Storm Resources Ltd. ("Storm" or the "Company") is Pleased to Announce Its Financial and Operating Results For the Three Months and Year Ended December 31, 2011

CALGARY, ALBERTA--(Marketwire - March 1, 2012) - Storm Resources Ltd. (TSX VENTURE:SRX)

Storm has also filed its audited financial statements as at December 31, 2011 and for the three months and year then ended along with the Management's Discussion and Analysis ("MD&A") for the same periods. This information appears on SEDAR at www.sedar.com and on Storm's website at www.stormresourcesltd.com.

Selected financial and operating information for the three months and year ended December 31, 2011, as well as reserve information at December 31, 2011, appears below and should be read in conjunction with the related financial statements and MD&A.

Highlights

Thousands of Cdn$, except volumetric and per share amounts		Three Months Ended December 31, 2011		Three Months Ended December 31, 2010		Year Ended December 31, 2011		Inception, June 8, 2010 to December 31, 2010(1)
FINANCIAL
	Gas sales	1,160		-		3,404		-
	NGL sales	594		-		1,020		-
	Oil sales	739		-		2,468		-
Production revenue		2,493		-		6,892		-
Funds from operations(2)		709		(708	)	1,874		(956	)
	Per share - basic ($)	0.03		(0.03	)	0.07		(0.04	)
	Per share - diluted ($)	0.03		(0.03	)	0.07		(0.04	)
Net income (loss)		(1,758	)	(1,087	)	(3,664	)	(1,493	)
	Per share - basic ($)	(0.07	)	(0.04	)	(0.14	)	(0.09	)
	Per share - diluted ($)	(0.07	)	(0.04	)	(0.14	)	(0.09	)
Capital expenditures, net of dispositions		20,687		13,373		40,796		16,797
(Debt) working capital		(15,171	)	20,593		(15,171	)	20,593
Weighted average common shares outstanding (000s)
	Basic	26,377		26,377		26,377		16,267
	Diluted	26,377		26,377		26,377		16,267
Common shares outstanding (000s)
	Basic	26,377		26,377		26,377		26,377
	Fully diluted	28,355		28,351		28,355		28,351
OPERATIONS(3)
Oil equivalent (6:1)
	Barrels of oil equivalent (000s)	72		-		198		-
	Barrels of oil equivalent per day	779		-		542		-
	Average selling price (Cdn$ per Boe)	34.78		-		34.86		-
Gas production
	Thousand cubic feet (000s)	346		-		964		-
	Thousand cubic feet per day	3,763		-		2,641		-
	Average selling price (Cdn$ per Mcf)	3.35		-		3.53		-
NGL Production
	Barrels (000s)	7		-		12		-
	Barrels per day	72		-		32		-
	Average selling price (Cdn$ per barrel)	89.95		-		87.36		-
Oil Production
	Barrels (000s)	7		-		25		-
	Barrels per day	80		-		69		-
	Average selling price (Cdn$ per barrel)	100.05		-		97.39		-
Wells drilled
	Gross	1.0		-		4.0		-
	Net	0.6		-		2.2		-

(1) Storm Resources Ltd. was incorporated on June 8, 2010 and was inactive until August 17, 2010 when they participated in a plan of arrangement along with Storm Exploration Inc., ARC Energy Trust and ARC Resources Ltd.

(2) Funds from operations and funds from operations per share are non-GAAP measurements. See discussion of Non-GAAP Measurements on page 18 of the MD&A and the reconciliation of funds from operations to the most directly comparable measurement under GAAP, "Cash Flows from Operating Activities", on page 26 of the MD&A.

(3) Storm had no production in 2010.

President's Message

2011 FOURTH QUARTER AND YEAR-END HIGHLIGHTS

• Production averaged 542 Boe per day in 2011 with significant growth in the second half of the year as evidenced by fourth quarter production averaging 779 Boe per day and production in December averaging 861 Boe per day. There are no prior year comparisons given that Storm commenced operations August 17, 2010 and had no production until January 2011. Growth in the second half of 2011 primarily resulted from the tie-in of two new horizontal wells in the Montney formation at Umbach, which added 300 net Boe per day in the fourth quarter, and the acquisition of a light oil property at Mica in north east British Columbia which closed on December 1, 2011 and added 145 net Boe per day in December.

• On December 1, 2011, Storm closed the acquisition of a light oil property at Mica in north east British Columbia which added 145 Boe per day of high netback production (current netback approximately $50.00 per Boe) and 722 Mboe of proved plus probable reserves. The purchase price, net of adjustments, was $15.4 million and was financed with existing cash resources plus an expanded credit facility.

• Storm entered into an arrangement agreement in the fourth quarter to acquire all of the outstanding common shares of Storm Gas Resource Corp. ("SGR"), its partner in the Horn River Basin of north east British Columbia ("HRB"). The arrangement closed on January 12, 2012 and added 360 Boe per day of production (100% natural gas) plus 81,400 net acres of undeveloped land including 58,400 net acres in the HRB. Based on an evaluation completed by InSite Petroleum Consultants Ltd. ("InSite") effective January 31, 2012, Storm acquired 2.6 Mmboe of proved reserves and 6.8 Mmboe of proved plus probable reserves. Excluding the 2.5 million SGR shares already owned by Storm, the final cost to acquire SGR was $43.5 million which resulted in the issuance of 11.8 million Storm shares to SGR shareholders.

• On January 20, 2012, Storm announced that it had entered into an arrangement agreement with Bellamont Exploration Ltd. ("Bellamont") which will result in both companies being combined. This transaction will increase Storm's production by 2,250 Boe per day (48% liquids) at closing and adds light oil drilling inventory in the Grimshaw and Grande Prairie areas of north west Alberta. Under the terms of the arrangement agreement, Bellamont shareholders will receive, at their election, for each common share of Bellamont held: $0.56 cash; or 0.1445 of a Storm common share; or a combination of cash and Storm shares. The cash amount payable to Bellamont shareholders is subject to a maximum total amount of $20.0 million. Including estimated net debt of $40.0 million at December 31, 2011, the total value of the transaction is $110.2 million, using Storm's closing share price of $3.00 per share on February 29, 2012.

