Storm Resources Ltd. (TSX VENTURE:SRX)
Storm has also filed its audited financial statements as at December 31, 2011
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, 2011, as well as reserve information at December 31, 2011, appears
below and should be read in conjunction with the related financial statements
and MD&A.
Highlights
Three Three
Months Months Inception,
Thousands of Cdn$, except Ended Ended Year Ended June 8, 2010
volumetric and per share December December December to December
amounts 31, 2011 31, 2010 31, 2011 31, 2010(1)
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FINANCIAL
Gas sales 1,160 - 3,404 -
NGL sales 594 - 1,020 -
Oil sales 739 - 2,468 -
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Production revenue 2,493 - 6,892 -
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Funds from operations(2) 709 (708) 1,874 (956)
Per share - basic ($) 0.03 (0.03) 0.07 (0.04)
Per share - diluted ($) 0.03 (0.03) 0.07 (0.04)
Net income (loss) (1,758) (1,087) (3,664) (1,493)
Per share - basic ($) (0.07) (0.04) (0.14) (0.09)
Per share - diluted ($) (0.07) (0.04) (0.14) (0.09)
Capital expenditures, net of
dispositions 20,687 13,373 40,796 16,797
(Debt) working capital (15,171) 20,593 (15,171) 20,593
Weighted average common shares
outstanding (000s)
Basic 26,377 26,377 26,377 16,267
Diluted 26,377 26,377 26,377 16,267
Common shares outstanding
(000s)
Basic 26,377 26,377 26,377 26,377
Fully diluted 28,355 28,351 28,355 28,351
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OPERATIONS(3)
Oil equivalent (6:1)
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Barrels of oil equivalent
(000s) 72 - 198 -
Barrels of oil equivalent
per day 779 - 542 -
Average selling price (Cdn$
per Boe) 34.78 - 34.86 -
Gas production
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Thousand cubic feet (000s) 346 - 964 -
Thousand cubic feet per day 3,763 - 2,641 -
Average selling price (Cdn$
per Mcf) 3.35 - 3.53 -
NGL Production
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Barrels (000s) 7 - 12 -
Barrels per day 72 - 32 -
Average selling price (Cdn$
per barrel) 89.95 - 87.36 -
Oil Production
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Barrels (000s) 7 - 25 -
Barrels per day 80 - 69 -
Average selling price (Cdn$
per barrel) 100.05 - 97.39 -
Wells drilled
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Gross 1.0 - 4.0 -
Net 0.6 - 2.2 -
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(1) Storm Resources Ltd. was incorporated on June 8, 2010 and was inactive until
August 17, 2010 when they participated in a plan of arrangement along with Storm
Exploration Inc., ARC Energy Trust and ARC Resources Ltd.
(2) Funds from operations and funds from operations per share are non-GAAP
measurements. See discussion of Non-GAAP Measurements on page 18 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.
(3) Storm had no production in 2010.
President's Message
2011 FOURTH QUARTER AND YEAR-END HIGHLIGHTS
-- Production averaged 542 Boe per day in 2011 with significant growth in
the second half of the year as evidenced by fourth quarter production
averaging 779 Boe per day and production in December averaging 861 Boe
per day. There are no prior year comparisons given that Storm commenced
operations August 17, 2010 and had no production until January 2011.
Growth in the second half of 2011 primarily resulted from the tie-in of
two new horizontal wells in the Montney formation at Umbach, which added
300 net Boe per day in the fourth quarter, and the acquisition of a
light oil property at Mica in north east British Columbia which closed
on December 1, 2011 and added 145 net Boe per day in December.
-- On December 1, 2011, Storm closed the acquisition of a light oil
property at Mica in north east British Columbia which added 145 Boe per
day of high netback production (current netback approximately $50.00 per
Boe) and 722 Mboe of proved plus probable reserves. The purchase price,
net of adjustments, was $15.4 million and was financed with existing
cash resources plus an expanded credit facility.
-- Storm entered into an arrangement agreement in the fourth quarter to
acquire all of the outstanding common shares of Storm Gas Resource Corp.
("SGR"), its partner in the Horn River Basin of north east British
Columbia ("HRB"). The arrangement closed on January 12, 2012 and added
360 Boe per day of production (100% natural gas) plus 81,400 net acres
of undeveloped land including 58,400 net acres in the HRB. Based on an
evaluation completed by InSite Petroleum Consultants Ltd. ("InSite")
effective January 31, 2012, Storm acquired 2.6 Mmboe of proved reserves
and 6.8 Mmboe of proved plus probable reserves. Excluding the 2.5
million SGR shares already owned by Storm, the final cost to acquire SGR
was $43.5 million which resulted in the issuance of 11.8 million Storm
shares to SGR shareholders.
-- On January 20, 2012, Storm announced that it had entered into an
arrangement agreement with Bellamont Exploration Ltd. ("Bellamont")
which will result in both companies being combined. This transaction
will increase Storm's production by 2,250 Boe per day (48% liquids) at
closing and adds light oil drilling inventory in the Grimshaw and Grande
Prairie areas of north west Alberta. Under the terms of the arrangement
agreement, Bellamont shareholders will receive, at their election, for
each common share of Bellamont held: $0.56 cash; or 0.1445 of a Storm
common share; or a combination of cash and Storm shares. The cash amount
payable to Bellamont shareholders is subject to a maximum total amount
of $20.0 million. Including estimated net debt of $40.0 million at
December 31, 2011, the total value of the transaction is $110.2 million,
using Storm's closing share price of $3.00 per share on February 29,
2012.
-- Storm's reserves grew significantly in 2011 with InSite estimating that
proved reserves increased by 403% to total 3.7 Mmboe and proved plus
probable reserves increased by 231% to total 8.3 Mmboe. The all-in cost
to add reserves was $20.87 per Boe for proved reserves and $15.39 per
Boe for proved plus probable reserves (includes all capital
expenditures, the change in future development costs, acquisitions,
dispositions and revisions).
