CALGARY, ALBERTA -- (Marketwire) -- 02/28/13 -- Storm Resources Ltd. (TSX VENTURE: SRX)
Storm has also filed its audited consolidated financial statements as at December 31, 2012 and for the three months and year then ended along with the 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, 2012, as well as reserve information at December 31, 2012, appears below and should be read in conjunction with the related financial statements and MD&A.
Highlights
Three Three
Months Months
Thousands of Cdn$, except Ended Ended Year Ended Year Ended
volumetric and per share December December December December
amounts 31, 2012 31, 2011 31, 2012 31, 2011
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FINANCIAL
Gas sales 3,416 1,160 8,054 3,404
NGL sales 1,597 594 4,466 1,020
Oil sales 5,399 739 19,793 2,468
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Revenue from product
sales(1) 10,412 2,493 32,313 6,892
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Funds from operations(2) 5,016 709 13,387 1,874
Per share - basic ($) 0.08 0.03 0.24 0.07
Per share - diluted ($) 0.08 0.03 0.24 0.07
Net income (loss) (2,320) (1,758) (6,574) (3,664)
Per share - basic ($) (0.04) (0.07) (0.12) (0.14)
Per share - diluted ($) (0.04) (0.07) (0.12) (0.14)
Field capital expenditures,
net of dispositions 8,777 20,687 14,282 40,796
Net debt/working capital 44,696 15,171 44,696 15,171
Weighted average common
shares outstanding (000s)
Basic 61,824 26,377 56,067 26,377
Diluted 61,824 26,377 56,067 26,377
Common shares outstanding
(000s)
Basic 61,824 26,377 61,824 26,377
Fully diluted 64,547 28,355 64,547 28,355
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OPERATIONS
Oil equivalent (6:1)
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Barrels of oil equivalent
(000s) 259 72 825 198
Barrels of oil equivalent
per day 2,815 779 2,254 542
Average selling price (Cdn$
per Boe)(1) 40.19 34.78 39.14 34.86
Gas production
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Thousand cubic feet (000s) 987 346 3,053 964
Thousand cubic feet per day 10,728 3,763 8,342 2,641
Average selling price (Cdn$
per Mcf) 3.46 3.35 2.64 3.53
NGL Production
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Barrels (000s) 25 7 67 12
Barrels per day 274 72 185 32
Average selling price (Cdn$
per barrel) 63.27 89.95 66.17 87.36
Oil Production
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Barrels (000s) 69 7 249 25
Barrels per day 753 80 679 69
Average selling price (Cdn$
per barrel)(1) 77.93 100.05 79.53 97.39
Wells drilled
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Gross 2.0 1.0 6.0 4.0
Net 1.2 0.6 4.4 2.2
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(1) Excludes hedging gains.
(2) Funds from operations and funds from operations per share are non-GAAP
measurements. See discussion of Non-GAAP Measurements on page 14 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 24 of the MD&A.
President's Message
2012 FOURTH QUARTER AND YEAR-END HIGHLIGHTS
-- Fourth quarter production averaged 2,815 Boe per day which is a year-
over-year increase of 260% or 55% on a per-share basis. Oil plus NGL
production grew to represent 36% of fourth quarter production versus 19%
a year ago. Average 2012 production grew 95% on a per-share basis to
2,254 Boe per day with 38% being oil plus NGL. Increased production was
the result of two corporate transactions that closed in the first
quarter of 2012, Bellamont Exploration Ltd. ("Bellamont") and Storm Gas
Resource Corp. ("SGR"), and also from new horizontal wells in the
Montney formation at Umbach. The Bellamont transaction added 1,253 Boe
per day to average 2012 production and the acquisition of SGR added 276
Boe per day. Increased oil plus NGL production in 2012 was primarily the
result of the Bellamont transaction which added 668 barrels per day of
oil plus NGL and from growth at Umbach where NGL production grew by 75
barrels per day.
