Storm Resources Ltd. ("Storm" or the "Company") Is Pleased to Announce Its Financial and Operating Results for the Three and Six Months Ended June 30, 2016

CALGARY, ALBERTA--(Marketwired - Aug. 15, 2016) - Storm Resources Ltd. (TSX VENTURE:SRX) -

Storm has filed its unaudited condensed interim consolidated financial statements as at June 30, 2016 and for the three and six months then ended along with Management's Discussion and Analysis ("MD&A") for the same period. 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 and six months ended June 30, 2016 appears below and should be read in conjunction with the related financial statements and MD&A.

Highlights

Thousands of Cdn$, except volumetric and per-share amounts		Three Months to June 30, 2016		Three Months to June 30, 2015		Six Months to June 30, 2016		Six Months to June 30, 2015
FINANCIAL
Revenue from product sales(1)		13,870		18,461		29,992		36,972
Funds from operations(2)		5,781		8,170		13,636		21,882
	Per share - basic ($)	0.05		0.07		0.11		0.20
	Per share - diluted ($)	0.05		0.07		0.11		0.20
Net loss		(20,493	)	(4,191	)	(25,477	)	(7,756	)
	Per share - basic ($)	(0.17	)	(0.04	)	(0.21	)	(0.07	)
	Per share - diluted ($)	(0.17	)	(0.04	)	(0.21	)	(0.07	)
Net capital invested
	Operations capital expenditures	613		8,864		24,559		44,544
Debt including working capital deficiency(3)		71,254		28,051		71,254		28,051
Common shares (000s)
	Weighted average - basic	119,929		113,090		119,761		112,211
	Weighted average - diluted	119,929		113,090		119,761		112,211
	Outstanding end of period - basic	120,179		119,355		120,179		119,355
OPERATIONS
(Cdn$ per Boe)
Revenue		11.86		21.01		12.55		21.02
Royalties		(0.19	)	(1.62	)	(0.48	)	(1.08	)
Production		(6.76	)	(8.56	)	(6.73	)	(8.61	)
Transportation		(0.33	)	(1.16	)	(0.43	)	(1.42	)
Field operating netback		4.58		9.67		4.91		9.91
Hedging gains		2.24		2.02		2.64		5.19
General and administrative		(1.19	)	(1.51	)	(1.22	)	(1.88	)
Interest and finance costs		(0.68	)	(0.87	)	(0.62	)	(0.79	)
Funds from operations - per Boe		4.95		9.31		5.71		12.43
Barrels of oil equivalent per day (6:1)		12,852		9,657		13,135		9,716
Gas Production
	Thousand cubic feet per day	63,800		46,391		64,906		47,049
	Price (Cdn$ per Mcf)	1.28		2.55		1.45		2.70
NGL production
	Barrels per day	2,219		1,602		2,318		1,548
	Price (Cdn$ per barrel)	31.93		41.23		30.47		39.25
Oil Production
	Barrels per day	-		323		-		326
	Price (Cdn$ per barrel)	-		57.58		-		50.29
Wells drilled (100% working interest)		-		-		7.0		6.0
Wells completed (100% working interest)		-		-		2.0		6.0

(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 26 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 19 of the MD&A.

(3) Excludes the fair value of commodity price contracts.

PRESIDENT'S MESSAGE

2016 SECOND QUARTER

• Production averaged 12,852 Boe per day (17% NGL), a year-over-year increase of 33% (32% on a per-share basis) and a quarter-over-quarter decrease of 4%. Production was reduced during April and May as a result of extremely low natural gas prices which resulted in approximately 1,000 Boe per day being shut in.

• NGL production was 2,219 barrels per day, an increase of 39% from the previous year. The price was $31.93 per barrel or 58% of the average Edmonton light oil price (53% of the NGL volume was higher value condensate and plant pentanes).

• There was minimal activity with three horizontal wells commencing production at Umbach during the quarter (one in April and two in June). At the end of the quarter, there was an inventory of nine horizontal wells (9.0 net) that have been drilled but not completed.

• Montney horizontal well performance at Umbach continues to improve with the five most recent wells with enough history averaging 5.5 Mmcf per day gross raw gas over the first 90 calendar days, a 15% increase from the average 2014 and 2015 wells. The four most recent wells with enough history have averaged 5.3 Mmcf per day over the first 180 calendar days, an improvement of 23% from the average 2014 and 2015 wells.

