. In addition, for the third quarter of 2009, the average Station 2 daily index price, which applied to approximately 75% of Storm's gas production both in the quarter and year to date, was about 1% lower than the average AECO daily index price. For the first nine months of 2009, AECO pricing was approximately 3% higher than Station 2. Storm's corporate average realized price per Mcf for natural gas for the third quarter of 2009 was approximately 13% higher than the equivalent AECO daily index price. This pricing premium is attributable to high heat content natural gas produced from the Montney formation at Parkland. In addition to superior heat content, Montney natural gas contains significant natural gas liquids volumes which has resulted in an approximate 59% year-to-date increase in natural gas liquids production in 2009 over 2008.



Production by Area - Boe/d

----------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
to to to to
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Fort St John/Parkland - BC 6,130 4,422 6,084 3,758
Grande Prairie - AB 1,332 1,738 1,467 1,853
Cabin-Kotcho-Junior - BC 519 883 605 910
Other 49 64 51 60
----------------------------------------
Total 8,030 7,107 8,207 6,581
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The above sets out the average production from each of Storm's core areas. The Company's focus on the Parkland area has resulted, in the third quarter, in a 39% year-over-year production growth from this area. Correspondingly, reduced investment in Alberta is evidenced by an approximate 23% reduction in quarterly year-over-year production. For the nine months ended September 30, 2009, Parkland production increased by 62% year over year, while Grand Prairie production fell by 21%, reflecting the focus of Storm's investment program.



Production Revenue

----------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
to to to to
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Natural gas $12,563 $31,933 $48,196 $88,522
Natural gas liquids 2,416 3,612 6,320 9,240
Crude oil 3,484 5,835 9,822 16,886
Royalty income 29 221 143 616
----------------------------------------
Revenue from product sales 18,492 41,601 64,481 115,264
Hedging (losses) gains 944 (1,386) (514) (2,187)
----------------------------------------
Total production revenue $19,436 $40,215 $63,967 $113,077
----------------------------------------------------------------------------
----------------------------------------------------------------------------


A reconciliation of revenue from product sales between the quarters ended September 30, 2009 and 2008 is as follows:



----------------------------------------------------------------------------
Natural Gas Royalty
Natural Gas Liquids Crude Oil Income Total
----------------------------------------------------------------------------
Revenue from product
sales - Q3 2008 $31,933 $3,612 $5,835 $221 $41,601
Contribution from
increased production
year over year 3,749 1,692 135 (141) 5,435
Contribution from
increased product
prices year over
year (23,119) (2,888) (2,486) (51) (28,544)
-------------------------------------------------------
Revenue from product
sales - Q3 2009 $12,563 $2,416 $3,484 $ 29 $18,492
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The collapse in revenues for 2009 is largely due to the fall in natural gas prices. Storm's realized price per Mcf before hedging adjustments for the last five quarters was:



----------------------------------------------------------------------------
Quarter Average Price Percentage
----------------------------------------------------------------------------
Q3 2008 $9.37 100%
----------------------------------------------------------------------------
Q4 2008 $7.49 84%
----------------------------------------------------------------------------
Q1 2009 $5.52 62%
----------------------------------------------------------------------------
Q2 2009 $3.65 41%
----------------------------------------------------------------------------
Q3 2009 $3.30 37%
----------------------------------------------------------------------------


Hedging

Crude Oil:

Storm entered into a fixed price sale agreement in respect of 350 barrels of crude oil per day, at a price of $59.40 per barrel for the period April 1 to June 30, 2009 and collars for the same volume for each of the last two quarters of 2009, at prices of $60 - $65/Bbl and $60 - $70/Bbl, respectively. During the three- and nine-month periods to September 30, 2009, the Company realized a hedging loss of $0.3 million and $0.7 million, respectively. In addition, the Company has a crude oil swap in place for the period January 1, 2010 to June 30, 2010 in respect of 450 barrels of crude oil per day at a fixed price of $83.45 per barrel. At September 30, 2009 the Company recognized on the Consolidated Statements of Income (Loss) and Retained Earnings, an unrealized mark-to-market gain of $1.3 million and $0.2 million for the three- and nine-month periods to September 30, 2009 on these derivative contracts. Accounting for crude oil contracts follows mark-to-market rules.

Natural Gas:

Storm also entered into fixed price natural gas sales contracts for the period November 1, 2009 until June 30, 2010. Details are as follows:



Volume Term
----------------------------------------------------------------------------
28,000 GJ/day November 2009 - March 2010
21,000 GJ/day April 2010 - June 2010

Pricing:

----------------------------------------------------------------------------
Period Price per GJ
----------------------------------------------------------------------------
November 2009 $ 4.53
----------------------------------------------------------------------------
December 2009 $ 4.53
----------------------------------------------------------------------------
First Quarter 2010 $ 4.89
----------------------------------------------------------------------------
Second Quarter 2010 $ 4.78
----------------------------------------------------------------------------


The Company uses hedge accounting rules for these contracts and has recognized an unrealized hedging loss in the amount of $4.3 million on the Consolidated Statements of Comprehensive Income (Loss).

Royalties



----------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
to to to to
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Charge for period $ 2,534 $ 8,733 $ 11,147 $ 24,139

Royalties as a percentage of revenue
from product sales before hedging
- Crown 13.4% 19.8% 17.0% 19.8%
- Other 0.3% 1.3% 0.3% 1.2%
----------------------------------------------------------------------------
Total 13.7% 21.1% 17.3% 21.0%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Per Boe $ 3.43 $ 13.36 $ 4.98 $ 13.39
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Royalties are paid primarily to the provincial governments in Alberta and British Columbia. The year-over-year reduction in the effective rate, and the per Boe reduction are, in part, a result of falling commodity prices. Additionally, under the new Royalty Framework in Alberta, royalty rates have fallen below those applicable under the pre-existing royalty regime. Recently announced changes to the New Royalty Framework in Alberta will have no effect on existing royalties, but the extension of the royalty holiday by one year may benefit future quarters and provides the Company with more flexibility regarding the timing of future drilling in Alberta. Similarly, recent changes to the royalty regime in British Columbia will also benefit future quarters. In addition, during the quarter ended September 30, 2009 the Company benefited from certain one-time royalty adjustments relating to prior periods, which are unlikely to be repeated in future periods.



Production Costs

----------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
to to to to
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Charge for period $ 3,915 $ 4,253 $ 12,536 $ 12,679
----------------------------------------------------------------------------

Percentage of revenue from
product sales before hedging 21.2% 10.0% 19.4% 11.0%

----------------------------------------------------------------------------
Per Boe $ 5.30 $ 6.50 $ 5.60 $ 7.03
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Although production grew for both the three and nine months ended September 30, 2009, cost reduction efforts, a better seasonal operating cost profile, the shut in of higher cost production and increasing volumes of lower operating cost natural gas from the Company's Parkland property, resulted in a reduction in both year-over-year and quarter-over-quarter total production costs. Per Boe, the effect was to reduce costs in 2009 by nearly 20% in each of the three- and nine-month periods.

Storm's cash costs per Boe, which comprise transportation, production, general and administrative and interest costs, amounted to $9.50 for the third quarter of 2009, compared to $9.95 for the second quarter of 2009 and to $10.45 for the third quarter of 2008.

For the nine-month periods to September 30, per Boe cash costs amounted to $9.76 in 2009 and $11.94 in 2008.



