Storm Exploration Inc. (TSX:SEO)
Three Three Six Six
Highlights - Months Months Months Months
Thousands of $CDN, to to to to
except volumetric and June 30, June 30, June 30, June 30,
per share amounts 2009 2008 2009 2008
----------------------------------------------------------------------------
Financial
Gas sales 14,026 29,547 (1) 35,633 55,788
NGL sales 2,028 3,239 3,904 5,628
Oil sales 3,097 (1) 5,906 5,972 (1) 11,051
Royalty income 47 196 114 395
----------------------------------------------
Production revenue 19,198 38,888 45,623 72,862
----------------------------------------------
Funds from operations (2) 8,460 23,250 22,180 42,768
Per share - basic ($) 0.18 0.52 0.48 0.96
Per share - diluted ($) 0.18 0.50 0.47 0.93
Net income (loss) (2,192) 9,465 (942) 15,889
Per share - basic ($) (0.05) 0.21 (0.02) 0.36
Per share - diluted ($) (0.05) 0.20 (0.02) 0.34
Capital expenditures, net of
dispositions 3,843 5,780 35,334 32,555
Debt, including working capital
deficiency 93,473 (3) 75,144 (3) 93,473 (3) 75,144
Weighted average common shares
outstanding (000s)
Basic 46,553 44,634 45,888 44,610
Diluted 47,637 46,179 46,959 46,101
Common shares outstanding
(000s)
Basic 46,554 44,657 46,554 44,657
Fully diluted 49,012 47,026 49,012 47,026
Operations
Oil equivalent (6:1)
Barrels of oil equivalent
(000s) 742 558 1,502 1,149
Barrels of oil equivalent per
day 8,153 6,130 8,296 6,315
Average selling price ($CDN
per BOE) 25.81 (1) 69.36 (1) 30.31 (1) 63.05
Gas production
Thousand cubic feet (000s) 3,839 2,893 7,752 5,943
Thousand cubic feet per day 42,185 31,786 42,831 32,656
Average selling price ($CDN
per mcf) 3.65 10.22 (1) 4.60 9.39
NGL Production
Barrels (000s) 49 28 97 59
Barrels per day 533 313 538 323
Average selling price ($CDN
per barrel) 41.77 113.64 40.11 95.69
Oil Production
Barrels (000s) 54 47 112 100
Barrels per day 589 519 620 549
Average selling price ($CDN
per barrel) 57.76 (1) 124.97 53.22 (1) 110.56
Wells drilled
Gross 0.0 0.0 4.0 11.0
Net 0.0 0.0 2.8 10.1
(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
HIGHLIGHTS for the Quarter Ended June 30, 2009
- Production increased to 8,153 Boe per day, a 33% increase from production of
6,130 Boe per day in the same period one year ago. This is a per share increase
of 28% using basic shares outstanding at quarter end. Approximately 600 Boe per
day was shut-in or curtailed for economic reasons during the quarter and another
120 Boe per day was shut-in as a result of the scheduled maintenance turnaround
of the Ft Nelson Gas Plant in June. Start-up of two new Montney horizontal wells
at Parkland was delayed until later in the second quarter with both currently
producing a total of 1,600 Boe per day (net).
- Activity during the quarter was low due to road use restrictions imposed every
spring (road bans) that prevent mobilization of rigs until late June and, also
as a result of reducing activity levels in response to the decline in natural
gas prices which has reduced cash flow available for re-investment. No wells
were drilled or completed in the second quarter.
- Cash flow for the quarter was $8.5 million or $0.18 per diluted share, a
decrease of 64% from $0.50 per diluted share in the prior year second quarter.
Not surprisingly, this was the result of lower commodity prices with the
year-over-year decline of 65% in the per Boe sales price more than offsetting
28% growth in production per share.
- The second quarter cash flow netback of $11.40 per Boe represents a decline of
73% from the cash flow netback of $41.69 per Boe in the year earlier period and,
again, this was due to the 63% decline in the per Boe sales price over the same
period. Total cash costs including operating expense, interest expense,
transportation costs, and general and administrative averaged $9.95 per Boe in
the quarter representing a 22% decline from the year earlier period which did
offset some of the commodity price decline. Notably, operating costs were $5.61
per Boe in the quarter, a decline of 21% from the previous year.
- Storm incurred a net loss for the quarter of $2.2 million, or a loss of $0.05
per diluted share which represents the first quarterly loss since we commenced
operations five years ago. This has been and continues to be a challenging and
very difficult business environment. Charges for depletion, depreciation and
accretion at $14.43 per Boe were 16% lower year over year but, this improvement
was more than offset by the decline in commodity prices over the same period.
- Capital investment totaled $3.8 million in the quarter, leaving bank debt and
working capital deficiency at $93.5 million or 2.8 times annualized second
quarter cash flow. Year over year, total debt has increased by 24% which is in
proportion to production per share growth of 28%.
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 6,016 Boe per day in the second quarter.
During the quarter, approximately 500 Boe per day was shut in or curtailed due
to low natural gas prices. Current production is approximately 6,100 Boe per day
with 500 Boe per day shut in.
During the second quarter, two Montney horizontal wells at Parkland that were
completed and tied in during the first quarter, began producing in mid-May and
early June (both 100% working interest). Each is currently being produced at a
restricted rate of approximately 4.5 Mmcf per day which represents 800 Boe per
day of net sales per well. Planned activity at Parkland over the remainder of
the year includes drilling three horizontal development wells (2.4 net) in our
Montney discovery, three vertical Montney step-outs (3.0 net), and one
exploratory Montney vertical well (1.0 net) to further evaluate a new pool
Montney lead.
Development of our Montney discovery continues to progress as expected. We are
currently producing about 27 Mmcf per day of gross raw gas from 14 horizontal
Montney gas wells plus 3 Mmcf per day of gross raw gas from 11 Montney vertical
wells. The first year average rate from our horizontal wells continues to be
approximately 2.3 Mmcf per day of raw gas, which represents 400 Boe per day of
sales gas per well.
Geological mapping suggests that our Montney discovery could be as large as 15
to 17 net sections. The 2008 year-end reserve evaluation completed by Paddock
Lindstrom & Associates Ltd. recognized an areal extent of 11 sections (7,040
acres) based on 13 successful vertical Montney gas wells. This resulted in
estimated Discovered Petroleum Initially in Place ("DPIIP") or gross Original
Gas in Place(1) ("OGIP") for our Montney discovery to be 409 Bcf. Estimated
DPIIP relies on a porosity cut-off of 6% on a sandstone scale which is somewhat
conservative in comparison to what is being used by other reserve evaluators in
the area. The areal extent of our discovery is likely to have increased by one
to two net sections based on results from the one successful vertical Montney
step-out we drilled in the first quarter and the recompletion of two suspended
wells in the first and third quarters. During the remainder of 2009, three
additional step-outs are planned in an effort to further expand the areal extent
of our Montney discovery.
In 2009, a total of $16 million has been budgeted to expand our infrastructure
at Parkland. In the first quarter, $4 million was invested in completing a
second facility which is currently capable of processing 12 Mmcf per day and has
been designed to be readily expandable to 50 Mmcf per day of capacity. Later
this year, we plan to expand this facility to 25 Mmcf per day of capacity and a
liquids extraction plant (refridge) will be added at an estimated cost of $12
million. We have started ordering and taking delivery of equipment and expect to
start construction in late October, with completion expected by early December.
The refridge plant is expected to result in liquids recoveries increasing from
16 to 45 barrels per Mmcf of sales gas which would increase liquids production
by 400 to 600 barrels per day and will add two to three million barrels of
natural gas liquids to our proven plus probable reserves (based on the DPIIP and
recoverable raw gas recognized in the 2008 year-end reserve evaluation).
In the second quarter, the field netback realized at our Parkland property was
$16.03 per Boe, production was 6,016 Boe per day (87.3% natural gas), and
operating costs were $3.93 per Boe.
1 When used in this press release, original gas in place ("OGIP") means
Discovered Petroleum Initially in Place which is defined in the COGEH handbook
as the quantity of hydrocarbons that are estimated to be in place within a known
accumulation. OGIP is used here as it is a more commonly used industry term when
referring to gas accumulations. Discovered Petroleum Initially in Place 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 Discovered Petroleum Initially in Place except for those
portions identified as proved or probable reserves.
