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 Months and Year Ended December 31, 2013

Mar 6, 2014 - 19:20 ET

CALGARY, ALBERTA--(Marketwired - March 6, 2014) - Storm Resources Ltd. (TSX VENTURE:SRX)

Storm has also filed its audited consolidated financial statements as at December 31, 2013 and for the three months and year then ended along with Management's Discussion and Analysis ("MD&A") for the same periods. This information appears on SEDAR at www.sedar.com and on Storm's website at www.stormresourcesltd.com.

Selected financial and operating information for the three months and year ended December 31, 2013, as well as reserve information at December 31, 2013, appears below and should be read in conjunction with the related financial statements and MD&A.

Highlights

Thousands of Cdn$, except volumetric and per share amounts Three Months Ended December 31, 2013 Three Months Ended December 31, 2012 Year Ended December 31, 2013 Year Ended December 31, 2012
FINANCIAL
Gas sales 7,807 3,416 21,019 8,054
NGL sales 4,483 1,597 13,124 4,466
Oil sales 3,090 5,399 15,435 19,793
Revenue from product sales(1) 15,380 10,412 49,578 32,313
Funds from operations(2) 7,501 5,016 21,949 13,387
Per share - basic ($) 0.09 0.08 0.30 0.24
Per share - diluted ($) 0.09 0.08 0.30 0.24
Net loss (25,174 ) (2,320 ) (26,203 ) (6,574 )
Per share - basic ($) (0.34 ) (0.04 ) (0.36 ) (0.12 )
Per share - diluted ($) (0.34 ) (0.04 ) (0.36 ) (0.12 )
Adjusted net income (loss) before reduction in carrying amount of property and equipment
826

(2,320
)
(203
)
(6,574
)
Per share - basic and diluted ($) 0.01 (0.04 ) 0.00 (0.12 )
Operations capital expenditures 11,380 10,016 67,410 26,868
Acquisitions and dispositions - (1,239 ) (14,966 ) 139,208
Debt including working capital deficiency 12,059 44,696 12,059 40,376
Weighted average common shares outstanding (000s)
Basic 81,994 61,824 73,391 56,067
Diluted 81,994 61,824 73,391 56,067
Common shares outstanding (000s)
Basic 87,483 61,824 87,483 61,824
Fully diluted 91,379 64,547 91,379 64,547
OPERATIONS
Oil equivalent (6:1)
Barrels of oil equivalent (000s) 439 259 1,328 825
Barrels of oil equivalent per day 4,773 2,815 3,637 2,254
Average selling price (Cdn$ per Boe)(1) 35.03 40.19 37.34 39.14
Gas production
Thousand cubic feet (000s) 2,015 987 5,783 3,053
Thousand cubic feet per day 21,898 10,728 15,843 8,342
Average selling price (Cdn$ per Mcf) 3.88 3.46 3.63 2.64
NGL Production
Barrels (000s) 64 25 187 67
Barrels per day 695 274 512 185
Average selling price (Cdn$ per barrel) 70.10 63.27 70.29 66.17
Oil Production
Barrels (000s) 39 69 177 249
Barrels per day 428 753 485 679
Average selling price (Cdn$ per barrel)(1) 78.47 77.93 87.16 79.53
Wells drilled
Gross 1.0 2.0 9.0 6.0
Net 1.0 1.2 8.6 4.4

(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 16 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 26 of the MD&A.

President's Message

2013 FOURTH QUARTER AND YEAR-END HIGHLIGHTS

  • Production for the year averaged 3,637 Boe per day (27% oil plus NGL) which represents an increase of 61% from 2012. Fourth quarter production was 4,773 Boe per day (24% oil plus NGL), a year-over-year increase of 70%. On a per-share basis, fourth quarter production increased 20% from the previous year while debt decreased by 70%, or $28.3 million. Increased production was the result of growth at Umbach where production averaged 3,262 Boe per day in the fourth quarter of 2013, a 480% increase from 564 Boe per day in the fourth quarter of 2012.

  • NGL production averaged 695 barrels per day in the fourth quarter, an increase of 154% from the fourth quarter of 2012. NGL production increased as a result of production growth from the liquids-rich Montney formation at Umbach. With condensate and pentane being approximately 60% of the NGL mix, the fourth quarter NGL price of $70.10 per barrel was 81% of the average Edmonton Par light oil price.

  • Activity in 2013 was focused at Umbach where eight Montney horizontal wells (7.6 net) plus one Montney vertical delineation well (1.0 net) were drilled and seven horizontal wells (6.2 net) were completed and pipeline connected. In the fourth quarter, one Montney horizontal well (1.0 net) was drilled, one Montney horizontal well (1.0 net) was completed and two Montney horizontal wells (2.0 net) were pipeline connected.

