Storm Resources Ltd. Is Pleased to Announce Its Financial and Operating Results for the Three Months and Year Ended December 31, 2015

CALGARY, ALBERTA--(Marketwired - Feb. 25, 2016) - Storm Resources Ltd. (TSX VENTURE:SRX) ("Storm" or the "Company") -

Storm has also filed its audited consolidated financial statements as at December 31, 2015 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, 2015, as well as reserves information at December 31, 2015, appears below and should be read in conjunction with the related financial statements and MD&A.

Highlights

Thousands of Cdn$, except volumetric and per-share amounts		Three Months to Dec. 31, 2015		Three Months to Dec. 31, 2014		Year Ended Dec. 31, 2015		Year Ended Dec. 31, 2014
FINANCIAL
Revenue from product sales(1)		14,480		28,070		67,736		95,480
Funds from operations(2)		9,182		13,892		39,046		45,412
	Per share - basic ($)	0.08		0.13		0.34		0.42
	Per share - diluted ($)	0.08		0.12		0.34		0.41
Net income (loss)		1,850		(7,422	)	(6,867	)	4,855
	Per share - basic ($)	0.02		(0.07	)	(0.06	)	0.04
	Per share - diluted ($)	0.02		(0.07	)	(0.06	)	0.04
Net capital invested		31,081		20,095		71,509		194,555
Operations capital expenditures		26,700		20,219		90,685		106,604
Land and property acquisitions/ (dispositions)		4,381		(124	)	(19,176	)	87,951
Debt including working capital deficiency(3)		61,721		63,080		61,721		63,080
Common shares (000s)
	Weighted average - basic	119,388		111,305		115,821		108,172
	Weighted average - diluted	119,388		112,850		115,821		109,981
	Outstanding end of period - basic	119,467		111,322		119,467		111,322
OPERATIONS
(Cdn$ per Boe)
Revenue		14.67		29.99		18.64		37.48
Royalties		0.05		(3.69	)	(0.82	)	(5.16	)
Production		(7.01	)	(8.40	)	(8.00	)	(9.33	)
Transportation		(0.79	)	(1.91	)	(1.13	)	(1.80	)
Field operating netback		6.92		15.99		8.69		21.19
Hedging gains (losses)		4.20		0.52		4.20		(1.26	)
General and administrative		(1.27	)	(1.16	)	(1.51	)	(1.50	)
Interest and finance costs		(0.54	)	(0.50	)	(0.62	)	(0.60	)
Funds from operations - per Boe		9.31		14.85		10.76		17.83
Barrels of oil equivalent per day (6:1)		10,730		10,173		9,956		6,980
Gas Production
Thousand cubic feet per day		53,147		49,094		48,656		33,067
Price (Cdn$ per Mcf)		1.78		3.85		2.39		4.58
NGL production
	Barrels per day	1,872		1,605		1,667		1,064
	Price (Cdn$ per barrel)	33.50		56.15		36.10		69.90
Oil Production
	Barrels per day	-		385		179		405
	Price (Cdn$ per barrel)	-		68.01		50.84		88.10
Wells drilled
	Gross	4.0		2.0		10.0		17.0
	Net	4.0		2.0		10.0		17.0

(1)	Excludes hedging gains and losses.
(2)	Certain financial amounts shown above are non-GAAP measurements, including funds from operations and funds from operations per share, operations capital expenditures, debt including working capital deficiency and all measurements per Boe. See discussion of Non-GAAP Measurements on page 37 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 29 of the MD&A.
(3)	Excludes the fair value of commodity price contracts.

PRESIDENT'S MESSAGE

2015 FOURTH QUARTER HIGHLIGHTS

• Production averaged 10,730 Boe per day (17% NGL), a per-share decrease of 2% from the previous year. During October and November, wells were shut in due to the low natural gas price at BC Station 2 (averaged $0.88 per GJ) which reduced production by approximately 2,700 Boe per day (production in December was 13,600 Boe per day).

• NGL production was 1,872 barrels per day, an increase of 17% from the previous year. The price was $33.50 per barrel which was 63% of the average Edmonton light oil price (57% of the NGL volume was higher value condensate and plant pentanes).

• On December 1, 2015, Storm began flowing gas on the Alliance Pipeline to Chicago which improved the natural gas price in December by approximately $0.45 per Mcf over the equivalent BC Station 2 price.

• Activity was focused at Umbach where four horizontal wells were drilled, six horizontal wells were completed and three horizontal wells commenced production.

• At the end of the quarter, there was an inventory of six horizontal wells (6.0 net) that had not started producing (includes two completed wells).

• Montney horizontal well performance at Umbach has continued to improve as length and the number of frac stages are increased. The three most recent wells started producing in November and December, had 22 to 24 frac stages and averaged 6.5 Mmcf per day gross raw gas (1,150 Boe per day sales) over the first 90 calendar days, a 40% improvement from the average 2014 well.