-- Capital investment totaled $8.8 million in the fourth quarter and $166.0
million for the year. The majority of 2012 capital investment related to
acquisitions net of dispositions, which totaled $139.2 million.
Acquisitions were $154.9 million which included the Bellamont
transaction for $96.6 million and the SGR acquisition for $55.2 million.
Dispositions totaled $15.7 million from the sale of two non-core
properties in the second half of 2012. Capital investment in operations
was $26.9 million for the year.
-- During 2012, activity was primarily focused on delineating the resource
in the Montney formation at Umbach. Drilling included six wells (4.4
net) with four horizontal wells (2.4 net) in the Montney at Umbach.
Three horizontal wells (1.8 net) were completed and pipeline connected
at Umbach. In the fourth quarter, two horizontal wells (1.2 net) were
drilled at Umbach with completion and tie-in of both planned for 2013.
-- Funds from operations in the fourth quarter was $5.0 million, or $0.08
per basic share, an increase of 165% from cash flow of $0.03 per basic
share in the prior year. For the year, funds from operations increased
by 610% to $13.4 million. The increase in quarterly and yearly funds
from operations resulted primarily from the Bellamont transaction which
increased higher priced oil plus NGL as a proportion of total production
and added $13.2 million of operating income in 2012.
-- Funds from operations increased throughout 2012 and averaged $19.37 per
Boe in the fourth quarter. The 2012 average funds from operations per
Boe was $16.19, an increase of 70% from the prior year amount of $9.48
per Boe. Total cash costs including operating expense, interest expense,
transportation costs, and cash general and administrative costs were
$19.83 per Boe in 2012 and decreased to $19.34 per Boe in the fourth
quarter.
-- Hedging gains from fixed price financial hedges put in place to protect
capital investment were $1.7 million in 2012. For 2013, commodity price
hedges currently include 400 barrels of oil per day in the first quarter
at an average floor price of Cdn $91.08 per barrel, 300 barrels of oil
per day in the second quarter at an average floor price of Cdn $91.48
per barrel, and 8,000 GJ per day of natural gas in the first quarter at
an average AECO floor price of $3.16 per GJ.
-- Net loss in the fourth quarter was $2.3 million or $0.04 per basic
share, a decrease from the net loss of $0.07 per basic share a year
earlier. Net loss for the year was $6.6 million or $0.12 per basic
share, a decrease from the prior year's net loss of $0.14 per basic
share. The net loss was primarily due to a $1.3 million loss on the sale
of investments, a write-down of investments of $2.6 million, and a $1.0
million loss on the disposition of oil and gas properties.
-- Debt and working capital deficiency was $44.7 million at year end.
Including the $4.3 million market value for Storm's investment in
publicly listed companies at year end, adjusted net debt was $40.4
million or 2.0 times annualized fourth quarter funds from operations.
Including previously announced asset dispositions for proceeds totaling
$20.1 million which closed in the first quarter of 2013, pro-forma
adjusted net debt decreases to $20.3 million which is 1.0 times
annualized fourth quarter funds from operations. Storm's bank credit
facility is $52.0 million after giving effect to asset sales in the
first quarter of 2013.
-- Total proved ("1P") reserves increased 270% to 13.8 Mmboe with additions
being 10.9 Mmboe. On a per-share basis using basic shares outstanding at
year end, the increase was 59%. Delineation drilling in the Montney at
Umbach added 4.1 Mmboe (38% of additions), the Bellamont transaction
added 4.8 Mmboe, and the acquisition of SGR added 2.6 Mmboe.
-- Total proved plus probable ("2P") reserves grew 230% to 27.3 Mmboe with
additions totaling 19.8 Mmboe. Growth on a per-share basis was 40% using
basic shares outstanding at year end. Delineation drilling in the
Montney at Umbach added 5.5 Mmboe (28% of additions), the Bellamont
transaction added 8.0 Mmboe, and the acquisition of SGR added 6.7 Mmboe.
