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, 2012

CALGARY, ALBERTA--(Marketwire - Feb. 28, 2013) - Storm Resources Ltd. (TSX VENTURE:SRX)

Storm has also filed its audited consolidated financial statements as at December 31, 2012 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, 2012, as well as reserve information at December 31, 2012, appears below and should be read in conjunction with the related financial statements and MD&A.

Highlights
Thousands of Cdn$, except volumetric and per share amounts		Three Months Ended December 31, 2012		Three Months Ended December 31, 2011		Year Ended December 31, 2012		Year Ended December 31, 2011
FINANCIAL
	Gas sales	3,416		1,160		8,054		3,404
	NGL sales	1,597		594		4,466		1,020
	Oil sales	5,399		739		19,793		2,468
Revenue from product sales(1)		10,412		2,493		32,313		6,892
Funds from operations(2)		5,016		709		13,387		1,874
	Per share - basic ($)	0.08		0.03		0.24		0.07
	Per share - diluted ($)	0.08		0.03		0.24		0.07
Net income (loss)		(2,320	)	(1,758	)	(6,574	)	(3,664	)
	Per share - basic ($)	(0.04	)	(0.07	)	(0.12	)	(0.14	)
	Per share - diluted ($)	(0.04	)	(0.07	)	(0.12	)	(0.14	)
Field capital expenditures, net of dispositions		8,777		20,687		14,282		40,796
Net debt/working capital		44,696		15,171		44,696		15,171
Weighted average common shares outstanding (000s)
	Basic	61,824		26,377		56,067		26,377
	Diluted	61,824		26,377		56,067		26,377
Common shares outstanding (000s)
	Basic	61,824		26,377		61,824		26,377
	Fully diluted	64,547		28,355		64,547		28,355
OPERATIONS
Oil equivalent (6:1)
	Barrels of oil equivalent (000s)	259		72		825		198
	Barrels of oil equivalent per day	2,815		779		2,254		542
	Average selling price (Cdn$ per Boe)(1)	40.19		34.78		39.14		34.86
Gas production
	Thousand cubic feet (000s)	987		346		3,053		964
	Thousand cubic feet per day	10,728		3,763		8,342		2,641
	Average selling price (Cdn$ per Mcf)	3.46		3.35		2.64		3.53
NGL Production
	Barrels (000s)	25		7		67		12
	Barrels per day	274		72		185		32
	Average selling price (Cdn$ per barrel)	63.27		89.95		66.17		87.36
Oil Production
	Barrels (000s)	69		7		249		25
	Barrels per day	753		80		679		69
	Average selling price (Cdn$ per barrel)(1)	77.93		100.05		79.53		97.39
Wells drilled
	Gross	2.0		1.0		6.0		4.0
	Net	1.2		0.6		4.4		2.2

(1)	Excludes hedging gains.
(2)	Funds from operations and funds from operations per share are non-GAAP measurements. See discussion of Non-GAAP Measurements on page 14 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 24 of the MD&A.

President's Message

2012 FOURTH QUARTER AND YEAR-END HIGHLIGHTS

• Fourth quarter production averaged 2,815 Boe per day which is a year-over-year increase of 260% or 55% on a per-share basis. Oil plus NGL production grew to represent 36% of fourth quarter production versus 19% a year ago. Average 2012 production grew 95% on a per-share basis to 2,254 Boe per day with 38% being oil plus NGL. Increased production was the result of two corporate transactions that closed in the first quarter of 2012, Bellamont Exploration Ltd. ("Bellamont") and Storm Gas Resource Corp. ("SGR"), and also from new horizontal wells in the Montney formation at Umbach. The Bellamont transaction added 1,253 Boe per day to average 2012 production and the acquisition of SGR added 276 Boe per day. Increased oil plus NGL production in 2012 was primarily the result of the Bellamont transaction which added 668 barrels per day of oil plus NGL and from growth at Umbach where NGL production grew by 75 barrels per day.
  
  
• Capital investment totaled $8.8 million in the fourth quarter and $166.0 million for the year. The majority of 2012 capital investment related to acquisitions net of dispositions, which totaled $139.2 million. Acquisitions were $154.9 million which included the Bellamont transaction for $96.6 million and the SGR acquisition for $55.2 million. Dispositions totaled $15.7 million from the sale of two non-core properties in the second half of 2012. Capital investment in operations was $26.9 million for the year.
  