-- InSite completed a resource evaluation effective December 31, 2011 which
confirms the significant resource and future drilling opportunity on
Storm's lands in the Umbach area and in the HRB. The best estimate of
contingent resources totals 51.2 Mmboe net sales for Umbach plus the HRB
(116.8 Mmboe net sales including SGR). At Umbach, the best estimate of
contingent resources was 14.1 Mmboe net sales to Storm (19% condensate
plus natural gas liquids). In the HRB, the best estimate of contingent
resources was 223 Bcf net sales to Storm and 393 Bcf net sales to SGR.
-- Fourth quarter activity included drilling a fourth horizontal well at
Umbach which was drilled and cased 2.5 miles south of the first
horizontal well. Logs from the vertical pilot hole indicate 30 metres of
net pay in the Montney formation which significantly expands the size of
the exploitable area. In addition, two other horizontal wells (1.2 net)
at Umbach were tied in and commenced production from the Montney
formation.
-- The operating netback averaged $20.71 per Boe in the fourth quarter and
was $22.81 per Boe for the full year.
-- Capital investment in the fourth quarter was $20.7 million with major
expenditures being $15.4 million to acquire the Mica property and $4.7
million for drilling and completions. Capital investment in 2011 totaled
$40.8 million.
-- During 2011, Storm drilled four wells (2.2 net) with a 100% success rate
including one horizontal well (0.4 net) in the Muskwa/Otter Park
formation of the HRB and three horizontal wells (1.8 net) into the
Montney formation at Umbach.
-- At December 31, 2011, Storm's debt and working capital deficiency was
$15.2 million. After taking into account the value of Storm's investment
in publicly listed companies ($8.8 million at year end), net debt was
$6.3 million.
TRANSACTION WITH BELLAMONT EXPLORATION LTD.
On January 20, 2012, Storm announced that it had entered into an arrangement
agreement with Bellamont which will result in both companies being combined.
Under the terms of the arrangement agreement, Bellamont shareholders will
receive, at their election, for each common share of Bellamont held: $0.56 cash;
or 0.1445 of a Storm common share; or a combination of cash and Storm shares.
The cash amount payable to Bellamont shareholders is subject to a maximum total
amount of $20.0 million which, if elected, will result in 16.7 million Storm
shares being issued. Bellamont's asset base is primarily operated, high working
interest assets focused within the Grande Prairie area of north west Alberta
which have a higher overall netback given that liquids are 48% of total
production.
The transaction with Bellamont will be funded in part through a $23.6 million
private placement of common shares of Storm at a price of $3.40 per Storm share
(6,946,000 shares to be issued). Management, directors and employees are
investing $8.4 million to subscribe for 2,468,000 shares. Closing of the private
placement occurred on February 22, 2012 and the funds are being held in escrow
pending completion of the transaction with Bellamont (a condition of the private
placement) which is expected to close on March 23, 2012.
Additional information regarding the arrangement with Bellamont:
-- Bellamont's net debt at December 31, 2011 is estimated to be $40.0
million (includes transaction costs plus employee severance);
-- Including net debt of $40.0 million, the total value of the transaction
is $110.2 million, using Storm's closing share price of $3.00 per share
on February 29, 2012;
-- Storm's cost to acquire Bellamont's shares is $65.9 million after
deducting net debt and proceeds ($4.25 million) from the recent sale by
Bellamont of undeveloped lands;
-- Annualized cash flow from Bellamont's assets is estimated to be $23.0
million based on expected production at closing of 2,250 Boe per day
(48% oil plus NGLs) with a $28.00 per Boe operating netback which
assumes Cdn$100/Bbl Edmonton Par, Cdn$2.40/GJ AECO, operating costs of
$13.50 per Boe, transportation cost of $1.50 per Boe and an average
royalty rate of 17%;
-- Undeveloped land value of $3.1 million which is internally estimated by
Storm (previous estimate of $7.35 million was adjusted lower to reflect
recent sale of undeveloped lands for $4.25 million);
-- Annual production decline is relatively shallow at 20% to 25% (decline
is less than 10% on older wells that came on production before January
2010, approximately half of Bellamont's current production);
-- A new horizontal well at Grimshaw will begin producing in early March
and is expected to add 50 to 100 barrels of oil per day;
-- Current production is approximately 2,050 Boe per day with 300 net Boe
per day currently shut in due to mechanical issues (pipeline failures at
Saddle Hills and Grande Prairie, liquids rich Montney gas well at Grande
Prairie awaiting installation of artificial lift); and,
-- InSite is evaluating the reserves associated with Bellamont's asset base
and results are expected to be released in late March 2012.
Combining Bellamont and Storm will result in a company with a more diversified,
resource-oriented asset base. Near-term growth will primarily come from
exploitation of Bellamont's Montney light oil pool at Grimshaw and from
delineating Storm's liquids rich natural gas resource in the Montney formation
at Umbach. Longer term, growth will come from improving natural gas prices and
from further exploitation of Storm's large resource in the HRB. Bellamont
shareholders retain exposure to upside associated with the Grimshaw Montney
light oil pool and gain asset diversification into much larger resource
opportunities at Umbach (liquids rich Montney gas) and in the HRB (Muskwa and
Otter Park shale gas). Storm shareholders benefit from higher netbacks,
increased cash flow and relatively shallow decline associated with Bellamont's
asset base, which will result in increased production growth as well as
acceleration of resource delineation at Umbach.