• Controllable cash costs (operating, cash G&A, interest expense) were $8.82 per Boe, a year-over-year decrease of 12%.

• Funds from operations was $9.31 per Boe, a year-over-year decrease of $5.54 per Boe. Revenue declined by $15.32 per Boe which was partially offset by a hedging gain of $4.20 per Boe, royalties decreasing by $3.74 per Boe and operating costs declining by $1.39 per Boe.

• Net income was $1.9 million or $1.88 per Boe which reflects the year-over-year improvement in capital efficiency (notable given that revenue per Boe decreased by 51%).

• Debt including working capital deficiency was $61.7 million which is 1.7 times annualized fourth quarter funds flow. Storm's bank credit facility is currently $140.0 million.

2015 YEAR END HIGHLIGHTS

• Production for the year averaged 9,956 Boe per day (19% oil plus NGL), a year-over-year increase of 43%, or 33% on a per-share basis. Wells were shut in during the second half of the year as a result of a low natural gas price at BC Station 2 which reduced production for the year by approximately 1,400 Boe per day. The yearly average was also reduced from the McMahon Gas Plant being shut in for 28 days in June for a loss of 550 Boe per day and properties in the Grande Prairie area producing 725 Boe per day were sold effective July 1, 2015.

• Controllable cash costs (operating, cash G&A, interest expense) were $10.13 per Boe, a decrease of 11% from last year.

• Funds from operations totaled $39.0 million, a year-over-year decrease of 14% which was mainly caused by revenue per Boe decreasing by 50% which exceeded production growth of 43%.

• Net capital investment was $71.5 million and included $23.6 million of proceeds from selling non-core properties in the Grande Prairie area of Alberta, $4.5 million to acquire undeveloped land at Umbach (12 net sections) and $36.0 million to expand infrastructure at Umbach.

• Infrastructure investment at Umbach included $18.5 million to increase field compression capacity to 80 Mmcf raw gas per day (from 45 Mmcf raw gas per day at the end of 2014), $5.3 million for 20 kilometers of pipeline, and $4.8 million to purchase major equipment for the third field compression facility.

• The one year FD&A cost (all-in) for reserve additions was $6.53 per Boe for PDP, $3.38 per Boe for 1P and $0.50 per Boe for 2P. The removal of reserves and associated FDC for a disposition and for economic factors reduced the 1P and 2P FD&A cost. The one year F&D excluding acquisitions, dispositions and revisions (per NI51-101) is more representative and was $7.61 per Boe for 1P and $6.47 per Boe for 2P.

• The recycle ratio using the one year FD&A cost (all-in) and the funds from operations netback was 1.6X for PDP, 3.2X for 1P and 21.5X for 2P.

• Using fourth quarter production, the reserve life index was 5.3 years for PDP, 18.8 years for 1P and 25.7 years for 2P.

• Cost of production additions in 2015 improved to $11,000 per Boe per day using total capital investment and fourth quarter production of 6,500 Boe per day from wells that started production in 2015 (last year was $29,800 per Boe per day). This is reduced to $8,500 per Boe per day when land and property acquisitions/dispositions and investment in infrastructure are excluded (approximates the cost to maintain production levels).

• Storm's enterprise value at year end plus FDC was equal to $10.29 per Boe on a 2P basis. Enterprise value was determined using the year-end closing share price of $3.62, 119.4 million shares outstanding, and after adding year-end debt including working capital deficiency.

2015 YEAR END RESERVE EVALUATION

Reserves	2015		2014		Change
Proved Developed Producing or "PDP" (Mboe)	20,810		13,487		+54	%
Total Proved or "1P" (Mboe)	73,434		59,551		+23	%
Total Proved plus Probable or "2P" (Mboe)	100,722		88,024		+14	%
PDP as % of 2P	21	%	15	%
1P as a % of 2P	73	%	68	%

• PDP reserve growth of 54% was consistent with the 43% year-over-year increase in corporate production.

Reserves Per Share Outstanding at Year End	2015	2014	Change
PDP (Mboe per million shares)	174	121	+44	%
1P (Mboe per million shares)	615	535	+15	%
2P (Mboe per million shares)	844	791	+7	%

• Reserve growth on a per share basis was reduced by an equity issue completed in May 2015.

Future Development Capital ("FDC")	2015		2014
1P ($M)	$	435,000	$	448,000
2P ($M)	$	543,000	$	607,000

• The year-over-year decrease in FDC was the result of selling properties at Grande Prairie (2P FDC $37.4 million removed), removing three drilling locations in the HRB (2P FDC $56.6 million removed) and increasing the number of 2P future drilling locations at Umbach (2P FDC increased $30 million).

