Storm Exploration Inc. (TSX:SEO)
Consolidated Highlights
Three Months Three Months Year Year
Thousands of Cdn$, Ended Ended Ended Ended
except volumetric December 31, December 31, December 31, December 31,
and per share amounts 2009 2008 2009 2008
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FINANCIAL
Gas sales 18,554(1) 28,875(1) 66,750(1) 115,210(1)
NGL sales 3,350 2,542 9,670 11,782
Oil sales 2,963(1) 3,935 12,271(1) 20,821
Royalty income 36 95 179 711
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Production revenue 24,903(1) 35,447(1) 88,870(1) 148,524(1)
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Funds from operations (2) 13,798 20,432 44,596 87,490
Per share - basic ($) 0.30 0.46 0.96 1,96
Per share - diluted ($) 0.29 0.45 0.94 1.91
Net income (loss) 2,147 5,968 (317) 34,686
Per share - basic ($) 0.05 0.13 (0.01) 0.78
Per share - diluted ($) 0.05 0.13 (0.01) 0.76
Capital expenditures,
net of dispositions 5,844 35,342 55,608 94,954
Debt, including
working capital
deficiency 93,032(3) 98,790(3) 93,032(3) 98,790(3)
Weighted average common
shares outstanding
(000s)
Basic 46,711 44,702 46,275 44,654
Diluted 47,857 45,981 47,226 45,877
Common shares
outstanding (000s)
Basic 46,743 44,703 46,743 44,703
Fully diluted 49,757 46,970 49,757 46,970
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OPERATIONS
Oil equivalent (6:1)
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Barrels of oil
equivalent (000s) 726 751 2,966 2,554
Barrels of oil
equivalent per day 7,890 8,161 8,127 6,978
Average selling price
(Cdn$ per Boe) 34.68(1) 47.08(1) 29.95(1) 57.87(1)
Gas production
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Thousand cubic feet
(000s) 3,710 3,857 15,271 13,209
Thousand cubic feet
per day 40,325 41,919 41,839 36,089
Average selling price
(Cdn$ per Mcf) 5.00 7.49(1) 4.37 8.72(1)
NGL Production
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Barrels (000s) 60 45 211 140
Barrels per day 652 489 578 383
Average selling price
(Cdn$ per barrel) 55.84 56.52 45.84 83.97
Oil Production
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Barrels (000s) 48 63 210 212
Barrels per day 517 686 576 580
Average selling price
(Cdn$ per barrel) 68.69(1) 62.35 59.03(1) 98.06
Wells drilled
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Gross 3.0 9.0 11.0 29.0
Net 2.1 9.0 8.9 27.8
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(1) Includes results of hedging activities.
(2) Funds from operations and funds from operations per share are non-GAAP
measurements. See MD&A.
(3) Excludes unrealized liability related to financial instruments.
PRESIDENT'S MESSAGE
2009 IN REVIEW
- Average production in 2009 increased to 8,127 Boe per day, representing growth
of 16% from average production of 6,978 Boe per day in 2008. This is a per-share
increase of 12% using basic shares outstanding at year end.
- Fourth quarter production averaged 7,890 Boe per day, a decline of 3% from
production of 8,161 Boe per day in the fourth quarter of 2008. The decline was
due to a much smaller drilling program in 2009 (four horizontal Montney gas
wells versus 11 horizontal Montney gas wells drilled in 2008) which was in
response to a significant decline in natural gas prices. Fourth quarter
production was lower than our previous estimate of 8,200 to 8,300 Boe per day
due to a sudden increase in water production at a gas well at Kotcho (loss of
200 Boe per day from the third quarter average), cold weather in early December
delaying completions, well tie-ins, and the delayed start up of our new natural
gas liquids extraction plant ("refridge") at Parkland.
- For the year, Storm drilled 11 wells (8.9 net) which resulted in 11 gas wells
(8.9 net) for a 100% success rate. At our Parkland property, four horizontal
Montney gas wells (4.0 net) and four vertical Montney gas wells (4.0 net) were
drilled. This was a significant reduction from the 2008 drilling program of 29
wells (27.8 net) with 11 horizontal Montney gas wells (10.7 net). In the fourth
quarter, all three wells drilled were successful, resulting in three gas wells
(3.0 net) including two horizontal Montney gas wells.
- During 2009, we added to our Horn River Basin ("HRB") land position by
acquiring 32 gross sections (40% working interest) at Crown land sales. Our land
position in the HRB now totals 75 gross sections or 30 net sections. This area
offers the potential for significant production and reserve growth from the
Devonian aged Muskwa, Otter Park, and Evie/Klua shales.
- Cash flow for the year totaled $44.6 million, or $0.94 per diluted share, a
decrease of 51% from cash flow of $1.91 per diluted share in the prior year.
Although production increased 16% year over year, this was more than offset by a
48% decrease in the per-Boe wellhead price. A 51% decline in the average spot
price for natural gas ($3.74 per GJ at AECO in 2009 versus $7.71 per GJ at AECO
in 2008) was the primary cause for the decrease in the wellhead price. Fourth
quarter cash flow was $13.8 million, or $0.29 per diluted share.
- The 2009 cash flow netback was $15.03 per Boe, a decrease of 56% from the
prior year amount of $34.53 per Boe, which was due to lower commodity prices. In
addition, we had limited natural gas hedging protection which would have offset
some of the impact of the 51% decline in the average natural gas spot price. Our
fourth quarter cash flow netback improved to $19.00 per Boe as spot natural gas
prices increased to average $4.26 per GJ at AECO.
- Total cash costs declined 14% from the previous year to average $9.90 per Boe
in 2009 (includes operating expense, interest expense, transportation costs, and
cash general and administrative costs). Operating costs were $5.51 per Boe, an
18% improvement from the previous year. Operating costs showed improvement
throughout the year and averaged $5.23 per Boe in the fourth quarter.
- Net loss for the year was $0.3 million, or $0.01 per diluted share, compared
to income of $34.7 million, or $0.76 per diluted share, in 2008. Decreased
earnings were due to the significant decline in commodity prices with the
average wellhead price of $30.32 per Boe being 48% lower than in 2008. Charges
for depletion, depreciation and amortization, at $14.77 per Boe, were 10% lower
year over year, but this was not enough to offset the effect of the sharp
decline in commodity prices. Profitability did return in the fourth quarter with
net income of $2.1 million or $0.05 per diluted share.
- Net capital investment was $5.8 million in the fourth quarter and totaled
$55.6 million for the year. This included $16 million (29% of total capital
investment) to further expand our infrastructure at Parkland which will improve
our competitive advantage in the area. In 2009, dispositions totaled $18.6
million and acquisitions were $9.5 million. Storm's 2009 capital investment
program was funded primarily with cash flow. An equity issue completed in
February 2009 provided gross proceeds totaling $19.6 million and was used to
fund the acquisition of a gross overriding royalty at Parkland for $9.0 million
and to fund part of our infrastructure investment at Parkland.
- During the fourth quarter, non-core properties in the Grande Prairie area,
producing 214 Boe per day, were sold for proceeds totaling $17.2 million. The
effective date of this transaction was November 1, 2009.
- Bank debt and working capital deficiency at year end was $93.0 million, or 1.7
times annualized fourth quarter cash flow. This represents a year-over-year
decrease in total debt of $5.8 million. Storm's revolving bank credit facility
is $120 million.
- At December 31, 2009, proved producing reserves increased by 8% to 12.55
million Boe ("Mmboe"). Proved reserves were 25.3 Mmboe, a year-over-year
decrease of 4%. Proved plus probable reserves were 41.0 Mmboe, a decrease of 2%
from the previous year. The year-over-year decrease in proved and proved plus
probable reserves was due to non-core property dispositions, and a smaller
drilling program resulting in fewer reserve additions from exploration and
development activities. The proved plus probable reserve life index is 13.8
years using average 2009 production of 8,127 Boe per day.
- Proved and probable reserves assigned to our Montney discovery at Parkland
grew by 8%, or 2.8 Mmboe, and totaled 36.5 Mmboe at the end of 2009. This was
the result of successful vertical Montney delineation wells which expanded the
areal extent of our Montney discovery, and from the installation of a refridge
plant which increased recovery of natural gas liquids.
- The all-in cost to add reserves was $17.08 per Boe for proved reserves and
$14.69 per Boe for proved plus probable reserves (includes all capital
expenditures, the change in future development costs, acquisitions, dispositions
and revisions).
- The cost to add reserves per National Instrument 51-101, which excludes the
effect of acquisitions, dispositions and revisions, was $14.09 per Boe for
proved reserves and $9.66 per Boe for proved plus probable reserves.
- Estimated net asset value per fully diluted share at December 31, 2009 was
$13.49, using the pre-tax present value of proved and probable reserves
discounted at 10% with December 31, 2009 forecast prices.
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.
CORE AREA REVIEW
Parkland/Fort St. John Area, North East British Columbia
This area includes our Montney discovery and is the largest of Storm's core
areas, with net production averaging 5,913 Boe per day in the fourth quarter.
Average production in 2009 was 6,083 Boe per day, an increase of 44% from
average 2008 production of 4,219 Boe per day.
Fourth quarter activity included:
- Completing two vertical Montney step-outs (2.0 net) drilled earlier in the
year. Each well was completed separately in two intervals of the Montney (the
upper sands and the lower sands). Four intervals were completed with test rates
in excess of 1 Mmcf per day from each interval.
- Drilling two horizontal Montney development wells (2.0 net). One began
producing in mid-December and the other in mid-January, with first-month rates
from each well being restricted to approximately 4 Mmcf per day as a result of
bottlenecks in the pipeline gathering system.
- Expanding the second Parkland facility which now has capacity for 24 Mmcf per
day and adding a natural gas liquids ("NGL") extraction plant ("refridge").
Combined capacity at our two Parkland facilities is now 52 Mmcf per day with
throughput in January averaging 34.5 Mmcf per day of gross raw gas.
Our drilling program in 2010 will continue to be focused on our Parkland
property where we plan to drill 12 horizontal Montney development wells (10.1
net) and three vertical Montney step-outs (2.6 net). We expect to drill one
horizontal well in the first quarter which will test drainage in the lower
sands. If this well is successful, we plan to drill up to two more horizontals
into the lower sands in the third quarter.
Development of our Montney discovery continues to progress as expected. In
January 2010, production totaled 30 Mmcf per day of gross raw gas from 17
horizontal and 12 vertical Montney gas wells. We plan to drill an additional
seven horizontal wells (5.7 net) in the first quarter and we expect that four of
these will be completed, pipeline connected, and begin producing by the end of
March. First-year rates from our producing horizontal wells are averaging
approximately 2.4 Mmcf per day of raw gas which represents 440 Boe per day of
total sales per well.
We recently entered into a farm-in agreement covering four sections immediately
adjacent to our existing lands with Storm earning a 60% working interest in all
four sections by paying 100% of the cost to drill, complete, and tie in eight
horizontal wells and by paying 100% of the cost to drill two vertical wells. All
earning wells must be drilled before October 31, 2011. No reserves were assigned
to these lands in the year-end reserve evaluation. This is a relatively large
capital commitment to earn a 60% working interest in four sections of Montney
rights and reflects the high level of certainty we have in the upside potential
on these lands which is supported by offsetting vertical and horizontal well
control. We are planning to drill four of the earning horizontals and one
earning vertical in 2010.
The Paddock Lindstrom & Associates Limited ("PLA") year-end reserve evaluation
divided the Montney formation which is 80 to 110 metres thick into two units,
the upper sands and the lower sands. The presentation on our website contains a
log which shows both units. In the upper sands, the PLA evaluation recognized:
- Discovered Petroleum Initially in Place ("DPIIP")(1) of 1,331 Bcf of gross raw
gas (928 Bcf net to Storm) based on a productive area of 36.3 gross sections
(23.5 net sections) which includes the farm-in lands discussed above. A 3%
sandstone scale cut-off was used in determining net pay, which is consistent
with the BC Oil and Gas Commission and is a reduction from the 6% cut-off used
previously.
- A proved plus probable producing area of 13.5 gross sections (11.7 net
sections) containing estimated DPIIP of 535 Bcf of gross raw gas (466 Bcf net to
Storm) which is based on log analysis from 16 vertical gas wells on these lands
with average net pay of 43 metres (using a 3% sandstone scale cut-off) and
average porosity of 6.8%. In total, 244 Bcf of gross raw gas (210 Bcf net to
Storm) or 46% of DPIIP was recognized as ultimately recoverable using a density
of four horizontal wells per section. This includes the 17.6 Bcf of gross raw
gas that had been produced by the end of 2009. A total of 37 gross undrilled
horizontal locations (29.5 net) were assigned an average of 4.3 Bcf of proved
plus probable recoverable raw gas.
In the lower sands, no reserves or DPIIP was recognized in the PLA evaluation.
We have separately completed and tested the lower sands in six vertical wells
(including two in the fourth quarter) with final test rates ranging from 0.2 to
1.7 Mmcf per day. On one of these wells, there was evidence of possible
communication between completions in the upper and lower sands indicating that
the lower sands could be partially drained in some areas. Based on forecast
declines and recovery of DPIIP or Original Gas in Place ("OGIP")(1), it does not
appear that the lower sands are being effectively drained by the horizontals we
have drilled into the upper sands. The completed vertical wells show that an
area of 9.5 gross sections (7.8 net) is potentially productive with estimated
net pay of 22 to 37 metres (3% sandstone scale cut-off) and average porosity of
5.8%. Drainage and productivity of the lower sands will be evaluated as part of
our 2010 capital investment program. The first horizontal well into the lower
sands has already been drilled and should be completed and tied in by the end of
March.
Increasing our inventory of undrilled horizontal locations by expanding the
producing area of the Montney formation (upper and lower sands) is also an
objective for our 2010 capital investment program. We are planning to drill
three more vertical delineation wells in 2010 with one, at a 100% working
interest, being drilled in the first quarter.
During 2009, we invested $16 million to expand our infrastructure at Parkland by
completing the second facility, expanding it to 24 Mmcf per day of capacity, and
adding a refridge plant. In 2010, we are planning to invest $7 million to expand
and debottleneck the gathering system (Q1) and add a third compressor to expand
capacity of the second facility to 30 Mmcf per day (Q3).
Financial results from our Parkland property continue to improve. In the fourth
quarter, operating costs averaged $3.59 per Boe, the field netback was $23.48
per Boe and production averaged 5,913 Boe per day (14% oil and NGLs). For the
year, operating costs averaged $3.81 per Boe, the field netback was $19.50 per
Boe and production averaged 5,959 Boe per day (13% oil and NGLs). The addition
of the refridge plant in mid-December increased production by 420 Boe per day
with 80% of the increase being NGLs and is expected to reduce operating costs by
$2.5 to $3.0 million per year. We expect further gains in NGL recovery after the
gathering system has been expanded in the first quarter and we are able to
direct all of our wells producing higher heat content natural gas into the new
refridge plant. Approximately 30% of Storm's current production continues to be
processed at the McMahon gas plant where liquids recoveries will be unchanged
from current levels
Grande Prairie Area, North West Alberta
Production from this area averaged 1,315 Boe per day in the fourth quarter and,
for the year, production averaged 1,428 Boe per day which is a decline of 21%
from average 2008 production of 1,816 Boe per day. Current production is
approximately 1,100 Boe per day.
(1) When used in this press release, Discovered Petroleum Initially in Place
("DPIIP") is defined in the COGEH handbook as the quantity of hydrocarbons that
are estimated to be in place within a known accumulation. Original Gas in Place
("OGIP") is a more commonly used industry term when referring to gas
accumulations. 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.
During the fourth quarter, non-core properties at Saddle Hills, Sinclair, and
Valhalla were sold for proceeds totaling $17.15 million, comprised of $14
million cash plus 5.08 million shares of Bellamont Exploration Ltd., valued at
$0.62 per share. The effective date was November 1, 2009 and the transaction
closed on November 29, 2009. Production from the properties being sold averaged
214 Boe per day in the third quarter. At the end of 2008, proven and probable
reserves assigned to these properties totaled 1.176 million Boe (1.11 million
Boe adjusted for production to November 1) with future development capital of
$3.8 million.
Cabin-Kotcho-Junior Area, North East British Columbia
Net production from this area averaged 454 Boe per day in the fourth quarter.
Average production of 567 Boe per day during 2009 represents a 49% decline from
average production of 884 Boe per day in the year earlier period. Current
production is approximately 400 Boe per day.
This winter, we had planned to drill two horizontal wells plus install
compression at an existing facility to test the productivity of the Jean Marie
formation in the Junior area. These wells have been delayed and the capital
reallocated to fund a horizontal well testing the lower sands in the Montney at
Parkland. Based on mapping of the Jean Marie formation and proximity to
offsetting producing horizontals, we have 33 net sections in the area which have
the greatest potential to be developed with horizontal wells in the Jean Marie
formation. The estimated cost to drill, complete, and tie in a horizontal well
is approximately $2.1 million. Based on offsetting wells in the immediate area,
first-year rates could average 800 to 1,400 Mcf per day and 1.0 to 1.5 Bcf of
gross raw gas could be recovered with a horizontal well. Initial drilling
density would be one horizontal well per section.
Horn River Basin ("HRB"), North East British Columbia
Storm's undeveloped land position in the HRB is prospective for Devonian shale
gas in the Muskwa, Otter Park, and Evie/Klua formations and currently includes
75 gross sections at a 40% working interest (19,700 net acres), with Storm Gas
Resource Corp. ("SGR") owning the remaining 60% working interest. Combined with
Storm's 22% ownership position in SGR, our exposure to this unconventional shale
gas play is approximately 53%.
We have identified a central project area encompassing 35 gross sections (14.0
net) which contains an estimated 2.6 Tcf of gross DPIIP (internal estimate
prepared by Storm management). Our estimate of DPIIP is based on information and
data from various sources including wells in the immediate area and assumes:
- gross pay of 60 to 110 metres with 3.7% average porosity (both the Muskwa and
Otter Park shales);
- average gas saturation of 80%;
- average reservoir pressure of 25,200 kPaa;
- average gas content of 40 to 80 Scf/ton; and
- the adsorbed gas volume represents 45% of estimated DPIIP.
The Evie/Klua shale interval was not included in the DPIIP estimate because less
information is available regarding the productivity of this shale in the area.
Last winter, two vertical wells (60% SGR, 40% Storm) were drilled in the HRB
with the first well being cored, completed and flow tested in the Muskwa and
Otter Park shales. Results were encouraging but inconclusive in terms of
determining the potential for exploitation with multi-stage frac horizontal
wells.
Our plans for 2010 include:
- completing and testing the second vertical well drilled last winter in both
the Muskwa and Otter Park intervals as well as in the Evie/Klua interval (Q1);
- drilling one more vertical delineation well which will be cored in all three
shale intervals (Q1);
- constructing all-season roads and recording 3-D seismic across the southern
half of our core project area (Q1); and
- drilling one to two horizontal wells in the summer/fall with the estimated
cost of each well totaling $14 million gross, including $4 million for drilling
each horizontal and $10 million for completion with 10 to 12 fracs.
In total, Storm expects to invest approximately $12 to $15 million net to our
40% working interest in 2010 to advance the HRB shale project towards
commerciality. It is likely to be mid-2011 before we have enough production data
from the horizontal wells to have an opinion as to the commerciality of the
shales in our lands. Although the HRB has attracted a lot of attention and
excitement recently, this remains an early- stage project with a high level of
associated economic risk.
STORM GAS RESOURCE CORP.
Storm Gas Resource Corp. ("SGR") was formed in June 2007, to pursue
unconventional gas opportunities in the HRB and elsewhere. In October 2009, SGR
completed a private equity issue and raised $12.4 million (net of share issue
costs) at a price of $6.50 per share. Storm participated in this equity issue
and acquired an additional 0.45 million shares at $6.50 per share. Excluding
equity gains and losses, Storm's investment to date in SGR totals $9.1 million
and our share ownership position totals 2.5 million shares, representing 22%
ownership of SGR. Currently, SGR's land position in the HRB totals 131 gross
sections or 74 net sections. At the end of 2009, SGR's balance sheet showed a
cash position of approximately $31 million.
STORM VENTURES INTERNATIONAL INC.
Storm owns 4.5 million shares of Storm Ventures International Inc. ("SVI"), a
Calgary-based, private energy company focused on international exploration and
exploitation opportunities. Our share position has a value of $13.5 million
using a recent private placement equity financing which raised $150 million.