-- The all-in cost to add 1P reserves was $21.85 per Boe and for 2P
reserves was $16.26 per Boe. The all-in cost includes all capital
expenditures, the change in future development costs, acquisitions,
dispositions and revisions.
-- The cost to add reserves per National Instrument 51-101 ("NI 51-101"),
which excludes the effect of acquisitions, divestitures and revisions,
was $14.20 per Boe for 1P reserves and $12.19 per Boe for 2P reserves.
All reserves additions per NI 51-101 were at Umbach.
-- Storm's asset value is $2.35 per share using the net present value of 2P
reserves, discounted at 10% before tax, and after deducting adjusted net
debt of $40.4 million at the end of 2012. This excludes any value for
Storm's landholdings which totaled 310,000 net acres at year end.
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.
Umbach, Northeast British Columbia
Storm's land position at Umbach totals 99 net sections (126 gross sections) or 69,000 net acres. Two project areas have been identified with one area consisting of 63 gross sections of jointly owned lands (36 net sections with an average Storm working interest of 57%) and the other area containing 63 sections of land at a 100% working interest. Fourth quarter production averaged 564 Boe per day (29% NGL) with NGL recovery being 67 Bbls per Mmcf of natural gas sales. NGL included 50% condensate plus pentanes recovered during processing, 24% butane, and 26% propane. The fourth quarter operating netback was $17.70 per Boe with revenue of $31.28 per Boe, a royalty rate of 12%, and operating costs were $9.80 per Boe.
Repeated outages and capacity constraints with third party field compression resulted in production from Umbach being reduced by 300 Boe per day in the fourth quarter. For most of the quarter, one to three horizontals were shut in and run time on the remaining horizontals was intermittent.
On the jointly owned lands, nine horizontal wells have been drilled all at a 60% working interest with seven of those having been completed and tied in. Initial production and flow test results from the last three horizontal wells that were drilled lower into the Montney formation and completed with larger water based fracture treatments are encouraging although additional uninterrupted production history is required to confirm the level of improvement. As production declines and as field compression capacity becomes available, the remaining two horizontal wells will be completed and tied in which is likely to be in the third and fourth quarters. From January 1st to February 25th, production has averaged 425 Boe per day net from one to four horizontal wells with third party field compression having been shut in for 17 days to complete repairs and modifications. Production is currently approximately 750 Boe per day net from four horizontal wells. Total sustainable productive capability of all seven horizontal wells is estimated at 1,500 Boe per day net to Storm. Production from the joint lands is expected to be restricted to 600 to 1,000 Boe per day net for the next three to six months.
On the 100% working interest lands, one horizontal well has been drilled and has been completed with first production expected early in the second quarter once an eight kilometre pipeline connection to an existing field compression facility is completed. Storm has entered into an agreement to acquire ownership in this existing facility for $4.5 million with available capacity being approximately 20 Mmcf per day. Production from horizontal wells connected to this facility will be directed to the McMahon Gas Plant for processing which will reduce NGL recovery to 37 Bbls per Mmcf sales; however, the field netback will increase by $2 per Boe at current commodity prices because eliminating third party fees for field compression will reduce operating costs by more than $3 per Boe. In the second half of 2013, it is expected that three to four more horizontal wells will be drilled on the 100% working interest lands and will be pipeline connected to this facility.
The gross cost to drill and complete the last two horizontal wells (the sixth and seventh) averaged $4.8 million which is a significant improvement from the average cost of $5.5 million for the first five horizontal wells. Both were drilled from existing pads. As the focus transitions from resource delineation to development in 2013, horizontal well costs are expected to decline as wells are drilled from common pads and further drilling and completion efficiencies are realized.
On the first four horizontal wells, first year average rates have been approximately 290 Boe per day (1.5 Mmcf raw gas per day) with estimated 2P reserves of 540 Mboe (2.8 Bcf gross raw gas) assigned to the Upper Montney formation only. This has generated a rate of return below Storm's targeted threshold of 20% to 25%. Completion techniques on the most recent horizontal wells have been modified to access the Upper and Middle Montney intervals to improve the first year average rate which is expected to result in the rate of return improving to meet or exceed the minimum targeted level.