  • On Storm's 100% working interest lands at Umbach, five horizontal Montney wells (5.0 net) were drilled with rates over the first 90 operated days (excluding days shut in) averaging 3.7 Mmcf per day gross raw gas which is equivalent to 670 Boe per day sales. This is an improvement of 70% when compared to earlier horizontal wells drilled in 2010 and 2011.

  • Funds from operations for the year totaled $21.9 million, an increase of 64% from the previous year. Funds from operations in the fourth quarter was $7.5 million or $0.09 per basic share, an increase of 12% from $0.08 per basic share in the prior year. The increase in funds from operations was the result of significant production growth at Umbach.

  • The funds from operations netback was $16.52 per Boe in 2013, an increase of 2% from the previous year. The funds from operations netback improved to $17.08 per Boe in the fourth quarter.

  • The field operating netback excluding hedging gains or losses was $20.43 per Boe for the full year and increased to $20.82 per Boe in the fourth quarter.

  • Operating costs improved throughout the year. The full year operating cost of $10.86 per Boe was 5% lower than the previous year while the fourth quarter operating cost of $9.73 per Boe was 17% lower than the fourth quarter of 2012. Improving operating costs are the result of production growth at Umbach where operating costs were $8.73 per Boe in 2013 which was lower than the corporate average of $10.86 per Boe.

  • Controllable cash costs (operating, transportation, cash G&A, interest expense) declined to $16.24 per Boe in 2013 from $19.83 per Boe in the prior year. Controllable cash costs showed further improvement to average $15.38 per Boe in the fourth quarter. The largest improvement was with cash G&A which decreased $1.52 per Boe to average $2.98 per Boe during 2013.

  • Capital investment was $11.4 million in the fourth quarter and $52.4 million for the year, net of dispositions. Investment in 2013 was focused on exploitation of the Montney formation at Umbach including $14.0 million for infrastructure, $15.0 million to acquire undeveloped land and $36.0 million for drilling and completions. Dispositions in 2013 totaled $19.5 million from the sale of non-core properties early in 2013.

  • Debt plus working capital deficiency, net of investments, ended the year at $12.1 million which is 0.4 times annualized fourth quarter cash flow. In November 2013, Storm's bank credit line was increased to $65.0 million from $52.0 million.

  • Total proved ("1P") reserves increased 50% to 20,764 Mboe with the all-in cost for additions being $13.19 per Boe. Total proved plus probable ("2P") reserves increased 48% to 40,541 Mboe with the all-in cost for additions being $9.79 per Boe. The increase in 1P and 2P reserves was the result of continued delineation drilling in the upper Montney formation at Umbach.

  • Better than expected horizontal well performance resulted in PDP reserves at Umbach being revised higher by 439 Mboe.

  • Additions to 2P reserves replaced 910% of 2013 production.

  • Recycle ratio was 2.1 for 2P reserve additions using the all-in cost for reserve additions and the 2013 field operating netback of $20.43 per Boe excluding hedging gains or losses.

  • Cost of adding production during 2013 was $17.22 per Boe for proved developed producing reserves ("PDP") on an all-in basis and was approximately $20,000 per Boe per day using 2013 capital investment of $52.4 million and production additions of 2,600 Boe per day (average fourth quarter rate from wells starting production in 2013).

  • Subsequent to year end, Storm closed the acquisition of a 100% working interest in 29 sections of land in the Umbach-Nig area, prospective for liquids rich natural gas from the Montney formation. The acquisition included two horizontal wells producing 359 Boe net per day (19% NGL) from the Montney formation. Total cost of $87.9 million consisted of $30.0 million in cash and 13.6 million common shares of Storm with a deemed value of $4.25 per common share (closing price on the TSX Venture Exchange January 30, 2014). The cash portion was funded with $34.8 million of gross proceeds from a bought deal financing and non-brokered private placement of common shares which closed on February 14, 2014 (8.5 million common shares were issued at a price of $4.10 per common share).

OPERATIONS REVIEW

Storm has a focused asset base with large land positions in resource plays at Umbach and in the HRB which have multi-year drilling upside while the Grande Prairie area, with its shallow decline, provides cash flow available for investment.

Umbach, Northeast British Columbia

Storm's land position at Umbach is prospective for liquids-rich natural gas from the Montney formation and currently totals 140 net sections (168 gross sections) or 98,000 net acres. There are three project areas at Umbach:

  • Umbach South with 87 net sections at a 100% working interest (includes the 29 sections recently acquired) where fourth quarter production averaged 2,293 Boe per day.

  • Umbach North with 33 net sections of jointly owned lands (61 gross sections with Storm's working interest being 60% on most of the lands) where fourth quarter production average 969 Boe per day.

  • Nig with 20 net sections at a 100% working interest.

