CALGARY, ALBERTA--(Marketwired - Nov. 11, 2015) - Storm Resources Ltd. (TSX VENTURE:SRX)

Storm has also filed its unaudited condensed interim consolidated financial statements as at September 30, 2015 and for the three and nine 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 nine months ended September 30, 2015 appears below and should be read in conjunction with the related financial statements and MD&A.

HIGHLIGHTS
Thousands of Cdn$, except volumetric and per-share amounts		Three Months to Sept. 30, 2015			Three Months to Sept. 30, 2014			Nine Months to Sept. 30, 2015			Nine Months to Sept. 30, 2014
FINANCIAL
Revenue from product sales(1)		16,283			24,902			53,256			67,410
Funds from operations(2)		7,982			11,784			29,864			31,520
	Per share - basic ($)	0.07			0.11			0.26			0.29
	Per share - diluted ($)	0.07			0.11			0.26			0.29
Net income (loss)		(961	)		5,473			(8,717	)		12,277
	Per share - basic ($)	(0.01	)		0.05			(0.08	)		0.11
	Per share - diluted ($)	(0.01	)		0.05			(0.08	)		0.11
Operations capital expenditures		19,557			30,426			64,101			86,385
Land and property acquisitions/ (dispositions)		(23,673	)		-			(23,673	)		88,075
Debt including working capital deficiency		39,994			56,157			39,994			56,157
Common shares (000s)
	Weighted average - basic	119,355			110,954			114,618			107,116
	Weighted average - diluted	119,355			112,526			114,618			108,828
	Outstanding end of period - basic	119,355			111,295			119,355			111,295
OPERATIONS
(Cdn$ per Boe)
Revenue		18.33			37.80			20.12			41.82
Royalties		(1.28	)		(5.99	)		(1.15	)		(6.02	)
Production		(7.89	)		(9.53	)		(8.37	)		(9.87	)
Transportation		(0.94	)		(1.69	)		(1.26	)		(1.74	)
Field operating netback		8.22			20.59			9.34			24.19
Hedging gains (losses)		2.22			(1.17	)		4.20			(2.29	)
General and administrative		(1.07	)		(0.98	)		(1.60	)		(1.69	)
Interest		(0.39	)		(0.56	)		(0.65	)		(0.66	)
Funds from operations - per Boe		8.98			17.88			11.29			19.55
Barrels of oil equivalent per day (6:1)		9,654			7,160			9,695			5,904
Gas Production
	Thousand cubic feet per day	47,325			33,674			47,142			27,667
	Price (Cdn$ per Mcf)	2.46			4.48			2.62			5.02
NGL production
	Barrels per day	1,697			1,154			1,598			882
	Price (Cdn$ per barrel)	33.32			73.09			37.13			78.33
Oil Production
	Barrels per day	70			394			240			412
	Price (Cdn$ per barrel)	55.93			90.31			50.84			94.44
Wells drilled
	Gross	-			3.0			6.0			15.0
	Net	-			3.0			6.0			15.0

1)	Excludes hedging gains and losses.
2)	Funds from operations and funds from operations per share are non-GAAP measurements. 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.

PRESIDENT'S MESSAGE

2015 THIRD QUARTER HIGHLIGHTS

• Production averaged 9,654 Boe per day (18% oil plus NGL), a per-share increase of 27% from the previous year. Production was reduced by approximately 2,900 Boe per day as a result of shutting in up to half of Storm's production at Umbach several times during the quarter when the natural gas price at BC Station 2 was too low and would have resulted in an unacceptably low field netback (caused by constraints and outages on the Spectra and TransCanada sales pipeline systems).
  
  
• NGL production was 1,697 barrels per day, an increase of 47% from the previous year. The price was $33.32 per barrel which was 59% of the average Edmonton light oil price (59% of the NGL volume was higher value condensate and plant pentanes). The NGL price was reduced by the negative price for propane (-$8.18 per barrel) which affected 17% of the NGL volume.
  
  
• Activity was focused at Umbach where four horizontal wells were completed and a fifth compressor was installed at the second field compression facility to increase capacity by 10 Mmcf per day (total field compression capacity at Umbach is now 82 Mmcf per day).
  