Proceeds from this equity financing were used to fund the acquisition of
properties in West Central Alberta for $190 million which are producing 5,100
Boe per day with proved plus probable reserves of 14.6 million Boe at October 1,
2009. The acquisition provides a new core growth area and the increased cash
flow, plus balance sheet capacity, will support activity planned for Tunisia and
the UK through 2011.
SVI is primarily focused on advancing three major international development
projects including the Remada Sud light oil discovery in Tunisia with DPIIP
independently estimated at 170 million barrels in the Ordovician Birben Tartar
formation, the Cosmos fallow discovery offshore Tunisia with estimated DPIIP of
25 million barrels, and the Vulcan project in the UK sector of the North Sea
with potentially 320 to 360 Bcf of DPIIP.
SVI has also entered into property acquisition agreements at Cobra (UK North Sea
gas) and Adam (onshore Tunisian oil) which will add 750 Boe per day of
production and 3 million Boe of proven plus probable reserves at a cost of US
$20.3 million.
Near term, most of SVI's planned activities are in Tunisia:
- The Ordovician discovery well at Sud Remada continues to flow 200 barrels per
day of light oil and a 3-D seismic survey has recently been completed. Two
additional appraisal/development wells are expected to be drilled in the first
half of 2010 to further assess the commercial potential of this discovery.
- At Jenein Center, four exploration targets have been identified with one
structure containing estimated DPIIP of 27 million barrels which will be tested
with a well in the first half of 2010 with SVI paying 30% of the cost while
retaining a 65% working interest.
- Offshore Tunisia in the Gulf of Hammamet, SVI expects to drill its first
exploration well at Fushia in 2010, with SVI paying 8% of the cost while
retaining a 35% working interest. The target is light oil in the Birsa sandstone
with estimated DPIIP being 40 to 100 million barrels of oil in place.
- With respect to the Cosmos fallow discovery, also in the Gulf of Hammamet, SVI
is in the process of sourcing a partner (maintaining 40% operated working
interest), has finalized the FPSO selection, agreed to participation terms with
ETAP, and is planning for first oil in mid-2011. Cosmos South was discovered in
1986 with two tested wells and DPIIP is potentially 25 million barrels of oil in
place with another 12 million barrels of oil in place associated with adjacent,
terraced structures.
OUTLOOK
First quarter 2010 production will be affected by the failure on February 6th of
a firetube inside a heater in our refridge plant at Parkland. As a result of
this, the refridge plant has been shut down until the firetube can be repaired.
Initially, our produced volumes were redirected to the first Parkland facility
which resulted in production being reduced by 1,200 Boe per day as numerous
wells were shut in given that capacity at this facility is limited to 28 Mmcf
per day of raw gas. On February 19th, all wells were producing again as we were
able to re-route gas from our second facility back to the McMahon Gas Plant;
however, with the refridge plant still shut in, production is reduced by
approximately 400 Boe per day. We expect to have the firetube repaired and
reinstalled by March 5th, which will allow us to restart the refridge plant.
Based on field estimates, production in January was approximately 8,100 Boe per
day and will be approximately 7,600 Boe per day in February. Prior to the
failure of the line heater, production had increased to approximately 8,700 Boe
per day as a result of the tie in of a new Montney horizontal well in
mid-January. Production is expected to increase significantly by the end of
March after we complete expansion of the pipeline gathering system and with the
anticipated tie in of four more horizontal Montney gas wells that are expected
to be drilled and completed in the first quarter. However, frac equipment
utilization is very high right now which has the potential to delay horizontal
well completions.
In 2010, we plan to reinvest cash flow and use a limited amount of debt to fund
our capital budget which includes:
- Capital investment of $85 to $90 million, with approximately 50% of this
amount being spent in the first half of 2010. This includes drilling 18 gross
wells (13.9 net), the expenditure of $12 to $15 million in the HRB to advance
the development of our shale gas project, and $7 million to further expand our
infrastructure at Parkland.
- A drilling program with 18 gross wells, including 12 horizontal development
wells (10.1 net) in our Montney discovery at Parkland, and one vertical well
plus one to two horizontal wells in the HRB at a 40% working interest.
- An allocation of $70 million to drilling, completion and tie-ins, the
above-mentioned $7 million to expanding infrastructure at Parkland, $5 million
for land and seismic, and $5 million for miscellaneous projects and contingency
items. Over 80% of our capital budget will be invested in the Parkland area.
- Exit production or production for the final quarter of 2010 of approximately
9,500 Boe per day, an increase of 20% over 2009 fourth quarter production.
- Operating costs for the year are forecast to be $4.50 per Boe.
- General and administrative costs for the year are expected to be $1.30 per Boe.
- The corporate royalty rate is expected to average 20%; this does not include
the effect of British Columbia's royalty incentive program.
Cash flow is expected to total $75 to $80 million, assuming average prices of
$5.00 per GJ at AECO for natural gas and Cdn $75.00 per barrel for oil at
Edmonton. The capital budget will be reviewed in mid-2010 and in the event that
natural gas prices are higher or lower than expected, the Company will adjust
capital spending at that time to better match cash flow.
Natural gas prices so far this year have averaged $5.25 per GJ at AECO, which is
a significant improvement from the 2009 average AECO spot price of $3.74 per GJ.
We expect to rely more heavily on hedging than we have in the past to provide
support for our capital investment program, given that development of our
resource-style opportunities is capital intensive. Given our low cost structure,
a natural gas price of $5.00 per GJ at AECO provides a 50% rate of return on
horizontal Montney development wells at Parkland and provides sufficient cash
flow corporately to fund 15% to 20% growth in production and to invest $12
million to advance our HRB shale gas project. In order to provide this level of
price support, we have been and will continue to enter into short-term financial
hedges that provide us with a floor price of $5.00 per GJ at AECO. Where
appropriate, we will use collars to retain exposure to upside in natural gas
price should the current rally continue. Information regarding our current hedge
position is provided in management's discussion and analysis of the financial
results. These hedges, combined with the disposition of non-core properties in
the Grande Prairie area late in 2009, ensure that we have the financial capacity
to execute on our 2010 plans.
At Parkland, the potential growth associated with our Montney discovery is
significant with the current undrilled inventory of 29.5 net horizontal wells in
the upper sands (proved plus probable locations in the year-end reserve
evaluation) representing potential future net production additions totaling
12,900 Boe per day using the average first-year rate of 440 Boe per day per
horizontal. Our focus in 2010 will be on proving up the additional upside
potential associated with:
- Further expansion of the producing area of the upper sands, with eight gross
sections (5.0 net) being the most prospective at this time based on existing
well control, which potentially adds 20 net undrilled horizontal locations in
the upper sands representing possible future net production additions of 8,800
Boe per day.
- Drilling the earning wells for a farm-in we recently completed on four
immediately adjacent sections (60% working interest earned once the commitment
wells are drilled) which will potentially add 9.6 net undrilled horizontal wells
in the upper sands to our inventory and 4,200 Boe per day of net future
production additions.
- Evaluating the lower Montney sands which have potential for 31.2 net undrilled
horizontal locations in the 7.8 net sections most likely to be productive based
on vertical well control.
Although we have generated significant growth at Parkland over the last three
years, we believe that there still remains significant upside associated with
this asset.
We are pleased to announce that Mr. Jim Wilson has joined Storm's Board of
Directors and has agreed to chair the Audit Committee. Mr. Wilson is a Chartered
Accountant with 28 years of industry experience, having served as an officer and
director of a number of public and private oil and gas production and
exploration companies. His responsibilities have included finance, treasury, tax
planning, strategic planning, risk management, accounting, human resources and
administration activities.
Our focus on accretively growing net asset value has not changed. We will
continue to be patient in our hunt for new opportunities given the future growth
potential offered by our existing asset base, which includes several years of
low-risk development opportunities as well as exposure to what could be a very
high impact shale gas project in the HRB. Our low cost structure combined with
the depth and quality of our inventory allows us to remain focused on growing
net asset value per share over the long term which will benefit all
shareholders.
The severe financial crisis and extreme commodity price volatility presented us
with many challenges to overcome during 2009. I would like to thank our
employees and directors for their hard work and effort during this very
difficult period and once again very much appreciate the continued patience and
support of our shareholders.
Sincerely,
Brian Lavergne, President and Chief Executive Officer
February 24, 2010
RESERVES AT DECEMBER 31, 2009
Storm's year-end reserve evaluation effective December 31, 2009 was prepared by
Paddock Lindstrom & Associates Limited ("PLA"). PLA has evaluated all of Storm's
crude oil, NGL and natural gas reserves. The PLA price forecast at December 31,
2009 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 PLA, and the report of the Reserves Committee has been
accepted by the Company's Board of Directors.
Summary
- Proved developed producing ("PDP") reserves increased by 8% from the previous
year and totaled 12.55 Mmboe. The year-over-year increase in PDP reserves is the
result of increased production levels from the Montney formation at Parkland
where declines are forecast to continue flattening over time. PDP reserves
represent 50% of proved reserves, compared to 44% in 2008, and 31% of proved
plus probable reserves compared to 28% in 2008.
- Proved reserves totaled 25.3 Mmboe, a decrease of 1.1 Mmboe, or 4%, from last
year. The decrease is primarily the result of the disposition of non-core
properties with 0.7 Mmboe of proved reserves. Excluding dispositions, additions
net of revisions were 2.6 Mmboe and replaced 88% of 2009 production. The proved
reserve life index ("RLI") is 8.8 years using fourth quarter 2009 production of
7,890 Boe per day.
- Proved plus probable reserves totaled 41.0 Mmboe, a decrease of 0.9 Mmboe, or
2%, from the year earlier. The decrease is the result of the disposition of
non-core properties with 1.1 Mmboe of proved plus probable reserves. Excluding
dispositions, additions net of revisions were 3.2 Mmboe and replaced 107% of
2009 production. The proved plus probable RLI is 14.2 years using fourth quarter
2009 production of 7,890 Boe per day.
- The proved finding and development cost, as per NI 51-101 requirements, was
$14.09 per Boe and the proved plus probable finding and development cost, as per
NI 51-101 requirements, was $9.66 per Boe. The change in future development
costs ("FDC") was included in the calculation and the effect of acquisitions,
divestitures, and revisions was excluded. For comparison, the three-year average
is $13.95 per Boe for proved and $10.46 per Boe for proved plus probable
reserves.
- The all-in cost to add proved reserves was $17.08 per Boe, and for adding
proved plus probable reserves was $14.69 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. For comparison, the three-year average is
$15.20 per Boe for proved and $11.99 per Boe for proved plus probable.
- The net present value of proved plus probable reserves, discounted at 10%
before tax, amounted to $664 million which results in the estimated net asset
value per fully diluted share at December 31, 2009 being $13.49 after deducting
total debt at year end and after adding value for undeveloped land and for our
share ownership position in SGR and SVI. The forecast AECO natural gas price
used in the first three years of the evaluation averages $6.29 per Mmbtu or
$5.96 per GJ which is comparable to current futures prices.
- Future development costs were $117.3 million on a proved basis and $193.6
million on a proved plus probable basis. A breakdown of these amounts follows.
Future Development Costs
Proved 2009 2008
----------------------------------------------------------------------------
Parkland horizontal Montney locations $104.6 mllion $114.2 million
# of Parkland horizontal Montney locations 17.5 net 20 net
Parkland Montney completions, tie-ins $3.9 million $8.8 million
Parkland infrastructure $8.3 million $13 million
Remaining wells/properties $0.5 million $4.3 million
----------------------------------------------------------------------------
Total proved $117.3 million $140.3 million
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Proved Plus Probable 2009 2008
----------------------------------------------------------------------------
Parkland horizontal Montney locations $177.9 million $183.0 million
# of Parkland horizontal Montney locations 29.5 net 31.6 net
Parkland Montney completions, tie-ins $3.9 million $8.8 million
Parkland infrastructure $8.3 million $14.5 million
Remaining wells/properties $3.5 million $12.5 million
----------------------------------------------------------------------------
Total proved plus probable $193.6 million $218.8 million
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Storm is currently planning to drill 12 horizontal Montney gas wells (10.1 net)
in 2010.
- During 2009, non-core properties with proved and probable reserves of 1,108
Mboe were sold at an average price of $18.91 per Boe including the impact of
FDC.
- The majority of reserves were assigned to the Parkland property, which
represented 91% of total Company proved reserves and 93% of total Company proved
plus probable reserves.
Reserves Breakdown
2009 2008
----------------------------------------------------------------------------
Proved producing
Parkland Montney (Mboe) 9,468 6,567
Parkland Halfway/Doig (Mboe) 855 1,402
Remaining wells/properties (Mboe) 2,228 3,635
----------------------------------------------------------------------------
Total proved producing 12,551 11,604
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Proved
Parkland Montney (Mboe) 22,107 20,807
Parkland Halfway/Doig (Mboe) 983 1,586
Remaining wells/properties (Mboe) 2,240 3,991
----------------------------------------------------------------------------
Total proved 25,330 26,384
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Proved plus probable additional
Parkland Montney (Mboe) 36,549 33,771
Parkland Halfway/Doig (Mboe) 1,396 2,512
Remaining wells/properties (Mboe) 3,062 5,619
----------------------------------------------------------------------------
Total proved plus probable additional 41,007 41,902
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- At Parkland, 37 gross undrilled horizontal Montney well locations (29.5 net)
were recognized in the upper sands as part of the proved plus probable
evaluation, an increase from 32 gross (31.6 net) at the end of 2008. An average
of 4.3 Bcf gross raw recoverable gas (785 Mboe sales) was assigned to each
undrilled horizontal which is an increase from last year where an average of 4.2
Bcf gross raw gas was assigned to undrilled horizontals. Average cost to drill,
complete, and tie in each horizontal increased to $6.0 million in the 2009
evaluation versus $5.8 million previously, which is the result of increasing
frac density to nine fracs per horizontal from eight fracs. In general,
undrilled horizontal development wells are recognized as part of proved plus
probable reserves if there is sufficient well control and if they are likely to
be drilled within three years.
- At Parkland, PLA has estimated DPIIP in the upper sands of the Montney
formation to be 1,331 Bcf of gross raw gas, or 928 Bcf net to Storm. This
estimate is based on an area of 36.25 gross sections, or 23.5 net sections.
Proved plus probable reserves in the upper sands were assigned to 13.5 gross
sections (11.7 net) where DPIIP is estimated to be 535 Bcf of gross raw gas (466
Bcf net to Storm). In total, 244 Bcf of gross raw gas (210 Bcf net to Storm) was
recognized as recoverable from the upper sands, which includes the 17.6 Bcf of
gross raw gas that had been produced by the end of 2009. This represents a
recovery of 46% from the upper sands within the proved plus probable area.
- The recycle or reinvestment ratio was 0.9 times for proved reserves and 1.0
times for proved plus probable reserves, using the cash flow netback of $15.03
per Boe for 2009. This measurement uses the all-in proved finding cost of $17.08
per Boe and the all-in proved plus probable finding cost of $14.69 per Boe
(reflects Storm's entire capital investment program including acquisitions,
dispositions, revisions, as well as the change in future development costs). The
2009 recycle ratio was impacted by low natural gas prices and the absence of
meaningful hedges.
- Net downward revisions to prior year reserves totaled 2.3% on a proved basis
and 4.8% on a proved plus probable basis. Revisions to last year's proved plus
probable reserves totaled 2.0 Mmboe with major revisions being experienced at
our Kotcho and Teepee properties where the performance of two gas wells suddenly
deteriorated (-0.5 Mmboe proved plus probable), at Parkland where recoveries
from the Halfway and Doig formations were reduced due to continued uncertainty
with well performance (-0.9 Mmboe proved plus probable), and at Junior where a
probable Slave Point drilling location was removed due to uncertainty with
timing (-0.2 Mmboe proved plus probable).
Gross Company Interest Reserves as at December 31, 2009
(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 126 63,923 1,772 12,551
Proved non-producing - 5,823 176 1,147
----------------------------------------------------------------------------
Total proved
developed 126 69,746 1,948 13,698
Proved undeveloped - 58,254 1,922 11,632
----------------------------------------------------------------------------
Total proved 126 128,000 3,870 25,330
Probable additional 27 79,131 2,462 15,677
----------------------------------------------------------------------------
Total proved plus
probable 153 207,131 6,332 41,007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross Company Reserve Reconciliation for 2009
(Gross company interest reserves before deduction of royalties payable)
6:1 Oil Equivalent (Mboe)
----------------------------------------------------------------------------
Total Proved plus
Proved Probable Probable
----------------------------------------------------------------------------
December 31, 2008 - opening balance 26,384 15,518 41,902
Acquisitions - - -
Discoveries - - -
Extensions 3,233 1,971 5,204
Dispositions (706) (402) (1,108)
Technical revisions (615) (1,410) (2,025)
Production (2,966) - (2,966)
----------------------------------------------------------------------------
December 31, 2009 - closing balance 25,330 15,677 41,007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NI 51-101 Finding and Development Costs
Total Proved Finding and Development
Cost 2009 2008 Three-Year Total
----------------------------------------------------------------------------
Capital expenditures excluding
acquisitions and dispositions (000s) $ 64,701 $ 102,650 $ 236,638
Net change from previously
allocated future development capital
(000s) (20,109) 121,090 117,622
----------------------------------------------------------------------------
Total capital including the net
change in future capital (000s) $ 44,592 $ 223,740 $ 354,260
----------------------------------------------------------------------------
Reserve additions excluding
acquisitions, dispositions and
revisions (Mboe) 3,165 17,288 25,388
Total proved finding and development
costs (per Boe) $ 14.09 $ 12.94 $ 13.95
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Proved Plus Probable Finding
and Development Cost 2009 2008 Three-Year Total
----------------------------------------------------------------------------
Capital expenditures excluding
acquisitions and dispositions (000s) $ 64,701 $ 102,650 $ 236,638
Net change from previously
allocated future development capital
(000s) (15,128) 174,036 194,593
----------------------------------------------------------------------------
Total capital including the net
change in future capital (000s) $ 49,573 $ 276,686 $ 431,231
----------------------------------------------------------------------------
Reserve additions excluding
acquisitions, dispositions and
revisions (Mboe) 5,134 26,331 41,213
Total proved plus probable finding
and development costs (per Boe) $ 9.66 $ 10.51 $ 10.46
----------------------------------------------------------------------------
----------------------------------------------------------------------------
All-In Finding, Development and Acquisition Costs
Total Proved All-In Finding,
Development and Acquisition Cost
including FDC, Acquisitions,
Dispositions, Revisions 2009 2008 Three-Year Total
----------------------------------------------------------------------------
Capital expenditures including
acquisitions and dispositions
(000s) $ 55,608 $ 95,500 $ 244,880
Net change from previously
allocated future development
capital (000s) (22,948) 117, 206 110,864
----------------------------------------------------------------------------
Total capital including the net
change in future capital (000s) $ 32,660 $ 212,706 $ 355,744
----------------------------------------------------------------------------
Reserve additions including
acquisitions, dispositions and
revisions (Mboe) 1,912 16,336 23,407
All-in total proved finding and
development costs (per Boe) $ 17.08 $ 13.02 $ 15.20
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Proved Plus Probable All-In
Finding, Development and
Acquisition Cost including FDC,
Acquisitions,
Dispositions, Revisions 2009 2008 Three-Year Total
----------------------------------------------------------------------------
Capital expenditures including
acquisitions and dispositions
(000s) $ 55,608 $ 95,500 $ 244,880
Net change from previously
allocated future development
capital (000s) (25,194) 171,177 177,777
----------------------------------------------------------------------------
Total capital including the net
change in future capital (000s) $ 30,414 $ 266,677 $ 422,657
----------------------------------------------------------------------------
Reserve additions including
acquisitions, dispositions and
revisions (Mboe) 2,071 23,974 35,249
All-In total proved plus probable
finding and development costs
(per Boe) $ 14.69 $ 11.12 $ 11.99
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total exploration and development costs incurred in the most recent financial
year and the change during that year in estimated future development costs,
generally will not reflect the total cost of reserve additions in that year.
Net Present Value Summary (before tax) as at December 31, 2009
Benchmark oil and NGL prices used are adjusted for quality of oil or NGL prduced
and for transportation costs. The calculated NPVs include a deduction for
estimated future well abandonment costs.
