Storm Resources Aerial

PRESS RELEASE ARCHIVES


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, 2015

Aug 13, 2015 - 17:12 ET

CALGARY, ALBERTA--(Marketwired - Aug. 13, 2015) - Storm Resources Ltd. (TSX VENTURE:SRX) -

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

Highlights



Thousands of Cdn$, except volumetric
and per-share amounts
Three Months to
June 30, 2015
Three Months to
June 30, 2014
Six Months to
June 30, 2015
Six Months to
June 30, 2014
FINANCIAL
Revenue from product sales(1) 18,461 21,701 36,972 42,508
Funds from operations(2) 8,170 11,076 21,882 19,736
Per share - basic ($) 0.07 0.10 0.20 0.19
Per share - diluted ($) 0.07 0.10 0.20 0.18
Net income (loss) (4,191 ) 6,598 (7,756 ) 6,804
Per share - basic ($) (0.04 ) 0.06 (0.07 ) 0.06
Per share - diluted ($) (0.04 ) 0.06 (0.07 ) 0.06
Operations capital expenditures 8,864 33,640 44,544 55,983
Land and property acquisitions - - - 88,051
Debt including working capital deficiency 28,051 41,837 28,051 41,837
Common shares (000s)
Weighted average - basic 113,090 109,842 112,211 105,280
Weighted average - diluted 113,090 111,998 112,211 107,197
Outstanding end of period - basic 119,355 109,925 119,355 109,925
OPERATIONS
(Cdn$ per Boe)
Revenue 21.01 43.66 21.02 44.60
Royalties (1.62 ) (4.64 ) (1.08 ) (6.04 )
Production (8.56 ) (9.41 ) (8.61 ) (10.11 )
Transportation (1.16 ) (1.83 ) (1.42 ) (1.77 )
Field operating netback 9.67 27.78 9.91 26.68
Hedging gains (losses) 2.02 (3.02 ) 5.19 (3.06 )
General and administrative (1.51 ) (1.53 ) (1.88 ) (2.19 )
Interest (0.87 ) (0.96 ) (0.79 ) (0.73 )
Funds from operations - Boe
9.31

22.27

12.43

20.70
Barrels of oil equivalent per day (6:1)
9,657

5,462

9,716

5,266
Gas Production
Thousand cubic feet per day 46,391 25,506 47,049 24,613
Price (Cdn$ per Mcf) 2.55 5.20 2.70 5.40
NGL production
Barrels per day 1,602 762 1,548 743
Price (Cdn$ per barrel) 41.23 80.57 39.25 82.47
Oil Production
Barrels per day 323 449 326 420
Price (Cdn$ per barrel) 57.58 99.27 50.29 96.40
Wells drilled
Gross - 7.0 6.0 12.0
Net - 7.0 6.0 12.0
  1. Before hedging activities.
  2. Funds from operations and funds from operations per share are non-GAAP measurements. See discussion of Non-GAAP Measurements on page 10 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 21 of the MD&A.