• Storm's reserves grew significantly in 2011 with InSite estimating that proved reserves increased by 403% to total 3.7 Mmboe and proved plus probable reserves increased by 231% to total 8.3 Mmboe. The all-in cost to add reserves was $20.87 per Boe for proved reserves and $15.39 per Boe for proved plus probable reserves (includes all capital expenditures, the change in future development costs, acquisitions, dispositions and revisions).

• InSite completed a resource evaluation effective December 31, 2011 which confirms the significant resource and future drilling opportunity on Storm's lands in the Umbach area and in the HRB. The best estimate of contingent resources totals 51.2 Mmboe net sales for Umbach plus the HRB (116.8 Mmboe net sales including SGR). At Umbach, the best estimate of contingent resources was 14.1 Mmboe net sales to Storm (19% condensate plus natural gas liquids). In the HRB, the best estimate of contingent resources was 223 Bcf net sales to Storm and 393 Bcf net sales to SGR.

• Fourth quarter activity included drilling a fourth horizontal well at Umbach which was drilled and cased 2.5 miles south of the first horizontal well. Logs from the vertical pilot hole indicate 30 metres of net pay in the Montney formation which significantly expands the size of the exploitable area. In addition, two other horizontal wells (1.2 net) at Umbach were tied in and commenced production from the Montney formation.

• The operating netback averaged $20.71 per Boe in the fourth quarter and was $22.81 per Boe for the full year.

• Capital investment in the fourth quarter was $20.7 million with major expenditures being $15.4 million to acquire the Mica property and $4.7 million for drilling and completions. Capital investment in 2011 totaled $40.8 million.
• During 2011, Storm drilled four wells (2.2 net) with a 100% success rate including one horizontal well (0.4 net) in the Muskwa/Otter Park formation of the HRB and three horizontal wells (1.8 net) into the Montney formation at Umbach.

• At December 31, 2011, Storm's debt and working capital deficiency was $15.2 million. After taking into account the value of Storm's investment in publicly listed companies ($8.8 million at year end), net debt was $6.3 million.

TRANSACTION WITH BELLAMONT EXPLORATION LTD.

On January 20, 2012, Storm announced that it had entered into an arrangement agreement with Bellamont which will result in both companies being combined. Under the terms of the arrangement agreement, Bellamont shareholders will receive, at their election, for each common share of Bellamont held: $0.56 cash; or 0.1445 of a Storm common share; or a combination of cash and Storm shares. The cash amount payable to Bellamont shareholders is subject to a maximum total amount of $20.0 million which, if elected, will result in 16.7 million Storm shares being issued. Bellamont's asset base is primarily operated, high working interest assets focused within the Grande Prairie area of north west Alberta which have a higher overall netback given that liquids are 48% of total production.

The transaction with Bellamont will be funded in part through a $23.6 million private placement of common shares of Storm at a price of $3.40 per Storm share (6,946,000 shares to be issued). Management, directors and employees are investing $8.4 million to subscribe for 2,468,000 shares. Closing of the private placement occurred on February 22, 2012 and the funds are being held in escrow pending completion of the transaction with Bellamont (a condition of the private placement) which is expected to close on March 23, 2012.

Additional information regarding the arrangement with Bellamont:

• Bellamont's net debt at December 31, 2011 is estimated to be $40.0 million (includes transaction costs plus employee severance);

• Including net debt of $40.0 million, the total value of the transaction is $110.2 million, using Storm's closing share price of $3.00 per share on February 29, 2012;

• Storm's cost to acquire Bellamont's shares is $65.9 million after deducting net debt and proceeds ($4.25 million) from the recent sale by Bellamont of undeveloped lands;

• Annualized cash flow from Bellamont's assets is estimated to be $23.0 million based on expected production at closing of 2,250 Boe per day (48% oil plus NGLs) with a $28.00 per Boe operating netback which assumes Cdn$100/Bbl Edmonton Par, Cdn$2.40/GJ AECO, operating costs of $13.50 per Boe, transportation cost of $1.50 per Boe and an average royalty rate of 17%;

• Undeveloped land value of $3.1 million which is internally estimated by Storm (previous estimate of $7.35 million was adjusted lower to reflect recent sale of undeveloped lands for $4.25 million);

• Annual production decline is relatively shallow at 20% to 25% (decline is less than 10% on older wells that came on production before January 2010, approximately half of Bellamont's current production);

• A new horizontal well at Grimshaw will begin producing in early March and is expected to add 50 to 100 barrels of oil per day;

• Current production is approximately 2,050 Boe per day with 300 net Boe per day currently shut in due to mechanical issues (pipeline failures at Saddle Hills and Grande Prairie, liquids rich Montney gas well at Grande Prairie awaiting installation of artificial lift); and,

• InSite is evaluating the reserves associated with Bellamont's asset base and results are expected to be released in late March 2012.

Combining Bellamont and Storm will result in a company with a more diversified, resource-oriented asset base. Near-term growth will primarily come from exploitation of Bellamont's Montney light oil pool at Grimshaw and from delineating Storm's liquids rich natural gas resource in the Montney formation at Umbach. Longer term, growth will come from improving natural gas prices and from further exploitation of Storm's large resource in the HRB. Bellamont shareholders retain exposure to upside associated with the Grimshaw Montney light oil pool and gain asset diversification into much larger resource opportunities at Umbach (liquids rich Montney gas) and in the HRB (Muskwa and Otter Park shale gas). Storm shareholders benefit from higher netbacks, increased cash flow and relatively shallow decline associated with Bellamont's asset base, which will result in increased production growth as well as acceleration of resource delineation at Umbach.