Discounted Discounted Discounted Discounted
at at at at
Undiscounted 5% 10% 15% 20%
(000s) (000s) (000s) (000s) (000s)
----------------------------------------------------------------------------
Proved producing $ 420,904 $ 321,467 $ 262,791 $ 224,426 $ 197,385
Proved non-producing 37,425 29,246 24,240 20,858 18,402
----------------------------------------------------------------------------
Total proved developed 458,329 350,713 287,031 245,284 215,787
Proved undeveloped 355,075 225,453 154,035 110,148 80,950
----------------------------------------------------------------------------
Total proved 813,404 576,166 441,066 355,432 296,737
Probable additional 587,724 337,575 222,814 159,690 120,410
----------------------------------------------------------------------------
Total proved plus
probable $1,401,128 $ 913,741 $ 663,880 $ 515,122 $ 417,147
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Present Value Summary (after tax) as at December 31, 2009
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
at at at at
Undiscounted 5% 10% 15% 20%
(000s) (000s) (000s) (000s) (000s)
----------------------------------------------------------------------------
Proved producing $ 367,373 282,924 $ 232,758 $ 199,737 $ 176,325
Proved non-producing 27,727 21,520 17,722 15,157 13,299
----------------------------------------------------------------------------
Total proved developed 395,100 304,444 250,480 214,894 189,624
Proved undeveloped 265,913 165,742 110,268 76,083 53,326
----------------------------------------------------------------------------
Total proved 661,013 470,186 360,748 290,977 242,950
Probable additional 440,918 251,188 164,004 116,027 86,206
----------------------------------------------------------------------------
Total proved plus
probable $ 1,101,931 $ 721,374 $ 524,752 $ 407,004 $ 329,156
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Paddock Lindstrom & Associates Ltd. Escalating Price Forecast as at December
31, 2009
Edmonton
WTI Light Henry Hub AECO
Crude Oil Crude Oil Natural Gas Natural Gas Propane Butane
(US$/Bbl) (Cdn$/Bbl) (US$/Mmbtu) (Cdn$/Mmbtu) (Cdn$/Bbl) (Cdn$/Bbl)
----------------------------------------------------------------------------
2010 80.00 82.43 6.00 5.82 49.46 61.82
2011 82.50 85.02 6.50 6.29 51.01 63.77
2012 85.00 87.62 7.00 6.77 52.57 65.71
2013 90.00 92.84 7.50 7.28 55.71 69.63
2014 95.00 98.07 8.00 7.80 58.84 73.55
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2009 Actual 2009 Actual 2009 Actual
Price and PLA Price and PLA Price and PLA
Forecast Price Forecast Price Forecast Price
Storm Wellhead Storm Wellhead Storm Wellhead
Oil Price Gas Price NGL Price
(Cdn$/Bbl) (Cdn$/Mcf) (Cdn$/Bbl)
----------------------------------------------------------------------------
2009 Actual (1) 58.88 4.19 42.18
2010 (2) 79.93 6.08 48.40
2011 (2) 82.53 6.60 50.03
2012 (2) 85.27 7.14 51.55
2013 (2) 90.99 7.73 54.44
2014 (2) 95.88 8.31 57.40
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) 2009 actual wellhead price excludes hedging gains/losses and is after
deduction of transportation costs.
(2) PLA forecast prices are after deduction of transportation costs.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL AND OPERATING RESULTS FOR THE
THREE MONTHS AND YEAR ENDED DECEMBER 31, 2009
Set out below is management's discussion and analysis ("MD&A") of financial and
operating results for Storm Exploration Inc. ("Storm" or the "Company") for the
three months and year ended December 31, 2009. It should be read in conjunction
with the audited consolidated financial statements for the year ended December
31, 2009, the unaudited consolidated financial statements for the three months
ended March, June and September 2009 and other operating and financial
information included in this report. In addition, readers are directed to the
discussion below regarding Forward-Looking Statements, Boe Presentation and
Non-GAAP Measurements.
This management's discussion and analysis is dated February 24, 2010.
INTRODUCTION AND LIMITATIONS
Basis of Presentation - Financial data presented below have largely been derived
from the Company's consolidated financial statements for the three months and
year ended December 31, 2009, prepared in accordance with Canadian Generally
Accepted Accounting Principles ("GAAP"). Accounting policies adopted by the
Company are set out in Note 2 to the audited consolidated financial statements
for the years ended December 31, 2009 and 2008. The reporting and the
measurement currency is the Canadian dollar. Unless otherwise indicated, tabular
financial amounts, other than per share and per Boe amounts, are in thousands.
Forward-Looking Statements - Certain information set forth in this document,
including management's assessment of Storm's future plans and operations,
contains forward-looking information (within the meaning of applicable Canadian
securities legislation). Such statements or information are generally
identifiable by words such as "anticipate", "believe", "intend", "plan",
"expect", "estimate", "budget", "outlook", "forecast" or other similar words and
include statements relating to or associated with individual wells, regions or
projects. Any statements regarding the following are forward-looking statements:
- future crude oil or natural gas prices;
- future production levels;
- future revenues or costs or revenues or costs per commodity unit;
- future capital expenditures and their allocation to specific exploration and
development activities;
- future drilling of new wells;
- future earnings;
- future asset acquisitions or dispositions;
- future sources of funding for capital program;
- future debt levels;
- availability of committed credit facilities;
- development plans;
- ultimate recoverability of reserves or resources;
- expected finding and development costs and operating costs;
- estimates on a per-share basis;
- dates or time periods by which certain geographical areas will be developed;
- changes to any of the foregoing; and
- the effect on financial reporting in future periods resulting from the
adoption of International Financial Reporting Standards on January 1, 2011.
Statements relating to "reserves" or "resources" are forward-looking statements,
as they involve the implied assessment, based on estimates and assumptions, that
the reserves and resources described exist in the quantities predicted or
estimated, and can be profitably produced in the future.
The forward-looking statements are subject to known and unknown risks and
uncertainties and other factors which may cause actual results, levels of
activity and achievements to differ materially from those expressed or implied
by such statements. Such factors include the material risks described in Storm's
Annual Information Form and this MD&A under "Risk Assessment" and the material
assumptions disclosed in the "Production and Revenue" section hereof under the
headings "Production Profile and Per-Unit Prices" and "Royalties"; under
"Production Costs"; "Field Netbacks", "Interest", "General and Administrative
Costs" and "Future Income Taxes"; under the "Investment and Financing" section
hereof, under the headings "Working Capital", "Bank Debt, Liquidity and Capital
Resources", "Investments", "Future Income Taxes", "Asset Retirement Obligation",
"Share Capital", "Contractual Obligations" and "Selected Annual Financial
Information"; industry conditions, volatility of commodity prices, currency
fluctuations, imprecision of reserve estimates, environmental risks, competition
from other industry participants, the lack of availability of qualified
personnel or management, stock market volatility and ability to access
sufficient capital from internal and external sources. All of these caveats
should be considered in the context of current economic conditions, in
particular reduced commodity prices and the condition of financial institutions
and markets, each of which is outside the control of the Company. Readers are
advised that the assumptions used in the preparation of such information,
although considered reasonable at the time of preparation, may prove to be
imprecise and, as such, undue reliance should not be placed on forward-looking
statements. Storm's actual results, performance or achievement, could differ
materially from those expressed in, or implied by, these forward-looking
statements. Storm disclaims any intention or obligation to publicly update or
revise any forward-looking statements, whether as a result of new information,
future events or otherwise, except as required under securities law. References
to forward-looking information are made elsewhere in this year-end report. The
forward-looking statements contained herein are expressly qualified by this
cautionary statement.
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.
Non-GAAP Measurements - Within management's discussion and analysis, references
are made to terms which are not recognized under GAAP in Canada. Specifically,
"funds from operations", "funds from operations per share", "field netbacks",
"cash costs" and "recycle ratio" as well as any "per-Boe" amounts, do not have
any standardized meaning as prescribed by GAAP in Canada and are regarded as
non-GAAP measures. It is likely that these non-GAAP measurements may not be
comparable to the calculation of similar amounts for other entities. In
particular, funds from operations is not intended to represent, or be equivalent
to, cash flow from operating activities calculated in accordance with Canadian
GAAP which appears on the Company's consolidated statements of cash flows. Funds
from operations and similar non-GAAP terms are used to benchmark operations
against prior periods and peer group companies. Non-GAAP funds from operations
is also used to determine debt to cash flow ratios for the purposes of
establishing interest costs under the Company's banking agreement.
A reconciliation of funds from operations to cash flows from operating
activities is as follows:
Year Ended Year Ended
December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Cash flow from operating activities $ 45,621 $ 85,972
Net change in non-cash working capital
items (1,025) 1,518
----------------------------------------------------------------------------
Non-GAAP funds from operations $ 44,596 $ 87,490
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Non-GAAP funds from operations per share is calculated using the weighted
average number of common shares outstanding consistent with the calculation of
net income per share. Non-GAAP field netbacks equals total revenue net of
hedging gains or losses, plus royalty income, less royalties paid, production
and transportation costs, calculated on a Boe basis for the reporting period.
Non-GAAP cash flow netback equals the field netback less interest and general
and administrative costs, also calculated on a Boe basis. Total Boe is
calculated by multiplying the daily production by the number of days in the year
or quarter as the case may be. Non- GAAP cash costs per Boe are the total of
production costs, transportation costs, interest and general and administrative
costs. Recycle ratio is calculated by dividing the field netback by finding
costs.
OPERATIONAL AND FINANCIAL RESULTS
Production and Revenue
Average Daily Production
Year Ended Year Ended
December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Natural gas (Mcf/d) 41,839 36,089
Natural gas liquids (Bbls/d) 578 383
Crude oil (Bbls/d) 576 580
----------------------------------------------------------------------------
Total (Boe/d) 8,127 6,978
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Boe production in 2009 increased by 16% when compared to 2008. The
year-over-year production increase is largely attributable to increased gas
production from the Company's core Parkland area. In 2009, production was
largely static quarter over quarter. The primary area for production growth
within the Company's opportunity inventory is its Montney natural gas discovery
at Parkland, British Columbia. Horizontal wells in the Montney tend to be
characterized by very high initial deliverability, followed by rapid production
declines for a period of several months; thereafter, production declines tend to
slow. Production growth from drilling horizontal wells at Parkland would have
resulted in the Company selling volumes produced at high initial rates into a
depressed market for natural gas. As a result, drilling activity was limited in
2009 which slowed the growth of Storm's production base. In addition, in 2009,
investment capital was also directed to facility expansion to handle future
production growth, which limited the amount of capital available for drilling.
In addition, effective November 1, 2009, Storm sold properties in the Peace
River Arch of Alberta, which produced approximately 214 Boe per day, largely
crude oil.
Production per million shares outstanding in 2009 averaged 174 Boe per day,
compared to 156 Boe per day in 2008, an increase of 12%.
Production Profile and Per-Unit Prices
Year Ended Year Ended
December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Percentage Average Selling Percentage Average Selling
of Price Before of Price Before
Total Boe Transportation Total Boe Transportation
Production Costs Production Costs
----------------------------------------------------------------------------
Natural gas - Mcf 86% $ 4.38 86% $ 8.88
Natural gas
liquids - Bbl 7% $ 45.84 6% $ 83.97
Crude oil - Bbl 7% $ 63.89 8% $ 98.06
----------------------------------------------------------------------------
Per Boe $ 30.32 $ 58.73
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Per-unit prices do not include adjustments for hedging gains or losses.
Storm's production base is largely natural gas and associated liquids. In
addition, Storm's prospect inventory is largely focused on natural gas and,
based on exploitation of the Company's existing asset base, in the short and
medium term crude oil will not materially increase as a percentage of Boe
production.
Storm's gas production in Alberta and British Columbia is sold at prices which
reflect both the benchmark AECO daily index pricing and Station 2 daily index
pricing. Prices for natural gas in 2009 fell throughout the year, until the
final months when a modest improvement became apparent. As an illustration of
the extent of the price decline, natural gas prices reached a ten-year low in
the third quarter of 2009. Pricing by quarter was as follows:
Year Ended Year Ended
December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Storm AECO C Station 2 Storm AECO C Station 2
Realized Daily Daily Realized Daily Daily
Price Average Average Price Average Average
(1) (1) (1) (1) (1) (1)
----------------------------------------------------------------------------
Q1 $ 5.52 $ 4.66 $ 4.57 $ 8.60 $ 7.49 $ 7.43
Q2 $ 3.65 $ 3.27 $ 3.06 $ 10.49 $ 9.68 $ 9.59
Q3 $ 3.30 $ 2.78 $ 2.75 $ 9.37 $ 7.34 $ 7.07
Q4 $ 5.05 $ 4.26 $ 4.24 $ 7.49 $ 6.34 $ 6.32
Year $ 4.38 $ 3.74 $ 3.65 $ 8.88 $ 7.71 $ 7.60
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Storm realized price is measured in Mcf; Index prices in GJ..
(2) Per-unit prices do not include adjustments for hedging gains or losses.
For 2009, approximately 63% of Storm's gas production was sold with reference to
Station 2 pricing compared to 67% in 2008.
Storm's corporate average realized price of $4.38 per Mcf for natural gas for
2009 was approximately 20% higher than the equivalent index price. This pricing
premium is attributable to high heat content natural gas produced from the
Montney formation at Parkland. In addition to superior heat content, Montney
natural gas contains significant natural gas liquids volumes which have resulted
in an approximate 51% year-to-date increase in natural gas liquids production.
The introduction of a refrigeration plant at Parkland in December 2009 should
result in increased liquids production in future periods, estimated to be more
than 300 barrels per day. However, this benefit will, to a degree, be offset by
a reduction in the pricing premium for natural gas attributable to heat content.
Production by Area - Boe/d
Year Ended Year Ended
December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Fort St. John/Parkland - BC 6,083 4,219
Grande Prairie - AB 1,428 1,816
Cabin-Kotcho-Junior - BC 567 884
Other 49 59
----------------------------------------------------------------------------
Total 8,127 6,978
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The above sets out the average production from each of Storm's main producing
areas. The Company's focus on the Parkland area has resulted in 44%
year-over-year production growth from this area. Correspondingly, reduced
investment in Alberta is evidenced by an approximate 21% reduction in
year-over-year production. Within the Parkland area, production from the Montney
approximated 5,200 Boe per day in 2009 compared to 2,600 Boe per day in 2008, an
increase of 100%. Halfway and Doig gas production, also from the Parkland area,
amounted to approximately 755 Boe per day in 2009, compared to approximately
1,406 Boe per day in 2008, a decline of 46%. This production decline is a result
of the dedication of investment capital to the higher margin Montney play and
from shutting in production due to low natural gas prices.
Production Revenue
Year Ended Year Ended
December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Natural gas $ 66,838 $ 117,397
Natural gas liquids 9,670 11,782
Crude oil 13,427 20,821
Royalty income 180 711
----------------------------------------------------------------------------
Revenue from product sales 90,115 150,711
Hedging (losses) gains (1,245) (2,187)
----------------------------------------------------------------------------
Total production revenue $ 88,870 $ 148,524
----------------------------------------------------------------------------
----------------------------------------------------------------------------
A reconciliation of revenue from product sales between 2009 and 2008 is as
follows:
Natural Gas Royalty
Natural Gas Liquids Crude Oil Income Total
----------------------------------------------------------------------------
Revenue from
product sales -
2008 $ 117,397 $ 11,782 $ 20,821 $ 711 $ 150,711
Effect of
production
changes
year over year 18,316 5,931 (210) (353) 23,684
Effect of
decreased product
prices
year over year (68,875) (8,043) (7,184) (178) (84,280)
----------------------------------------------------------------------------
Revenue from
product sales -
2009 $ 66,838 $ 9,670 $ 13,427 $ 180 $ 90,115
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The collapse in revenues for 2009 is largely due to the fall in natural gas
prices. Reduced commodity prices resulted in a year-over-year fall in revenue of
56%, offset by a 16% contribution from increased production, for an overall
reduction in revenue of 40%.
Hedging
Crude Oil:
Storm entered into a fixed price sale agreement in respect of 350 barrels of
crude oil per day, at a price of $59.40 per barrel for the period April 1 to
June 30, 2009 and collars for the same volume for each of the last two quarters
of 2009, at prices of $60 - $65/Bbl and $60 - $70/Bbl, respectively. Completion
of these contracts resulted in a hedging loss of $1.0 million. In addition, the
Company has a crude oil swap in place for the period January 1, 2010 to June 30,
2010 in respect of 450 barrels of crude oil per day at a fixed price of $83.45
per barrel. At December 31, 2009, the Company recognized on the Consolidated
Statements of Income (Loss) and Retained Earnings, an unrealized mark-to-market
loss of $0.1 million on these contracts. Accounting for crude oil derivative
contracts follows mark-to-market rules.
Natural Gas:
In 2009 Storm also entered into fixed price natural gas sales contracts for the
period November 1, 2009 to June 30, 2010. The Company realized a hedging loss of
$0.1 million on these contracts for the year ended December 31, 2009. Contracts
outstanding at December 31, 2009 are as follows:
Volume Price Term
----------------------------------------------------------------------------
Natural Gas Swaps
28,000 GJ/day $ 4.89 January 2010 - March 2010
21,000 GJ/day $ 4.78 April 2010 - June 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company uses hedge accounting rules for these contracts and has recognized
an unrealized hedging loss in the amount of $1.7 million on the Consolidated
Statements of Comprehensive Income (Loss) in respect of contracts outstanding at
December 31, 2009.
Subsequent to December 31, 2009, Storm entered into additional natural gas
hedging contracts:
Volume Price Term
----------------------------------------------------------------------------
Collar
7,000 GJ/day $ 5.00 - $5.70 April 2010 - September 2010
Swap
5,000 GJ/day $5.20 July 2010 - September 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
No amounts were recognized in 2009 for potential gains or losses on these
contracts. It is possible that additional hedges will be put in place in 2010.
Although in prior years Storm has not been an aggressive user of hedging
instruments, the extreme volatility of natural gas prices over the last two
years has resulted in erratic cash flows. Maintaining a consistent capital
investment program requires cash flow stability, with the result that a
disciplined hedging program may form an integral part of the Company's
operational approach.
Royalties
Year Ended Year Ended
December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Charge for year $ 15,069 $ 31,021
Royalties as a percentage of revenue
from product sales before hedging
Crown 16.4% 19.9%
Other 0.3% 0.7%
----------------------------------------------------------------------------
Total 16.7% 20.6%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Per Boe $ 5.08 $ 12.15
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Royalties are paid primarily to the provincial governments in Alberta and
British Columbia. The year-over-year reduction in the effective rate, and the
per-Boe reduction are largely a result of falling commodity prices.
Additionally, under the new Royalty Framework in Alberta, royalty rates have
fallen below those applicable under the pre-existing royalty regime. Recently
announced changes to the New Royalty Framework in Alberta will have no effect on
existing royalties, but the extension of the royalty holiday by one year may
benefit future quarters and provides the Company with more flexibility regarding
the timing of future drilling in Alberta. Similarly, recent changes to the
royalty regime in British Columbia will also benefit future quarters.
Production Costs
Year Ended Year Ended
December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Charge for year $ 16,335 $ 17,065
Percentage of revenue from product
sales before hedging 18.1% 11.3%
Per Boe $ 5.51 $ 6.68
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Although production grew by 16% in 2009, cost reduction efforts, a better
seasonal operating cost profile, the shut in of higher cost production and
increasing volumes of lower operating cost natural gas from the Company's
Parkland property, resulted in a 4% reduction in year-over-year production
costs. Per Boe, the effect was to reduce costs in 2009 by nearly 18%. Management
expects that the introduction of a refrigeration plant at Parkland in December
2009, will result in a further reduction in operating costs, effective the first
quarter of 2010.
Storm's cash costs per Boe, which comprise production, transportation, interest
and general and administrative costs, amounted to $9.90 for 2009, compared to
$11.47 for 2008, a reduction of 14%.
Transportation Costs
Year Ended Year Ended
December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Charge for year $ 4,711 $ 5,279
Percentage of revenue from product
sales before hedging 5.2% 3.5%
Per Boe $ 1.59 $ 2.07
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total transportation costs fell by 11% year over year, in spite of increased
production. Increased gas production from the Parkland area and the shut in of
higher cost production elsewhere in 2009 resulted in lower costs. Storm's low
per-unit production and transportation costs reflect Storm's high level of
operatorship as well as facility control and ownership and reasonable proximity
to major pipelines.