Grande Prairie Area, North West Alberta
Production from this area averaged 1,470 Boe per day in the second quarter which
is a decline of 17% from production of 1,773 Boe per day in the year earlier
period. Approximately 100 Boe per day was shut in during the quarter due to low
natural gas prices. Current production is approximately 1,400 Boe per day with
100 Boe per day still shut in. Third quarter production from this area is
expected to be reduced by approximately 100 Boe per day as result of planned
facility maintenance turnarounds in September. Declines from this area continue
to moderate which is indicative of the higher quality nature of this more mature
asset.
In order to benefit from Alberta`s recently announced royalty incentive
programs, we are planning to drill two locations (75% average working interest)
in the fourth quarter. Additional wells are likely to be drilled in 2010 to
further benefit from the royalty incentive programs. The locations are mainly
lower risk infills or twins of existing wells and the royalty incentive programs
will offset 50% to 75% of the cost to drill these wells.
Cabin-Kotcho-Junior Area, North East British Columbia
Net production from this area averaged 620 Boe per day in the second quarter, a
decline of 36% from the year earlier period. Production during the quarter was
affected by the scheduled 21 day maintenance shut-down of the Ft Nelson Gas
Plant which reduced production by 120 Boe per day for the quarter. Current
production is approximately 575 Boe per day and we have shut-in 150 Boe per day
due to low natural gas prices.
We are currently finalizing plans for a winter drilling program involving two to
four horizontal wells plus a small facility expansion to test the productivity
of the Jean Marie formation in the Junior area. Based on mapping and proximity
to offsetting producing Jean Marie horizontals, we have 33 net sections in the
area which have the greatest potential for development with horizontal wells.
Our estimated average 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 each horizontal well. Drilling density
would be one horizontal well per section.
Horn River Basin ("HRB"), North East British Columbia
Since early 2008, Storm has jointly acquired 64 gross sections of undeveloped
land in the HRB at a 40% working interest (16,400 net acres) prospective for
Devonian shale gas. This land position has been acquired at an average cost of
$400 per acre. The lands were purchased in partnership with Storm Gas Resource
Corp. ("SGR") which owns 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%.
In the first quarter, two vertical wells (60% SGR, 40% Storm) were drilled in
the HRB to prove the productivity of our lands. The first well was cored,
completed and flow tested in the Muskwa and Otter Park shales. Results were
encouraging but inconclusive in terms of determining the exploitation potential
with multi-stage frac horizontal wells. Both of the vertical test wells are
within a central project area encompassing 35 gross sections (14.0 net)
containing 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:
- average 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 per ton,
- the calculated adsorbed gas volume represents 45% of estimated DPIIP.
The Klua/Evie shale was not included in the DPIIP estimate because less
information is available regarding the productivity of this shale in the area.
The next step in advancing this play is drilling horizontal wells to obtain
production data (initial rates, declines, estimates of potential recoverable
reserves) as well as operational experience which we can then use in determining
the economic viability of larger scale exploitation with multi-stage frac
horizontal wells. We are currently estimating that the cost to drill a
horizontal well is $4 million with the cost of a 10 frac completion being $10
million. The completions may be done in the summer of 2010 in order to eliminate
the significant cost associated with storing large quantities of water in tanks
and heating them during the winter. Cost of drilling and completing horizontal
wells may be lower than this as part of a larger scale development program;
however, the actual cost reduction is difficult to quantify at this time given
that we have not yet drilled any horizontal wells in the HRB. The initial test
horizontals would potentially be tied in and producing early in 2011. We are
currently working with SGR to finalize plans for 2010 which will potentially
include drilling and completing one to two horizontal wells, completing the
second standing vertical well drilled last winter, drilling and coring one more
vertical delineation well, recording 3-D seismic, and constructing associated
roads, facilities, and pipelines. Initial estimates of the gross cost are
between $35 and $45 million (incurred between early 2010 and early 2011)
depending on the number of horizontal wells drilled and also completed. The
potential economic returns associated with full scale development of the HRB
shales are not expected to be known until after we have several months of
production history from the horizontal wells which is likely to be up to two
years in the future. This remains an early stage project with a high level of
associated economic risk.
STORM GAS RESOURCE CORP.
Storm Gas Resource Corp was formed in June 2007, to pursue unconventional gas
opportunities in the HRB and elsewhere. During 2008, SGR completed a private
equity issue and raised $38.2 million (net of share issue costs) at a price of
$6.50 per share. Storm's investment to date in SGR totals $6.2 million and our
share ownership position is 2.05 million shares, representing 22% ownership of
SGR. Currently, SGR's land position in the HRB totals 123 gross sections or 70
net sections.
Our investment in SGR and partnership in the HRB are at an early stage in terms
of information and results and we don't expect to have an indication regarding
upside potential for at least two to three years.
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 notional value of $28
million or $0.60 per fully diluted Storm share using the price of a rights
offering completed in August 2008 which was $6.25 per share. At the end of 2008,
SVI's independently reviewed proven plus probable reserves totaled 36.4 million
Boe. SVI is primarily focused on advancing three major development projects
including the Vulcan project in the North Sea with potentially 320 to 360 Bcf of
original gas in place, the Remada Sud light oil discovery in Tunisia with Stock
Tank Original Oil in Place ('STOOIP') independently estimated at 170 million
barrels in the Ordovician formation, and the Cosmos fallow discovery offshore
Tunisia with estimated STOOIP of 25 million barrels.
SVI's production averaged 12.9 Mmcf per day in the first quarter generating
field cash flow of Cdn$7.4 million with field cash flow for 2009 estimated to be
Cdn$26 million (before interest and general and administrative expenses).
Estimated field cash flow for 2009 is supported by a hedge on 5.9 Mmcf per day
with a floor price of $11.00 per Mcf. SVI ended the first quarter with cash of
Cdn$38 million and with Cdn$36 million drawn on a loan facility with the Royal
Bank of Scotland.
Early in the second quarter of 2009, SVI commenced an extended production test
of an Ordovician light oil discovery at Remada Sud in Tunisia which had been
drilled and completed early in 2008. Results to date are encouraging with the
well flowing 225 barrels per day of light oil at a 3% watercut. SVI is applying
to extend the test from 90 to 180 days and will submit a preliminary development
plan before year end for execution in 2010. This plan is expected to include a
3-D seismic survey and two additional appraisal/development wells to assess the
commercial potential of this discovery.
Three higher impact exploratory wells are expected to be drilled before the end
of 2009 with SVI being the operator of all three wells. Two are in Tunisia with
one being the Fushia prospect offshore in the Gulf of Hammamet targeting a 100
Mmbbl prospect (pay 38.75% and retain a 65% interest) and the other being
onshore targeting a 25 Mmbbl prospect in the Silurian Acacus formation on the
Jenein Centre block (pay 30% and retain a 65% interest). The third is the
Coriander prospect in the North Sea, which is part of the Vulcan project area
containing fallow discoveries and prospects with prospective gas in place
totaling 1 Tcf.
OUTLOOK
Storm's capital investment plan for 2009 is being reduced to reflect lower than
budgeted cash flow. Capital investment for the year will be reduced to $67
million which still includes $16 million to be invested in expanding our
infrastructure at Parkland. This will be funded primarily with cash flow which
is expected to total $45 to $50 million assuming average 2009 prices of $4.00
per GJ at AECO for natural gas and $56.00 per barrel for oil at Edmonton. The
equity issue completed in March funds the remainder, which allowed us to
complete the first quarter acquisition of a gross overriding royalty at Parkland
for $9 million and has also provided certainty on being able to fund the
addition of a refridge plant at Parkland to increase recovery of higher value
natural gas liquids. Our 2009 drilling program will now total 13 gross wells
(10.7 net). In the second half of 2009, we plan to drill three Montney
horizontal wells (2.4 net) at Parkland, four Montney verticals (4.0 net), and
two wells (1.5 net) in the Grande Prairie area.
Guidance will be impacted by the reduction to capital investment and we now
expect exit production or production for the final quarter of 2009 to be
approximately 8,400 to 8,600 Boe per day, an increase of 5% over 2008 fourth
quarter production. This results in year over year production growth of 15% to
20% (average 2008 production was 6,975 Boe per day). Operating costs for the
remainder of 2009 are forecast to be $5.50 per Boe which is somewhat lower than
previous guidance as a result of shutting in higher cost wells and increased
production from our Parkland property. General and administrative costs for the
year are still expected to be $1.25 per Boe (unchanged) and the corporate
royalty rate, giving effect to the New Royalty Framework's effect on Alberta
production, is expected to average 19% in 2009 (down from our previous estimate
of 21%).