FD&A Cost (all-in)	2015		2014
PDP ($/Boe)	$	6.53	$	23.01
1P ($/Boe)	$	3.38	$	11.68
2P ($/Boe)	$	0.50	$	9.64

• The all-in FD&A cost reflects the result of Storm's entire capital investment program and was significantly improved in 2015 because of positive technical revisions from well performance at Umbach exceeding expectations plus a large reduction in the value of land and property acquisitions/dispositions (net proceeds of $19.2 million realized in 2015 versus an expenditure of $88.0 million in 2014).

Recycle Ratio Using FD&A Cost (all-in)	2015		2014
Annual field operating netback excluding hedging	$	8.69	$	21.19
PDP Recycle		1.3X		0.9X
1P Recycle		2.6X		1.8X
2P Recycle		17.4X		2.2X

• Recycle ratios improved significantly in 2015 as a result of the decrease in the FD&A cost. The PDP recycle ratio was 1.6X using the 2015 funds from operations netback (includes cash G&A, interest expense, and hedging gains).

Net Present Value Discounted at 10% (before tax)	2015		2014		Change
PDP ($M)	$	213,000	$	199,000	+7	%
1P ($M)	$	442,000	$	493,000	-10	%
2P ($M)	$	592,000	$	684,000	-13	%

• Net present values discounted at 10% were largely unchanged from last year as the price forecast for AECO natural gas used by Storm's external reservoir engineer, InSite Petroleum Consultants Ltd. ("InSite"), decreased by 24% over the first five years. For Edmonton Par light oil, the decrease was 13%.

OPERATIONS REVIEW

Umbach, Northeast British Columbia

Storm's land position at Umbach is prospective for liquids-rich natural gas from the Montney formation and currently totals 109,000 net acres (155 net sections). To date, a total of 40.4 net horizontal wells (44.0 gross) have been drilled into the Montney formation with 31.4 net being on production.

Fourth quarter production from Umbach was 10,729 Boe per day and represented 100% of corporate production in the quarter. NGL recovery was 35 barrels per Mmcf sales (57% of the NGL volume is higher priced field condensate plus pentanes recovered at the gas plant). Revenue was $14.72 per Boe ($1.78 per Mcf sales and $33.50 per barrel of NGL), transportation costs were $0.79 per Boe, royalties were $0.07 per Boe (1% of revenue), operating costs were $6.91 per Boe and the operating netback was $6.95 per Boe. The natural gas sales price in December was $0.45 per Mcf higher than what was realized in October and November.

Activity in the fourth quarter included drilling four horizontal wells (4.0 net), completing six horizontal wells (6.0 net) and pipeline connecting three horizontal wells (3.0 net). At year end, there was an inventory of six horizontal wells (6.0 net) that had not started producing (includes two completed wells).

In the first quarter of 2016, seven more horizontal wells (7.0 net) will be drilled and two horizontal wells (2.0 net) will be completed.

Storm's two operated field compression facilities (both 100% working interest) have total capacity of 80 Mmcf per day raw gas with actual throughput in December averaging 73 Mmcf per day raw gas. As a result of the low natural gas price at AECO and BC Station 2, timing to start up the third field compression facility with initial capacity of 35 Mmcf per day is being moved back to the fourth quarter of 2016 (was May 2016). The estimated total cost is unchanged at $25.0 million (expandable to 70 Mmcf per day raw gas for an additional $7.0 million). During 2015, $4.8 million was invested for site preparation and to purchase major equipment for the third facility.

Raw gas from Storm's field compression facilities is sent to the McMahon and Stoddart Gas Plants where Storm has firm processing commitments totaling 65 Mmcf per day raw gas in 2016.

Shown below is a summary of horizontal well performance and costs. On a per-stage basis, the 2015 drill and complete cost decreased by 15% from 2014 with cost reductions coming from pad drilling, improved water management practices and lower service costs. Performance to date of the 2015 wells does not fully reflect the increased level of stimulation because calendar day rates were reduced by the downtime experienced in the second half of 2015. The three most recent 2015 wells with 22 to 24 frac stages averaged 6.5 Mmcf per day gross raw gas over the first 90 calendar days, an improvement of 40% from the average 2014 horizontal well.

Year of Completion	Avg Frac Stages	Actual Drill & Complete Cost	IP 90 Cal Day Mmcf/d Raw	IP 180 Cal Day Mmcf/d Raw	IP 365 Cal Day Mmcf/d Raw
2010 - 12 7 wells	11		1.9 Mmcf/d 7 hz's	1.4 Mmcf/d 7 hz's	1.3 Mmcf/d 7 hz's
2013 6 wells	17	$4.6 million ($270 K/stage)	3.5 Mmcf/d 6 hz's	2.9 Mmcf/d 6 hz's	2.2 Mmcf/d 6 hz's
2014 13 wells	19	$4.6 million ($240 K/stage)	4.6 Mmcf/d 13 hz's	4.2 Mmcf/d 13 hz's	3.3 Mmcf/d 11 hz's
2015 11 wells	22	$4.5 million ($205 K/stage)	5.0 Mmcf/d 9 hz's	3.7 Mmcf/d 3 hz's
2016 4 wells	29