  
• During 2012, activity was primarily focused on delineating the resource in the Montney formation at Umbach. Drilling included six wells (4.4 net) with four horizontal wells (2.4 net) in the Montney at Umbach. Three horizontal wells (1.8 net) were completed and pipeline connected at Umbach. In the fourth quarter, two horizontal wells (1.2 net) were drilled at Umbach with completion and tie-in of both planned for 2013.
  
  
• Funds from operations in the fourth quarter was $5.0 million, or $0.08 per basic share, an increase of 165% from cash flow of $0.03 per basic share in the prior year. For the year, funds from operations increased by 610% to $13.4 million. The increase in quarterly and yearly funds from operations resulted primarily from the Bellamont transaction which increased higher priced oil plus NGL as a proportion of total production and added $13.2 million of operating income in 2012.
  
  
• Funds from operations increased throughout 2012 and averaged $19.37 per Boe in the fourth quarter. The 2012 average funds from operations per Boe was $16.19, an increase of 70% from the prior year amount of $9.48 per Boe. Total cash costs including operating expense, interest expense, transportation costs, and cash general and administrative costs were $19.83 per Boe in 2012 and decreased to $19.34 per Boe in the fourth quarter.
  
  
• Hedging gains from fixed price financial hedges put in place to protect capital investment were $1.7 million in 2012. For 2013, commodity price hedges currently include 400 barrels of oil per day in the first quarter at an average floor price of Cdn $91.08 per barrel, 300 barrels of oil per day in the second quarter at an average floor price of Cdn $91.48 per barrel, and 8,000 GJ per day of natural gas in the first quarter at an average AECO floor price of $3.16 per GJ.
  
  
• Net loss in the fourth quarter was $2.3 million or $0.04 per basic share, a decrease from the net loss of $0.07 per basic share a year earlier. Net loss for the year was $6.6 million or $0.12 per basic share, a decrease from the prior year's net loss of $0.14 per basic share. The net loss was primarily due to a $1.3 million loss on the sale of investments, a write-down of investments of $2.6 million, and a $1.0 million loss on the disposition of oil and gas properties.
  
  
• Debt and working capital deficiency was $44.7 million at year end. Including the $4.3 million market value for Storm's investment in publicly listed companies at year end, adjusted net debt was $40.4 million or 2.0 times annualized fourth quarter funds from operations. Including previously announced asset dispositions for proceeds totaling $20.1 million which closed in the first quarter of 2013, pro-forma adjusted net debt decreases to $20.3 million which is 1.0 times annualized fourth quarter funds from operations. Storm's bank credit facility is $52.0 million after giving effect to asset sales in the first quarter of 2013.
  
  
• Total proved ("1P") reserves increased 270% to 13.8 Mmboe with additions being 10.9 Mmboe. On a per-share basis using basic shares outstanding at year end, the increase was 59%. Delineation drilling in the Montney at Umbach added 4.1 Mmboe (38% of additions), the Bellamont transaction added 4.8 Mmboe, and the acquisition of SGR added 2.6 Mmboe.
  
  
• Total proved plus probable ("2P") reserves grew 230% to 27.3 Mmboe with additions totaling 19.8 Mmboe. Growth on a per-share basis was 40% using basic shares outstanding at year end. Delineation drilling in the Montney at Umbach added 5.5 Mmboe (28% of additions), the Bellamont transaction added 8.0 Mmboe, and the acquisition of SGR added 6.7 Mmboe.
  
  
• The all-in cost to add 1P reserves was $21.85 per Boe and for 2P reserves was $16.26 per Boe. The all-in cost includes all capital expenditures, the change in future development costs, acquisitions, dispositions and revisions.
  
  
• The cost to add reserves per National Instrument 51-101 ("NI 51-101"), which excludes the effect of acquisitions, divestitures and revisions, was $14.20 per Boe for 1P reserves and $12.19 per Boe for 2P reserves. All reserves additions per NI 51-101 were at Umbach.
  
  
• Storm's asset value is $2.35 per share using the net present value of 2P reserves, discounted at 10% before tax, and after deducting adjusted net debt of $40.4 million at the end of 2012. This excludes any value for Storm's landholdings which totaled 310,000 net acres at year end.
  

OPERATIONS REVIEW

Storm has a focused asset base with large land positions in resource plays at Umbach and in the Horn River Basin ("HRB") which have multi-year drilling upside.

