Storm Exploration Inc. (TSX:SEO)
Consolidated Highlights
Three Months Three Months
Ended Ended
Thousands of Cdn$, except volumetric and per March 31, March 31,
share amounts 2010 2009
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FINANCIAL
Gas sales 20,475(1) 21,607
NGL sales 7,389 1,876
Oil sales 1,249(1) 2,269(1)
Royalty income 57 67
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Production revenue 29,170(1) 25,819(1)
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Funds from operations (2) 17,601 13,720
Per share - basic ($) 0.38 0.30
Per share - diluted ($) 0.37 0.30
Net income 3,040 1,250
Per share - basic ($) 0.06 0.03
Per share - diluted ($) 0.06 0.03
Capital expenditures, net of dispositions 36,839 31,491
Debt, including working capital deficiency 111,281(3) 97,886(3)
Weighted average common shares outstanding
(000s)
Basic 46,907 45,216
Diluted 47,649 46,260
Common shares outstanding (000s)
Basic 46,985 46,553
Fully diluted 49,910 48,973
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OPERATIONS
Oil equivalent (6:1)
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Barrels of oil equivalent (000s) 751 760
Barrels of oil equivalent per day 8,346 8,441
Average selling price (Cdn$ per Boe) 38.69(1) 34.70(1)
Gas production
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Thousand cubic feet (000s) 3,768 3,914
Thousand cubic feet per day 41,862 43,485
Average selling price (Cdn$ per Mcf) 5.43(1) 5.52
NGL Production
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Barrels (000s) 109 49
Barrels per day 1,207 542
Average selling price (Cdn$ per barrel) 68.02 38.46
Oil Production
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Barrels (000s) 15 59
Barrels per day 162 651
Average selling price (Cdn$ per barrel) 82.04(1) 49.06(1)
Wells drilled
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Gross 9.0 4.0
Net 7.7 2.8
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(1) Includes results of hedging activities.
(2) Funds from operations and funds from operations per share are non-GAAP
measurements. See MD&A.
(3) Excludes unrealized asset/liability related to financial instruments.
PRESIDENT'S MESSAGE
First Quarter 2010 Highlights
- Production in the first quarter averaged 8,346 Boe per day (16% oil and NGL),
a 1% decrease from production of 8,441 Boe per day (14% oil and NGL) in the same
period one year ago. Oil and NGL production, as a proportion of total
production, increased due to the start-up of a liquids extraction ("refridge")
plant at Parkland in mid-December 2009. As a result of our successful first
quarter drilling program, production in the second quarter is expected to
average 9,500 Boe per day.
- All nine wells drilled in the quarter were successful, resulting in nine gas
wells (7.7 net). This included one vertical well (1.0 net) and seven horizontal
wells (5.7 net) in our Montney discovery at Parkland. During the quarter, four
horizontal Montney wells (4.0 net) were completed and tied in.
- Cash flow for the quarter was $17.6 million or $0.37 per diluted share, an
increase of 23% from $0.30 per diluted share in the prior year first quarter.
The year-over-year increase in cash flow is due to a higher proportion of
liquids production plus lower operating costs and royalties. Both production and
natural gas prices were relatively unchanged.
- The first quarter cash flow netback of $23.43 per Boe represents an increase
of 30% from the cash flow netback of $18.05 per Boe in the year earlier period.
Although natural gas prices were similar to last year, the wellhead price per
Boe increased by $4.49 which was due to both higher oil and NGL production and
pricing. Total cash costs, which include production costs, interest,
transportation and general and administrative costs, declined by $0.41 per Boe
from the year earlier period to average $9.40 per Boe in the first quarter.
Notably, production costs were $4.78 per Boe in the quarter, a decline of 19%
from the previous year.
- Net income for the quarter was $3.0 million, or $0.06 per diluted share, an
increase of 100% from net income of $0.03 per diluted share in the prior year
period. Charges for depletion, depreciation and accretion, at $15.44 per Boe,
were 4% higher year over year.
- Capital investment totaled $36.8 million in the quarter, leaving bank debt and
working capital deficiency at $111.3 million, or 1.6 times annualized first
quarter cash flow. Storm's revolving bank credit facility was recently increased
from $120 million to $140 million.
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 6,794 Boe per day in the first quarter.
Production during the quarter was reduced by 250 Boe per day due to the failure
on Feb 12th of a fire tube in a process heater in the refridge plant at
Parkland. The fire tube was repaired by late February and, in early April, was
replaced in order to avoid this problem in the future. Current production from
this area is approximately 8,200 Boe per day with 8,000 Boe per day from the
Parkland property.
Most of our activity during the first quarter was focused on the Parkland property:
- Drilled one successful vertical Montney step-out well (1.0 net) which is
estimated to have expanded the proved plus probable reserve area by 1.0 to 1.5
net sections.
- Drilled six horizontal Montney wells (4.7 net) into the upper sands of the
Upper Montney formation, and completed and tied in three horizontal Montney
wells (3.0 net) in the upper sands. Production rates on the new horizontals
averaged 4.2 Mmcf/d of raw gas in the first 30 days of production. The remaining
three horizontals (1.7 net) will be completed in the second half of 2010.
- Drilled one horizontal Montney well (1.0 net) into the lower sands of the
Upper Montney formation. This well was completed with seven 50 ton fracs and
began producing April 15th at 2.5 Mmcf/d of raw gas with current production
being 1.1 Mmcf/d of raw gas.
- Expanded and debottlenecked the gathering system (invested $3.7 million) to
allow for future production growth and to maximize gas throughput and liquids
recovery at the 3-9 refridge plant.
In the second half of 2010, we are planning to drill six to nine horizontals
(6.0 to 7.1 net) in the Montney formation at our Parkland property. This will
include three earning horizontals on lands we farmed in on during the quarter,
plus a second horizontal into the lower sands. In addition to this, two more
vertical Montney step-outs (1.6 net) will be drilled as part of our focus on
expanding the proved plus probable reserve area.
The first horizontal in the lower sands of the Upper Montney formation was
drilled, completed with seven 50 ton fracs, and tied in for a total cost of $4.5
million. Pressure data from this horizontal and production monitoring of the
offsetting upper sands horizontal (100 metres away laterally), indicate that the
lower sands have not been drained. We anticipate drilling a second horizontal
into the lower sands in the third quarter, which will be completed with nine
larger 75 ton fracs to improve the production rate. No reserves have yet been
assigned to the lower sands.
There are currently 21 horizontal wells producing from our Montney discovery at
Parkland with first-year rates averaging approximately 2.4 Mmcf/d of raw gas
which represents 450 Boe per day of total sales per well. Production rates have
continued to improve as completions have evolved from five fracture treatments
on the early horizontals to nine fracture treatments on the most recent
horizontals. Fracture treatment size has remained constant at 125 tons of sand
per stage except on the first horizontal in the lower sands which was fractured
with 50 tons of sand per stage. The average cost to drill, complete and tie in a
horizontal well in the upper sands was approximately $5.5 million in the first
quarter.
During the first quarter, we entered into a farm-in agreement covering four
sections immediately adjacent to our existing lands with Storm earning a 60%
working interest in all four sections by paying 100% of the cost to drill,
complete, and tie in eight horizontal wells, and by paying 100% of the cost to
drill two vertical wells. All earning wells must be drilled before October 31,
2011. No reserves were assigned to these lands in the year-end reserve
evaluation. The first earning horizontal was drilled in the first quarter and
three more earning horizontals plus one earning vertical are planned for the
second half of 2010. Ultimately, this farm-in has the potential to add 15% to
20% to reserves assuming 16 horizontals are drilled in the upper sands (4
horizontals per section) and this is highly accretive to net asset value given
that the earning wells will be funded out of cash flow resulting in no equity
dilution.
The Montney formation at Parkland is 80 to 110 metres thick and is sub-divided
into the upper sands and the lower sands (see presentation on Storm's website
for type log illustration).
- In the upper sands, Discovered Petroleum Initially in Place ("DPIIP")(1) is
1,331 Bcf of gross raw gas (928 Bcf net to Storm) based on a productive area of
36.3 gross sections (23.5 net sections) which includes the farm-in lands
discussed above. Within the DPIIP area, proved plus probable reserves were
assigned to approximately half of the net area resulting in 29.5 net undrilled
horizontal locations in 11.7 net sections (37 gross undrilled horizontals in
13.5 gross sections) at four horizontals per section. The undrilled horizontals
were assigned an average of 4.3 Bcf of proved plus probable recoverable raw gas.
There is potential to add 47 net undrilled horizontals outside of the proved
plus probable area but, within the DPIIP area. Approximately two thirds of the
additional 47 net undrilled horizontals would be within one mile of the area
where proved plus probable reserves have been assigned.
- In the lower sands, no reserves have been booked. The lower sands have been
separately completed and tested in six vertical wells with final test rates
ranging from 0.2 to 1.7 Mmcf/d. The completed vertical wells show that an area
of 9.5 gross sections (7.8 net) is potentially productive with estimated net pay
of 22 to 37 metres (3% sandstone scale cut-off) and average porosity of 5.8%. At
four horizontals per section, there would be 31.2 net undrilled horizontals in
the lower sands within the 7.8 net sections currently known to be productive.
As a result of expanding our 3-9 facility in mid-December 2009, combined
capacity at our two Parkland facilities is now 53 Mmcf per day with current
throughput being 44 Mmcf per day of gross raw gas, or 40 Mmcf per day net sales
gas plus 1,450 net barrels per day of condensate and NGL. The refridge plant,
installed as part of the 3-9 facility expansion, has resulted in condensate and
NGL production increasing by 500 barrels per day and has reduced operating costs
by $2.8 million per year. In order to accommodate future growth, a further
expansion of our facility capacity will be required in 2011 with the timing and
cost to be determined over the next three to six months.