Based on the performance of the 2014 and 2015 horizontal wells, Storm management uses a 6.3 Bcf raw gas type curve for internal budgeting purposes (type curve has the same decline profile as the type curves used by InSite in the 2015 reserve evaluation). The first year average rate is 3.6 Mmcf per day raw gas which is 640 Boe per day sales (10% shrinkage and 32 barrels of NGL per Mmcf sales). Using the actual cost of $4.8 million to drill, complete and tie in a horizontal well in 2015, the payout is approximately 32 months and the rate of return is 26% based on $2.60 per GJ at AECO, $2.10 per GJ at BC Station 2 and Cdn $53.00 per barrel for Edmonton light oil (expected longer term commodity prices with pricing held flat for the life of the well). See the presentation on Storm's website for further details.

Horn River Basin, Northeast British Columbia

Storm has a 100% working interest in 119 sections in the Horn River Basin (78,000 net acres) which are prospective for natural gas from the Muskwa, Otter Park and Evie/Klua shales. The one horizontal well producing 280 Boe per day was shut in during July 2015 due to the low natural gas price at BC Station 2.

Grande Prairie Area, Northwest Alberta

Storm's remaining Alberta property at Valhalla was shut in during August 2015 as a result of the decline in the natural gas price (capable of producing 300 Boe per day).

HEDGING AND TRANSPORTATION

The purpose of Storm's commodity price hedges is to provide greater certainty regarding future cash flows and capital investment in order to support longer term growth plans. A maximum of 50% of the most recent monthly production will be hedged; anticipated production growth is not hedged. Although Storm has no oil production, approximately 80% of NGL production is priced in reference to WTI (condensate, plant pentane, and butane).

A gain of $15.3 million was realized from commodity price hedging in 2015 and the fair market value of commodity price contracts for 2016 and 2017 was $8.0 million at year end.

A summary of commodity price hedges for 2016 is provided below.

	Volume		Price
Crude Oil	500 Bopd		WTI Cdn$75.00 X Cdn$90.75/Bbl
Natural Gas	21,250 GJ/d (17,000 Mcf/d) 11,000 GJ/d (8,800 Mcf/d) 33,000 Mmbtu/d (27,800 Mcf/d)		AECO Cdn$2.98/GJ ($3.72/Mcf) BC Stn 2 price = AECO - Cdn$0.3375/GJ Chicago price = AECO + US$0.672/Mmbtu

Storm's transportation commitments increase from 62 Mmcf per day in 2016 to 91 Mmcf per day in 2018 (interruptible capacity on the Alliance Pipeline adds up to 25% of contracted capacity or 11 Mmcf per day in 2016 and 13 Mmcf per day in 2018).

2016		2017		2018
43.5 Mmcf/d (54,800 GJ/d) Alliance Pipeline Chicago - Cdn$1.35/GJ toll(1)(2)		48.0 Mmcf/d (60,500 GJ/d) Alliance Pipeline Chicago - Cdn$1.35/GJ toll(1)(2)		52.5 Mmcf/d (66,000 GJ/d) Alliance Pipeline Chicago - Cdn$1.35/GJ toll(1)
9.0 Mmcf/d (11,400 GJ/d) Spectra T-north BC Stn 2(3) - Cdn$0.16/GJ toll		24.0 Mmcf/d (30,200 GJ/d) Spectra T-north BC Stn 2(3) - Cdn$0.16/GJ toll		29.0 Mmcf/d (36,500 GJ/d) Spectra T-north BC Stn 2 - Cdn$0.16/GJ toll
9.8 Mmcf/d (12,400 GJ/d) AECO - $0.68/GJ(1)				10.0 Mmcf/d (12,600 GJ/d) Spectra T-north & TCPL sale at AECO - $0.45/GJ toll

(1)	Volumes sold at McMahon Gas Plant with pipeline tariff deducted from realized price.
(2)	The Chicago - AECO differential has been fixed for 33,000 Mmbtu per day in 2016 at +US$0.672 per Mmbtu and for 35,000 Mmbtu per day in 2017 at +US$0.577 per Mmbtu.
(3)	The AECO - BC Station 2 differential has been fixed for 11,000 GJ per day in 2016 at -$0.3375 per GJ and for 5,000 GJ per day in 2017 at -$0.445 per GJ.

COMPARISON OF 2015 RESULTS VERSUS GUIDANCE

Shown below is a comparison of Storm's actual 2015 results to what was provided for guidance.

