Storm Resources Ltd. is Pleased to Announce its Financial and Operating Results for the Three and Nine Months Ended September 30, 2013

CALGARY, ALBERTA–(Marketwired – Nov. 14, 2013) – Storm Resources Ltd. (TSX VENTURE:SRX) –

Storm has also filed its unaudited condensed interim consolidated financial statements as at September 30, 2013 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, 2013, appears below and should be read in conjunction with the related financial statements and MD&A.

Highlights

(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 9 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

THIRD QUARTER 2013 HIGHLIGHTS

• Production averaged 3,800 Boe per day (28% oil plus NGL), an increase of 10% from the previous quarter. Compared to the same period a year ago, production was 60% higher, or 28% on a per-share basis. Forecast production for the fourth quarter remains at 4,500 to 5,000 Boe per day. Production increased as a result of growth at Umbach where production averaged 2,170 Boe per day (57% of total corporate production), an increase of 21% from the previous quarter and 425% from a year ago.

• Crude oil and NGL production averaged 1,058 barrels per day, an increase of 12% from the previous quarter. NGL production was 600 barrels per day, an increase of 24% from the previous quarter and 200% from the year earlier period. The increase in NGL production was the result of growth at Umbach where NGL recovery from the liquids-rich natural gas produced from the Montney formation was 521 barrels per day, or 53 barrels per Mmcf sales gas. The third quarter NGL price was $73.98 per barrel which was 70% of the average Edmonton Par light oil price.

• Funds from operations was $6.1 million, or $0.08 per basic share, an improvement of 21% from the previous quarter and 27% from the year ago period. Although natural gas prices decreased 22% from the previous quarter, the funds flow netback increased to $17.56 per Boe from $16.09 per Boe in the prior quarter as a result of a decrease in controllable cash costs (operating, transportation, cash G&A, interest expense). Controllable cash costs improved to $14.27 per Boe in the quarter from $16.38 per Boe in the prior quarter and $18.58 per Boe in the same period one year ago.

• The field operating netback was $20.39 per Boe excluding a hedging loss of $0.24 per Boe with operating costs decreasing by 6% from the previous quarter to $10.36 per Boe. At Umbach, operating costs were $8.60 per Boe and the operating netback was $19.14 per Boe.

• Capital investment totaled $23.7 million and major expenditures included $3.0 million to construct field gathering pipelines at Umbach and $19.3 million, also at Umbach, to drill five horizontal wells (5.0 net) and to complete and tie in four horizontal wells (3.6 net).

• Horizontal well performance at Umbach continues to improve with the first three horizontals on Storm’s 100% working interest lands averaging 4.4 Mmcf per day gross raw gas (800 Boe per day sales) over the first 30 days (operated day rates), an increase of 60% when compared to the first four horizontal wells that came on production in 2011 and 2012.

• Net loss was $1.4 million or $0.02 per basic share, an improvement from net loss of $0.07 per basic share a year earlier. The net loss was primarily due to non-cash mark-to-market losses on an investment and commodity price hedges.

• Debt plus working capital deficiency, net of investments, ended the quarter at $41.0 million which is 1.7 times annualized third quarter cash flow. In early November, Storm’s bank credit line was increased to $65.0 million from $52.0 million.

• Commodity price hedges were added subsequent to quarter end in order to ensure that commodity price fluctuations do not have a significant effect on capital investment and growth in 2014. For all of 2014, a natural gas volume of 9,000 GJ per day (approximately 7,500 Mcf per day) has a floor price of $3.31 per GJ (approximately $4.00 per Mcf). For January to June of 2014, the price of 375 barrels per day of oil was fixed at WTI Cdn $102.00 per barrel (WTI price in $US per barrel converted to $Cdn per barrel).

• Equity financings were announced October 28, 2013 whereby Storm will issue 10.1 million common shares priced at $3.35 per share for net proceeds of approximately $32.0 million. Proceeds will be used to expand 2014 capital investment and accelerate growth at Umbach. The related financings comprise a bought deal financing under a short form prospectus for 9.0 million shares and a non-brokered financing where 1.1 million shares will be issued to certain directors, officers and employees of Storm. The expected closing date for both financings is November 19, 2013.

OPERATIONS REVIEW

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

Umbach, North East British Columbia

Storm’s land position at Umbach is prospective for liquids-rich natural gas from the Montney formation and totals 112 net sections (140 gross sections), or 79,000 net acres. There are two project areas with one area consisting of 79 net sections of land at a 100% working interest and the other area consisting of 33 net sections of jointly owned lands (61 gross sections with Storm’s working interest being 60% on most of the lands). Since entering the area in 2010, Storm has invested $29.0 million to acquire this land position ($810 per hectare or $325 per acre) which includes the cost of the first horizontal well that was drilled as part of a farm-in to earn the initial 11.6 net sections.