Umbach, Northeast British Columbia

Storm's land position at Umbach totals 99 net sections (126 gross sections) or 69,000 net acres. Two project areas have been identified with one area consisting of 63 gross sections of jointly owned lands (36 net sections with an average Storm working interest of 57%) and the other area containing 63 sections of land at a 100% working interest. Fourth quarter production averaged 564 Boe per day (29% NGL) with NGL recovery being 67 Bbls per Mmcf of natural gas sales. NGL included 50% condensate plus pentanes recovered during processing, 24% butane, and 26% propane. The fourth quarter operating netback was $17.70 per Boe with revenue of $31.28 per Boe, a royalty rate of 12%, and operating costs were $9.80 per Boe.

Repeated outages and capacity constraints with third party field compression resulted in production from Umbach being reduced by 300 Boe per day in the fourth quarter. For most of the quarter, one to three horizontals were shut in and run time on the remaining horizontals was intermittent.

On the jointly owned lands, nine horizontal wells have been drilled all at a 60% working interest with seven of those having been completed and tied in. Initial production and flow test results from the last three horizontal wells that were drilled lower into the Montney formation and completed with larger water based fracture treatments are encouraging although additional uninterrupted production history is required to confirm the level of improvement. As production declines and as field compression capacity becomes available, the remaining two horizontal wells will be completed and tied in which is likely to be in the third and fourth quarters. From January 1^st to February 25^th, production has averaged 425 Boe per day net from one to four horizontal wells with third party field compression having been shut in for 17 days to complete repairs and modifications. Production is currently approximately 750 Boe per day net from four horizontal wells. Total sustainable productive capability of all seven horizontal wells is estimated at 1,500 Boe per day net to Storm. Production from the joint lands is expected to be restricted to 600 to 1,000 Boe per day net for the next three to six months.

On the 100% working interest lands, one horizontal well has been drilled and has been completed with first production expected early in the second quarter once an eight kilometre pipeline connection to an existing field compression facility is completed. Storm has entered into an agreement to acquire ownership in this existing facility for $4.5 million with available capacity being approximately 20 Mmcf per day. Production from horizontal wells connected to this facility will be directed to the McMahon Gas Plant for processing which will reduce NGL recovery to 37 Bbls per Mmcf sales; however, the field netback will increase by $2 per Boe at current commodity prices because eliminating third party fees for field compression will reduce operating costs by more than $3 per Boe. In the second half of 2013, it is expected that three to four more horizontal wells will be drilled on the 100% working interest lands and will be pipeline connected to this facility.

The gross cost to drill and complete the last two horizontal wells (the sixth and seventh) averaged $4.8 million which is a significant improvement from the average cost of $5.5 million for the first five horizontal wells. Both were drilled from existing pads. As the focus transitions from resource delineation to development in 2013, horizontal well costs are expected to decline as wells are drilled from common pads and further drilling and completion efficiencies are realized.

On the first four horizontal wells, first year average rates have been approximately 290 Boe per day (1.5 Mmcf raw gas per day) with estimated 2P reserves of 540 Mboe (2.8 Bcf gross raw gas) assigned to the Upper Montney formation only. This has generated a rate of return below Storm's targeted threshold of 20% to 25%. Completion techniques on the most recent horizontal wells have been modified to access the Upper and Middle Montney intervals to improve the first year average rate which is expected to result in the rate of return improving to meet or exceed the minimum targeted level.

Grande Prairie Area, Northwest Alberta and Northeast British Columbia

Production in this area comes from properties acquired through the transaction with Bellamont which closed in the first quarter of 2012. Production in the fourth quarter averaged 1,884 Boe per day (46% oil plus NGL) at an operating netback of $25.40 per Boe. In early October, with natural gas prices at AECO recovering to $3.00 per GJ, shut-in natural gas wells were reactivated which added 455 Boe per day in the fourth quarter. The sale of the Mica property was completed on October 18^th with net proceeds at closing totaling $13.3 million (145 Boe per day). During the first quarter of 2013, the Rycroft property was sold January 18^th (30 Boe per day) and the Saddle Hills and Gold Creek properties were sold February 15^th (275 Boe per day) with proceeds from both transactions totaling $20.1 million. Current production after the recent dispositions is approximately 1,500 Boe per day (41% liquids).

