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, 2014

CALGARY, ALBERTA--(Marketwired - Feb. 26, 2015) - Storm Resources Ltd. (TSX VENTURE:SRX) -

Storm has also filed its audited consolidated financial statements as at December 31, 2014 and for the three months and year then ended along with 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, 2014, as well as reserves information at December 31, 2014, appears below and should be read in conjunction with the related financial statements and MD&A.

Highlights

Thousands of Cdn$, except volumetric and per-share amounts		Three Months Ended December 31, 2014	Three Months Ended December 31, 2013	Year Ended December 31, 2014	Year Ended December 31, 2013
FINANCIAL
Revenue from product sales		28,070	15,380	95,480	49,578
Funds from operations(1)		13,892	7,501	45,412	21,949
	Per share - basic ($)	0.13	0.09	0.42	0.30
	Per share - diluted ($)	0.12	0.09	0.41	0.30
Net income (loss)		(7,422)	(25,174)	4,855	(26,203)
	Per share - basic ($)	(0.07)	(0.34)	0.04	(0.36)
	Per share - diluted ($)	(0.07)	(0.34)	0.04	(0.36)
Operations capital expenditures		20,219	11,380	106,604	67,410
Land and property acquisitions/dispositions		(124)	-	87,951	(14,966)
Debt including working capital deficiency		63,080	12,059	63,080	12,059
Common shares (000s)
	Weighted average - basic	111,305	81,994	108,172	73,391
	Weighted average - diluted	112,850	81,994	109,981	73,391
	Outstanding end of period - basic	111,322	87,483	111,322	87,483
OPERATIONS
Revenue (Cdn$ per Boe)		29.99	35.02	37.48	37.34
Royalties (Cdn$ per Boe)		(3.69)	(2.65)	(5.16)	(4.55)
Production (Cdn$ per Boe)		(8.40)	(9.73)	(9.33)	(10.86)
Transportation (Cdn$ per Boe)		(1.91)	(1.82)	(1.80)	(1.50)
Field operating netback		15.99	20.82	21.19	20.43
Hedging gains (losses) (Cdn$ per Boe)		0.52	0.09	(1.26)	(0.03)
General and administrative (Cdn$ per Boe)		(1.16)	(3.25)	(1.50)	(2.98)
Interest (Cdn$ per Boe)		(0.50)	(0.58)	(0.60)	(0.90)
Funds from operations netback (Cdn$ per Boe)		14.85	17.10	17.83	16.52
Barrels of oil equivalent per day (6:1)		10,173	4,773	6,980	3,637
Gas Production
	Thousand cubic feet per day	49,094	21,898	33,067	15,843
	Price (Cdn$ per Mcf)	3.85	3.88	4.58	3.63
NGL production
	Barrels per day	1,605	695	1,064	512
	Price (Cdn$ per barrel)	56.15	70.10	69.90	0.29
Oil Production
	Barrels per day	385	428	405	485
	Price (Cdn$ per barrel)	68.01	78.47	88.10	87.16
Wells drilled
	Gross	2.0	1.0	17.0	9.0
	Net	2.0	1.0	17.0	8.6
(1) Funds from operations, funds from operations per share and funds from operations netback are non-GAAP measurements. See discussion of Non-GAAP Measurements on page 19 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 30 of the MD&A.

PRESIDENT'S MESSAGE

2014 FOURTH QUARTER AND YEAR-END HIGHLIGHTS

• In 2014, significant per-share growth in production and reserves was achieved and material improvements were realized in controllable cash costs and the cost of reserve additions.

• Production for the year averaged 6,980 Boe per day (21% oil plus NGL), a per-share increase of 51% from 2013 (notable given the 28% increase in shares outstanding). Fourth quarter production was 10,173 Boe per day (20% oil plus NGL), an increase of 69% on a per-share basis from the previous year. The increase was the result of growth at Umbach where fourth quarter production was 8,775 Boe per day, an increase of 169% from 3,262 Boe per day in the fourth quarter of 2013.

• NGL production was 1,605 barrels per day in the fourth quarter, year-over-year growth of 131%. The increase was the result of production growth from the liquids-rich Montney formation at Umbach where NGL recovery was 35 barrels per Mmcf sales in the fourth quarter. With approximately 60% of the NGL mix being condensate plus pentanes, the NGL price of $56.15 per barrel was 74% of the average Edmonton light oil price.

• Activity during 2014 was focused at Umbach, where 16 Montney horizontal wells (16.0 net) plus one Montney vertical delineation well (1.0 net) were drilled, 13 horizontal wells (12.6 net) were completed, 10 horizontal wells (9.6 net) began producing, and a 100% working interest field compression facility was started up in August. In the fourth quarter, two Montney horizontal wells (2.0 net) were drilled, four Montney horizontal wells (4.0 net) were completed and three Montney horizontal wells (3.0 net) began producing.

• For the 2014 Montney horizontal wells at Umbach, calendar day rates (including downtime) over the first 90 days averaged 4.8 Mmcf per day gross raw gas (865 Boe per day sales), an improvement of 37% from the average 2013 horizontal well.

• Both operated facilities at Umbach have been full since mid-September and there is currently an inventory of 11 horizontal wells (11.0 net) that have not started producing which includes four completed horizontal wells. In addition, two more horizontal wells (2.0 net) remain to be drilled in the first quarter. Storm will achieve 2015 production guidance with forecast production from these horizontal wells.