Field Netbacks
Details of field netbacks per commodity unit are as follows:
Year Ended December 31, 2009
----------------------------------------------------------------------------
Natural Gas
Crude Oil Liquids Natural Gas Total
($/Bbl) ($/Bbl) ($/Mcf) ($/Boe)
----------------------------------------------------------------------------
Product sales $ 63.89 $ 45.84 $ 4.38 $ 30.32
Hedging loss -
realized (4.86) - (0.01) (0.37)
Royalty income 0.15 0.07 0.01 0.06
Royalties (10.14) (10.48) (0.70) (5.08)
Production costs (1) (7.77) - (0.96) (5.51)
Transportation (5.01) (3.66) (0.19) (1.59)
----------------------------------------------------------------------------
Field netback $ 36.26 $ 31.77 $ 2.53 $ 17.83
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year Ended December 31, 2008
----------------------------------------------------------------------------
Natural Gas
Crude Oil Liquids Natural Gas Total
($/Bbl) ($/Bbl) ($/Mcf) ($/Boe)
----------------------------------------------------------------------------
Product sales $ 98.06 $ 83.97 $ 8.88 $ 58.73
Hedging loss -
realized - - (0.17) (0.86)
Royalty income 0.80 0.35 0.04 0.28
Royalties (16.07) (18.47) (1.89) (12.15)
Production costs (1) (8.04) - (1.16) (6.68)
Transportation (5.03) (1.84) (0.30) (2.07)
----------------------------------------------------------------------------
Field netback $ 69.72 $ 64.01 $ 5.40 $ 37.25
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Production costs for natural gas liquids are included with natural gas
costs.
Field netbacks for 2009 fell 52% year over year as a result of a 48% reduction
in per-Boe revenue. Direct costs, principally price-sensitive royalties, fell by
42% year over year. Storm has, and may in the future, shut in production if
individual wells are not providing an acceptable economic return, which may
affect production levels in future quarters.
Based on an all-in proved plus probable finding cost for 2009 of $14.69 (2008 -
$11.12), Storm's recycle ratio (field netback divided by finding costs) for the
year was 1.2 (2008 - 3.3).
Interest
Year Ended Year Ended
December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Charge for year $ 3,636 $ 3,503
Per Boe $ 1.23 $ 1.37
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest is paid on Storm's revolving bank facility. The Company normally
borrows using bankers' acceptances plus a stamping fee. Although interest paid
on bankers' acceptances fell year over year, the stamping fee payable by the
Company increased considerably upon the renewal of the Company's banking
agreement, effective May 1, 2009. Nevertheless, higher debt levels were largely
responsible for the 4% year-over-year increase in borrowing costs.
General and Administrative Costs
Year Ended Year Ended
Total Costs December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Gross general and administrative costs $ 6,858 $ 6,390
Capital and operating recoveries (2,198) (2,949)
----------------------------------------------------------------------------
Net general and administrative costs $ 4,660 $ 3,441
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year Ended Year Ended
Costs per Boe December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Gross general and administrative costs $ 2.31 $ 2.50
Capital and operating recoveries (0.74) (1.15)
----------------------------------------------------------------------------
Net general and administrative costs $ 1.57 $ 1.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The 7% increase in gross general and administrative costs for 2009, when
compared to the prior year, was primarily due to an increased staff count, as
well as higher year-over-year compensation. Lower field activity levels, when
compared to the prior year, resulted in a 25% reduction in capital recoveries
with the consequence that net general and administrative costs increased by 35%
in 2009. Per-Boe net general and administrative costs increased by 16% year over
year.
Storm does not capitalize general and administrative costs. Net general and
administrative costs per Boe for 2010 should be lower, due to increased capital
and operating recoveries resulting from higher levels of field activity.
Stock-Based Compensation Costs
Year Ended Year Ended
December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Charge for year $ 2,022 $ 1,886
Per Boe $ 0.68 $ 0.74
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Stock-based compensation costs are non-cash charges which reflect the estimated
value of stock options issued to Storm's directors and employees. The value of
the award is recognized as an expense over the period from the grant date to the
date of vesting of the award. The increase in the charge for 2009, compared to
the prior year, is a result of stock options being issued in 2009 at a price
higher than the historical average price, net of certain prior year awards being
fully expensed.
Depletion, Depreciation and Accretion
Year Ended Year Ended
December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Depletion and depreciation charge for
year $ 43,340 $ 41,601
Accretion charge for year 484 488
----------------------------------------------------------------------------
Total $ 43,824 $ 42,089
----------------------------------------------------------------------------
Per Boe $ 14.77 $ 16.48
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The total charge for depletion and depreciation for 2009 increased by 4%
compared to 2008 due to increased product volumes being offset by a lower
per-unit rate.
The year-over-year decrease in the charge for depletion and depreciation in 2009
per Boe is approximately 10%. The reduction is attributable to proved oil and
gas reserves being added, effective January 1, 2009, at a cost lower than the
cumulative amount for prior periods. Accretion is the increase for the reporting
period in the present value of the Company's asset retirement obligation, which
is discounted using an interest rate of 8%.
Investment Gain (Loss)
As described in Note 4 to the consolidated financial statements, Storm accounts
for its investment in Storm Gas Resource Corp. ("SGR") using the equity method,
in accordance with which the Company's pro rata share of changes in SGR's equity
is included in the determination of the Company's net income for the period. The
investment loss recorded in 2009 represents Storm's share of changes in SGR's
equity for the year. The investment gain recognized in 2008 was a dilution gain
resulting from a reduction in Storm's ownership position, consequent on the
completion by SGR of an equity issue at a price higher than Storm's average
investment cost.
Future Income Taxes
For 2009, Storm recorded a recovery of future income taxes of $1.7 million
compared to a provision for future income taxes of $12.4 million for 2008. The
anomalous amount for future income tax recovery for 2009, is a consequence of
the revaluation of future income taxes at December 31, 2009 using the lower
rates expected to be applicable in the year of payment. The statutory combined
federal and provincial rate applicable to income in 2009 is 28%, compared to 30%
for 2008.
At December 31, 2009, Storm had tax pools carried forward estimated to be $214
million. In addition, Storm has a capital loss in the amount of $10 million
available for application against future capital gains.
Net Income (Loss) and Net Income (Loss) Per Share
The Company incurred a net loss of $0.3 million for 2009, compared to net income
of $34.7 million for 2008.
Year Ended Year Ended
December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Per diluted share Per diluted share
----------------------------------------------------------------------------
Net income (loss) $ (317) $ (0.01) $34,686 $ 0.76
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Non-GAAP Funds from Operations and Funds from Operations per Share
Year Ended Year Ended
December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Per diluted share Per diluted share
----------------------------------------------------------------------------
Funds from operations $ 44,596 $ 0.94 $ 87,490 $ 1.91
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Non-GAAP funds from operations is not a measure recognized by GAAP in Canada,
although it is widely used by analysts and other financial statement users. It
is also used by the Company's bankers to measure debt to cash flow ratios, which
determines interest costs under the Company's banking agreement. The most
directly comparable measure under GAAP is cash flows from operating activities,
as set out below.
Cash Flows from Operating Activities and Cash Flows from Operating
Activities per Share
Year Ended Year Ended
December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Per diluted share Per diluted share
----------------------------------------------------------------------------
Cash flows from operating
activities $ 45,621 $ 0.97 $ 85,972 $ 1.87
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Comprehensive Income (Loss)
Under GAAP, comprehensive income (loss) comprises unrealized gains and losses
resulting from the mark-to-market valuation of certain assets and liabilities.
For 2009, Storm's comprehensive loss comprised the following:
- unrealized hedging gains or losses on contracts to which hedge accounting
rules are deemed to apply; for Storm, natural gas hedging contracts follow hedge
accounting rules
- unrealized gains or losses on investments which are considered to be available
for sale.
INVESTMENT AND FINANCING
Working Capital
Receivables comprise production revenue receivables and accruals, and
receivables in respect of operating and capital costs. Investments included in
current assets comprise 5.1 million shares of Bellamont Exploration Ltd., a
junior oil and gas corporation, whose shares trade on the Toronto Stock
Exchange. As the shares of this corporation are regarded as being available for
sale, under GAAP the investment is carried at fair value, determined using the
year-end market price. Prepaid and other include unamortized insurance premiums,
deposits, prepayments and certain inventory equipment items.
Accounts payable and accrued liabilities include operating, administrative and
capital costs payable. Net payables in respect of cash calls issued to partners
regarding capital projects and estimates of amounts owing but not yet invoiced
to the Company have been included in accounts payable.
Excluding an unrealized financial instrument loss provision, Storm had a working
capital deficiency of $6.3 million at December 31, 2009, compared to $16.9
million at December 31, 2008. The working capital deficiency at each year end
reflects the seasonality of Storm's field operations. The Company's working
capital deficiency is cyclical and is usually highest at the end of the first
quarter of each year and lowest at the end of second quarter. The reduction of
working capital deficiency year over year is, in part, due to lower levels of
field activity.
Capital Expenditures
Capital costs incurred were as follows:
Year Ended Year Ended
December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Land and lease $ 2,720 $ 7,634
Seismic 1,205 (1,197)
Drilling and completions 38,624 74,023
Facilities and equipment 22,152 18,762
----------------------------------------------------------------------------
Field expenditures 64,701 99,222
Property acquisitions 9,469 712
Property dispositions (18,562) (4,980)
----------------------------------------------------------------------------
Total $ 55,608 $ 94,954
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Bank Debt, Liquidity and Capital Resources
Storm has a revolving borrowing base bank credit facility which is renewable
annually but subject to mid-year review. The facility was renewed effective May
1, 2009 and amounts to $120 million, which was recently reconfirmed. The amount
drawn on the facility at December 31, 2009 amounted to $86.8 million, or 72% of
the available facility. Total debt, including working capital deficiency (less
unrealized financial instrument losses), amounted to $93.0 million at December
31, 2009, resulting in a ratio of debt to annualized funds from operations for
2009 of 2.1 times.
The Company normally funds its bank borrowings by drawing bankers' acceptances
plus a stamping fee. The renewal of Storm's banking facility in 2009 included a
large increase in stamping fees, standby fees and other costs. Nevertheless,
year over year, the core bankers' acceptance rate has fallen considerably. In
this circumstance, Storm has fixed its bankers' acceptance rate, before
application of stamping fees, for $60 million through a swap mechanism at a cost
of 69.5 basis points for a period of twelve months, beginning May 2009.
Storm funds its field capital programs through cash flow and bank borrowings.
The decline in natural gas prices severely reduced cash flows in 2009 resulting
in constraints to the Company's capital programs. Acquisitions are funded by a
combination of debt and, if required, equity. Field capital programs tend to be
concentrated in the winter months, with the result that, in the ordinary course,
capital expenditures in the first and fourth quarters of the year will exceed
cash flow, compensated by lower capital expenditures in the second and third
quarters. In quarters of high field activity, Storm operates with a substantial
working capital deficit, which is reduced in quarters of lower field activity.
In March 2009, Storm issued 1,850,000 common shares at a price of $10.60 per
share for total proceeds of $19.6 million, before commission and expenses.
Proceeds from the offering were initially used to reduce bank indebtedness.
Capital programs were funded as follows:
Year Ended Year Ended
December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Non-GAAP funds from operations $ 44,596 $ 87,490
Non-cash working capital (10,155) 6,677
Issue of common shares - net of
expenses 19,238 795
Increase in bank indebtedness 4,854 7,432
Proceeds from property sales 18,562 4,980
----------------------------------------------------------------------------
Cash available for investment $ 77,095 $ 107,374
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Field expenditures $ 64,701 $ 99,222
Property acquisitions 9,469 712
Investments 2,925 7,440
----------------------------------------------------------------------------
Total cost of investment programs $ 77,095 $ 107,374
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Investments
Bellamont Exploration Ltd.
In November 2009, the Company sold certain producing properties to Bellamont
Exploration Ltd. ("Bellamont") for proceeds totaling $17.2 million, comprised of
$14.0 million in cash and 5.08 million shares in Bellamont. The shares are
considered available for sale by management and are carried at fair value,
determined with reference to the published share price, with the corresponding
holding gain recognized in other comprehensive income.
Storm Gas Resource Corp.
Storm Gas Resource Corp. ("SGR") was incorporated to identify and participate in
unconventional natural gas opportunities, initially a shale gas resource in the
Horn River Basin of northeastern British Columbia. Storm's initial investment in
SGR at $1.00 per share in June, 2007, was satisfied by a cash contribution of
$833,000 and the transfer of undeveloped lands with a value of $417,000. In July
2008, Storm subscribed for an additional 200,000 common shares in SGR at a price
of $5.20 per share, and also participated in a private placement, subscribing
for 600,000 common shares at a price of $6.50 per share. The private placement
resulted in SGR issuing 5,880,000 common shares at a price of $6.50 per share,
for total proceeds after commission and expenses of $38,220,000. As the private
placement involved the sale of shares by SGR at a price higher than Storm's
initial investment cost, the Company recognized a dilution gain in 2008 of $3.5
million. In November 2009, SGR completed a further equity issue, raising $12.4
million after commissions and expenses. Under the offering, Storm acquired an
additional 450,000 shares for a cost of $2.9 million, or $6.50 per share.
Storm's ownership position in SGR is 22%. Including the dilution gain, the
carrying amount of Storm's 2,500,000 common shares of SGR is $4.79 per share.
This amount should not be regarded as representative of the value of Storm's
investment in SGR. Total cash invested, plus property transferred to SGR,
amounts to $9.1 million or $3.65 per SGR share. In addition to its investment in
SGR, Storm has a direct 40% working interest in undeveloped lands jointly
acquired with SGR in the Horn River Basin of northeastern British Columbia. This
interest, together with Storm's investment in SGR, provides the Company with 53%
exposure to the potential upside in the Horn River Basin lands.
Storm provides management services to SGR at cost. Amounts charged by Storm to
SGR for 2009 were $0.3 million (2008 - $0.1 million).
Storm Ventures International Inc.
At December 31, 2009, the Company's investment in Storm Ventures International
Inc. ("SVI") represented a 6% ownership position, comprising 4,500,000 common
shares. The carrying amount of SVI on Storm's consolidated balance sheet
approximates $2.34 per SVI share, and comprises Storm's investment cost, plus a
dilution gain recognized during a prior year. This carrying amount should not be
regarded as representative of the value of Storm's investment. During 2008,
Storm invested $1.25 million to acquire an additional 200,000 common shares,
resulting in total cash invested in SVI by Storm of $4.25 million.
Future Income Taxes
Estimated future income taxes at December 31, 2009 largely represents the excess
of the accounting amounts over the related tax bases of property and equipment
and share capital.
Details of the Company's tax pools are as follows:
Maximum Annual
Tax Pool December 31, 2009 Deduction
----------------------------------------------------------------------------
Canadian oil and gas property expense $ 82,720 10%
Canadian development expense 70,832 30%
Canadian exploration expense 4,132 100%
Undepreciated capital cost 54,442 20 - 100%
Other 2,048 7 - 20%
----------------------------------------------------------------------------
Total $ 214,174
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital losses $ 9,666
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Asset Retirement Obligation
Storm's asset retirement obligation represents the present value of estimated
future costs to be incurred to abandon and reclaim the Company's wells and
facilities. Changes in amount of the obligation between 2008 and 2009 comprise
the present value of additional obligations accruing to the Company as a result
of field activity and acquisitions and dispositions during the period, less
costs paid in settlement of abandonment obligations, plus the quarterly increase
in the present value of the obligation. The discount rate used to establish the
present value is 8%. Future costs to abandon and reclaim Storm's properties are
based on an internal evaluation of each of the Company's properties, supported
by external data from industry sources.
Share Capital
Details of outstanding share capital and dilutive elements as at and for the
years ended December 31, 2009 and 2008:
December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Common shares outstanding - end of
year 46,743 44,703
Unexercised stock options 3,014 2,267
----------------------------------------------------------------------------
Fully diluted common shares - end of
year 49,757 46,970
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted average common shares - basic 46,275 44,654
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted average common shares -
diluted 47,226 45,877
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Stock options outstanding are exercisable over five years on various dates
beginning September 2005 at prices ranging from $3.61 to $12.60.
CONTRACTUAL OBLIGATIONS
In the course of its business Storm enters into various contractual obligations,
including the following:
- purchase of services;
- royalty agreements;
- operating agreements;
- processing agreements;
- right of way agreements; and
- lease obligations for accommodation, office equipment and automotive equipment.
All such contractual obligations reflect market conditions at the time of
contract and do not involve related parties, except that SGR subleases office
space from the Company at the same rate as the Company's head lease.
Obligations with a fixed term are as follows:
Obligation 2010 2011 2012 2013 2014
----------------------------------------------------------------------------
Lease of premises $ 825 $ 838 $ 838 $ 419 $ -
Equipment leases 200 145 50 - -
Gas transportation and
processing commitments 1,726 1,434 887 486 240
----------------------------------------------------------------------------
Total $2,751 $2,417 $1,775 $905 $240
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NET ASSET VALUE
An estimate of Storm's net asset value at December 31, 2009 is as follows:
(000s) December 31, 2009
----------------------------------------------------------------------------
Present value of proved plus probable reserves,
before tax, discounted at 10% $ 663,880
Undeveloped land including Surmont oil sands
leases (1) 42,404
Horn River Basin (2) 3,800
Investment - SGR (3) 16,250
Investment - SVI (4) 13,500
Cash proceeds on exercise of stock options 24,240
Net debt (93,032)
----------------------------------------------------------------------------
Net asset value before tax $ 671,042
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fully diluted common shares outstanding (000s) 49,757
----------------------------------------------------------------------------
Net asset value per common share ($/share) $ 13.49
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Based on report of Seaton-Jordan & Associates Ltd. effective December
1, 2009.
(2) Seismic and drilling incurred to December 31, 2009.
(3) Based on a private placement completed in 2009 at $6.50 per share.
(4) Based on a private placement completed in January 2010 at $3.00 per
share.
FOURTH QUARTER RESULTS
Storm's summarized financial and operating results for the fourth quarter
of 2009, compared to the fourth quarter of 2008, are as follows:
Three Months Ended Three Months Ended Percentage
(Unaudited) December 31, 2009 December 31, 2008 Change
----------------------------------------------------------------------------
Financial
----------------------------------------------------------------------------
Production revenue
($000s) 24,903 35,447 (30%)
----------------------------------------------------------------------------
Funds from operations
($000s) 13,798 20,432 (32%)
Per share - basic ($) 0.30 0.46 (35%)
Per share - diluted ($) 0.29 0.45 (36%)
----------------------------------------------------------------------------
Net income ($000s) 2,147 5,968 (64%)
Per share - basic ($) 0.05 0.13 (62%)
Per share - diluted ($) 0.05 0.13 (62%)
----------------------------------------------------------------------------
Capital expenditures
- net ($000s) 5,844 35,342 (83%)
----------------------------------------------------------------------------
Debt, including working
capital deficiency ($000s) 93,032 98,790 (6%)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operations
----------------------------------------------------------------------------
Boe production per day 7,890 8,161 (3%)
Gas production per day (Mcf) 40,325 41,919 (4%)
NGL production per day (Bbls) 652 489 33%
Oil production per day (Bbls) 517 686 (25%)
Gross wells drilled 4.0 9.0 (56%)
Net wells drilled 2.1 9.0 (77%)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Production
In the fourth quarter of 2009, average Boe per day volumes fell by 3% when
compared to the fourth quarter of 2008, and by 2% when compared to the third
quarter of 2009. Production of natural gas amounted to 85% of total Boe
production in the fourth quarter of 2009, generally consistent with earlier
quarters. Largely flat production year over year and quarter over quarter is
consistent with the Company's reluctance to bring on stream high productivity
natural gas wells in periods of low prices.
Production Revenue
Production revenue for the fourth quarter of 2009 fell by 30%, when compared to
the fourth quarter of 2008, but increased by 28% when compared to the
immediately preceding quarter. The average realized price per Boe for the
quarter amounted to $35.26, 25% less than the equivalent amount for the final
quarter of 2008, but 42% more than in the third quarter of 2009, corresponding
to increased commodity prices in the fourth quarter. Due to over supply and
higher than normal inventory levels, Storm's realized gas price for the final
quarter of 2009 was $5.03; the price for the final quarter of 2008 was $7.49 and
was $3.30 for the third quarter of 2009.
Royalties
Royalties for the fourth quarter of 2009 amounted to $3.9 million, a decrease of
43% when compared to the same quarter of 2008 and an increase of 55% compared to
the third quarter of 2008. Price volatility largely accounts for the changes.