Financial results from our Parkland property showed further improvement in the
first quarter with an operating cost of $3.08 per Boe and a field netback of
$28.77 per Boe. Production averaged 6,604 Boe per day including 1,102 barrels
per day of condensate and NGL.
Discovered Petroleum Initially in Place ("DPIIP") - Is defined in the COGEH
handbook as the quantity of hydrocarbons that are estimated to be in place
within a known accumulation. Original Gas in Place ("OGIP") is a more commonly
used industry term when referring to gas accumulations. DPIIP is divided into
recoverable and unrecoverable portions, with the estimated future recoverable
portion classified as reserves and contingent resources. There is no certainty
that it will be economically viable or technically feasible to produce any
portion of this DPIIP except for those portions identified as proved or probable
reserves.
Grande Prairie Area, North West Alberta
Production from this area averaged 1,100 Boe per day in the first quarter and
current production is approximately 1,000 Boe per day.
Cabin-Kotcho-Junior Area, North East British Columbia
Net production from this area averaged 414 Boe per day in the first quarter and
current production is approximately 350 Boe per day.
In the Sahtahneh, or Junior area, Storm has 33 net sections which have potential
to be developed with horizontal wells in the Jean Marie formation. This is based
on mapping and proximity to offsetting horizontals which are producing from the
Jean Marie formation. Two horizontal locations have been licenced to test the
economics associated with larger scale development, and will be drilled when
Storm has sufficient discretionary cash flow available, which is primarily
dependent on natural gas prices. The estimated cost to drill, complete, and tie
in a horizontal well is expected to be $2.1 million and, based on offsetting
wells, first-year rates are expected to average 800 to 1,400 Mcf/d with 1.0 to
1.5 Bcf of recoverable raw gas per horizontal. Initial drilling density would be
one horizontal well per section.
Horn River Basin ("HRB"), North East British Columbia
Storm's undeveloped land position in the HRB is prospective for Devonian shale
gas in the Muskwa, Otter Park, and Evie/Klua formations and currently includes
87 gross sections at a 40% working interest (22,850 net acres), with Storm Gas
Resource Corp. ("SGR") owning the remaining 60% working interest. We added to
our land position in the first quarter by acquiring 12 gross sections (40%
working interest) for $100 per acre at Crown land sales. Our land position
combined with Storm's 22% equity ownership position in SGR, gives us 53%
exposure to this unconventional shale gas play.
We have identified a central project area encompassing 35 gross sections (14.0
net to Storm) which contains an estimated 2.6 Tcf of gross DPIIP in the Muskwa
and Otter Park shales (internal estimate prepared by Storm management). The
Evie/Klua shale interval was not included in the DPIIP estimate because less
information is available regarding the productivity of this shale in the area.
Our initial efforts are directed towards proving commerciality of the Muskwa and
Otter Park shales within this central project area.
During the first quarter, the second vertical well (60% SGR, 40% Storm), which
had been drilled the previous winter, was completed and tested. In addition, 60
square kilometres of 3-D seismic was recorded across the southern half of the
central project area and eight kilometers of high grade gravel roads plus two
drilling pads were constructed. Drilling of the third vertical delineation well,
which had been planned for the first quarter, was deferred due to difficulties
in sourcing a drilling rig and the early start to spring break-up.
We anticipate one horizontal well will be drilled this summer, with completion
planned for the fall. The estimated cost to drill a horizontal is expected to be
$4 million with the cost of completion estimated at $10 million for 12 fracture
stimulations. A pad for a second horizontal location has also been constructed
with drilling and completion being contingent on reviewing results from the
first horizontal well. First gas sales from successful horizontal wells is
possible in early 2011.
Storm expects to invest approximately $12 million net to our 40% working
interest in 2010 to advance the HRB shale project towards commerciality. It is
likely to be mid-2011 before we have enough production data from horizontal
wells to have an opinion as to the commerciality of the shales in our lands.
STORM GAS RESOURCE CORP.
Storm Gas Resource Corp. was formed in June 2007, to pursue unconventional gas
opportunities in the HRB and elsewhere. Storm's investment to date in SGR totals
$9.1 million and our share ownership position totals 2.5 million shares,
representing 22% ownership of SGR. Currently, SGR's land position in the HRB
totals 73 net sections. At the end of 2009, SGR's balance sheet showed a cash
position of $31 million.
STORM VENTURES INTERNATIONAL INC.
Storm owns 4.5 million shares of Storm Ventures International Inc. ("SVI"), a
Calgary-based, private energy company. SVI recently announced two significant
transactions:
1) In mid-March, SVI's United Kingdom North Sea assets were combined with Bridge
Energy Norge ASA ("Bridge"), a private company focused on exploration
opportunities in the Norwegian sector of the North Sea. The combined company has
production of approximately 1,500 Boe per day, several development opportunities
in the UK sector of the North Sea to pursue in the short term, and a number
exploratory leads in the Norwegian sector of the North Sea which offer
longer-term upside. At closing, SVI received 28,776,000 common shares of Bridge
which represents 80% of the 35,970,000 outstanding common shares. After closing,
Bridge completed a private placement of 16,225,000 shares priced at NOK 20 per
share, or approximately US $3.30 per share, which provided gross proceeds of
approximately US $54 million. Bridge has applied for a listing on the Oslo stock
exchange and, if the listing application is accepted, the Bridge shares received
by SVI will be distributed to SVI shareholders which will result in Storm
receiving approximately 1,050,000 common shares of Bridge.
2) On May 3rd, Iteration Energy Ltd. ("ITX") and SVI announced they had entered
into a definitive arrangement agreement to complete a strategic business
combination which would result in the creation of a growth oriented company
named Chinook Energy Inc. ("Chinook") with current production exceeding 20,000
Boe per day (33% liquids) and 83.4 million Boe of proved plus probable reserves.
A condition of the arrangement agreement is that the Toronto Stock Exchange
shall have approved, subject only to customary conditions, the listing of the
outstanding SVI shares and the SVI shares issuable pursuant to the arrangement
so that Chinook shall be a public company. ITX shareholders may elect to receive
either 0.5631 of a common share of SVI or $1.83 cash for each share of ITX held,
subject to a minimum cash component of $50 million and a maximum cash component
of $225 million. The arrangement contemplates a $3.25 per share value for SVI.
Chinook will combine high quality, gas weighted assets in Western Canada with
high impact exploration and development opportunities in Tunisia which have the
potential for material growth. In Western Canada, Chinook's production will be
19,900 Boe per day with 775,000 acres of undeveloped land. In Tunisia, Chinook
is producing 800 barrels per day of light oil with more than 1.4 million acres
of undeveloped land. Chinook is finalizing a $300 million credit facility which
would have $190 million to $225 million drawn, depending on the cash elections
made by ITX shareholders.
In the short term, Storm will retain its shares of Bridge for investment
purposes. Upon closing of the ITX transaction, Storm will review the
practicality and procedure to distribute its shares in Chinook and Bridge to
Storm's shareholders.
OUTLOOK
Guidance for 2010 is unchanged and includes:
- Capital investment of $85 million to $90 million with over 80% invested in the
Parkland area.
-Exit production or production for the final quarter of 2010 of approximately
9,500 to 9,800 Boe per day, an increase of more than 20% over 2009 fourth
quarter production.
- Operating costs for the year are forecast to be $4.50 per Boe.
- General and administrative costs for the year are expected to be $1.30 per Boe.
- The corporate royalty rate is expected to average 13% to 15% which includes
the effect of British Columbia's royalty incentive programs.
Cash flow in 2010 is estimated to be $70 million to $75 million assuming
commodity prices in the remainder of 2010 average $3.75 per GJ at AECO for
natural gas and Cdn $75.00 per barrel for oil at Edmonton.
To date in 2010, natural gas prices are approximately the same as in 2009 which
ended up being a very challenging year for Storm from a growth perspective given
the significant reduction in capital investment that was required to keep debt
at reasonable levels in relation to cash flow. This year, we are in a much
better financial position given:
1) hedges we've put in place to protect first half capital spending have an
unrealized mark-to-market gain of $6.5 million at the end of the first quarter;
2) the reduction in the qualifying depth for horizontals under the British
Columbia deep royalty credit program decreases the 2010 royalty payments by $4
to $5 million as compared to 2009;
3) increased oil and NGL production and pricing adds $11 million to cash flow
when comparing annualized first quarter results to full year 2009 results.
Our improved financial position means that we have more flexibility and, as a
result, we do not plan to reduce capital investment at this time. We will be
able to fund our capital investment program in 2010 with cash flow plus a small
amount of debt plus advance our HRB shale gas project, which has significant
longer-term upside, towards commerciality by drilling and completing a
horizontal well this summer.
The refridge plant at Parkland has resulted in a significant increase to oil and
NGL production with liquids recovery in the first quarter averaging 34 barrels
per Mmcf versus 25 barrels per Mmcf in 2009. The increased liquids production
has offset most of the recent weakness in natural gas prices with the rate of
return on our typical Montney horizontal being 41% at current futures prices
($3.92 per GJ AECO, Cdn $91 per barrel for light oil).
At Parkland, the potential growth associated with the upper and lower sands in
the Montney remains significant. Within the upper sands, there is potential for
as many as 76.5 net undrilled horizontal locations with only 29.5 net locations
recognized in the year-end reserve evaluation. In addition, in the lower sands,
there is potential for another 31.2 net horizontal locations in the 7.8 net
sections most likely to be productive based on vertical well control. With
potentially more than 100 net undrilled horizontal locations, there remains
significant upside associated with this asset.
Our focus remains on accretively growing net asset value and we will continue to
be patient in our hunt for new opportunities, given the opportunities for growth
offered by our existing high quality asset base which has low operating costs
and higher than average netbacks.
Sincerely,
Brian Lavergne,
President and Chief Executive Officer
May 11, 2010
Management's Discussion and Analysis
Set out below is management's discussion and analysis ("MD&A") of financial and
operating results for Storm Exploration Inc. ("Storm" or the "Company") for the
three months ended March 31, 2010. It should be read in conjunction with the
unaudited consolidated financial statements for the three months ended March 31,
2010, the audited consolidated financial statements for the year ended December
31, 2009 and other operating and financial information included in this report.