Grande Prairie Area, Northwest Alberta and Northeast British Columbia
Production in this area comes from properties acquired through the transaction with Bellamont which closed in the first quarter of 2012. Production in the fourth quarter averaged 1,884 Boe per day (46% oil plus NGL) at an operating netback of $25.40 per Boe. In early October, with natural gas prices at AECO recovering to $3.00 per GJ, shut-in natural gas wells were reactivated which added 455 Boe per day in the fourth quarter. The sale of the Mica property was completed on October 18th with net proceeds at closing totaling $13.3 million (145 Boe per day). During the first quarter of 2013, the Rycroft property was sold January 18th (30 Boe per day) and the Saddle Hills and Gold Creek properties were sold February 15th (275 Boe per day) with proceeds from both transactions totaling $20.1 million. Current production after the recent dispositions is approximately 1,500 Boe per day (41% liquids).
There was minimal activity in the fourth quarter. A horizontal well drilled and completed in the Grande Prairie Dunvegan C light oil pool in the third quarter, was produced for a short period of time in November, and is now shut in as the production rate was below economic limits. The poor production rate was the result of problems casing the well which resulted in an open hole completion instead of the planned multi-stage fracture treatment. At Grimshaw, water injection commenced into a horizontal well in the Montney A pool in late August which has resulted in a flattening of the pool decline over the last four months. Significant progress was made on operating cost reductions in 2012 with realized savings totaling $2.5 million per year from electrifying well sites, purchasing surface equipment to eliminate processing fees, shutting in or disposing of uneconomic wells, returning rental equipment and eliminating water trucking and disposal. Wells that were shut in or disposed had total cash flow of $50,000 from April 2011 to March 2012.
Horn River Basin, Northeast British Columbia
Storm's undeveloped land position in the HRB totals 135 sections at a 100% working interest (87,700 net acres) and is prospective for natural gas from the Muskwa, Otter Park and Evie/Klua shales. The resource in the Muskwa and Otter Park shales is large with the best estimate of DPIIP in the 30 section core producing area being 3.1 Tcf gross raw gas (evaluated by InSite Petroleum Consultants Ltd. December 31, 2011). Productivity has been proven across the core producing area with one horizontal well that has been producing for 23 months plus two completed and tested vertical wells.
During the fourth quarter, production in the HRB averaged 367 Boe per day at an operating netback of $9.99 per Boe. All of Storm's production is from a horizontal well with 12 fracture stimulations that is currently producing 2.7 Mmcf per day gross raw gas with cumulative production of 2.8 Bcf gross raw gas since production commenced in March 2011. Field compression has not been installed so the flow rate since inception has been restricted by the high flowing pressure in the raw gas gathering pipeline (1,000 psig). Significant improvements in productivity and reserves are expected on future horizontals by increasing fracture density (15 to 18 fracture stimulations per horizontal) and by installing field compression.
INVESTMENTS
At the end of the fourth quarter, Storm owned 3 million shares in Chinook Energy Inc., a TSX-listed oil and gas exploration and production company (symbol 'CKE') based in Calgary with operations focused in Tunisia and western Canada. These shares had a value of $4.3 million at the end of 2012. During the fourth quarter of 2012, Storm sold its remaining shares in Bridge Energy ASA for proceeds totaling $1.8 million.
OUTLOOK
Results in 2012 were generally in line with guidance (year-end debt, operating costs, royalty rate, operations capital). Production in the fourth quarter of 2012 was below previous guidance (2,815 Boe per day versus previous guidance of 3,000 Boe per day) due to outages and capacity constraints with third party field compression at Umbach. Production in the first quarter of 2013 is expected to be 2,500 Boe per day and will increase to 3,000 Boe per day in the second quarter. This reflects the impact of the asset dispositions, continuing downtime with third party field compression at Umbach, and maintenance turnarounds at the Fort Nelson gas plant (HRB shut in for 28 days) and the Teepee gas plant (half of Grande Prairie area shut in for 15 days). Production growth is expected to resume in the second half of 2013 with additions at Umbach coming from expansion of the gathering system and as horizontal wells are drilled, completed and tied in on 100% working interest lands.