The royalty rate in the fourth quarter of 2009 was 15%; for the fourth quarter
of 2008, 19%; and for the third quarter of 2009, 14%.
Production Costs
Production costs for the quarter fell by 13% to $3.8 million when compared to
the final quarter of 2008 and by 3% when compared to the third quarter of 2009.
The year-over-year reduction in production costs, considerably in excess of the
equivalent reduction in production volumes, is due largely to the growth in
lower cost Montney gas as a percentage of total production. Cost efficiencies
also helped and in future periods the installation of the refrigeration plant at
Parkland should result in further cost reductions. Per Boe costs have fallen;
for the final quarter of 2009 production costs per Boe amounted to $5.23,
compared to $5.84 for the same quarter of 2008 and to $5.30 per Boe in the third
quarter of 2009.
Cash costs per Boe, comprising production costs, transportation, interest and
general and administrative costs, amounted to $10.31 for the final quarter of
2009, $10.34 for the equivalent quarter of 2008 and $9.50 for the third quarter
of 2009. Year-over-year reductions in production and transportation costs more
than offset interest and general and administrative costs. Within 2009, lower
production costs were offset by higher interest and general and administrative
costs.
Transportation Costs
Transportation costs for the final quarter of 2009 amounted to $1.2 million, a
decrease of 17% over 2008 but an increase of 14% over the immediately preceding
quarter. Costs per Boe amounted to $1.60 in the fourth quarter of 2009, compared
to $1.85 in the same quarter of 2008 and to $1.38 in the third quarter of 2009.
The year-over-year reduction in transportation costs per Boe is a result of
increased production from the Parkland area.
Field Netbacks
Details of field netbacks per commodity unit are as follows:
Three Months to December 31, 2009
----------------------------------------------------------------------------
Natural Gas
Crude Oil Liquids Natural Gas Total
($/Bbl) ($/Bbl) ($/Mcf) ($/Boe)
----------------------------------------------------------------------------
Product sales $ 75.74 $ 55.84 $ 5.03 $ 35.26
Hedging loss - realized (7.05) - (0.03) (0.59)
Royalty income 0.15 0.06 0.01 0.04
Royalties (13.27) (12.58) (0.69) (5.40)
Production costs (7.98) - (0.92) (5.23)
Transportation (4.71) (3.87) (0.19) (1.60)
----------------------------------------------------------------------------
Field netback $ 42.88 $ 39.45 $ 3.21 $ 22.48
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months to December 31, 2008
----------------------------------------------------------------------------
Natural Gas
Crude Oil Liquids Natural Gas Total
($/Bbl) ($/Bbl) ($/Mcf) ($/Boe)
----------------------------------------------------------------------------
Product sales $ 62.35 $ 56.52 $ 7.49 $ 47.08
Hedging loss - realized - - - -
Royalty income 0.28 0.16 0.02 0.13
Royalties (10.21) (10.14) (1.50) (9.17)
Production costs (6.95) - (1.02) (5.84)
Transportation (4.57) (1.16) (0.27) (1.85)
----------------------------------------------------------------------------
Field netback $ 40.90 $ 45.38 $ 4.72 $ 30.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Field netbacks for the final quarter of 2009 were still considerably lower than
the same quarter of 2008; however, netbacks were 55% higher than the third
quarter of 2009, as a consequence of a largely equivalent increase in natural
gas prices.
Based on an all-in proved plus probable finding cost for 2009 of $14.69, Storm's
recycle ratio (field netback divided by finding costs) for the three months
ended December 31, 2009 was 1.5.
Interest
Interest costs for the final quarter of 2009 increased by 78% to $1.2 million
compared to the same quarter in 2008 and by 16% compared to the third quarter of
2009. Interest costs per Boe amounted to $1.65 in the fourth quarter of 2009,
compared to $0.90 in the same quarter of 2008 and $1.40 in the third quarter of
2009. The final quarter of 2008 benefited from a very low interest rate, as a
consequence of the recession-driven fall in core interest rates, coupled with a
low stamping fee structure, which increased considerably upon renewal of the
Company's bank facility in May 2009. The quarter-over-quarter increase in
interest costs resulted from growing bank borrowings, which were reduced in
December 2009, through proceeds from the sale of producing properties.
General and Administrative
Three Months Ended December 31 2009 2008
----------------------------------------------------------------------------
Gross general and administrative costs $ 2,049 $ 2,269
Capital and operating recoveries (718) (952)
----------------------------------------------------------------------------
Net general and administrative costs $ 1,331 $ 1,317
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Per Boe
Three Months Ended December 31 2009 2008
----------------------------------------------------------------------------
Gross general and administrative costs $ 2.82 $ 3.02
Capital and operating recoveries (0.99) (1.27)
----------------------------------------------------------------------------
Net general and administrative costs $ 1.83 $ 1.75
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross general and administrative costs for the final quarter of 2009 fell by 10%
when compared to the final quarter of 2008 and increased by 36% compared to the
third quarter of 2009. The year-on-year reduction in general and administrative
costs is largely attributable to lower employee bonuses. The increase in the
final quarter of 2009, when compared to the third quarter, is due to the
inclusion in the final quarter of certain costs related to the Company's year
end, including external services. Reduced capital and operating recoveries year
over year corresponded to lower field activity, although in the final quarter of
2009, recoveries increased over the immediately prior quarter in response to
higher levels of field activity as the Company began its winter drilling
program.
Stock-Based Compensation
Stock-based compensation increased by 17% in the final quarter of 2009 compared
to the same quarter of 2008 and fell by 8% when compared to the third quarter of
2009. The increase in stock-based compensation in 2009 is attributable to the
issue of stock options during the year.
Depletion, Depreciation and Accretion
Lower production resulted in the charge for depletion, depreciation and
accretion falling by 4% in the final quarter of 2009. Compared to the
immediately prior quarter, the charge for the fourth quarter of 2009 increased
by 4%, with lower production being offset by an increase in the per-unit rate
resulting from the application of the 2009 year-end reserve report to the
depletion calculation for the final quarter of the year. Per Boe, depletion,
depreciation and accretion amounted to $15.33 in the final quarter of 2009; the
charge for the final quarter of 2008 amounted to $15.44 and for the third
quarter of 2009, $14.49.
Net Income
For the final quarter of 2009, Storm reported quarterly income, the first time
since the first quarter of the year. However, income for the quarter was 36% of
the same quarter of 2008. Per diluted share amounts were $0.05 for the final
quarter of 2009; $0.13 for the final quarter of 2008; and a loss of $0.03 for
the third quarter of 2009.
Funds from Operations and Cash Flows from Operating Activities
Non-GAAP funds from operations for the fourth quarter of 2009 fell by 32% to
$13.8 million from $20.4 million in the fourth quarter of 2008, but increased by
60% compared to the third quarter of 2009. Per diluted share amounts were $0.29
for the final quarter of 2009; $0.45 for the final quarter of 2008; and $0.18
for the third quarter of 2008. The large variations in these reported amounts
corresponds to the volatility of commodity pricing, particularly natural gas,
among the various quarters.
Non-GAAP funds from operations is not a measure recognized by GAAP in Canada.
The most directly comparable measure under GAAP is cash flows from operating
activities. Cash flows from operating activities for the quarter ended December
31, 2009 amounted $13.4 million, compared to $20.1 million for the same quarter
of 2008; and to $8.5 million for the third quarter of 2009.
Capital expenditures
Net capital expenditures for the final quarter of 2009 amounted to $5.8 million,
compared to $35.3 million in 2008, and to $14.4 million in the third quarter of
2009. Net capital expenditures for the final quarter of 2009 included proceeds
on disposition of producing properties, in the amount of $17.0 million.
Quarterly Results
Summarized information by quarter for the two years ended December 31, 2009
appears below:
Dec.31, Sep. 30, Jun. 30, Mar. 31,
Quarter Ended 2009 2009 2009 2009
----------------------------------------------------------------------------
Production revenue ($000s) 24,903 19,436 18,712 25,819
Funds from operations ($000s) 13,798 8,618 8,460 13,720
Per share
- basic ($) 0.30 0.18 0.18 0.30
- diluted ($) 0.29 0.18 0.18 0.30
Net income (loss) ($000s) 2,147 (1,522) (2,192) 1,250
Per share
- basic ($) 0.05 (0.03) (0.05) 0.03
- diluted ($) 0.05 (0.03) (0.05) 0.03
Average daily production - Boe 7,890 8,030 8,153 8,441
Average field netback ($/Boe) 22.48 14.49 14.22 20.15
Capital expenditures - net ($000s) 5,844 14,430 3,843 31,491
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dec. 31, Sep. 30, Jun. 30, Mar. 31,
Quarter Ended 2008 2008 2008 2008
----------------------------------------------------------------------------
Production revenue ($000s) 35,447 40,215 38,888 33,974
Funds from operations ($000s) 20,432 24,290 23,250 19,518
Per share
- basic ($) 0.46 0.54 0.52 0.44
- diluted ($) 0.45 0.53 0.50 0.43
Net income (loss) ($000s) 5,968 12,829 9,465 6,426
Per share
- basic ($) 0.13 0.28 0.21 0.14
- diluted ($) 0.13 0.28 0.20 0.14
Average daily production - Boe 8,161 7,107 6,130 6,500
Average field netback ($/Boe) 30.35 39.77 45.09 35.87
Capital expenditures - net ($000s) 35,342 27,057 5,780 26,775
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SELECTED ANNUAL FINANCIAL INFORMATION
Year Ended Year Ended Year Ended Year Ended
December 31, December 31, December 31, December 31,
2009 2008 2007 2006
----------------------------------------------------------------------------
Production revenue ($000s) 88,870 148,524 98,291 80,165
Funds from operations
($000s) 44,596 87,490 51,943 43,297
Per share
- basic ($) 0.96 1.96 1.20 1.04
- diluted ($) 0.94 1.91 1.18 1.03
Net income (loss) ($000s) (317) 34,686 11,049 11,505
Per share
- basic ($) (0.01) 0.78 0.25 0.28
- diluted ($) (0.01) 0.76 0.25 0.27
Total assets ($000s) 344,932 328,376 260,907 202,652
Debt, including working
capital deficiency ($000s) 93,032 98,790 84,681 57,314
Average daily production
(Boe) 8,127 6,978 5,775 4,720
Field netbacks ($/Boe) 17.83 37.25 27.56 27.46
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Comparability of net income between years is affected by variations in
production revenue and increased costs relating to a production base that has
generally grown throughout the years above, and is expected to continue to grow
in future years. Also, in 2008, the Company realized a non-cash investment gain
for which there was no equivalent in the other years above .
Earnings per share and per diluted share, are affected by variations in net
income and the issue of common shares in each of 2009, 2008, 2007 and 2006, and
the periodic issue and exercise of stock options. Increases in total assets for
each period reflect the Company's need to continually invest in capital assets
to maintain and grow production.
Debt has grown each period as bank debt is used, in part, to fund capital
investment, including acquisitions, although bank debt at the end of 2009 was
lower due to proceeds on the sale of non-core properties.
Share Trading
Set out below is share trading activity for Storm for 2009 and 2008:
2009 Q1 Q2 Q3 Q4 Year - 2009
----------------------------------------------------------------------------
High ($) 14.22 14.77 14.98 15.56 15.56
Low ($) 8.63 10.77 10.57 11.47 8.63
Close ($) 11.42 11.70 14.75 13.03 13.03
Volume traded (000s) 11,056 4,609 6,150 3,970 25,785
Value traded ($000s) 127,929 59,110 77,806 52,512 317,357
Weighted average
trading price ($) 11.57 12.83 12.65 13.23 12.31
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2008 Q1 Q2 Q3 Q4 Year - 2008
----------------------------------------------------------------------------
High ($) 12.20 19.41 19.75 14.25 19.75
Low ($) 8.52 11.74 11.53 6.92 6.92
Close ($) 12.02 19.17 13.89 13.82 13.82
Volume traded (000s) 7,219 11,515 11,939 12,078 42,751
Value traded ($000s) 75,928 178,132 188,404 135,146 577,610
Weighted average
trading price ($) 10.52 15.47 15.78 11.19 13.51
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CRITICAL ACCOUNTING ESTIMATES
Financial amounts included in the Company's Management's Discussion and Analysis
and in the consolidated financial statements for the year ended December 31,
2009 are based on accounting policies, estimates and judgment which reflect
information available to management at the time of preparation. Certain
financial amounts are derived from a fully completed transaction cycle, or are
validated by events subsequent to the end of the reporting year, or are based on
established and effective measurement and control systems. However, other
amounts, as described below, are based on estimations using information that
involves a high degree of measurement uncertainty which could have a material
effect on Storm's operating results and financial position.
Oil and Gas Properties
Storm uses the full cost method of accounting for exploration and development
activities whereby all costs associated with these activities are capitalized.
The aggregate of capitalized costs, less unproved property costs, but including
estimated future development costs, is amortized using the unit-of-production
method based on estimated proved reserves estimated by external reservoir
engineers reporting to the Reserves Committee of the Board of Directors.
Storm's investment in oil and gas assets is evaluated at least annually (the
"ceiling test") to consider whether the investment is recoverable and to ensure
that the carrying amount on the Company's balance sheet does not exceed the
value of the properties, as determined by formula. If the carrying amount of the
oil and gas assets is not determined to be recoverable, a loss is recognized to
the extent that the carrying amount exceeds the sum of the discounted cash flows
expected from the production of proved and probable reserves plus the lower of
cost and market value of unproved properties. Cash flows are estimated using
future product prices and costs and are discounted using a risk-free rate
appropriate to the Company. No write downs of the carrying amount of Storm's oil
and gas assets have been required upon the application of the ceiling test.
The amount of the charge for depletion and the periodic application of the
ceiling test are based on the independent reserves report, which reflects future
events, including future pricing, which are subject to a high degree of
estimation.
Asset Retirement Obligation
Storm records as a liability the estimated fair value of obligations associated
with the retirement of field assets, such as producing well sites and processing
facilities. The carrying amount of property and equipment is increased by an
amount equivalent to the liability. The future asset retirement obligation is
based on the Company's ownership interest in wells and facilities, and reflects
estimated costs to complete the abandonment and reclamation as well as the
estimated timing of the costs to be incurred in future periods. The liability is
increased each reporting period to reflect the passage of time, with the
accretion charged to earnings. The liability is also adjusted to reflect changes
in the amount and timing of the future retirement obligation and is reduced by
the amount of any costs incurred in the period. The amount of the abandonment
obligation, the charge for accretion and the charge for depletion of the amount
added to property and equipment are subject to uncertainty of estimation.
Income Taxes
The measurement of Storm's future income and other tax liabilities and assets,
including losses carried forward and asset pools, requires interpretation of
complex laws and regulations. All tax filings and compliance with tax
regulations are subject to audit and reassessment, potentially several years
after the initial filing. Accordingly, actual income tax assets or liabilities
may differ significantly from the amounts initially estimated.
Stock-Based Compensation
To determine the charge for stock-based compensation, the Company estimates the
fair value of stock options at time of issue using assumptions regarding the
life of the option, dividend yields, interest rates and the volatility of the
security under option. Although the assumptions used to value a specific option
remain unchanged throughout the life of the option, assumptions may change with
respect to subsequent option grants. In addition, the assumptions used may not
properly represent the fair value of stock options at any time; as no
alternative valuation model is applied, the difference between the Company's
estimation of fair value and the actual value of the option is not measurable.
RISK ASSESSMENT
There are a number of risks facing participants in the Canadian oil and gas
industry. Some risks are common to all businesses while others are specific to
the industry. The following reviews a number of the identifiable business risks
faced by Storm. Business risks evolve constantly and additional risks emerge
periodically. The risks below are those identified by management at the date of
completion of this report, and may not describe all of the business risks faced
by the Company.
Exploration
Storm's exploration program requires sophisticated and scarce technical skills
as well as capital and access to land, services and equipment to generate and
test exploration ideas. Further, the drilling of an exploratory prospect
frequently does not result in the discovery of economical reserves. Storm
endeavours to minimize finding risk by ensuring that:
- Activity is focused in core regions where expertise and experience can be levered;
- Prospects are internally generated;
- Storm serves as operator where possible to maintain operational quality,
timing and control;
- Geophysical techniques such as seismic are utilized where appropriate and
available; and
- Where possible, prospects have multi-zone potential.
Commodity Price Fluctuations
Pricing for the Company's products is volatile and subject to a myriad of
factors, largely out of the Company's control. Low prices, particularly for the
Company's primary product, natural gas, have a material effect on the Company's
re-investment capacity, and hence ultimate growth potential and profitability.
Low prices also limit access to capital, both equity and debt. High netback
production, a low cost structure, along with a stable balance sheet, helps to
mitigate commodity price exposure. Storm may also secure price protection
through hedging.
Adverse Well or Reservoir Performance
Changes in well performance in any one or a number of producing pools could
result in termination or limitation of production, or acceleration of decline
rates, resulting in reduced overall corporate volumes and revenues. In addition,
new wells, particularly new wells at Parkland in the Company's Montney
formation, tend to produce at high initial rates followed by rapid declines
until a flattening decline profile emerges. Correspondingly, the timing of tie
in of new wells may affect comparability of intra year production levels. Long
life gas reserves, operated under prudent production practices, mitigate
exposure to high decline wells or pools.
Field Operations
Storm's exploration, development and production activities involve the use of
heavy equipment and the handling of potentially volatile liquids and gases.
Catastrophic events such as well blowouts, explosions and fires within pipeline,
gathering, or facility infrastructure, as well as failure of mechanical
equipment, could lead to sour gas releases, spills, personal injuries and damage
to the environment, as well as uncontrolled cost escalation. With support from
suitably qualified external parties, the Company has developed and implemented
policies and procedures to mitigate environmental, health and safety risks.
These policies and procedures include the use of formal corporate policies,
emergency response plans, and other policies and procedures reflecting best oil
field practices. These policies and procedures are subject to periodic review.
Storm also manages environmental and safety risks by maintaining its facilities
to a high standard and complying with all provincial and federal environmental
and safety regulations.
Storm maintains industry-specific insurance policies, including business
interruption on certain facilities. Although the Company believes its current
insurance coverage corresponds to industry standards, there is no guarantee that
such coverage will be available in the future, and if it is, at a cost
acceptable to the Company, or that existing coverage will necessarily extend to
all circumstances or incidents resulting in loss. In addition, stress in credit
markets in recent years may have unexpected effects on the solvency of insurance
providers.
Industry Capacity Constraints
High levels of field activity can result in shortages of services, products,
equipment, or manpower in many or all necessary components of the exploration
and development cycle. Increased demand leads to higher land and service costs
during peak activity periods. Competition in the Canadian oil and gas industry,
particularly in recent years, has been considerable. Although economic
conditions over the last eighteen months resulted in an easing of competitive
conditions in the short and medium term, competition in the Company's most
prospective areas continues to be intense. Storm's competitors include companies
with far greater resources, including access to capital. Storm competes by
maintaining a large inventory of self-generated exploration and development
locations, by acting as operator where possible, and through facility access and
ownership. Storm also seeks to mitigate such risks through careful management of
key supplier relationships and by maintaining a balance of field activity
throughout the year.
Capital Programs
Capital expenditures are designed to accomplish two main objectives, being the
generation of short and medium term cash flow from development activities, and
future cash flow from the discovery of reserves through exploration. Storm faces
constant production declines from existing wells which have to be replaced by
new production. Storm focuses its activity in core areas, which allows it to
leverage its experience and knowledge, and acts as operator wherever possible.
The Company uses farmouts to minimize risk on plays it considers higher risk or
where total capital invested exceeds an acceptable level. In addition, Storm may
enter into hedging agreements in support of capital programs, particularly when
cash flow for any period is anticipated to be lower than capital expenditures.
Capital programs are financed primarily through cash flow and constraints on
cash flow resulting from lower commodity prices will result in a reduction in
capital expenditures. In addition, credit availability from the Company's
bankers is also necessary to support capital programs and any changes to credit
availability may have an effect on both the size of the Company's capital
program and the timing of expenditures.
Acquisitions
Storm's objective of rapid and controlled growth is, in part, supported through
carefully selected and managed acquisitions. Acquisitions have to be acceptably
priced and production should provide netbacks at least equivalent to the
Company's existing production, or provide identifiable opportunities to increase
value. An acquisition should also offer potential for near and medium term
development and be in areas where Storm can readily add to the acquired land
position. Processing and transportation infrastructure must also be in place, or
within the Company's financial capacity to construct. Storm has completed no
major acquisitions since 2007.