In addition, readers are directed to the discussion below regarding
Forward-Looking Statements, Boe Presentation and Non-GAAP Measurements.
This management's discussion and analysis is dated May 11, 2010.
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
months ended March 31, 2010, prepared in accordance with Canadian Generally
Accepted Accounting Principles ("GAAP"). Accounting policies adopted by the
Company are set out in Note 2 to the unaudited consolidated financial statements
for the three months ended March 31, 2010 and in Note 2 to the Company's audited
consolidated financial statements for the year ended December 31, 2009. The
reporting and the measurement currency is the Canadian dollar. Unless otherwise
indicated, tabular financial amounts, other than per share and per Boe amounts,
are in thousands.
Forward-Looking Statements - Certain information set forth in this document,
including management's assessment of Storm's future plans and operations,
contains forward-looking information (within the meaning of applicable Canadian
securities legislation). Such statements or information are generally
identifiable by words such as "anticipate", "believe", "intend", "plan",
"expect", "estimate", "budget", "outlook", "forecast" or other similar words and
include statements relating to or associated with individual wells, regions or
projects. Any statements regarding the following are forward-looking statements:
- future crude oil or natural gas prices;
- future production levels;
- future revenues or costs or revenues or costs per commodity unit;
- future capital expenditures and their allocation to specific exploration and
development activities;
- future drilling of new wells;
- future earnings;
- future asset acquisitions or dispositions;
- future sources of funding for capital program;
- future debt levels;
- availability of committed credit facilities;
- development plans;
- ultimate recoverability of reserves or resources;
- expected finding and development costs and operating costs;
- estimates on a per-share basis;
- dates or time periods by which certain geographical areas will be developed;
- changes to any of the foregoing; and
- the effect on financial reporting in future periods resulting from the
adoption of International Financial Reporting Standards on January 1, 2011.
Statements relating to "reserves" or "resources" are forward-looking statements,
as they involve the implied assessment, based on estimates and assumptions, that
the reserves and resources described exist in the quantities predicted or
estimated, and can be profitably produced in the future.
The forward-looking statements are subject to known and unknown risks and
uncertainties and other factors which may cause actual results, levels of
activity and achievements to differ materially from those expressed or implied
by such statements. Such factors include the material risks described in Storm's
Annual Information Form and as incorporated by reference in the December 31,
2009 MD&A under "Risk Assessment" and the material assumptions disclosed in the
"Production and Revenue" section hereof under the headings "Production Profile
and Per-Unit Prices" and "Royalties"; under "Production Costs"; "Field
Netbacks", "Interest", "General and Administrative Costs" and "Future Income
Taxes"; under the "Investment and Financing" section hereof, under the headings
"Working Capital", "Capital Expenditures", "Bank Debt, Liquidity and Capital
Resources", "Investments", "Future Income Taxes", "Asset Retirement Obligation",
"Share Capital" and "Contractual Obligations"; industry conditions, volatility
of commodity prices, currency fluctuations, imprecision of reserve estimates,
environmental risks, competition from other industry participants, the lack of
availability of qualified personnel or management, stock market volatility and
ability to access sufficient capital from internal and external sources. All of
these caveats should be considered in the context of current economic
conditions, in particular reduced commodity prices, which are outside the
control of the Company. Readers are advised that the assumptions used in the
preparation of such information, although considered reasonable at the time of
preparation, may prove to be imprecise and, as such, undue reliance should not
be placed on forward-looking statements. Storm's actual results, performance or
achievement, could differ materially from those expressed in, or implied by,
these forward-looking statements. Storm disclaims any intention or obligation to
publicly update or revise any forward-looking statements, whether as a result of
new information, future events or otherwise, except as required under securities
law. References to forward-looking information are made elsewhere in this
year-end report. The forward-looking statements contained herein are expressly
qualified by this cautionary statement.
Boe Presentation - For the purpose of calculating unit revenues and costs,
natural gas is converted to a barrel of oil equivalent ("Boe") using six
thousand cubic feet ("Mcf") of natural gas equal to one barrel of oil unless
otherwise stated. Boe may be misleading, particularly if used in isolation. A
Boe conversion ratio of six Mcf to one barrel ("Bbl") is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead. All Boe measurements and
conversions in this report are derived by converting natural gas to oil in the
ratio of six thousand cubic feet of gas to one barrel of oil.
Non-GAAP Measurements - Within management's discussion and analysis, references
are made to terms which are not recognized under GAAP in Canada. Specifically,
"funds from operations", "funds from operations per share", "field netbacks",
"cash costs" and "recycle ratio" as well as any "per Boe" amounts, do not have
any standardized meaning as prescribed by GAAP in Canada and are regarded as
non-GAAP measures. It is likely that these non-GAAP measurements may not be
comparable to the calculation of similar amounts for other entities. In
particular, funds from operations is not intended to represent, or be equivalent
to, cash flow from operating activities calculated in accordance with Canadian
GAAP which appears on the Company's consolidated statements of cash flows. Funds
from operations and similar non-GAAP terms are used to benchmark operations
against prior periods and peer group companies. Non-GAAP funds from operations
is also used to determine debt to cash flow ratios for the purposes of
establishing interest costs under the Company's banking agreement.
A reconciliation of funds from operations to cash flows from operating
activities is as follows:
Quarter Ended
Quarter Ended Quarter Ended December 31,
March 31, 2010 March 31, 2009 2009
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Cash flow from operating
activities $ 13,689 $ 14,633 $ 13,413
Net change in non-cash working
capital items 3,912 (913) 385
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Non-GAAP funds from operations $ 17,601 $ 13,720 $ 13,798
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Non-GAAP funds from operations per share is calculated using the weighted
average number of common shares outstanding consistent with the calculation of
net income per share. Non-GAAP field netbacks equals total revenue net of
hedging gains or losses, plus royalty income, less royalties paid, production
and transportation costs, calculated on a Boe basis for the reporting period.
Non-GAAP cash flow netback equals field netback less interest and general and
administrative costs, also calculated on a Boe basis. Total Boe is calculated by
multiplying the daily production by the number of days in the year or quarter as
the case may be. Non-GAAP cash costs per Boe are the total of production costs,
transportation costs, interest and general and administrative costs. Recycle
ratio is calculated by dividing the field netback by finding costs.
OPERATIONAL AND FINANCIAL RESULTS
Production and Revenue
Average Daily Production
Quarter Ended
Quarter Ended Quarter Ended December 31,
March 31, 2010 March 31, 2009 2009
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Natural gas (Mcf/d) 41,862 43,485 40,325
Natural gas liquids (Bbls/d) 1,207 542 652
Crude oil (Bbls/d) 162 651 517
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Total (Boe/d) 8,346 8,441 7,890
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Total Boe production for the first quarter of 2010 fell by 1% when compared to
the first quarter of 2009 and increased by 6% when compared to the immediately
prior quarter. Essentially flat year-over-year production is attributable to the
sharply diminished drilling program during 2009, driven by low commodity prices,
particularly for natural gas which prevailed throughout most of that year.
However, increased drilling activity in the first quarter of 2010 resulted in
the quarter-over-quarter uplift in production. In particular, natural gas
liquids production showed a considerable increase in the first quarter of 2010.
In part, the increase is due to investment in facilities at Parkland late in
2009, which has resulted in a higher liquids capture for the Company. In
addition, about 330 Bbls of condensate, previously included with oil production
has, effective January 1, 2010, been included in natural gas liquids production.
The disposition of 220 Boe per day, primarily light oil, late in 2009, also
contributed to the decrease in oil production. Production increases came from
the Company's core Parkland area.
Daily production per million shares outstanding in the first quarter of 2010
averaged 178 Boe, compared to 187 Boe in the first quarter of 2009, a decrease
of 5%.
Production Profile and Per-Unit Prices
Quarter Ended Quarter Ended
March 31, 2010 March 31, 2009
----------------------------------------------------------------------------
Average Average
Selling Price Selling Price
Percentage Before Percentage Before
of Total Boe Transportation of Total Boe Transportation
Production Costs Production Costs
----------------------------------------------------------------------------
Natural gas - Mcf 84% $ 5.56 86% $ 5.52
Natural gas
liquids - Bbl 14% $ 68.02 6% $ 38.46
Crude oil - Bbl 2% $ 77.90 8% $ 49.95
----------------------------------------------------------------------------
Per Boe $ 39.25 $ 34.76
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter Ended
December 31, 2009
----------------------------------------------------------------------------
Average
Selling Price
Percentage Before
of Total Boe Transportation
Production Costs
----------------------------------------------------------------------------
Natural gas - Mcf 85% $ 5.03
Natural gas
liquids - Bbl 8% $ 55.84
Crude oil - Bbl 7% $ 75.74
----------------------------------------------------------------------------
Per Boe $ 35.26
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 liquids rich natural
gas and, based on exploitation of the Company's existing asset base, short and
medium term crude oil will not materially increase as a percentage of Boe
production. Growth in gas production year-over-year and quarter-over-quarter
came largely from the Parkland area in British Columbia, in particular from the
Company's Montney discovery.
Storm's gas production in Alberta and British Columbia is sold at prices which
reflect both the benchmark AECO daily index pricing and Station 2 daily index
pricing. Prices for natural gas fell throughout 2009, until the final months
when a modest improvement became apparent, which continued into the first
quarter of 2010. However, since March 2010, prices for natural gas have fallen
considerably due in part to high storage levels, weak industrial demand and
production levels which seem to be impervious to market signals. The widely
recognized benchmark average AECO index price for the first quarter of 2010 was
$5.08 per GJ, compared to $5.34 per GJ for the first quarter of 2009, and to
$4.01 per GJ for the final quarter of 2009. In addition, for the first quarter
of 2010, the average Station 2 daily index price, which applied to approximately
40% of Storm's gas production in the quarter, was about 11% lower than the
average AECO index price. Storm's corporate average realized price per Mcf for
natural gas for the first quarter of 2010 was approximately 9% higher than the
equivalent AECO index price. This pricing premium is attributable to high heat
content natural gas produced from the Montney formation at Parkland.