At Grimshaw, there remains significant upside associated with further exploiting and delineating Bellamont's large Montney light oil pool. Bellamont has a 100% working interest in 17 sections of land at Grimshaw. Storm management estimates that DPIIP in the Montney pool ranges from 19 million barrels of oil to more than 35 million barrels of oil. Estimated DPIIP is based on an areal extent of 2.0 to 4.5 sections, net pay of 7 metres, average porosity of 17% and average oil saturation of 44%. In the second half of 2012, Storm plans to drill five horizontal wells which will include up to two step-out horizontals with logged vertical pilot holes. Bellamont recently drilled a vertical well which encountered a new pool to the west. This vertical well is expected to begin producing in the first quarter of 2012 and, this summer, a horizontal well with a logged vertical pilot hole is expected to be drilled offsetting the discovery well. Storm will continue to advance Bellamont's plans to initiate a waterflood in the pool which could materially increase oil recovery and reserves at minimal cost. New horizontal wells benefit from a 5% royalty rate under Alberta's New Well Royalty Rate program.

ACQUISITION OF STORM GAS RESOURCE CORP.

On November 11, 2011, Storm entered into a definitive arrangement agreement to acquire all of the outstanding shares of SGR, its partner in the HRB. On January 12, 2012, the transaction was completed with Storm issuing 1.33 common shares for each SGR common share not owned by Storm (Storm owned 2.5 million shares of SGR) which resulted in the issuance of 11.8 million Storm shares. The total value of the transaction was $55.8 million using Storm's closing share price of $3.70 per share on January 12, 2012.

The acquisition of SGR added approximately 360 Boe per day of production (100% natural gas) and 81,400 net acres of undeveloped land which includes 58,400 net acres in the HRB. Storm's undeveloped land holdings in the HRB now total 88,600 net acres at a 100% working interest.

InSite estimated DPIIP, contingent resources, and reserves for the Muskwa and Otter Park formations in SGR's HRB lands as of January 31, 2012. DPIIP was determined over 30 gross sections where both reserves and contingent resources were assigned and the best estimate was 3.1 Tcf gross raw gas. In terms of contingent resources, Storm acquired from SGR a best estimate of 393 Bcf net sales. Proved and probable reserves acquired from SGR totaled 41 Bcf net sales (6,831 Mboe) which includes $74.2 million of associated future development capital to complete a standing horizontal gas well (0.6 net SGR:0.4 net Storm) and drill six horizontal gas wells (3.6 net SGR).

OPERATIONS REVIEW

Storm has a focused asset base with the majority of production coming from two large scale resource plays with multi-year drilling upside: liquids rich natural gas from the Montney formation at Umbach and shale gas from the Muskwa and Otter Park shales in the HRB.

Umbach, North East British Columbia

Storm's current land holdings at Umbach total 98 gross sections or 70 net sections at Umbach (53,800 net undeveloped acres), all of which are prospective for liquids rich natural gas from the Montney formation. Storm's lands are subdivided into a northern area, which consists of 60 gross sections at 53% working interest, and a southern area which consists of 38 gross sections at a 100% working interest. Production averaged 414 Boe per day in the fourth quarter while the operating netback was $17.75 per Boe (17% condensate plus natural gas liquids).

In the fourth quarter, the third horizontal well (60% working interest) was completed with 11 fracture stimulations and began producing in November at an initial rate of approximately 2.0 Mmcf per day gross raw gas. A fourth horizontal well was drilled and cased 2.5 miles south of the first horizontal well and included a vertical pilot hole. Logs from the vertical pilot hole indicate 30 metres of net pay in the Montney formation which significantly expands the areal extent of the exploitable area.

Total production at Umbach from three horizontal wells (60% working interest) is currently 3.4 Mmcf per day gross raw gas (3.0 Mmcf per day gross sales gas plus 102 barrels per day gross condensate and natural gas liquids). Currently, production is processed at the McMahon Gas Plant with total condensate plus natural gas liquids production averaging 34 barrels per Mmcf of sales gas in the fourth quarter (62% condensate and pentane). In early March, production will be re-directed to the Stoddart Gas Plant which will increase propane, butane, and pentane recovery resulting in condensate plus natural gas liquids production increasing to 40 to 50 barrels per Mmcf of sales gas (approximately 55% condensate and pentane).

Results to date from the first three horizontal wells have been very encouraging as evidenced by liquids recoveries and the rapid flattening of the decline after three to six months of production. After a year of production, the rate on the first horizontal well has stabilized at approximately 1.1 Mmcf per day gross raw gas or 1.0 Mmcf per day gross sales gas plus 34 barrels per day of condensate and natural gas liquids. Production history for each horizontal since inception is provided in the presentation on Storm's website www.stormresourcesltd.com. Different fracture treatments were conducted on each of the three producing horizontal wells in an attempt to improve productivity and reserves. Further optimization is planned in 2012 which will include varying the sand tonnage in fracture treatments, modifying the fluid system, and possibly lowering the wellbore so that the middle Montney is also accessed.

At the end of 2011, InSite's evaluation of the Montney formation on the northern lands results in the best case estimate of DPIIP to be 465 Bcf gross raw gas on 19.75 gross sections (average working interest 57%). DPIIP includes the producing area of 3.5 gross sections with proved plus probable reserves totalling 2,975 Mboe sales (19% condensate plus natural gas liquids) net to Storm and the area where contingent resources were assigned to 16.25 gross sections with the best estimate being 14,058 Mboe sales net to Storm (19% condensate plus natural gas liquids). Condensate plus natural gas liquids was estimated to be 40 barrels per Mmcf per day of gas sales. Based on existing vertical and horizontal well control in the northern area, more than 40 gross sections are likely to be productive in the Montney formation and Storm's 2012 activity will be focused on proving up the resource in this larger area.

Storm's activity in 2012 will be focused on increasing the size of the resource in the Montney formation by drilling step-out horizontal wells and optimizing completions to increase production rates and reserves. Activity will include:

• Drilling a vertical delineation well (100% working interest) in the southern area in the first quarter which will be re-entered and drilled horizontally in the third or fourth quarter if prospectivity of the Montney formation is confirmed by log analysis;

• Completing the fourth horizontal well (60% working interest) late in the second quarter; and

• Drilling and completing two to three additional horizontal wells (1.2 to 1.8 net) in the third and fourth quarters.

Horn River Basin, North East British Columbia

Storm's undeveloped land position in the HRB currently totals 135 gross sections at a 100% working interest (88,600 net acres) and is prospective for natural gas from the Muskwa, Otter Park, and Evie/Klua shales. During the fourth quarter, production from this area averaged 266 Boe per day at an operating netback of $10.35 per Boe. On January 12, 2012, Storm completed the previously announced acquisition of SGR, its partner in the HRB, which added 360 Boe per day.