At Grimshaw, there remains significant upside associated with further exploiting
and delineating Bellamont's large Montney light oil pool. Bellamont has a 100%
working interest in 17 sections of land at Grimshaw. Storm management estimates
that DPIIP in the Montney pool ranges from 19 million barrels of oil to more
than 35 million barrels of oil. Estimated DPIIP is based on an areal extent of
2.0 to 4.5 sections, net pay of 7 metres, average porosity of 17% and average
oil saturation of 44%. In the second half of 2012, Storm plans to drill five
horizontal wells which will include up to two step-out horizontals with logged
vertical pilot holes. Bellamont recently drilled a vertical well which
encountered a new pool to the west. This vertical well is expected to begin
producing in the first quarter of 2012 and, this summer, a horizontal well with
a logged vertical pilot hole is expected to be drilled offsetting the discovery
well. Storm will continue to advance Bellamont's plans to initiate a waterflood
in the pool which could materially increase oil recovery and reserves at minimal
cost. New horizontal wells benefit from a 5% royalty rate under Alberta's New
Well Royalty Rate program.
ACQUISITION OF STORM GAS RESOURCE CORP.
On November 11, 2011, Storm entered into a definitive arrangement agreement to
acquire all of the outstanding shares of SGR, its partner in the HRB. On January
12, 2012, the transaction was completed with Storm issuing 1.33 common shares
for each SGR common share not owned by Storm (Storm owned 2.5 million shares of
SGR) which resulted in the issuance of 11.8 million Storm shares. The total
value of the transaction was $55.8 million using Storm's closing share price of
$3.70 per share on January 12, 2012.
The acquisition of SGR added approximately 360 Boe per day of production (100%
natural gas) and 81,400 net acres of undeveloped land which includes 58,400 net
acres in the HRB. Storm's undeveloped land holdings in the HRB now total 88,600
net acres at a 100% working interest.
InSite estimated DPIIP, contingent resources, and reserves for the Muskwa and
Otter Park formations in SGR's HRB lands as of January 31, 2012. DPIIP was
determined over 30 gross sections where both reserves and contingent resources
were assigned and the best estimate was 3.1 Tcf gross raw gas. In terms of
contingent resources, Storm acquired from SGR a best estimate of 393 Bcf net
sales. Proved and probable reserves acquired from SGR totaled 41 Bcf net sales
(6,831 Mboe) which includes $74.2 million of associated future development
capital to complete a standing horizontal gas well (0.6 net SGR:0.4 net Storm)
and drill six horizontal gas wells (3.6 net SGR).
OPERATIONS REVIEW
Storm has a focused asset base with the majority of production coming from two
large scale resource plays with multi-year drilling upside: liquids rich natural
gas from the Montney formation at Umbach and shale gas from the Muskwa and Otter
Park shales in the HRB.
Umbach, North East British Columbia
Storm's current land holdings at Umbach total 98 gross sections or 70 net
sections at Umbach (53,800 net undeveloped acres), all of which are prospective
for liquids rich natural gas from the Montney formation. Storm's lands are
subdivided into a northern area, which consists of 60 gross sections at 53%
working interest, and a southern area which consists of 38 gross sections at a
100% working interest. Production averaged 414 Boe per day in the fourth quarter
while the operating netback was $17.75 per Boe (17% condensate plus natural gas
liquids).
In the fourth quarter, the third horizontal well (60% working interest) was
completed with 11 fracture stimulations and began producing in November at an
initial rate of approximately 2.0 Mmcf per day gross raw gas. A fourth
horizontal well was drilled and cased 2.5 miles south of the first horizontal
well and included a vertical pilot hole. Logs from the vertical pilot hole
indicate 30 metres of net pay in the Montney formation which significantly
expands the areal extent of the exploitable area.
Total production at Umbach from three horizontal wells (60% working interest) is
currently 3.4 Mmcf per day gross raw gas (3.0 Mmcf per day gross sales gas plus
102 barrels per day gross condensate and natural gas liquids). Currently,
production is processed at the McMahon Gas Plant with total condensate plus
natural gas liquids production averaging 34 barrels per Mmcf of sales gas in the
fourth quarter (62% condensate and pentane). In early March, production will be
re-directed to the Stoddart Gas Plant which will increase propane, butane, and
pentane recovery resulting in condensate plus natural gas liquids production
increasing to 40 to 50 barrels per Mmcf of sales gas (approximately 55%
condensate and pentane).
Results to date from the first three horizontal wells have been very encouraging
as evidenced by liquids recoveries and the rapid flattening of the decline after
three to six months of production. After a year of production, the rate on the
first horizontal well has stabilized at approximately 1.1 Mmcf per day gross raw
gas or 1.0 Mmcf per day gross sales gas plus 34 barrels per day of condensate
and natural gas liquids. Production history for each horizontal since inception
is provided in the presentation on Storm's website www.stormresourcesltd.com.
Different fracture treatments were conducted on each of the three producing
horizontal wells in an attempt to improve productivity and reserves. Further
optimization is planned in 2012 which will include varying the sand tonnage in
fracture treatments, modifying the fluid system, and possibly lowering the
wellbore so that the middle Montney is also accessed.
At the end of 2011, InSite's evaluation of the Montney formation on the northern
lands results in the best case estimate of DPIIP to be 465 Bcf gross raw gas on
19.75 gross sections (average working interest 57%). DPIIP includes the
producing area of 3.5 gross sections with proved plus probable reserves
totalling 2,975 Mboe sales (19% condensate plus natural gas liquids) net to
Storm and the area where contingent resources were assigned to 16.25 gross
sections with the best estimate being 14,058 Mboe sales net to Storm (19%
condensate plus natural gas liquids). Condensate plus natural gas liquids was
estimated to be 40 barrels per Mmcf per day of gas sales. Based on existing
vertical and horizontal well control in the northern area, more than 40 gross
sections are likely to be productive in the Montney formation and Storm's 2012
activity will be focused on proving up the resource in this larger area.
Storm's activity in 2012 will be focused on increasing the size of the resource
in the Montney formation by drilling step-out horizontal wells and optimizing
completions to increase production rates and reserves. Activity will include:
-- Drilling a vertical delineation well (100% working interest) in the
southern area in the first quarter which will be re-entered and drilled
horizontally in the third or fourth quarter if prospectivity of the
Montney formation is confirmed by log analysis;
-- Completing the fourth horizontal well (60% working interest) late in the
second quarter; and
-- Drilling and completing two to three additional horizontal wells (1.2 to
1.8 net) in the third and fourth quarters.