Transportation Costs

----------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
to to to to
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Charge for period $ 1,022 $ 1,221 $ 3,549 $ 3,887
----------------------------------------------------------------------------
Percentage of revenue from product
sales before hedging 5.5% 3.0% 5.5% 3.0%
----------------------------------------------------------------------------
Per Boe $ 1.38 $ 1.87 $ 1.58 $ 2.16
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Total and per-unit transportation costs fell year over year and quarter over quarter, in spite of flat or increased production. Increased gas production from the Parkland area and the shut in of higher cost production resulted in lower per-unit costs year over year. Storm's low per-unit production and transportation costs reflect Storm's high level of operatorship as well as facility control and ownership.

Field Netbacks



Details of field netbacks per commodity unit are as follows:

----------------------------------------------------------------------------
Three Months to September 30, 2009
----------------------------------------------------------------------------
Natural
Gas Natural
Crude Oil Liquids Gas Total
($/Bbl) ($/Bbl) ($/Mcf) ($/Boe)
----------------------------------------------------------------------------
Product sales $69.17 $45.06 $3.30 $ 24.99
----------------------------------------------------------------------------
Hedging loss - realized (6.30) - - (0.43)
----------------------------------------------------------------------------
Royalty income 0.16 0.04 - 0.04
----------------------------------------------------------------------------
Royalties (11.17) (10.45) (0.37) (3.43)
----------------------------------------------------------------------------
Production costs (1) (7.77) - (0.93) (5.30)
----------------------------------------------------------------------------
Transportation (4.88) (3.14) (0.16) (1.38)
----------------------------------------------------------------------------
Field netback $39.21 $31.51 $1.84 $ 14.49
----------------------------------------------------------------------------
----------------------------------------------------------------------------


----------------------------------------------------------------------------
Three Months to September 30, 2008
----------------------------------------------------------------------------
Natural
Gas Natural
Crude Oil Liquids Gas Total
($/Bbl) ($/Bbl) ($/Mcf) ($/Boe)
----------------------------------------------------------------------------
Product sales $ 118.48 $ 98.90 $ 9.37 $ 63.29
----------------------------------------------------------------------------
Hedging loss - realized - - (0.41) (2.12)
----------------------------------------------------------------------------
Royalty income 0.55 0.40 0.05 0.33
----------------------------------------------------------------------------
Royalties (19.48) (24.22) (2.02) (13.36)
----------------------------------------------------------------------------
Production costs (1) (8.63) - (1.12) (6.50)
----------------------------------------------------------------------------
Transportation (4.56) (1.33) (0.28) (1.87)
----------------------------------------------------------------------------
Field netback $ 86.36 $ 73.75 $ 5.59 $ 39.77
----------------------------------------------------------------------------
----------------------------------------------------------------------------


----------------------------------------------------------------------------
Nine Months to September 30, 2009
----------------------------------------------------------------------------
Natural
Gas Natural
Crude Oil Liquids Gas Total
($/Bbl) ($/Bbl) ($/Mcf) ($/Boe)
----------------------------------------------------------------------------
Product sales $ 60.41 $ 41.87 $ 4.17 $ 28.72
----------------------------------------------------------------------------
Hedging loss - realized (4.21) - - (0.31)
----------------------------------------------------------------------------
Royalty income 0.17 0.06 0.02 0.07
----------------------------------------------------------------------------
Royalties (9.23) (9.65) (0.19) (4.98)
----------------------------------------------------------------------------
Production costs (1) (7.70) - (0.70) (5.60)
----------------------------------------------------------------------------
Transportation (5.10) (3.57) (0.98) (1.58)
----------------------------------------------------------------------------
Field netback $ 34.34 $ 28.71 $ 2.32 $ 16.32
----------------------------------------------------------------------------
----------------------------------------------------------------------------


----------------------------------------------------------------------------
Nine Months to September 30, 2008
----------------------------------------------------------------------------
Natural
Gas Natural
Crude Oil Liquids Gas Total
($/Bbl) ($/Bbl) ($/Mcf) ($/Boe)
----------------------------------------------------------------------------
Product sales $ 113.17 $ 96.92 $ 9.47 $ 63.58
----------------------------------------------------------------------------
Hedging loss - realized - - (0.23) (1.21)
----------------------------------------------------------------------------
Royalty income 1.03 0.43 0.04 0.34
----------------------------------------------------------------------------
Royalties (18.54) (22.39) (2.06) (13.39)
----------------------------------------------------------------------------
Production costs (1) (8.50) - (1.22) (7.03)
----------------------------------------------------------------------------
Transportation (5.23) (2.15) (0.31) (2.16)
----------------------------------------------------------------------------
Field netback $81.93 $ 72.81 $ 5.69 $ 40.13
----------------------------------------------------------------------------

(1) Production costs for natural gas liquids are included with natural gas
costs.


Field netbacks for the third quarter of 2009 fell 64% year over year as a result of a 61% reduction in per Boe revenue. Direct costs, principally price-sensitive royalties, fell by 53% year over year. For the nine months to September 30, 2009, field netbacks fell by 59% year over year. Storm has and may in the future shut in production if individual wells are not providing an acceptable economic return, which may affect production levels in future quarters.

Based on an all-in proved plus probable finding cost for 2008 of $11.10, Storm's recycle ratio (field netback divided by finding costs) for the third quarter of 2009 was 1.3.

Interest



----------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
to to to to
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Charge for period $ 1,036 $ 825 $ 2,438 $ 2,830
----------------------------------------------------------------------------
Per Boe $ 1.40 $ 1.26 $ 1.09 $ 1.57
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Interest is paid on Storm's revolving bank facility. The Company normally borrows using bankers' acceptances plus a stamping fee. Although interest paid on bankers' acceptances has fallen year over year, the stamping fee payable by the Company increased considerably upon the renewal of the Company's banking agreement effective March 25, 2009. Nevertheless, higher debt levels were largely responsible for the year-over-year increase in borrowing costs. Borrowing costs for the third quarter of 2009 increased by 26% over borrowing costs for the third quarter of 2008, with similarly increased borrowing costs expected for the remainder of 2009.



General and Administrative Costs

Total costs
----------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
to to to to
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Gross general and administrative
costs $ 1,504 $ 1,368 $ 4,809 $ 4,121
----------------------------------------------------------------------------
Capital and operating recoveries (455) (835) (1,480) (1,997)
----------------------------------------------------------------------------
Net general and administrative costs $ 1,049 $ 533 $ 3,329 $ 2,124
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Costs per Boe
----------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
to to to to
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Gross general and administrative
costs $ 2.04 $ 2.09 $ 2.15 $ 2.29
----------------------------------------------------------------------------
Capital and operating recoveries (0.62) (1.27) (0.66) (1.11)
----------------------------------------------------------------------------
Net general and administrative costs $ 1.42 $ 0.82 $ 1.49 $ 1.18
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Increases in gross general and administrative costs for the quarter and nine months ended September 30, 2009, when compared to the prior year, were primarily due to an increased staff count, as well as higher year-over-year compensation. Lower field activity levels, when compared to the prior year, resulted in lower capital recoveries with the consequence that net general and administrative costs per Boe for the three and nine months to September 30, 2009 are higher.

Storm does not capitalize general and administrative costs. General and administrative costs per Boe for the following two quarters should be lower, due to higher capital and operating recoveries, resulting from higher levels of field activity.



Stock Based Compensation Costs

----------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
to to to to
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Charge for period $ 587 $ 615 $ 1,388 $ 1,346
----------------------------------------------------------------------------
Per Boe $ 0.79 $ 0.94 $ 0.62 $ 0.75
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Stock-based compensation costs are non-cash charges which reflect the estimated value of stock options issued to Storm's directors and employees. The value of the award is recognized as an expense over the period from the grant date to the date of vesting of the award. The decrease in the charge for the third quarter of 2009 compared to the prior year is a result of certain prior year awards being fully expensed. The marginal increase in the charge for the first nine months of 2009, when compared to the prior year, relates to the issue of additional stock options in 2009, net of prior year awards being fully expensed.