• Funds flow was $5.8 million ($4.95 per Boe), a decrease of 29% from a year ago. Although production per share increased and controllable cash costs decreased, this was more than offset by a 50% decrease in the natural gas price which averaged $1.28 per Mcf in the quarter.

• Controllable cash costs (operating, cash G&A, interest expense) were $8.63 per Boe, a year-over-year decrease of 21%. Transportation cost is excluded given that the sales price for volumes shipped on the Alliance Pipeline includes a deduction for the pipeline tariff (artificially reduces the transportation cost).

• Net loss was $20.5 million or $17.51 per Boe and reflects the extremely low commodity prices in the quarter with funds from operations at $4.95 per Boe being less than the depletion and depreciation rate of $8.21 per Boe. The net loss also includes a mark to market loss of $15.8 million related to the change in the fair value of commodity price hedges since the previous quarter (this is a non-cash item).

• Net capital investment was $0.6 million with investment being minimized as a result of extremely low commodity prices.

• Debt including working capital deficiency was $71.3 million which is 3.1 times annualized second quarter funds flow. This is a reduction of $5.9 million from the previous quarter. In May, the bank credit facility was set at $130.0 million after the annual review was completed (previously $140.0 million).

• Commodity price hedges were added with approximately 24% of current production being hedged for 2017 (there were no hedges for 2017 when first quarter results were released May 12, 2016).

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, 48 horizontal wells have been drilled (44.4 net) with 39 horizontal wells producing at the end of the second quarter (35.4 net).

Production in the second quarter was 12,852 Boe per day and NGL recovery was 35 barrels per Mmcf sales with 53% being higher priced field condensate plus pentanes recovered at the gas plant.

During the second quarter, three horizontal wells (3.0 net) started production. There is currently an inventory of nine horizontal wells (9.0 net) that have not started producing which includes three completed wells.

Storm's two operated field compression facilities have total capacity of 80 Mmcf per day raw gas with actual throughput in the second quarter averaging 67 Mmcf per day raw gas. Construction of a third field compression facility with initial capacity of 35 Mmcf per day is planned for early 2017 with start-up in April for an estimated total cost of $25.0 million with $10.9 million having been invested to date to purchase major equipment ($6.1 million in Q1 2016 and $4.8 million in 2015). The third facility is expandable to 70 Mmcf per day raw gas for an additional investment of $7.0 million.

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.

A summary of horizontal well performance and costs is provided below. The five most recent horizontal wells have averaged 5.5 Mmcf per day gross raw gas over the first 90 calendar days, a 15% improvement from the average 2014 and 2015 horizontal well. On a per-stage basis, the drill and complete cost for the most recent wells has decreased by 28% from 2014.

Year of Completion	Frac Stages	Completed Length	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
20136 wells	17	1,190 m	$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
201412 wells*	19	1,170 m	$4.6 million $240 K/stage	4.9 Mmcf/d 12 hz's	4.4 Mmcf/d 12 hz's	3.5 Mmcf/d 12 hz's
201511 wells	22	1,360 m	$4.4 million $200 K/stage	4.7 Mmcf/d 11 hz's	4.2 Mmcf/d 9 hz's	3.1 Mmcf/d 3 hz's
Q4/15 to Q1/167 wells	25	1,415 m	$4.3 million $172 K/stage	5.5 Mmcf/d 5 hz's	5.3 Mmcf/d 4 hz's

* 2014 wells exclude a middle Montney well (comparing upper Montney wells only).

The majority of future horizontal wells are expected to have greater than 1,600 metres of completed length with more than 28 frac stages while the average 2014 and 2015 wells have a completed length of 1,265 metres and an average of 21 frac stages. More information on the type curve and well economics is provided in the presentation on Storm's website.

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. Storm's 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. Cumulative production to date from this well is 5.1 Bcf raw.

HEDGING & TRANSPORTATION

Commodity price hedges are used to support longer term growth by providing some certainty regarding future revenue and funds flow. The objective is to hedge 50% of most recent monthly production for the next 12 months and 25% of most recent monthly production for 13 to 24 months forward; anticipated production growth is not hedged. Although Storm has no oil production, the WTI price is hedged as approximately 80% of NGL production is priced in reference to WTI (condensate, plant pentane and butane). A summary of commodity price hedges is provided below.