Preliminary 2013 guidance provided November 13, 2012 is being revised to reflect the recent asset dispositions that closed in the first quarter of 2013 (total proceeds $20.1 million) and an increase in activity levels at Umbach. Net of acquisitions and dispositions, total capital investment is expected to be $25 million. Updated guidance is provided below:
2013 Guidance 2012 Actual
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Year-end adjusted debt plus working
capital deficiency (1) $44.0 million $40.4 million
Average operating costs $10 - $11 per Boe $11.48 per Boe
Average royalty rate (on production
revenue before hedging) 11% - 12% 11.1%
Operations capital, excluding
dispositions $40.0 million $26.9 million
Property dispositions(2) $20.0 million $15.7 million
Corporate or property acquisitions $4.5 million $154.9 million
Cash G&A $3.9 million $3.7 million
Exit or fourth quarter average 4,000 - 4,500 Boe
production per day 2,815 Boe per day
(25% oil + NGL) (36% oil + NGL)
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(1) Includes value of publicly listed securities.
(2) Dispositions closed in February 2013.
The 2013 capital investment program will be focused on developing the resource in the Montney formation at Umbach. Major expenditures will include:
-- $20.0 million of proceeds from property dispositions;
-- $4.5 million to acquire a working interest in an existing facility at
Umbach;
-- $10.0 million to drill five horizontal wells (4.6 net) at Umbach;
-- $15.0 million to complete and tie in seven horizontal wells (5.8 net) at
Umbach;
-- $6.0 million for the purchase of undeveloped land;
-- $5.0 million to expand the gathering pipeline system at Umbach.
With a 2013 natural gas price at AECO of $3 per GJ and an Edmonton Par oil price of $87 per barrel, this program will be funded with cash flow, the sale of non-core assets, and with bank debt. Adjusted net debt is forecast to be unchanged at $45 million at the end of 2013 (including public company investments) which is within Storm's current bank line of $52 million and approximately two times forecast 2013 funds from operations.
Over the last year, Storm has gained critical mass and cash flow through two corporate transactions. Activity in 2012 was focused on drilling horizontal wells at Umbach to continue delineating the large, liquids-rich natural gas resource in the Montney formation. To date, Storm has delineated approximately 40% of its land position at Umbach with reserves assigned to only the Upper Montney formation on 11% of the land base. Well control confirms that there is a significant inventory of undrilled horizontal wells in the Upper and Middle Montney intervals. As a result, in 2013, the focus will transition to developing the resource and growing production and cash flow. NGL recovery of 67 barrels per Mmcf sales through a shallow-cut gas plant greatly improves the netback and economics at current natural gas prices. Modifications to the completion technique are expected to improve first year average rates and result in a rate of return meeting or exceeding 20% to 25% at current commodity prices. If results at Umbach are supportive of doing so, development may be accelerated with funding being provided by additional asset sales.
Regarding the HRB property, the optionality of Storm's land position is confirmed by recent transactions involving major land positions either in the HRB or other large scale, gas-prone resource plays in British Columbia and Alberta. The HRB continues to offer significant leverage to improving natural gas prices and remains a long term, core asset for Storm.
I would like to thank Storm's employees for their effort and hard work in 2012 and our directors for their guidance and continued support. Our goal continues to be accretive growth in net asset value which will be achieved through development of the larger scale, liquids-rich resource in the Montney formation at Umbach. We look forward to providing updates on our progress throughout 2013.
Respectfully,
Brian Lavergne, President and Chief Executive Officer
February 28, 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.