Depletion, Depreciation and Accretion

----------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
to to to to
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Depreciation and depletion charge
for period $ 10,578 $ 10,603 $ 32,334 $ 30,129
----------------------------------------------------------------------------
Accretion charge for period 124 122 363 367
----------------------------------------------------------------------------
Total $ 10,702 $ 10,725 $ 32,697 $ 30,496
----------------------------------------------------------------------------
Total per Boe $ 14.49 $ 16.40 $ 14.59 $ 16.91
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The total charge for depletion and depreciation for the three months to September 30, 2009 compared to the same quarter of 2008 is approximately equal, due to increased product volumes being offset by a lower per-unit rate.

The decrease in the charge for depletion and depreciation per Boe for the third quarter and first nine months of 2009 when compared to the equivalent periods of 2008 is approximately 12% and 14% respectively. The reduction is attributable to proved oil and gas reserves being added, effective January 1, 2009, at a cost considerably lower than in prior periods. Accretion is the increase for the reporting period in the present value of the Company's asset retirement obligation, which is discounted using an interest rate of 8%.

Investment Gain (Loss)

As described in footnote 4 to the consolidated financial statements, Storm accounts for its investment in Storm Gas Resource Corp. ("SGR") using the equity method, in accordance with which the Company's pro rata share of changes in SGR's equity is included in the determination of the Company's net income for the period. The investment gain recognized in 2008 was a dilution gain resulting from a reduction in Storm's ownership position, consequent on the completion by SGR of an equity issue at a price higher than Storm's average investment cost. The investment loss recorded in the third quarter of 2009 represents Storm's pro rata share of changes in SGR's equity.

Future Income Taxes

For the three months ended September 30, 2009, Storm recorded a recovery of future income taxes of $0.6 million compared to a provision for future income taxes of $3.6 million for the quarter ended September 30, 2008. For the nine-month period ended September 30, 2009, the future income tax recovery amounted to $1.3 million compared to a future income tax provision of $10.0 million for the same period of 2008. The statutory combined federal and provincial rate applicable to income in 2009 is 29%, compared to 30% for 2008.

At September 30, 2009, Storm had tax pools carried forward estimated to be $222 million. In addition, Storm has a capital loss in the amount of $10 million available for application against future capital gains.

Net Income (loss) and Net Income (loss) Per Share

The Company incurred a net loss of $1.5 million for the quarter ended September 30, 2009, compared to net income of $12.8 million for the quarter ended September 30, 2008. For the nine months ended September 30, 2009, the net loss amounted to $2.5 million compared to net income of $28.7 million for the same period in the prior year.



----------------------------------------------------------------------------
Three Months to Three Months to Nine Months to Nine Months to
Sept. 30, 2009 Sept. 30, 2008 Sept. 30, 2009 Sept. 30, 2008
----------------------------------------------------------------------------
Per Per Per Per
diluted diluted diluted diluted
share share share share
----------------------------------------------------------------------------
Net
income
(loss)
for
period ($1,522) ($0.03) $12,829 $0.28 ($2,464) ($0.05) $28,718 $0.63
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Non-GAAP Funds from Operations and Funds from Operations per Share

----------------------------------------------------------------------------
Three Months to Three Months to Nine Months to Nine Months to
Sept. 30, 2009 Sept. 30, 2008 Sept. 30, 2009 Sept. 30, 2008
----------------------------------------------------------------------------
Per Per Per Per
diluted diluted diluted diluted
share share share share
----------------------------------------------------------------------------

Funds from
operations $8,618 $0.18 $24,290 $0.53 $30,798 $0.65 $67,058 $1.46
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Non-GAAP funds from operations is not a measure recognized by GAAP in Canada, although it is widely used by analysts and other financial statement users. It is also used by the Company's bankers to measure cash flow to debt ratios, which determines interest costs under the Company's banking agreement. The most directly comparable measure under GAAP is cash flows from operating activities, as set out below.



Cash Flows from Operating Activities and Cash Flows from Operating
Activities per Share

----------------------------------------------------------------------------
Three Months to Three Months to Nine Months to Nine Months to
Sept. 30, 2009 Sept. 30, 2008 Sept. 30, 2009 Sept. 30, 2008
----------------------------------------------------------------------------
Per Per Per Per
diluted diluted diluted diluted
share share share share
----------------------------------------------------------------------------
Cash flows
from
operating
activities $8,483 $0.18 $24,131 $0.53 $32,208 $0.68 $65,901 $1.44
----------------------------------------------------------------------------
----------------------------------------------------------------------------


INVESTMENT AND FINANCING

Working Capital

Receivables comprise production revenue receivables and accruals, and receivables in respect of operating and capital costs. Prepaid and other costs include unamortized insurance premiums, deposits, prepayments and certain inventory equipment items.

Accounts payable and accrued liabilities include operating, administrative and capital costs payable. Net payables in respect of cash calls issued to partners regarding capital projects and estimates of amounts owing but not yet invoiced to the Company have been included in accounts payable.

Excluding an unrealized financial instrument provision, Storm had a working capital deficiency of $4.0 million at September 30, 2009, compared to $16.9 million at September 30, 2008 and $16.9 million at December 31, 2008. The working capital deficiency at each period end reflects the Company's preference to act as operator and the seasonality of its field operations. The Company's working capital deficiency is cyclical and is usually highest at the end of the first quarter of each year and lowest at the end of second quarter.

Capital Expenditures

Capital costs incurred were as follows:



----------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
to to to to
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Land and lease, net $ 441 $ 1,416 $ 2,260 $ 4,213
----------------------------------------------------------------------------
Seismic 16 (1,122) 1,158 (1,199)
----------------------------------------------------------------------------
Drilling and completions 8,538 23,640 24,911 51,483
----------------------------------------------------------------------------
Facilities and equipment 5,423 6,523 13,848 10,661
----------------------------------------
----------------------------------------------------------------------------
Field expenditures 14,418 30,457 42,177 65,158
----------------------------------------------------------------------------
Property acquisitions 12 - 9,148 507
----------------------------------------------------------------------------
Property dispositions - (3,400) (1,561) (6,053)
----------------------------------------
----------------------------------------------------------------------------
Total $ 14,430 $ 27,057 $ 49,764 $ 59,612
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Bank Debt, Liquidity and Capital Resources

Storm has a revolving borrowing base bank credit facility which is renewable annually but subject to mid-year review. The facility was renewed effective May 1, 2009 and amounts to $120 million, which amount was recently reconfirmed. The amount drawn on the facility at September 30, 2009 amounted to $94.9 million, or 79% of the available facility. Total debt, including working capital deficiency (less unrealized financial instrument losses), amounted to $98.9 million at September 30, 2009, resulting in a ratio of debt to annualized funds from operations for the first nine months of 2009 of 2.4 times.

Giving effect to the post-September 30, 2009 sale of certain minor properties, pro forma debt at quarter end would approximate $82 million, with a pro forma debt to year-to-date annualized funds ratio of approximately 2.0 times.

The Company normally funds its borrowing by drawing bankers' acceptances plus a stamping fee. The renewal of Storm's banking facility earlier in 2009 included a large increase in stamping fees, standby fees and other costs. Nevertheless, year over year, the core bankers' acceptance rate has fallen considerably, such that year-over-year total borrowing costs have fallen. In this circumstance, Storm has fixed its bankers' acceptance rate, before application of stamping fees, for $60 million through a swap mechanism at a cost of 69.5 basis points for a period of twelve months, beginning May 2009.