In the fourth quarter, completion operations on the second horizontal well (40% Storm, 60% SGR) began November 12 and were suspended November 29 following an unexpected operational problem. After the first fracture stimulation was pumped, the bridge plug required to isolate the first interval became stuck in the horizontal section while it was being moved into position. The bridge plug was retrieved; however, the delay resulted in the expiry of the window of availability for the fracturing crew.

Production performance of the first horizontal well (40% Storm, 60% SGR) with 12 fracture stimulations continues to exceed expectations with the current rate being approximately 3.9 Mmcf per day gross raw gas and cumulative production of 1.9 Bcf gross raw gas since production commenced on March 7, 2011. Compression has not yet been installed resulting in the flow rate being restricted. Productivity has been higher than expected and the decline rate has been relatively moderate which has resulted in performance to date exceeding the initial type curve which predicted recovery of 9 Bcf gross raw gas. InSite's amended type curve predicts ultimate production of 9.6 Bcf gross raw gas without field compression. Significant improvements in productivity and reserves are expected on future horizontals by increasing fracture density (15 to 18 fracture stimulations per horizontal) and by installing field compression. At current natural gas prices, Storm expects that no royalties will be paid on production from the first two horizontals in the next two to three years due to their qualification under British Columbia's Deep Royalty Credit and Infrastructure Royalty Credit Programs.

At the end of 2011, InSite's evaluation of the Muskwa and Otter Park shales resulted in the best estimate of DPIIP being 3.1 Tcf gross raw gas on 30 gross sections (Storm's working interest is 100% after the transaction with SGR closed). The producing area where proved plus probable reserves were assigned is 3.0 gross sections and the area where contingent resources were assigned is 27 gross sections.

Mica, North East British Columbia

The acquisition of the producing property at Mica closed December 1, 2011 and added 145 Boe per day of production (70% light oil and natural gas liquids, 30% natural gas). The purchase price, net of adjustments, was $15.4 million and was financed with existing cash resources plus an expanded credit facility. Storm acquired a 100% working interest in seven producing oil wells. The field netback for the property is currently estimated to be $49.00 per Boe with operating costs of $14.30 per Boe and a royalty rate of 10%. The acquired asset contains an estimated 722 Mboe of proved plus probable reserves (70% light oil plus natural gas liquids) based on the year-end evaluation completed by InSite (reserve estimate is based on forecast decline from existing producing wells and does not include any upside from infill drilling or initiating a waterflood). Storm management estimates that DPIIP is approximately 7.0 million barrels of oil with recovery to date being 21% (average production of 210,000 barrels of oil from each producing well) and this could be improved to 35% to 40% by drilling six infill wells plus initiating a waterflood (future development capital internally estimated to be $12.6 million). Near-term plans include initiating a waterflood in the first quarter and, in the second half of 2012, expanding the waterflood along with drilling up to two infill vertical wells.

INVESTMENTS

At the end of 2011, Storm had share ownership positions in one private company and two publicly traded companies. The value of the share positions in the two public companies totaled $8.8 million at the end of the fourth quarter and these securities could possibly be sold in the future with the proceeds being used to finance the Company's capital programs.

Chinook Energy Inc. ("Chinook")

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

Bridge Energy ASA ("Bridge")

Storm holds 1.05 million common shares of Bridge (symbol 'Bridge' on the Oslo Stock Exchange), a Norwegian-based exploration and production company with production of approximately 1,400 Boe per day, several development opportunities in the UK sector of the North Sea, and a number of exploratory leads in the Norwegian sector of the North Sea.

Storm Gas Resource Corp. ("SGR")

At the end of 2011, Storm's share ownership position in SGR totaled 2.5 million shares, representing 22% ownership of SGR. On January 12, 2012, Storm completed the acquisition of SGR by issuing 11,761,190 common shares of Storm at a deemed issuance price of $3.70 per Storm share in exchange for all of the issued and outstanding common shares of SGR that were not owned by Storm.

OUTLOOK

Based on field estimates, production in the first quarter to the end of February has averaged approximately 1,050 Boe per day with 18% liquids. Production is forecast to increase to 3,600 to 4,000 Boe per day (41% liquids) in the fourth quarter of 2012 after the transaction with Bellamont closes and including planned capital investment on operations of $34.0 million. Capital investment includes $27.0 million for drilling and completions and $7.0 million for land, seismic and facilities. Drilling activity will include one vertical well (1.0 net) at Umbach, two horizontal wells (1.2 net) at Umbach, completing one standing horizontal well (0.6 net) at Umbach, five horizontal wells (5.0 net) at Grimshaw, and one to three horizontals or verticals (all 100% working interest) targeting light oil opportunities in the Grande Prairie or Mica area. In addition, $5.0 million will be invested to initiate the waterflood at Mica, commence water disposal and injection at Grimshaw, and to modify two existing facilities in the Grande Prairie area. Further details regarding Storm's 2012 operating guidance is provided in the following table:

		Storm		Bellamont		Pro Forma Combined
Forecast daily production in Q2 2012 after deducting 5% for unplanned outages/failures:
	Natural gas (Mcf)	5,000		6,500		11,500
	Crude oil and NGLs (Bbl)	200		1,040		1,240
	Total Boe per day	1,035		2,125		3,160
	Oil and liquids %	19	%	49	%	39	%
Estimated field netback at $2.40/GJ AECO, Cdn $100/Bbl Edmonton Par(1)		$23/Boe		$28/Boe		$26 - $27/Boe
Undeveloped land - net acres		228,000		78,000		306,000
Indicated bank line						$70.0 million
2012 average operating costs(2)						$10 to $12 per Boe
2012 average royalty rate(2)						12	%
2012 operations capital						$34.0 million
2012 cash G&A(2)(3)						$3.6 million
2012 exit or fourth quarter average production				3,600 to 4,000 Boe per day (41% oil + NGLs			)

(1) Using Storm and Bellamont 2011 average royalty rates, operating costs and deducted $1.60 per Boe transportation costs.