Reserves at December 31, 2012
Storm's year-end reserve evaluation effective December 31, 2012 was prepared by InSite Petroleum Consultants Ltd. ("InSite") under date of February 15, 2013. InSite has evaluated all of Storm's crude oil, NGL and natural gas reserves. The InSite price forecast at December 31, 2012 was used to determine all estimates of future net revenue (also referred to as net present value or NPV). Storm's Reserves Committee, comprised 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.
Summary
-- Proved developed producing reserves increased 273% to total 5,860 Mboe,
an increase of 59% per share.
-- Total proved ("1P") reserves grew 272% to total 13,822 Mboe. This is an
increase of 59% on a per-share basis.
-- Total proved plus probable ("2P") reserves totaled 27,331 Mboe which is
an increase of 228%. The increase is 49% on a per-share basis.
-- Additions to 2P reserves were 19,828 Mboe with 40% from the Bellamont
transaction, 34% from the SGR acquisition, and 28% from delineation
drilling of the Montney formation at Umbach.
-- The net present value of 2P reserves, discounted at 10% before tax,
increased 238% to $186 million with the majority of this being
attributed to the Umbach property (39%).
-- Storm's asset value is $2.35 per share using the net present value of 2P
reserves, discounted at 10% before tax, and after deducting adjusted net
debt of $40.4 million at the end of 2012. This excludes any value for
Storm's landholdings which totaled 310,000 net acres at year end.
-- The 1P finding and development cost as per NI 51-101 requirements was
$14.20 per Boe and the 2P finding and development cost, as per NI 51-101
requirements, was $12.19 per Boe. This includes the change in FDC and
excludes the effect of acquisitions, divestitures and revisions.
-- The all-in cost to add 1P reserves was $21.85 per Boe and for 2P
reserves was $16.26 per Boe. The all-in calculation reflects the result
of Storm's entire capital investment program as it takes into account
the effect of acquisitions (Bellamont and SGR), dispositions, revisions,
as well as the change in future development costs.
-- Recycle ratio was 1.4 for 2P reserve additions using the all-in cost of
$16.26 per Boe and the 2012 field netback of $23.21 per Boe.
-- Drilling activity in 2012 resulted in the addition of 4,067 Mboe on a 1P
basis and 5,514 Mboe on a 2P basis with all additions being from the
Montney formation at Umbach.
-- The transaction with Bellamont added 4,784 Mboe 1P reserves and 7,972
Mboe 2P reserves. 2P FDC was $40.2 million net to Bellamont. The all-in
cost to add 1P reserves was $22.40 per Boe and for 2P reserves was
$17.55 per Boe.
-- The acquisition of SGR added 2,577 Mboe 1P reserves and 6,737 Mboe 2P
reserves with 2P FDC of $75.7 million net to SGR. The all-in cost to add
1P reserves was $34.71 per Boe and for 2P reserves was $19.42 per Boe.
Cost to add reserves with the SGR acquisition is high as it does not
reflect contingent resources with the best estimate being 393 Bcf sales
net to SGR as evaluated by InSite effective December 31, 2011.
-- FDC was $103 million on a 1P basis and $229 million on a 2P basis.
-- At Umbach, 2P reserves were 8,679 Mboe (32% of total corporate) with 661
Mboe assigned to complete two standing horizontal wells (1.2 net) and to
drill 19 horizontal wells (11.4 net). Recoverable reserves assigned to
horizontal drilling locations averaged 2.9 Bcf of gross raw gas.
Shrinkage of 15% was used along with NGL recovery of 61 barrels per Mmcf
of sales. 2P FDC was $63.6 million net. Reserves were assigned to the
Upper Montney formation only and no reserves were recognized on Storm's
100% working interest lands.
-- In the HRB, 2P reserves were 11,128 Mboe (41% of total corporate) with
1,466 Mboe assigned to complete a standing horizontal shale gas well
(1.0 net) and to drill six horizontal shale gas wells (6.0 net).