Storm funds its field capital programs through cash flow and bank borrowings. The decline in natural gas prices has severely reduced cash flows in 2009 resulting in constraints to the Company's capital programs. Further reductions may follow in the final quarter of 2009, in the absence of a material recovery in natural gas prices. Acquisitions are funded by a combination of debt and, if required, equity. Field capital programs tend to be concentrated in the winter months, with the result that, in the ordinary course, capital expenditures in the first and fourth quarters of the year will exceed cash flow, compensated by lower capital expenditures in the second and third quarters. In quarters of high field activity, Storm operates with a substantial working capital deficit, which is paid down in quarters of lower field activity.

In March 2009, Storm issued 1,850,000 common shares at a price of $10.60 per share for total proceeds of $19.6 million, before commission and expenses. Proceeds from the offering were initially used to reduce bank indebtedness.

Capital programs were funded as follows:



----------------------------------------------------------------------------
Three Three Nine Nine
Months Months Months Months
to to to to
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Non-GAAP funds from operations $ 8,618 $ 24,290 $ 30,798 $ 67,058
----------------------------------------------------------------------------
Non-cash working capital 2,482 8,220 (12,872) 6,740
----------------------------------------------------------------------------
Issue of common shares - net of
expenses 410 196 18,881 771
----------------------------------------------------------------------------
Increase (decrease) in bank
indebtedness 2,920 541 12,957 (7,517)
----------------------------------------------------------------------------
Proceeds on property sales - 3,400 1,561 6,053
----------------------------------------------------------------------------
Cash available for investment $ 14,430 $ 36,647 $ 51,325 $ 73,105
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Field expenditures $ 14,418 $ 30,457 $ 51,325 $ 65,665
----------------------------------------------------------------------------
Property acquisitions 12 - - -
----------------------------------------------------------------------------
Investments in SGR & SVI - 6,190 - 7,440
----------------------------------------------------------------------------
Total cost of investment programs $ 14,430 $ 36,647 $ 51,325 $ 73,105
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Investments

Storm Gas Resource Corp.

Storm Gas Resource Corp. ("SGR") was incorporated to identify and participate in unconventional natural gas opportunities, initially a shale gas resource in the Horn River Basin of northeastern British Columbia. Storm's initial investment in SGR at $1.00 per share in June, 2007, was satisfied by a cash contribution of $833,000 and the transfer of undeveloped lands with a value of $417,000. In July 2008, Storm subscribed for an additional 200,000 common shares in SGR at a price of $5.20 per share, and also participated in a private placement, subscribing for 600,000 common shares at a price of $6.50 per share. The private placement resulted in SGR issuing 5,880,000 common shares at a price of $6.50 per share, for total proceeds after commission and expenses of $38,220,000. As the private placement involved the sale of shares by SGR at a price higher than Storm's initial investment cost, the Company recognized a dilution gain in 2008 of $3.5 million. Storm's ownership position in SGR is 22%. Including the dilution gain, the carrying amount of Storm's 2,050,000 common shares of SGR is $4.41 per share. This amount should not be regarded as representative of the value of Storm's investment in SGR. Total cash invested, plus property transferred to SGR, amounts to $6.19 million or $3.02 per SGR share. In addition to its investment in SGR, Storm has a direct 40% working interest in undeveloped lands jointly acquired with SGR in the Horn River Basin of northeastern British Columbia. This interest, together with Storm's investment in SGR, provides the Company with 53% exposure to the potential upside in the Horn River Basin lands.

Storm provides management services to SGR at cost. Amounts charged by Storm to SGR for the three months and nine months ended September 30, 2009 were $65,000 and $195,000, respectively. No intercompany charges were incurred in 2008.

Subsequent to September 30, 2009, SGR completed a further equity issue, raising $12.4 million after commissions and expenses. Under the offering, Storm acquired an additional 450,000 shares for a cost of $2.9 million, or $6.50 per share, and maintained its 22% ownership position.

Storm Ventures International Inc.

At September 30, 2009, the Company's investment in Storm Ventures International Inc. ("SVI") represented a 6% ownership position, comprising 4,500,000 common shares. The carrying amount of SVI on Storm's consolidated balance sheet approximates $2.34 per SVI share, and comprises Storm's investment cost, plus a dilution gain recognized during a prior year. This carrying amount should not be regarded as representative of the value of Storm's investment. During 2008, Storm invested $1.25 million to acquire an additional 200,000 common shares, resulting in total cash invested in SVI since inception of Storm being $4.25 million.

Future Income Taxes

Estimated future income taxes at September 30, 2009 largely represents the excess of the accounting amounts over the related tax bases of property and equipment and share capital.



Details of the Company's tax pools are as follows:
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Maximum
As at Annual
Tax Pool September 30, 2009 deduction
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Canadian oil and gas property expense $ 97,125 10%
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Canadian development expense 64,988 30%
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Canadian exploration expense 4,027 100%
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Undepreciated capital cost 53,755 20 - 100%
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Other 2,231 7 - 20%
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Total $ 222,126
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Capital losses $ 9,666
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Asset Retirement Obligation

Storm's asset retirement obligation represents the present value of estimated future costs to be incurred to abandon and reclaim the Company's wells and facilities. Changes in amount of the obligation between December 31, 2008 and September 30, 2009 comprise the present value of additional obligations accruing to the Company as a result of field activity and acquisitions during the period, less costs paid in settlement of abandonment obligations, plus the quarterly increase in the present value of the obligation. The discount rate used to establish the present value is 8%. Future costs to abandon and reclaim Storm's properties are based on an internal evaluation of each of the Company's properties, supported by external data from industry sources.

Share Capital

Details of outstanding share capital and dilutive elements:



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As at and for the As at and for the As at and for the
three months ended nine months ended year ended
September 30, 2009 September 30, 2009 December 31, 2008
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Common shares
outstanding
- end of period 46,669 46,669 44,703
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Stock options 3,105 3,105 2,267
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Fully diluted
common shares
- end of period 49,774 49,774 46,970
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Weighted average
common shares
- basic 46,600 46,128 44,654
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Weighted average
common shares
- diluted 47,812 47,230 45,877
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Stock options outstanding are exercisable over five years on various dates beginning September 2005 at prices ranging from $2.60 to $12.17.

CONTRACTUAL OBLIGATIONS

In the course of its business Storm enters into various contractual obligations, including the following:

- purchase of services;

- royalty agreements;

- operating agreements;

- processing agreements;

- right of way agreements; and

- lease obligations for accommodation, office equipment and automotive equipment.

All such contractual obligations reflect market conditions at the time of contract and do not involve related parties except that SGR subleases office space from the Company at the same rate as the Company's head lease.



Obligations with a fixed term are as follows:

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Obligation 2009 2010 2011 2012 2013
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Lease of premises $406 $825 $838 $838 $ 419
Equipment leases 48 159 104 13 -
Gas transportation and
processing commitments 559 1,437 1,146 599 198
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Total $ 1,013 $ 2,421 $ 2,088 $ 1,450 $ 617
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QUARTERLY RESULTS

Summarized information by quarter for the two years ended September 30, 2009
appears below:

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Sept. 30, Jun. 30, Mar. 31, Dec. 31,
Quarter Ended 2009 2009 2009 2008

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Production revenue ($000s) 19,436 18,712 25,819 35,447

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Funds from operations ($000s) 8,618 8,460 13,720 20,432
Per share
- basic ($) 0.18 0.18 0.30 0.46
- diluted ($) 0.18 0.18 0.30 0.45

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Net income (loss)($000s) (1,522) (2,192) 1,250 5,968
Per share
- basic ($) (0.03) (0.05) 0.03 0.13
- diluted ($) (0.03) (0.05) 0.03 0.13

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Average daily production - Boe 8,030 8,153 8,441 8,161

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Average field netback ($/Boe) 14.49 14.22 20.15 30.35