Our capital is expected to go a little further through the remainder of this
year with the cost of drilling and completing wells potentially declining by 10%
to 15% based on information available at this time. This is primarily the result
of lower steel costs, reductions in day rates for drilling rigs and reduced bid
levels on fracture treatments.
Corporate production is currently approximately 8,100 Boe per day with 750 Boe
per day shut in as a result of low natural gas prices. At current natural gas
prices, we expect to maintain corporate production at this level through the
third quarter.
In the current depressed natural gas price environment, our focus remains on
accretive growth in net asset value which will be accomplished by:
- shutting in higher cost wells or properties so that reserves are not produced
at a loss.
- drilling fewer horizontal Montney gas wells given that the increase in forward
strip pricing encourages us to defer drilling wells with high initial rates and
steep initial declines.
- continuing to drill Montney vertical step-outs which add horizontal locations
and new reserves but do not have a meaningful impact on production.
- advancing our knowledge of the HRB Devonian shale play by drilling multi-stage
frac horizontal wells as well as additional vertical delineation wells.
- testing the development potential of the Jean Marie formation on our large
land position in the Junior area.
This will impact production growth in the near term. Production growth will
remain subdued until natural gas prices recover to a level where an acceptable
economic return can be generated and where our cash flow is large enough to
support funding both a development program as well as growth initiatives
(approximately $5 per GJ at AECO). Given our control of infrastructure at
Parkland and inventory of horizontal Montney development locations which have
been defined with vertical well control, we expect to be able to rapidly
increase corporate production when the price of natural gas inevitably recovers.
At Parkland, considerable upside potential remains associated with:
- expanding the areal extent of our Montney discovery which could cover as many
as 15 to 17 net sections with up to 54 undrilled horizontal locations (four
horizontal wells per section) representing potential future production additions
of as much as 21,600 Boe per day.
- separate, new pool Montney leads on the 72 net sections of Montney rights that
we own which will be further tested with at least one vertical well this year
and we will also monitor the progress of competitors in the immediate area.
- recognizing a higher recovery factor and/or a lower porosity cut-off which
would increase DPIIP (gas in place) on our existing lands and potentially add to
the inventory of horizontal locations.
- Additional facility expansions to further increase recovery of natural gas
liquids ('NGLs').
Although reserves at Parkland have increased significantly over the last two
years, this is far from being a mature asset.
On August 6th, the Province of British Columbia announced an oil and gas
stimulus package to boost investment which included four royalty initiatives.
Three of these initiatives are expected to provide an immediate benefit to Storm
including:
- The two percent Royalty Relief Program which applies to the first 12 months of
production for wells spudded before the end of June 2010.
- The 15% increase in the royalty deductions available to wells that qualify for
the Deep Well Credit program.
- The qualification of horizontal wells drilled between 1,900 and 2,300 metres
of true vertical depth into the Deep Well Credit program which would include
most of the horizontal wells drilled in the Montney at Parkland.
The total benefit of all three initiatives amounts to approximately $1.0 to $1.2
million per Montney horizontal at Parkland using natural gas prices of $5.30 per
GJ (2010 futures price) to $6.15 per GJ (2011 futures price). This should
increase Storm's cash flow in both the short term (two percent Royalty Relief
Program) and long term (Deep Well Credit Program) which should correspondingly
allow us to increase our planned level of expenditures in British Columbia. For
example, instead of drilling nine horizontals at Parkland in 2010 (preliminary
plan), we should be able to fund the drilling of eleven horizontal wells. Any
additional wells we drill should increase employment in the short term and
should result in incremental growth in our natural gas production which, longer
term, provides the Province with additional royalty revenue. Thankfully, British
Columbia is willing to be realistic in their assessment of industry conditions
and is trying to ensure that their fiscal regime is fair and will also encourage
investment during the current difficult and challenging business environment.
Ultimately, we expect this to result in increased prosperity for British
Columbians as additional capital is invested in the Province with some of this
capital coming from the equity markets (investors will direct additional capital
into companies active in British Columbia) and some being attracted away from
areas with less favorable fiscal regimes (Alberta).
Natural gas prices remain at relatively depressed levels making it challenging
for us to fund growth in production from cash flow while also making a
significant investment in infrastructure at Parkland. Although production growth
is deferred in the short term, the additional investment in our infrastructure
at Parkland provides an immediate benefit in the form of increased production
and is also a key step in our efforts to maximize the future economic value of
this important asset. Despite the current difficult environment, we are very
optimistic about our future growth potential given the high quality of our asset
base, which contains several years of low risk development opportunities as well
as exposure to what could potentially be a very high impact gas project in the
HRB. Our low cost structure does leave us with more flexibility than most and we
do expect to show accretive growth in net asset value this year.
Sincerely,
Brian Lavergne, President and Chief Executive Officer
August 13, 2009
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL AND OPERATING RESULTS FOR THE
THREE AND SIX MONTHS ENDED JUNE 30, 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 and six months ended June 30, 2009. It should be read in conjunction with
the unaudited consolidated financial statements for the three and six months
ended June 30, 2009, the audited consolidated statements for the year ended
December 31, 2008 and other operating and financial information included in this
press release. 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 August 13, 2009.
Introduction and Limitations:
Basis of Presentation - Financial data presented below have largely been derived
from the Company's unaudited consolidated financial statements for the three and
six months ended June 30, 2009, prepared in accordance with Canadian Generally
Accepted Accounting Principles ("GAAP"). Accounting policies adopted by the
Company are set out in footnote 2 to the unaudited consolidated financial
statements for the three and six months ended June 30, 2009 and in footnote 2 to
the Company's audited consolidated financial statements for the year ended
December 31, 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 capital expenditures and their allocation to 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 by which certain areas will be developed; and
- changes to any of the foregoing.
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 "Field
Netback", "Interest" and "General and Administrative Costs"; under the
"Investment and Financing" section hereof, under the headings "Bank Debt,
Liquidity and Capital Resources"; and "Asset Retirement Obligation"; 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, either in this document or in the Company's MD&A contained
in its annual report for the year ended December 31, 2008. All of these caveats
should be considered in the context of current economic conditions, in
particular reduced commodity prices and the distressed 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 in the press release
dated August 13, 2009 this MD&A forms part of. 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", and "netbacks" 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. Funds from operations is also
used to determine leverage 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:
----------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
to to to to
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Cash flow from operating
activities $ 9,092 $ 24,890 $ 23,725 $ 41,770
----------------------------------------------------------------------------
Net change in non-cash working
capital items (632) (1,640) (1,545) 998
----------------------------------------------------------------------------
----------------------------------------
Funds from operations $ 8,460 $ 23,250 $ 22,180 $ 42,768
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATIONAL AND FINANCIAL RESULTS
PRODUCTION AND REVENUE
Average Daily Production
----------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
to to to to
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Natural gas (Mcf/d) 42,185 31,786 42,831 32,656
----------------------------------------------------------------------------
Natural gas liquids (Bbls/d) 533 313 538 323
----------------------------------------------------------------------------
Crude oil (Bbls/d) 589 519 620 549
----------------------------------------------------------------------------
Total (Boe/d) 8,153 6,130 8,296 6,315
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Boe production in the second quarter of 2009 increased by 33% when
compared to the same quarter in 2008 and fell by 3% when compared to the first
quarter of 2009. The year-over-year production increase is largely attributable
to increased gas production from the Company's core Parkland area. Within the
Parkland area, Montney gas production approximated 5,000 Boe per day in the
second quarter of 2009, compared to 2,000 Boe in the same quarter of 2008.
Production, averaging 700 Boe per day, was shut in during the second quarter of
2009 due to low natural gas prices. Additional production may be shut in if
product prices continue to fall. Year-to-date, production shut in has averaged
500 Boe.
Production per million shares outstanding in the second quarter of 2009 averaged
175 Boe per day, compared to 137 Boe per day for the second quarter of 2008, an
increase of 28%.
For the six months ended June 30, 2009 production increased by 31% when compared
to the equivalent period in 2008, or an increase of 28% per million shares
outstanding for each period.