Recoverable reserves assigned to each of the horizontal drilling
locations averaged 10 Bcf of gross raw gas. Shrinkage of 12% was used to
determine sales gas volumes. 2P FDC was $125.1 million gross and
includes $12.1 million for associated infrastructure.
-- Property dispositions in 2012 (Mica and Red Earth) reduced 1P reserves
by 626 Mboe and 2P reserves by 735 Mboe.
Gross Company Interest Reserves as at December 31, 2012
(Before deduction of royalties payable, not including royalties receivable)
6:1 Oil
Light Crude Sales Gas NGL Equivalent
Oil (Mbbls) (Mmcf) (Mbbls) (Mboe)
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Proved producing 2,049 19,535 555 5,860
Proved non-producing - 397 8 74
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Total proved developed 2,049 19,932 563 5,934
Proved undeveloped 300 39,068 1,077 7,888
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Total proved 2,349 59,000 1,640 13,822
Probable additional 1,265 66,600 1,144 13,509
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Total proved plus probable 3,614 125,600 2,784 27,331
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Gross Company Reserve Reconciliation for 2012
(Gross company interest reserves before deduction of royalties payable)
6:1 Oil Equivalent (Mboe)
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Total Proved plus
Proved Probable Probable
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December 31, 2011 - opening balance 3,714 4,608 8,322
Acquisitions 7,361 7,348 14,709
Discoveries - - -
Extensions 4,067 1,447 5,514
Dispositions (626) (109) (735)
Technical revisions 126 216 342
Production (819) - (819)
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December 31, 2012 - closing balance 13,823 13,510 27,333
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Future Development Costs
Proved
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3.0 net horizontals plus
HRB infrastructure $ 55.5 million
Umbach 8.4 net horizontals $ 39.8 million
Grande Prairie 3.0 net horizontals $ 7.5 million
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Total $ 102.8 million
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Proved Plus Probable
Additional
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7.0 net horizontals plus
HRB infrastructure $ 125.1 million
Umbach 12.6 net horizontals $ 63.6 million
Grande Prairie 11.0 net horizontals $ 40.2 million
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Total $ 229.0 million
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Proved Plus Probable
Proved Expenditures Additional Expenditures
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2013 $ 29.3 million $ 37.7 million
2014 $ 18.0 million $ 33.2 million
2015 $ 18.6 million $ 59.4 million
2016 $ 34.9 million $ 43.0 million
2017 $ 2.1 million $ 41.8 million
2018 $ - $ 13.9 million
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NI 51-101 Finding and Development Costs
Total Proved Finding and Development 3 Year
Cost 2012 2011 2010 Average
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Capital expenditures excluding
acquisitions and dispositions
(000s) $ 26,868 $ 25,360 $ 16,800 $ 69,028
Net change in FDC (000s) 30,863 25,541 4,679 61,083
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Total capital including the net
change in future capital (000s) $ 57,731 $ 50,901 $ 21,479 $ 130,111
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Reserve additions excluding
acquisitions, dispositions and
revisions (Mboe) 4,067 2,505 738 7,310
Total proved finding and development
costs (per Boe) $ 14.20 $ 20.32 $ 29.10 $ 17.80
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Total Proved Plus Probable Finding 3 Year
and Development Cost 2012 2011 2010 Average
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Capital expenditures excluding
acquisitions and dispositions
(000s) $ 26,868 $ 25,360 $ 16,800 $ 69,028
Net change in FDC (000s) 40,341 51,725 21,057 113,123
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Total capital including the net
change in future capital (000s) $ 67,209 $ 77,085 $ 37,857 $ 182,151
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Reserve additions excluding
acquisitions, dispositions and
revisions (Mboe) 5,514 5,278 2,512 13,304
Total proved plus probable finding
and development costs (per Boe) $ 12.19 $ 14.60 $ 15.07 $ 13.69