(2) Assumes transaction with Bellamont closes prior to April 1, 2012.

(3) Excludes transaction costs associated with the SGR acquisition and Bellamont combination which are required to be expensed under IFRS.

After closing of the Bellamont transaction, Storm's near term objectives are to:

• Continue delineating and developing Bellamont's light oil Montney pool at Grimshaw by drilling five infill and step-out horizontals in the second half of 2012;

• Advance additional light oil opportunities on Bellamont's lands in the Grande Prairie area which will involve drilling one to three horizontal development wells (all 100% working interest);

• Initiate a waterflood at Mica;

• Implement operating cost reductions at Bellamont's properties which are expected to result in savings of more than $2.0 million per year; and

• Further expand the liquids rich Montney gas resource at Umbach by completing the fourth horizontal well (0.6 net) on the northern lands, drilling and completing two to three additional horizontal wells (1.2 to 1.8 net) on the northern lands and drilling one vertical delineation well (1.0 net) on the southern lands.

The acquisition of the Mica light oil property in the fourth quarter of 2011, and the recently announced business combination with Bellamont, result from Storm's commitment to grow its business in an environment of low natural gas prices through commodity diversification which provides access to higher netback opportunities. In addition, both transactions add to Storm's opportunity base and provide additional financial capacity to support future growth. Storm retains significant leverage to improving natural gas prices through the large resource plays at Umbach and in the HRB where multi-year drilling upside has been identified. With results to date in Umbach and the HRB having met or exceeded expectations, we expect that the already significant resource we have identified to date on our lands will continue to expand with future activity. Success in converting only a portion of the best estimate of contingent resources at Umbach and in the HRB (116.8 Mmboe net sales including SGR) will result in significant future reserve growth.

Storm's efforts in 2012 will be primarily focused on growing liquids production in the Grande Prairie, Mica, and Grimshaw areas while also continuing to expand the identified liquids rich natural gas resource in the Montney formation at Umbach. Our disciplined approach to capital investment has resulted in significant growth for shareholders on a per-share basis since operations began at the 'first Storm' in November 1998. We will continue doing what has worked so well for us and are confident that it will carry us through the current low in the natural gas commodity price cycle.

In closing, I would like to thank the hard working and talented team of Storm employees for their efforts, our shareholders for their continued confidence and our Board of Directors for their invaluable advice and guidance.

Respectfully,

Brian Lavergne, President and Chief Executive Officer

March 1, 2012

Discovered-Petroleum-Initially-in-Place ("DPIIP") - is defined in the Canadian Oil and Gas Evaluation Handbook ("COGEH") as the quantity of hydrocarbons that are estimated to be in place within a known accumulation. DPIIP is divided into recoverable and unrecoverable portions, with the estimated future recoverable portion classified as reserves and contingent resources. There is no certainty that it will be economically viable or technically feasible to produce any portion of this DPIIP except for those portions identified as proved or probable reserves.

Contingent Resources - are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project at an early stage of development. Estimates of contingent resources described herein are estimates only; the actual resources may be higher or lower than those calculated in the independent evaluation. There is no certainty that the resources described in the evaluation will be commercially produced.

Boe Presentation - For the purpose of calculating unit revenues and costs, natural gas is converted to a barrel of oil equivalent ("Boe") using six thousand cubic feet ("Mcf") of natural gas equal to one barrel of oil unless otherwise stated. Boe may be misleading, particularly if used in isolation. A Boe conversion ratio of six Mcf to one barrel ("Bbl") is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All Boe measurements and conversions in this report are derived by converting natural gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil. Mboe means 1,000 Boe.

Reserves at December 31, 2011

Storm's year-end reserve and resource evaluations effective December 31, 2011 were prepared by InSite Petroleum Consultants Ltd. ("InSite") which was formerly Paddock Lindstrom & Associates Limited. InSite has evaluated all of Storm's crude oil, NGL and natural gas reserves. The InSite price forecast at December 31, 2011 was used to determine all estimates of future net revenue (also referred to as net present value or NPV). Storm's Reserves Committee, comprised of independent and appropriately qualified directors, has reviewed and approved the evaluation prepared by InSite and the report of the Reserves Committee has been accepted by the Company's Board of Directors.

Summary

• Proved reserves totaled 3,714 Mboe and proved plus probable reserves totaled 8,322 Mboe.

• The proved finding and development cost as per NI 51-101 requirements was $20.32 per Boe and the proved plus probable finding and development cost, as per NI 51-101 requirements, was $14.60 per Boe. This includes the change in future development costs ("FDC") and excludes the effect of acquisitions, divestitures, and revisions.

• The all-in cost to add proved reserves was $20.87 per Boe and for proved plus probable reserves was $15.39 per Boe. The all-in calculation reflects the result of Storm's entire capital investment program as it takes into account the effect of acquisitions, dispositions, revisions, as well as the change in future development costs.

• The net present value of proved plus probable reserves, discounted at 10% before tax, amounted to $54.5 million with the majority of this being attributed to the Umbach (50%) and Mica properties (30%). The InSite price forecast effective December 31, 2011 was used in the reserve evaluation.

• FDC was $30.2 million on a proved basis and $72.8 million on a proved plus probable basis.

• Drilling activity in 2011 resulted in the addition of 2,505 Mboe on a proved basis and 5,278 Mboe on a proved plus probable basis.

• In the HRB, proved plus probable reserves were 4,561 Mboe with 4,092 Mboe assigned to complete a standing horizontal shale gas well (0.4 net) and to drill six horizontal shale gas wells (2.4 net). Recoverable reserves assigned to each of the horizontal drilling locations was 9.6 to 10.4 Bcf of gross raw gas. Shrinkage of 12% was used to determine sales gas volumes. Proved plus probable FDC was $123.8 million gross ($49.5 million net) which includes $14.8 million gross, or $5.9 million net, being invested in associated infrastructure. In general, undrilled horizontal development wells are recognized as part of proved plus probable reserves if there is sufficient horizontal plus vertical well control and if they are likely to be drilled within three years.