Production Profile and Per Unit Prices
----------------------------------------------------------------------------
Three Months to June 30, Three Months to June 30,
2009 2008
----------------------------------------------------------------------------
Average Selling Average Selling
Percentage Price Before Percentage Price Before
of Total Boe Transportation of Total Boe Transportation
Production Costs Production Costs
----------------------------------------------------------------------------
Natural gas
- Mcf 86% $ 3.65 86% $ 10.49
----------------------------------------------------------------------------
Natural gas
liquids - Bbl 7% $ 41.77 5% $ 113.64
----------------------------------------------------------------------------
Crude oil - Bbl 7% $ 63.63 9% $ 124.97
----------------------------------------------------------------------------
Per Boe $ 26.23 $ 70.80
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six Months to June 30, 2009 Six Months to June 30, 2008
----------------------------------------------------------------------------
Average Selling Average Selling
Percentage Price Before Percentage Price Before
of Total Boe Transportation of Total Boe Transportation
Production Costs Production Costs
----------------------------------------------------------------------------
Natural gas
- Mcf 86% $ 4.60 86% $ 9.53
----------------------------------------------------------------------------
Natural gas
liquids - Bbl 7% $ 40.11 5% $ 95.69
----------------------------------------------------------------------------
Crude oil - Bbl 7% $ 56.49 9% $ 110.56
----------------------------------------------------------------------------
Per Boe $ 30.55 $ 63.75
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 both Alberta and British Columbia is sold at prices
which reflect both AECO daily index pricing and Station 2 daily index pricing.
The average AECO daily index price for the second quarter of 2009 was $3.27 per
GJ, compared to $9.67 per GJ for the second quarter of 2008, a year-over-year
reduction of 66%. Compared to $4.67 per GJ for the first quarter of 2009, second
quarter pricing was lower by 30%. In addition, for the second quarter of 2009
the average Station 2 daily index price, which applied to approximately 60% of
Storm's gas production in the quarter, was 7% lower than the average AECO daily
index price. Storm's corporate average realized price for natural gas for the
second quarter of 2009 was approximately 12% higher than the AECO daily index
price. This pricing premium is attributable to high heat content natural gas
delivered from the Montney formation at Parkland. In addition to superior heat
content, Montney natural gas has a natural gas liquids content of approximately
16 barrels per Mmcf, which has resulted in an approximate 70% increase in
natural gas liquids production in 2009 over 2008.
Production by Area - Boe per Day
----------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
to to to to
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Fort St John/Parkland - BC 6,016 3,333 6,060 3,422
----------------------------------------------------------------------------
Grande Prairie Area - AB 1,470 1,773 1,535 1,907
----------------------------------------------------------------------------
Cabin-Kotcho-Junior - BC 620 962 649 924
----------------------------------------------------------------------------
Other 47 62 52 62
----------------------------------------------------------------------------
Total 8,153 6,130 8,296 6,315
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The above sets out the average production from each of Storm's core areas. The
Company's focus on the Parkland area has resulted in 80% year-over-year
production growth from this area. Correspondingly, reduced investment in Alberta
is evidenced by an approximate 17% reduction in year-over-year production.
Production Revenue
----------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
to to to to
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Natural gas $ 14,026 $ 30,349 $ 35,633 $ 56,590
----------------------------------------------------------------------------
Natural gas liquids 2,028 3,239 3,904 5,628
----------------------------------------------------------------------------
Crude oil 3,412 5,906 6,339 11,051
----------------------------------------------------------------------------
Hedging losses (315) (802) (367) (802)
----------------------------------------------------------------------------
Revenue from product sales 19,151 38,692 45,509 72,467
----------------------------------------------------------------------------
Royalty income 47 196 114 395
----------------------------------------------------------------------------
Total production revenue $ 19,198 $ 38,888 $ 45,623 $ 72,862
----------------------------------------------------------------------------
----------------------------------------------------------------------------
A reconciliation of revenue from product sales between the quarters ended
June 30, 2009 and 2008 is as follows:
----------------------------------------------------------------------------
Natural
Natural Gas Crude
Gas Liquids Oil Total
----------------------------------------------------------------------------
Revenue from product sales - second
quarter 2008 $29,547 3,239 5,906 $ 38,692
----------------------------------------------------------------------------
Contribution from increased
production 9,920 2,278 798 12,996
----------------------------------------------------------------------------
Effect of reduced product prices (26,243) (3,489) (3,292) (33,024)
----------------------------------------------------------------------------
Gain (loss) from hedging activities 802 - (315) 487
----------------------------------------------------------------------------
Revenue from product sales - second
quarter 2009 $14,026 2,028 3,097 $ 19,151
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The collapse in revenues for 2009 is largely due to the fall in natural gas
prices. Using December 2008 as a baseline value, AECO daily index prices in 2009
have been as follows:
----------------------------------------------------------------------------
Month Average Index Price Month Average Index Price
----------------------------------------------------------------------------
December 100 April 56
----------------------------------------------------------------------------
January 91 May 58
----------------------------------------------------------------------------
February 75 June 49
----------------------------------------------------------------------------
March 66 July 46
----------------------------------------------------------------------------
Hedging
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. During the
three and six month periods to June 30, 2009, the Company realized a hedging
loss of $0.3 million and $0.4 million, respectively. At June 30, 2009 the
Company had an unrealized mark-to-market loss of $1.1 million on these
derivative contracts.
ROYALTIES
----------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
to to to to
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Charge for period $ 3,360 $ 8,504 $ 8,613 $ 15,406
Royalties as a percentage of revenue
from product sales before royalties
- Crown 16.9% 20.3% 18.5% 20.1%
- Other 0.4% 1.2% 0.3% 1.1%
----------------------------------------------------------------------------
Total 17.3% 21.5% 18.8% 21.2%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Per Boe $ 4.53 $ 15.24 $ 5.74 $ 13.40
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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, in part, 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.
PRODUCTION COSTS
----------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
to to to to
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Charge for period $ 4,160 $ 3,978 $ 8,621 $ 8,426
----------------------------------------------------------------------------
Percentage of revenue from product
sales before hedging 21.4% 10.1% 18.8% 11.5%
----------------------------------------------------------------------------
Per Boe $ 5.61 $ 7.13 $ 5.74 $ 7.33
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Although production grew by more than 30% year-over-year for both the three and
six months ended June 30, 2009, cost reduction initiatives and increasing
volumes of lower operating cost natural gas from the Company's Parkland property
resulted in only modest increases in total production costs. Per Boe, the effect
was to reduce costs by more than 20% in each of the three and six month periods.
Storm's cash costs per Boe, which comprise transportation, production, general
and administrative and interest costs, amounted to $9.95 for the second quarter
of 2009, compared to $9.81 for the first quarter of 2009 and to $12.78 for the
second quarter of 2008.
For the six month periods to June 30, per Boe cash costs amounted to $9.87 in
2009 and $12.77 in 2008.
TRANSPORTATION COSTS
----------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
to to to to
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Charge for period $ 1,125 $ 1,258 $ 2,527 $ 2,666
Percentage of revenue from product
sales before hedging 5.8% 3.2% 5.5% 3.6%
----------------------------------------------------------------------------
Per Boe $ 1.52 $ 2.26 $ 1.68 $ 2.32
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total transportation costs were largely the same over each of the comparative
periods above, in spite of production increases. Increased gas production from
the Parkland area resulted in lower per unit costs year-over-year. Storm's low
per unit production and transportation costs reflects Storm's high level of
operatorship as well as facility control and ownership.