To date, Storm has been focused on exploiting the upper Montney although the middle and lower Montney may also be productive. Since entering the area in 2010, and including the lands acquired in January 2014, Storm has invested $108 million to acquire this land position ($2,750 per hectare or $1,100 per acre).

Production at Umbach grew to 3,262 net Boe per day (18% liquids) in the fourth quarter as a result of five Montney horizontal wells (4.6 net) that started production during August to November. Fourth quarter NGL recovery was 40 barrels per Mmcf sales or 629 barrels per day with approximately 60% being higher priced condensate plus pentanes. The operating netback in the fourth quarter was $21.74 per Boe with revenue, after deducting transportation costs, of $31.10 per Boe ($3.52 per Mcf sales and $67.49 per barrel of NGL), a royalty rate of 3%, and operating costs of $8.36 per Boe. Continuing production growth from the 100% working interest lands at Umbach South is expected to result in operating costs decreasing to approximately $7.00 per Boe in 2014.

Activity in the fourth quarter included converting a standing vertical well to a water disposal well, drilling one Montney horizontal well (1.0 net), completing one Montney horizontal well (1.0 net), and pipeline connecting two Montney horizontal wells (2.0 net) which started producing on October 19th and November 19th. To date in the first quarter, two Montney horizontal wells (2.0 net) have been drilled and two Montney horizontal wells have been completed with one starting production in late February.

A total of 18 horizontal wells have been drilled in the upper Montney at Umbach (14.4 net) and there are 14 producing horizontal wells (10.8 net). Production performance has continued to improve based on a comparison of operated day rates over the first 30 and 90 days (operated day rates exclude days where wells were shut in due to capacity constraints):


Start of Production

Frac
Stages
30-Day Average
Mmcf Per Day
90-Day Average
Mmcf Per Day
1st Year Average
Mmcf Per Day
Hz's 1 - 5 60% WI Umbach North Mar/11 - Oct/12 7 - 11 2.7 Mmcf/d
5 hz's
2.1 Mmcf/d
5 hz's
1.4 Mmcf/d
5 hz's
Hz's 6 - 8 60% WI Umbach North Nov/12 - Aug/13 14 - 16 3.3 Mmcf/d
3 hz's
2.8 Mmcf/d
3 hz's
not available
Hz's 10 - 14 100% WI Umbach South Apr/13 - Nov/13 17 - 18 4.2 Mmcf/d
5 hz's
3.7 Mmcf/d
3 hz's
not available

Comparing operated day rates over 30 and 90 days and using the InSite Petroleum Consultant Ltd. ("InSite") 2P type curve used in the 2013 year-end reserve evaluation, Storm management estimates that the most recent horizontal wells (10 to 14) will average 2.4 Mmcf per day in the first year with ultimate recovery of 4.4 Bcf.

Cost to drill and complete horizontal wells in 2013 averaged $4.6 million with the drilling cost averaging $2.2 million and the completion cost averaging $2.4 million. Tie-in costs have been approximately $0.5 million per horizontal well, not including cost of longer gathering pipelines to connect multi-well pads to field compression facilities. A decrease in costs is anticipated in 2014 with a larger program and with more horizontal wells being drilled from common pads.

Total investment in infrastructure in 2013 at Umbach was approximately $12.6 million which included the acquisition of field compression for $4.5 million plus construction of 18 kilometres of larger diameter 8-inch and 10-inch field gathering pipelines. In 2014, an additional $19.0 million will be invested in infrastructure which includes $5.0 million for larger diameter gathering pipelines plus $14.0 million to construct a second field compression facility with an initial capacity of 24 Mmcf per day. Capacity of the new field compression facility is expandable to 48 Mmmcf per day for an additional investment of $9.0 million with this expected to occur in 2015.

At pricing of $3.50 per GJ for natural gas and Cdn$89.00 per barrel for Edmonton Par (WTI US$93.00/Bbl, FX Cdn$0.92), the estimated field netback is $21.00 per Boe. With this pricing held constant, Storm management estimates that horizontal wells have an unrisked half cycle rate of return of 37% (1.9 years to payout) based on a first year average rate of 2.4 Mmcf per day gross raw gas (430 Boe per day), ultimate recovery of 4.4 Bcf gross raw gas per horizontal well, NGL recovery of 35 barrels per Mmcf sales (10% shrinkage), and $5.0 million to drill, complete and tie in a horizontal well.

On January 31, 2014, Storm closed the acquisition of two producing Montney horizontal wells and 29 sections of undeveloped land for a total cost of $87.9 million. The allocation of the purchase price was $61.5 million for nine sections with production, reserves and 35 horizontal drilling locations, and $26.4 million for the remaining 20 sections ($4,700 per hectare or $1,880 per acre). Highlights of the acquisition are as follows:

  • A 100% working interest was acquired in the lands and two producing horizontal wells (one upper Montney and one lower Montney).