• Funds from operations for the year totaled $45.4 million, or $0.42 per share, an increase of 40% on a per-share basis from the previous year. Funds from operations in the fourth quarter was $13.9 million, or $0.13 per basic share, an increase of 44% from the prior year.

• The funds from operations netback for the year was $17.83 per Boe, a year-over-year increase of 8% which was primarily the result of a decline in operating costs and cash G&A totaling $3.01 per Boe that was partially offset by an increased hedging loss of $1.23 per Boe.

• Controllable cash costs (operating, transportation, cash G&A, interest expense) were $13.23 per Boe in 2014, a year-over-year decrease of 19%. Controllable cash costs showed further improvement to average $11.97 per Boe in the fourth quarter. Cash G&A was $1.50 per Boe in 2014, a year-over-year decrease of 50%. Operating costs for the year decreased by 14% to average $9.33 per Boe and further improved to $8.40 per Boe in the fourth quarter.

• Net income for the year was $4.9 million, or $0.04 per share, a significant improvement when compared to the loss of $26.2 million in the previous year. This included a $22.7 million reduction in the carrying amount of the Grande Prairie properties which was partially offset by a $14.2 million unrealized gain on commodity price hedges.

• Capital investment was focused on the Umbach area and totaled $194.5 million for the year which included $88.0 million to acquire a 100% working interest in 29 sections of land at Umbach, $34.3 million for infrastructure and $68.1 million for drilling and completions.

• Cost of adding production during 2014 was approximately $16,400 per Boe per day using 2014 operations capital investment of $106.6 million and average fourth quarter production of 6,520 Boe per day from wells that started production in 2014 (excludes 350 Boe per day acquired in January 2014).

• Operating income for the year, being net income adjusted for impairment charges and unrealized hedging gains, was $13.4 million, or $0.12 per share.

• The unrealized value of the commodity price contracts was $12.9 million at year end and, during the fourth quarter, a cash gain of $0.5 million was realized.

• Debt plus working capital deficiency was $63.1 million at year end which is 1.1 times annualized fourth quarter cash flow. In November 2014, Storm's bank credit line was increased to $130.0 million from $90.0 million.

2014 YEAR-END RESERVE EVALUATION HIGHLIGHTS

	Dec 31, 2014	Dec 31, 2013	Change
Reserves
Proved Producing (Mboe)	13,487	7,579	+78%
Total Proved (Mboe)	59,551	20,764	+187%
Total proved plus Probable (Mboe)	88,024	40,541	+117%
Reserves per share
Proved Producing (Mboe per million shares)	121	87	+39%
Total Proved (Mboe per million shares)	535	237	+125%
Total proved plus Probable (Mboe per million shares)	791	463	+71%
Finding and Development ("F&D") Cost including the change in future development capital and excluding revisions, acquisitions, dispositions
Proved Producing ($/Boe)	$13.73	$19.53	-30%
Total Proved ($/Boe)	$10.20	$13.98	-27%
Total proved plus Probable ($/Boe)	$8.76	$10.75	-18%
All-in Finding, Development, and Acquisition ("FD&A") Cost including the change in future development capital
Proved Producing ($/Boe)	$23.01	$17.22	+34%
Total Proved ($/Boe)	$11.68	$13.19	-11%
Total proved plus Probable ($/Boe)	$9.64	$9.79	-1%
Recycle Ratio using F&D
Annual field operating netback excluding hedging	$21.19	$20.43
Proved Producing	1.5 X	1.0 X
Total Proved recycle	2.1 X	1.5 X
Total Proved plus Probable recycle	2.4 X	1.9 X
Recycle Ratio using all-in FD&A
Annual field operating netback excluding hedging	$21.19	$20.43
Proved Producing	0.9 X	1.2 X
Total Proved recycle	1.8 X	1.6 X
Total Proved plus Probable recycle	2.2 X	2.1 X
Reserve Life Index using fourth quarter production
Total Proved	16.1 years	11.9 years
Total Proved plus Probable	23.7 years	23.3 years
Net Present Value Discounted at 10% (before tax)
Proved Producing ($M)	$199,000	$122,000	+63%
Total Proved ($M)	$493,000	$184,000	+168%
Total proved plus Probable ($M)	$684,000	$298,000	+130%

• Reserve additions replaced 332% of 2014 production on a proved producing basis, 1,522% on a total proved basis, and 1,863% on a total proved plus probable basis.

• The all-in 2P 2014 FD&A cost of $9.64 was impacted by an acquisition in the Umbach area in January 2014 for a total cost of $88.0 million with $78.2 million allocated to acquiring undeveloped land and the remainder to acquiring production and reserves. The 2P F&D cost of $8.76 per NI 51-101 guidelines more realistically reflects the cost of developing the Montney at Umbach in 2014 as this excludes the effect of acquisitions, dispositions and revisions.

• At Umbach, the area where total proved plus probable reserves were assigned grew to 18% of Storm's 141 net sections from 8% last year and this included 73.4 net horizontal drilling locations which represents approximately five years of activity.