FIELD NETBACKS
Details of field netbacks per commodity unit are as follows:
----------------------------------------------------------------------------
Three Months to June 30, 2009
----------------------------------------------------------------------------
CrudeOil Natural Gas Natural Gas Total
($/Bbl) Liquids ($/Bbl) ($/Mcf) ($/Boe)
----------------------------------------------------------------------------
Product sales $ 63.63 $ 41.77 $ 3.65 $ 26.23
----------------------------------------------------------------------------
Hedging loss (5.87) - - (0.42)
----------------------------------------------------------------------------
Royalty income 0.17 0.07 0.01 0.07
----------------------------------------------------------------------------
Royalties (9.23) (9.65) (0.62) (4.53)
----------------------------------------------------------------------------
Production costs (1) (7.76) - (0.98) (5.61)
----------------------------------------------------------------------------
Transportation (5.36) (3.73) (0.17) (1.52)
----------------------------------------------------------------------------
Field netback $ 35.58 $ 28.46 $ 1.89 $ 14.22
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months to June 30, 2008
----------------------------------------------------------------------------
CrudeOil Natural Gas Natural Gas Total
($/Bbl) Liquids ($/Bbl) ($/Mcf) ($/Boe)
----------------------------------------------------------------------------
Product sales $ 124.97 $ 113.64 $ 10.49 $ 70.80
----------------------------------------------------------------------------
Hedging loss - - (0.27) (1.44)
----------------------------------------------------------------------------
Royalty income 0.79 0.43 0.04 0.35
----------------------------------------------------------------------------
Royalties (21.71) (25.42) (2.33) (15.24)
----------------------------------------------------------------------------
Production costs (1) (8.42) - (1.24) (7.13)
----------------------------------------------------------------------------
Transportation (5.87) (1.83) (0.32) (2.25)
----------------------------------------------------------------------------
Field netback $ 89.76 $ 86.82 $ 6.37 $ 45.09
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six Months to June 30, 2009
----------------------------------------------------------------------------
CrudeOil Natural Gas Natural Gas Total
($/Bbl) Liquids ($/Bbl) ($/Mcf) ($/Boe)
----------------------------------------------------------------------------
Product sales $ 56.49 $ 40.11 $ 4.60 $ 30.55
----------------------------------------------------------------------------
Hedging loss (3.27) - - (0.24)
----------------------------------------------------------------------------
Royalty income 0.14 0.08 0.01 0.08
----------------------------------------------------------------------------
Royalties (8.35) (9.22) (0.87) (5.74)
----------------------------------------------------------------------------
Production costs (1) (7.68) - (1.00) (5.74)
----------------------------------------------------------------------------
Transportation (5.20) (3.81) (0.20) (1.68)
----------------------------------------------------------------------------
Field netback $ 32.13 $ 27.16 $ 2.54 $ 17.23
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six Months to June 30, 2008
----------------------------------------------------------------------------
CrudeOil Natural Gas Natural Gas Total
($/Bbl) Liquids ($/Bbl) ($/Mcf) ($/Boe)
----------------------------------------------------------------------------
Product sales $ 110.56 $ 95.69 $ 9.53 $ 63.75
----------------------------------------------------------------------------
Hedging loss - (0.14) (0.70)
----------------------------------------------------------------------------
Royalty income 1.25 0.46 0.04 0.33
----------------------------------------------------------------------------
Royalties (18.08) (21.26) (2.06) (13.40)
----------------------------------------------------------------------------
Production costs (1) (8.43) - (1.28) (7.33)
----------------------------------------------------------------------------
Transportation (5.56) (2.66) (0.33) (2.32)
----------------------------------------------------------------------------
Field netback $ 79.74 $ 72.23 $ 5.76 $ 40.33
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Production costs for natural gas liquids are included with natural gas
costs.
Field netbacks for the second quarter of 2009 fell 68% year-over-year as a
result of a 63% reduction in per Boe revenue. Direct costs, principally
price-sensitive royalties, fell by 70% year-over-year, but the decline was
insufficient to offset the collapse in revenue. For the six months to June 30,
2009, field netbacks fell by 57% year-over-year. Storm will continue to shut in
production if individual wells are not providing a high enough economic return,
which may result in lower production levels in future quarters.
Based on an all-in proved plus probable finding cost for 2008 of $11.10, Storm's
recycle ratio (field netback divided by finding costs) for the second quarter of
2009 was 1.3.
INTEREST
----------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
to to to to
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Charge for period $ 824 $ 944 $ 1,402 $ 2,005
----------------------------------------------------------------------------
Per Boe $ 1.11 $ 1.69 $ 0.93 $ 1.74
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 has fallen year-over-year, the stamping fee payable by
the Company increased considerably upon the renewal of the Company's banking
agreement effective April 30, 2009. The consequence is that borrowing costs for
the second quarter of 2009 increased by 43% over borrowing costs for the first
quarter of the year, with similarly increased borrowing costs expected for the
remainder of 2009.
GENERAL AND ADMINISTRATIVE COSTS
Total costs:
----------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
to to to to
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Gross general and administrative
costs $ 1,436 $ 1,397 $ 3,305 $ 2,755
----------------------------------------------------------------------------
Capital and operating recoveries (167) (443) (1,025) (1,164)
----------------------------------------------------------------------------
Net general and administrative
costs $ 1,269 $ 954 $ 2,280 $ 1,591
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Costs per Boe:
----------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
to to to to
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Gross general and administrative
costs $ 1.94 $ 2.50 $ 2.20 $ 2.40
----------------------------------------------------------------------------
Capital and operating recoveries (0.23) (0.79) (0.68) (1.02)
----------------------------------------------------------------------------
Net general and administrative
costs $ 1.71 $ 1.71 $ 1.52 $ 1.38
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Increases in gross general and administrative costs for the quarter and six
months ended June 30, 2009, when compared to the prior year, were primarily due
to an increased staff count, as well as higher year-over-year compensation.
Seasonally lower field activity in the second quarter of each year, particularly
in 2009, results in lower capital recoveries. Net general and administrative
costs per Boe for the three and six months to June 30, 2009 are higher, due to
the effect of lower year-over-year recoveries.
Storm does not capitalize general and administrative costs. General and
administrative costs per Boe for future quarters should be lower, due to higher
capital and operating recoveries.
STOCK BASED COMPENSATION COSTS
----------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
to to to to
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Charge for period $ 405 $ 395 $ 801 $ 731
----------------------------------------------------------------------------
Per Boe $ 0.55 $ 0.71 $ 0.53 $ 0.64
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 in the second quarter
and for the first half of 2009, when compared to the prior year, relates to the
issue of additional stock options to new employees in 2008.
DEPLETION DEPRECIATION AND ACCRETION
----------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
to to to to
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Depreciation and depletion charge
for period $ 10,587 $ 9,470 $ 21,754 $ 19,527
----------------------------------------------------------------------------
Accretion charge for period 122 123 241 244
----------------------------------------------------------------------------
Total $ 10,709 $ 9,593 $ 21,995 $ 19,771
----------------------------------------------------------------------------
Total per Boe $ 14.43 $ 17.20 $ 14.65 $ 17.20
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The increase in the total charge for depletion, depreciation and accretion for
the second quarter and first half of 2009 compared to the equivalent period in
the prior year, is a consequence of higher production volumes.
The decrease in the charge for depletion and depreciation per Boe for the second
quarter and first half of 2009 when compared to the equivalent periods of 2008
is approximately 16%. The reduction is attributable to proved oil and gas
reserves being added, effective January 1, 2009, at a cost considerably lower
than in 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%.
INCOME AND OTHER TAXES
For the three months ended June 30, 2009, Storm recorded a recovery of future
income taxes of $0.9 million compared to a provision for future income taxes of
$3.8 million for the quarter ended June 30, 2008. For the six month periods
ended June 30, 2009 the future income tax recovery amounted to $0.8 million
compared to a future income tax provision of $6.4 million for the same period of
2008. Deferral of taxes to future periods largely results from resource pool
deductions exceeding the accounting charge for depletion, depreciation and
accretion. The statutory combined federal and provincial rate applicable to
income in 2009 is 29%, compared to 30% for 2008.
At June 30, 2009, Storm had tax pools carried forward estimated to be $216
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 $2.2 million for the quarter ended June 30,
2009, compared to net income of $9.5 million for the quarter ended June 30,
2008. Net income for the first quarter of 2009 amounted to $1.3 million. For the
six months ended June 30, 2009 the net loss amounted to $0.9 million compared to
net income of $15.9 million for the same period in the prior year.
----------------------------------------------------------------------------
Three Months to Three Months to Six Months to Six Months to
June 30, 2009 June 30, 2008 June 30, 2009 June 30, 2008
----------------------------------------------------------------
Per Per Per Per
diluted diluted diluted diluted
share share share share
----------------------------------------------------------------------------
Net income
(loss) $(2,192) $(0.05) $ 9,465 $0.20 $(942) $(0.02) $15,889 $0.34
----------------------------------------------------------------------------
NON-GAAP FUNDS FROM OPERATIONS AND FUNDS FROM OPERATIONS PER SHARE
----------------------------------------------------------------------------
Three Months to Three Months to Six Months to Six Months to
June 30, 2009 June 30, 2008 June 30, 2009 June 30, 2008
-----------------------------------------------------------------
Per Per Per Per
diluted diluted diluted diluted
share share- share- share-
----------------------------------------------------------------------------
Funds from
operations $8,460 $ 0.18 $ 23,250 $0.50 $ 22,180 $0.47 $ 42,768 $0.93
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 cash flow to debt ratios, which
determines stamping fees 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
----------------------------------------------------------------------------
Three Months to Three Months to Six Months to Six Months to
June 30, 2009 June 30, 2008 June 30, 2009 June 30, 2008
-----------------------------------------------------------------
Per Per Per Per
diluted diluted diluted diluted
share- share- share- share-
----------------------------------------------------------------------------
Cash flows
from
operating
activities $ 9,092 $ 0.19 $ 24,890 $0.54 $ 23,725 $0.51 $ 41,770 $0.91
----------------------------------------------------------------------------
----------------------------------------------------------------------------
INVESTMENT AND FINANCING
Working Capital
Receivables comprise production revenue receivables and accruals, and
receivables in respect of operating and capital costs. Prepaid and other costs
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 provision, Storm had a working
capital deficiency of $1.5 million at June 30, 2009, compared to $8.7 million at
June 30, 2008 and $16.9 million at December 31, 2008. The working capital
deficiency at each period end reflects the Company's preference to act as
operator and the seasonality of its field operations. The Company's working
capital deficiency is cyclical and is highest at the end of the first quarter of
each year and lowest at the end of second quarter.