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Capital expenditures net ($000s) 14,430 3,843 31,491 35,342

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Sept. 30, Jun. 30, Mar. 31, Dec. 31,
Quarter Ended 2008 2008 2008 2007

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Production revenue ($000s) 40,215 38,888 33,974 25,553

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Funds from operations ($000s) 24,290 23,250 19,518 13,233
Per share
- basic ($) 0.54 0.52 0.44 0.30
- diluted ($) 0.53 0.50 0.43 0.30

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Net income (loss)($000s) 12,829 9,465 6,426 2,852
Per share
- basic ($) 0.28 0.21 0.14 0.06
- diluted ($) 0.28 0.20 0.14 0.06

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Average daily production - Boe 7,107 6,130 6,500 5,992

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Average field netback ($/Boe) 39.77 45.09 35.87 27.44

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Capital expenditures net ($000s) 27,057 5,780 26,775 17,094

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CRITICAL ACCOUNTING ESTIMATES

Financial amounts included in the Company's management's discussion and analysis and in the unaudited consolidated financial statements for the three and nine months ended September 30, 2009 are based on accounting policies, estimates and judgment which reflect information available to management at the time of preparation. Information with respect to the accounting policies selected by the Company and the use of estimates is set out in the Company's audited consolidated financial statements for the year ended December 31, 2008 and the unaudited consolidated financial statements for the three months and nine months ended September 30, 2009.

RISK ASSESSMENT

There are a number of risks facing participants in the Canadian oil and gas industry. Some of the risks are common to all businesses while others are specific to the sector and others are specific to Storm. Information with respect to such risks is set out in the Company's annual report for the year ended December 31, 2008.

REPORTING CONTROLS

The Company's Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO") are responsible for establishing and maintaining disclosure controls and procedures ("DC&P") and internal controls over financial reporting ("ICFR"). Storm has codified and distributed to staff its policies, controls and procedures with respect to disclosure to third parties of information concerning the Company's operations and results. In addition, DC&P are designed to provide reasonable assurance that material information is made known to the CEO and CFO on a timely basis and that information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation. The CEO and CFO have concluded such controls are effective.

ICFR have been designed by the CEO and CFO, either directly or under their supervision, to provide reasonable assurance regarding the reliability of financial reporting, including financial reporting for external purposes under GAAP. As at December 31, 2008, the CEO and CFO evaluated the design and operating effectiveness of the Company's ICFR. In part, this evaluation was based on the work of third party specialists who were engaged by the Company to update documentation and test the operating effectiveness of such controls. Based on this evaluation, the CEO and CFO concluded that the design of ICFR was effective as at December 31, 2008 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. Further, the Company is required to disclose herein any change in the design of the Company's internal controls over financial reporting that occurred during the three and nine months ended on September 30, 2009 that has materially affected, or is reasonably likely to materially affect, the Company's internal controls over financial reporting. No material changes in the Company's design of internal controls over financial reporting were made or were identified during such period that have materially affected, or are reasonably likely to materially affect, the Company's internal controls over financial reporting. No circumstances suggesting a possible breach of disclosure controls were identified during the three and nine months ended September 30, 2009.

Because of inherent limitations, disclosure controls and procedures and internal controls over financial reporting cannot prevent or identify all mismeasurements, errors and fraud.

INTERNATIONAL FINANCIAL REPORTING STANDARDS

The Canadian Institute of Chartered Accountants, the primary source for accounting standards in Canada, proposes to implement International Financial Reporting Standards ("IFRS") as part of Canadian GAAP. Such standards have been established cooperatively by many countries and have widespread application to financial reporting by businesses throughout the world. The adoption of IFRS in Canada will result in major changes to GAAP in Canada and to financial reporting practices followed by Storm. The effective date of introduction for IFRS is proposed for company year ends beginning after December 31, 2010; thus, in the case of Storm, the year ended December 31, 2011. However, the need to have comparative information presented in accordance with IFRS for the year ended December 31, 2010, requires that the Company's consolidated balance sheet at January 1, 2010 be IFRS compliant, meaning that the Company must plan its conversion considerably in advance of the proposed implementation date. Currently, the application of IFRS to the oil and gas industry in Canada requires considerable clarification: correspondingly, the effect of IFRS on the Company's accounting policies and reporting standards and practices is not presently determinable.

With respect to organizing for the changeover, the Company has recruited appropriately qualified staff and has identified external resources to assist in the process. Key elements of the changeover plan include: staff education; choosing among policies permitted under IFRS; deciding whether certain changes will be applied on a retroactive or prospective basis; evaluating the effect of adoption on Storm's information technology and data systems and internal control over financial reporting and disclosure controls and procedures; alignment of internal and outsourced processes, applications and internal controls; external and internal communications; and liason with peers, industry groups and professional advisors.

ADDITIONAL INFORMATION

Additional information relating to the Company, including the Company's Annual Information Form, can be viewed at www.sedar.com or on the Company's website at www.stormexploration.com. Information can also be obtained by contacting the Company at Storm Exploration Inc., 800, 205 - 5th Avenue SW, Calgary, Alberta, T2P 2V7.



Consolidated Balance Sheets

($000s)(unaudited) September 30, December 31,
2009 2008
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ASSETS

Current
Accounts receivable $ 7,499 $ 14,274
Prepaids and other 7,366 2,916
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14,865 17,190

Property and equipment - net (Note 3) 308,788 290,944

Investments (Note 4) 19,567 20,242
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$ 343,220 $ 328,376
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LIABILITIES AND SHAREHOLDERS' EQUITY

Current
Accounts payable and accrued liabilities $ 18,879 $ 34,076
Unrealized financial instrument provision
(Note 11) 4,083 -
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22,962 34,076

Bank indebtedness (Note 5) 94,861 81,904
Asset retirement obligation (Note 6) 8,036 7,259
Future income taxes (Note 7) 20,028 22,875
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145,887 146,114
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Shareholders' equity (Note 8)
Share capital 107,352 88,013
Contributed surplus 5,228 3,980
Retained earnings 87,805 90,269
Accumulated other comprehensive income
(deficit) (3,052) -
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197,333 182,262
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Commitments (Note 13)

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$ 343,220 $ 328,376
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Consolidated Statements of Income (Loss) and Retained Earnings

Three Months Three Months Nine Months Nine Months
to to to to
September 30, September 30, September 30, September 30,
($000s)(unaudited) 2009 2008 2009 2008
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Revenue
Revenue from product
sales $ 18,492 $ 41,601 $ 64,481 $ 115,264
Realized loss on
financial instruments
(Note 11) (318) (1,386) (684) (2,187)
Unrealized gain on
financial instruments
(Note 11) 1,262 - 170 -
Royalties (2,534) (8,733) (11,147) (24,139)
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16,902 31,482 52,820 88,938
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Expenses
Production 3,915 4,253 12,536 12,679
Transportation 1,022 1,221 3,549 3,887
Interest 1,036 825 2,438 2,830
General and
administrative 1,049 533 3,329 2,124
Stock-based
compensation 587 615 1,388 1,346
Provision for
accounts receivable - 360 - 360
Depletion,
depreciation and
accretion 10,702 10,725 32,697 30,496
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18,311 18,532 55,937 53,722
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Income (loss) before
the following: (1,409) 12,950 (3,117) 35,216
Investment gain
(loss) (Note 4) (675) 3,527 (675) 3,527
Future income taxes
(Note 7) 562 (3,648) 1,328 (10,025)
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Net income (loss)
for the period (1,522) 12,829 (2,464) 28,718

Retained earnings,
beginning of period 89,327 71,472 90,269 55,583

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Retained earnings,
end of period $ 87,805 $ 84,301 $ 87,805 $ 84,301
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Net income (loss)
per share (Note 9)
- basic $ (0.03) $ 0.28 $ (0.05) $ 0.64
- diluted $ (0.03) $ 0.28 $ (0.05) $ 0.63