• Storm's enterprise value at the end of 2014 was $523.9 million which is equal to $16.32 per Boe on a 1P basis including future development costs ("FDC") and $12.85 per Boe on a 2P basis including FDC (using 111.3 million shares outstanding, the December 31 closing share price of $4.14 and year-end debt of $63.1 million).

• Storm's asset value using shares outstanding at year end grew to $5.58 per share from $3.25 per share last year and this excludes any amount for undeveloped land. Asset value was determined by deducting net debt at year end from the before tax net present value for proved plus probable reserves discounted at 10%.

OPERATIONS REVIEW

Storm has a focused asset base with large land positions in resource plays at Umbach and in the Horn River Basin ("HRB") each of which have multi-year drilling upside while the Grande Prairie area, with its shallow decline, provides cash flow available for investment.

Umbach, Northeast British Columbia

Storm's land position at Umbach is prospective for liquids-rich natural gas from the Montney formation and currently totals 141 net sections (167 gross sections), or 100,000 net acres. To date, a total of 30.4 net horizontal wells (34.0 gross) have been drilled into the Montney formation with 20.4 net being on production.

Fourth quarter production from Umbach was 8,775 Boe per day with NGL production of 1,540 barrels per day representing a recovery of 35 barrels per Mmcf sales (approximately 60% higher priced condensate plus pentanes). Revenue from Umbach was $29.08 per Boe ($3.88 per Mcf sales and $56.33 per barrel of NGL), transportation costs were $1.81 per Boe, royalties were $3.86 per Boe, or 13% of revenue, operating costs were $7.90 per Boe and the operating netback was $15.51 per Boe.

Activity in the fourth quarter included drilling two Montney horizontal wells (2.0 net) and completing four Montney horizontal wells (4.0 net) with three horizontal wells (3.0 net) starting production. In 2014, 16 Montney horizontal wells (16.0 net) were drilled and 13 horizontal wells (12.6 net) were completed which includes two wells (1.6 net) drilled in 2012 and 2013. Ten (9.6 net) of the completed horizontal wells started producing in 2014. There remains an inventory of 11 horizontal wells (11.0 net) that have not started producing which includes four completed horizontal wells and seven standing horizontal wells awaiting completion. In addition, two horizontal wells (2.0 net) remain to be drilled during the first quarter of 2015.

Storm operates two field compression facilities (both 100% working interest) that have total capacity of 45 Mmcf per day raw gas with the gas from both directed to the McMahon Gas Plant for processing. The first field compression facility with capacity of 18 Mmcf per day raw gas had average throughput of 17 Mmcf per day raw gas in the fourth quarter, with NGL recovery of 30 barrels per Mmcf sales. The second field compression facility with 27 Mmcf per day of capacity was started up in August 2014 and throughput in the fourth quarter averaged 24 Mmcf per day of gross raw gas with NGL recovery of 34 barrels per Mmcf of sales. Final cost of the second facility was $15.3 million (9% higher than initial guidance). Capacity of the second facility is being increased to 55 Mmcf per day raw gas in late March 2015 with the estimated cost being $13.5 million ($3.9 million to purchase equipment in 2014 and the remaining $9.6 million in the first quarter of 2015). In the second quarter of 2015, a condensate stabilizer and other equipment will be installed at the second facility with the estimated cost being $5.1 million.

During the first quarter of 2015, a 15-kilometre pipeline will be constructed to connect the first field compression facility to the Stoddart Gas Plant. The estimated gross cost is $4.8 million with Storm's working interest being 60%. This will increase NGL recovery from 30 to 55 barrels per Mmcf for production from the first field compression facility which has capacity of 18 Mmcf per day raw gas.

Construction of a third field compression facility (announced on November 13, 2014) is being deferred given the recent decline in NGL and natural gas prices. Engineering design has been completed and $5.0 million will be invested to purchase major equipment in 2015, which will shorten the construction period to six months once a decision is made to go ahead (likely in 2016). Total cost of the third facility is estimated to be $24.0 million for 35 Mmcf per day raw gas capacity and it will be expandable to 70 Mmcf per day for an additional investment of $7.0 million.

Comparing calendar day rates (includes downtime) over the first 180 days, the five 2014 Montney horizontal wells with enough history are 72% better than the average 2013 horizontal well. Following is a comparison of calendar day rates for all of the producing Montney horizontal wells.

	Frac Stages	IP 90 Cal Day Gross Raw Mmcf Per Day	IP 180 Cal Day Gross Raw Mmcf Per Day	IP 365 Cal Day Gross Raw Mmcf Per Day
2011 hz's (4 wells)	7 - 11	2.0 Mmcf/d 360 Boe/d sales 4 hz's	1.5 Mmcf/d 270 Boe/d sales 4 hz's	1.3 Mmcf/d 235 Boe/d sales 4 hz's
2012 hz's (3 wells)	14	1.6 Mmcf/d 290 Boe/d sales 3 hz's	1.3 Mmcf/d 235 Boe/d sales 3 hz's	1.5 Mmcf/d 270 Boe/d sales 3 hz's
2013 hz's (6 wells)	16 - 18	3.5 Mmcf/d 630 Boe/d sales 6 hz's	2.9 Mmcf/d 525 Boe/d sales 6 hz's	2.2 Mmcf/d 400 Boe/d sales 6 hz's
2014 hz's (7 wells)	16 - 20	4.8 Mmcf/d 865 Boe/d sales 10 hz's	5.0 Mmcf/d 900 Boe/d sales 5 hz's	4.3 Mmcf/d 780 Boe/d sales 1 hz
Sales volume is calculated using 8% shrinkage from raw gas to sales and 30 barrels of NGL per Mmcf sales.