Capital Expenditures
Capital costs incurred were as follows:
----------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
to to to to
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Land and lease, net 1,013 1,004 1,819 2,697
----------------------------------------------------------------------------
Seismic 478 23 1,142 23
----------------------------------------------------------------------------
Drilling and completions 571 6,936 16,373 27,843
----------------------------------------------------------------------------
Facilities and equipment 1,651 1,929 8,417 4,887
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Field expenditures 3,713 9,892 27,751 35,450
----------------------------------------------------------------------------
Property acquisitions 130 - 9,145 528
----------------------------------------------------------------------------
Property dispositions - (1,061) (1,562) (2,653)
----------------------------------------------------------------------------
Royalty recoveries - (3,051) - (770)
----------------------------------------------------------------------------
Total 3,843 5,780 35,334 32,555
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Bank Debt, Liquidity and Capital Resources
Storm has a revolving borrowing base bank credit facility which is renewable
annually. The facility was renewed effective May 1, 2009 and resulted in the
facility increasing from $110 million to $120 million. The amount drawn on the
facility at June 30, 2009 amounted to $91.9 million, or 77% of the available
facility. Total debt, including working capital deficiency (less unrealized
financial instrument losses), amounted to $93.5 million at June 30, 2009,
resulting in a ratio of debt to annualized funds from operations for the first
half of 2009 of 2.1 times.
The Company normally funds its borrowing by drawing bankers' acceptances plus a
stamping fee. The renewed banking facility included a large increase in stamping
fees, standby fees and other costs. Nevertheless, year-over-year, the core
bankers' acceptance rate has fallen considerably, such that year-over-year total
borrowing costs have fallen. 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 has severely reduced cash flows in 2009
resulting in reductions to the Company's capital programs and further reductions
may follow in the second half of 2009, in the absence of a material recovery in
commodity prices. 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 paid down 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:
----------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
to to to to
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Non-GAAP Funds from operations 8,460 23,250 22,180 42,768
----------------------------------------------------------------------------
Non cash working capital (11,460) (3,173) (15,354) (1,480)
----------------------------------------------------------------------------
Issue of common shares - net of
expenses (204) - 18,471 -
----------------------------------------------------------------------------
Issue of common shares - option
proceeds 172 575
----------------------------------------------------------------------------
Increase (decrease) in bank
indebtedness 7,047 (13,636) 10,037 (8,058)
----------------------------------------------------------------------------
Proceeds on property sales - 1,061 1,562 2,653
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash available for investment 3,843 7,674 36,896 36,458
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Field expenditures 3,713 6,841 27,751 34,680
----------------------------------------------------------------------------
Property acquisitions 130 - 9,145 528
----------------------------------------------------------------------------
Investment in Storm Gas Resource
Corp. - 833 - 1,250
----------------------------------------------------------------------------
------------------------------
Total cost of investment programs 3,843 7,674 36,896 36,458
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Investments
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. 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.
Storm's ownership position in SGR is 22%. Including the dilution gain, the
carrying amount of Storm's 2,050,000 common shares of SGR is $4.74 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 $6.19 million or $3.02 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 the three months and six months ended June 30, 2009 were $65,000 and
$130,000, respectively. No intercompany charges were applied in 2008.
Storm Ventures International Inc.
At June 30, 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 since inception of Storm being $4.25 million.
Future Income Taxes
Estimated future income taxes at June 30, 2009 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:
----------------------------------------------------------------------------
As at Maximum Annual
June 30, 2009 deduction
----------------------------------------------------------------------------
Canadian oil and gas property expense $90,343 10%
----------------------------------------------------------------------------
Canadian development expense 77,970 30%
----------------------------------------------------------------------------
Canadian exploration expense 4,073 100%
----------------------------------------------------------------------------
Undepreciated capital cost 41,511 20 - 100%
----------------------------------------------------------------------------
Other 2,389 7-20%
----------------------------------------------------------------------------
Total $216,286
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 December 31, 2008 and
June 30, 2009 comprise the present value of additional obligations accruing to
the Company as a result of field activity and acquisitions during the quarter,
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 As at and
for the three for the six As at and for
months ended months ended the year ended
June 30, 2009 June 30, 2009 December 31, 2008
----------------------------------------------------------------------------
Common shares outstanding
- end of period 46,554 46,554 44,703
----------------------------------------------------------------------------
Stock options 2,458 2,458 2,267
----------------------------------------------------------------------------
Fully diluted common shares
- end of period 49,012 49,012 46,970
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted average common
shares - basic 46,553 45,888 44,654
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted average common
shares - diluted 47,637 46,959 45,877
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Stock options outstanding are exercisable over five years on various dates
beginning September 2005 at prices ranging from $2.60 to $12.06.
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
- 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:
----------------------------------------------------------------------------
($000's) 2009 2010 2011 2012 2013
----------------------------------------------------------------------------
Lease of premises $ 406 $ 825 $ 838 $ 838 $ 419
----------------------------------------------------------------------------
Equipment leases 113 163 109 15 -
----------------------------------------------------------------------------
Gas transportation and
processing commitments 1,118 1,437 1,146 599 198
----------------------------------------------------------------------------
Total $ 1,636 $ 2,424 $ 2,092 $ 1,452 $ 617
----------------------------------------------------------------------------
----------------------------------------------------------------------------
QUARTERLY RESULTS
Summarized information by quarter for the two years ended June 30, 2009
appears below:
----------------------------------------------------------------------------
June March December September June March December September
Quarter 30, 31, 31, 30, 30, 31, 31, 30,
Ended 2009 2009 2008 2008 2008 2008 2007 2007
----------------------------------------------------------------------------
Production
revenue -
($000s) 19,198 26,425 35,447 40,215 38,888 33,974 25,553 19,573
----------------------------------------------------------------------------
Funds from
operations -
($000s)
Per share
($) 8,460 13,720 20,432 24,290 23,250 19,518 13,233 9,372
- basic 0.18 0.30 0.46 0.54 0.52 0.44 0.30 0.21
- diluted 0.18 0.30 0.45 0.53 0.50 0.43 0.30 0.20
----------------------------------------------------------------------------
Net income
(loss)-
($000s)
Per share
($) (2,192) 1.250 5,968 12,829 9,465 6,426 2,852 299
- basic (0.05) 0.03 0.13 0.28 0.21 0.14 0.06 0.01
- diluted (0.05) 0.03 0.13 0.28 0.20 0.14 0.06 0.01
----------------------------------------------------------------------------
Average daily
production -
Boe 8,153 8,441 8,161 7,107 6,130 6,500 5,992 5,618
----------------------------------------------------------------------------
Average field
netback -
($/Boe) 14.22 20.15 30.35 39.77 45.09 35.87 27.44 20.83
----------------------------------------------------------------------------
Capital
expenditures
net -
($000s) 3,843 31,491 35,342 27,057 5,780 26,775 17,094 19,953
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CRITICAL ACCOUNTING ESTIMATES
Financial amounts included in the Company's management's discussion and analysis
and in the unaudited consolidated financial statements for the three and six
months ended June 30, 2009 are based on accounting policies, estimates and
judgment which reflect information available to management at the time of
preparation. Information with respect to the accounting policies selected by the
Company and the use of estimates is set out in the Company's audited
consolidated financial statements for the year ended December 31, 2008 and the
unaudited consolidated financial statements for the three months and six months
ended June 30, 2009.