  
• Controllable cash costs (operating, G&A, and interest) were $9.35 per Boe which is a year-over-year decline of $1.72 per Boe, or 16%, and a decline of 15% from the previous quarter. Transportation cost is not included as recent natural gas marketing arrangements deduct the pipeline tariff from revenue which artificially reduces the transportation cost.
  
  
• Funds from operations was $8.98 per Boe, a year-over-year decrease of $8.90 per Boe, or 50%. Revenue declined by $19.47 per Boe which was partially offset by a cash hedging gain of $2.22 per Boe.
  
  
• Funds from operations was $8.0 million, or $0.07 per basic share, a decrease of 32% from the prior year. Higher production and the improvement in controllable cash costs was more than offset by the realized commodity price decreasing by 52% from the previous year.
  
  
• Operations capital investment was $19.6 million with $10.0 million for completions and $8.5 million for facilities plus pipelines.
  
  
• Debt plus working capital deficiency was $40.0 million which is 1.2 times annualized third quarter cash flow. Storm's bank credit facility is currently $140.0 million.
  
  
• The previously announced disposition of certain non-core properties in the Grande Prairie area of Alberta closed on July 15 (second quarter production from these properties was 600 Boe per day) with net proceeds of $23.7 million being used to reduce bank indebtedness.
  
  

OPERATIONS REVIEW

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

Umbach, Northeast British Columbia

Storm's land position at Umbach is prospective for liquids-rich natural gas from the Montney formation and currently totals 107,000 net acres (153 net sections). To date, a total of 34.4 net horizontal wells (38.0 gross) have been drilled into the Montney formation with 28.4 net being on production.

Third quarter production from Umbach was 9,332 Boe per day and represented 97% of corporate production in the quarter. NGL recovery was 37 barrels per Mmcf sales (59% of the NGL volume is higher priced field condensate plus pentanes recovered at the gas plant). Revenue was $18.14 per Boe ($2.46 per Mcf sales and $33.38 per barrel of NGL), transportation costs were $0.87 per Boe, royalties were $1.28 per Boe (7% of revenue), operating costs were $7.80 per Boe, and the operating netback was $8.19 per Boe.

Activity in the third quarter was mainly directed toward completing four horizontal wells and installing a fifth compressor at the second field compression facility. Three of the completed horizontal wells were part of a five well pad (infills) and the fourth completion was a single well pad (step-out to the south and east). In the fourth quarter, an additional five horizontal wells (two step-outs and three infills on the same pad) were completed in October, a single horizontal well will be completed in December (step-out to the west), and four horizontal wells (infills) will be drilled.

With the addition of the fifth compressor at the second facility (cost of $3.0 million), Storm's two operated field compression facilities (both 100% working interest) have current total capacity of 82 Mmcf per day raw gas. Actual throughput in the third quarter averaged 49 Mmcf per day raw gas. Timing to start up the third field compression facility is unchanged from early May 2016 with the total cost estimated to be $25.0 million for initial capacity of 35 Mmcf per day raw gas (expandable to 70 Mmcf per day raw gas by investing an additional $7.0 million). During 2015, $4.1 million will be invested 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.

As shown in the following summary, performance of the 2014 horizontal wells has shown significant improvement over earlier horizontal wells. Further improvement is expected from the 2015 horizontal wells as the length and the number of frac stages have been increased; however, production data to date has been impacted by the significant downtime experienced since June.

	Frac Stages		IP 90 Cal Day Gross Raw Mmcf Per Day	IP 180 Cal Day Gross Raw Mmcf Per Day	1st Year Cal Day Gross Raw Mmcf Per Day
2011 - 2012 hz's (7 wells)	7 - 14		1.9 Mmcf/d 340 Boe/d sales 7 hz's	1.4 Mmcf/d 250 Boe/d sales 7 hz's	1.3 Mmcf/d 230 Boe/d sales 7 hz's
2013 hz's (6 wells)	16 - 18		4.0 Mmcf/d 715 Boe/d sales 6 hz's	2.9 Mmcf/d 520 Boe/d sales 6 hz's	2.2 Mmcf/d 395 Boe/d sales 6 hz's
2014 hz's (10 wells)	16 - 20		4.7 Mmcf/d 840 Boe/d sales 10 hz's	4.2 Mmcf/d 750 Boe/d sales 10 hz's	3.8 Mmcf/d 680 Boe/d sales 7 hz's
2015 hz's (9 wells)	17 - 24		4.2 Mmcf/d 750 Boe/d sales 5 hz's	3.9 Mmcf/d 700 Boe/d sales 4 hz's