Consolidated Statements of Comprehensive Income (Loss)

Three Months Three Months Nine Months Nine Months
to to to to
September 30, September 30, September 30, September 30,
($000s)(unaudited) 2009 2008 2009 2008
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Net income (loss)
for the period $ (1,522) $ 12,829 $ (2,464) $ 28,718

Unrealized hedging
gain (loss) (4,253) 5,267 (4,253) -

Related income tax
benefit 1,201 (1,580) 1,201 -
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Other comprehensive
income (loss) (Note
11) (3,052) 3,687 (3,052) -
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Comprehensive income
(loss) for the
period $ (4,574) $ 16,516 $ (5,516) $ 28,718
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Consolidated Statements of Cash Flows

Three Months Three Months Nine Months Nine Months
to to to to
September 30, September 30, September 30, September 30,
($000s)(unaudited) 2009 2008 2009 2008
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Operating activities

Net income (loss)
for the period $ (1,522) $ 12,829 $ (2,464) $ 28,718

Investment loss
(gain) (Note 4) 675 (3,527) 675 (3,527)

Add non-cash items:
Depletion,
depreciation and
accretion 10,702 10,725 32,697 30,496
Unrealized gain on
financial
instruments
(Note 11) (1,262) - (170) -
Future income tax (562) 3,648 (1,328) 10,025
Stock based
compensation 587 615 1,388 1,346
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Funds from
operations 8,618 24,290 30,798 67,058
Net change in
non-cash working
capital items
(Note 10) (135) (159) 1,410 (1,157)
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8,483 24,131 32,208 65,901
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Financing activities
Issue of common
shares - net of
expenses 410 196 18,881 771
Increase (decrease)
in bank indebtedness 2,920 541 12,957 (7,517)
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3,330 737 31,838 (6,746)
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Investing activities
Increase in
investments - (6,190) - (7,440)
Additions to
property and
equipment (14,430) (30,457) (51,325) (65,665)
Disposals of
property and
equipment - 3,400 1,561 6,053
Net change in
non-cash working
capital items
(Note 10) 2,617 8,379 (14,282) 7,897
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(11,813) (24,868) (64,046) (59,155)
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Change in cash
during the period - - - -

Cash, beginning of
period - - - -
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Cash, end of period $ - $ - $ - $ -
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Three and nine months ended September 30, 2009 and 2008

Tabular amounts in thousands, except per share amounts

(unaudited)

1. NATURE OF OPERATIONS

Storm Exploration Inc. (the "Company" or "Storm"), is an oil and gas exploration and development company listed on the Toronto Stock Exchange under the symbol SEO. The Company operates in the provinces of Alberta and British Columbia. The Company's production base is largely natural gas and natural gas liquids. These consolidated financial statements include the accounts of Storm and its wholly owned subsidiary and partnership.

2. SIGNIFICANT ACCOUNTING POLICIES

These interim unaudited consolidated financial statements have been prepared by management in accordance with accounting principles generally accepted in Canada ("GAAP"), following the same accounting policies and methods of computation as used in the audited consolidated financial statements for the year ended December 31, 2008. The interim unaudited consolidated financial statement note disclosures do not include all disclosures applicable for annual audited financial statements. Accordingly, the interim unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and the notes thereto contained in the Company's annual report for the year ended December 31, 2008.

Future Accounting Changes

Convergence with International Financial Reporting Standards

Canada's Accounting Standards Board has confirmed January 1, 2011 as the effective date for the convergence of Canadian GAAP to International Financial Reporting Standards ("IFRS"). The Company will be required to begin reporting under IFRS in the first quarter of 2011 with comparative data for the prior year. IFRS uses a conceptual framework similar to Canadian GAAP; however, there will be significant differences in recognition, measurement and disclosures that will be addressed.

The Company has established a project group to review the adoption of IFRS and its effect on financial reporting software, bank covenants, business contracts and internal controls over financial reporting and to provide regular updates to the Audit Committee of the Board of Directors.



3. PROPERTY AND EQUIPMENT

September 30, December 31,
2009 2008
-------------------------------------
Property and equipment $ 460,572 $ 410,394
Accumulated depletion and depreciation (151,784) (119,450)
-------------------------------------
$ 308,788 $ 290,944
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-------------------------------------


At September 30, 2009, the depletion calculation excluded unproved properties of $24.0 million (December 31, 2008 - $23.3 million) and included future development costs of $110.7 million (December 31, 2008 - $140.3 million).



4. INVESTMENTS

September 30, December 31,
2009 2008
-------------------------------------
Investment in Storm Gas Resource Corp. $ 9,042 $ 9,717
Investment in Storm Ventures
International Inc. 10,525 10,525
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$ 19,567 $ 20,242
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-------------------------------------


The Company holds a 22% interest in a private company, Storm Gas Resource Corp. ("SGR") and accounts for its holding using the equity method. Subsequent to September 30, 2009, SGR issued common shares to raise $12.4 million after commissions and expenses of the offer. The Company took up sufficient shares to maintain its 22% interest at a cost of $2.9 million.

The Company also has a 6% interest in another private company, Storm Ventures International Inc., which is accounted for using the cost method as the ownership position does not meet the requirements for equity accounting.

5. BANK INDEBTEDNESS

The Company has an extendible revolving bank facility in the amount of $120 million (December 31, 2008 - $110 million), based on the Company's producing reserves. The revolving facility is available to the Company until April 30, 2010, but may be extended at the Company's request until April 29, 2011, subject to the bank's review of the Company's reserve lending base. If the revolving facility is not renewed at the end of the current revolving phase, the facility moves into a term phase whereby the loan is to be retired with one payment on the 366th day following the last day of the revolving phase, in an amount equal to the outstanding principal. Interest is paid on the revolving facility at banker's acceptance rates plus a stamping fee. Security comprises a floating charge demand debenture on the assets of the Company.

6. ASSET RETIREMENT OBLIGATION

The estimated future asset retirement obligation is based on the Company's net ownership interest in wells and facilities, the estimated costs to abandon and reclaim the wells and facilities and the estimated timing of the costs to be incurred in future periods. The total estimated undiscounted amount required to settle the Company's asset retirement obligations is approximately $14.3 million (December 31, 2008 - $13.0 million), which will be paid over the next 20 - 25 years, with the majority of costs paid between 2015 and 2031. A credit adjusted risk-free rate of eight percent was used to calculate the present value of the asset retirement obligations, amounting to $8.0 million (December 31, 2008 - $7.3 million).

The following table provides a reconciliation of the carrying amount of the obligation associated with the retirement of oil and gas properties:



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Nine Months Ended Year Ended
September 30, December 31,
2009 2008
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Asset retirement obligation, beginning
of period $ 7,259 $ 6,918
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Liabilities incurred 498 108
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Liabilities disposed (84) (255)
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Accretion expense 363 488
------------------------------------
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Asset retirement obligation, end of
period $ 8,036 $ 7,259
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7. FUTURE INCOME TAXES

The future income tax liability is based on the excess of the accounting amounts over the related tax bases of the Company's property and equipment, asset retirement obligation and share capital.
The Company has tax pools associated with property and equipment of approximately $222 million as well as capital losses of approximately $10 million, all of which are not subject to expiry.

The provision for future income taxes is different from the amount computed by applying the combined statutory Canadian federal and provincial tax rates to pre-tax income for the period.