  • Production from the two horizontal wells totaled 359 Boe per day (NGL recovery 38 bbls per Mmcf sales) in the third quarter of 2013 with the majority from the C-42-A horizontal well which has produced 1.4 Bcf to date from the upper Montney with the current rate being 1.6 Mmcf per day gross raw gas (295 Boe per day sales).

  • The acquired lands are contiguous with Storm's Umbach South lands where five Montney horizontal wells (5.0 net) were drilled and commenced production in 2013 from the upper Montney with rates averaging 4.3 Mmcf per day gross raw gas over the first 30 operating days and 3.7 Mmcf per day gross raw gas over the first 90 operating days (operating day rate excludes days shut in).

  • The upper Montney formation is the primary target based on results to date in the area; however, Storm management believes that the middle Montney may also be productive across the acquired lands.

  • Storm management estimates DPIIP of 1.6 Tcf in the upper Montney formation on the acquired lands based on data from existing wells on the 29 sections (seven vertical wells plus two Montney horizontal wells) indicating that the upper Montney formation is 52 metres thick, has average porosity of 6% and a reservoir pressure of 18,000 to 23,000 kPa.

  • Two to three horizontal wells will be drilled in the upper Montney on the acquired lands in 2014 with additional wells being planned for 2015.

Horn River Basin, Northeast British Columbia

Storm has a 100% working interest in 123 sections in the HRB (81,000 net acres) which is prospective for natural gas from the Muskwa, Otter Park and Evie/Klua shales. Fourth quarter production averaged 363 Boe per day at an operating netback of $11.59 per Boe. Wellsite compression was installed in November 2013 and production has increased to average 400 Boe per day to date in the first quarter of 2014. Production is from one horizontal well with 12 fracture stimulations which currently produces 2.7 Mmcf per day gross raw gas with cumulative production of 3.8 Bcf gross raw gas since start-up in March 2011. A second horizontal well was also drilled in 2011 and is awaiting completion with timing dependent on natural gas pricing.

A resource evaluation completed by InSite 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 evaluated area 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, Northwest Alberta and Northeast British Columbia

Production in the fourth quarter averaged 1,147 Boe per day (44% oil plus NGL) at an operating netback of $21.65 per Boe. No capital was invested in this area in the fourth quarter and minimal activity is planned during 2014. Cash flow from this area will continue to be re-invested to grow production at Umbach.

HEDGING UPDATE

Current commodity price hedges for 2014 include 11,500 Mcf per day (14,000 GJ per day) of natural gas with an average floor price of approximately $4.12 per Mcf and an average ceiling price of $4.34 per Mcf (AECO monthly index $3.39 per GJ for floor and $3.57 per GJ for ceiling). In addition, an oil price of WTI Cdn$101.89 per barrel (WTI price in $US per barrel converted to $Cdn per barrel) has been fixed on 338 barrels per day. It is likely that this hedge position will be expanded with the objective of ensuring that a decrease in commodity prices does not have a significant impact on capital investment and growth over the next 12 to 18 months.

COMPARISON OF 2013 RESULTS VERSUS GUIDANCE

Shown below is a comparison of Storm's actual 2013 results to guidance provided during 2013.

2013 Actual Results 2013 Guidance
November 14, 2013
2013 Guidance
May 15, 2013
2013 Guidance February 28, 2013
Year-end adjusted debt plus working capital deficiency(1)
$12.1 million

$40.0 million

$37.0 million

$44.0 million
Average operating costs $10.86 per Boe $10 - $11/Boe $10 - $11/Boe $10 - $11/Boe
Average royalty rate (on revenue before hedging)
12.2
%
14
%
13% - 14
%
11% - 12
%
Operations capital $67.5 million
$62.0 million
$62.0 million
$40.0 million
Asset dispositions $19.5 million
$19.5 million
$19.5 million
$20.0 million
Asset acquisitions $4.5 million $4.5 million $4.5 million $4.5 million
Cash G&A $4.0 million not provided $3.7 million $3.9 million
Exit or fourth quarter average production 4,773
Boe/d
(24% oil + NGL
) 4,500-5,000 Boe/d
(24% oil + NGL
) 4,500-5,000 Boe/d
(25% oil + NGL
) 4,000-4,500 Boe/d
(25% oil + NGL
)

(1) Includes value of publicly listed securities.

Actual operations capital investment in 2013 of $67.5 million was $5.5 million higher than most recent guidance of $62.0 million because of a casing failure during completion of a horizontal well at Umbach in the fourth quarter ($3.0 million) and because the drilling of one horizontal well at Umbach was advanced into the fourth quarter of 2013 instead of being drilled in 2014 ($2.5 million). Year-end adjusted debt was lower as the result of receiving net proceeds totaling $31.9 million from two equity financings that closed November 19, 2013.