Based on the performance of the 2014 horizontal wells and given that the majority of horizontal wells that will be completed in 2015 are 20% longer with more frac stages (20 to 24), Storm management is now using a 6.3 Bcf raw gas type curve for internal budgeting purposes (this type curve has same decline profile as the 3.2 and 4.4 Bcf raw gas 2P type curves used by InSite in the 2014 reserve evaluation). Previously, a 5.0 Bcf raw type curve was used which was based on the performance of the 2013 and 2014 horizontal wells. With a 6.3 Bcf raw gas type curve, the first year average rate is 3.6 Mmcf per day gross raw gas or 650 Boe per day sales (8% shrinkage from raw gas to sales and 30 barrels of NGL per Mmcf sales). Based on a cost of $5.4 million to drill, complete and tie in a horizontal well with 20 to 24 frac stages, the payout is approximately 23 months and the rate of return is 35% assuming flat pricing of $3.00 per GJ at AECO and Cdn $66.00 per barrel for Edmonton light oil (see presentation on website for further details). In 2014, the cost to drill a horizontal well averaged $2.1 million with the completion cost averaging $2.5 million for 16 to 20 frac stages. Drilling times have averaged approximately 14 days. Tie-in costs have averaged $0.3 million per horizontal well which doesn't include the cost of longer gathering pipelines to connect multi-well pads to field compression facilities. With the 2015 horizontal wells having an increased number of frac stages (20 to 24), the cost to drill, complete, and tie in a horizontal well was also increased to $5.4 million. These results do not recognize any improvement in service costs in 2015.

Horn River Basin, Northeast British Columbia

Storm has a 100% working interest in 123 sections in the HRB (81,000 net acres) which are prospective for natural gas from the Muskwa, Otter Park and Evie/Klua shales. Fourth quarter production averaged 307 Boe per day (100% natural gas), a year-over-year decline of 15%. The operating netback was $5.91 per Boe with revenue of $18.41 per Boe, transportation costs of $0.66 per Boe, an operating cost of $9.95 per Boe and a royalty of $1.89 per Boe, or 10% of revenue.

Grande Prairie Area, Northwest Alberta and Northeast British Columbia

Production in the fourth quarter was 1,091 Boe per day (41% oil plus NGL), a year-over-year decline of 5%. The operating netback was $19.96 per Boe with revenue of $41.35 per Boe, a transportation cost of $3.14 per Boe, an operating cost of $12.04 per Boe and a royalty of $6.20 per Boe, or 15% of revenue. Cash flow from this area continues to be re-invested to grow production at Umbach.

In mid-January 2015, approximately 150 Boe per day was shut in as a result of the recent decline in the natural gas price.

HEDGING UPDATE

For 2015, commodity price hedges include both fixed price swaps and collars with:

• 22,500 Mcf per day (27,900 GJ per day) of natural gas from January to December at an average floor price of approximately $4.28 per Mcf and an average ceiling price of $4.54 per Mcf (AECO monthly index $3.45 per GJ for floor and $3.66 per GJ for ceiling);

• 533 barrels per day of oil from January to September at a price of WTI Cdn$98.43 per barrel. This hedge was sold in January 2015 for net proceeds of $5.1 million.

At the end of 2014, the unrealized gain on the 2015 commodity prices hedges was $12.9 million.

The purpose of Storm's commodity price hedges is to reduce the effect of commodity price fluctuations on capital investment and growth over the next 12 months. A maximum of 50% of current production (most recent monthly or quarterly average), before royalties, will be hedged; anticipated production growth is not hedged.

COMPARISON OF 2014 RESULTS VERSUS GUIDANCE

Shown below is a comparison of Storm's actual 2014 results to guidance provided during 2014.

2014 Guidance	January 23, 2014 Original Guidance	May 14, 2014 Revised Guidance	November 13, 2014 Revised Guidance	Actual 2014 Results
AECO natural gas price	$3.35 per GJ	$4.25 per GJ	$4.30 per GJ	$4.27 per GJ
Edmonton light oil price	Cdn $89 per Bbl	Cdn $94 per Bbl	Cdn $97 per Bbl	Cdn $95 per Bbl
Average operating costs	$8.00 - $9.00 per Boe	$8.00 - $9.00 per Boe	$9.00 - $9.50 per Boe	$9.33 per Boe
Average royalty rate (% of revenue before hedging)	14% - 15%	15% - 16%	15%	13.7%
Operations capital (excluding acquisitions & dispositions)	$78.0 million	$97.0 million	$105.0 million	$106.7 million
Land & property acquisitions	$88.0 million	$88.0 million	$88.0 million	$88.0 million
Cash G&A	$4.0 million	$4.0 million	$3.8 million	$3.8 million
Forecast fourth quarter production	7,500 - 7,900 Boe/d (20% oil + NGL)	8,900 - 9,200 Boe/d (20% oil + NGL)	10,500 Boe/d (20% oil + NGL)	10,173 Boe/d(1) (20% oil + NGL)
Forecast annual production	5,500 - 6,500 Boe/d (21% oil + NGL)	6,000 - 6,700 Boe/d (21% oil + NGL)	7,000 Boe/d (21% oil + NGL)	6,980 Boe/d (21% oil + NGL)
Umbach horizontal wells drilled	10 gross (10.0 net)	14 gross (14.0 net)	16 gross (16.0 net)	16 gross (16.0 net)
Umbach horizontal wells completed	9 gross (9.0 net)	13 gross (12.6 net)	13 gross (12.6 net)	13 gross (12.6 net)
(1) Forecast production for the fourth quarter was impacted by an unplanned outage at the McMahon Gas Plant which resulted in the loss of 2,500 Boe per day for seven days in November.