PRESIDENT'S MESSAGE

2015 SECOND QUARTER HIGHLIGHTS

  • During the second quarter, horizontal well performance at Umbach continued to meet or exceed expectations and there remained an inventory of nine horizontal wells (9.0 net) that had not yet started producing at the end of the quarter.
  • Production averaged 9,657 Boe per day (20% oil plus NGL), a per-share increase of 69% from the previous year. Production was reduced by approximately 2,250 Boe per day by the planned maintenance turnaround of the McMahon Gas Plant which was shut in for 28 days in June. Prior to the turnaround, production in April and May averaged 11,900 Boe per day.
  • NGL production was 1,602 barrels per day, an increase of 110% from the previous year which was the result of production growth from the liquids-rich Montney formation at Umbach where NGL recovery was 37 barrels per Mmcf sales in the quarter. The NGL price was $41.23 per barrel which was 67% of the average Edmonton light oil price (approximately 61% of the NGL mix is higher value condensate and pentanes).
  • Activity in the quarter was focused at Umbach where two new horizontal wells came on production and a condensate stabilizer plus fuel gas conditioning skid was installed at the second field compression facility.
  • Funds from operations was $8.2 million, or $0.07 per basic share, a decrease of 26% from the prior year. The decline was entirely due to declining commodity prices.
  • Funds from operations was $9.31 per Boe, a year-over-year decrease of 58% with revenue per Boe declining by 52%, or $22.59 per Boe, being partially offset by a cash hedging gain of $2.02 per Boe.
  • Controllable cash costs (operating, transportation, cash G&A and interest) were $12.10 per Boe which is a year-over-year decline of 12% or $1.63 per Boe and a decline of 9% from the previous quarter.
  • Net loss was $4.2 million, or $0.04 per share, compared to net income of $6.6 million in the previous year. Loss on the sale of the non-core Grande Prairie properties was $1.6 million.
  • Capital investment totaled $8.9 million with $8.3 million for facilities and pipelines at Umbach.
  • Debt plus working capital deficiency was reduced to $28.1 million which was 0.9 times annualized second quarter cash flow. Storm's bank credit facility is currently $140.0 million.
  • During the quarter, longer term processing commitments were increased to 54 Mmcf per day raw gas and longer term transportation commitments were increased to 51 Mmcf per day sales which represents approximately 65% of forecast production in the fourth quarter of 2015. In the second quarter, processing and transportation commitments covered approximately 40% of production.
  • A bought deal financing of common shares was completed on June 10 with 8.0 million common shares being issued at a price of $4.55 per common share. Aggregrate net proceeds of $34.2 million will ultimately be used to accelerate growth into 2016.
  • Subsequent to quarter end, the previously announced disposition of certain non-core properties in the Grande Prairie area of Alberta closed on July 15 with an effective date of July 1. Net proceeds of $23.7 million were used to reduce bank indebtedness. Second quarter production from these properties was 600 Boe per day (58% oil plus NGL).

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 ("HRB").

Umbach, Northeast British Columbia

Storm's land position at Umbach is prospective for liquids-rich natural gas from the Montney formation and currently totals 100,000 net acres (141 net sections). To date, a total of 33.4 net horizontal wells (37.0 gross) have been drilled into the Montney formation with 24.4 net being on production.

Second quarter production from Umbach was 8,616 Boe per day, a year-over-year increase of 117%. Production was reduced by approximately 2,250 Boe per day as a result of the McMahon Gas Plant being shut in for 28 days in June for a planned maintenance turnaround. NGL production was 1,565 barrels per day, an increase of 125%, and represents a recovery of 37 barrels per Mmcf sales (approximately 61% of NGL is higher priced field condensate plus pentanes recovered at the gas plant). Revenue was $20.09 per Boe ($2.56 per Mcf sales and $40.43 per barrel of NGL), transportation costs were $1.01 per Boe, royalties were $1.54 per Boe (8% of revenue), operating costs were $7.80 per Boe and the operating netback was $9.74 per Boe.

Activity in the second quarter was mainly directed toward installing a condensate stabilizer and fuel gas conditioning unit at the second field compression facility at a cost of $6.7 million. These additions will improve condensate pricing and reduce operating costs. In addition, two horizontal wells (2.0 net) started producing in the second quarter. There is currently an inventory of nine horizontal wells (9.0 net) that have not started producing which includes three completed horizontal wells and six standing horizontal wells awaiting completion (includes three horizontal wells completed to date in the third quarter).

Storm's two operated field compression facilities (both 100% working interest) have total capacity of 72 Mmcf per day raw gas with second quarter throughput totaling 42.6 Mmcf per day raw gas (54 Mmcf per day raw gas in April and May before the shut-down of the McMahon Gas Plant). It is anticipated that total capacity will be increased to 82 Mmcf per day raw gas in early October 2015 by investing $3.0 million to add a fifth compressor to the second facility.

Planning has been completed for a third field compression facility with start-up planned for early May 2016. The total cost is estimated to be $24.0 million for an initial capacity of 35 Mmcf per day raw gas which will be expandable to 70 Mmcf per day raw gas for an additional investment of $7.0 million. During 2015, $4.0 million will be invested to purchase major equipment for the third facility.

Longer term processing commitments at the McMahon and Stoddart Gas Plants have recently increased to total 54 Mmcf per day raw gas. Additionally, longer term commitments for sales pipeline capacity now total 52 Mmcf per day sales gas in 2016 after the transportation commitment on the Alliance Pipeline was recently increased 42 Mmcf per day sales gas for delivery to the Chicago market starting December 2015. The commitment on the Alliance Pipeline was made to diversify the markets where Storm's natural gas is sold which will reduce exposure to the AECO - BC Station 2 price differential which has weakened since late 2014 and has averaged -$0.54 per GJ through the first half of 2015 (current forward strip for natural gas sold at Chicago in 2016 results in a differential of $-0.28 per GJ). For reference, the differential averaged -$0.21 per GJ from 2011 to 2014. Approximately 70% of Storm's natural gas production was sold into the BC Station 2 market in the second quarter and received a lower price as a result of the wider differential. The price differential has increased as a result of unplanned maintenance outages on the TransCanada NGTL Pipeline system in Alberta combined with continued growth of natural gas production from northeast British Columbia.