There was minimal activity in the fourth quarter. A horizontal well drilled and completed in the Grande Prairie Dunvegan C light oil pool in the third quarter, was produced for a short period of time in November, and is now shut in as the production rate was below economic limits. The poor production rate was the result of problems casing the well which resulted in an open hole completion instead of the planned multi-stage fracture treatment. At Grimshaw, water injection commenced into a horizontal well in the Montney A pool in late August which has resulted in a flattening of the pool decline over the last four months. Significant progress was made on operating cost reductions in 2012 with realized savings totaling $2.5 million per year from electrifying well sites, purchasing surface equipment to eliminate processing fees, shutting in or disposing of uneconomic wells, returning rental equipment and eliminating water trucking and disposal. Wells that were shut in or disposed had total cash flow of $50,000 from April 2011 to March 2012.

Horn River Basin, Northeast British Columbia

Storm's undeveloped land position in the HRB totals 135 sections at a 100% working interest (87,700 net acres) and is prospective for natural gas from the Muskwa, Otter Park and Evie/Klua shales. The resource in the Muskwa and Otter Park shales is large with the best estimate of DPIIP in the 30 section core producing area being 3.1 Tcf gross raw gas (evaluated by InSite Petroleum Consultants Ltd. December 31, 2011). Productivity has been proven across the core producing area with one horizontal well that has been producing for 23 months plus two completed and tested vertical wells.

During the fourth quarter, production in the HRB averaged 367 Boe per day at an operating netback of $9.99 per Boe. All of Storm's production is from a horizontal well with 12 fracture stimulations that is currently producing 2.7 Mmcf per day gross raw gas with cumulative production of 2.8 Bcf gross raw gas since production commenced in March 2011. Field compression has not been installed so the flow rate since inception has been restricted by the high flowing pressure in the raw gas gathering pipeline (1,000 psig). 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.

INVESTMENTS

At the end of the fourth quarter, Storm owned 3 million shares in Chinook Energy Inc., a TSX-listed oil and gas exploration and production company (symbol 'CKE') based in Calgary with operations focused in Tunisia and western Canada. These shares had a value of $4.3 million at the end of 2012. During the fourth quarter of 2012, Storm sold its remaining shares in Bridge Energy ASA for proceeds totaling $1.8 million.

OUTLOOK

Results in 2012 were generally in line with guidance (year-end debt, operating costs, royalty rate, operations capital). Production in the fourth quarter of 2012 was below previous guidance (2,815 Boe per day versus previous guidance of 3,000 Boe per day) due to outages and capacity constraints with third party field compression at Umbach. Production in the first quarter of 2013 is expected to be 2,500 Boe per day and will increase to 3,000 Boe per day in the second quarter. This reflects the impact of the asset dispositions, continuing downtime with third party field compression at Umbach, and maintenance turnarounds at the Fort Nelson gas plant (HRB shut in for 28 days) and the Teepee gas plant (half of Grande Prairie area shut in for 15 days). Production growth is expected to resume in the second half of 2013 with additions at Umbach coming from expansion of the gathering system and as horizontal wells are drilled, completed and tied in on 100% working interest lands.

Preliminary 2013 guidance provided November 13, 2012 is being revised to reflect the recent asset dispositions that closed in the first quarter of 2013 (total proceeds $20.1 million) and an increase in activity levels at Umbach. Net of acquisitions and dispositions, total capital investment is expected to be $25 million. Updated guidance is provided below:

	2013 Guidance		2012 Actual
Year-end adjusted debt plus working capital deficiency (1)	$44.0 million		$40.4 million
Average operating costs	$10 - $11 per Boe		$11.48 per Boe
Average royalty rate (on production revenue before hedging)	11% - 12	%	11.1	%
Operations capital, excluding dispositions	$40.0 million		$26.9 million
Property dispositions(2)	$20.0 million		$15.7 million
Corporate or property acquisitions	$4.5 million		$154.9 million
Cash G&A	$3.9 million		$3.7 million
Exit or fourth quarter average production	4,000 - 4,500 Boe per day		2,815 Boe per day
	(25% oil + NGL	)	(36% oil + NGL	)

(1)	Includes value of publicly listed securities.
(2)	Dispositions closed in February 2013.