RISK ASSESSMENT
There are a number of risks facing participants in the Canadian oil and gas
industry. Some of the risks are common to all businesses while others are
specific to the sector and others are specific to Storm. Information with
respect to such risks is set out in the Company's annual report for the year
ended December 31, 2008
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 concluded such controls are effective.
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, 2008, 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 update
documentation and test the operating effectiveness of such controls. Based on
this evaluation and enquiries made since that date, the CEO and CFO conclude
that the design of ICFR is sufficiently effective as at June 30, 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.
No changes to internal controls were made and no circumstances suggesting a
possible breach of disclosure controls were identified in the quarter ended June
30, 2009.
Because of inherent limitations, disclosure controls and procedures and internal
controls over financial reporting cannot prevent or identify all
mismeasurements, errors and fraud.
INTERNATIONAL FINANCIAL REPORTING STANDARDS
The Canadian Institute of Chartered Accountants, the primary source for
accounting standards in Canada, proposes to implement International Financial
Reporting Standards ("IFRS") as part of Canadian GAAP. Such standards have been
established cooperatively by many countries and have widespread application to
financial reporting by businesses throughout the world. The adoption of IFRS in
Canada will result in major changes to GAAP in Canada and to financial reporting
practices followed by Storm. The effective date of introduction for IFRS is
proposed for company year ends beginning after December 31, 2010; thus, in the
case of Storm, the year ended December 31, 2011. However, the need to have
comparative information presented in accordance with IFRS for the year ended
December 31, 2010, requires that the Company's consolidated balance sheet at
January 1, 2010 be IFRS compliant, meaning that the Company must plan its
conversion considerably in advance of the proposed implementation date.
Currently, the application of IFRS to the oil and gas industry in Canada
requires considerable clarification: correspondingly, the effect of IFRS on the
Company's accounting policies and reporting standards and practices is not
presently determinable.
With respect to organizing for the changeover, the Company has recruited
appropriately qualified staff and has identified external resources to assist in
the process. Key elements of the changeover plan include: staff education;
choosing among policies permitted under IFRS; deciding whether certain changes
will be applied on a retroactive or prospective basis; evaluating the effect of
adoption on Storm's information technology and data systems and internal control
over financial reporting and disclosure controls and procedures; alignment of
internal and outsourced processes, applications and internal controls; external
and internal communications; and liason with peers, industry groups and
professional advisors.
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.
Storm Exploration Inc.
Consolidated Balance Sheets
($000s)
(UNAUDITED)
June 30, 2009 December 31, 2008
-----------------------------------
ASSETS
Current
Accounts receivable 7,142 14,274
Prepaid and other costs 4,744 2,916
-----------------------------------
11,886 17,190
Property and Equipment - Net (Note 3) 304,712 290,944
Investments (Note 4) 20,242 20,242
-----------------------------------
336,840 328,376
-----------------------------------
-----------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Accounts payable and accrued liabilities 13,418 34,076
Unrealized financial instrument provision
(Note 11) 1,092 -
-----------------------------------
4,510 34,076
Bank Indebtedness (Note 5) 91,941 81,904
Asset Retirement Obligation (Note 6) 7,688 7,259
Future Income Taxes (Note 7) 21,799 22,875
-----------------------------------
135,938 146,114
-----------------------------------
Shareholders' Equity (Note 8)
Share capital 106,793 88,013
Contributed surplus 4,782 3,980
Retained earnings 89,327 90,269
Accumulated other comprehensive income
(deficit) - -
-----------------------------------
200,902 182,262
-----------------------------------
Commitments (note 13)
-----------------------------------
336,840 328,376
-----------------------------------
-----------------------------------
Storm Exploration Inc.
Consolidated Statements of Income and Retained Earnings
($000s)
(UNAUDITED)
Three Three Six Six
Months to Months to Months to Months to
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
-----------------------------------------
Revenue
Production revenue 19,198 38,888 45,623 72,862
Unrealized loss on financial
instruments (note 11) (486) - (1,092) -
Royalties (3,360) (8,504) (8,613) (15,406)
-----------------------------------------
15,352 30,384 35,918 57,456
-----------------------------------------
Expenses
Production 4,160 3,978 8,621 8,426
Transportation 1,125 1,258 2,527 2,666
Interest 824 944 1,402 2,005
General and administrative 1,269 954 2,280 1,591
Stock based compensation 405 395 801 731
Depletion, depreciation and
accretion 10,709 9,593 21,995 19,771
-----------------------------------------
18,492 17,122 37,626 35,190
-----------------------------------------
Income (loss) before taxes: (3,140) 13,262 (1,708) 22,266
Future income taxes (Note 7) 948 (3,797) 766 (6,377)
-----------------------------------------
Net income (loss) for the period (2,192) 9,465 (942) 15,889
Retained earnings, beginning of
period 91,519 62,007 90,269 55,583
-----------------------------------------
Retained earnings, end of period 89,327 71,472 89,327 71,472
-----------------------------------------
-----------------------------------------
Net Income (loss) per share (Note 9)
- basic (0.05) 0.21 (0.02) 0.36
- diluted (0.05) 0.20 (0.02) 0.34
Storm Exploration Inc.
Consolidated Statements of Comprehensive Income (Loss)
($000s)
(UNAUDITED)
Three Three Six Six
Months to Months to Months to Months to
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------
Net Income (loss) for the period (2,192) 9,465 (942) 15,889
Reversal of unrealized hedging loss - (2,489) - (5,267)
Related income tax benefit - 802 - 1,580
----------------------------------------
Other comprehensive income (Note 11) - (1,687) - (3,687)
----------------------------------------
----------------------------------------
Comprehensive income (loss) for the
period (2,192) 7,778 (942) 12,202
----------------------------------------
----------------------------------------
Storm Exploration Inc.
Consolidated Statements of Cash Flows
($000s)
(UNAUDITED)
Three Three Six Six
Months to Months to Months to Months to
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
-----------------------------------------
Operating activities
Net income (loss) for the period (2,192) 9,465 (942) 15,889
Add non-cash items:
Depletion, depreciation and
accretion 10,709 9,593 21,995 19,771
Unrealized loss on financial
instruments (Note 11) 486 - 1,092 -
Future income tax (948) 3,797 (766) 6,377
Stock based compensation 405 395 801 731
-----------------------------------------
Funds from operations 8,460 23,250 22,180 42,768
Net change in non-cash working
capital items
(Note 10) 632 1,640 1,545 (998)
-----------------------------------------
9,092 24,890 23,725 41,770
-----------------------------------------
Financing activities
Issue of common shares - net of
expenses (204) 172 18,471 575
Increase (decrease) in bank
indebtedness 7,047 (13,636) 10,037 (8,058)
-----------------------------------------
6,843 (13,464) 28,508 (7,483)
-----------------------------------------
Investing activities
Increase in investments - (833) - (1,250)
Additions to property and equipment (3,843) (6,841) (36,896) (35,208)
Disposals of property and equipment - 1,061 1,562 2,653
Net change in non-cash working
capital items
(Note 10) (12,092) (4,813) (16,899) (482)
-----------------------------------------
(15,935) (11,426) (52,233) (34,287)
-----------------------------------------
Change in cash during the period - - - -
Cash, beginning of period - - - -
-----------------------------------------
Cash, end of period - - - -
-----------------------------------------
-----------------------------------------
STORM EXPLORATION INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
THREE AND SIX MONTHS ENDED JUNE 30, 2009 AND 2008
(UNAUDITED)
Tabular amounts in '000s, 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 interim unaudited consolidated financial statements have been prepared by
management in accordance with accounting principles generally accepted in Canada
("GAAP"), following the same accounting policies and methods of computation as
used in the audited consolidated financial statements for the year ended
December 31, 2008. The interim unaudited consolidated financial statement note
disclosures do not include all disclosures applicable for annual audited
financial statements. Accordingly, the interim unaudited consolidated financial
statements should be read in conjunction with the audited consolidated financial
statements and the notes thereto contained in the Company's annual report for
the year ended December 31, 2008.
FUTURE ACCOUNTING CHANGES
Convergence with International Financial Reporting Standards
Canada's Accounting Standards Board has confirmed January 1, 2011 as the
effective date for the convergence 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 that
will be addressed.
The Company has established a project group to review the adoption of IFRS and
its effect on financial reporting software, bank covenants, business contracts
and internal controls over financial reporting and to provide regular updates to
the Audit Committee.