Horn River Basin, North East British Columbia
Storm's undeveloped land position in the HRB currently totals 135 gross sections
at a 100% working interest (88,600 net acres) and is prospective for natural gas
from the Muskwa, Otter Park, and Evie/Klua shales. During the fourth quarter,
production from this area averaged 266 Boe per day at an operating netback of
$10.35 per Boe. On January 12, 2012, Storm completed the previously announced
acquisition of SGR, its partner in the HRB, which added 360 Boe per day.
In the fourth quarter, completion operations on the second horizontal well (40%
Storm, 60% SGR) began November 12 and were suspended November 29 following an
unexpected operational problem. After the first fracture stimulation was pumped,
the bridge plug required to isolate the first interval became stuck in the
horizontal section while it was being moved into position. The bridge plug was
retrieved; however, the delay resulted in the expiry of the window of
availability for the fracturing crew.
Production performance of the first horizontal well (40% Storm, 60% SGR) with 12
fracture stimulations continues to exceed expectations with the current rate
being approximately 3.9 Mmcf per day gross raw gas and cumulative production of
1.9 Bcf gross raw gas since production commenced on March 7, 2011. Compression
has not yet been installed resulting in the flow rate being restricted.
Productivity has been higher than expected and the decline rate has been
relatively moderate which has resulted in performance to date exceeding the
initial type curve which predicted recovery of 9 Bcf gross raw gas. InSite's
amended type curve predicts ultimate production of 9.6 Bcf gross raw gas without
field compression. 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. At current
natural gas prices, Storm expects that no royalties will be paid on production
from the first two horizontals in the next two to three years due to their
qualification under British Columbia's Deep Royalty Credit and Infrastructure
Royalty Credit Programs.
At the end of 2011, InSite's evaluation of the Muskwa and Otter Park shales
resulted in the best estimate of DPIIP being 3.1 Tcf gross raw gas on 30 gross
sections (Storm's working interest is 100% after the transaction with SGR
closed). The producing area where proved plus probable reserves were assigned is
3.0 gross sections and the area where contingent resources were assigned is 27
gross sections.
Mica, North East British Columbia
The acquisition of the producing property at Mica closed December 1, 2011 and
added 145 Boe per day of production (70% light oil and natural gas liquids, 30%
natural gas). The purchase price, net of adjustments, was $15.4 million and was
financed with existing cash resources plus an expanded credit facility. Storm
acquired a 100% working interest in seven producing oil wells. The field netback
for the property is currently estimated to be $49.00 per Boe with operating
costs of $14.30 per Boe and a royalty rate of 10%. The acquired asset contains
an estimated 722 Mboe of proved plus probable reserves (70% light oil plus
natural gas liquids) based on the year-end evaluation completed by InSite
(reserve estimate is based on forecast decline from existing producing wells and
does not include any upside from infill drilling or initiating a waterflood).
Storm management estimates that DPIIP is approximately 7.0 million barrels of
oil with recovery to date being 21% (average production of 210,000 barrels of
oil from each producing well) and this could be improved to 35% to 40% by
drilling six infill wells plus initiating a waterflood (future development
capital internally estimated to be $12.6 million). Near-term plans include
initiating a waterflood in the first quarter and, in the second half of 2012,
expanding the waterflood along with drilling up to two infill vertical wells.
INVESTMENTS
At the end of 2011, Storm had share ownership positions in one private company
and two publicly traded companies. The value of the share positions in the two
public companies totaled $8.8 million at the end of the fourth quarter and these
securities could possibly be sold in the future with the proceeds being used to
finance the Company's capital programs.
Chinook Energy Inc. ("Chinook")
Storm holds 4.5 million shares of Chinook which is a TSX-listed oil and gas
exploration and production company (symbol 'CKE') based in Calgary with
operations focused in Tunisia and western Canada.
Bridge Energy ASA ("Bridge")
Storm holds 1.05 million common shares of Bridge (symbol 'Bridge' on the Oslo
Stock Exchange), a Norwegian-based exploration and production company with
production of approximately 1,400 Boe per day, several development opportunities
in the UK sector of the North Sea, and a number of exploratory leads in the
Norwegian sector of the North Sea.
Storm Gas Resource Corp. ("SGR")
At the end of 2011, Storm's share ownership position in SGR totaled 2.5 million
shares, representing 22% ownership of SGR. On January 12, 2012, Storm completed
the acquisition of SGR by issuing 11,761,190 common shares of Storm at a deemed
issuance price of $3.70 per Storm share in exchange for all of the issued and
outstanding common shares of SGR that were not owned by Storm.
OUTLOOK
Based on field estimates, production in the first quarter to the end of February
has averaged approximately 1,050 Boe per day with 18% liquids. Production is
forecast to increase to 3,600 to 4,000 Boe per day (41% liquids) in the fourth
quarter of 2012 after the transaction with Bellamont closes and including
planned capital investment on operations of $34.0 million. Capital investment
includes $27.0 million for drilling and completions and $7.0 million for land,
seismic and facilities. Drilling activity will include one vertical well (1.0
net) at Umbach, two horizontal wells (1.2 net) at Umbach, completing one
standing horizontal well (0.6 net) at Umbach, five horizontal wells (5.0 net) at
Grimshaw, and one to three horizontals or verticals (all 100% working interest)
targeting light oil opportunities in the Grande Prairie or Mica area. In
addition, $5.0 million will be invested to initiate the waterflood at Mica,
commence water disposal and injection at Grimshaw, and to modify two existing
facilities in the Grande Prairie area. Further details regarding Storm's 2012
operating guidance is provided in the following table:
Storm Bellamont Pro Forma Combined
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Forecast daily production in
Q2 2012 after deducting 5%
for unplanned
outages/failures:
Natural gas (Mcf) 5,000 6,500 11,500
Crude oil and NGLs (Bbl) 200 1,040 1,240
Total Boe per day 1,035 2,125 3,160
Oil and liquids % 19% 49% 39%
Estimated field netback at
$2.40/GJ AECO, Cdn $100/Bbl
Edmonton Par(1) $23/Boe $28/Boe $26 - $27/Boe
Undeveloped land - net acres 228,000 78,000 306,000
Indicated bank line $70.0 million
2012 average operating
costs(2) $10 to $12 per Boe
2012 average royalty rate(2) 12%
2012 operations capital $34.0 million
2012 cash G&A(2)(3) $3.6 million
2012 exit or fourth quarter 3,600 to 4,000 Boe per day
average production (41% oil + NGLs)
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(1) Using Storm and Bellamont 2011 average royalty rates, operating costs and
deducted $1.60 per Boe transportation costs.