Reserve Estimates
Estimates of economically recoverable oil and natural gas reserves and natural
gas liquids, and related future net cash flows, are based upon a number of
variable factors and assumptions. These include commodity prices, production,
future development and operating costs and potential changes to the Company's
operations arising from regulatory or fiscal changes. All of these estimates may
vary from actual results, with the result that estimates of recoverable oil and
natural gas reserves attributable to any property are subject to revision.
Assumptions are also made about rates and sustainability of production,
production rates, reserves life, access to pipelines and facilities and other
factors. Storm's actual production, revenues, taxes, development and operating
expenditures associated with its reserves may vary from such estimates, and such
variances may be material.
The Company's independent engineering firm, Paddock Lindstrom & Associates Ltd.
completes an evaluation of the Storm's reserves each year and reports to the
Company's Reserves Committee.
Production
Production of oil and natural gas reserves at an acceptable level of
profitability may not be possible during periods of low commodity prices. Storm
attempts to mitigate this risk by focusing on high net back opportunities and
acting as operator where possible, thus allowing the Company to manage costs,
timing, method and marketing of production. Production risk is also addressed by
concentrating exploration efforts in regions where infrastructure is Storm owned
or readily accessible at an acceptable cost.
Financial and Liquidity Risks
Storm faces a number of financial risks over which it has no control, such as
commodity prices, exchange rates, interest rates, access to credit and capital
markets, as well as changes to government regulations and tax and royalty
policies. The Company uses the following guidelines to address financial
exposure:
- Internally generated cash flow provides the initial source of funding on which
the Company's annual capital expenditure program is based;
- Debt may be utilized to expand capital programs, including acquisitions, when
it is deemed appropriate and where debt retirement can be controlled;
- Equity, including flow-through shares, if available on acceptable terms, may
be raised to fund acquisitions or expansions of operations;
- Farmouts or similar structures may be arranged if management considers that a
project requires too much capital or where the project affects the Company's
risk profile.
Marketing Risks
Markets for Storm's products are outside its capacity to control or influence,
and can be affected by events such as weather, regional, national and
international supply and demand imbalances, geopolitical events, currency
fluctuation, introduction of new, or termination of existing supply
arrangements, as well as downtime due to facility maintenance or damage. Storm
attempts to mitigate these risks as follows:
- Natural gas properties are developed in areas where there is suitable
processing and pipeline infrastructure.
- Exploration efforts focus on liquids-rich natural gas reserves.
- Financial instruments may be used to manage commodity price volatility where
Storm has capital programs, including acquisitions, whose cost exceeds near term
projected cash flows.
Climate Change
Public and political focus on climate change and its possible amelioration has
grown considerably in recent months and years. In terms of recent events, the
United Nations Climate Change Conference held in Copenhagen in December 2009
resulted in the Copenhagen Accord, which contains international principles,
objectives and funding commitments, but no legally binding emissions reductions
targets. Canada recently filed documents with the United Nations pursuant to the
Copenhagan Accord, setting a domestic greenhouse gas emissions reductions target
of 17% below 2005 levels by 2020, in line with U.S. domestic targets. The
federal government has not yet enacted or provided details regarding federal
greenhouse gas emissions reduction regulations and it is not known when it may
do so. In addition, there have also been concerns recently about the quality and
objectivity of evidence and scientific methods underlying certain climate change
publications. Although the evolution of public policy over the next several
years, and its effect on Storm, cannot be determined at this stage, it is
likely, given that the Company is a producer of primary hydrocarbons as well as
greenhouse gases, that Storm's business will be subject to increased regulation
and to additional costs and taxes which cannot be identified at this time.
Further, it is also possible that regulatory development may cause changes in
demand for Storm's products as well as changes to the Company's operating
practices.
In British Columbia, a carbon tax was introduced in 2008 that applied to
virtually all hydrocarbon-based fuels. The tax applies to all emissions of
greenhouse gases and to the purchase and use of hydrocarbons used as fuels. The
tax started at a rate of $10 per tonne of carbon greenhouse emissions, and is
increasing by $5 per tonne a year until 2012.
In Alberta, targets are in place for the reduction of greenhouse gases, which
mandate the reduction of emissions from large facilities emitting more than
100,000 tonnes of greenhouse gases per annum. Such facilities are obliged to
reduce their greenhouse gases by 12 percent, from a baseline level. In lieu of
other compliance options such as implementing engineering and operating changes,
companies can comply by purchasing carbon credits, or by paying $15 per tonne to
the Alberta Climate Change and Emissions Management Fund. Storm has no
facilities subject to these regulations.
Storm is committed to following best practices and strives constantly to reduce
its emissions and improve the efficiency of its energy usage. An illustration
would be the electrification in 2009 of part of the Company's facilities at
Parkland, British Columbia.
Access to Debt and Equity
Storm's capital structure involves the use of bank debt and from time to time
access to equity markets. The last two years has seen the collapse of, or losses
reported by, major international financial institutions, along with severe
curtailment of liquidity in debt markets and the injection of public money to
support both debt and equity markets and financial institutions. Although the
Canadian banking sector, in comparison to its international peers, showed
resilience in the face of these events, it did report considerable losses and
will likely be affected by any continuing weakness in credit markets. In view of
these circumstances, the Company has reviewed its lending arrangements with its
bankers and has received indications that, subject to annual review, existing
credit arrangements will be maintained and that, other than the effect of
changes in commodity pricing, criteria necessary to secure borrowing to support
the Company's growth have not been changed. However, additional circumstances
may emerge, including continuing declines in commodity prices, which could have
the effect of reducing credit available to Storm, or being available only at an
unacceptable cost, thus reducing the Company's ability to finance future growth.
Further, access to equity markets may be negatively affected by unanticipated
events.
Storm's long-standing approach to financing operations through internally
generated cash flow should mitigate the effect of any limitation in access to
debt and equity markets. However, continuing low commodity prices, particularly
for natural gas, will reduce cash flows; correspondingly, the rate of growth
shown in recent years of the Company's business may not be sustainable.
The events of the last two years are likely to result in changed and increased
regulation of debt and equity markets, which may also have an undeterminable
effect on Storm's financial structure and cost of doing business.
Extraordinary Circumstances
Storm's operations and its financial condition may be affected by uncontrollable
and unpredictable circumstances such as weather patterns, changes in
contractual, regulatory or fiscal terms, exclusion from third party pipelines or
facilities, or actions by certain groups such as industry organizations, local
communities, or militant groups.
REPORTING CONTROLS
The Company's Chief Executive Officer ("CEO") and Chief Financial Officer
("CFO") are responsible for establishing and maintaining disclosure controls and
procedures ("DC&P") and internal controls over financial reporting ("ICFR").
Storm has codified and distributed to staff its policies, controls and
procedures with respect to disclosure to third parties of information concerning
the Company's operations and results. In addition, DC&P are designed to provide
reasonable assurance that material information is made known to the CEO and CFO
on a timely basis and that information required to be disclosed by the Company
in its annual filings, interim filings or other reports filed or submitted by it
under securities legislation is recorded, processed, summarized and reported
within the time periods specified in securities legislation. The CEO and CFO
have evaluated, or caused to be evaluated under supervision, the effectiveness
of Storm's DC&P and have concluded that Storm's DC&P are effective as at
December 31, 2009, based on that evaluation.
ICFR have been designed by the CEO and CFO, either directly or under their
supervision, to provide reasonable assurance regarding the reliability of
financial reporting, including financial reporting for external purposes under
GAAP. As at December 31, 2009, the CEO and CFO evaluated the design and
operating effectiveness of the Company's ICFR. In part, this evaluation was
based on the work of third party specialists who were engaged by the Company to
establish internal control documentation and, effective December 31, 2008, to
test the operating effectiveness of such controls. In 2009, the Company updated
its documentation and tested internal controls using internal resources.
Based on this evaluation, the CEO and CFO concluded that the design of ICFR was
effective as at December 31, 2009 to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with Canadian GAAP. Further, the Company is
required to disclose herein any change in the design of the Company's ICFR that
occurred during the year ended December 31, 2009 that has materially affected,
or is reasonably likely to materially affect, the Company's ICFR. No material
changes in the Company's design of ICFR were made or were identified during such
period that have materially affected, or are reasonably likely to materially
affect, the Company's ICFR. No circumstances suggesting a possible breach of
disclosure controls were identified during the year ended December 31, 2009.
Because of inherent limitations, disclosure controls and procedures and internal
controls over financial reporting cannot prevent or identify all
mismeasurements, errors and fraud.
FINANCIAL REPORTING UPDATE
Current Year Accounting Changes
Effective December 31, 2009, the Company adopted the amendments to Handbook
Section 3862, Financial Instruments - Disclosures. The amendments include
enhanced disclosures relating to the fair value of financial instruments and the
liquidity risk associated with financial instruments.
Future Accounting Changes
The CICA has issued Handbook Sections 1582 "Business Combinations", 1601
"Consolidated Financial Statements" and 1602 "Non-Controlling Interests", all of
which replace existing Handbook standards and are effective on or after January
1, 2011. See Note 2 to the consolidated financial statements for further
details.
International Financial Reporting Standards
Canada's Accounting Standards Board has confirmed January 1, 2011 as the date
that International Financial Reporting Standards ("IFRS") will replace existing
Canadian GAAP for all publicly accountable enterprises in Canada. The Company
will begin reporting under IFRS in the first quarter of 2011, with restatement,
for comparative purposes, of amounts reported on the Company's opening IFRS
balance sheet as at January 1, 2010 and of quarterly amounts reported by the
Company during 2010.
The Company has developed a changeover plan that addresses accounting policy
changes, financial reporting requirements, adjustments to internal controls over
financial reporting, and to information technology and systems impacts, business
process changes, and education and training requirements. Staff participate in
on-going meetings with peers in the industry and accounting and information
system service providers to identify the practices that will be used to obtain
the most relevant and comparable financial information upon conversion to IFRS.
The Company has also developed position papers documenting its accounting policy
choices and the effects of those choices on the organization.
The Company has completed an initial assessment of the effects of adopting IFRS
and identified the following as having the greatest potential to change the
Company's accounting policies and procedures, financial reporting and
information systems upon conversion to IFRS.
Property and Equipment
IFRS 1, First-time Adoption of International Financial Reporting Standards,
provides entities adopting IFRS for the first time with a number of optional
exemptions and mandatory exemptions to the general requirement for full
retrospective application of IFRS. For companies such as Storm, using the Full
Cost method of accounting for oil and gas assets under Canadian GAAP, IFRS 1
permits the use of the net book value of assets under Canadian GAAP as the
initial measurement upon transition to IFRS. In keeping with industry peers,
Storm intends to use this exemption as it will provide the most relevant and
fair presentation of Storm's assets upon transition.
IFRS 6, Exploration for and Evaluation of Mineral Resources, is the standard
under which oil and gas exploration and evaluation costs are to be accounted
for, and it requires entities to choose from among several different policies
when accounting for exploration and evaluation costs. Storm plans to capitalize
its exploration and evaluation costs until it is determined that the property
contains reserves and is transferred to development or production assets, or
that no future economic benefits exist and the costs are expensed and
de-recognized. Costs incurred prior to obtaining the right to explore will be
expensed. Exploration and evaluation costs will be reported as a separate line
item on the Company's balance sheet; however, the adoption of IFRS 6 should have
no other significant effect on Storm's financial results.
IFRS 16, Property, Plant and Equipment, requires the Company to identify the
significant parts of its property, plant and equipment and to depreciate and
deplete each part separately, in contrast to Canadian GAAP where full cost
accounting permitted one such calculation for the full cost pool. In addition,
IFRS requires the recognition of gains and losses on disposition of oil and gas
properties. Under Canadian GAAP, proceeds of smaller dispositions were credited
against the carrying amount of the full cost asset pool. The IFRS method of
componentizing property, plant and equipment may result in an increase in the
number of component parts, analogous to separate cost centers recorded and
depreciated/depleted and, as a result, will affect the depletion calculation.
Costs of unsuccessful wells will be capitalized with either exploration and
evaluation costs or property and equipment, depending on the location, and will
be subject to the impairment test of the related area or CGU.
IAS 36, Impairment of Assets, requires impairment testing to be performed at the
cash generating unit "CGU" level as opposed to the full cost pool as permitted
under full-cost accounting under Canadian GAAP. The concept of full-cost
accounting under existing Canadian GAAP does not fit within the IFRS Framework
and, as such, Canadian companies engaged in oil and gas exploration and
development must allocate the carrying amount of their oil and gas assets to
CGUs at the date of transition to IFRS. A "CGU" is defined as the smallest
identifiable asset or group of assets that generates largely independent cash
flows. This change will result in impairment test calculations at the CGU level
and could possibly result in more frequent write-downs of the carrying values of
CGUs since the impairment tests are performed at a lower level than under
Canadian GAAP.
IAS 36 also uses a one-step approach for testing and measuring impairments, with
asset carrying amounts being compared to the higher of value in use and fair
value, less costs to sell. Value in use is defined as being equal to the present
value of future cash flows expected to be derived from the asset in its current
state. In the absence of an active market, fair value, less cost to sell, may
also be determined using discounted cash flows. The use of discounted cash flows
under IFRS differs from Canadian GAAP where undiscounted cash flows are used to
compare against the asset's carrying amount to determine if impairment exists.
This may result in more frequent write-downs, since asset carrying amounts that
were previously supported under Canadian GAAP, based on undiscounted cash flows,
may not be supported on a discounted cash flow basis under IFRS. However, under
IAS 36, previous impairment losses can be reversed where circumstances change,
such that the impairment has reduced. This also differs from Canadian GAAP,
which prohibits the reversal of previously recognized impairment losses.
Financial Instruments
IFRS prohibits the use of the "critical terms match" approach and "shortcut"
methods, which assume no ineffectiveness in a hedge transaction, whereas
Canadian GAAP permits the use of both for assessing and measuring
ineffectiveness of a hedge if certain conditions are met. This change will
likely prevent Storm from applying hedge accounting rules to its derivative
contracts.
Decommissioning Liabilities
In calculating asset retirement obligations, IFRS requires the use of the
current market-based discount rate at each reporting date rather than the
entity's credit-adjusted risk-free rate used under Canadian GAAP. This change
will affect the Company's asset retirement obligation liability at the date of
conversion to IFRS.
Future Income Taxes
The requirements under IFRS for future income taxes are similar to that required
under Canadian GAAP and should not have a significant effect on the Company's
financial statements.
Internal Controls over Financial Reporting
All entity level, information technology, disclosure and business process
controls will be updated and tested to reflect changes arising from the
Company's conversion to IFRS to enable Storm's CEO and CFO to certify as to the
effectiveness of internal controls as required under Canadian Security
Administrators' National Instrument 52-109. Where material changes are
identified, these changes will be tested to ensure that no material deficiencies
exist as a result of the Company's conversion to IFRS.
Information Systems
The adoption of IFRS will affect information systems requirements. The Company
is working with external suppliers on systems upgrades and changes to the chart
of accounts, as well as cost centre hierarchies and related measurements to
accommodate the new CGU definitions, and to month-end accounting processes to
ensure an efficient conversion to IFRS.
Summary
The differences described above are those existing based on Canadian GAAP and
IFRS today and should not be regarded as complete, as the intention is to
highlight those areas believed to be most significant. This analysis of possible
changes is on-going and not all decisions have been made where choices of
accounting policies are available. Further, the International Accounting
Standards Board has significant on-going projects that could affect the
Company's financial statements in future years.
An analysis of the effects of the adoption of IFRS on Storm's financial
statements is set out below. It should be recognized that this analysis is
preliminary and not comprehensive and is likely to change as IFRS and industry
and management's interpretation of IFRS evolves.
Financial Statement Effect on Financial
Category Change Under IFRS Statements of Storm
----------------------------------------------------------------------------
Property and Equipment Existing full-cost pool Certain costs
to be divided into attributable to areas
exploration and with no future
evaluation and development potential
development will be charged
and producing segments. to retained earnings on
Test for impairment at transition. Future
transition. depletion charges will
be reduced accordingly.
----------------------------------------------------------------------------
Property and Equipment Development and producing Additional depletion
segments to be calculations will be
allocated into Cash required at each
Generating Units (CGU) reporting period.
and depleted at a lower
level.
----------------------------------------------------------------------------
Property and Equipment Depletion can be Use of proved plus
calculated using either probable reserves in
proven or proved plus depletion calculation
probable reserves. will reduce depletion
expense.
----------------------------------------------------------------------------
Property and Equipment Gains and losses on Gains and losses on
dispositions will be property sales will be a
measured and recognized frequent income
in the income statement. statement item,
There is no de leading to a
minimis rule as more erratic earnings
exists under current profile.
----------------------------------------------------------------------------
Property and Equipment Impairment test will be Impairment of CGUs from
calculated at the CGU existing asset
level plus changes to base is unlikely to be
the impairment an issue.
calculation
methodology.
----------------------------------------------------------------------------
Financial Instruments Hedge accounting All future hedges will
requirements have be marked to market
become significantly and gains or losses will
more stringent. be included in the
income statement.
----------------------------------------------------------------------------
Asset Retirement A market-based discount Effect not yet
Obligation rate will be used determinable.
instead of using a
credit-adjusted
risk-free rate.
----------------------------------------------------------------------------
Borrowing Costs Interest costs relating Likely no effect on
to the financing of Storm, based on existing
assets with a long assets.
ready-for-use time frame
to be capitalized.
----------------------------------------------------------------------------
Cash Flow Statement To focus on cash More a presentation than
measurements only, with a measurement issue.
no adjustment for However, non-GAAP
working capital funds from operations
components. will be harder
to measure and may
disappear from common
usage.
----------------------------------------------------------------------------
Share-Based Payments Stock options that vest No material effect
in installments should likely.
be valued separately.
----------------------------------------------------------------------------
ADDITIONAL INFORMATION
Additional information relating to the Company, including the Company's Annual
Information Form, can be viewed at www.sedar.com or on the Company's website at
www.stormexploration.com. Information can also be obtained by contacting the
Company at Storm Exploration Inc., 800, 205 - 5th Avenue SW, Calgary, Alberta,
T2P 2V7.
MANAGEMENT'S REPORT
To the Shareholders of Storm Exploration Inc.
The consolidated financial statements of Storm Exploration Inc. were prepared by
management in accordance with appropriately selected generally accepted
accounting principles in Canada. Management has used estimates and careful
judgment, particularly in those circumstances where transactions affecting
current periods are dependent on information not know for certain until a future
period. The financial and operational information contained in this year-end
report is consistent with that reported in the financial statements.
Management is responsible for the integrity of the financial and operational
information contained in this report. The Company has designed and maintains
internal controls to provide reasonable assurance that assets are properly
safeguarded and that the financial records are well maintained and provide
relevant, timely and reliable information to management. The consolidated
financial statements have been prepared within reasonable limits of materiality
and within the framework of the significant accounting policies summarized in
the notes to the consolidated financial statements.
External auditors appointed by the shareholders have conducted an independent
examination of the corporate and accounting records in order to express their
opinion on the consolidated financial statements. The Audit Committee has met
with the external auditors and management in order to determine if management
has fulfilled its responsibilities in the preparation of the consolidated
financial statements. The Board of Directors has approved the consolidated
financial statements on the recommendation of the Audit Committee.
Donald McLean, Vice President, Finance and CFO
John Devlin, Controller
February 24, 2010
AUDITORS' REPORT
To the Shareholders of Storm Exploration Inc.
We have audited the consolidated balance sheets of Storm Exploration Inc. as at
December 31, 2009 and December 31, 2008 and the consolidated statements of
income (loss) and retained earnings, comprehensive income (loss) and cash flows
for the years then ended. These financial statements are the responsibility of
the company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
In our opinion, these financial statements present fairly, in all material
respects, the financial position of the company as at December 31, 2009 and
December 31, 2008 and the results of its operations and its cash flows for the
years then ended in accordance with Canadian generally accepted accounting
principles.