The 2013 capital investment program will be focused on developing the resource in the Montney formation at Umbach. Major expenditures will include:

• $20.0 million of proceeds from property dispositions;
• $4.5 million to acquire a working interest in an existing facility at Umbach;
• $10.0 million to drill five horizontal wells (4.6 net) at Umbach;
• $15.0 million to complete and tie in seven horizontal wells (5.8 net) at Umbach;
• $6.0 million for the purchase of undeveloped land;
• $5.0 million to expand the gathering pipeline system at Umbach.

With a 2013 natural gas price at AECO of $3 per GJ and an Edmonton Par oil price of $87 per barrel, this program will be funded with cash flow, the sale of non-core assets, and with bank debt. Adjusted net debt is forecast to be unchanged at $45 million at the end of 2013 (including public company investments) which is within Storm's current bank line of $52 million and approximately two times forecast 2013 funds from operations.

Over the last year, Storm has gained critical mass and cash flow through two corporate transactions. Activity in 2012 was focused on drilling horizontal wells at Umbach to continue delineating the large, liquids-rich natural gas resource in the Montney formation. To date, Storm has delineated approximately 40% of its land position at Umbach with reserves assigned to only the Upper Montney formation on 11% of the land base. Well control confirms that there is a significant inventory of undrilled horizontal wells in the Upper and Middle Montney intervals. As a result, in 2013, the focus will transition to developing the resource and growing production and cash flow. NGL recovery of 67 barrels per Mmcf sales through a shallow-cut gas plant greatly improves the netback and economics at current natural gas prices. Modifications to the completion technique are expected to improve first year average rates and result in a rate of return meeting or exceeding 20% to 25% at current commodity prices. If results at Umbach are supportive of doing so, development may be accelerated with funding being provided by additional asset sales.

Regarding the HRB property, the optionality of Storm's land position is confirmed by recent transactions involving major land positions either in the HRB or other large scale, gas-prone resource plays in British Columbia and Alberta. The HRB continues to offer significant leverage to improving natural gas prices and remains a long term, core asset for Storm.

I would like to thank Storm's employees for their effort and hard work in 2012 and our directors for their guidance and continued support. Our goal continues to be accretive growth in net asset value which will be achieved through development of the larger scale, liquids-rich resource in the Montney formation at Umbach. We look forward to providing updates on our progress throughout 2013.

Respectfully,

Brian Lavergne, President and Chief Executive Officer

February 28, 2013

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

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

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

Reserves at December 31, 2012

Storm's year-end reserve evaluation effective December 31, 2012 was prepared by InSite Petroleum Consultants Ltd. ("InSite") under date of February 15, 2013. InSite has evaluated all of Storm's crude oil, NGL and natural gas reserves. The InSite price forecast at December 31, 2012 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 developed producing reserves increased 273% to total 5,860 Mboe, an increase of 59% per share.
  
  
• Total proved ("1P") reserves grew 272% to total 13,822 Mboe. This is an increase of 59% on a per-share basis.
  
  
• Total proved plus probable ("2P") reserves totaled 27,331 Mboe which is an increase of 228%. The increase is 49% on a per-share basis.
  
  
• Additions to 2P reserves were 19,828 Mboe with 40% from the Bellamont transaction, 34% from the SGR acquisition, and 28% from delineation drilling of the Montney formation at Umbach.
  
  
• The net present value of 2P reserves, discounted at 10% before tax, increased 238% to $186 million with the majority of this being attributed to the Umbach property (39%).
  
  
• Storm's asset value is $2.35 per share using the net present value of 2P reserves, discounted at 10% before tax, and after deducting adjusted net debt of $40.4 million at the end of 2012. This excludes any value for Storm's landholdings which totaled 310,000 net acres at year end.
  
  
• The 1P finding and development cost as per NI 51-101 requirements was $14.20 per Boe and the 2P finding and development cost, as per NI 51-101 requirements, was $12.19 per Boe. This includes the change in FDC and excludes the effect of acquisitions, divestitures and revisions.
  
  
• The all-in cost to add 1P reserves was $21.85 per Boe and for 2P reserves was $16.26 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 (Bellamont and SGR), dispositions, revisions, as well as the change in future development costs.
  
  
• Recycle ratio was 1.4 for 2P reserve additions using the all-in cost of $16.26 per Boe and the 2012 field netback of $23.21 per Boe.
  
  
• Drilling activity in 2012 resulted in the addition of 4,067 Mboe on a 1P basis and 5,514 Mboe on a 2P basis with all additions being from the Montney formation at Umbach.
  