(2) Assumes transaction with Bellamont closes prior to April 1, 2012.
(3) Excludes transaction costs associated with the SGR acquisition and Bellamont
combination which are required to be expensed under IFRS.
After closing of the Bellamont transaction, Storm's near term objectives are to:
-- Continue delineating and developing Bellamont's light oil Montney pool
at Grimshaw by drilling five infill and step-out horizontals in the
second half of 2012;
-- Advance additional light oil opportunities on Bellamont's lands in the
Grande Prairie area which will involve drilling one to three horizontal
development wells (all 100% working interest);
-- Initiate a waterflood at Mica;
-- Implement operating cost reductions at Bellamont's properties which are
expected to result in savings of more than $2.0 million per year; and
-- Further expand the liquids rich Montney gas resource at Umbach by
completing the fourth horizontal well (0.6 net) on the northern lands,
drilling and completing two to three additional horizontal wells (1.2 to
1.8 net) on the northern lands and drilling one vertical delineation
well (1.0 net) on the southern lands.
The acquisition of the Mica light oil property in the fourth quarter of 2011,
and the recently announced business combination with Bellamont, result from
Storm's commitment to grow its business in an environment of low natural gas
prices through commodity diversification which provides access to higher netback
opportunities. In addition, both transactions add to Storm's opportunity base
and provide additional financial capacity to support future growth. Storm
retains significant leverage to improving natural gas prices through the large
resource plays at Umbach and in the HRB where multi-year drilling upside has
been identified. With results to date in Umbach and the HRB having met or
exceeded expectations, we expect that the already significant resource we have
identified to date on our lands will continue to expand with future activity.
Success in converting only a portion of the best estimate of contingent
resources at Umbach and in the HRB (116.8 Mmboe net sales including SGR) will
result in significant future reserve growth.
Storm's efforts in 2012 will be primarily focused on growing liquids production
in the Grande Prairie, Mica, and Grimshaw areas while also continuing to expand
the identified liquids rich natural gas resource in the Montney formation at
Umbach. Our disciplined approach to capital investment has resulted in
significant growth for shareholders on a per-share basis since operations began
at the 'first Storm' in November 1998. We will continue doing what has worked so
well for us and are confident that it will carry us through the current low in
the natural gas commodity price cycle.
In closing, I would like to thank the hard working and talented team of Storm
employees for their efforts, our shareholders for their continued confidence and
our Board of Directors for their invaluable advice and guidance.
Respectfully,
Brian Lavergne, President and Chief Executive Officer
March 1, 2012
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 described herein 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, 2011
Storm's year-end reserve and resource evaluations effective December 31, 2011
were prepared by InSite Petroleum Consultants Ltd. ("InSite") which was formerly
Paddock Lindstrom & Associates Limited. InSite has evaluated all of Storm's
crude oil, NGL and natural gas reserves. The InSite price forecast at December
31, 2011 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 reserves totaled 3,714 Mboe and proved plus probable reserves
totaled 8,322 Mboe.
-- The proved finding and development cost as per NI 51-101 requirements
was $20.32 per Boe and the proved plus probable finding and development
cost, as per NI 51-101 requirements, was $14.60 per Boe. This includes
the change in future development costs ("FDC") and excludes the effect
of acquisitions, divestitures, and revisions.
-- The all-in cost to add proved reserves was $20.87 per Boe and for proved
plus probable reserves was $15.39 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, dispositions, revisions,
as well as the change in future development costs.
-- The net present value of proved plus probable reserves, discounted at
10% before tax, amounted to $54.5 million with the majority of this
being attributed to the Umbach (50%) and Mica properties (30%). The
InSite price forecast effective December 31, 2011 was used in the
reserve evaluation.
-- FDC was $30.2 million on a proved basis and $72.8 million on a proved
plus probable basis.
-- Drilling activity in 2011 resulted in the addition of 2,505 Mboe on a
proved basis and 5,278 Mboe on a proved plus probable basis.
-- In the HRB, proved plus probable reserves were 4,561 Mboe with 4,092
Mboe assigned to complete a standing horizontal shale gas well (0.4 net)
and to drill six horizontal shale gas wells (2.4 net). Recoverable
reserves assigned to each of the horizontal drilling locations was 9.6
to 10.4 Bcf of gross raw gas. Shrinkage of 12% was used to determine
sales gas volumes. Proved plus probable FDC was $123.8 million gross
($49.5 million net) which includes $14.8 million gross, or $5.9 million
net, being invested in associated infrastructure. In general, undrilled
horizontal development wells are recognized as part of proved plus
probable reserves if there is sufficient horizontal plus vertical well
control and if they are likely to be drilled within three years.
-- At Umbach, proved plus probable reserves were 2,975 Mboe with 2,336 Mboe
assigned to complete a standing horizontal well (0.6 net) and to drill
seven horizontal wells (4.2 net). Recoverable reserves assigned to each
of the horizontal drilling locations was 2.6 Bcf of gross raw gas.