As shown in the following summary, performance of the 2014 horizontal wells has shown significant improvement over earlier horizontal wells and further improvements are expected with the 2015 horizontal wells as the length and the number of frac stages are being increased. Note that calendar day rates for the 2015 horizontal wells have been reduced by the shut in of the McMahon Gas Plant for a maintenance turnaround.

Frac
Stages
IP 90 Cal Day Gross
Raw Mmcf Per Day
IP 180 Cal Day Gross
Raw Mmcf Per Day
1stYear Cal Day Gross
Raw Mmcf Per Day
2011 - 2012 hz's(7 wells) 7 - 14 1.9 Mmcf/d
345 Boe/d sales
7 hz's
1.4 Mmcf/d
255 Boe/d sales
7 hz's
1.3 Mmcf/d
235 Boe/d sales
7 hz's
2013 hz's(6 wells) 16 - 18 4.0 Mmcf/d
725 Boe/d sales
6 hz's
2.9 Mmcf/d
525 Boe/d sales
6 hz's
2.2 Mmcf/d
400 Boe/d sales
6 hz's
2014 hz's(10 wells) 16 - 20 4.7 Mmcf/d
850 Boe/d sales
10 hz's
4.9 Mmcf/d
760 Boe/d sales
10 hz's
3.7 Mmcf/d
670 Boe/d sales
5 hz's
2015 hz's(4 wells) 18 - 22 4.3 Mmcf/d
780 Boe/d sales
4 hz's
4.8 Mmcf/d
870 Boe/d sales
1 hz

Note: Sales volume is calculated using 8% shrinkage from raw gas to sales and 30 barrels of NGL per Mmcf sales.

Based on the performance of the 2013 to 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 $5.4 million to drill, complete and tie in a horizontal well with 20 to 24 frac stages and a first year average rate of 3.6 Mmcf per day raw gas, the payout is approximately 30 months and the rate of return is 27% based on $2.80 per GJ at AECO, $2.40 per GJ at BC Station 2 and Cdn $61.00 per barrel for Edmonton light oil (approximate 2016 forward strip pricing held flat for the life of the well). See the presentation on Storm's website for further details. The actual cost to drill, complete, and tie in a horizontal well with 16 to 20 frac stages averaged $4.9 million in 2014, however, for the 2015 horizontal wells, this was increased to $5.4 million as the number of frac stages is being increased to 20 to 24. These results do not recognize any reduction in service costs in 2015.

Horn River Basin, Northeast British Columbia

Storm has a 100% working interest in 119 sections in the HRB (78,000 net acres) which are prospective for natural gas from the Muskwa, Otter Park and Evie/Klua shales. Second quarter production averaged 282 Boe per day (100% natural gas), a year-over-year decline of 19%. The operating netback was $2.35 per Boe with revenue of $12.64 per Boe, transportation costs of $0.50 per Boe, an operating cost of $9.35 per Boe and a royalty of $0.45 per Boe, or 4% of revenue.

Grande Prairie Area, Northwest Alberta

Production in the second quarter was 759 Boe per day (47% oil plus NGL) and was reduced by 115 Boe per day due to a scheduled maintenance shutdown at a third party processing plant in May. In mid-January 2015, approximately 150 Boe per day was shut in as a result of the decline in the natural gas price and, on July 1, 2015, properties that produced 600 Boe per day in the second quarter were sold. The operating netback was $12.00 per Boe with revenue of $35.40 per Boe, a transportation cost of $3.19 per Boe, an operating cost of $17.22 per Boe and a royalty of $3.00 per Boe, or 9% of revenue.

There remains one property in the Grande Prairie area at Valhalla which produced 159 Boe per day in the second quarter (6% oil plus NGL).