  
• The transaction with Bellamont added 4,784 Mboe 1P reserves and 7,972 Mboe 2P reserves. 2P FDC was $40.2 million net to Bellamont. The all-in cost to add 1P reserves was $22.40 per Boe and for 2P reserves was $17.55 per Boe.
  
  
• The acquisition of SGR added 2,577 Mboe 1P reserves and 6,737 Mboe 2P reserves with 2P FDC of $75.7 million net to SGR. The all-in cost to add 1P reserves was $34.71 per Boe and for 2P reserves was $19.42 per Boe. Cost to add reserves with the SGR acquisition is high as it does not reflect contingent resources with the best estimate being 393 Bcf sales net to SGR as evaluated by InSite effective December 31, 2011.
  
  
• FDC was $103 million on a 1P basis and $229 million on a 2P basis.
  
  
• At Umbach, 2P reserves were 8,679 Mboe (32% of total corporate) with 661 Mboe assigned to complete two standing horizontal wells (1.2 net) and to drill 19 horizontal wells (11.4 net). Recoverable reserves assigned to horizontal drilling locations averaged 2.9 Bcf of gross raw gas. Shrinkage of 15% was used along with NGL recovery of 61 barrels per Mmcf of sales. 2P FDC was $63.6 million net. Reserves were assigned to the Upper Montney formation only and no reserves were recognized on Storm's 100% working interest lands.
  
  
• In the HRB, 2P reserves were 11,128 Mboe (41% of total corporate) with 1,466 Mboe assigned to complete a standing horizontal shale gas well (1.0 net) and to drill six horizontal shale gas wells (6.0 net). Recoverable reserves assigned to each of the horizontal drilling locations averaged 10 Bcf of gross raw gas. Shrinkage of 12% was used to determine sales gas volumes. 2P FDC was $125.1 million gross and includes $12.1 million for associated infrastructure.
  
  
• Property dispositions in 2012 (Mica and Red Earth) reduced 1P reserves by 626 Mboe and 2P reserves by 735 Mboe.
  

Gross Company Interest Reserves as at December 31, 2012
(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	2,049	19,535	555	5,860
Proved non-producing	-	397	8	74
Total proved developed	2,049	19,932	563	5,934
Proved undeveloped	300	39,068	1,077	7,888
Total proved	2,349	59,000	1,640	13,822
Probable additional	1,265	66,600	1,144	13,509
Total proved plus probable	3,614	125,600	2,784	27,331

Gross Company Reserve Reconciliation for 2012
(Gross company interest reserves before deduction of royalties payable)
6:1 Oil Equivalent (Mboe)
	Total Proved		Probable		Proved plus Probable
December 31, 2011 - opening balance	3,714		4,608		8,322
Acquisitions	7,361		7,348		14,709
Discoveries	-		-		-
Extensions	4,067		1,447		5,514
Dispositions	(626	)	(109	)	(735	)
Technical revisions	126		216		342
Production	(819	)	-		(819	)
December 31, 2012 - closing balance	13,823		13,510		27,333

Future Development Costs
Proved
	HRB	3.0 net horizontals plus infrastructure	$ 55.5 million
	Umbach	8.4 net horizontals	$ 39.8 million
	Grande Prairie	3.0 net horizontals	$ 7.5 million
Total			$ 102.8 million
Proved Plus Probable Additional
	HRB	7.0 net horizontals plus infrastructure	$ 125.1 million
	Umbach	12.6 net horizontals	$ 63.6 million
	Grande Prairie	11.0 net horizontals	$ 40.2 million
Total			$ 229.0 million
		Proved Expenditures	Proved Plus Probable Additional Expenditures
2013		$ 29.3 million	$ 37.7 million
2014		$ 18.0 million	$ 33.2 million
2015		$ 18.6 million	$ 59.4 million
2016		$ 34.9 million	$ 43.0 million
2017		$ 2.1 million	$ 41.8 million
2018		$ -	$ 13.9 million