OUTLOOK

Production in January and February averaged 4,970 Boe per day based on field estimates and first quarter production is forecast to be 5,000 Boe per day. Production is expected to be 5,000 to 5,500 Boe per day until September 2014 when the new facility at Umbach will be operational.

Storm's guidance for 2014 remains unchanged from what was provided on January 23, 2014 and is set forth below.

2014 Guidance
Estimated year-end debt plus working capital deficiency(1) $ 50.0 million
Estimated average operating costs $ 8.00 - $9.00 per Boe
Estimated average royalty rate (on production revenue before hedging) 14% - 15 %
Estimated operations capital, excluding acquisitions & dispositions $ 78.0 million
Estimated acquisitions $ 87.9 million
Estimated cash G&A net of recoveries $ 4.0 million
Forecast fourth quarter average production 7,500 - 7,900 Boe/d
(20% oil + NGL )
Forecast average annual production 5,500 - 6,500 Boe/d
(21% oil + NGL )

(1) Includes value of publicly listed securities.

Major expenditures included in operations capital investment for 2014 include:

  • $47.0 million at Umbach to drill 10 horizontal wells (10.0 net) with 9 horizontal wells (9.0 net) being completed and tied in; and
  • $19.0 million to expand infrastructure at Umbach, including a new field compression facility, expandable from initial capacity of 24 Mmcf per day to 48 Mmcf per day (expansion expected to occur in 2015).

This level of investment is forecast to increase Storm's fourth quarter 2014 production to 7,500 to 7,900 Boe per day which represents 60% growth on a year-over-year basis.

Guidance for 2014 assumes an average natural gas price at AECO of $3.75 per GJ and an Edmonton Par oil price of Cdn$90 per barrel. This reflects estimated first quarter pricing of AECO $5.00 per GJ and Edmonton Par Cdn$98 per barrel. Adjusted net debt is forecasted to be $50.0 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.

At Umbach, Storm is still in the early stages of delineating a large, higher quality, liquids-rich resource in the Montney formation. NGL recovery increases revenue and the relatively shallow depth (1,400 to 1,600 metres) results in a lower drilling and completion cost with both providing Storm with a competitive advantage. Significant future reserve growth is expected given 2P reserves have been assigned to the upper Montney on only 8% of Storm's land position at Umbach. In addition, showing that the middle and lower Montney are also productive and sustained improvements in horizontal well productivity would also lead to reserve additions. With a strong balance sheet and a plan in place to further expand owned and operated infrastructure, continued rapid growth is expected from Umbach during 2014 and 2015.

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

Capital investment will be reviewed mid-year and, should natural gas prices remain elevated and horizontal well performance at Umbach continue to meet or exceed expectations, it is likely that capital investment would be increased in the second half of 2014 and forecast fourth quarter production would also be increased.

In closing, I would like to thank Storm's employees for their effort and hard work in 2013 and Storm's Directors for their advice and guidance. A lot was accomplished in 2013 and we look forward to providing updates on our progress throughout 2014.

Respectfully,

Brian Lavergne, President and Chief Executive Officer

March 6, 2014

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.

Reserves at December 31, 2013

Storm's year-end reserve evaluation effective December 31, 2013 was prepared by InSite Petroleum Consultants Ltd. ("InSite") under date of February 24, 2014. InSite has evaluated all of Storm's crude oil, NGL and natural gas reserves. The InSite price forecast at December 31, 2013 was used to determine all estimates of future net revenue (also referred to as net present value or NPV). Storm's Reserves Committee which is made up of independent and appropriately qualified directors, has reviewed and approved the evaluation prepared by InSite, and the report of the Reserves Committee has been accepted by the Company's Board of Directors.

Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without including any royalty interests) unless noted otherwise. All reserves information has been prepared in accordance with National Instrument ("NI") 51-101. In addition to the information disclosed in this report, more detailed information will be included in Storm's Annual Information Form.

Summary

  • Proved developed producing ("PDP") reserves increased 29% to total 7,579 Mboe with additions of 3,046 Mboe replacing 131% of production. The all-in cost to add PDP reserves was $17.22 per Boe(1).

  • Total proved ("1P") reserves increased 50% to total 20,764 Mboe with the all-in cost to add 1P reserves being $13.19 per Boe(1). This is a per-share increase of 17% on a debt adjusted basis(2). The 1P reserve life index ("RLI") is 12 years using production in the fourth quarter of 2013.

  • Total proved plus probable ("2P") reserves increased 48% to total 40,541 Mboe with the all-in cost to add 2P reserves being $9.79 per Boe(1). This is a per-share increase of 15% on a debt adjusted basis(2). The 2P RLI is 23 years using production in the fourth quarter of 2013.