HEDGING UPDATE

Realized cash gains in 2015 on Storm's commodity price hedges totaled $9.1 million up to the end of the second quarter. A summary of current hedges is provided below:

H2 2015 2016
Crude Oil WTI Cdn $77.25/Bbl 500 Bopd
Natural Gas AECO Cdn $3.36/GJ
($4.20/Mcf)
32,000 GJ/d
(25,600 Mcf/d)
AECO Cdn $3.00/GJ
($3.75/Mcf)
16,000 GJ/d
(13,000 Mcf/d)
Fixed AECO - Stn 2 differential at
-$0.3375/GJ on 11,000 GJ/d

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.

OUTLOOK

In the second quarter, production averaged 9,657 Boe per day which was lower than the forecast of 10,000 to 10,500 Boe per day provided with the release of first quarter results on May 13, 2015. Although production in April and May averaged 11,900 Boe per day, production in June was reduced by approximately 6,800 Boe per day due to the McMahon Gas Plant being shut in for 28 days in June for a planned maintenance turnaround. This was longer than the original expectation of 21 days and resulted in second quarter production being lower than forecast.

Production in the third quarter of 2015 is forecast to be 10,000 to 11,000 Boe per day and will depend largely on the duration and magnitude of constraints on the TransCanada NGTL pipeline system in Alberta. Production to date in the third quarter has averaged 9,000 Boe per day based on field estimates and has been impacted by unplanned restrictions on the Spectra Energy T-North Pipeline caused by restrictions on the TransCanada NGTL Pipeline system, unplanned outages and restrictions on the Alliance Pipeline and 5 days of unplanned downtime at the McMahon Gas Plant. Capital investment in the third quarter is expected to total $30.0 million with the majority directed to completing seven horizontal wells (7.0 net).

With the proceeds of the equity issue that closed in June, capital investment for 2015 is being increased to $106.0 million which will result in six more horizontal wells (6.0 net) being drilled and three more horizontal wells (3.0 net) being completed. None of these are scheduled to begin production until 2016. As a result of horizontal well performance continuing to exceed expectations, forecast production for the fourth quarter is being increased to 14,000 to 15,000 Boe per day which is a 6% increase from previous guidance after deducting 600 Boe per day for non-core property dispositions. This assumes that the restrictions on the TransCanada NGTL Pipeline system are largely eliminated by mid to late October.


2015 Guidance
November 13, 2014
Original Guidance
February 26, 2015
Revised Guidance
August 13, 2015
Revised Guidance
AECO natural gas price $3.25 per GJ $2.35 - $2.90 per GJ $2.68 per GJ
BC STN 2 natural gas price $3.00 per GJ $2.05 - $2.60 per GJ $2.01 per GJ
Edmonton light oil price Cdn$83 per Bbl Cdn$53 - $62 per Bbl Cdn$59 per Bbl
Estimated average operating costs $7.50 - $8.00 per Boe $8.00 - $8.50 per Boe $7.75 - $8.00 per Boe
Estimated average royalty rate(on production revenue before hedging) 12% - 14% 6% - 10% 7% - 8%
Estimated operations capital(excluding acquisitions & dispositions) $110.0 million $80.0 million $106.0 million
Estimated land and property acquisitions/(dispositions) $0.0 million $0.0 million ($23.7 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 - 14,500 Boe/d
(19% oil + NGL)
14,000 - 15,000 Boe/d
(18% NGL)
Forecast annual production 11,500 - 12,700 Boe/d
(19% oil + NGL)
11,000 - 12,000 Boe/d
(20% oil + NGL)
11,000 - 12,000 Boe/d
(19% oil + NGL)
Umbach horizontal wells drilled 9 gross (9.0 net) 6 gross (6.0 net) 12 gross (12.0 net)
Umbach horizontal wells completed 14 gross (14.0 net) 11 gross (11.0 net) 14 gross (14.0 net
Umbach horizontal wells starting production 16 gross (16.0 net) 14 gross (14.0 net) 14 gross (14.0 net

Capital investment is focused entirely at Umbach in 2015 and will include:

  • $67.0 million for drilling and completions;
  • $4.2 million for larger diameter gathering pipelines and the pipeline connection to the Stoddart Gas Plant;
  • $18.5 million to expand the second field compression facility from 27 to 64 Mmcf per day and install a condensate stabilizer and fuel gas conditioning unit;
  • $4.0 million to order the long-lead-time equipment for the third field compression facility.