OUTLOOK

Production in January 2015 averaged 10,060 Boe per day based on field estimates and production in the first quarter of 2015 is forecast to be 9,500 to 10,000 Boe per day which includes three to five days of downtime at Umbach for piping connections associated with the expansion of the second field compression facility. Capital investment in the first quarter is expected to total $35.0 to $38.0 million which includes drilling six Montney horizontal wells (6.0 net), completing two horizontal wells (2.0 net), constructing a 15-kilometer pipeline connection to the Stoddart Gas Plant and expanding the second field compression facility at Umbach. At Umbach, the existing field compression facilities are full and there is currently an inventory of 11 horizontal wells (11.0 net) that will start production after the second field compression facility is expanded from 27 to 55 Mmcf per day raw gas in late March.

Guidance for 2015 is being revised from original guidance provided November 13, 2014. Due to the recent decline in oil and natural gas prices, operations capital expenditures will be reduced to $80.0 million from $110.0 million. The effect on production guidance is expected to be minimal because Umbach horizontal well performance has been higher than that used in the production forecast. In addition, throughput at the second Umbach field compression facility has been 27 Mmcf per day raw gas which has exceeded the design capacity of 24 Mmcf per day and the expansion in March is now expected to increase capacity to 55 Mmcf per day raw gas versus previous expectations of 48 Mmcf per day.

2015 Guidance	November 13, 2014 Original Guidance	February 26, 2015 Revised Guidance
AECO natural gas price	$3.25 per GJ	$2.35 - $2.90 per GJ
BC STN 2 natural gas price	$3.00 per GJ	$2.05 - $2.60 per GJ
Edmonton light oil price	Cdn$83 per Bbl	Cdn$53 - $62 per Bbl
Estimated average operating costs	$7.50 - $8.00 per Boe	$8.00 - $8.50 per Boe
Estimated average royalty rate (on production revenue before hedging)	12% - 14%	6% - 10%
Estimated operations capital (excluding acquisitions & dispositions)	$110.0 million	$80.0 million
Estimated land & property acquisitions	$0.0 million	$0.0 million
Estimated cash G&A net of recoveries	$5.3 million	$5.3 million
Forecast fourth quarter production	14,000 - 14,500 Boe/d (18% oil + NGL)	14,000 - 14,500 Boe/d (19% oil + NGL)
Forecast annual production	11,500 - 12,700 Boe/d (19% oil + NGL)	11,000 - 12,000 Boe/d (20% oil + NGL)
Umbach horizontal wells drilled	9 gross (9.0 net)	6 gross (6.0 net)
Umbach horizontal wells completed	14 gross (14.0 net)	11 gross (11.0 net)
Umbach horizontal wells starting production	16 gross (16.0 net)	14 gross (14.0 net)

Capital investment for 2015 includes:

• $47.8 million at Umbach for drilling and completions;
• $18.4 million to expand infrastructure at Umbach, including expansion of the second field compression facility from 27 Mmcf per day to 55 Mmcf per day in late March; and
• $5.0 million to order major equipment for a third field compression facility at Umbach which will shorten the construction period to six months once a decision is made to build it.

This level of investment is forecast to increase production in the fourth quarter of 2015 to 14,000 to 14,500 Boe per day which represents 40% growth per share on a year-over-year basis.

Average production in 2015 is forecast to be 11,000 to 12,000 Boe per day with the mid-point representing an increase of 67% from average production in 2014. This includes approximately 60% of Umbach production being shut in for 35 days from June 6 to July 11 for a scheduled maintenance turnaround at the McMahon Gas Plant.

Total debt at the end of 2015 is forecast to be $85.0 to $96.0 million which would be approximately 1.2 to 1.9 times annualized funds from operations in the fourth quarter of 2015 (assuming commodity prices in 2015 average AECO $2.35 to 2.90 per GJ and Edmonton light oil Cdn$53.00 to $62.00 per barrel). The year-over-year increase in debt is forecast to be 30% to 50% which is consistent with year-over-year production growth. Debt is primarily funding infrastructure expansion at Umbach in 2015 which is an investment in a long-life asset.

Storm is still in the early stages of delineating a large, higher quality, liquids-rich resource in the Montney formation at Umbach. At the end of 2014, proved plus probable reserves were assigned on only 18% of Storm's land position (25.5 net sections of 141 net sections) leaving room for significant future reserve growth from drilling horizontal wells to test the remaining lands which appear to be highly prospective given horizontal well results on offsetting acreage. In addition, continuing to optimize horizontal well length, spacing between horizontal wells, number of frac stages and completion techniques is also likely to increase reserve bookings per horizontal well and will reduce the cost of reserve additions.