  • The trailing three year all-in cost to add 1P reserves is $18.51 per Boe and is $13.80 per Boe to add 2P reserves.

  • Recycle ratio was 1.5 for 1P reserve additions and 2.1 for 2P reserve additions using the all-in cost for reserve additions and the 2013 field operating netback of $20.44 per Boe excluding hedging gains or losses.

  • The finding and development cost ("FDC") per NI 51-101 requirements (removing effect of acquisitions, dispositions and revisions) was $13.98 per Boe to add 1P reserves and $10.75 per Boe to add 2P reserves.

  • The year-over-year increase in 1P reserves was 6,942 Mboe which replaced 430% of 2013 production and the increase in 2P reserves was 13,210 Mboe which replaced 910% of 2013 production.

  • 66% of total 2P reserves are at Umbach, 20% at Horn River Basin ("HRB") and 14% at Grande Prairie.

  • Storm's asset value is $3.25 per share using the before tax 2P reserve value of $298 million (discounted at 10%) and after deducting adjusted net debt of $12.1 million at the end of 2013. This excludes any value for Storm's landholdings which totaled 302,000 net acres at year end.

  • The majority of additions to 1P and 2P reserves in 2013 was from drilling activity (extensions) at Umbach where 10,355 Mboe was added on a 1P basis and 18,822 Mboe was added on a 2P basis with all of this being from the upper Montney formation.

  • FDC was $159 million on a 1P basis and $319 MM on a 2P basis which is an increase from the end of 2012 where FDC was $103 million on a 1P basis and $229 million on a 2P basis. This represents approximately four years of activity based on the anticipated 2014 capital investment levels.

  • Property dispositions completed during 2013 reduced 1P reserves by 859 Mboe and 2P reserves by 1,137 Mboe. FDC associated with the dispositions was $1.7 million on a 2P basis (there was no 1P FDC). With net proceeds from the dispositions totaling $19.5 million and including FDC, reserves were sold for $22.70 per Boe on a 1P basis and $18.65 per Boe on a 2P basis.

  • Technical revisions increased PDP reserves by 403 Mboe with 1P and 2P reserves being reduced by 78 Mboe and 304 Mboe respectively. This was related to well performance with negative 2P revisions at Grande Prairie totaling 437 Mboe that were partially offset by positive 2P revisions of 105 Mboe in the HRB and 28 Mboe at Umbach North. Notably, improved horizontal well performance resulted in PDP reserves at Umbach being revised higher by 439 Mboe.

  • Economic factors reduced 1P reserves by 1,149 Mboe and reduced 2P reserves by 2,844 Mboe. This was the result of removing two future horizontal drilling locations in the HRB due to low natural gas prices.

  • At Umbach South (100% working interest), 2P reserves totaled 16,070 Mboe which is 40% of Storm's total 2P. There are five horizontal wells with PDP reserves and 20 future horizontal drilling locations (20.0 net) were recognized on 6.25 gross sections (6.25 net) with 2P reserves averaging 642 Mboe per future drilling location (four proved plus probable future horizontal drilling locations per producing horizontal well). An average of 3.5 Bcf of gross raw gas was assigned per future horizontal drilling location with 10% shrinkage from raw gas to sales gas and NGL recovery of 37 barrels per Mmcf of sales (McMahon Gas Plant). 2P FDC totalled $113 million net.

  • At Umbach North (60% working interest), 2P reserves totaled 10,741 Mboe which is 26% of Storm's total 2P. There are eight horizontal wells with PDP reserves and 26 future horizontal drilling locations (15.6 net) were recognized on 8.5 gross sections (5.1 net) with 2P reserves averaging 549 Mboe per future drilling location (3.25 proved plus probable future horizontal drilling locations per producing horizontal well). An average of 3 Bcf of gross raw gas was assigned per future horizontal drilling location with 17% shrinkage from raw gas to sales gas and NGL recovery of 54 barrels per Mmcf of sales (Stoddart Gas Plant). 2P FDC totalled $84 million net.

  • DPIIP in the upper Montney formation at Umbach was 604 Bcf for the area where 2P reserves were recognized, an average of 41 Bcf per section.

  • Significant additional reserves are likely to be added in the future at Umbach given that reserves are recognized in the upper Montney only on 8% of Storm's 140 net sections in the area. Additionally, comparing 30 to 90 operating day rates, Storm management estimates ultimate recovery from the horizontal wells drilled to date at Umbach South will be 4.4 Bcf which is higher than InSite's estimate of 3.5 Bcf for future horizontal drilling locations. More production history is required to confirm Storm management's estimate of ultimate recovery.