Total debt at the end of 2015 is forecast to be $67.0 million assuming average 2015 pricing of AECO $2.68 per GJ, BC Station 2 $2.01 per GJ and Edmonton light oil Cdn$59.00 per barrel which represents actual prices to date plus current forward strip pricing for the remainder of 2015. This would be approximately 1.3 times annualized funds from operations in the fourth quarter of 2015.

Preliminary guidance for 2016 is also being provided:


2016 Guidance
August 13, 2015
Preliminary Guidance
AECO natural gas price $2.80 per GJ
BC STN 2 natural gas price $2.40 per GJ
Edmonton light oil price Cdn$61.00 per Bbl
Estimated average operating costs $7.00 - $7.50 per Boe
Estimated average royalty rate(on production revenue before hedging) 8% - 10%
Estimated operations capital(excluding acquisitions & dispositions) $106.0 million
Estimated cash G&A net of recoveries $5.6 million
Forecast fourth quarter production 20,000 - 21,000 Boe/d
(17% NGL)
Forecast annual production 16,000 - 19,000 Boe/d
(17% oil + NGL)
Umbach horizontal wells drilled
Umbach horizontal wells completed
Umbach horizontal wells starting production
12 gross (12.0 net)
15 gross (15.0 net)
17 gross (17.0 net)

Capital investment in 2016 will also be directed entirely to Umbach and will include:

  • $64.0 million for drilling and completions;
  • $24.0 million to construct a third facility which will include a condensate stabilizer for planned start-up in early May 2016.

The corporate operating cost in 2015 is expected to decline below $7.25 per Boe in the fourth quarter from $8.56 per Boe in the second quarter. This is the result of selling higher cost properties in the Grande Prairie area as well as a reduction in operating costs at Umbach which are expected to decline to $6.75 per Boe in the fourth quarter due to continued production growth, recent longer term processing commitments which have a lower associated fee, and infrastructure projects including conversion of wells to salt water disposal and adding a fuel gas conditioning unit.

Proceeds from the equity issue that closed in June are being used to increase capital investment in 2015 which will accelerate production growth in 2016. This decision is supported by forward strip pricing for 2016 (approximately AECO $2.80 per GJ) which results in a half cycle rate of return of 27% for horizontal wells drilled at Umbach. Accelerating growth is also supported by the multi-year inventory of 170 horizontals that remain to be drilled in the upper Montney on the one-third of Storm's lands which have been delineated to date. In addition, in the current business environment, the cost to drill and complete horizontal wells is expected to be lower while further expanding the infrastructure at Umbach in 2016 will increase Storm's 'head start' on competitors in the area.

With a strong balance sheet, an evolving longer term infrastructure plan at Umbach, and with the Montney at Umbach providing Storm with a competitive advantage (increased revenue from NGL recovery plus a lower drilling and completion cost from the shallower depth), Storm remains well positioned for continued rapid growth into 2016 and beyond.

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

Respectfully,

Brian Lavergne,

President and Chief Executive Officer

August 13, 2015

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

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

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

Forward-Looking Information - This press release contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words "will", "expect", "anticipate", "intend", "believe", "plan", "potential", "outlook", "forecast", "estimate" and similar expressions are intended to identify forward-looking statements or information. More particularly, and without limitation, this press release contains forward-looking statements and information concerning: production; drilling plans; capacity of facilities; installation of a condensation stabilizer and equipment; construction of a 15-kilometer pipeline; timing and construction of a third field compression facility and the purchase of equipment in connection therewith; the effect on the Company of the operations capital expenditures being reduced in 2015; 2015 guidance in respect of certain operational and financial metrics, including, but not limited to, estimated average operating costs, estimated average royalty rate, estimated operations capital, estimated land and property acquisitions costs, estimated general and administrative costs, estimated fourth quarter production, estimated annual production, estimated number of Umbach horizontal wells drilled, completed and starting production and estimated debt at end of 2015; reserve volumes; capital expenditures; royalties; financing; commodity prices; and production, operating and general and administrative costs. Statements of "reserves" are also deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

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

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

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

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.



FOR FURTHER INFORMATION PLEASE CONTACT:

Storm Resources Ltd.
Brian Lavergne
President & Chief Executive Officer
(403) 817-6145

Storm Resources Ltd.
Donald McLean
Chief Financial Officer
(403) 817-6145

Storm Resources Ltd.
Carol Knudsen
Manager, Corporate Affairs
(403) 817-6145
www.stormresourcesltd.com