3. PROPERTY AND EQUIPMENT
June 30, 2009 December 31, 2008
-----------------------------------
Property and equipment $ 445,916 $ 410,394
Accumulated depletion and depreciation (141,204) (119,450)
-----------------------------------
$ 304,712 $ 290,944
-----------------------------------
-----------------------------------
At June 30, 2009, the depletion calculation excluded unproved properties of
$24.9 million (December 31, 2008 - $23.3 million) and included future
development costs of $120.6 million (December 31, 2008 - $140.3 million).
4. INVESTMENTS
June 30, 2009 December 31, 2008
-----------------------------------
Investment in Storm Gas Resource Corp. $ 9,717 $ 9,717
Investment in Storm Ventures
International Inc. 10,525 10,525
-----------------------------------
$ 20,242 $ 20,242
-----------------------------------
-----------------------------------
The Company holds a 22% interest in a private company, Storm Gas Resource Corp.
and accounts for its holding using the equity method. Changes to the equity of
Storm Gas Resource Corp. for any of the reporting periods are not material to
the Company.
The Company also has a 6% interest in another private company, Storm Ventures
International Inc., which is accounted for using the cost method as the
ownership position does not meet the requirements for equity accounting.
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 $13.6 million
(December 31, 2008 - $13.0 million), which will be paid over the next 20-25
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 $7.7 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:
----------------------------------------------------------------------------
Six months ended Year ended
June 30, 2009 December 31, 2008
----------------------------------------------------------------------------
Asset retirement obligation, beginning
of period $ 7,259 $ 6,918
----------------------------------------------------------------------------
Liabilities incurred 254 108
----------------------------------------------------------------------------
Liabilities disposed (66) (255)
----------------------------------------------------------------------------
Accretion expense 241 488
----------------------------------------------------------------------------
Asset retirement obligation, end of
period $ 7,688 $ 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 $216 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:
Three Three Six Six
months to months to months to months to
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
------------------------------------------
Statutory combined federal and
provincial income tax rate 29% 30% 29% 30%
Expected income taxes $ (927) $ 3,992 $ (504) $ 6,704
Add (deduct) the income tax effect of:
Stock-based compensation 119 119 236 220
Rate adjustments (39) (316) (491) (550)
Other (101) 2 (7) 3
------------------------------------------
Future Income Tax $ (948) $ 3,797 $ (766) $ 6,377
------------------------------------------
------------------------------------------
The components of the future income tax liability are as follows:
June 30, 2009 December 31, 2008
-----------------------------------
Property and equipment $ 24,493 $ 25,331
Asset retirement obligation (2,076) (2,033)
Share issue costs (618) (423)
-----------------------------------
Future income tax liability $ 21,799 $ 22,875
-----------------------------------
-----------------------------------
8. 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, 2008 44,703 $ 88,013
Issuance of common shares (i) 1,850 19,610
Stock options exercised 1 8
Share issue costs (net of income tax benefit) (838)
-------------------------------
Balance as at June 30, 2009 46,554 $ 106,793
-------------------------------
-------------------------------
(1) 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.
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 June 30, 2009
are as follows:
----------------------------------------------------------------------------
Number of options Weighted Average
Exercise Price
Outstanding at December 31, 2008 2,267 $ 6.03
Issued during period 193 $ 11.85
Exercised during period (1) (8.27)
----------------------------------------------------------------------------
Outstanding at June 30, 2009 2,459 $ 6.48
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
$ 2.60 to $3.61 266 0.7 $ 3.33 266 $ 3.33
$ 3.91 to $5.71 1,299 1.8 $ 5.46 725 $ 5.35
$ 6.03 to $8.57 693 3.2 $ 8.06 197 $ 7.79
$ 9.62 to $12.06 201 4.6 $ 11.83 2 11.40
-----------------------------------------------------------
2,459 2.3 $ 6.48 1,190 $ 5.31
-----------------------------------------------------------
-----------------------------------------------------------
Using the Black-Scholes pricing model, the weighted average fair value of the
options granted to date in 2009 was estimated to be $3.70 (2008 - $8.68), using
risk-free interest rates of 2.5 %, volatility of 40% and an expected average
life 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.
9. PER SHARE AMOUNTS
Three Three Six Six
Months to Months to Months to Months to
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
------------------------------------------
Basic
Net income per share $ (0.05) $ 0.21 $ (0.02) $ 0.36
Weighted average number of
shares outstanding ('000) 46,553 44,634 45,888 44,610
Diluted
Net income per share $ (0.05) $ 0.20 $ (0.02) $ 0.34
Weighted average number of
shares outstanding ('000) 47,637 46,179 46,959 46,101
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
Three Three Six Six
months to months to months to months to
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
------------------------------------------
Accounts receivable $ 3,013 $ 3,086 $ 7,132 $ 665
Prepaid costs and deposits (1,556) (384) (1,827) (1,036)
Accounts payable and accrued
liabilities $ (12,917) $ (5,875) $(20,659) $ (1,109)
------------------------------------------
Change in non-cash working capital $ (11,460) $ (3,173) $(15,354) $ (1,480)
------------------------------------------
------------------------------------------
Relating to:
Financing activities $ - $ - $ - $ -
Investing activities (12,092) (4,813) (16,899) (482)
Operating activities 632 1,640 1,545 (998)
------------------------------------------
$ (11,460) $ (3,173) $(15,354) $ (1,480)
------------------------------------------
------------------------------------------
Interest paid during the period $ 824 $ 944 $ 1,402 $ 2,005
------------------------------------------
------------------------------------------
Income taxes paid during the period $ - $ - $ - $ -
------------------------------------------
------------------------------------------
11. FINANCIAL INSTRUMENTS
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, 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 are 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 recent widespread disruption of credit
markets, together with falling commodity prices, exposes 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 of 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 declines from existing properties. In certain
circumstances, usually 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.
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 have in the
past qualified 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, derivative instruments in
place during the first six months of 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 three and six months ended June 30, 2009, the Company realized losses on
financial instruments of $52,000 and 367,000, respectively (2008 - $nil) which
are offset against production revenues.
As at June 30, 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 $1.1 million for the six months ended June 30, 2009
is recognized in the financial statements as a current liability and a reduction
of revenue:
Volume Price Term
Costless Collars
350 Bbls/d $60.00 - $65.00 / Bbl July 1, 2009 - Sept 30, 2009
350 Bbls/d $60.00 - $70.00 / Bbl Oct 1, 2009 - Dec 31, 2009
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 June 30, 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 June 30, 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 June 30, 2009, the Company had no contracts
in place to reduce foreign exchange risk.
Sensivities
Using the Company's actual production volumes, royalty rates, income tax rates
and debt levels for the first half of 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 Change
in net in net
Change in income per Change in income per
Factor net income share net income share
----------------------------------------------------------------------------
$US 1.00/bbl change in the
price of WTI $146,000 $0.00 $ 93,000 $0.00
$0.10/mcf change in the price
of natural gas $460,000 $0.01 $329,000 $0.01
1% change in the interest rate $628,000 $0.01 $536,000 $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 somewhat 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:
----------------------------------------------------------------------------
As at and for the As at and for the
six months twelve months
ended ended
June 30, 2009 December 31, 2008
----------------------------------------------------------------------------
Current assets $ 11,886 $ 17,190
----------------------------------------------------------------------------
Accounts payable and accrued
liabilities 13,418 34,076
----------------------------------------------------------------------------
Working capital deficiency 1,532 16,886
----------------------------------------------------------------------------
Bank indebtedness 91,941 81,904
----------------------------------------------------------------------------
Net debt 93,473 98,790
----------------------------------------------------------------------------
Annualized funds from operations
for the period $ 44,360 $ 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 June 30, 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 cash flow 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.
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 on-going
business:
----------------------------------------------------------------------------
2009 2010 2011 2012 2013
----------------------------------------------------------------------------
Lease of premises $ 406 $ 825 $ 838 $ 838 $ 419
----------------------------------------------------------------------------
Equipment leases 113 163 109 15 -
----------------------------------------------------------------------------
Gas transportation and
processing commitments 1,118 1,437 1,146 599 198
----------------------------------------------------------------------------
Total $ 1,636 $ 2,425 $ 2,093 $ 1,452 $ 617
----------------------------------------------------------------------------
----------------------------------------------------------------------------
StorageVault Canada (TSX:SVI)
Historical Stock Chart
From Jun 2024 to Jul 2024
StorageVault Canada (TSX:SVI)
Historical Stock Chart
From Jul 2023 to Jul 2024