Chartered Accountants
Calgary, Alberta
February 24, 2010
Consolidated Balance Sheets
($000s) December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
ASSETS
----------------------------------------------------------------------------
Current
Accounts receivable $ 10,919 $ 14,274
Investments (Note 4) 3,607 -
Prepaids and other 4,861 2,916
----------------------------------------------------------------------------
19,387 17,190
Property and equipment - net (Note 3) 303,053 290,944
Investments (Note 4) 22,492 20,242
----------------------------------------------------------------------------
$ 344,932 $ 328,376
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
----------------------------------------------------------------------------
Current
Accounts payable and accrued liabilities $ 25,661 $ 34,076
Unrealized financial instrument
provision (Note 11) 1,855 -
----------------------------------------------------------------------------
27,516 34,076
Bank indebtedness (Note 5) 86,758 81,904
Asset retirement obligation (Note 6) 7,584 7,259
Future income taxes (Note 7) 20,478 22,875
----------------------------------------------------------------------------
142,336 146,114
----------------------------------------------------------------------------
Shareholders' equity (Note 8)
Share capital 107,852 88,013
Contributed surplus 5,719 3,980
Retained earnings 89,952 90,269
Accumulated other comprehensive
income (deficit) (927) -
----------------------------------------------------------------------------
202,596 182,262
----------------------------------------------------------------------------
Commitments (Note 13)
----------------------------------------------------------------------------
$ 344,932 $ 328,376
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Income (Loss) and Retained Earnings
Year Ended Year Ended
($000s except per-share amounts) December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Revenue
Revenue from product sales $ 90,115 $ 150,711
Realized loss on financial
instruments (Note 11) (1,108) (2,187)
Unrealized loss on financial
instruments (Note 11) (137) -
Royalties (15,069) (31,021)
----------------------------------------------------------------------------
73,801 117,503
----------------------------------------------------------------------------
Expenses
Production 16,335 17,065
Transportation 4,711 5,279
Interest 3,636 3,503
General and administrative 4,660 3,441
Stock-based compensation 2,022 1,886
Provision for accounts receivable - 725
Depletion, depreciation and accretion 43,824 42,089
----------------------------------------------------------------------------
75,188 73,988
----------------------------------------------------------------------------
Income (loss) before the following: (1,387) 43,515
Investment gain (loss) (Note 4) (675) 3,527
Future income taxes (Note 7) 1,745 (12,356)
----------------------------------------------------------------------------
Net income (loss) for the year (317) 34,686
Retained earnings, beginning of year 90,269 55,583
----------------------------------------------------------------------------
Retained earnings, end of year $ 89,952 $ 90,269
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income (loss) per share (Note 9)
- basic $ (0.01) $ 0.78
- diluted $ (0.01) $ 0.76
Consolidated Statements of Comprehensive Income (Loss)
Year Ended Year Ended
($000s) December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Net income (loss) for the period $ (317) $ 34,686
Unrealized hedging loss (Note 11) (1,718) -
Unrealized gain on shares available
for sale (Note 4) 457 -
Related income tax 334 -
----------------------------------------------------------------------------
Other comprehensive loss (927) -
----------------------------------------------------------------------------
Comprehensive income (loss) for the year $ (1,244) $ 34,686
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Cash Flows
Year Ended Year Ended
($000s) December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Operating activities
Net income (loss) for the year $ (317) $ 34,686
Non-cash items:
Investment loss (gain) (Note 4) 675 (3,527)
Depletion, depreciation and accretion 43,824 42,089
Unrealized loss on financial
instruments (Note 11) 137 -
Future income tax (1,745) 12,356
Stock-based compensation 2,022 1,886
----------------------------------------------------------------------------
Funds from operations 44,596 87,490
Net change in non-cash working capital
items (Note 10) 1,025 (1,518)
----------------------------------------------------------------------------
45,621 85,972
----------------------------------------------------------------------------
Financing activities
Issue of common shares - net of expenses 19,238 795
Increase in bank indebtedness 4,854 7,432
----------------------------------------------------------------------------
24,092 8,227
----------------------------------------------------------------------------
Investing activities
Increase in investments (Note 4) (2,925) (7,440)
Additions to property and equipment (74,170) (99,934)
Disposals of property and equipment 18,562 4,980
Net change in non-cash working capital
items (Note 10) (11,180) 8,195
----------------------------------------------------------------------------
(69,713) (94,199)
----------------------------------------------------------------------------
Change in cash during the year - -
Cash, beginning of year - -
----------------------------------------------------------------------------
Cash, end of year $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Years ended December 31, 2009 and 2008
Tabular amounts in thousands, except per share amounts
1. NATURE OF OPERATIONS
Storm Exploration Inc. (the "Company" or "Storm"), is an oil and gas exploration
and development company listed on the Toronto Stock Exchange under the symbol
SEO. The Company operates in the provinces of Alberta and British Columbia. The
Company's production base is largely natural gas and natural gas liquids. These
consolidated financial statements include the accounts of Storm and its wholly
owned subsidiary and partnership.
2. SIGNIFICANT ACCOUNTING POLICIES
These consolidated financial statements of Storm have been prepared by
management in accordance with accounting principles generally accepted in Canada
("GAAP"). The significant accounting policies used in the preparation of these
consolidated financial statements are as follows:
Property and Equipment
Petroleum and Natural Gas Properties and Equipment
The Company follows the full-cost method of accounting for petroleum and natural
gas properties, whereby all costs associated with the exploration for and
development of petroleum and natural gas reserves, whether productive or
unproductive, are capitalized in a Canadian cost centre. Such costs include land
acquisition, drilling of both productive and unproductive wells, geological and
geophysical costs, the cost of production equipment and the present value of the
future asset retirement obligation. General and administrative costs are not
capitalized.
Depletion and Depreciation
Capitalized costs are depleted using the unit-of-production method based on
estimated proved petroleum and natural gas reserves, before royalties, as
determined by independent engineers. Production and reserves of natural gas are
converted to equivalent barrels of crude oil on the basis of six thousand cubic
feet of gas to one barrel of oil. Costs of acquiring and evaluating unproved
properties are excluded from depletion calculations until it is determined
whether or not proved reserves are attributable to the properties or impairment
occurs. Proceeds from the sale of petroleum and natural gas properties and
related equipment are applied against capitalized costs, with no gain or loss
recognized, unless such a sale would result in a change in the rate of depletion
of 20% or more.
Processing facilities and well equipment are depreciated on a straight-line
basis over the estimated useful life of the facilities and equipment.
Impairment
Net capitalized costs of the Company's petroleum and natural gas properties are
subject, at least annually, to a ceiling test to ensure that capitalized costs
do not exceed an estimate of future net revenues. This latter amount is the
aggregate of expected undiscounted future net cash flows from proved reserves
and the lower of cost or market value of unproved properties. Future cash flows
are estimated using expected future prices and costs. If the carrying amount is
not fully recoverable, the amount of impairment is measured by comparing the
carrying amounts of the capital assets to an amount equal to the estimated net
present value of future cash flows from proved plus probable reserves. This
impairment in the carrying amount would be recognized and charged to current
operations as additional depletion. No such charges have been incurred by the
Company.
Office Furniture and Equipment
Furniture and equipment is recorded at cost and is depreciated on a straight
line basis over its expected useful life of 10 years.
Joint Operations
Substantially all of the Company's exploration and production activities are
conducted through unincorporated joint ventures, under joint operating
agreements. The accounts of the Company reflect its proportionate interest in
such activities.
Investments
The Company has long-term investments in two private companies, Storm Gas
Resource Corp. ("SGR") and Storm Ventures International Inc. ("SVI"), which are
accounted for using the equity method and the cost method, respectively.
The Company's investment in Bellamont Exploration Ltd. ("Bellamont") is
designated as available for sale and carried at fair value with the
corresponding gain (loss) recognized in other comprehensive income.
Asset Retirement Obligation
The Company recognizes the fair value of the retirement obligation associated
with properties in the period in which this liability arises and when reasonable
estimates of fair value can be made. The fair value of the liability is
calculated as the present value of the expected future costs of abandonment and
reclamation. The obligation is recorded as a long term liability with a
corresponding increase to the carrying amount of property and equipment. The
liability is increased each reporting period through the accretion of interest
up to the future amount of the liability. The charge for accretion is recorded
as an expense in the Company's consolidated statement of income. The increase in
the carrying amount of the property and equipment is amortized on the same basis
as property and equipment. Actual costs incurred upon settlement of the
abandonment obligation are charged against the liability.
Revenue Recognition
Revenues from the sale of crude oil, natural gas liquids and natural gas are
recorded when title passes to a third party.
Income Taxes
Income taxes are calculated using the liability method of tax accounting.
Temporary differences arising from the difference between the tax basis of an
asset or liability and its carrying amount on the consolidated balance sheet are
used to calculate future income tax assets and liabilities. Future income tax
assets and liabilities are calculated using tax rates anticipated to apply in
the periods that the temporary differences are expected to reverse.
Flow-Through Shares
Flow-through shares were issued in 2006 and 2007, with the proceeds used to fund
qualifying exploration expenditures within a defined period. Expenditures funded
by flow-through arrangements are renounced to investors in accordance with tax
legislation. Share capital is reduced and the future tax liability is increased
by the estimated future income tax cost of the renounced tax deductions.
Stock-Based Compensation
The Company has issued options to acquire common shares to directors, officers
and employees of the Company. These options are accounted for using the fair
value method which estimates the value of the options at the date of the grant
using the Black-Scholes option pricing model. The fair value thus established is
recognized as an expense over the vesting period of the options with an
equivalent increase to contributed surplus.
Per-Share Amounts
Net income per share is calculated using the weighted average number of shares
outstanding during each reporting period. Diluted net income per share is
calculated using the treasury stock method to determine the dilutive effect of
stock options. The treasury stock method assumes that the proceeds received from
the exercise of "in the money" stock options are used to purchase common shares
at the market price at the end of the reporting period.
Measurement Uncertainty
The amounts recorded for depletion and depreciation of property and equipment,
the provision for the asset retirement obligation and amounts used for ceiling
test calculations are based on estimates of reserves, production rates and
future commodity prices and costs. Stock-based compensation and future income
tax include assumptions with respect to future costs, discount rates, income tax
rates and timing of deductions. These estimates are subject to measurement
uncertainty and the effect on the consolidated financial statements of changes
in such estimates in future periods could be material.
Financial Instruments
A financial instrument is any contract that gives rise to a financial asset of
one entity and a financial liability or equity instrument of another entity.
Upon initial recognition, financial instruments are measured at fair value.
Measurement in subsequent periods depends on whether the financial instrument
has been classified as held-for-trading, available-for-sale, held-to-maturity,
loans and receivables, or other financial liabilities.
a. Held-for-trading
Financial assets and liabilities designated as held-for-trading are subsequently
measured at fair value with changes in those fair values charged immediately to
earnings. With the exception of derivative contracts that qualify for hedge
accounting, the Company classifies all derivative contracts as held-for-trading.
b. Available-for-sale assets
Available-for-sale financial assets are subsequently measured at fair value with
changes in fair value recognized in Other Comprehensive Income (Loss) ("OCI"),
net of tax. Amounts recognized in OCI for available-for-sale financial assets
are charged to earnings when the asset is derecognized or when there is an other
than temporary asset impairment. The Company classifies its investment in
Bellamont shares as an available-for-sale asset.
c. Held-to-maturity investments, loans and receivables and other financial
liabilities
Held-to-maturity investments, loans and receivables, and other financial
liabilities are subsequently measured at amortized cost using the effective
interest method. The Company classifies accounts receivable as loans and
receivables, and accounts payable and accrued liabilities, and bank indebtedness
as other financial liabilities.
Storm is exposed to market risks resulting from fluctuations in commodity
prices, foreign exchange rates and interest rates in the normal course of
operations. A variety of derivative instruments may be used by the Company to
reduce its exposure to fluctuations in commodity prices, foreign exchange rates,
and interest rates. The Company does not use these derivative instruments for
trading or speculative purposes. The fair values of these derivative instruments
are based on an estimate of the amounts that would have been received or paid to
settle these instruments prior to maturity. The Company considers all of these
transactions to be effective economic hedges; however, some of Storm's contracts
do not qualify or have not been designated as effective hedges for accounting
purposes.
For derivative instruments that do not qualify for hedge accounting, the Company
applies the fair value method of accounting by recording an asset or liability
on the Consolidated Balance Sheet and recognizing changes in the fair value of
the instruments in earnings during the current period.
For derivative instruments that qualify as effective accounting hedges, policies
and procedures are in place to ensure that the required documentation and
approvals are obtained. Where specific hedges are executed, the Company
assesses, both at the inception of the hedge and thereafter, whether the
derivative used in the particular hedging transaction is effective in offsetting
changes in fair value or cash flows of the hedged item.
In a cash flow hedging relationship, the effective portion of the change in the
fair value of the hedging derivative is recognized in OCI while the ineffective
portion is recognized in earnings.
Transaction costs are expensed as incurred for all financial instruments. The
Company assesses at each reporting period whether its financial assets are
impaired.
Changes in Accounting Policies
Effective December 31, 2009, the Company adopted the amendments to Handbook
Section 3862, Financial Instruments - Disclosures. The amendments include
enhanced disclosures relating to the fair value of financial instruments and the
liquidity risk associated with financial instruments. Refer to Note 11,
Financial Instruments, for enhanced fair value disclosures. The amendments are
consistent with recent amendments to financial instrument disclosure standards
in International Financial Reporting Standards ("IFRS").
Future Accounting Changes
Business Combinations
The CICA issued Handbook Section 1582 "Business Combinations" that replaces the
previous business combinations standard. Under this guidance, the purchase price
used in a business combination is based on the fair value of shares exchanged at
the market price at acquisition date. Under the current standard, the purchase
price used is based on the market price of shares for a reasonable period before
and after the date the acquisition is agreed upon and announced. In addition,
the guidance generally requires all transaction costs to be expensed. Current
standards allow for the capitalization of these costs as part of the purchase
price. This standard applies prospectively to business combinations on or after
January 1, 2011.
Consolidated Financial Statements and Non-Controlling Interest
The CICA issued Handbook Sections 1601 "Consolidated Financial Statements", and
1602 "Non-controlling Interests", which replaces the existing guidance under
Section 1600 "Consolidated Financial Statements". Section 1601 establishes
standards for the preparation of Consolidated Financial Statements. Section 1602
provides guidance on accounting for a non-controlling interest in a subsidiary
in Consolidated Financial Statements subsequent to a business combination. These
standards will be effective for Storm for business combinations occurring on or
after January 1, 2011.
International Financial Reporting Standards
The CICA has confirmed January 1, 2011 as the effective date for the conversion
of Canadian GAAP to International Financial Reporting Standards ("IFRS"). The
Company will be required to begin reporting under IFRS in the first quarter of
2011 with comparative data for the prior year. IFRS uses a conceptual framework
similar to Canadian GAAP; however, there will be significant differences in
recognition, measurement and disclosures.
The Company has begun the process of transitioning to IFRS and has identified
key areas of Storm's financial reporting, internal controls and business
processes that will be affected by this change.
3. PROPERTY AND EQUIPMENT
December 31, December 31,
2009 2008
----------------------------------------------------------------------------
Property and equipment $ 465,843 $ 410,394
Accumulated depletion and depreciation (162,790) (119,450)
----------------------------------------------------------------------------
$ 303,053 $ 290,944
----------------------------------------------------------------------------
----------------------------------------------------------------------------
At December 31, 2009, the depletion calculation excluded unproved properties of
$29.2 million (December 31, 2008 - $23.3 million) and included future
development costs of $117.3 million (December 31, 2008 - $140.3 million).
The prices used, in Canadian dollars, in the ceiling test evaluation of the
Company's natural gas, crude oil and natural gas liquids reserves at December
31, 2009 were:
Annual
Increase
2010 2011 2012 2013 2014 to 2029
----------------------------------------------------------------------------
Natural gas ($/Mcf) 6.11 6.66 7.22 7.81 8.39 2.0%
Crude oil ($/Bbl) 79.93 82.53 85.27 90.99 95.88 2.0%
Natural gas liquids ($/Bbl) 57.34 58.78 60.35 63.82 67.42 2.0%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
4. INVESTMENTS
December 31, December 31,
2009 2008
----------------------------------------------------------------------------
Investment in Bellamont Exploration Ltd. $ 3,607 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Long-term investments:
Investment in Storm Gas Resource Corp. $ 11,967 $ 9,717
Investment in Storm Ventures International Inc. 10,525 10,525
----------------------------------------------------------------------------
$ 22,492 $ 20,242
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In November, 2009 the Company sold certain producing properties to Bellamont
Exploration Ltd. ("Bellamont") for proceeds totaling $17.2 million, comprised of
$14.0 million in cash and 5.08 million shares in Bellamont. This investment in
Bellamont shares is carried at fair value, determined with reference to the
published share price, with the corresponding holding gain recognized in other
comprehensive income.
The Company's long-term investments include interests in two private companies,
Storm Gas Resource Corp. ("SGR") and Storm Ventures International Inc. ("SVI").
Storm's initial investment in SGR, comprising cash and lands transferred at fair
value, totaled $1.3 million and represented a 45% interest. In July 2008 Storm
participated in a private placement of common shares in SGR, the terms of which
were such that the Company's ownership position was reduced from 45% to 22%. As
the shares issued under the private placement were sold at a share price greater
than the price of Storm's initial investment, the Company recognized a dilution
gain of $3.5 million in 2008. In November 2009, Storm participated in another
private placement of common shares of SGR at a cost of $2.9 million, maintaining
its 22% interest in SGR. In 2009, Storm recorded an investment loss in SGR,
representing Storm's pro-rata share of changes in SGR's equity. The common
shares of SGR are unlisted and the carrying amount of the Company's investment
does not represent a market valuation of the Company's investment in SGR. The
Company's 22% interest in SGR is accounted for using the equity method. In 2009,
the Company provided management services to SGR at a cost of $0.3 million (2008
- $0.1 million). The Company and SGR are also 40:60 joint venture participants
in certain undeveloped lands.
The Company's 6% interest in SVI is accounted for using the cost method. In July
2008, the Company participated in a private placement of common shares of SVI in
the amount of $1.3 million; as the Company's participation was not pro rata to
its existing interest, the Company's ownership position in SVI was reduced from
13% to 12%. Subsequently, in December 2008, SVI issued additional common shares,
reducing the Company's ownership position to 6%. The common shares of SVI are
unlisted and the carrying amount of the Company's investment does not represent
a market valuation of the Company's investment in SVI.
5. BANK INDEBTEDNESS
The Company has an extendible revolving bank facility in the amount of $120
million (December 31, 2008 - $110 million), based on the Company's producing
reserves. The revolving facility is available to the Company until April 30,
2010, but may be extended at the Company's request until April 29, 2011, subject
to the bank's review of the Company's reserve lending base. If the revolving
facility is not renewed at the end of the current revolving phase, the facility
moves into a term phase whereby the loan is to be retired with one payment on
the 366th day following the last day of the revolving phase, in an amount equal
to the outstanding principal. Interest is paid on the revolving facility at
banker's acceptance rates plus a stamping fee. Security comprises a floating
charge demand debenture on the assets of the Company.
6. ASSET RETIREMENT OBLIGATION
The estimated future asset retirement obligation is based on the Company's net
ownership interest in wells and facilities, the estimated costs to abandon and
reclaim the wells and facilities and the estimated timing of the costs to be
incurred in future periods. The total estimated undiscounted amount required to
settle the Company's asset retirement obligations is approximately $12.8 million
(December 31, 2008 - $13.0 million), which will be paid over the next 21 years,
with the majority of costs paid between 2015 and 2031. A credit adjusted
risk-free rate of eight percent was used to calculate the present value of the
asset retirement obligations, amounting to $7.6 million (December 31, 2008 -
$7.3 million).
The following table provides a reconciliation of the carrying amount of the
obligation associated with the retirement of oil and gas properties:
2009 2008
----------------------------------------------------------------------------
Asset retirement obligation, beginning of year $ 7,259 $ 6,918
Liabilities incurred 741 108
Liabilities disposed (900) (255)
Accretion expense 484 488
----------------------------------------------------------------------------
Asset retirement obligation, end of year $ 7,584 $ 7,259
----------------------------------------------------------------------------
----------------------------------------------------------------------------
7. FUTURE INCOME TAXES
The future income tax liability is based on the excess of the accounting amounts
over the related tax bases of the Company's property and equipment, asset
retirement obligation and share capital.
The Company has tax pools associated with property and equipment of
approximately $214 million as well as capital losses of approximately $10
million, all of which are not subject to expiry.
The provision for future income taxes is different from the amount computed by
applying the combined statutory Canadian federal and provincial tax rates to
pre-tax income for the period.