Pricing by quarter in 2009 and into 2010 was as follows:
----------------------------------------------------------------------------
Storm AECO C Station 2
Realized Price Monthly Average Daily Average
($/Mcf)(1) ($/GJ)(1) ($/GJ)(1)
----------------------------------------------------------------------------
Q1 2009 $ 5.52 $ 5.34 $ 4.57
Q2 2009 $ 3.65 $ 3.47 $ 3.06
Q3 2009 $ 3.30 $ 2.87 $ 2.75
Q4 2009 $ 5.03 $ 4.01 $ 4.24
Q1 2010 $ 5.56 $ 5.08 $ 4.53
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Storm realized price is measured in Mcf; Index prices in GJ.
(2) Per-unit prices do not include adjustments for hedging gains or losses.
Production by Area Boe/d
Quarter Ended
Quarter Ended Quarter Ended December 31,
March 31, 2010 March 31, 2009 2009
----------------------------------------------------------------------------
Fort St. John/Parkland - BC 6,794 6,105 6,079
Grande Prairie - AB 1,100 1,600 1,315
Cabin-Kotcho-Junior - BC 414 677 454
Other 38 59 42
----------------------------------------------------------------------------
Total 8,346 8,441 7,890
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The above table sets out the average production from each of Storm's main
producing areas. For the three months ended March 31, 2010, Parkland production
increased by 11% year over year, while Grande Prairie production fell by 31%,
reflecting the focus of Storm's investment program. Correspondingly, reduced
investment in Alberta is evidenced by an approximate 31% reduction in quarterly
year-over-year production.
Production Revenue
Quarter Ended
Quarter Ended Quarter Ended December 31,
March 31, 2010 March 31, 2009 2009
----------------------------------------------------------------------------
Natural gas $ 20,954 $ 21,607 $ 18,643
Natural gas liquids 7,389 1,876 3,350
Crude oil 1,137 2,927 3,605
Royalty income 56 67 36
----------------------------------------------------------------------------
Revenue from product sales 29,536 26,477 25,634
Hedging losses (366) (658) (731)
----------------------------------------------------------------------------
Total production revenue $ 29,170 $ 25,819 $ 24,903
----------------------------------------------------------------------------
----------------------------------------------------------------------------
A reconciliation of revenue from product sales between Q1 2010 and Q1 2009
is as follows:
Natural Gas Royalty
Natural Gas Liquids Crude Oil Income Total
----------------------------------------------------------------------------
Revenue from product
sales - Q1 2009 $ 21,607 $ 1,876 $ 2,927 $ 67 $ 26,477
Effect of production
changes year over year (807) 2,302 (2,198) 2 (701)
Effect of changing
product prices
year over year 154 3,211 408 (13) 3,760
----------------------------------------------------------------------------
Revenue from product
sales - Q1 2010 $ 20,954 $ 7,389 $ 1,137 $ 56 $ 29,536
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The year-over-year increase in revenues is due to increased production and a 77%
price increase in natural gas liquids.
Hedging
Crude Oil:
Storm entered into a fixed price sale contract in respect of 450 barrels of
crude oil per day, at a price of $83.45 per barrel for the period January 1 to
June 30, 2010. At March 31, 2010, the Company recognized on the Consolidated
Statements of Income and Retained Earnings, a realized gain of $0.06 million and
an unrealized mark-to-market gain of $0.05 million on this contract. Accounting
for crude oil derivative contracts follows mark-to-market rules. The crude oil
volume covered by the contract exceeds the Company's current oil production.
However, natural gas liquids production includes condensate, the pricing of
which is based on crude oil pricing, and this more than covers the difference
between actual oil production and the hedged volume.
Natural Gas:
For 2010, Storm entered into fixed price natural gas sales contracts for the
period January 1, 2010 to September 30, 2010. The Company realized a hedging
loss of $0.5 million on these contracts for the quarter ended March 31, 2010.
Contracts outstanding at March 31, 2010 were as follows:
Volume Price Term
----------------------------------------------------------------------------
Swap - 21,000 GJ/day $4.78 April 2010 - June 2010
Collar - 7,000 GJ/day $ 5.00 to $5.70 April 2010 - September 2010
Swap - 5,000 GJ/day $5.20 July 2010 - September 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company uses hedge accounting rules for these contracts and has recognized
an unrealized hedging gain in the amount of $6.5 million on the Consolidated
Statements of Comprehensive Income and Accumulated Other Comprehensive Income in
respect of contracts outstanding at March 31, 2010.
Royalties
Quarter Ended
Quarter Ended Quarter Ended December 31,
March 31, 2010 March 31, 2009 2009
----------------------------------------------------------------------------
Charge for period $ 4,457 $ 5,253 $ 3,922
Royalties as a percentage of
revenue from product sales
before hedging 15.1% 19.9% 15.3%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Per Boe $ 5.93 $ 6.91 $ 5.40
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Royalties are paid primarily to the provincial governments in Alberta and
British Columbia. The year-over-year reduction in the royalty rate is due to the
expansion in both provinces of royalty incentive programs, which will continue
to benefit future quarters.
Production Costs
Quarter Ended
Quarter Ended Quarter Ended December 31,
March 31, 2010 March 31, 2009 2009
----------------------------------------------------------------------------
Charge for period $ 3,587 $ 4,461 $ 3,799
Percentage of revenue from
product sales before hedging 12.1% 16.9% 14.8%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Per Boe $ 4.78 $ 5.87 $ 5.23
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year-over-year production costs fell by approximately 20%, both in total and per
Boe. The introduction of the refridge plant at Parkland in late 2009, plus
Storm's constant focus on cost control, resulted in a steadily downward cost
profile over the last several quarters. In particular, operating costs at
Parkland declined to $3.08 per Boe in the first quarter of 2010, a reduction of
approximately $0.75 over the average for 2009. Increased production from
Parkland should result in further reductions to Boe costs in future quarters.
Storm's cash costs per Boe, which comprise production, transportation, interest
and general and administrative costs, amounted to $9.40 for the first quarter of
2010, compared to $9.81 for the first quarter of 2009 and to $10.31 for the
fourth quarter of 2009.
Transportation Costs
Quarter Ended
Quarter Ended Quarter Ended December 31,
March 31, 2010 March 31, 2009 2009
----------------------------------------------------------------------------
Charge for period $ 1,277 $ 1,402 $ 1,162
Percentage of revenue from
product sales before hedging 4.3% 5.3% 4.5%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Per Boe $ 1.70 $ 1.85 $ 1.60
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total and per-unit transportation costs fell year over year and increased
slightly quarter over quarter. The modest increase in the first quarter of 2010,
compared to the immediately prior quarter, is due to higher transportation costs
associated with trucking of increased volumes of natural gas liquids at
Parkland. Storm's low per-unit production and transportation costs reflect
Storm's high level of operatorship as well as facility control and ownership and
reasonable proximity to major pipelines.
Field Netbacks
Details of field netbacks per commodity unit are as follows:
Quarter Ended March 31, 2010
----------------------------------------------------------------------------
Natural Gas
Crude Oil Liquids Natural Gas Total
($/Bbl) ($/Bbl) ($/Mcf) ($/Boe)
----------------------------------------------------------------------------
Product sales $ 77.90 $ 68.02 $ 5.56 $ 39.25
Hedging gain (loss)
realized 4.14 - (0.13) (0.56)
Royalty income 0.28 0.02 0.01 0.07
Royalties (6.80) (12.61) (0.79) (5.93)
Production costs (1) (7.37) - (0.92) (4.78)
Transportation (3.96) (4.95) (0.18) (1.70)
----------------------------------------------------------------------------
Field netback $ 64.19 $ 50.48 $ 3.55 $ 26.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter Ended March 31, 2009
----------------------------------------------------------------------------
Natural Gas
Crude Oil Liquids Natural Gas Total
($/Bbl) ($/Bbl) ($/Mcf) ($/Boe)
----------------------------------------------------------------------------
Product sales $ 49.95 $ 38.46 $ 5.52 $ 34.76
Hedging loss - realized (0.89) - - (0.07)
Royalty income 0.13 0.08 0.01 0.09
Royalties (7.55) (8.78) (1.12) (6.91)
Production costs (1) (7.61) - (1.03) (5.87)
Transportation (5.06) (3.89) (0.23) (1.85)
----------------------------------------------------------------------------
Field netback $ 28.97 $ 25.87 $ 3.15 $ 20.15
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter Ended December 31, 2009
----------------------------------------------------------------------------
Natural Gas
Crude Oil Liquids Natural Gas Total
($/Bbl) ($/Bbl) ($/Mcf) ($/Boe)
----------------------------------------------------------------------------
Product sales $ 75.74 $ 55.84 $ 5.03 $ 35.26
Hedging loss - realized (7.05) - (0.03) (0.59)
Royalty income 0.15 0.06 0.01 0.04
Royalties (13.27) (12.58) (0.69) (5.40)
Production costs (1) (7.98) - (0.92) (5.23)
Transportation (4.71) (3.87) (0.19) (1.60)
----------------------------------------------------------------------------
Field netback $ 42.88 $ 39.45 $ 3.21 $ 22.48
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Production costs for natural gas liquids are included with natural gas
costs.
Field netbacks for the first quarter of 2010 increased by 31% year over year.
Revenue per Boe after hedging adjustments increased by 12% and direct costs fell
by 15%. The lower cost profile of the first quarter of 2010 is likely
sustainable into future quarters and lowers the Company's break-even point in a
period of low commodity prices.