NI 51-101 Finding and Development Costs
Total Proved Finding and Development Cost	2012	2011	2010	3 Year Average
Capital expenditures excluding acquisitions and dispositions (000s)	$ 26,868	$ 25,360	$ 16,800	$ 69,028
Net change in FDC (000s)	30,863	25,541	4,679	61,083
Total capital including the net change in future capital (000s)	$ 57,731	$ 50,901	$ 21,479	$ 130,111
Reserve additions excluding acquisitions, dispositions and revisions (Mboe)	4,067	2,505	738	7,310
Total proved finding and development costs (per Boe)	$ 14.20	$ 20.32	$ 29.10	$ 17.80
Total Proved Plus Probable Finding and Development Cost	2012	2011	2010	3 Year Average
Capital expenditures excluding acquisitions and dispositions (000s)	$ 26,868	$ 25,360	$ 16,800	$ 69,028
Net change in FDC (000s)	40,341	51,725	21,057	113,123
Total capital including the net change in future capital (000s)	$ 67,209	$ 77,085	$ 37,857	$ 182,151
Reserve additions excluding acquisitions, dispositions and revisions (Mboe)	5,514	5,278	2,512	13,304
Total proved plus probable finding and development costs (per Boe)	$ 12.19	$ 14.60	$ 15.07	$ 13.69

All-In Finding, Development and Acquisition Costs
Total Proved All-In Finding, Development and Acquisition Cost including FDC, Acquisitions, Dispositions, Revisions	2012	2011	2010	3 Year Average
Capital expenditures including acquisitions and dispositions (000s)	$ 166,076	$ 40,795	$ 16,800	$ 223,671
Net change in FDC (000s)	72,655	25,541	4,679	102,875
Total capital including the net change in future capital (000s)	$ 238,731	$ 66,336	$ 21,479	$ 326,546
Reserve additions including acquisitions,dispositions and revisions (Mboe)	10,927	3,178	738	14,843
All-in total proved finding and development costs (per Boe)	$ 21.85	$ 20.87	$ 29.10	$ 22.00
Total Proved Plus Probable All-In Finding, Development and Acquisition Cost including FDC, Acquisitions, Dispositions, Revisions	2012	2011	2010	3 Year Average
Capital expenditures including acquisitions and dispositions (000s)	$ 166,076	$ 40,795	$ 16,800	$ 223,671
Net change in FDC (000s)	156,258	51,725	21,057	229,040
Total capital including the net change in future capital (000s)	$ 322,334	$ 92,520	$ 37,857	$ 452,711
Reserve additions including acquisitions,dispositions and revisions (Mboe)	19,828	6,012	2,512	28,352
All-In total proved plus probable finding and development costs (per Boe)	$ 16.26	$ 15.39	$ 15.07	$ 15.97

Net Present Value Summary (before tax) as at December 31, 2012

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	$ 164,695	$ 125,620	$ 101,403	$ 85,241	$ 73,808
Proved non-producing	416	382	353	328	306
Total proved developed	$ 165,111	$ 126,002	$ 101,756	$ 85,569	$ 74,114
Proved undeveloped	91,890	49,156	24,643	9,763	328
Total proved	$ 257,002	$ 175,159	$ 126,399	$ 95,333	$ 74,442
Probable additional	226,565	113,694	59,667	31,173	15,027
Total proved plus probable	$ 483,566	$ 788,852	$ 186,066	$ 126,506	$ 89,469

Numbers in this table may not add due to rounding.

Net Present Value Summary (after tax) as at December 31, 2012

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	$ 164,696	$ 125,620	$ 101,403	$ 85,241	$ 73,808
Proved non-producing	416	383	354	328	306
Total proved developed	$ 165,112	$ 126,003	$ 101,757	$ 85,569	$ 74,114
Proved undeveloped	89,076	48,030	24,169	9,555	232
Total proved	$ 254,188	$ 174,033	$ 125,926	$ 95,124	$ 74,347
Probable additional	170,535	85,623	44,517	22,510	9,841
Total proved plus probable	$ 424,723	$ 259,656	$ 170,442	$ 117,635	$ 84,188

Numbers in this table may not add due to rounding.

InSite Escalating Price Forecast as at December 31, 2012
	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)
2013	92.00	90.00	3.75	3.34	36.00	76.50
2014	94.00	91.96	4.25	3.83	45.98	78.17
2015	96.00	93.92	4.75	4.33	56.35	79.83
2016	98.00	95.88	5.20	4.77	57.53	81.50
2017	100.00	97.84	5.55	5.11	58.70	83.16

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

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

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

Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect the operations or financial results of the Company are included or are incorporated by reference in the company's MD&A for the three months and year ended December 31, 2012.

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