Note: Sales volume is calculated using 10% shrinkage from raw gas to sales and 32 barrels of NGL per Mmcf sales.

To date in 2015, the cost to drill and complete a horizontal well has averaged $4.6 million for an average of 22 frac stages. This is a 14% decrease in the cost per frac stage from the average cost of $4.6 million for the 2014 horizontal wells which had an average of 19 frac stages.

Based on the performance of the 2014 horizontal wells, Storm management is using a 6.3 Bcf raw gas type curve for internal budgeting purposes (this type curve has the same decline profile as the 3.2 and 4.4 Bcf raw gas 2P type curves used by InSite in the 2014 reserve evaluation). Using a cost of $4.9 million to drill, complete and tie in a horizontal well, and a first year average rate of 3.6 Mmcf per day raw gas, the payout is approximately 22 months and the rate of return is 38% based on $3.00 per GJ at AECO, $2.65 per GJ at BC Station 2 and Cdn $62.00 per barrel for Edmonton light oil. Expected longer term commodity prices were used with pricing then 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. Third quarter production averaged 137 Boe per day (100% natural gas) with production being shut in at the end of July due to the low natural gas price at BC Station 2. The operating netback was ($0.16) per Boe with revenue of $11.82 per Boe, transportation costs of $0.49 per Boe, an operating cost of $11.07 per Boe and a royalty of $0.42 per Boe, or 4% of revenue.

Grande Prairie Area, Northwest Alberta

Production in the quarter was 185 Boe per day (45% oil plus NGL). The majority of the properties in this area were sold on July 15 and there remains only the Valhalla property which has been shut in as a result of the decline in the natural gas price (capable of producing 300 Boe per day).

HEDGING AND MARKETING

Realized cash gains in 2015 on Storm's commodity price hedges totaled $11.1 million to the end of the third quarter. A summary of current price hedges is provided below.

		Q4 2015			2016
Crude Oil					WTI Cdn $75.00/Bbl floor WTI Cdn $90.75/Bbl ceiling	500 Bopd
Natural Gas		AECO Cdn $3.36/GJ ($4.20/Mcf)	35,670 GJ/d (28,500 Mcf/d)		AECO Cdn $2.98/GJ ($3.72/Mcf)	21,250 GJ/d (17,000 Mcf/d)

Although Storm has no oil production, the WTI hedge protects condensate and plant pentanes revenue which are priced in reference to WTI.

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 current production (most recent monthly or quarterly average), before royalties, will be hedged; anticipated production growth is not hedged.

Storm's marketing commitments are summarized below. These do not fix the price but show the price differentials and transportation cost.

		Q4 2015		2016
		Physical sale at McMahon Gas Plant 4,300 GJ/d Chicago monthly or daily price minus Alliance pipeline toll Cdn$1.40/GJ		Physical sale at McMahon Gas Plant 18,200 GJ/d Chicago monthly or daily price minus Alliance pipeline toll Cdn$1.40/GJ
Natural Gas		Physical sale at McMahon Gas Plant 13,400 GJ/d AECO +US$0.79/Mmbtu minus Alliance pipeline toll Cdn$1.40/GJ		Physical sale at McMahon Gas Plant 34,800 GJ/d AECO +US$0.67/Mmbtu minus Alliance pipeline toll Cdn$1.40/GJ
		Physical sale at BC Stn 2 12,800 GJ/d AECO -$0.78/GJ minus Spectra T-north pipeline toll Cdn$0.17/GJ		Physical sale at BC Stn 2 11,000 GJ/d AECO -$0.34/GJ minus Spectra T-north pipeline toll Cdn $0.17/GJ
		Physical sale at McMahon Gas Plant 11,400 GJ/d AECO -$0.22/GJ		Physical sale at McMahon Gas Plant 10,300 GJ/d AECO -$0.68/GJ