Third quarter production grew to 2,170 net Boe per day (24% liquids) with the start of production from three horizontal wells (2.6 net) in August and September. Production in October was 2,750 Boe per day and has increased to a current level of approximately 3,600 Boe per day. NGL recovery averaged 53 barrels per Mmcf sales, or 521 barrels per day, in the third quarter with approximately 56% being condensate plus pentanes. The operating netback in the third quarter was $19.14 per Boe with revenue, after deducting transportation costs, of $31.85 per Boe ($3.14 per Mcf and $73.09 per barrel), a royalty rate of 13%, and operating costs of $8.60 per Boe. Continuing production growth from the 100% working interest lands is expected to result in operating costs decreasing by approximately $1.00 per Boe over the next six months.

Activity in the third quarter included drilling five horizontal wells (5.0 net), completing four horizontal wells (3.6 net) and installing six kilometres of 10-inch gathering pipeline. The four completed horizontal wells began producing on August 5, August 25, September 12 and October 19 respectively. To date in the fourth quarter, one horizontal well (1.0 net) has been completed and is being pipeline connected.

Storm has drilled 15 horizontal wells at Umbach (11.4 net) and has 12 producing horizontal wells (8.8 net). There are nine horizontal wells (5.4 net) on the joint lands where Storm has a 60% working interest and six horizontal wells on the 100% working interest lands. Several changes have been made to recent horizontal wells including targeting different intervals in the Montney formation and modifying the completion technique. Production performance has improved with the first three horizontals on Storm’s 100% working interest lands averaging 4.4 Mmcf per day gross raw gas (800 Boe per day sales) over the first 30 days using operated day rates (excludes days where the wells were shut in due to capacity constraints). This is an improvement of 60% when compared to the first four horizontal wells drilled on the joint lands that started producing in 2011 and 2012. Additional production history is required in order to estimate first year average rates and ultimate recovery for the most recent horizontal wells.

As a result of the transition to development in 2013 (activity in 2012 was focused on resource delineation), the total cost to drill, complete, equip and tie in a horizontal well has decreased to approximately $5.0 million from approximately $6.2 million for the first four horizontal wells. The five horizontal wells (5.0 net) drilled in third quarter of 2013 were on common pads or were drilled from existing pads and this reduced the average drill cost to $2.0 million with drilling times averaging 14 days. Four horizontal wells (3.6 net) were completed in the third quarter at an average cost of $2.4 million. Tie-in costs were $0.6 million per horizontal well (not including cost of longer gathering pipelines to connect multi-well pads to field compression facilities). Further cost reductions are expected in 2014 with a larger drilling program and with more horizontal wells being drilled from common pads which will reduce the completion cost as well as the cost to equip and tie in new wells.

Total investment in infrastructure at Umbach is forecast to be $12.0 million in 2013 which includes the acquisition of field compression for $4.5 million on April 1^st and construction of 20 kilometres of larger diameter 8 inch and 10 inch field gathering pipelines. Preliminary guidance for 2014 includes investing an additional $16.0 million for infrastructure which would include $12.0 million to construct a second field compression facility with initial capacity of 12.5 Mmcf per day expandable to 48 Mmcf per day. An additional investment of $2.0 million would be required for expansion to 24 Mmcf per day and a further $9.0 million for expansion to 48 Mmcf per day (total $11.0 million to expand to 48 Mmcf per day). This strategic investment in infrastructure provides Storm with operational control, enables significant low cost production growth into 2015, and will reduce operating costs by eliminating fees for using third party field compression.

Assuming a field netback of $20 per Boe, NGL recovery of 35 barrels per Mmcf sales (10% shrinkage), a first year average rate of 2.4 Mmcf per day gross raw gas (430 Boe per day), ultimate recovery of 4.3 Bcf gross raw gas per horizontal well and $5.0 million to drill, complete and tie in a horizontal well, Storm’s management estimates that rates of return for horizontal wells exceed 30% on an unrisked basis. This is based on flat pricing of $3.35 per GJ for natural gas and Cdn $89.00 per barrel for Edmonton Par (WTI US $93.00/Bbl). Additional enhancements to completion methods could result in further improvements to horizontal well production rates and ultimate recovery.