  • In the HRB, 2P reserves were 8,258 Mboe with 1,466 Mboe assigned to complete a standing horizontal shale gas well (1.0 net) and to drill four future horizontal shale gas wells (4.0 net). Recoverable reserves assigned to each of the future horizontal drilling locations averaged 10 Bcf of gross raw gas. Shrinkage of 12% was used to determine sales gas volumes. 2P FDC was $84 million gross.

(1) The all-in calculation reflects the result of Storm's entire capital investment program as it takes into account the effect of acquisitions, dispositions and revisions, as well as the change in future development costs.

(2) Debt adjusted calculation increases 2013 year-end debt from $12.1 million to $44.7 million to equal the 2012 year-end debt by buying back 8 million shares at $4.05 per share (Storm's December 31, 2013 closing share price).

INFORMATION REGARDING DISCLOSURE ON OIL AND GAS RESERVES AND RESOURCES

All amounts are stated in Canadian dollars unless otherwise specified. Where applicable, natural gas has been converted to barrels of oil equivalent ("Boe") based on 6 Mcf:1 Boe. The Boe rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not recognize a value equivalent at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value. Production volumes and revenues are reported on a company gross basis, before deduction of Crown and other royalties, unless otherwise stated. Unless otherwise specified, all reserves volumes are based on "company gross reserves" using forecast prices and costs. The oil and gas reserves statement for the year-ended December 31, 2013, which will include complete disclosure of oil and gas reserves and other information in accordance with NI 51-101, will be contained within the Annual Information Form which will be available on SEDAR.

References to estimates of oil and gas classified as DPIIP are not, and should not be confused with, oil and gas reserves.

Gross Company Interest Reserves as at December 31, 2013
(Before deduction of royalties payable, not including royalties receivable)
Light Crude Oil (Mbbls) Sales Gas
(Mmcf)
NGL
(Mbbls)
6:1 Oil Equivalent (Mboe)
Proved producing 1,123 32,719 1,003 7,579
Proved non-producing - 123 2 22
Total proved developed 1,123 32,842 1,005 7,601
Proved undeveloped 300 65,758 1,903 13,163
Total proved 1,423 98,600 2,908 20,764
Probable additional 870 99,177 2,378 19,777
Total proved plus probable 2,293 197,777 5,286 40,541
Gross Company Reserve Reconciliation for 2013
(Gross company interest reserves before deduction of royalties payable)
6:1 Oil Equivalent (Mboe)

Total
Proved


Probable

Proved plus Probable
December 31, 2012 - opening balance 13,822 13,509 27,331
Acquisitions - - -
Discoveries - - -
Extensions 10,356 8,467 18,823
Dispositions (859 ) (278 ) (1,137 )
Technical revisions (78 ) (226 ) (304 )
Economic factors (1,149 ) (1,695 ) (2,844 )
Production (1,328 ) - (1,328 )
December 31, 2013 - closing balance 20,764 19,777 40,541
Future Development Costs ("FDC")
Proved
HRB 2.0 net horizontals plus infrastructure $ 34.9 million
Umbach 20.6 net horizontals plus infrastructure $ 117.0 million
Grande Prairie 3.0 net horizontals at Grimshaw $ 7.6 million
Total $ 159.5 million
Proved Plus Probable Additional
HRB 5.0 net horizontals plus infrastructure $ 83.8 million
Umbach 36.0 net horizontals plus infrastructure $ 197.9 million
Grande Prairie 5.0 net horizontals at Grimshaw; 5.0 net horizontals at GP Montney; and
1.0 net horizontal at GP Dunvegan

$ 37.2 million
Total $ 318.9 million

Proved Expenditures
Proved Plus Probable Additional Expenditures
2014 $ 62,950 $ 67,800
2015 $ 13,107 $ 75,888
2016 $ 48,472 $ 63,454
2017 $ 34,946 $ 78,572
2018 $ - $ 33,155
2019 $ - $ -
Total FDC - undiscounted $ 159,475 $ 318,869
Total FDC - discounted at 10% $ 134,383 $ 259,220

Note: InSite escalates capital costs at 2% per year after 2014.

NI 51-101 Finding and Development Costs

Total Proved Finding and Development Cost 2013 2012 2011 3 Year Total
Capital expenditures excluding acquisitions and dispositions (000s) $
67,450
$
26,868
$
25,360
$
119,768
Net change in FDC (000s) 77,282 30,863 25,541 133,686
Total capital including the net change in future capital (000s) $ 144,732 $ 57,731 $ 50,901 $ 253,364
Reserve additions excluding acquisitions, dispositions, revisions and economic factors (Mboe)
10,356

4,067

2,505

16,928
Total proved finding and development costs (per Boe) $ 13.98 $ 14.20 $ 20.32 $ 14.97
Total Proved Plus Probable Finding and Development Cost 2013 2012 2011 3 Year Total
Capital expenditures excluding acquisitions and dispositions (000s) $
67,450
$
26,868
$
25,360
$
119,678
Net change in FDC (000s) 134,903 40,341 51,725 226,969
Total capital including the net change in future capital (000s) $ 202,353 $ 67,209 $ 77,085 $ 346,647
Reserve additions excluding acquisitions, dispositions, revisions and economic factors (Mboe)
18,823