Shrinkage of 11% was used as well as total liquids recovery of 40
barrels per Mmcf of sales gas. Proved plus probable FDC was $38.8
million gross ($23.3 million net). In general, undrilled horizontal
development wells are recognized as part of proved plus probable
reserves if there is sufficient horizontal plus vertical well control
and if they are likely to be drilled within three years.
-- At Mica, proved plus probable reserves totaled 722 Mboe (70% light oil
plus natural gas liquids) and is based on forecast decline from existing
producing wells; no reserves were included for infill drilling or
initiating a waterflood.
-- Based on an update completed by InSite effective January 31, 2012, the
acquisition of SGR added 2,645 Mboe proved reserves and 6,831 Mboe
proved plus probable reserves. Proved plus probable FDC was $74.2
million net to SGR. Note that the acquisition of SGR closed on January
12, 2012.
-- The resource opportunity on Storm's land base is significant. The best
case estimate of DPIIP at Umbach in the liquids rich Montney formation
is 465 Bcf gross raw gas over an area of 19.75 gross sections (13,762
gross acres, average Storm working interest of 57%). The evaluated area
covers less than 20% of Storm's land position in the area. The best case
estimate of DPIIP in the HRB is 3.1 Tcf gross raw gas over an area of 30
gross sections (19,463 gross acres) with Storm's average working
interest being 100% (after closing the acquisition of SGR on January 12,
2012). The evaluated area covers less than 22% of Storm's land position
in the area.
-- Future reserve growth will come from converting contingent resources to
proved plus probable reserves. The total best estimate of contingent
resources is 116,800 Mboe net sales with 14,058 Mboe at Umbach and
102,752 Mboe in the HRB (223 Bcf net sales to Storm plus 393 Bcf net
sales to SGR).
Gross Company Interest Reserves as at December 31, 2011
(Before deduction of royalties payable, not including royalties receivable)
Light Crude Oil Sales Gas NGL 6:1 Oil Equivalent
(Mbbls) (Mmcf) (Mbbls) (Mboe)
----------------------------------------------------------------------------
Proved producing 476 5,893 110 1,568
Proved non-
producing - - - -
----------------------------------------------------------------------------
Total proved
developed 476 5,893 110 1,568
Proved undeveloped - 12,038 140 2,146
----------------------------------------------------------------------------
Total proved 476 17,931 250 3,714
Probable additional 79 25,208 328 4,608
----------------------------------------------------------------------------
Total proved plus
probable 555 43,139 578 8,322
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross Company Reserve Reconciliation for 2011
(Gross company interest reserves before deduction of royalties payable)
6:1 Oil Equivalent (Mboe)
----------------------------------------------------------------------------
Total Proved plus
Proved Probable Probable
----------------------------------------------------------------------------
December 31, 2010 - opening balance 738 1,774 2,512
Acquisitions 634 92 726
Discoveries - - -
Extensions 2,505 2,773 5,278
Dispositions - - -
Technical revisions 35 (31) 4
Production (198) - (198)
----------------------------------------------------------------------------
December 31, 2011 - closing balance 3,714 4,608 8,322
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Future Development Costs
Proved
----------------------------------------------------------------------------
HRB 1.2 net horizontals plus infrastructure $ 21.3 million
Umbach 1.8 net horizontals $ 8.9 million
----------------------------------------------------------------------------
Total $ 30.2 million
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Proved Plus Probable
Additional
----------------------------------------------------------------------------
HRB 2.8 net horizontals plus infrastructure $ 49.5 million
Umbach 4.8 net horizontals $ 23.3 million
----------------------------------------------------------------------------
Total $ 72.8 million
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Proved Plus Probable
Proved Expenditures Additional Expenditures
----------------------------------------------------------------------------
2012 $ 5.9 million $ 12.9 million
2013 $ 16.0 million $ 29.2 million
2014 $ 7.4 million $ 8.9 million
2015 $ 0.8 million $ 16.4 million
2016 - $ 5.5 million
----------------------------------------------------------------------------
NI 51-101 Finding and Development Costs
Total Proved Finding and Development Cost 2011 2010
----------------------------------------------------------------------------
Capital expenditures excluding acquisitions and
dispositions (000s) $ 25,360 $ 16,800
Net change in FDC (000s) 25,541 4,679
----------------------------------------------------------------------------
Total capital including the net change in future capital
(000s) $ 50,901 $ 21,479
----------------------------------------------------------------------------
Reserve additions excluding acquisitions, dispositions
and revisions (Mboe) 2,505 738
Total proved finding and development costs (per Boe) $ 20.32 $ 29.10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Proved Plus Probable Finding and Development Cost 2011 2010
----------------------------------------------------------------------------
Capital expenditures excluding acquisitions and
dispositions (000s) $ 25,360 $ 16,800
Net change in FDC (000s) 51,725 21,057
----------------------------------------------------------------------------
Total capital including the net change in future capital
(000s) $ 77,085 $ 37,857
----------------------------------------------------------------------------
Reserve additions excluding acquisitions, dispositions
and revisions (Mboe) 5,278 2,512
Total proved plus probable finding and development costs
(per Boe) $ 14.60 $ 15.07
----------------------------------------------------------------------------
----------------------------------------------------------------------------
All-In Finding, Development and Acquisition Costs
Total Proved All-In Finding, Development and
Acquisition Cost including FDC, Acquisitions,
Dispositions, Revisions 2011 2010
----------------------------------------------------------------------------
Capital expenditures including acquisitions and
dispositions (000s) $ 40,795 $ 16,800
Net change in FDC (000s) 25,541 4,679
----------------------------------------------------------------------------
Total capital including the net change in future
capital (000s) $ 66,336 $ 21,479
----------------------------------------------------------------------------
Reserve additions including acquisitions, dispositions
and revisions (Mboe) 3,178 738
All-in total proved finding and development costs (per
Boe) $ 20.87 $ 29.10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Proved Plus Probable All-In Finding, Development
and Acquisition Cost including FDC, Acquisitions,
Dispositions, Revisions 2011 2010
----------------------------------------------------------------------------
Capital expenditures including acquisitions and
dispositions (000s) $ 40,795 $ 16,800
Net change in FDC (000s) 51,725 21,057
----------------------------------------------------------------------------
Total capital including the net change in future
capital (000s) $ 92,520 $ 37,857
----------------------------------------------------------------------------
Reserve additions including acquisitions, dispositions
and revisions (Mboe) 6,012 2,512
All-In total proved plus probable finding and
development costs (per Boe) $ 15.39 $ 15.07
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Present Value Summary (before tax) as at December 31, 2011
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)
----------------------------------------------------------------------------
Proved producing $ 52,462 $ 37,803 $ 29,777 $ 24,746 $ 21,304
Proved non-
producing - - - - -
----------------------------------------------------------------------------
Total proved
developed $ 52,462 $ 37,803 $ 29,777 $ 24,746 $ 21,304
Proved undeveloped 20,114 8,967 2,575 (1,282) (3,694)
----------------------------------------------------------------------------
Total proved $ 72,576 $ 46,770 $ 32,352 $ 23,464 $ 17,609
Probable additional 82,519 41,976 22,153 11,392 5,113
----------------------------------------------------------------------------
Total proved plus
probable $ 155,095 $ 88,747 $ 54,505 $ 34,856 $ 22,722
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Numbers in this table may not add due to rounding.