• At Umbach, proved plus probable reserves were 2,975 Mboe with 2,336 Mboe assigned to complete a standing horizontal well (0.6 net) and to drill seven horizontal wells (4.2 net). Recoverable reserves assigned to each of the horizontal drilling locations was 2.6 Bcf of gross raw gas. Shrinkage of 11% was used as well as total liquids recovery of 40 barrels per Mmcf of sales gas. Proved plus probable FDC was $38.8 million gross ($23.3 million net). In general, undrilled horizontal development wells are recognized as part of proved plus probable reserves if there is sufficient horizontal plus vertical well control and if they are likely to be drilled within three years.

• At Mica, proved plus probable reserves totaled 722 Mboe (70% light oil plus natural gas liquids) and is based on forecast decline from existing producing wells; no reserves were included for infill drilling or initiating a waterflood.

• Based on an update completed by InSite effective January 31, 2012, the acquisition of SGR added 2,645 Mboe proved reserves and 6,831 Mboe proved plus probable reserves. Proved plus probable FDC was $74.2 million net to SGR. Note that the acquisition of SGR closed on January 12, 2012.

• The resource opportunity on Storm's land base is significant. The best case estimate of DPIIP at Umbach in the liquids rich Montney formation is 465 Bcf gross raw gas over an area of 19.75 gross sections (13,762 gross acres, average Storm working interest of 57%). The evaluated area covers less than 20% of Storm's land position in the area. The best case estimate of DPIIP in the HRB is 3.1 Tcf gross raw gas over an area of 30 gross sections (19,463 gross acres) with Storm's average working interest being 100% (after closing the acquisition of SGR on January 12, 2012). The evaluated area covers less than 22% of Storm's land position in the area.

• Future reserve growth will come from converting contingent resources to proved plus probable reserves. The total best estimate of contingent resources is 116,800 Mboe net sales with 14,058 Mboe at Umbach and 102,752 Mboe in the HRB (223 Bcf net sales to Storm plus 393 Bcf net sales to SGR).

Gross Company Interest Reserves as at December 31, 2011

(Before deduction of royalties payable, not including royalties receivable)

	Light Crude Oil (Mbbls)	Sales Gas (Mmcf)	NGL (Mbbls)	6:1 Oil Equivalent (Mboe)
Proved producing	476	5,893	110	1,568
Proved non-producing	-	-	-	-
Total proved developed	476	5,893	110	1,568
Proved undeveloped	-	12,038	140	2,146
Total proved	476	17,931	250	3,714
Probable additional	79	25,208	328	4,608
Total proved plus probable	555	43,139	578	8,322

Gross Company Reserve Reconciliation for 2011

(Gross company interest reserves before deduction of royalties payable)

6:1 Oil Equivalent (Mboe)
	Total Proved		Probable		Proved plus Probable
December 31, 2010 - opening balance	738		1,774		2,512
Acquisitions	634		92		726
Discoveries	-		-		-
Extensions	2,505		2,773		5,278
Dispositions	-		-		-
Technical revisions	35		(31	)	4
Production	(198	)	-		(198	)
December 31, 2011 - closing balance	3,714		4,608		8,322

Future Development Costs

Proved
	HRB	1.2 net horizontals plus infrastructure	$	21.3 million
	Umbach	1.8 net horizontals	$	8.9 million
Total			$	30.2 million
Proved Plus Probable Additional
	HRB	2.8 net horizontals plus infrastructure	$	49.5 million
	Umbach	4.8 net horizontals	$	23.3 million
Total			$	72.8 million

	Proved Expenditures		Proved Plus Probable Additional Expenditures
2012	$	5.9 million	$	12.9 million
2013	$	16.0 million	$	29.2 million
2014	$	7.4 million	$	8.9 million
2015	$	0.8 million	$	16.4 million
2016		-	$	5.5 million

NI 51-101 Finding and Development Costs

Total Proved Finding and Development Cost	2011		2010
Capital expenditures excluding acquisitions and dispositions (000s)	$	25,360	$	16,800
Net change in FDC (000s)		25,541		4,679
Total capital including the net change in future capital (000s)	$	50,901	$	21,479
Reserve additions excluding acquisitions, dispositions and revisions (Mboe)		2,505		738
Total proved finding and development costs (per Boe)	$	20.32	$	29.10
Total Proved Plus Probable Finding and Development Cost		2011		2010
Capital expenditures excluding acquisitions and dispositions (000s)	$	25,360	$	16,800
Net change in FDC (000s)		51,725		21,057
Total capital including the net change in future capital (000s)	$	77,085	$	37,857
Reserve additions excluding acquisitions, dispositions and revisions (Mboe)		5,278		2,512
Total proved plus probable finding and development costs (per Boe)	$	14.60	$	15.07

All-In Finding, Development and Acquisition Costs

Total Proved All-In Finding, Development and Acquisition Cost including FDC, Acquisitions, Dispositions, Revisions	2011		2010
Capital expenditures including acquisitions and dispositions (000s)	$	40,795	$	16,800
Net change in FDC (000s)		25,541		4,679
Total capital including the net change in future capital (000s)	$	66,336	$	21,479
Reserve additions including acquisitions, dispositions and revisions (Mboe)		3,178		738
All-in total proved finding and development costs (per Boe)	$	20.87	$	29.10
Total Proved Plus Probable All-In Finding, Development and Acquisition Cost including FDC, Acquisitions, Dispositions, Revisions		2011		2010
Capital expenditures including acquisitions and dispositions (000s)	$	40,795	$	16,800
Net change in FDC (000s)		51,725		21,057
Total capital including the net change in future capital (000s)	$	92,520	$	37,857
Reserve additions including acquisitions, dispositions and revisions (Mboe)		6,012		2,512
All-In total proved plus probable finding and development costs (per Boe)	$	15.39	$	15.07

Net Present Value Summary (before tax) as at December 31, 2011

Benchmark oil and NGL prices used are adjusted for quality of oil or NGL produced and for transportation costs. The calculated NPVs include a deduction for estimated future well abandonment costs.