Based on an all-in proved plus probable finding cost for the last three years of
$11.99, Storm's recycle ratio (field netback divided by finding costs) for the
first quarter of 2010 was 2.2.
Interest
Quarter Ended
Quarter Ended Quarter Ended December 31,
March 31, 2010 March 31, 2009 2009
----------------------------------------------------------------------------
Charge for period $ 1,239 $ 578 $ 1,198
Per Boe $ 1.65 $ 0.76 $ 1.65
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest is paid on Storm's revolving bank facility. The Company normally
borrows using bankers' acceptances plus a stamping fee. Although the interest
rate paid on bankers' acceptances fell year over year, the stamping and other
fees payable by the Company increased considerably upon the renewal of the
Company's banking agreement, effective May 1, 2009. Higher debt levels were also
responsible for the 114% year-over-year increase in borrowing costs.
General and Administrative Costs
Quarter Ended
Quarter Ended Quarter Ended December 31,
Total Costs March 31, 2010 March 31, 2009 2009
----------------------------------------------------------------------------
Gross general and
administrative charge for
period $ 1,856 $ 1,869 $ 2,049
Capital and operating
recoveries (899) (858) (718)
----------------------------------------------------------------------------
Net general and administrative
costs for period $ 957 $ 1,011 $ 1,331
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter Ended
Costs per Boe Quarter Ended Quarter Ended December 31,
March 31, 2010 March 31, 2009 2009
----------------------------------------------------------------------------
Gross general and
administrative charge for
period $ 2.47 $ 2.46 $ 2.82
Capital and operating
recoveries (1.20) (1.13) (0.99)
----------------------------------------------------------------------------
Net general and administrative
for period $ 1.27 $ 1.33 $ 1.83
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross general and administrative costs for the quarter ended March 31, 2010,
were unchanged when compared to the prior year. Higher field activity levels,
when compared to the first quarter of 2009, resulted in higher capital
recoveries with a corresponding reduction in net general and administrative
costs per Boe for the three months to March 31, 2010.
Storm does not capitalize general and administrative costs. Net general and
administrative costs per Boe for the second half of 2010 should be lower, due to
increased capital and operating recoveries resulting from higher levels of field
activity.
Stock-Based Compensation Costs
Quarter Ended
Quarter Ended Quarter Ended December 31,
March 31, 2010 March 31, 2009 2009
----------------------------------------------------------------------------
Charge for period $ 673 $ 396 $ 634
Per Boe $ 0.90 $ 0.52 $ 0.87
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Stock-based compensation costs are non-cash charges which reflect the estimated
value of stock options issued to Storm's directors and employees. The value of
the award is recognized as an expense over the period from the grant date to the
date of vesting of the award. The increase in the charge for the first quarter
of 2010, compared to the prior year, is a result of stock options being issued
in 2009 and 2010 at a price higher than the historical average price, net of
certain prior year awards being fully expensed.
Depletion, Depreciation and Accretion
Quarter Ended
Quarter Ended Quarter Ended December 31,
March 31, 2010 March 31, 2009 2009
----------------------------------------------------------------------------
Depletion and depreciation
charge for period $ 11,485 $ 11,167 $ 11,006
Accretion charge for period 112 119 121
----------------------------------------------------------------------------
Total $ 11,597 $ 11,286 $ 11,127
----------------------------------------------------------------------------
Per Boe $ 15.44 $ 14.86 $ 15.33
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The increase in the total charge for depletion, depreciation and accretion for
the first quarter of 2010 compared to the immediately prior quarter, is a
consequence of higher production volumes, as the depletion component of the
charge is based on a cost per Boe.
The increase in the charge for depletion and depreciation per Boe for the first
quarter of 2010 when compared to the equivalent quarter of 2009 is 4%. The
increase is attributable to proved oil and gas reserves being added in 2009 at a
cost higher 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%.
Investment Loss
As described in Note 4 to the consolidated financial statements, Storm accounts
for its investment in Storm Gas Resource Corp. ("SGR") using the equity method,
in accordance with which the Company's pro rata share of changes in SGR's equity
is included in the determination of the Company's net income for the period. The
investment loss recorded in the first quarter of 2010 represents Storm's share
of changes in SGR's equity for the period.
Future Income Taxes
For the three months ended March 31, 2010, Storm recorded a provision for future
income taxes of $2.1 million compared to a provision for future income taxes of
$0.2 million for the quarter ended March 31, 2009. The statutory combined
federal and provincial rate applicable to income in 2010 is 28%, compared to 29%
for 2009.
At March 31, 2010, Storm had tax pools carried forward estimated to be $233
million. In addition, Storm has a capital loss in the amount of $9.7 million
available for application against future capital gains.
Net Income and Net Income Per Share
The Company generated net income of $3.0 million for the first quarter of 2010,
compared to net income of $1.3 million for the first quarter of 2009.
Quarter Ended Quarter Ended Quarter Ended
March 31, 2010 March 31, 2009 December 31, 2009
----------------------------------------------------------------------------
Per diluted Per diluted Per diluted
share share share
----------------------------------------------------------------------------
Net income $ 3,040 $ 0.06 $ 1,250 $ 0.03 $ 2,147 $ 0.05
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Non-GAAP Funds from Operations and Funds from Operations per Share
Quarter Ended Quarter Ended Quarter Ended
March 31, 2010 March 31, 2009 December 31, 2009
----------------------------------------------------------------------------
Per diluted Per diluted Per diluted
share share share
----------------------------------------------------------------------------
Funds from
operations $ 17,601 $ 0.37 $ 13,720 $ 0.30 $ 13,798 $ 0.29
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Non-GAAP funds from operations is not a measure recognized by GAAP in Canada,
although it is widely used by analysts and other financial statement users. It
is also used by the Company's bankers to measure debt to cash flow ratios, which
determines interest costs under the Company's banking agreement. The most
directly comparable measure under GAAP is cash flows from operating activities,
as set out below.
Cash Flows from Operating Activities and Cash Flows from Operating
Activities per Share
Quarter Ended Quarter Ended Quarter Ended
March 31, 2010 March 31, 2009 December 31, 2009
----------------------------------------------------------------------------
Per diluted Per diluted Per diluted
share share share
----------------------------------------------------------------------------
Cash flows
from
operating
activities $ 13,689 $ 0.29 $ 14,663 $ 0.32 $ 13,413 $ 0.28
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Comprehensive Income (Loss)
Under GAAP, comprehensive income (loss) comprises unrealized gains and losses
resulting from the mark-to-market valuation of certain assets and liabilities.
For the first quarter of 2010, Storm's comprehensive loss comprised the
following:
- unrealized hedging gains or losses on contracts to which hedge accounting
rules are deemed to apply; for Storm, natural gas hedging contracts follow hedge
accounting rules
- unrealized gains or losses on investments which are considered to be available
for sale.
INVESTMENT AND FINANCING
Working Capital
Receivables comprise production revenue receivables and accruals, and
receivables in respect of operating and capital costs. Investments included in
current assets comprise 5.1 million shares of Bellamont Exploration Ltd., a
junior oil and gas corporation, whose shares trade on the Toronto Stock
Exchange. As the shares of this corporation are regarded as being available for
sale, under GAAP the investment is carried at fair value, determined using the
period end market price. Prepaid and other include unamortized insurance
premiums, deposits, prepayments and certain inventory equipment items.
Accounts payable and accrued liabilities include operating, administrative and
capital costs payable. Net payables in respect of cash calls issued to partners
regarding capital projects and estimates of amounts owing but not yet invoiced
to the Company have been included in accounts payable.
Excluding an unrealized financial instrument gain, Storm had a working capital
deficiency of $12.1 million at March 31, 2010, compared to $13.0 million at
March 31, 2009 and $6.3 million at December 31, 2009. The working capital
deficiency at each period end reflects the seasonality of Storm's field
operations. The Company's working capital deficiency is cyclical and is usually
highest at the end of the first quarter of each year and lowest at the end of
second quarter.
Capital Expenditures
Capital costs incurred were as follows:
Quarter Ended Quarter Ended Quarter Ended
March 31, 2010 March 31, 2009 December 31, 2009
----------------------------------------------------------------------------
Land and lease $ 1,104 $ 806 $ 460
Seismic 894 664 47
Drilling and completions 26,761 15,802 13,713
Facilities and equipment 8,027 6,766 8,295
Other 45 3 9
----------------------------------------------------------------------------
Field expenditures 36,831 24,041 22,524
Property acquisitions 8 9,012 321
Property dispositions - (1,562) (17,001)
----------------------------------------------------------------------------
Total $ 36,839 $ 31,491 $ 5,844
----------------------------------------------------------------------------
----------------------------------------------------------------------------
During the quarter ended March 31, 2010 the Company drilled nine successful gas
wells (7.7 net), including one vertical well (1.0 net) and seven horizontal
wells (5.7 net) in the Montney discovery at Parkland. Four horizontal Montney
wells (4.0 net) were also completed and tied in during the quarter. The Company
also invested $3.7 million to expand and debottleneck the gathering system to
allow for future production growth and to maximize gas throughput and liquids
recovery at the 3-9 refridge plant.
In the second half of 2010, Storm plans to drill six to nine horizontals (6.0 to
7.1 net) in the Montney formation at its Parkland property which includes three
earning horizontals on lands farmed in on during the quarter, plus a second
horizontal into the lower sands. In addition, two more vertical Montney
step-outs (1.6 net) will be drilled as part of the Company's focus on expanding
the proved plus probable reserve area. Storm also expects to invest
approximately $12 million net to our 40% working interest in 2010 to advance the
HRB shale project towards commerciality as part of the Company's expected $48 to
$53 million capital investment during the remainder of 2010.