2015 Guidance		Original Guidance Nov 13, 2014		Last Update Nov 11, 2015		Actual 2015 Results
AECO natural gas price		$3.25 per GJ		$2.60 per GJ		$2.55 per GJ
BC Stn 2 natural gas price		$3.00 per GJ		$1.87 per GJ		$1.70 per GJ
Edmonton light oil price		Cdn$83 per Bbl		Cdn$58 per Bbl		Cdn$57 per Bbl
Estimated average operating costs		$7.50 - $8.00 per Boe		$7.75 - $8.00		$8.00 per Boe
Estimated average royalty rate (% production revenue before hedging)		12% - 14	%	6% - 7	%	4	%
Estimated operations capital (excluding acquisitions & dispositions)		$110.0 million		$92.0 million		$90.7 million
Estimated land and property acquisitions/(dispositions)		$0.0 million		($19.3 million	)	($19.2 million	)
Estimated cash G&A net of recoveries		$5.3 million		$5.3 million		$5.5 million
Forecast fourth quarter production		14,000 - 14,500 Boe/d (18% oil + NGL	)	10,000 - 12,000 (18% NGL	)	10,730 Boe/d (17% NGL	)
Forecast annual production		11,500 - 12,700 Boe/d (19% oil + NGL	)	10,000 - 11,000 (19% oil + NGL	)	9,956 Boe/d (19% oil + NGL	)
Umbach horizontal wells:
	Drilled	9 gross (9.0 net	)	10 gross (10.0 net	)	10 gross (10.0 net	)
	Completed	14 gross (14.0 net	)	13 gross (13.0 net	)	13 gross (13.0 net	)
	Starting production	16 gross (16.0 net	)	13 gross (13.0 net	)	12 gross (12.0 net	)

Comparing actual 2015 results to original guidance:

• Forecast annual and fourth quarter production was lower as a result of wells shut in during the second half of 2015 due to the low BC Station 2 natural gas price (loss of 1,400 Boe per day during 2015), plus the mid-year disposal of Alberta properties (loss of 300 Boe).

• The royalty rate was lower as a result of receiving $2.0 million of infrastructure royalty credits and from lower commodity prices (royalty rate in British Columbia depends on well productivity and the natural gas price).

• Operations capital investment was less than forecast due to the third field compression facility at Umbach being deferred into 2016 from October 2015 ($25.0 million estimated total cost less $4.8 million paid in 2015 for major equipment and site preparation).

OUTLOOK

Production in the first quarter of 2016 is forecast to be 13,000 to 14,000 Boe per day and will largely depend on natural gas prices. Production to date in the first quarter has averaged approximately 13,500 Boe per day based on field estimates. Capital investment in the first quarter is expected to be $25.0 million.

Guidance for 2016 is being revised due to the continuing decline in commodity prices which has reduced forecast funds flow. Capital investment in 2016 will be reduced to $80 million which will result in fewer horizontal wells being drilled and completed plus the start-up of the third field compression facility at Umbach being delayed to the fourth quarter of 2016. If commodity prices remain at current levels or continue to decline, capital investment would likely be further reduced in mid-May to approximately $45 million which would result in forecast production averaging 13,000 to 14,000 Boe per day in 2016 and the third field compression facility being delayed until 2017 (requires approximately seven horizontal wells starting production in 2016 to offset declines). Revised guidance for 2016 is provided below with assumed commodity prices being approximately equal to the current forward strip.

2016 Guidance	Original Guidance Nov 11, 2015		Revised Feb 25, 2016
Chicago natural gas price			US$2.20 per mmbtu
AECO natural gas price	$2.50 per GJ		$2.00 per GJ
BC STN 2 natural gas price	$1.90 per GJ		$1.45 per GJ
Edmonton light oil price	Cdn$57 per Bbl		Cdn$46 per Bbl
Estimated average operating costs	$7.00 - $7.50 per Boe		$7.00 per Boe
Estimated average royalty rate (% production revenue before hedging)	7% - 8	%	5% - 6	%
Estimated operations capital (excluding acquisitions & dispositions)	$105.0 million		$80.0 million
Estimated land and property acquisitions/ (dispositions)
Estimated cash G&A net of recoveries	$5.0 million		$5.0 million
Estimated funds flow			$39.0 million
Forecast fourth quarter production	20,000 - 21,000 Boe/d (17% NGL	)	15,500 - 16,500 Boe/d (18% NGL	)
Forecast annual production	16,000 - 18,000 Boe/d (17% oil + NGL	)	14,000 - 15,000 Boe/d (18% oil + NGL	)
Umbach horizontal wells drilled	14 gross (14.0 net	)	12 gross (12.0 net	)
Umbach horizontal wells completed	14 gross (14.0 net	)	10 gross (10.0 net	)
Umbach horizontal wells connected	16 gross (16.0 net	)	12 gross (12.0 net	)

Capital investment in 2016 will be directed entirely to Umbach and will include $48 million for drilling and completions plus $24 million for infrastructure (includes remaining $21 million for the third field compression facility). Infrastructure expansion is being funded with debt which is an investment in a long life asset (value doesn't decline with time).