Net Present Value Summary (after tax) as at December 31, 2011
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 $ 52,462 $ 37,803 $ 29,777 $ 24,746 $ 21,303
Proved non-
producing - - - - -
----------------------------------------------------------------------------
Total proved
developed $ 52,462 $ 37,803 $ 29,777 $ 24,746 $ 21,303
Proved undeveloped $ 20,114 $ 8,967 $ 2,575 $ (1,282) $ (3,694)
----------------------------------------------------------------------------
Total proved $ 72,576 $ 46,770 $ 32,352 $ 23,464 $ 17,609
Probable additional $ 62,590 $ 32,123 $ 16,849 $ 8,353 $ 3,285
----------------------------------------------------------------------------
Total proved plus
probable $ 135,166 $ 78,893 $ 49,201 $ 31,817 $ 20,894
----------------------------------------------------------------------------
----------------------------------------------------------------------------
InSite Escalating Price Forecast as at December 31, 2011
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)
----------------------------------------------------------------------------
2012 100.00 98.00 3.90 3.45 58.80 73.50
2013 101.00 99.00 4.50 4.04 59.40 74.25
2014 102.00 99.96 5.00 4.53 59.98 74.97
2015 103.00 100.92 5.50 5.02 60.55 75.69
2016 104.00 101.88 6.00 5.51 61.13 76.41
----------------------------------------------------------------------------
----------------------------------------------------------------------------
InSite Summary of DPIIP and Contingent Resources for the Horn River Basin
Effective December 31, 2011
Independent evaluator, InSite, completed an evaluation of Storm's DPIIP and
contingent resources for the Muskwa and Otter Park formations. The evaluated
area covers 30 gross sections, or 19,463 gross acres. The InSite evaluation was
prepared in accordance with the Canadian Oil and Gas Evaluation Handbook. The
contingencies that prevent the contingent resources from being classified as
reserves are associated with the early evaluation stage of these potential
development opportunities. Additional drilling, completion and testing data is
generally required before a commitment can be made to their development. There
is no certainty that it will be commercially viable to produce any of the
resources. The key findings of the evaluation are as follows:
Low Estimate Best Estimate High Estimate
(1) (1) (1)
----------------------------------------------------------------------------
Muskwa and Otter Park
Average gross thickness 92 metres 92 metres 92 metres
Average porosity 3.5% 4.25% 5.0%
Gross DPIIP within
evaluation area (gross raw
Bcf)(2) 2,836 3,117 3,398
DPIIP net to Storm's working
interest (net raw Bcf)(2) 1,039 1,141 1,244
Proved plus probable
reserves net to Storm's
working interest (net sales
Bcf)(3)(4) 27 27 27
Estimated economic
contingent resources net to
Storm's working interest
(net sales Bcf)(3)(4)(5) 161 223 295
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Notes:
(1) Numbers in this table are subject to rounding error.
(2) DPIIP has been estimated using the gross shale thickness, gas saturation of
78 percent, gas formation volume factor of 205 scf per ft3, gas Z of 0.98,
reservoir temperature of 265 F, average reservoir pressure of 4,142 psig and
adsorbed gas content of 69 scf per ton.
(3) Contingent resources do not include proved plus probable reserves that were
assigned by InSite in the 2011 year-end reserve evaluation.
(4) Gas shrinkage of 12 percent is included in determining proved plus probable
reserves plus contingent resources.
(5) Storm's net working interest proved plus probable reserves and contingent
resources are before deducting royalties payable.
Proved plus probable reserves assigned in the 2011 year-end reserve evaluation
were 27 Bcf sales gas net to Storm and were excluded from estimated contingent
resources. The low estimate of contingent resources was 161 Bcf sales net to
Storm. The low estimate is the most conservative estimate and carries the
greatest level of confidence (at least 90 percent) that the resource will be
recovered. The best estimate (50 percent confidence) of contingent resources was
223 Bcf sales net to Storm. The high estimate (less than 10 percent confidence)
of contingent resources is 295 Bcf sales net to Storm. The remainder of the
DPIIP beyond what has been cumulatively produced, classified as proved plus
probable reserves, or classified as contingent resource, is currently considered
to be the unrecoverable portion.
InSite Summary of DPIIP and Contingent Resources for the Umbach Area
Effective December 31, 2011
InSite completed an evaluation of DPIIP and contingent resources for the Montney
formation on the northern land block. The evaluated area was 19.75 gross
sections (13,762 gross acres) with Storm's average working interest being 57%.