OUTLOOK

In the third quarter, production averaged 9,654 Boe per day which was lower than the forecast of 10,000 to 11,000 Boe per day provided with the release of second quarter results on August 13, 2015. Production was reduced by approximately 2,900 Boe per day as a result of shutting in production for several periods where the BC Stn 2 natural gas price was very low (the daily spot price averaged $1.22 per GJ from August 7 to 12, $0.75 per GJ from August 24 to September 4, and $0.72 per GJ from September 22 to 30). This was caused by constraints on the TransCanada and Spectra sales pipeline systems which reduced takeaway capacity from British Columbia and increased volumes being sold at BC Station 2. During periods where the natural gas price at BC Station 2 results in an unacceptably low field netback, Storm has reduced production to equal the volume of natural gas that is hedged (incremental volumes above what is hedged receive the BC Station 2 daily spot price).

Production in the fourth quarter of 2015 is forecast to be 10,000 to 12,000 Boe per day and will depend largely on constraints on the TransCanada pipeline system in Alberta and their impact on the daily spot natural gas price at BC Station 2. Production to date in the fourth quarter has averaged 8,900 Boe per day based on field estimates with approximately 3,900 Boe per day shut in during October due to the BC Station 2 natural gas price averaging $0.97 per GJ as a result of continued constraints on the TransCanada sales pipeline system.

Revised guidance for 2015 is provided below with the major revisions being reductions to forecast commodity prices and forecast production plus a reduction in capital investment due to lower service costs and the drilling of two horizontal wells being deferred to 2016.

2015 Guidance		Original Guidance November 13, 2014		Revised August 13, 2015		Revised November 11, 2015
AECO natural gas price		$3.25 per GJ		$2.68 per GJ		$2.60 per GJ
BC STN 2 natural gas price		$3.00 per GJ		$2.01 per GJ		$1.87 per GJ
Edmonton light oil price		Cdn$83 per Bbl		Cdn$59 per Bbl		Cdn$58 per Bbl
Estimated average operating costs		$7.50 - $8.00 per Boe		$7.75 - $8.00 per Boe		$7.75 - $8.00 per Boe
Estimated average royalty rate (on production revenue before hedging)		12% - 14%		7% - 8%		6% - 7%
Estimated operations capital (excluding acquisitions & dispositions)		$110.0 million		$106.0 million		$92.0 million
Estimated land and propertyacquisitions/(dispositions)		$0.0 million		($23.7 million)		($19.3 million)
Estimated cash G&A net of recoveries		$5.3 million		$5.3 million		$5.3 million
Forecast fourth quarter production		14,000 - 14,500 Boe/d (18% oil + NGL)		14,000 - 15,000 Boe/d (18% NGL)		10,000 - 12,000 Boe/d (18% NGL)
Forecast annual production		11,500 - 12,700 Boe/d (19% oil + NGL)		11,000 - 12,000 Boe/d (19% oil + NGL)		10,000 - 11,000 Boe/d (19% oil + NGL)
Umbach horizontal wells drilled		9 gross (9.0 net)		12 gross (12.0 net)		10 gross (10.0 net)
Umbach horizontal wells completed		14 gross (14.0 net)		14 gross (14.0 net)		13 gross (13.0 net)
Umbach horizontal wells starting prod'n		16 gross (16.0 net)		14 gross (14.0 net)		13 gross (13.0 net)

Capital investment in 2015 is focused entirely on the Umbach area with $50.0 million for drilling and completions plus $34.0 million to expand infrastructure (including $4.1 million to order long-lead-time equipment for the third field compression facility).

Guidance for 2016 has been finalized and is shown below.