The differences are as follows:

Three Three Nine Nine
Months to Months to Months to Months to
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2009 2008 2009 2008
----------------------------------------------------
Statutory combined
federal and
provincial income tax
rate 29% 30% 29% 30%

Expected income taxes $ (614) $ 5,060 $ (1,118) $ 11,764

Add (deduct) the income
tax effect of:
Stock-based compensation 173 189 409 409
Investment loss 199 (1,071) 199 (1,071)
Rate adjustments (369) (531) (860) (1,081)
Other 49 1 42 4
----------------------------------------------------
Future income taxes $ (562) $ 3,648 $ (1,328) $ 10,025
----------------------------------------------------
----------------------------------------------------

The components of the future income tax liability are as follows:

September 30, December 31,
2009 2008
------------------------------------
Property and equipment $ 23,974 $ 25,331
Asset retirement obligation (2,170) (2,033)
Share issue costs (575) (423)
Unrealized financial instrument
provision (1,201) -
------------------------------------
Future income tax liability $ 20,028 $ 22,875
------------------------------------
------------------------------------


8. SHARE CAPITAL

Authorized

An unlimited number of non-voting common shares

An unlimited number of voting common shares

An unlimited number of preferred shares

Included in the following common share balances are 1,275,000 non-voting common shares.

Except for voting rights, non-voting and voting common shares are identical.



Issued

Number of
Shares Consideration
----------------------------
Balance as at December 31, 2008 44,703 $ 88,013
Issuance of common shares (1) 1,850 19,610
Stock options exercised 116 590
Share issue costs (net of income tax benefit) (861)
----------------------------
Balance as at September 30, 2009 46,669 $ 107,352
----------------------------
----------------------------

(1) On March 6, 2009, 1,850,000 common shares were issued at a price of
$10.60 per share for total proceeds of $19,610,000, before commission
and expenses.


Stock-Based Compensation Plans

The Company has a stock option plan under which it may grant, at the Company's discretion, options to purchase common shares to directors, officers and employees. Under the stock option plan a total of 3,700,000 common shares have been reserved for issuance. Details of the options outstanding at September 30, 2009 are as follows:



Number of options Weighted Average
Exercise Price
----------------------------------------------------------------------------
Outstanding at December 31, 2008 2,267 $ 6.03
Issued during period 962 12.10
Exercised during period (116) 3.84
Forfeited during period (8) 12.03
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Outstanding at September 30, 2009 3,105 $ 7.98
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Outstanding Options Exercisable Options
-----------------------------------------------------------
-----------------------------------------------------------
Weighted Weighted Weighted
Number of Average Average Number of Average
Range of Options Remaining Exercise Options Exercise
Exercise Price Outstanding Life (years) Price Outstanding Price
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----------------------------------------------------------------------------

$ 2.60 to $3.61 186 0.6 $ 3.61 186 $ 3.61
$ 3.91 to $5.67 1,273 1.5 $ 5.46 988 $ 5.42
$ 6.03 to $8.57 683 3.0 $ 8.05 207 $ 7.78
$ 9.62 to $12.17 963 4.8 $ 12.09 2 $ 11.40
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3,105 2.8 $ 7.98 1,383 $ 5.54
-----------------------------------------------------------
-----------------------------------------------------------


Using the Black-Scholes pricing model, the weighted average fair value of the options granted to date in 2009 was estimated to be $3.78 (2008 - $8.68), using risk-free interest rates of 2.5%, volatility of 40% and an expected average vesting period of 30 months. The amortized cost of the options is charged as stock-based compensation in the consolidated statement of income (loss) with an equivalent offset to contributed surplus.



9. PER SHARE AMOUNTS

Three Three Nine Nine
Months to Months to Months to Months to
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2009 2008 2009 2008
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Basic
Net income per share $ (0.03) $ 0.28 $ (0.05) $ 0.64
Weighted average
number of shares
outstanding (000s) 46,600 44,692 46,128 44,638

Diluted
Net income per share $ (0.03) $ 0.28 $ (0.05) $ 0.63
Weighted average
number of shares
outstanding (000s) 47,812 46,001 47,230 45,873
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The reconciling items between basic and diluted weighted average common
shares are stock options described in Note 8.

10. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in non-cash working capital

Three Three Nine Nine
Months to Months to Months to Months to
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2009 2008 2009 2008
-----------------------------------------------------
Accounts receivable $ (357) $ (4,009) $ 6,775 $ (3,343)
Prepaids and other (2,623) (213) (4,450) (1,249)
Accounts payable and
accrued liabilities 5,462 12,442 (15,197) 11,332
-----------------------------------------------------
Change in non-cash
working capital $ 2,482 $ 8,220 $ (12,872) $ 6,740
-----------------------------------------------------
-----------------------------------------------------

Relating to:

Financing activities $ - $ - $ - $ -
Investing activities 2,617 8,379 (14,282) 7,897
Operating activities (135) (159) 1,410 (1,157)
-----------------------------------------------------
$ 2,482 $ 8,220 $ (12,872) $ 6,740
-----------------------------------------------------
-----------------------------------------------------
Interest paid during
the period $ 1,036 $ 825 $ 2,438 $ 2,830
-----------------------------------------------------
-----------------------------------------------------
Income taxes paid
during the period $ - $ - $ - $ -
-----------------------------------------------------
-----------------------------------------------------


11. FINANCIAL INSTRUMENTS

The Company holds various financial instruments. These financial instruments expose the Company to the following risks:

- credit risk

- market risk

- liquidity risk

Management has primary responsibility for monitoring and managing financial instrument risks under direction from the Board of Directors, which has overall responsibility for establishing the Company's risk management framework. In certain circumstances, for example, hedging of future production revenue, the Board has established policies and risk limits and controls, and monitors these risks in relation to market conditions. In other circumstances, for example, extending credit to purchasers of the Company's products, the Board has delegated responsibility for credit assessment to management, but receives frequent financial and operating reports.

The Company's financial instruments recognized on the consolidated balance sheet consist of accounts receivable, bank indebtedness, accounts payable and accrued liabilities and unrealized financial instrument provision. The fair value of these financial instruments approximates their carrying amounts.

Credit risk

A substantial portion of the Company's accounts receivable is concentrated with a limited number of purchasers of commodities and joint venture partners in the oil and gas industry and are subject to normal industry credit risk. Management considers this concentration of credit risk to be limited, as commodity purchasers are major industry participants, and receivables from partners are protected by effective industry standard legal remedies. In addition, the Company's high working interest in its major operating properties mitigates the risk of partner default. The Company requires cash calls from its partners on major field projects in advance of commencement. Receivables related to the sale of the Company's production are normally collected on the 25th day of the month following delivery. Nevertheless, the widespread disruption of credit markets over the last twelve months, together with falling commodity prices, exposes the Company to greater credit risks, necessitating greater vigilance regarding provision of credit to customers and to joint venture partners.

Market risk

Market risks are as follows and are largely outside of the control of the Company:

- Commodity prices

- Interest rates

- Foreign exchange

Commodity prices

The Company is constantly exposed to the risk of declining prices for its products with a corresponding reduction in cash flow. Reduced cash flow may result in lower levels of capital being available for field activity, thus compromising the Company's capacity to grow production while at the same time replacing continuous declines from existing properties. In certain circumstances, usually when debt levels are forecast to increase due to capital expenditures exceeding cash flow, or where the Company has financed, in whole or in part, an acquisition using bank debt, the Company may enter into oil and natural gas hedging contracts in order to provide stability of future cash flow. These contracts reduce the fluctuation in production revenue by fixing prices of future deliveries of oil and natural gas. Such arrangements are made in accordance with the Company's risk management policy and the Company does not use these instruments for trading or speculative purposes. The Company formally documents all relationships between derivative instruments and hedged items, as well as the risk management objectives and strategy for undertaking hedge transactions. Certain derivative instruments used by the Company qualify for hedge accounting treatment. Realized gains and losses on these contracts are recognized as revenue in the same period in which the revenues associated with the hedged transactions are recognized. The Company also assesses, both at the contract's inception and on an ongoing basis, whether the instruments that are used are highly effective in offsetting the changes in fair values or cash flows of hedged items. However, certain derivative instruments, relating to crude oil, in place during the first nine months of 2009 did not satisfy hedge accounting criteria. As a result, these financial instruments have been valued on a mark-to-market basis and the resulting gain or loss recognized in income.