Horn River Basin, North East British Columbia

Storm has a 100% working interest in 135 sections in the HRB (87,700 net acres) which is prospective for natural gas from the Muskwa, Otter Park and Evie/Klua shales. Production in the third quarter averaged 335 Boe per day at an operating netback of $7.43 per Boe. Production is from one horizontal well with 12 fracture stimulations that began producing in March 2011 and is currently producing 2.4 Mmcf per day gross raw gas with cumulative production of 3.5 Bcf gross raw gas. Since the start of production, the flow rate has been restricted by the high operating pressure of the gathering pipeline (approximately 6,000 kPa). As a result, in early November, field compression was installed at a cost of approximately $0.5 million. A second horizontal well was also drilled in 2011 and is awaiting completion with the timing dependent on the natural gas price.

A resource evaluation completed by InSite Petroleum Consultants Ltd. effective December 31, 2011 estimates that the best estimate of DPIIP in the core producing area is 3.1 Tcf gross raw gas with the best estimate of contingent resources being 616 Bcf. The area that was evaluated includes 30 sections at a 100% working interest and represents 22% of Storm’s total land holdings in the HRB. Commerciality has been proven across the core producing area with a horizontal well that has been producing for 30 months plus two vertical wells that were completed and tested with final test rates of 900 Mcf per day over the final 24 hours of each flow test.

Grande Prairie Area, North West Alberta and North East British Columbia

Production in the third quarter averaged 1,294 Boe per day (41% oil plus NGL) at an operating netback of $25.16 per Boe. This is a decline of approximately 3% from the previous quarter. There was no capital invested in this area in the third quarter and no activity is planned for the fourth quarter. As a result of the relatively shallow decline, cash flow from this area will continue to be re-invested to grow production at Umbach.

OUTLOOK

Production in October was approximately 4,260 Boe per day and guidance for 2013 exit or fourth quarter production is unchanged at 4,500 to 5,000 Boe per day. The remainder of Storm’s 2013 guidance is also unchanged. Guidance for 2014 has been reviewed and approved by Storm’s Board of Directors and is provided below.

(1) Includes value of publicly listed securities.

Major expenditures in the 2014 capital investment program include:

• $55.0 million at Umbach to drill 11 horizontal wells (11.0 net) with 11 horizontal wells (10.6 net) being completed and tied in; and
• $16.0 million to expand infrastructure at Umbach, which includes $12.0 million to construct a new field compression facility expandable from initial capacity of 12 Mmcf per day to 48 Mmcf per day.

The preliminary 2014 budget assumes an average natural gas price at AECO of $3.35 per GJ and an Edmonton Par oil price of Cdn $89 per barrel. Assumed commodity prices generally reflect forward strip pricing as of October 23, 2013 and commodity price hedges are being added for 2014 so that a decrease in commodity prices does not have a significant effect on growth and guidance. Adjusted net debt is forecasted to be $50 million to $55 million at the end of 2014 (including public company investments), which would be approximately 1.0 times annualized funds from operations in the fourth quarter of 2014.

The decision to issue equity to accelerate capital investment at Umbach was primarily based on the improvement in horizontal well performance and the size of the opportunity that has been delineated to date on Storm’s 112 net sections of Montney lands. Approximately 35% of this land position has been delineated with vertical wells and 15 horizontal wells (11.4 net). With spacing of four horizontal wells per section, 140 horizontal locations remain to be drilled on the lands that have been delineated to date. In the 2012 year-end reserve report, reserves were assigned to 11.4 net horizontal drilling locations with no reserves assigned to the 100% working interest lands.

Storm’s land position in the HRB continues to be a core, long term asset with significant leverage to increased natural gas prices or to LNG development on Canada’s west coast.

Although Storm is still in the early stages of delineating a large resource in the Montney formation at Umbach, a sizable multi-year drilling opportunity has already been identified. The NGL recovered from the liquids-rich natural gas in the Montney formation provides Storm with a competitive advantage at the current natural gas price by increasing revenue and the operating netback. In addition, the relatively shallow depth (1,400 to 1,600 metres) results in a lower drilling and completion cost.

The recently announced equity issues provide funding to accelerate development at Umbach in 2014 which is forecast to result in corporate production volumes increasing by 60% over the next 12 months to 7,300 to 7,800 Boe per day. Constructing a second field compression facility expandable to 48 Mmcf per day positions Storm for further growth into 2015.

Respectfully,

Brian Lavergne, President and Chief Executive Officer

November 14, 2013

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; reserve volumes; capital expenditures; royalties; financing; commodity prices; and production, operating and general and administrative costs.

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, 2013.

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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