Although the recent decline in commodity prices is going to make 2015 much more challenging, Storm's commodity price hedges will mitigate the impact. In addition, the liquids-rich natural gas in the Montney at Umbach provides Storm with a competitive advantage from increased revenue through NGL recovery while the relatively shallow depth (1,400 to 1,600 metres) results in a lower drilling and completion cost. With an evolving long term plan in place to continue expanding infrastructure, plus a large inventory of horizontal drilling locations that provide reasonable rates of return at relatively low commodity prices, high levels of growth are expected to continue for the next three to five years.

Storm's land position in the HRB continues to be a core, long-term asset with significant leverage to higher natural gas prices.

In closing, I would like to thank Storm's employees for their efforts and Storm's Directors for their valuable advice and guidance in 2014 which resulted in record levels of production plus significant growth in reserves and asset value.

Respectfully,

Brian Lavergne, President and Chief Executive Officer

February 26, 2015

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, 2014

Storm's year-end reserve evaluation effective December 31, 2014 was prepared by InSite Petroleum Consultants Ltd. ("InSite") under date of February 18, 2015. InSite has evaluated all of Storm's crude oil, NGL and natural gas reserves. The InSite price forecast at December 31, 2014 was used to determine all estimates of future net revenue (also referred to as net present value or NPV). Storm's Reserves Committee which is made up 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.

Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without including any royalty interests) unless noted otherwise. All reserves information has been prepared in accordance with National Instrument ("NI") 51-101. In addition to the information disclosed in this report, more detailed information will be included in Storm's Annual Information Form.

Summary

• Proved developed producing ("PDP") reserves increased 78% to total 13,487 Mboe with additions replacing 332% of 2014 production.

• Total proved ("1P") reserves increased 187% to total 59,551 Mboe with additions replacing 1,522% of 2014 production.

• Total proved plus probable ("2P") reserves increased 117% to total 88,024 Mboe with additions replacing 1,863% of 2014 production.

• Total proved reserves were 68% of total proved plus probable reserves, a significant improvement from 51% in 2013.

• The finding and development ("F&D") cost for reserve additions per NI 51-101 requirements (removing effect of acquisitions, dispositions and revisions) was $13.73 per Boe for PDP, $10.20 per Boe for 1P and $8.76 per Boe for 2P.

• The all-in finding, development, and acquisition ("FD&A") cost⁽¹⁾ to add reserves was $23.01 per Boe for PDP, $11.68 per Boe for 1P and was $9.64 per Boe for 2P.

• Reserve life index using average production in the fourth quarter of 2014 was 3.6 years for PDP reserves, 16.1 years for 1P reserves and 23.3 years for 2P reserves.

• Recycle ratio using the F&D cost was 2.1 for 1P reserve additions and 2.4 for 2P reserve additions using the 2014 field operating netback of $21.19 per Boe excluding hedging gains or losses.

• Recycle ratio using the FD&A cost was 1.8 for 1P reserve additions and 2.2 for 2P reserve additions using the 2014 field operating netback of $21.19 per Boe excluding hedging gains or losses.

• Technical revisions increased PDP reserves by 130 Mboe, 1P reserves by 2,068 Mboe and 2P reserves by 4,352 Mboe.

• Breaking down 2P reserves by area, 86% is at Umbach, 9% at the Horn River Basin ("HRB") and 5% is at Grande Prairie.

• Future development costs ("FDC") were $447.7 million on a 1P basis and $606.6 million on a 2P basis which represents approximately five years of activity in the evaluation.

• At Umbach, there are 30.4 net producing and non-producing horizontal wells with 21,749 Mboe of 2P reserves plus 73.4 net future horizontal drilling locations with 53,519 Mboe of 2P reserves. Associated 2P FDC was $484.0 million net.

• At Umbach, 53 net 2P horizontal drilling locations were assigned an average of 4.4 Bcf gross raw gas on the 100% working interest lands, an increase of 26% from 3.5 Bcf gross raw gas assigned in 2013. On the 60% working interest lands, 20.4 net 2P horizontal drilling locations were assigned an average of 3.2 Bcf gross raw gas, an increase of 7% from 3.0 Bcf gross raw gas assigned in 2013.

• At Umbach, 2P reserves were recognized in the upper Montney only on 18% or 25.5 net sections of Storm's 141 net sections in the area with DPIIP averaging 43 Bcf gross raw gas per section in the upper Montney (total net DPIIP 1.1 Tcf on 25.5 net sections). Forecast recovery of DPIIP totals 40% for 2P reserves.

• The forecast decline in 2015 is 35% for wells on production at December 31, 2014 (decline from January 2015 to December 2015).

1. The all-in calculation reflects the result of Storm's entire capital investment program as it takes into account the effect of acquisitions, dispositions and revisions, as well as the change in FDC.