	Undiscounted (000s)		Discounted at 5% (000s)		Discounted at 10% (000s)		Discounted at 15% (000s)			Discounted at 20% (000s)
Proved producing	$	52,462	$	37,803	$	29,777	$	24,746		$	21,304
Proved non-producing		-		-		-		-			-
Total proved developed	$	52,462	$	37,803	$	29,777	$	24,746		$	21,304
Proved undeveloped		20,114		8,967		2,575		(1,282	)		(3,694	)
Total proved	$	72,576	$	46,770	$	32,352	$	23,464		$	17,609
Probable additional		82,519		41,976		22,153		11,392			5,113
Total proved plus probable	$	155,095	$	88,747	$	54,505	$	34,856		$	22,722

Numbers in this table may not add due to rounding.

Net Present Value Summary (after tax) as at December 31, 2011

Benchmark oil and NGL prices used are adjusted for quality of oil or NGL produced and for transportation costs. The calculated NPVs each include a deduction for estimated future well abandonment costs.

	Undiscounted (000s)		Discounted at 5% (000s)		Discounted at 10% (000s)		Discounted at 15% (000s)			Discounted at 20% (000s)
Proved producing	$	52,462	$	37,803	$	29,777	$	24,746		$	21,303
Proved non-producing		-		-		-		-			-
Total proved developed	$	52,462	$	37,803	$	29,777	$	24,746		$	21,303
Proved undeveloped	$	20,114	$	8,967	$	2,575	$	(1,282	)	$	(3,694	)
Total proved	$	72,576	$	46,770	$	32,352	$	23,464		$	17,609
Probable additional	$	62,590	$	32,123	$	16,849	$	8,353		$	3,285
Total proved plus probable	$	135,166	$	78,893	$	49,201	$	31,817		$	20,894

InSite Escalating Price Forecast as at December 31, 2011

	WTI Crude Oil (US$/Bbl)	Edmonton Light Crude Oil (Cdn$/Bbl)	Henry Hub Natural Gas (US$/Mmbtu)	AECO Natural Gas (Cdn$/Mmbtu)	Propane (Cdn$/Bbl)	Butane (Cdn$/Bbl)
2012	100.00	98.00	3.90	3.45	58.80	73.50
2013	101.00	99.00	4.50	4.04	59.40	74.25
2014	102.00	99.96	5.00	4.53	59.98	74.97
2015	103.00	100.92	5.50	5.02	60.55	75.69
2016	104.00	101.88	6.00	5.51	61.13	76.41

InSite Summary of DPIIP and Contingent Resources for the Horn River Basin

Effective December 31, 2011

Independent evaluator, InSite, completed an evaluation of Storm's DPIIP and contingent resources for the Muskwa and Otter Park formations. The evaluated area covers 30 gross sections, or 19,463 gross acres. The InSite evaluation was prepared in accordance with the Canadian Oil and Gas Evaluation Handbook. The contingencies that prevent the contingent resources from being classified as reserves are associated with the early evaluation stage of these potential development opportunities. Additional drilling, completion and testing data is generally required before a commitment can be made to their development. There is no certainty that it will be commercially viable to produce any of the resources. The key findings of the evaluation are as follows:

		Low Estimate (1)		Best Estimate (1)		High Estimate (1)
Muskwa and Otter Park
	Average gross thickness	92 metres		92 metres		92 metres
	Average porosity	3.5	%	4.25	%	5.0	%
Gross DPIIP within evaluation area (gross raw Bcf)(2)		2,836		3,117		3,398
DPIIP net to Storm's working interest (net raw Bcf)(2)		1,039		1,141		1,244
Proved plus probable reserves net to Storm's working interest (net sales Bcf)(3)(4)		27		27		27
Estimated economic contingent resources net to Storm's working interest (net sales Bcf)(3)(4)(5)		161		223		295

Notes:

(1) Numbers in this table are subject to rounding error.

(2) DPIIP has been estimated using the gross shale thickness, gas saturation of 78 percent, gas formation volume factor of 205 scf per ft³, gas Z of 0.98, reservoir temperature of 265 F, average reservoir pressure of 4,142 psig and adsorbed gas content of 69 scf per ton.

(3) Contingent resources do not include proved plus probable reserves that were assigned by InSite in the 2011 year-end reserve evaluation.

(4) Gas shrinkage of 12 percent is included in determining proved plus probable reserves plus contingent resources.

(5) Storm's net working interest proved plus probable reserves and contingent resources are before deducting royalties payable.

Proved plus probable reserves assigned in the 2011 year-end reserve evaluation were 27 Bcf sales gas net to Storm and were excluded from estimated contingent resources. The low estimate of contingent resources was 161 Bcf sales net to Storm. The low estimate is the most conservative estimate and carries the greatest level of confidence (at least 90 percent) that the resource will be recovered. The best estimate (50 percent confidence) of contingent resources was 223 Bcf sales net to Storm. The high estimate (less than 10 percent confidence) of contingent resources is 295 Bcf sales net to Storm. The remainder of the DPIIP beyond what has been cumulatively produced, classified as proved plus probable reserves, or classified as contingent resource, is currently considered to be the unrecoverable portion.

InSite Summary of DPIIP and Contingent Resources for the Umbach Area

Effective December 31, 2011

InSite completed an evaluation of DPIIP and contingent resources for the Montney formation on the northern land block. The evaluated area was 19.75 gross sections (13,762 gross acres) with Storm's average working interest being 57%. The InSite evaluation was prepared in accordance with the Canadian Oil and Gas Evaluation Handbook. The contingencies that prevent the contingent resources from being classified as reserves are associated with the early evaluation stage of these potential development opportunities. Additional drilling, completion, and testing data is generally required before a commitment can be made to their development. There is no certainty that it will be commercially viable to produce any of the resources. The key findings of the evaluation are as follows:

		Low Estimate (1)		Best Estimate (1)		High Estimate (1)
Montney
	Average net pay	26 metres		26 metres		26 metres
	Average porosity	7	%	7	%	7	%
Gross DPIIP within evaluation area (gross raw Bcf)(2)		465		465		465
DPIIP net to Storm's working interest (net raw Bcf)(2)		266		266		266
Proved plus probable reserves net to Storm's working interest (net sales Mboe)(3)(4)		2,975		2,975		2,975
Estimated economic contingent resources net to Storm's working interest (net sales) (3)(4)(5)
	Natural gas	58 Bcf		68 Bcf		78 Bcf
	Natural gas liquids	2,309 Mbbls		2,694 Mbbls		3,078 Mbbls
	Mboe	12,050 Mboe		14,059 Mboe		16,067 Mboe

Notes:

(1) Numbers in this table are subject to rounding error.