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All-In Finding, Development and Acquisition Costs
Total Proved All-In Finding,
Development and Acquisition
Cost including FDC, Acquisitions, 3 Year
Dispositions, Revisions 2012 2011 2010 Average
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Capital expenditures including
acquisitions and dispositions
(000s) $ 166,076 $ 40,795 $ 16,800 $ 223,671
Net change in FDC (000s) 72,655 25,541 4,679 102,875
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Total capital including the net
change in future capital (000s) $ 238,731 $ 66,336 $ 21,479 $ 326,546
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Reserve additions including
acquisitions,dispositions and
revisions (Mboe) 10,927 3,178 738 14,843
All-in total proved finding and
development costs (per Boe) $ 21.85 $ 20.87 $ 29.10 $ 22.00
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Total Proved Plus Probable All-In
Finding, Development and
Acquisition Cost including FDC,
Acquisitions, Dispositions, 3 Year
Revisions 2012 2011 2010 Average
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Capital expenditures including
acquisitions and dispositions
(000s) $ 166,076 $ 40,795 $ 16,800 $ 223,671
Net change in FDC (000s) 156,258 51,725 21,057 229,040
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Total capital including the net
change in future capital (000s) $ 322,334 $ 92,520 $ 37,857 $ 452,711
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Reserve additions including
acquisitions,dispositions and
revisions (Mboe) 19,828 6,012 2,512 28,352
All-In total proved plus probable
finding and development costs (per
Boe) $ 16.26 $ 15.39 $ 15.07 $ 15.97
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Net Present Value Summary (before tax) as at December 31, 2012
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.
Discounted Discounted Discounted Discounted
Undiscounted at 5% at 10% at 15% at 20%
(000s) (000s) (000s) (000s) (000s)
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Proved producing $ 164,695 $ 125,620 $ 101,403 $ 85,241 $ 73,808
Proved non-
producing 416 382 353 328 306
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Total proved
developed $ 165,111 $ 126,002 $ 101,756 $ 85,569 $ 74,114
Proved
undeveloped 91,890 49,156 24,643 9,763 328
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Total proved $ 257,002 $ 175,159 $ 126,399 $ 95,333 $ 74,442
Probable
additional 226,565 113,694 59,667 31,173 15,027
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Total proved
plus probable $ 483,566 $ 788,852 $ 186,066 $ 126,506 $ 89,469
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Numbers in this table may not add due to rounding.
Net Present Value Summary (after tax) as at December 31, 2012
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.
Discounted Discounted Discounted Discounted
Undiscounted at 5% at 10% at 15% at 20%
(000s) (000s) (000s) (000s) (000s)
----------------------------------------------------------------------------
Proved producing $ 164,696 $ 125,620 $ 101,403 $ 85,241 $ 73,808
Proved non-
producing 416 383 354 328 306
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Total proved
developed $ 165,112 $ 126,003 $ 101,757 $ 85,569 $ 74,114
Proved
undeveloped 89,076 48,030 24,169 9,555 232
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Total proved $ 254,188 $ 174,033 $ 125,926 $ 95,124 $ 74,347
Probable
additional 170,535 85,623 44,517 22,510 9,841
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Total proved
plus probable $ 424,723 $ 259,656 $ 170,442 $ 117,635 $ 84,188
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Numbers in this table may not add due to rounding.
InSite Escalating Price Forecast as at December 31, 2012
Edmonton
WTI Light Crude Henry Hub AECO
Crude Oil Oil Natural Gas Natural Gas Propane Butane
(US$/Bbl) (Cdn$/Bbl) (US$/Mmbtu) (Cdn$/Mmbtu) (Cdn$/Bbl) (Cdn$/Bbl)
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2013 92.00 90.00 3.75 3.34 36.00 76.50
2014 94.00 91.96 4.25 3.83 45.98 78.17
2015 96.00 93.92 4.75 4.33 56.35 79.83
2016 98.00 95.88 5.20 4.77 57.53 81.50
2017 100.00 97.84 5.55 5.11 58.70 83.16
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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, 2012.
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.
Contacts:
Storm Resources Ltd.
Brian Lavergne
President & CEO
(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