The InSite evaluation was prepared in accordance with the Canadian Oil and Gas
Evaluation Handbook. The contingencies that prevent the contingent resources
from being classified as reserves are associated with the early evaluation stage
of these potential development opportunities. Additional drilling, completion,
and testing data is generally required before a commitment can be made to their
development. There is no certainty that it will be commercially viable to
produce any of the resources. The key findings of the evaluation are as follows:
Low Estimate Best Estimate High Estimate
(1) (1) (1)
----------------------------------------------------------------------------
Montney
Average net pay 26 metres 26 metres 26 metres
Average porosity 7% 7% 7%
Gross DPIIP within evaluation
area (gross raw Bcf)(2) 465 465 465
DPIIP net to Storm's working
interest (net raw Bcf)(2) 266 266 266
Proved plus probable reserves
net to Storm's working
interest (net sales
Mboe)(3)(4) 2,975 2,975 2,975
Estimated economic contingent
resources net to Storm's
working interest (net sales)
(3)(4)(5)
Natural gas 58 Bcf 68 Bcf 78 Bcf
Natural gas liquids 2,309 Mbbls 2,694 Mbbls 3,078 Mbbls
Mboe 12,050 Mboe 14,059 Mboe 16,067 Mboe
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Notes:
(1) Numbers in this table are subject to rounding error.
(2) DPIIP has been estimated using a net pay cut-off of 20 metres, gas
saturation of 80 percent, gas formation volume factor of 161 scf per ft3, gas Z
of 0.8, reservoir temperature of 149 F and average reservoir pressure of 2,220
psia.
(3) Contingent resources do not include proved plus probable reserves that were
assigned by InSite in the 2011 year-end reserve evaluation.
(4) Gas shrinkage of 11 percent and 40 barrels of natural gas liquids per Mmcf
sales gas was used in determining proved plus probable reserves and contingent
resources.
(5) Storm's net working interest proved plus probable reserves and contingent
resources are before deducting royalties payable.
Proved plus probable reserves assigned in the 2011 year-end reserve evaluation
were 2,975 Mboe sales net to Storm and were excluded from estimated contingent
resources. The low estimate of contingent resources was 12,050 Mboe sales net to
Storm. The low estimate is the most conservative estimate and carries the
greatest level of confidence (at least 90 percent) that the resource will be
recovered. The best estimate (50 percent confidence) of contingent resources was
14,059 Mboe sales net to Storm. The high estimate (less than 10 percent
confidence) of contingent resources is 16,067 Mboe sales net to Storm. The
remainder of the DPIIP beyond what has been cumulatively produced, classified as
proved plus probable reserves, or classified as contingent resource, is
currently considered to be the unrecoverable portion.
RESERVES AND CONTINGENT RESOURCES ADDED AS A RESULT OF THE ACQUISITION OF SGR,
AS AT JANUARY 31, 2012
InSite evaluated the reserves and resources added as a result of the acquisition
of SGR, which closed on January 12, 2012. Note that the effective date of this
evaluation was January 31, 2012.
Gross SGR Interest Reserves as at January 31, 2012
(Before deduction of royalties payable)
6:1 Oil
Light Crude Oil Sales Gas NGL Equivalent
(Mbbls) (Mmcf) (Mbbls) (Mboe)
----------------------------------------------------------------------------
Proved producing - 3,121 - 520
Proved non-producing - - - -
----------------------------------------------------------------------------
Total proved developed - 3,121 - 520
Proved undeveloped - 12,746 - 2,124
----------------------------------------------------------------------------
Total proved - 15,868 - 2,645
Probable additional - 25,116 - 4,186
----------------------------------------------------------------------------
Total proved plus probable - 40,984 - 6,831
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Numbers in this table may not add due to rounding.
Future Development Costs Net to SGR
Proved
----------------------------------------------------------------------------
HRB 1.8 net horizontals plus infrastructure $ 31.9 million
----------------------------------------------------------------------------
Total $ 31.9 million
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Proved Plus Probable
Additional
----------------------------------------------------------------------------
HRB 4.2 net horizontals plus infrastructure $ 74.2 million
----------------------------------------------------------------------------
Total $ 74.2 million
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Proved Expenditures Proved Plus Probable Additional Expenditures
----------------------------------------------------------------------------
2012 - $ 7.1 million
2013 $ 19.5 million $ 21.0 million
2014 $ 11.1 million $ 13.3 million
2015 $ 1.2 million $ 24.6 million
2016 - $ 8.2 million
----------------------------------------------------------------------------
InSite Summary of SGR's DPIIP and Contingent Resources for the Horn River Basin
Effective January 31, 2012
Low Estimate Best Estimate High Estimate
(1) (1) (1)
----------------------------------------------------------------------------
Gross DPIIP within evaluation
area (gross raw Bcf) 2,836 3,117 3,398
DPIIP net to SGR's working
interest (net raw Bcf) 1,797 1,976 2,154
Proved plus probable reserves
net to SGR's working
interest (net sales Bcf) 41 41 41
Estimated economic contingent
resources net to SGR's
working interest (net sales
Bcf)(2)(3) 283 393 519
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Notes:
(1) Numbers in this table are subject to rounding error.
(2) DPIIP has been estimated using the gross shale thickness, gas saturation of
78 percent, gas formation volume factor of 205 scf per ft3, gas Z of 0.98,
reservoir temperature of 265 F, average reservoir pressure of 4,142 psig and
adsorbed gas content of 69 scf per ton.
(3) Contingent resources do not include proved plus probable reserves that were
assigned by InSite in the 2011 year-end reserve evaluation.
(4) Gas shrinkage of 12 percent is included in determining proved plus probable
reserves plus contingent resources.
(5) SGR's net working interest proved plus probable reserves and contingent
resources are before deducting royalties payable.
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", "expects", "believe",
"plans", "potential" 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; and production 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, 2011.
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.