Natural gas sales will be more diversified going forward with Storm's contracted capacity on the Alliance Pipeline for delivery to Chicago. Using forecasted natural gas production in 2016, approximately 22% will be sold at Chicago pricing, 65% sold at an AECO price less a fixed differential and the remaining 13% at the Chicago or BC Station 2 price (whichever is higher). This is much different from 2015 where approximately 50% received the BC Station 2 price which reduced the realized natural gas price and operating netback in the second half of the year.

The high quality and competitive advantages of Storm's Montney land position at Umbach (shallow depth and liquids rich) are reflected in the 2015 all-in PDP FD&A cost of $6.53 per Boe which resulted in a recycle ratio of 1.6X using the 2015 funds flow netback. This is a significant achievement given the low netback in 2015 and reflects Storm's sustainability in the current low commodity price environment. An important objective in 2016 is to achieve further reductions in the PDP FD&A cost in order to remain competitive. For evaluating capital efficiency, PDP FD&A has become a better metric than 1P or 2P FD&A given that it isn't influenced by the accuracy of estimates for future development capital (including required infrastructure).

Storm is still in the early stages of delineating the large liquids rich resource in the Montney formation at Umbach. At the end of 2015, only 20% of Storm's land position was assigned 2P reserves (31 net sections of 155 net sections) which leaves room for significant future reserve growth from the remaining lands which appear to be highly prospective given horizontal well results on offsetting acreage. Over time, data from the wells that have been drilled on offsetting lands is likely to result in reserve additions on Storm's lands.

Storm's results in 2015 reflect a focus on converting Montney resource at Umbach into production and cash flow plus reducing the cost structure (both controllable cash costs and cost of PDP reserve additions). Looking ahead to 2016, the business environment for oil and gas producers continues to become more challenging with the ongoing decline in commodity prices. Storm plans to weather the storm by continuing to build a business for the longer term with a focus on operational excellence which will include:

• further improving capital efficiency by reducing PDP FD&A costs (add length and frac stages on horizontal wells at Umbach;
• increasing the funds flow netback by decreasing controllable cash costs;
• identifying and capturing opportunities that increase future net asset value; and
• maintaining a strong balance sheet so that growth can be accelerated when commodity prices improve.

Storm's land position in the Horn River Basin 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 in 2015 which resulted in record levels of production and significant improvements in capital efficiency. In addition, the invaluable advice, guidance, and support provided by Storm's Directors continues to be very much appreciated.

Respectfully,

Brian Lavergne, President and Chief Executive Officer

February 25, 2016

RESERVES AT DECEMBER 31, 2015

Storm's year-end reserve evaluation effective December 31, 2015 was prepared by InSite Petroleum Consultants Ltd. ("InSite") under date of February 16, 2016. InSite has evaluated all of Storm's crude oil, NGL and natural gas reserves. The InSite price forecast at December 31, 2015 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 54% to total 20,810 Mboe with additions replacing 300% of 2015 production.

• Total proved ("1P") reserves increased 23% to total 73,434 Mboe with additions replacing 480% of 2015 production.

• Total proved plus probable ("2P") reserves increased 14% to total 100,722 Mboe with additions replacing 450% of 2015 production.

• Total proved reserves were 73% of total proved plus probable reserves, an improvement from 68% in 2014.

• The all-in finding, development, and acquisition ("FD&A") cost⁽¹⁾ to add reserves was $6.53 per Boe for PDP, $3.38 per Boe for 1P and was $0.50 per Boe for 2P.

• Recycle ratio using the all-in FD&A cost was 1.3 for PDP additions, 2.6 for 1P additions, and 17.3 for 2P additions using the 2015 field operating netback of $8.68 per Boe excluding hedging gains or losses.

• Technical revisions were primarily due to horizontal well performance exceeding expectations which increased PDP reserves by 1,221 Mboe, 1P reserves by 6,700 Mboe and 2P reserves by 5,482 Mboe.

• Economic factors were the elimination of undeveloped drilling locations at the Horn River Basin ("HRB") in northeast British Columbia, reducing 1P reserves by 2,364 Mboe and 2P reserves by 4,462 Mboe.

• Breaking down 2P reserves by area, 96.2% is at Umbach, 3.4% at the HRB and 0.4% is at Grande Prairie.

• Future development costs ("FDC") were $435.4 million on a 1P basis and $543.3 million on a 2P basis which represents approximately five years of activity in the evaluation based on forecast capital investment in 2016.

• At Umbach the 100% working interest lands were assigned 70 net 2P horizontal drilling locations at an average of 4.7 Bcf gross raw gas, an increase of 7% from 4.4 Bcf gross raw gas assigned in 2014. On the 60% working interest lands, 20.4 net 2P horizontal drilling locations were assigned an average of 3.7 Bcf gross raw gas, an increase of 16% from 3.2 Bcf gross raw gas assigned in 2014.