For the three and nine months ended September 30, 2009, the Company realized losses on financial instruments of $0.3 million (2008 - $1.4 million) and $0.7 million (2008 - $2.2 million), respectively.

As at September 30, 2009, Storm has the following derivative contracts in place, which do not meet the hedge accounting criteria. The unrealized mark-to-market gain on these contracts of $1.3 million and $0.2 million for the three and nine months ended September 30, 2009, respectively, is recognized in the financial statements as an increase in revenue and a reduction of the unrealized financial instrument provision on the balance sheet:



Volume Price Term
----------------------------------------------------------------------------

Costless Collars
350 Bbls/d $60.00 - $70.00/Bbl Oct.1, 2009 - Dec.31, 2009

Crude Oil Swap
450 Bbls/d $ 83.45/Bbl Jan.1, 2010 - Jun.30, 2010


As at September 30, 2009, Storm has the following derivative contracts in place, which meet the hedge accounting criteria. The unrealized mark-to-market loss on these contracts of $4.3 million for the nine months ended September 30, 2009 is recognized in the financial statements as a current liability and a reduction of other comprehensive income:



Volume Price Term
----------------------------------------------------------------------------

Natural Gas Swaps
28,000 GJ/day $ 4.29 - $5.21/GJ Nov.1, 2009 - Mar.31, 2010
21,000 GJ/day $ 4.73 - $4.90/GJ Apr.1, 2010 - Jun.30, 2010


Interest rates

Interest on the Company's revolving bank facility varies with changes in interest rates, and is most commonly based on bankers' acceptance rates plus a stamping fee. The Company is thus exposed to increased borrowing costs during periods of increasing interest rates, with a corresponding reduction in both cash flows and project economics. As at September 30, 2009, Storm has fixed the interest rate on $60 million of bankers acceptances at a rate of 0.695%, plus stamping fees, for the period May 8, 2009 to May 10, 2010. Mark-to-market measurement of this derivative instrument does not have a material effect on the value of the Company's debt at September 30, 2009.

Foreign exchange

Although the Company's product revenues are denominated in Canadian dollars, the underlying market prices are affected by the exchange rate between the Canadian and the United States dollar. As at September 30, 2009, the Company had no contracts in place to reduce foreign exchange risk.

Sensitivities

Using the Company's actual production volumes, royalty rates, income tax rates and debt levels for the first nine months of 2009 and 2008, the estimated after-tax effects that changes in certain factors would have on net income and net income per share is as follows:



2009 2008
Change Change
in Net in Net
Change in Income Per Change in Income Per
Factor Net Income Share Net Income Share
----------------------------------------------------------------------------
US$ 1.00/bbl change in
the price of WTI $ 219,000 $ 0.00 $ 150,000 $ 0.00

$0.10/Mcf change in the
price of natural gas $ 701,000 $ 0.01 $ 522,000 $ 0.01

1% change in the interest
rate $ 650,000 $ 0.01 $ 565,000 $ 0.01
----------------------------------------------------------------------------


Liquidity risk

Liquidity difficulties would emerge if the Company was unable to meet its financial obligations as they fell due within normal credit terms. This may be the consequence of diminished cash flows resulting from lower product prices, production interruptions, or operating or capital cost increases. Liquidity difficulties could also occur if the Company's bankers were unable to continue to provide credit at a level, cost and on terms compatible with the Company's capital requirements. Generally, the Company will, over a reasonable period of time, limit its capital programs to cash flow from operations. In addition, the Company endeavours to maintain its debt at a level somewhat less than the maximum amount of its total bank facility to ensure financial flexibility to deal with unforeseen or rapidly changing circumstances.

12. CAPITAL MANAGEMENT

Capital management is fundamental to the Company's objective of cost-effective production growth, while simultaneously replacing continuous production declines. The Company's capital comprises shareholders' equity, bank indebtedness and working capital. Capital management involves the preparation of an annual budget, which may only be implemented after approval by the Company's Board of Directors. As the Company's business evolves during the fiscal year, the budget may be amended; however, any changes are again subject to approval by the Board of Directors. As part of the budget process, and as part of capital management control procedures, the Company continuously uses a non-GAAP measurement of net debt to cash flow to measure and control debt levels during the fiscal year. Debt to cash flow is also used by the Company's bankers to set the stamping fee applicable to the Company's bank indebtedness.



The measurement is established as follows:

----------------------------------------------------------------------------
As at and for As at and for
the the
nine months twelve months
ended ended
September 30, December 31,
2009 2008
----------------------------------------------------------------------------
Current assets $ 14,865 $ 17,190
----------------------------------------------------------------------------
Accounts payable and accrued liabilities 18,879 34,076
--------------------------------
----------------------------------------------------------------------------
Working capital deficiency 4,014 16,886
----------------------------------------------------------------------------
Bank indebtedness 94,861 81,904
--------------------------------
----------------------------------------------------------------------------
Net debt 98,875 98,790
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year-to-date annualized funds from
operations $ 41,064 $ 87,490
----------------------------------------------------------------------------
Net debt to non-GAAP funds from operations 2.4 : 1 1.1 : 1
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The above measurement is subject to quarterly variations and is usually highest in the first and fourth quarter of each year, when capital expenditures normally exceed cash flow, with a resulting increase in net debt. The increase in this ratio at September 30, 2009 is a result of decreased cash flow in 2009 due to lower commodity prices.

The Company's credit availability is based on the Company's producing reserves. The non-GAAP measurement of net debt to cash flow is used to determine the interest rate applied to the Company's bank indebtedness, with interest rates changing at certain threshold levels of net debt to cash flow. The Company's bankers are entitled to complete a year-end and a mid-year evaluation of the Company's borrowing base, which, in circumstances of falling commodity prices, negative changes to the Company's operating activities, or credit limitations affecting the Company's banking syndicate, may result in a decrease in the line of credit available to the Company. The Company's bankers have recently completed a mid-year evaluation of the Company's borrowing base and have confirmed that the bank facility will remain unchanged at $120 million.

From time to time, the Company may enter into hedging arrangements if capital programs or acquisition costs result in a high net debt to cash flow ratio. Such arrangements provide for stability of cash flow during periods when the Company applies cash flow to reduce its net debt.

Increased debt levels arising from acquisitions, or capital programs exceeding cash flow, may be addressed by reduced capital expenditures, disposal of non-core assets or the issue of common shares.

13. COMMITMENTS

The Company has the following fixed-term commitments relating to its ongoing business:



----------------------------------------------------------------------------
2009 2010 2011 2012 2013
----------------------------------------------------------------------------
Lease of premises $ 406 $ 825 $ 838 $ 838 $ 419
----------------------------------------------------------------------------
Equipment leases 48 159 104 13 -
----------------------------------------------------------------------------
Gas transportation and
processing commitments 559 1,437 1,146 599 198
----------------------------------------------------------------------------
Total $ 1,013 $ 2,421 $ 2,088 $ 1,450 $ 617
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Contact Information

  • Storm Exploration Inc.
    Brian Lavergne
    President
    (403) 264-3520
    or
    Storm Exploration Inc.
    Donald McLean
    Chief Financial Officer
    (403) 264-3520
    www.stormexploration.com