INFORMATION REGARDING DISCLOSURE ON OIL AND GAS RESERVES AND RESOURCES

All amounts are stated in Canadian dollars unless otherwise specified. Where applicable, natural gas has been converted to barrels of oil equivalent ("Boe") based on 6 Mcf:1 Boe. The Boe rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not recognize a value equivalent at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value. Production volumes and revenues are reported on a company gross basis, before deduction of Crown and other royalties, unless otherwise stated. Unless otherwise specified, all reserves volumes are based on "company gross reserves" using forecast prices and costs. The oil and gas reserves statement for the year ended December 31, 2014, which will include complete disclosure of oil and gas reserves and other information in accordance with NI 51-101, will be contained within the Annual Information Form which will be available on SEDAR.

References to estimates of oil and gas classified as DPIIP are not, and should not be confused with, oil and gas reserves.

Gross Company Interest Reserves as at December 31, 2014
(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	940	62,696	2,098	13,487
Proved non-producing	-	10,676	373	2,153
Total proved developed	940	73,372	2,471	15,640
Proved undeveloped	300	222,301	6,560	43,911
Total proved	1,240	295,673	9,032	59,551
Probable additional	846	144,778	3,498	28,473
Total proved plus probable	2,086	440,452	12,530	88,024
Numbers in this table may not add due to rounding.

Gross Company Reserve Reconciliation for 2014
(Gross company interest reserves before deduction of royalties payable)

	6:1 Oil Equivalent (Mboe)
	Proved Developed Producing	Total Proved	Probable	Proved plus Probable
December 31, 2013 - opening balance	7,579	20,764	19,777	40,541
Acquisitions	558	558	119	677
Discoveries	-	-	-	-
Extensions	7,766	38,707	6,295	45,002
Dispositions	-	-	-	-
Technical revisions - Umbach	292	2,284	2,514	4,798
Technical revisions - other properties	(162)	(216)	(230)	(446)
Economic factors	-	-	-	-
Production	(2,547)	(2,547)	-	(2,547)
December 31, 2014 - closing balance	13,487	59,551	28,473	88,024
Numbers in this table may not add due to rounding.

Future Development Costs ("FDC")

Proved
HRB	Drill 2.0 net horizontals plus infrastructure	$ 35.5 million
Umbach	Drill 59.0 net horizontals plus infrastructure	$ 404.5 million
Grande Prairie	Drill 3.0 net horizontals at Grimshaw	$ 7.7 million
Total		$ 447.7 million
Proved Plus Probable Additional
HRB	Drill 5.0 net horizontals plus infrastructure	$ 85.5 million
Umbach	Drill 73.4 net horizontals plus infrastructure	$ 483.7 million
Grande Prairie	Drill 5.0 net horizontals at Grimshaw; 5.0 net horizontals at GP Montney; and 1.0 net horizontal at GP Dunvegan	$ 37.4 million
Total		$ 606.6 million
	Proved Expenditures	Proved Plus Probable Additional Expenditures
2015	57,250	63,250
2016	75,154	89,678
2017	122,819	152,793
2018	129,637	153,461
2019	62,857	141,907
2020	-	5,465
Total FDC - undiscounted	447,717	606,555
Total FDC - discounted at 10%	356,196	470,717
Note: InSite escalates capital costs at 2% per year after 2015.
Numbers in this table may not add due to rounding.

NI 51-101 Finding and Development Costs ("F&D")
(excluding acquisitions, dispositions, revisions)

Proved Developed Producing F&D Cost	2014	2013	2012	3 Year Total
Capital expenditures excluding acquisitions and dispositions (000s)	$ 106,604	$ 67,450	$ 26,868	$ 200,922
Net change in FDC (000s)	-	-	-	-
Total capital	$ 106,604	$ 67,450	$ 26,868	$ 200,922
Reserve additions excluding acquisitions, dispositions, and revisions (Mboe)	7,766	3,464	840	12,070
Proved developed producing F&D cost	$ 13.73	$ 19.47	$ 31.99	$ 16.64
Total Proved F&D Cost	2014	2013	2012	3 Year Total
Capital expenditures excluding acquisitions and dispositions (000s)	$ 106,604	$ 67,450	$ 26,868	$ 200,922
Net change in FDC (000s)	288,242	77,282	30,863	396,387
Total capital including the net change in future capital (000s)	$ 394,846	$ 144,732	$ 57,731	$ 597,309
Reserve additions excluding acquisitions, dispositions, and revisions (Mboe)	38,707	10,356	4,067	53,130
Total proved F&D cost (per Boe)	$ 10.20	$ 13.98	$ 14.20	$ 11.24
Total Proved Plus Probable F&D Cost	2014	2013	2012	3 Year Total
Capital expenditures excluding acquisitions and dispositions (000s)	$ 106,604	$ 67,450	$ 26,868	$ 200,922
Net change in FDC (000s)	287,686	134,903	40,341	462,930
Total capital including the net change in future capital (000s)	$ 394,290	$ 202,353	$ 67,209	$ 663,852
Reserve additions excluding acquisitions, dispositions, and revisions (Mboe)	45,001	18,823	5,514	69,338
Total proved plus probable F&D cost	$ 8.76	$ 10.75	$ 12.19	$ 9.57
Operating netback per Boe excluding hedging	$ 21.19	$ 20.43	$ 21.22	$ 20.97
Recycle ratio for proved plus probable F&D cost using operating netback (excluding hedging)	2.4	1.9	1.7	2.2

All-In Finding, Development and Acquisition Costs ("FD&A")
(including acquisitions, dispositions and revisions)