• Ultimate 2P recovery for the producing horizontal wells at Umbach is forecast to average 5.5 Bcf gross raw gas for the wells drilled in 2015, 6.2 Bcf gross raw gas for the wells drilled in 2014 (revised up from 5.4 Bcf last year), and 4.4 Bcf gross raw gas for the wells drilled in 2013 (revised up from 4.2 Bcf last year).

• At Umbach, 2P reserves were recognized in the upper Montney only on 20% or 31.2 net sections of Storm's 153 net sections in the area with DPIIP averaging 48 Bcf gross raw gas per section in the upper Montney (total net DPIIP 1.5 Tcf on 31.2 net sections). Forecast recovery of DPIIP totals 38% for 2P reserves.

• Umbach 2P FDC totaled $514.0 million for 90.4 net 2P future horizontal drilling locations which equals an average of $5.7 million per location and includes $0.6 million per location for future infrastructure expansion (last year was $484.0 million for 79.4 net locations which was $6.1 million per future horizontal drilling location and included $0.8 million per location for future infrastructure expansion).

⁽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, 2015, 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, 2015

(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	-	104,004	3,476	20,810
Proved non-producing	-	5,926	196	1,183
Total proved developed	-	109,930	3,672	21,993
Proved undeveloped	-	258,552	8,349	51,441
Total proved	-	368,483	12,020	73,434
Probable additional	-	138,588	4,190	27,288
Total proved plus probable	-	507,071	16,210	100,722

Numbers in this table may not add due to rounding.

Reserve Life Index ("RLI") Using Fourth Quarter Production

	2015	2014	2013
PDP	5 years	4 years	4 years
1P	19 years	16 years	12 years
2P	26 years	24 years	23 years

Gross Company Reserve Reconciliation for 2015

(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, 2014 - opening balance	13,487		59,551		28,473		88,024
Acquisitions	-		-		-		-
Discoveries	-		-		-		-
Extensions	1,714		14,950		4,507		19,457
Category transfer	9,471		-		-		-
Dispositions	(1,450	)	(1,768	)	(2,377	)	(4,145	)
Technical revisions	1,221		6,700		(1,218	)	5,482
Economic factors	-		(2,364	)	(2,098	)	(4,462	)
Production	(3,634	)	(3,634	)	-		(3,634	)
December 31, 2015 - closing balance	20,810		73,434		27,288		100,722

Numbers in this table may not add due to rounding.

Future Development Costs ("FDC")

	Undiscounted Proved Expenditures ($M)	Undiscounted Proved Plus Probable Expenditures (M$)
2016	41,300	41,300
2017	98,379	98,379
2018	109,627	118,262
2019	83,591	119,343
2020	79,591	136,072
2021	22,954	29,909
Total FDC - undiscounted	435,442	543,266
Total FDC - discounted at 10%	340,521	413,996
HRB	$12.3 million	$28.9 million
Umbach	$423.1 million	$514.4 million

Note: InSite escalates capital costs at 2% per year after 2016.

Numbers in this table may not add due to rounding.

All-In Finding, Development and Acquisition Costs ("FD&A")

(including acquisitions, dispositions and revisions)

Proved Developed Producing FD&A Cost (All-In)	2015			2014			2013			3 Year Total
Net capital investment (000s)	$	71,509		$	194,555		$	52,444		$	318,508
Total capital	$	71,509		$	194,555		$	52,444		$	318,508
Total reserve additions (Mboe)		10,956			8,456			3,047			22,457
All-in PDP FD&A cost	$	6.53		$	23.01		$	17.21		$	14.18
Total Proved FD&A Cost (All-In)	2015			2014			2013			3 Year Total
Net capital investment (000s)	$	71,509		$	194,555		$	52,444		$	318,508
Change in FDC (000s)		(12,275	)		288,242			56,600			332,567
Total capital including change in FDC (000s)	$	59,234		$	482,797		$	109,044		$	651,075
Total reserve additions (Mboe)		17,517			41,334			8,270			67,121
All-in 1P FD&A cost (per Boe)	$	3.38		$	11.68		$	13.19		$	9.70
Total Proved Plus Probable FD&A Cost (All-In)	2015			2014			2013			3 Year Total
Net capital investment (000s)	$	71,509		$	194,555		$	52,444		$	318,508
Change in FDC (000s)		(63,288	)		287,686			89,829			314,227
Total capital including change in FDC (000s)	$	8,221		$	482,241		$	142,273		$	632,735
Total reserve additions (Mboe)		16,332			50,030			14,538			80,900
All-In 2P FD&A cost (per Boe)	$	0.50		$	9.64		$	9.79		$	7.82
Recycle Ratio
Operating netback per Boe excluding hedging	$	8.68		$	21.19		$	20.43		$	15.00
Recycle ratio for all-in PDP FD&A cost		1.3			0.9			1.2			1.1
Recycle ratio for all-in 1P FD&A cost		2.6			1.8			1.5			1.5
Recycle ratio for all-in 2P FD&A cost		17.4			2.2			2.1			1.9