The differences are as follows:
2009 2008
----------------------------------------------------------------------------
Statutory combined federal and provincial income
tax rate 28% 30%
Expected income taxes $ (587) $ 14,280
Add (deduct) the income tax effect of:
Stock-based compensation 575 572
Equity loss (gain) 192 (1,071)
Rate adjustments (1,942) (1,432)
Other 17 7
----------------------------------------------------------------------------
Future income taxes $ (1,745) $ 12,356
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The components of the future income tax liability are as follows:
December 31, December 31,
2009 2008
----------------------------------------------------------------------------
Property and equipment $ 23,253 $ 25,331
Asset retirement obligation (1,942) (2,033)
Share issue costs (499) (423)
Unrealized financial instrument provision (334) -
----------------------------------------------------------------------------
Future income tax liability $ 20,478 $ 22,875
----------------------------------------------------------------------------
----------------------------------------------------------------------------
8. SHAREHOLDERS' EQUITY
Share Capital
Authorized
An unlimited number of non-voting common shares
An unlimited number of voting common shares
An unlimited number of preferred shares
Included in the following common share balances are 1,275,000 non-voting common
shares. Except for voting rights, non-voting and voting common shares are
identical.
Issued
Number of Shares Consideration
----------------------------------------------------------------------------
Balance as at December 31, 2007 44,532 $ 86,994
Stock options exercised (1) 171 1,019
----------------------------------------------------------------------------
Balance at December 31, 2008 44,703 88,013
Issuance of common shares (2) 1,850 19,610
Stock options exercised (3) 190 1,095
Share issue costs (net of income tax
benefit) (866)
----------------------------------------------------------------------------
Balance as at December 31, 2009 46,743 $ 107,852
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) During 2008, 171,000 stock options were exercised for proceeds of
$795,000 and related prior stock-based compensation expense of $224,000
was added to share capital.
(2) On March 6, 2009, 1,850,000 common shares were issued at a price of
$10.60 per share for total proceeds of $19,610,000, before commission
and expenses.
(3) During 2009, 190,000 stock options were exercised for proceeds of
$812,000 and related prior stock-based compensation expense of
$283,000 was added to share capital.
Stock-Based Compensation Plans
The Company has a stock option plan under which it may grant, at the Company's
discretion, options to purchase common shares to directors, officers and
employees. Under the stock option plan a total of 3,700,000 common shares have
been reserved for issuance. Details of the options outstanding at December 31,
2009 are as follows:
Weighted Average
Number of options Exercise Price
----------------------------------------------------------------------------
Outstanding at December 31, 2008 2,267 $ 6.03
Issued during year 994 $ 12.12
Exercised during year (190) $ 4.25
Forfeited during year (57) $ 11.48
----------------------------------------------------------------------------
Outstanding at December 31, 2009 3,014 $ 8.04
----------------------------------------------------------------------------
----------------------------------------------------------------------------
December 31, December 31,
2009 2008
----------------------------------------------------------------------------
Average remaining life (years) 2.6 2.6
Number exercisable at end of year (000s) 1,489 1,001
----------------------------------------------------------------------------
Option prices $3.61 - $12.60 $2.60 - $11.40
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Outstanding Options Exercisable Options
----------------------------------------------------------------------------
Weighted Weighted Weighted
Number of Average Average Number of Average
Range of Options Remaining Exercise Options Exercise
Exercise Price Outstanding Life (years) Price Outstanding Price
----------------------------------------------------------------------------
$3.61 to $5.39 413 0.4 $ 4.26 413 $ 4.26
$5.67 to $8.27 1,627 2.0 $ 6.62 1,074 $ 6.41
$8.57 to $12.60 974 4.5 $ 12.04 2 $ 11.40
----------------------------------------------------------------------------
3,014 2.6 $ 8.04 1,489 $ 5.82
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Using the Black-Scholes pricing model, the weighted average fair value of the
options granted in 2009 was estimated to be $3.79 (2008 - $8.68), using
risk-free interest rates of 2.5%, volatility of 40% and an expected average
vesting period of 30 months. The amortized cost of the options is charged as
stock-based compensation in the consolidated statement of income (loss) with an
equivalent offset to contributed surplus.
Contributed Surplus
December 31, December 31,
2009 2008
----------------------------------------------------------------------------
Balance, beginning of year $ 3,980 $ 2,318
Stock-based compensation 2,022 1,886
Transfer to share capital on exercise of options (283) (224)
----------------------------------------------------------------------------
Balance, end of year $ 5,719 $ 3,980
----------------------------------------------------------------------------
----------------------------------------------------------------------------
9. PER SHARE AMOUNTS
Year Ended Year Ended
December 31, December 31,
2009 2008
----------------------------------------------------------------------------
Basic
Net income per share $ (0.01) $ 0.78
Weighted average number of shares
outstanding (000s) 46,275 44,654
Diluted
Net income per share $ (0.01) $ 0.76
Weighted average number of shares
outstanding (000s) 47,226 45,877
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The reconciling items between basic and diluted weighted average common
shares are stock options described in Note 8.
10. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in non-cash working capital
Year Ended Year Ended
December 31, December 31,
2009 2008
----------------------------------------------------------------------------
Accounts receivable $ 3,355 $ (2,325)
Prepaids and other (5,095) (971)
Accounts payable and accrued liabilities (8,415) 9,973
----------------------------------------------------------------------------
Change in non-cash working capital $ (10,155) $ 6,677
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Relating to:
Operating activities 1,025 (1,518)
Financing activities $ - $ -
Investing activities (11,180) 8,195
----------------------------------------------------------------------------
$ (10,155) $ 6,677
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid during the year $ 3,636 $ 3,503
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Income taxes paid during the year $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
11. FINANCIAL INSTRUMENTS
Financial Instrument Classification and Measurement
The Company's financial instruments carried on the Consolidated Balance Sheet
are carried at amortized cost with the exception of its investment in derivative
contracts and its investment in Bellamont, which are carried at fair value.
There were no significant differences between the carrying value of financial
instruments and their estimated fair values as at December 31, 2009.
The Company's investment in Bellamont and derivative contracts are transacted in
active markets. Storm classifies the fair value of these transactions according
to the following hierarchy based on the amount of observable inputs used to
value the instrument.
- Level 1 - Quoted prices are available in active markets for identical assets
or liabilities as of the reporting date. Active markets are those in which
transactions occur in sufficient frequency and volume to provide pricing
information on an ongoing basis.
- Level 2 - Pricing inputs are other than quoted prices in active markets
included in Level 1. Prices in Level 2 are either directly or indirectly
observable as of the reporting date. Level 2 valuations are based on inputs,
including quoted forward prices for commodities, time value and volatility
factors, which can be substantially observed or corroborated in the marketplace.
- Level 3 - Valuations in this level are those with inputs for the asset or
liability that are not based on observable market data.
The Company's investment in Bellamont and its derivative contracts have been
assessed on the fair value hierarchy described above. The investment in
Bellamont is classified as Level 1 and the derivative contracts as Level 2.
Assessment of the significance of a particular input to the fair value
measurement requires judgment and may affect the placement within the fair value
hierarchy level.
Risk Management
The Company holds various financial instruments. These financial instruments
expose the Company to the following risks:
- credit risk;
- market risk;
- liquidity risk.
Management has primary responsibility for monitoring and managing financial
instrument risks under direction from the Board of Directors, which has overall
responsibility for establishing the Company's risk management framework. In
certain circumstances, for example, hedging of future production revenue, the
Board has established policies and risk limits and controls, and monitors these
risks in relation to market conditions. In other circumstances, for example,
extending credit to purchasers of the Company's products, the Board has
delegated responsibility for credit assessment to management, but receives
frequent financial and operating reports.
The Company's financial instruments recognized on the consolidated balance sheet
consist of accounts receivable, investments, bank indebtedness, accounts payable
and accrued liabilities and unrealized financial instrument provision. The fair
value of these financial instruments approximates their carrying amounts.
Credit risk
A substantial portion of the Company's accounts receivable is concentrated with
a limited number of purchasers of commodities and joint venture partners in the
oil and gas industry and are subject to normal industry credit risk. Management
considers this concentration of credit risk to be limited, as commodity
purchasers are major industry participants, and receivables from partners are
protected by effective industry standard legal remedies. In addition, the
Company's high working interest in its major operating properties mitigates the
risk of partner default. The Company requires cash calls from its partners on
major field projects in advance of commencement. Receivables related to the sale
of the Company's production are normally collected on the 25th day of the month
following delivery. Nevertheless, the widespread disruption of credit markets
over the last two years, together with falling commodity prices, has exposed the
Company to greater credit risks, necessitating greater vigilance regarding
provision of credit to customers and to joint venture partners.
Market risk
Market risks are as follows and are largely outside the control of the Company:
- commodity prices;
- interest rates;
- foreign exchange.
Commodity prices
The Company is constantly exposed to the risk of declining prices for its
products with a corresponding reduction in cash flow. Reduced cash flow may
result in lower levels of capital being available for field activity, thus
compromising the Company's capacity to grow production while at the same time
replacing continuous production declines from existing properties. When debt
levels are forecast to increase due to capital expenditures exceeding cash flow,
or where the Company has financed, in whole or in part, an acquisition using
bank debt, the Company may enter into oil and natural gas hedging contracts in
order to provide stability of future cash flow and thus predictable debt
reduction. These contracts reduce the fluctuation in production revenue by
fixing prices of future deliveries of oil and natural gas. Such arrangements are
made in accordance with the Company's risk management policy and the Company
does not use these instruments for trading or speculative purposes. The Company
formally documents all relationships between derivative instruments and hedged
items, as well as the risk management objectives and strategy for undertaking
hedge transactions. Certain derivative instruments used by the Company qualify
for hedge accounting treatment. Realized gains and losses on these contracts are
recognized as revenue in the same period in which the revenues associated with
the hedged transactions are recognized. The Company also assesses, both at the
contract's inception and on an ongoing basis, whether the instruments that are
used are highly effective in offsetting the changes in fair values or cash flows
of hedged items. However, certain derivative instruments, relating to crude oil,
in place during 2009 did not satisfy hedge accounting criteria. As a result,
these financial instruments have been valued on a mark-to-market basis and the
resulting gain or loss recognized in income.
For the year ended December 31, 2009, the Company realized losses on financial
instruments of $1.1 million (2008 - $2.2 million).
As at December 31, 2009, Storm has the following derivative contracts in place,
which do not meet the hedge accounting criteria. The unrealized mark-to-market
loss on these contracts of $0.1 million as at December 31, 2009 (2008 - $nil) is
recognized in the financial statements as a decrease in revenue and an increase
in the unrealized financial instrument provision included with current
liabilities:
Volume Price Term
----------------------------------------------------------------------------
Crude Oil Swap
450 Bbls/d $ 83.45/Bbl Jan. 1, 2010 - Jun. 30, 2010
----------------------------------------------------------------------------
As at December 31, 2009, Storm has the following derivative contracts in place,
which meet the hedge accounting criteria. The unrealized mark-to-market loss on
these contracts of $1.7 million as at December 31, 2009 (2008 - $nil) is
recognized in the financial statements as a reduction of other comprehensive
income and an increase in the unrealized financial instrument provision included
with current liabilities:
Volume Price Term
----------------------------------------------------------------------------
Natural Gas Swaps
28,000 GJ/day $ 4.73 - $5.21/GJ Jan. 1, 2010 - Mar. 31, 2010
21,000 GJ/day $ 4.73 - $4.90/GJ Apr. 1, 2010 - Jun. 30, 2010
----------------------------------------------------------------------------
Subsequent to December 31, 2009, the Company entered into additional
derivative natural gas contracts as follows:
Volume Price Term
----------------------------------------------------------------------------
Collar
7,000 GJ/day $ 5.00 - $5.70 April 2010 - September 2010
Swap
5,000 GJ/day $5.20 July 2010 - September 2010
----------------------------------------------------------------------------
Interest rates
Interest on the Company's revolving bank facility varies with changes in
interest rates, and is most commonly based on bankers' acceptance rates plus a
stamping fee. The Company is thus exposed to increased borrowing costs during
periods of increasing interest rates, with a corresponding reduction in both
cash flows and project economics. As at December 31, 2009, Storm has fixed the
interest rate on $60 million of bankers acceptances at a rate of 0.695%, plus
stamping fees, for the period May 8, 2009 to May 10, 2010. Mark-to-market
measurement of this derivative instrument does not have a material effect on the
value of the Company's debt at December 31, 2009.
Foreign exchange
Although the Company's product revenues are denominated in Canadian dollars, the
underlying market prices are affected by the exchange rate between the Canadian
and the United States dollar. As at December 31, 2009, the Company had no
contracts in place to reduce foreign exchange risk.
Sensitivities
Using the Company's actual production volumes, royalty rates, income tax rates
and debt levels for the years ended December 31, 2009 and 2008, the estimated
after-tax effects that changes in certain factors would have on net income and
net income per share is as follows:
2009 2008
----------------------------------------------------------------------------
Change in Change in
Change in Net Income Change in Net Income
Factor Net Income Per Share Net Income Per Share
----------------------------------------------------------------------------
US$ 1.00/Bbl change in the
price of WTI $ 298,000 $ 0.01 $ 223,000 $ 0.00
$0.10/Mcf change in the price
of natural gas $ 915,000 $ 0.02 $ 749,000 $ 0.02
1% change in the interest rate $ 647,000 $ 0.01 $ 562,000 $ 0.01
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liquidity risk
Liquidity difficulties would emerge if the Company was unable to meet its
financial obligations as they fell due within normal credit terms. This may be
the consequence of diminished cash flows resulting from lower product prices,
production interruptions, or operating or capital cost increases. Liquidity
difficulties could also occur if the Company's bankers were unable to continue
to provide credit at a level, cost and on terms compatible with the Company's
capital requirements. Generally, the Company will, over a reasonable period of
time, limit its capital programs to cash flow from operations. In addition, the
Company endeavours to maintain its debt at a level less than the maximum amount
of its total bank facility to ensure financial flexibility to deal with
unforeseen or rapidly changing circumstances.
12. CAPITAL MANAGEMENT
Capital management is fundamental to the Company's objective of cost-effective
production growth, while simultaneously replacing continuous production
declines. The Company's capital comprises shareholders' equity, bank
indebtedness and working capital. Capital management involves the preparation of
an annual budget, which may only be implemented after approval by the Company's
Board of Directors. As the Company's business evolves during the fiscal year,
the budget may be amended; however, any changes are again subject to approval by
the Board of Directors. As part of the budget process, and as part of capital
management control procedures, the Company continuously uses a non-GAAP
measurement of net debt to cash flow to measure and control debt levels during
the fiscal year. Debt to cash flow is also used by the Company's bankers to set
the stamping fee applicable to the Company's bank indebtedness.
The measurement is established as follows:
December 31, December 31,
2009 2008
----------------------------------------------------------------------------
Current assets $ 19,387 $ 17,190
Accounts payable and accrued liabilities 25,661 34,076
----------------------------------------------------------------------------
Working capital deficiency 6,274 16,886
Bank indebtedness 86,758 81,904
----------------------------------------------------------------------------
Net debt $ 93,032 $ 98,790
Funds from operations for the year $ 44,596 $ 87,490
Net debt to non-GAAP funds from operations 2.1:1 1.1:1
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The above measurement is subject to quarterly variations and is usually highest
in the first and fourth quarter of each year, when capital expenditures normally
exceed cash flow, with a resulting increase in net debt. The increase in this
ratio at December 31, 2009 is a result of decreased cash flow in 2009 due to
lower commodity prices.
The Company's credit availability is based on the Company's producing reserves.
The non-GAAP measurement of net debt to funds from operations is used to
determine the interest rate applied to the Company's bank indebtedness, with
interest rates changing at certain threshold levels of net debt to cash flow.
The Company's bankers are entitled to complete a year-end and a mid-year
evaluation of the Company's borrowing base, which, in circumstances of falling
commodity prices, negative changes to the Company's operating activities, or
credit limitations affecting the Company's banking syndicate, may result in a
decrease in the line of credit available to the Company. The Company's bankers
completed a mid-term evaluation of the Company's borrowing base and have
confirmed that the bank facility will remain unchanged at $120 million.
From time to time, the Company may enter into hedging arrangements if capital
programs or acquisition costs result in a high net debt to cash flow ratio. Such
arrangements provide for stability of cash flow during periods when the Company
applies cash flow to reduce its net debt.
Increased debt levels arising from acquisitions, or capital programs exceeding
cash flow, may be addressed by reduced capital expenditures, disposal of
non-core assets or the issue of common shares.
13. COMMITMENTS
The Company has the following fixed-term commitments relating to its ongoing
business:
2010 2011 2012 2013 2014
----------------------------------------------------------------------------
Lease of premises $ 825 $ 838 $ 838 $ 419 $ -
Equipment leases 200 145 50 - -
Gas transportation and
processing commitments 1,726 1,434 887 486 240
----------------------------------------------------------------------------
Total $ 2,751 $ 2,417 $ 1,775 $ 905 $ 240
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Senior Management
Brian Lavergne Harry Ediger
President & CEO Vice President, Land
Robert S. Tiberio Eric Blakely
Chief Operating Officer Vice President, Exploration
Donald G. McLean John Devlin
Vice President, Finance & CFO Controller
----------------------------------------------------------------------------
Directors
Matthew J. Brister (1) (2) Brian Lavergne
CEO
John A. Brussa (3)
Gregory G. Turnbull (3)
Mark Butler (3) Corporate Secretary
Stuart G. Clark (1)
Chairman P.Grant Wierzba (2)
Jim Wilson (1)
(1) Member, Audit Committee (2) Member, Reserves Committee (3) Member,
Compensation, Governance and Nomination Committee
Mr. Henry Lawrie, a long-time director of the Company, Chairman of the Audit
Committee and member of the Reserves Committee, passed away on November 7, 2009.
Mr. Lawrie's contributions to the direction of the Company over the years, in
particular his focus on clarity and quality of public reporting and his capable
mentorship of staff, were invaluable. His enthusiasm and support will be greatly
missed.
----------------------------------------------------------------------------
Stock Exchange Listing Registrar & Transfer Agent
Toronto Stock Exchange Alliance Trust Company
Trading Symbol "SEO" Calgary, Alberta
Solicitors Executive Offices
McCarthy Tetrault LLP Suite 800, 205 - 5(th) Avenue S.W.
Burnet Duckworth & Palmer LLP Calgary, Alberta, T2P 2V7 Canada
Calgary, Alberta Tel: (403) 264-3520 Fax: (403) 264-3552
www.stormexploration.com
Auditors Bankers
PricewaterhouseCoopers LLP CIBC, Oil & Gas Group
Calgary, Alberta Bank of Montreal
Union Bank
Reserve Engineers ATB Financial
Calgary, Alberta
Paddock Lindstrom & Associates Ltd.
Calgary, Alberta
----------------------------------------------------------------------------
Abbreviations
3-D Three-dimensional
API American Petroleum Institute
Bbls Barrels of oil or natural gas liquids
Bbls/d Barrels per day
Bcf Billions of cubic feet
Bcfe Billions of cubic feet equivalent
Boe Barrels of oil equivalent
Boe/d Barrels of oil equivalent per day
Bopd Barrels of oil per day
Cdn$ Canadian dollar
DPIIP Discovered Petroleum Initially in Place
ETAP Entreprise Tunisienne d'Activites Petrolieres
FPSO Floating, Production, Storage, Offloading vessel
GJ Gigajoules
GJ/d Gigajoules per day
Mbbls Thousands of barrels
Mboe Thousands of barrels of oil equivalent
Mcf Thousands of cubic feet
Mcf/d Thousands of cubic feet per day
Mmbbls Millions of barrels
Mmbtu Millions of British Thermal Units
Mmbtu/d Millions of British Thermal Units per day
Mmcf Millions of cubic feet
Mmcf/d Millions of cubic feet per day
Mstb Thousand stock tank barrels
NAV Net Asset Value
NGL Natural gas liquids
NPV Net present value
OGIP Original Gas in Place
OPEC Organization of Petroleum Exporting Countries
Scf/ton Standard cubic foot per ton
STOOIP Stock Tank Original Oil in Place
Tcf Trillions of cubic feet
TSX Toronto Stock Exchange
US$ United States dollar
WTI West Texas Intermediate
----------------------------------------------------------------------------
Annual Meeting
The Annual General Meeting of Shareholders will be held at 3:30 p.m. on
Thursday, May 13, 2010 in the TELUS 108/109 rooms, Calgary TELUS Convention
Centre, 136 Eighth Avenue S.E., Calgary, Alberta. All shareholders and invited
guests are encouraged to attend.
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