Q3 - Q4 2016
Crude Oil	800 Bopd	WTI Cdn$70.05 floor, Cdn$81.48/Bbl ceiling
Natural Gas	45,500 GJ/d (36,400 Mcf/d)	AECO Cdn$2.33/GJ ($2.91/Mcf)
	11,000 GJ/d (8,800 Mcf/d)	BC Stn 2 price = AECO - Cdn$0.34/GJ
	33,000 Mmbtu/d (27,850 Mcf/d)	Chicago price = AECO + US$0.67/Mmbtu
2017
Crude Oil	400 Bopd	WTI Cdn$62.69 floor, Cdn$68.33/Bbl ceiling
Natural Gas	20,000 GJ/d (16,000 Mcf/d)	AECO Cdn$2.52/GJ ($3.15/Mcf)
	5,000 GJ/d (4,000 Mcf/d)	BC Stn 2 price = AECO - Cdn$0.44/GJ
	35,000 Mmbtu/d (29,540 Mcf/d)	Chicago price = AECO + US$0.58/Mmbtu

Storm's strategy with respect to natural gas transportation commitments is to diversify natural gas sales by selling at Chicago, AECO and BC Station 2. Current transportation commitments total 65 Mmcf per day in 2016 and increase to 91 Mmcf per day in 2018 (interruptible capacity on the Alliance Pipeline adds up to 11 Mmcf per day in 2016 and 14 Mmcf per day in 2018). A summary is provided below and further information on pipeline tariffs and price deductions is provided in the presentation on Storm's website.

2016	2017	2018
Alliance Pipeline 46 Mmcf/d(1) Chicago price	Alliance Pipeline 51 Mmcf/d(1) Chicago price	Alliance Pipeline 55 Mmcf/d(1) Chicago price
Spectra T-north 9 Mmcf/d BC Stn 2 price	Spectra T-north 9 Mmcf/d BC Stn 2 price	Spectra T-north 26 Mmcf/d BC Stn 2 price
Marketing Arrangement 10 Mmcf/d AECO price -$0.68/GJ		Spectra T-north & TCPL 10 Mmcf/d AECO price

(1) Interruptible capacity on the Alliance Pipeline adds up to 25% of contracted capacity.

OUTLOOK

Production in the third quarter is forecast to be approximately 12,500 to 13,500 Boe per day. Capital investment in the third quarter is expected to be $8.0 to $11.0 million which includes completing and pipeline connecting three to four horizontal wells at Umbach.

When first quarter results were reported on May 12, natural gas prices in April had averaged $1.04/GJ at AECO and US$1.92/Mmbtu at Chicago, the field netback was $2.15 per Boe and production was reduced to meet firm transportation and processing commitments. In such circumstances, Storm's primary objective was to avoid increasing debt in order to preserve the ability to accelerate growth when the natural gas price improved. With the recent improvement in the natural gas price (July was $2.25/GJ at AECO and US$2.73/MMbtu at Chicago), the field netback has improved to approximately $10.00 per Boe and growth is again economically justifiable. If natural gas prices remain at this level during the second half of 2016, additional horizontal wells will be drilled and completed at Umbach and capital investment for 2016 will increase to $36.0 to $50.0 million (was $37.0 to $42.0 million). This includes $6.1 million incurred in the first quarter to purchase major equipment for the third field compression facility at Umbach where start-up is planned for April 2017. Updated guidance for 2016 and preliminary guidance for 2017 is provided below.

2016 Guidance
	May 12, 2016	Updated Aug 15, 2016
Chicago natural gas price	US$2.20/Mmbtu	US$2.40/Mmbtu(1)
AECO natural gas price	$1.60/GJ	$1.95/GJ(1)
BC STN 2 natural gas price	$1.25/GJ	$1.65/GJ(1)
Edmonton light oil price	Cdn$50/Bbl	Cdn$50/Bbl(1)
Estimated average operating costs	$7.00/Boe	$7.00/Boe
Estimated average royalty rate (% production revenue before hedging)	5% - 6%	5% - 6%
Estimated operations capital (excluding acquisitions & dispositions)	$37.0 - $42.0 million	$36.0 - $50.0 million
Estimated cash G&A net of recoveries	$5.7 million $1.20/Boe	$5.7 million $1.20/Boe
Forecast fourth quarter production	13,000 - 14,000 Boe/d (18% NGL)	13,000 - 14,000 Boe/d (18% NGL)
Forecast annual production	12,500 - 13,500 Boe/d (18% NGL)	12,500 - 13,500 Boe/d (18% NGL)
Umbach horizontal wells drilled Umbach horizontal wells completed Umbach horizontal wells connected	8 gross (8.0 net) 6 gross (6.0 net) 8 gross (8.0 net)	10 gross (10.0 net) 8 gross (8.0 net) 10 gross (10.0 net)

(1) Assumed commodity prices are approximately equal to realized prices to date and the current forward strip.