NI 51-101 Finding and Development Costs ("F&D")

(excluding acquisitions, dispositions, revisions)

Total Proved F&D Cost	2015		2014		2013		3 Year Total
Capital expenditures excluding acquisitions and dispositions (000s)	$	95,099	$	106,604	$	67,450	$	269,153
Change in FDC (000s)		18,604		288,242		77,282		384,128
Total capital including change in FDC (000s)	$	113,703	$	394,846	$	144,732	$	653,281
Reserve additions excluding acquisitions, dispositions, and revisions (Mboe)		14,950		38,707		10,356		64,013
1P F&D cost (per Boe)	$	7.61	$	10.20	$	13.98	$	10.21
Total Proved Plus Probable F&D Cost	2015		2014		2013		3 Year Total
Capital expenditures excluding acquisitions and dispositions (000s)	$	95,099	$	106,604	$	67,450	$	269,153
Change in FDC (000s)		30,717		287,686		134,903		453,306
Total capital including change in FDC (000s)	$	125,816	$	394,290	$	202,353	$	722,459
Reserve additions excluding acquisitions, dispositions, and revisions (Mboe)		19,457		45,001		18,823		83,281
2P F&D cost	$	6.47	$	8.76	$	10.75	$	8.67

Net Present Value Summary (before tax) as at December 31, 2015

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	341,642	263,305	213,054	178,793	154,232
Proved non-producing	17,777	13,009	10,051	8,092	6,724
Total proved developed	359,419	276,314	223,105	186,885	160,956
Proved undeveloped	627,336	367,602	218,610	128,126	70,612
Total proved	986,755	643,916	441,715	315,012	231,567
Probable additional	516,188	266,667	150,273	90,456	57,169
Total proved plus probable	1,502,943	910,582	591,989	405,467	288,736

Numbers in this table may not add due to rounding.

Net Present Value Summary (after tax) as at December 31, 2015

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	341,642	263,305	213,054	178,793	154,232
Proved non-producing	17,777	13,009	10,051	8,092	6,724
Total proved developed	359,419	276,314	223,105	186,885	160,956
Proved undeveloped	480,971	280,602	164,057	92,379	46,319
Total proved	840,390	556,916	387,162	279,264	207,275
Probable additional	382,688	195,748	108,701	64,148	39,522
Total proved plus probable	1,223,078	752,663	495,863	343,412	246,797

Numbers in this table may not add due to rounding.

InSite Escalating Price Forecast as at December 31, 2015

	WTI Crude Oil (US$/Bbl)	Edmonton Par Crude Oil (Cdn$/Bbl)	Henry Hub Natural Gas (US$/Mmbtu)	AECO Natural Gas (Cdn$/Mmbtu)
2016	45.00	55.64	2.50	2.71
2017	55.00	68.33	3.00	3.27
2018	65.00	78.23	3.50	3.74
2019	70.00	81.22	3.75	3.87
2020	75.00	85.06	4.00	4.05

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.

Non-GAAP Measures - This document contains the terms "funds from operations", "funds from operations per share", "netbacks", "cash costs", and measurements "per Boe" which are not recognized under Generally Accepted Accounting Principles ("GAAP") and are regarded as non-GAAP measures. These non-GAAP measures may not be comparable to the calculation of similar amounts for other entities and readers are cautioned that use of such measures to compare enterprises may not be valid. In particular, funds from operations is not intended to represent, or be equivalent to, cash flow from operating activities calculated in accordance with GAAP, which is measured on the Company's consolidated statements of cash flows. Funds from operations and similar non-GAAP terms are used to benchmark operations against prior periods and peer group companies and are widely used by investors, analysts and other parties. These measurements are also used by lenders to measure compliance with debt covenants and thus set interest costs. Additional information relating to certain of these non-GAAP measures, including the reconciliation between funds from operations and cash flow from operating activities, can be found in the MD&A.

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 and completion plans; capacity of facilities; 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 2016; hedging; 2015 and 2016 guidance in respect of certain operational and financial metrics, including, but not limited to, commodity pricing, estimated average operating costs, estimated average royalty rate, estimated operations capital, estimated land and property acquisitions costs, estimated general and administrative costs, estimated first quarter production, estimated annual production, estimated number of Umbach horizontal wells drilled, completed and starting production and estimated debt in 2015 and 2016; reserve volumes; capital expenditures; royalties; financing; commodity prices; anticipated lower costs for services; natural gas sales; improvement on controllable cash costs; 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, 2015.

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.