Bank Debt, Liquidity and Capital Resources
Storm has a revolving borrowing base bank credit facility which is renewable
annually but subject to mid-year review. The facility was renewed effective
April 30, 2010 and amounts to $140 million, an increase of $20 million over the
prior facility. The amount drawn on the facility at March 31, 2010 amounted to
$99.1 million, or 71% of the new facility. Total debt, including working capital
deficiency (less unrealized financial instrument losses), amounted to $111.3
million at March 31, 2010, resulting in a ratio of debt to annualized funds from
operations for 2010 of 1.6 times.
The Company normally funds its bank borrowings by drawing bankers' acceptances
plus a stamping fee. The renewal of Storm's banking facility in 2009 included a
large increase in stamping fees, standby fees and other costs. The renewal of
the bank facility in 2010 resulted in a modest decrease in fees and costs;
nevertheless, they remain at an historically high level. In part, the high fee
structure is offset by low core interest rates. However, recent commentary
suggests that increased interest rates can be expected in the remainder of 2010.
Storm funds its field capital programs through cash flow and bank borrowings.
The decline in natural gas prices severely reduced cash flows in recent quarters
resulting in constraints to the Company's capital programs. In 2010, an
effective hedging program, supported by a low cost structure, should provide
additional financial capacity to maintain a capital program consistent with the
Company's growth plans.
Acquisitions are funded by a combination of debt and, if required, equity. Field
capital programs tend to be concentrated in the winter months, with the result
that, in the ordinary course, capital expenditures in the first and fourth
quarters of the year will exceed cash flow, compensated by lower capital
expenditures in the second and third quarters. In quarters of high field
activity, Storm operates with a substantial working capital deficit, which is
reduced in quarters of lower field activity. The Company's capital budget is set
by management at the beginning of the calendar year and approved by the Board of
Directors. It is updated regularly with major changes subject to approval by the
Board of Directors.
Capital programs were funded as follows:
Quarter Ended Quarter Ended Quarter Ended
March 31, 2010 March 31, 2009 December 31, 2009
----------------------------------------------------------------------------
Non-GAAP funds from
operations $ 17,601 $ 13,720 $ 13,798
Non-cash working capital 5,770 (3,894) 2,717
Issue of common shares -
net of expenses 1,089 18,675 357
Increase (decrease) in bank
indebtedness 12,379 2,990 (8,103)
Proceeds from property sales - 1,562 17,002
----------------------------------------------------------------------------
Cash available for
investment $ 36,839 $ 33,053 $ 25,771
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Field expenditures 36,831 $ 24,041 $ 22,525
Property acquisitions 8 9,012 321
Investments - - 2,925
----------------------------------------------------------------------------
Total cost of investment
programs $ 36,839 $ 33,053 $ 25,771
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Investments
Bellamont Exploration Ltd.
In November 2009, the Company sold certain producing properties to Bellamont
Exploration Ltd. ("Bellamont") for proceeds totaling $17.2 million, comprised of
$14.0 million in cash and 5.08 million shares in Bellamont. The shares are
considered available for sale by management and are carried at fair value,
determined with reference to the published share price, with the corresponding
holding gain recognized in other comprehensive income.
Storm Gas Resource Corp.
Storm Gas Resource Corp. ("SGR") was incorporated to identify and participate in
unconventional natural gas opportunities, initially a shale gas resource in the
Horn River Basin of northeastern British Columbia. Storm owns 2,500,000 shares,
equal to 22% of the outstanding shares. The investment in SGR is made up as
follows:
----------------------------------------------------------------------------
Cash invested $ 8,698
Land transferred 417
Dilution gain on equity issue 3,527
Equity loss (920)
----------------------------------------------------------------------------
Total $ 11,722
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Including the dilution gain and equity loss, the carrying amount of Storm's
2,500,000 common shares of SGR is $4.69 per share. This amount should not be
regarded as representative of the value of Storm's investment in SGR. Total cash
invested, plus property transferred to SGR, amounts to $9.1 million, or $3.65
per SGR share. In addition to its investment in SGR, Storm has a direct 40%
working interest in undeveloped lands jointly acquired with SGR in the Horn
River Basin of northeastern British Columbia. This interest, together with
Storm's investment in SGR, provides the Company with 53% exposure to the
potential upside in the Horn River Basin lands.
Storm provides management services to SGR at cost. Amounts charged by Storm to
SGR in the three months ended March 31, 2010 were $0.08 million (March 31, 2009
- $0.07 million).
Storm Ventures International Inc.
At March 31, 2010, the Company's investment in Storm Ventures International Inc.
("SVI") represented a 4% 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.
Subsequent to March 31, 2010, SVI entered into certain transactions as follows:
- The transfer, in exchange for shares, of assets in the UK sector of the North
Sea to a corporation, Bridge Energy Norge ASA, which we understand will seek a
listing on the Oslo bourse.
- A business combination with Iteration Energy Ltd, an intermediate oil and gas
producer listed on the Toronto Stock Exchange. The combined entity, to be listed
on the Toronto Stock Exchange under the name Chinook Energy Inc., will be
managed by SVI management and will have approximately 20,000 Boe of daily
production and a land inventory of 775,000 acres in western Canada. It will also
have 800 Boe of daily production in Tunisia along with a substantial onshore and
offshore prospect inventory in that country.
The consequence of these transactions will be to provide shareholders of SVI
with a valuation and liquidity. During the coming months, Storm will consider
how best to make that value available to its shareholders.
Future Income Taxes
Estimated future income taxes at March 31, 2010 largely represent 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
Tax Pool March 31, 2010 Deduction
----------------------------------------------------------------------------
Canadian oil and gas property expense $ 78,321 10%
Canadian development expense 95,013 30%
Canadian exploration expense - 100%
Undepreciated capital cost 58,206 20 - 100%
Other 1,864 7 - 20%
----------------------------------------------------------------------------
Total 233,404
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 in the quarter ended March 31,
2010 comprise the present value of additional obligations accruing to the
Company as a result of field activity and acquisitions and dispositions during
the quarter, less costs paid in settlement of abandonment obligations, plus the
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:
Quarter Ended Quarter Ended Quarter Ended
March 31, 2010 March 31, 2009 December 31, 2009
----------------------------------------------------------------------------
Common shares outstanding
- end of period $ 46,986 46,553 $ 46,743
Unexercised stock options 2,924 2,420 3,014
----------------------------------------------------------------------------
Fully diluted common shares
end of period 49,910 48,973 49,757
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted average common
shares - basic 46,907 45,216 46,711
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted average common
shares - diluted $ 47,649 46,260 $ 47,857
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Stock options outstanding are exercisable over five years on various dates
beginning September 2005 at prices ranging from $3.61 to $12.60.
CONTRACTUAL OBLIGATIONS
In the course of its business Storm enters into various contractual obligations,
including the following:
- purchase of services;
- royalty agreements;
- operating agreements;
- processing agreements;
- right of way agreements; and
- lease obligations for accommodation, office equipment and automotive equipment.
All such contractual obligations reflect market conditions at the time of
contract and do not involve related parties, except that SGR subleases office
space from the Company at the same rate as the Company's head lease.
Obligations with a fixed term are as follows:
Obligation 2010 2011 2012 2013 2014
----------------------------------------------------------------------------
Lease of premises $ 619 $ 838 $ 838 $ 419 $ -
Equipment leases 126 132 67 9 1
Gas transportation and
processing commitments 1,295 1,434 887 486 240
----------------------------------------------------------------------------
Total $ 2,040 $ 2,404 $ 1,792 $ 914 $ 241
----------------------------------------------------------------------------
----------------------------------------------------------------------------
QUARTERLY RESULTS
Summarized information by quarter for the two years ended March 31, 2010
appears below:
Mar. 31, Dec. 31, Sep. 30, Jun. 30,
Quarter Ended 2010 2009 2009 2009
----------------------------------------------------------------------------
Production revenue ($000s) 29,170 24,903 19,436 18,712
Funds from operations ($000s) 17,601 13,798 8,618 8,460
Per share
- basic ($) 0.38 0.30 0.18 0.18
- diluted ($) 0.37 0.29 0.18 0.18
Net income (loss) ($000s) 3,040 2,147 (1,522) (2,192)
Per share
- basic ($) 0.06 0.05 (0.03) (0.05)
- diluted ($) 0.06 0.05 (0.03) (0.05)
Average daily production - Boe 8,346 7,890 8,030 8,153
Average field netback ($/Boe) 26.35 22.48 14.49 14.22
Capital expenditures - net ($000s) 36,839 5,844 14,430 3,843
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Mar. 31, Dec. 31, Sep. 30, Jun. 30,
Quarter Ended 2009 2008 2008 2008
----------------------------------------------------------------------------
Production revenue ($000s) 25,819 35,447 40,215 38,888
Funds from operations ($000s) 13,720 20,432 24,290 23,250
Per share
- basic ($) 0.30 0.46 0.54 0.52
- diluted ($) 0.30 0.45 0.53 0.50
Net income (loss) ($000s) 1,250 5,968 12,829 9,465
Per share
- basic ($) 0.03 0.13 0.28 0.21
- diluted ($) 0.03 0.13 0.28 0.20
Average daily production - Boe 8,441 8,161 7,107 6,130
Average field netback ($/Boe) 20.15 30.35 39.77 45.09
Capital expenditures - net ($000s) 31,491 35,342 27,057 5,780
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 months
ended March 31, 2010 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, 2009 and the unaudited consolidated
financial statements for the three months ended March 31, 2010.
RISK ASSESSMENT
There are a number of risks facing participants in the Canadian oil and gas
industry. Some risks are common to all businesses while others are specific to
the industry and others are specific to Storm. Information with respect to such
risks is set out in the Company's year-end report for the year ended December
31, 2009.
REPORTING CONTROLS
The Company's Chief Executive Officer ("CEO") and Chief Financial Officer
("CFO") are responsible for establishing and maintaining disclosure controls and
procedures ("DC&P") and internal controls over financial reporting ("ICFR").