5,514

5,278

29,615
Total proved plus probable finding and development costs (per Boe) $
10.75
$
12.19
$
14.60
$
11.71

All-In Finding, Development and Acquisition Costs

Total Proved All-In Finding, Development and Acquisition Cost including FDC, Acquisitions, Dispositions, Revisions 2013 2012 2011 3 Year Total
Capital expenditures including acquisitions and dispositions (000s) $ 52,444 $ 166,076 $ 40,795 $ 259,315
Net change in FDC (000s) 56,600 72,655 25,541 154,796
Total capital including the net change in future capital (000s) $ 109,044 $ 238,731 $ 66,336 $ 414,111
Reserve additions including acquisitions, dispositions revisions and economic factors (Mboe)
8,270

10,927

3,178

22,375
All-in total proved finding and development costs (per Boe) $ 13.19 $ 21.85 $ 20.87 $ 18.51
Total Proved Plus Probable All-In Finding, Development and Acquisition Cost including FDC, Acquisitions, Dispositions, Revisions
2013

2012

2011

3 Year Total
Capital expenditures including acquisitions and dispositions (000s) $
52,444
$
166,076
$
40,795
$
259,315
Net change in FDC (000s) 89,829 156,258 51,725 297,812
Total capital including the net change in future capital (000s) $ 142,273 $ 322,334 $ 92,520 $ 557,127
Reserve additions including acquisitions, dispositions revisions and economic factors (Mboe)
14,538

19,828

6,012

40,378
All-In total proved plus probable finding and development costs (per Boe) $
9.79
$
16.26
$
15.39
$
13.80
Operating netback per Boe excluding hedging $ 20.43 $ 21.22 $ 22.81
Recycle ratio based on operating netback (excluding hedging gains or losses
Proved plus probable 2.1 1.3 1.5

Net Present Value Summary (before tax) as at December 31, 2013

Benchmark oil and NGL prices used are adjusted for quality of oil or NGL produced and for transportation costs. The calculated NPVs include a deduction for estimated future well abandonment costs.



Undiscounted
(000s)

Discounted at 5%
(000s)

Discounted at 10%
(000s)

Discounted at 15%
(000s)

Discounted at 20%
(000s)
Proved producing $ 184,439 $ 146,816 $ 122,247 $ 105,198 $ 92,774
Proved non-producing 92 87 82 78 74
Total proved developed $ 184,531 $ 146,903 $ 122,329 $ 105,276 $ 92,848
Proved undeveloped 184,537 107,293 62,108 34,079 15,855
Total proved $ 369,068 $ 254,196 $ 184,438 $ 139,355 $ 108,704
Probable additional 364,989 197,446 113,383 67,039 39,544
Total proved plus probable $ 734,058 $ 451,643 $ 297,821 $ 206,393 $ 148,248

Numbers in this table may not add due to rounding.

Net Present Value Summary (after tax) as at December 31, 2013

Benchmark oil and NGL prices used are adjusted for quality of oil or NGL produced and for transportation costs. The calculated NPVs each include a deduction for estimated future well abandonment costs.



Undiscounted
(000s)

Discounted at 5%
(000s)

Discounted at 10%
(000s)

Discounted at 15%
(000s)

Discounted at 20%
(000s)
Proved producing 184,439 146,816 122,247 105,198 92,774
Proved non-producing 92 87 82 78 74
Total proved developed 184,531 146,903 122,329 105,276 92,848
Proved undeveloped 162,353 95,685 55,755 30,462 13,725
Total proved 346,884 242,588 178,084 135,738 106,574
Probable additional 274,236 146,917 82,937 47,569 26,517
Total proved plus probable 621,121 389,504 261,021 183,308 133,091

Numbers in this table may not add due to rounding.

InSite Escalating Price Forecast as at December 31, 2013

WTI
Crude Oil
(US$/Bbl)
Edmonton
Light Crude Oil
(Cdn$/Bbl)
Henry Hub
Natural Gas
(US$/Mmbtu)
AECO Natural Gas
(Cdn$/Mmbtu)

Propane
(Cdn$/Bbl)

Butane
(Cdn$/Bbl)
2014 96.00 96.05 4.25 3.99 48.03 76.84
2015 95.00 97.50 4.40 4.14 53.63 78.00
2016 95.00 97.45 4.75 4.50 53.60 77.96
2017 95.00 97.40 5.00 4.75 53.57 77.92
2018 96.00 98.40 5.25 5.01 54.12 78.72

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 months and year ended December 31, 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.

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