2016 Guidance History
	AECO Natural gas price	Estimated Operations Capital	Forecast Fourth Quarter Production	Forecast Annual Production
August 15, 2016	$1.95/GJ	$36.0 to $50.0 million	13,000 - 14,000 Boe/d	12,500 - 13,500 Boe/d
May 12, 2016	$1.60/GJ	$37.0 to $42.0 million	13,000 - 14,000 Boe/d	12,500 - 13,500 Boe/d
February 25, 2016	$2.00/GJ	$80.0 million	15,500 - 16,500 Boe/d	14,000 - 15,000 Boe/d
November 11, 2015	$2.50/GJ	$105.0 million	20,000 - 21,000 Boe/d	16,000 - 18,000 Boe/d
August 13, 2015	$2.80/GJ	$106.0 million	20,000 - 21,000 Boe/d	16,000 - 19,000 Boe/d

2017 Preliminary Guidance
	Aug 15, 2016
Chicago natural gas price	US$3.00 per Mmbtu
AECO natural gas price	$2.65 per GJ
BC STN 2 natural gas price	$2.25 per GJ
Edmonton light oil price	Cdn$55 per Bbl
Estimated average operating costs	$7.00 per Boe
Estimated average royalty rate (% production revenue before hedging)	7% - 9%
Estimated operations capital (excluding acquisitions & dispositions)	$80.0 million
Estimated cash G&A net of recoveries	$4.8 million $0.85 per Boe
Forecast fourth quarter production	16,000 - 18,000 Boe/d (17% NGL)
Forecast annual production	15,000 - 17,000 Boe/d (17% NGL)
Umbach horizontal wells drilled Umbach horizontal wells completed Umbach horizontal wells connected	12 gross (12.0 net) 11 gross (11.0 net) 11 gross (11.0 net)

The AECO - BC Station 2 price differential was -$0.20 per GJ in the second quarter, an improvement from the 2015 average of -$0.85 per GJ. Having the differential return to historical levels (average for 2010 to 2014 was -$0.20 per GJ) is supportive of Storm's future production growth which would be sold at BC Station 2.

Natural gas prices in North America have improved significantly over the last three months as a result of increasing demand in the United States (electric power generation, LNG exports, exports to Mexico) and flat to declining production. With rig counts at historical lows and higher debt levels preventing many producers from increasing capital investment, natural gas prices should continue improving into 2017. Longer term also appears increasingly bullish with LNG export capacity of more than 9 Bcf/d currently operating or under construction on the US Gulf Coast plus US exports to Mexico are expected to continue increasing as multiple new export pipelines and interconnections are completed over the next two years.

Although Storm's growth rate in 2016 was reduced by the deferral of activity due to very low natural gas prices in the first half of the year, production is still forecast to increase by 36% per share on a year-over-year basis. Storm's strong financial position will support planned growth in 2017 which includes the addition of a third field compression facility at Umbach with initial capacity of 35 Mmcf per day (April 2017 start-up).

The cost to drill and complete horizontal wells at Umbach has decreased by 28% on a per-stage basis since 2014. Further reductions are expected in the second half of 2016 from lower service costs and from modifying completion techniques.

At Umbach, Storm has a higher quality, liquids-rich land position in the Montney formation which is at a relatively shallow depth resulting in a lower cost to drill and complete horizontal wells. With 155 net sections, there remains room for significant future growth given that there are producing horizontal wells on only 6% of the lands (9 net sections), proved plus probable reserves are assigned on only 20% of the lands (31 net sections), and approximately 33% of the lands have been delineated to date with producing horizontal wells. The focus remains on increasing value for shareholders by converting this large resource into production and cash flow per share growth. This will come from continuing to improve well performance, finding ways to further reduce the cost to drill and complete wells, decreasing controllable cash costs (reducing third party processing fees), and maintaining a strong balance sheet to preserve the ability to accelerate growth when commodity prices are supportive of doing so.

Brian Lavergne,
President and Chief Executive Officer

August 15, 2016

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", "field netbacks", "field operating income", "total operating income", "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; 2016 and 2017 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 acquisition 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 in 2016 and 2017; reserve volumes; commodity prices; production, operating and general and administrative costs; anticipated lower costs for services; anticipated higher level of run rate cash flow associated with a larger production base; natural gas sales; and improvement on controllable cash 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 and six months ended June 30, 2016.

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.