Storm has codified and distributed to staff its policies, controls and
procedures with respect to disclosure to third parties of information concerning
the Company's operations and results. In addition, DC&P are designed to provide
reasonable assurance that material information is made known to the CEO and CFO
on a timely basis and that information required to be disclosed by the Company
in its annual filings, interim filings or other reports filed or submitted by it
under securities legislation is recorded, processed, summarized and reported
within the time periods specified in securities legislation. The CEO and CFO
have evaluated, or caused to be evaluated under supervision, the effectiveness
of Storm's DC&P and have concluded that Storm's DC&P are effective as at March
31, 2010, based on that evaluation.
ICFR have been designed by the CEO and CFO, either directly or under their
supervision, to provide reasonable assurance regarding the reliability of
financial reporting, including financial reporting for external purposes under
GAAP. As at March 31, 2010, the CEO and CFO evaluated the design and operating
effectiveness of the Company's ICFR. In part, this evaluation was based on the
work of third party specialists who were engaged by the Company to establish
internal control documentation and, effective December 31, 2008, to test the
operating effectiveness of such controls. In 2009 and 2010, the Company updated
its documentation and tested internal controls using internal resources.
Based on this evaluation, the CEO and CFO concluded that the design of ICFR was
effective as at March 31, 2010 to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with Canadian GAAP. Further, the Company is
required to disclose herein any change in the design of the Company's ICFR that
occurred during the quarter ended March 31, 2010 that has materially affected,
or is reasonably likely to materially affect, the Company's ICFR. No material
changes in the Company's design of ICFR were made or were identified during such
period that have materially affected, or are reasonably likely to materially
affect, the Company's ICFR. No circumstances suggesting a possible breach of
disclosure controls were identified during the three months ended March 31,
2010.
Because of inherent limitations, disclosure controls and procedures and internal
controls over financial reporting cannot prevent or identify all
mismeasurements, errors and fraud.
FINANCIAL REPORTING UPDATE
Future Accounting Changes
The CICA has issued Handbook Sections 1582 "Business Combinations", 1601
"Consolidated Financial Statements" and 1602 "Non-Controlling Interests", all of
which replace existing Handbook standards and are effective on or after January
1, 2011. See Note 2 to the consolidated financial statements for further
details.
International Financial Reporting Standards
Canada's Accounting Standards Board has confirmed January 1, 2011 as the date
that International Financial Reporting Standards ("IFRS") will replace existing
Canadian GAAP for all publicly accountable enterprises in Canada. The Company
will begin reporting under IFRS in the first quarter of 2011, with restatement,
for comparative purposes, of amounts reported on the Company's opening IFRS
balance sheet as at January 1, 2010 and of quarterly amounts reported by the
Company during 2010.
The Company has completed an initial assessment of the effects of adopting IFRS
and identified the following as having the greatest potential to change the
Company's accounting policies and procedures, financial reporting and
information systems upon conversion to IFRS.
Financial Statement Effect on Financial
Category Change Under IFRS Statements of Storm
----------------------------------------------------------------------------
Property and Equipment Existing full-cost pool Certain costs
to be divided into attributable to areas
exploration and with no future
evaluation and development potential
development and will be charged to
producing segments. retained earnings on
Test for impairment at transition. Future
transition. depletion charges will
be reduced accordingly.
----------------------------------------------------------------------------
Property and Equipment Development and Additional depletion
producing segments to be calculations will be
allocated into CGUs and required at each
depleted at a lower reporting period.
level.
----------------------------------------------------------------------------
Property and Equipment Depletion can be Use of proved plus
calculated using either probable reserves in
proven or proved depletion calculation
plus probable reserves. will reduce depletion
expense.
----------------------------------------------------------------------------
Property and Equipment Gains and losses on Gains and losses on
dispositions will be property sales will be a
measured and recognized frequent income
in the income statement. statement item, leading
There is no de minimis to a more erratic
rule as exists under earnings profile.
current GAAP.
----------------------------------------------------------------------------
Property and Equipment Impairment test will be Impairment of CGUs from
calculated at the CGU existing asset base is
level plus changes to unlikely to be an issue.
the impairment
calculation methodology.
----------------------------------------------------------------------------
Financial Instruments Hedge accounting All future hedges will
requirements have become be marked-to-market and
significantly more gains or losses will be
stringent. included in the income
statement.
----------------------------------------------------------------------------
Asset Retirement A market-based discount Effect not yet
Obligation rate will be used determinable.
instead of using a
credit-adjusted
risk-free rate.
----------------------------------------------------------------------------
Borrowing Costs Interest costs relating Likely no effect on
to the financing of Storm, based on existing
assets with a long assets.
ready-for-use time frame
to be capitalized.
----------------------------------------------------------------------------
Cash Flow Statement To focus on cash More a presentation than
measurements only, with a measurement issue.
no adjustment for However, non-GAAP funds
working capital from operations will be
components. harder to measure and
may disappear from
common usage.
----------------------------------------------------------------------------
Share-Based Payments Stock options that vest No material effect
in installments should likely.
be valued separately.
----------------------------------------------------------------------------
The Company's staff has begun to design and document the changes required to
accounting policies, financial reporting, internal controls over financial
reporting, information technology and systems, business processes, and staff
education and training and expects to complete this phase of the conversion
process by the end of June. The Company is also preparing an opening balance
sheet (January 1, 2010) in accordance with IFRS and plans to have the Company's
external auditors review this balance sheet and the proposed accounting and
policy changes in the second half of this year. Staff continue to participate in
meetings with peers in the industry and accounting and information system
service providers to identify the practices that will be used to obtain the most
relevant and comparable financial information upon conversion to IFRS.
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.
Consolidated Balance Sheets
($000s) (unaudited) March 31, December 31,
2010 2009
----------------------------------------------------------------------------
ASSETS
----------------------------------------------------------------------------
Current
Accounts receivable $ 14,332 $ 10,919
Investments (Note 4) 3,506 3,607
Prepaids and other 3,918 4,861
Fair value of financial instruments
(Note 11) 4,732 -
----------------------------------------------------------------------------
26,488 19,387
Property and equipment - net (Note 3) 328,516 303,053
Investments (Note 4) 22,247 22,492
----------------------------------------------------------------------------
$ 377,251 $ 344,932
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
----------------------------------------------------------------------------
Current
Accounts payable and accrued liabilities $ 33,900 $ 25,661
Fair value of financial instruments
(Note 11) 85 1,855
----------------------------------------------------------------------------
33,985 27,516
Bank indebtedness (Note 5) 99,137 86,758
Asset retirement obligation (Note 6) 7,805 7,584
Future income taxes (Note 7) 24,268 20,478
----------------------------------------------------------------------------
165,195 142,336
----------------------------------------------------------------------------
Shareholders' equity (Note 8)
Share capital 109,236 107,852
Contributed surplus 6,073 5,719
Retained earnings 92,993 89,952
Accumulated other comprehensive
income (deficit) 3,754 (927)
----------------------------------------------------------------------------
212,056 202,596
----------------------------------------------------------------------------
Commitments (Note 13) $ 377,251 $ 344,932
Consolidated Statements of Income and Retained Earnings
($000s except per-share amounts) Three Months to Three Months to
(unaudited) March 31, 2010 March 31, 2009
----------------------------------------------------------------------------
Revenue
Revenue from product sales $ 29,536 $ 26,477
Realized loss on financial instruments
(Note 11) (418) (52)
Unrealized gain (loss) on financial
instruments (Note 11) 52 (606)
Royalties (4,457) (5,253)
----------------------------------------------------------------------------
24,713 20,566
----------------------------------------------------------------------------
Expenses
Production 3,587 4,461
Transportation 1,277 1,402
Interest 1,239 578
General and administrative 957 1,011
Stock-based compensation 673 396
Depletion, depreciation and accretion 11,597 11,286
----------------------------------------------------------------------------
19,330 19,134
----------------------------------------------------------------------------
Income before the following: 5,383 1,432
Investment loss (Note 4) (245) -
----------------------------------------------------------------------------
Income before taxes: 5,138 1,432
Future income taxes (Note 7) (2,098) (182)
----------------------------------------------------------------------------
Net income for the period 3,040 1,250
Retained earnings, beginning of period 89,953 90,269
----------------------------------------------------------------------------
Retained earnings, end of period $ 92,993 $ 91,519
----------------------------------------------------------------------------
Net income per share (Note 9)
- basic $ 0.06 $ 0.03
- diluted $ 0.06 $ 0.03
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Comprehensive Income and Accumulated Other
Comprehensive Income (Deficit)
Three Months to Three Months to
($000s) (unaudited) March 31, 2010 March 31, 2009
----------------------------------------------------------------------------
Net income for the period $ 3,040 $ 1,250
Unrealized hedging gain (Note 11) 6,450 -
Unrealized loss on shares available
for sale (Note 4) (101) -
Related income tax (1,668) -
----------------------------------------------------------------------------
Other comprehensive income 4,681 -
----------------------------------------------------------------------------
Comprehensive income for the period $ 7,721 $ 1,250
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated other comprehensive income
(deficit), beginning of period $ (927) $ -
Other comprehensive income for the period 4,681 -
----------------------------------------------------------------------------
Accumulated other comprehensive income
(deficit), end of period $ 3,754 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Cash Flows
Three Months to Three Months to
($000s) (unaudited) March 31, 2010 March 31, 2009
----------------------------------------------------------------------------
Operating activities
Net income for the period $ 3,040 $ 1,250
Non-cash items:
Investment loss (Note 4) 245 -
Depletion, depreciation and accretion 11,597 11,286
Unrealized loss (gain) on financial
instruments (Note 11) (52) 606
Future income tax 2,098 182
Stock-based compensation 673 396
----------------------------------------------------------------------------
Funds from operations 17,601 13,720
Net change in non-cash working capital
items (Note 10) (3,912) 913
----------------------------------------------------------------------------
13,689 14,633
----------------------------------------------------------------------------
Financing activities
Issue of common shares - net of expenses 1,089 18,675
Increase in bank indebtedness 12,379 2,990
----------------------------------------------------------------------------
13,468 21,665
----------------------------------------------------------------------------
Investing activities
Additions to property and equipment (36,839) (33,053)
Disposals of property and equipment - 1,562
Net change in non-cash working capital
items (Note 10) 9,682 (4,807)
----------------------------------------------------------------------------
(27,157) (36,298)
----------------------------------------------------------------------------
Change in cash during the period - -
Cash, beginning of period - -
----------------------------------------------------------------------------
Cash, end of period $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Notes to the Consolidated Financial Statements
Three months ended March 31, 2010 and 2009
Tabular amounts in thousands, except per share amounts
(unaudited)
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 of Storm 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, 2009. 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 year-end
report for the year ended December 31, 2009.