Proved Developed Producing FD&A Cost	2014	2013	2012	3 Year Total
Capital expenditures including acquisitions and dispositions (000s)	$ 194,555	$ 52,444	$ 166,076	$ 413,075
Net change in FDC (000s)	-	-	-	-
Total capital	$ 194,555	$ 52,444	$ 166,076	$ 413,075
Total reserve additions (Mboe)	8,456	3,047	5,117	16,620
All-in proved developed producing F&D cost	$ 23.01	$ 17.21	$ 32.46	$ 24.85
Total Proved FD&A Cost	2014	2013	2012	3 Year Total
Capital expenditures including acquisitions and dispositions (000s)	$ 194,555	$ 52,444	$ 166,076	$ 413,075
Net change in FDC (000s)	288,242	56,600	72,655	417,497
Total capital including the net change in future capital (000s)	$ 482,797	$ 109,044	$ 238,731	$ 830,572
Total reserve additions (Mboe)	41,334	8,270	10,927	60,531
All-in total proved F&D cost (per Boe)	$ 11.68	$ 13.19	$ 21.85	$ 13.72
Total Proved Plus Probable FD&A Cost	2014	2013	2012	3 Year Total
Capital expenditures including acquisitions and dispositions (000s)	$ 194,555	$ 52,444	$ 166,076	$ 413,075
Net change in FDC (000s)	287,686	89,829	156,258	533,773
Total capital including the net change in future capital (000s)	$ 482,241	$ 142,273	$ 322,334	$ 946,848
Total reserve additions (Mboe)	50,030	14,538	19,828	84,396
All-In total proved plus probable F&D cost (per Boe)	$ 9.64	$ 9.79	$ 16.26	$ 11.22
Operating netback per Boe excluding hedging	$ 21.19	$ 20.43	$ 21.22	$ 20.97
Recycle ratio for proved plus probable FD&A cost using operating netback (excluding hedging)	2.2	2.1	1.3	1.9

Net Present Value Summary (before tax) as at December 31, 2014

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	$ 301,021	$ 239,533	$ 199,069	$ 170,841	$ 150,201
Proved non-producing	48,474	38,290	31,796	27,351	24,134
Total proved developed	$ 349,495	$ 277,823	$ 230,865	$ 198,192	$ 174,335
Proved undeveloped	694,842	421,652	262,392	163,942	100,157
Total proved	$ 1,044,338	$ 699,476	$ 493,257	$ 362,133	$ 274,492
Probable additional	629,545	332,499	190,573	115,724	73,005
Total proved plus probable	$ 1,673,883	$ 1,031,974	$ 683,829	$ 477,858	$ 347,497
Numbers in this table may not add due to rounding.

Net Present Value Summary (after tax) as at December 31, 2014

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	$ 301,021	$ 239,533	$ 199,069	$ 170,841	$ 150,201
Proved non-producing	48,474	38,290	31,796	27,351	24,134
Total proved developed	$ 349,495	$ 277,823	$ 230,865	$ 198,192	$ 174,335
Proved undeveloped	531,153	318,100	193,246	115,727	65,343
Total proved	$ 880,649	$ 595,923	$ 424,111	$ 313,919	$ 239,677
Probable additional	473,166	246,451	138,292	81,451	49,208
Total proved plus probable	$ 1,353,814	$ 842,374	$ 562,403	$ 395,370	$ 288,885
Numbers in this table may not add due to rounding.

InSite Escalating Price Forecast as at December 31, 2014

	WTI Crude Oil (US$/Bbl)	Edmonton Par Crude Oil (Cdn$/Bbl)	Henry Hub Natural Gas (US$/Mmbtu)	AECO Natural Gas (Cdn$/Mmbtu)	Propane (Cdn$/Bbl)	Butane (Cdn$/Bbl)
2015	65.00	68.58	3.50	3.58	34.29	48.01
2016	75.00	80.07	4.00	4.15	40.03	56.05
2017	80.00	85.74	4.25	4.43	42.87	60.02
2018	85.00	91.41	4.50	4.71	45.70	63.99
2019	90.00	97.07	4.75	4.99	48.54	67.95

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; capacity of facilities; installation of a condensation stabilizer and equipment; construction of a 15-kilometer pipeline; timing and construction of a third field compression facility and the purchase of equipment in connection therewith; the effect on the Company of the operations capital expenditures being reduced in 2015; 2015 guidance in respect of certain operational and financial metrics, including, but not limited to, estimated average operating costs, estimated average royalty rate, estimated operations capital, estimated land and property acquisitions costs, estimated general and administrative costs, estimated fourth quarter production, estimated annual production, estimated number of Umbach horizontal wells drilled, completed and starting production and estimated debt at end of 2015; reserve volumes; capital expenditures; royalties; financing; commodity prices; and production, operating and general and administrative costs. Statements of "reserves" are also deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

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, 2014.

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

NEITHER THE TSX VENTURE EXCHANGE NOR ITS REGULATION SERVICES PROVIDER (AS THAT TERM IS DEFINED IN THE POLICIES OF THE TSX VENTURE EXCHANGE) ACCEPTS RESPONSIBILITY FOR THE ADEQUACY OR ACCURACY OF THIS PRESS RELEASE.