2016 Guidance	November 11, 2015
AECO natural gas price	$2.50 per GJ
BC STN 2 natural gas price	$1.90 per GJ
Edmonton light oil price	Cdn$57.00 per Bbl
Estimated average operating costs	$7.00 - $7.50 per Boe
Estimated average royalty rate (on production revenue before hedging)	7% - 8%
Estimated operations capital (excluding acquisitions & dispositions)	$105.0 million
Estimated cash G&A net of recoveries	$5.0 million
Forecast fourth quarter production	20,000 - 21,000 Boe/d (17% NGL)
Forecast annual production	16,000 - 18,000 Boe/d (17% oil + NGL)
Umbach horizontal wells drilled	14 gross (14.0 net)
Umbach horizontal wells completed	14 gross (14.0 net)
Umbach horizontal wells starting prod'n	16 gross (16.0 net)

Capital investment in 2016 will be directed entirely to Umbach and will include $63.0 million for drilling and completions plus $34.0 million for infrastructure (remaining $21.0 million for the third field compression facility). With this level of investment, total debt at the end of 2016 is forecast to be $105.0 million which would be approximately 1.5 times annualized funds from operations in the fourth quarter of 2016.

Note that capital investment in 2016 of $105.0 million per the above table is based on a daily spot natural gas price of $1.90 per GJ at BC Station 2. Storm's incremental growth volumes receive the BC Station 2 daily spot price and, should the price be materially below this level, capital investment in 2016 for infrastructure plus drilling and completions may be delayed which would reduce forecast production. This is consistent with what has been done since the BC Station 2 price began weakening in July 2015 which resulted in production being shut in plus drilling and completions being deferred as capital investment is contingent on achieving a minimum netback or rate of return. If necessary, Storm can reduce capital investment to $50.0 to $55.0 million which would result in forecast production being maintained at 14,000 to 15,000 Boe per day throughout 2016 (using the current forward strip, debt at the end of 2016 would be unchanged from the end of 2015). Approximately 95% of this level of production would be covered by Storm's pipeline commitments and marketing arrangements and would not be exposed to the BC Station 2 daily spot price.

Although constraints on the TransCanada sales pipeline system have continued into the fourth quarter, which has continued to depress the BC Station 2 natural gas price, the impact on Storm will be diminished going forward as a result of firm pipeline commitments and marketing agreements which cover 59 Mmcf per day sales in 2016 (67 Mmcf per day including interruptible service on the Alliance Pipeline) and increases to 88 Mmcf per day sales in 2018 (98 Mmcf per day including interruptible service on the Alliance Pipeline). For comparison, in 2015, transportation commitments totaled 22 Mmcf per day sales. Natural gas sales will also be more diversified as, using forecast natural gas production for 2016, approximately 18% will be sold in Chicago at the daily spot or monthly index price (through the Alliance Pipeline), 33% sold in Chicago at the AECO monthly index price plus $0.67 USD per Mmbtu (through the Alliance Pipeline), 11% sold at BC Station 2 at the AECO monthly index less $0.34 per GJ, 10% sold at the McMahon Gas Plant at the AECO monthly index less $0.68 per GJ, and the remaining 28% will be sold at BC Station 2 at the daily spot price. To ensure that the firm pipeline commitments and marketing arrangements can be met, there are also firm processing commitments which total 65 Mmcf per day raw gas in 2016.

Controllable cash costs (operating, G&A, and interest) have averaged $10.62 per Boe to date in 2015 which is a 7% improvement when compared to $11.43 per Boe in 2014. Previously, Storm included transportation costs in controllable cash costs; however, this is being removed because recent marketing arrangements result in pipeline tariffs being deducted from the sales price which artificially reduces transportation costs. Further improvement in controllable cash costs on a per-Boe basis is expected given that operating costs will decrease as a result of continued production growth, recent longer term processing commitments with lower associated fees, and recent investments in infrastructure at Umbach (conversion of a second well to salt water disposal and adding a fuel gas conditioning unit).

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.

Respectfully,

Brian Lavergne, President and Chief Executive Officer

November 11, 2015

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; installation of a condensation stabilizer and equipment; 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; 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 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 2015 and 2016; 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; anticipated impact on Storm of constraints on the TransCanada sales pipeline system; 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 nine months ended September 30, 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.

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