(2) DPIIP has been estimated using a net pay cut-off of 20 metres, gas saturation of 80 percent, gas formation volume factor of 161 scf per ft³, gas Z of 0.8, reservoir temperature of 149 F and average reservoir pressure of 2,220 psia.

(3) Contingent resources do not include proved plus probable reserves that were assigned by InSite in the 2011 year-end reserve evaluation.

(4) Gas shrinkage of 11 percent and 40 barrels of natural gas liquids per Mmcf sales gas was used in determining proved plus probable reserves and contingent resources.

(5) Storm's net working interest proved plus probable reserves and contingent resources are before deducting royalties payable.

Proved plus probable reserves assigned in the 2011 year-end reserve evaluation were 2,975 Mboe sales net to Storm and were excluded from estimated contingent resources. The low estimate of contingent resources was 12,050 Mboe sales net to Storm. The low estimate is the most conservative estimate and carries the greatest level of confidence (at least 90 percent) that the resource will be recovered. The best estimate (50 percent confidence) of contingent resources was 14,059 Mboe sales net to Storm. The high estimate (less than 10 percent confidence) of contingent resources is 16,067 Mboe sales net to Storm. The remainder of the DPIIP beyond what has been cumulatively produced, classified as proved plus probable reserves, or classified as contingent resource, is currently considered to be the unrecoverable portion.

RESERVES AND CONTINGENT RESOURCES ADDED AS A RESULT OF THE ACQUISITION OF SGR, AS AT JANUARY 31, 2012

InSite evaluated the reserves and resources added as a result of the acquisition of SGR, which closed on January 12, 2012. Note that the effective date of this evaluation was January 31, 2012.

Gross SGR Interest Reserves as at January 31, 2012

(Before deduction of royalties payable)

	Light Crude Oil (Mbbls)	Sales Gas (Mmcf)	NGL (Mbbls)	6:1 Oil Equivalent (Mboe)
Proved producing	-	3,121	-	520
Proved non-producing	-	-	-	-
Total proved developed	-	3,121	-	520
Proved undeveloped	-	12,746	-	2,124
Total proved	-	15,868	-	2,645
Probable additional	-	25,116	-	4,186
Total proved plus probable	-	40,984	-	6,831

Numbers in this table may not add due to rounding.

Future Development Costs Net to SGR

Proved
	HRB	1.8 net horizontals plus infrastructure	$	31.9 million
Total			$	31.9 million
Proved Plus Probable Additional
	HRB	4.2 net horizontals plus infrastructure	$	74.2 million
Total			$	74.2 million

	Proved Expenditures		Proved Plus Probable Additional Expenditures
2012		-	$	7.1 million
2013	$	19.5 million	$	21.0 million
2014	$	11.1 million	$	13.3 million
2015	$	1.2 million	$	24.6 million
2016		-	$	8.2 million

InSite Summary of SGR's DPIIP and Contingent Resources for the Horn River Basin

Effective January 31, 2012

	Low Estimate (1)	Best Estimate (1)	High Estimate (1)
Gross DPIIP within evaluation area (gross raw Bcf)	2,836	3,117	3,398
DPIIP net to SGR's working interest (net raw Bcf)	1,797	1,976	2,154
Proved plus probable reserves net to SGR's working interest (net sales Bcf)	41	41	41
Estimated economic contingent resources net to SGR's working interest (net sales Bcf)(2)(3)	283	393	519

Notes:

(1) Numbers in this table are subject to rounding error.

(2) DPIIP has been estimated using the gross shale thickness, gas saturation of 78 percent, gas formation volume factor of 205 scf per ft³, gas Z of 0.98, reservoir temperature of 265 F, average reservoir pressure of 4,142 psig and adsorbed gas content of 69 scf per ton.

(3) Contingent resources do not include proved plus probable reserves that were assigned by InSite in the 2011 year-end reserve evaluation.

(4) Gas shrinkage of 12 percent is included in determining proved plus probable reserves plus contingent resources.

(5) SGR's net working interest proved plus probable reserves and contingent resources are before deducting royalties payable.

Forward-Looking Information - This press release contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words "will", "expects", "believe", "plans", "potential" and similar expressions are intended to identify forward-looking statements or information. More particularly, and without limitation, this press release contains forward-looking statements and information concerning: production; drilling plans; reserve volumes; capital expenditures; royalties; and production and general and administrative costs.

The forward-looking statements and information in this press release are based on certain key expectations and assumptions made by Storm, including: prevailing commodity prices and exchange rates; applicable royalty rates and tax laws; future well production rates; reserve and resource volumes; the performance of existing wells; success to be expected in drilling new wells; the adequacy of budgeted capital expenditures to carrying out planned activities; the availability and cost of services; and the receipt, in a timely manner, of regulatory and other required approvals. Although the Company believes that the expectations and assumptions on which such forward-looking statements and information are based are reasonable, undue reliance should not be placed on these forward-looking statements and information because of their inherent uncertainty. In particular, there is no assurance that exploitation of the Company's undeveloped lands and prospects will result in the emergence of profitable operations.

Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to the risks associated with the oil and gas industry in general such as: operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to reserves, production, costs and expenses; health, safety and environmental risks; commodity price and exchange rate fluctuations; marketing and transportation of petroleum and natural gas and loss of markets; environmental risks; competition; ability to access sufficient capital from internal and external sources; stock market volatility; and changes in legislation, including but not limited to tax laws, royalty rates and environmental regulations.

Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect the operations or financial results of the Company are included or are incorporated by reference in the company's MD&A for the three months and year ended December 31, 2011.

The forward-looking statements and information contained in this press release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.