Future Accounting Changes
Business Combinations
The CICA issued Handbook Section 1582 "Business Combinations" that replaces the
previous business combinations standard. Under this guidance, the purchase price
used in a business combination is based on the fair value of shares exchanged at
the market price at acquisition date. Under the current standard, the purchase
price used is based on the market price of shares for a reasonable period before
and after the date the acquisition is agreed upon and announced. In addition,
the guidance generally requires all transaction costs to be expensed. Current
standards allow for the capitalization of these costs as part of the purchase
price. This standard applies prospectively to business combinations on or after
January 1, 2011.
Consolidated Financial Statements and Non-Controlling Interest
The CICA issued Handbook Sections 1601 "Consolidated Financial Statements", and
1602 "Non-controlling Interests", which replaces the existing guidance under
Section 1600 "Consolidated Financial Statements". Section 1601 establishes
standards for the preparation of Consolidated Financial Statements. Section 1602
provides guidance on accounting for a non-controlling interest in a subsidiary
in Consolidated Financial Statements subsequent to a business combination. These
standards will be effective for Storm for business combinations occurring on or
after January 1, 2011.
International Financial Reporting Standards
The CICA has confirmed January 1, 2011 as the effective date for the conversion
of Canadian GAAP to International Financial Reporting Standards ("IFRS"). The
Company will be required to begin reporting under IFRS in the first quarter of
2011 with comparative data for the prior year. IFRS uses a conceptual framework
similar to Canadian GAAP; however, there will be significant differences in
recognition, measurement and disclosures.
The Company has begun the process of transitioning to IFRS and has identified
key areas of Storm's financial reporting, internal controls and business
processes that will be affected by this change.
3. PROPERTY AND EQUIPMENT
March 31, 2010 December 31, 2009
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Property and equipment $ 502,791 $ 465,843
Accumulated depletion and depreciation (174,275) (162,790)
----------------------------------------------------------------------------
$ 328,516 $ 303,053
----------------------------------------------------------------------------
----------------------------------------------------------------------------
At March 31, 2010, the depletion calculation excluded unproved properties of
$28.9 million (December 31, 2009 - $29.2 million) and included future
development costs of $117.3 million (December 31, 2009 - $117.3 million).
4. INVESTMENTS
March 31, 2010 December 31, 2009
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Investment in Bellamont Exploration Ltd. $ 3,506 $ 3,607
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Long-term investments:
Investment in Storm Gas Resource Corp. 11,722 $ 11,967
Investment in Storm Ventures
International Inc. 10,525 10,525
----------------------------------------------------------------------------
$ 22,247 $ 22,492
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In November 2009, the Company sold certain producing properties to Bellamont
Exploration Ltd. ("Bellamont") for proceeds totaling $17.2 million, comprised of
$14.0 million in cash and 5.08 million shares in Bellamont. This investment in
Bellamont shares is carried at the fair value of $3.5 million, determined with
reference to the published share price, with the resulting holding loss of $0.1
million for the three months ended March 31, 2010 recognized in other
comprehensive income.
The Company's long-term investments include interests in two private companies,
Storm Gas Resource Corp. ("SGR") and Storm Ventures International Inc. ("SVI").
Storm's 22% interest in SGR is accounted for using the equity method, with
recorded investment losses representing Storm's pro-rata share of changes in
SGR's equity. The Company's 3.7% interest in SVI is accounted for using the cost
method. The common shares of both SGR and SVI are unlisted and the carrying
amount of the Company's investment does not represent a market valuation of the
Company's investment.
In the first quarter of 2010, the Company provided management services to SGR at
a cost of $76,000 (2009 - $67,000). The Company and SGR are also 40:60 joint
venture participants in certain undeveloped lands.
5. BANK INDEBTEDNESS
The Company has an extendible revolving bank facility in the amount of $140
million, based on the Company's producing reserves. The revolving facility is
available to the Company until April 29, 2011, but may be extended at the
Company's request until April 28, 2012, 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, 2009 - $12.8 million), which will be paid over the next 21 years,
with the majority of costs paid between 2015 and 2031. A credit adjusted
risk-free rate of eight percent was used to calculate the present value of the
asset retirement obligations, amounting to $7.8 million (December 31, 2009 -
$7.6 million).
The following table provides a reconciliation of the carrying amount of the
obligation associated with the retirement of oil and gas properties:
Three Months Ended Year Ended
March 31, 2010 December 31, 2009
----------------------------------------------------------------------------
Asset retirement obligation,
beginning of period $ 7,584 $ 7,259
Liabilities incurred 235 741
Liabilities disposed (126) (900)
Accretion expense 112 484
----------------------------------------------------------------------------
Asset retirement obligation,
end of period $ 7,805 $ 7,584
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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, share capital and unrealized financial instrument
gains/losses.
The Company has tax pools associated with property and equipment of
approximately $233 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:
March 31, 2010 March 31, 2009
----------------------------------------------------------------------------
Statutory combined federal and
provincial income tax rate 28% 29%
Expected income taxes $ 1,453 $ 423
Add (deduct) the income tax effect of:
Stock-based compensation 190 117
Equity loss (gain) 69 -
Rate adjustments 87 (452)
Other 299 94
----------------------------------------------------------------------------
Future income taxes $ 2,098 $ 182
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The components of the future income tax liability are as follows:
March 31, 2010 December 31, 2009
----------------------------------------------------------------------------
Property and equipment $ 25,040 $ 23,253
Asset retirement obligation (1,990) (1,942)
Share issue costs (450) (499)
Unrealized financial instrument provision 1,668 (334)
----------------------------------------------------------------------------
Future income tax liability $ 24,268 $ 20,478
----------------------------------------------------------------------------
----------------------------------------------------------------------------
8. SHAREHOLDERS' EQUITY
Share Capital
Authorized
An unlimited number of non-voting common shares
An unlimited number of voting common shares
An unlimited number of preferred shares
Included in the following common share balances are 1,275,000 non-voting
common shares.
Except for voting rights, non-voting and voting common shares are identical.
Issued
Number of Shares Consideration
----------------------------------------------------------------------------
Balance as at December 31, 2009 46,743 $ 107,852
Private placement of flow-through
common shares (1) 8 95
Stock options exercised (2) 234 1,313
Tax effect of flow-through share
renunciations (24)
----------------------------------------------------------------------------
Balance as at March 31, 2010 46,985 $ 109,236
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) On March 19, 2010, 8,000 flow-through common shares were issued to a
director at a price of $11.86 per share for total proceeds of $95,000.
The terms of this share issue require the Company to renounce to the
subscriber Canadian Exploration Expenditures in the amount of $95,000,
to be incurred prior to December 31, 2010.
(2) During 2010, 234,000 stock options were exercised for proceeds of
$994,000 and related prior stock compensation expense of $319,000 was
added to share capital.
Stock-Based Compensation Plans
The Company has a stock option plan under which it may grant, at the Company's
discretion, options to purchase common shares to directors, officers and
employees. Under the stock option plan a total of 3,700,000 common shares have
been reserved for issuance. Details of the options outstanding at March 31, 2010
are as follows:
Weighted Average
Number of options Exercise Price
----------------------------------------------------------------------------
Outstanding at December 31, 2009 3,014 $ 8.04
Issued during period 155 11.86
Exercised during period (234) 4.24
Forfeited during period (11) 9.24
----------------------------------------------------------------------------
Outstanding at March 31, 2010 2,924 $ 8.55
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Outstanding Options Exercisable Options
----------------------------------------------------------------------------
Weighted Weighted Weighted
Number of Average Average Number of Average
Range of Options Remaining Exercise Options Exercise
Exercise Price Outstanding Life (years) Price Outstanding Price
----------------------------------------------------------------------------
$ 3.61 to $5.39 193 0.3 $ 4.44 193 $ 4.44
$ 5.67 to $8.27 1,606 1.8 $ 6.61 1,064 $ 6.41
$ 8.57 to $12.60 1,125 3.7 $ 12.01 39 $ 11.78
----------------------------------------------------------------------------
2,924 2.7 $ 8.55 1,296 $ 6.28
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Using the Black-Scholes pricing model, the weighted average fair value of the
options granted in 2010 was estimated to be $3.80 (2009 - $3.70), using
risk-free interest rates of 4.5%, volatility of 40% and an expected average
vesting period of 30 months. The amortized cost of the options is charged as
stock-based compensation in the consolidated statement of income (loss) with an
equivalent offset to contributed surplus.
9. PER SHARE AMOUNTS
Three Months Ended Three Months Ended
March 31, 2010 March 31, 2009
----------------------------------------------------------------------------
Basic
Net income per share $ 0.06 $ 0.03
Weighted average number of shares
outstanding (000s) 46,907 45,216
Diluted
Net income per share $ 0.06 $ 0.03
Weighted average number of shares
outstanding (000s) 47,649 46,260
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 Months Ended Three Months Ended
March 31, 2010 March 31, 2009
----------------------------------------------------------------------------
Accounts receivable $ (3,413) $ 4,119
Prepaids and other 943 (271)
Accounts payable and accrued
liabilities 8,240 (7,742)
----------------------------------------------------------------------------
Change in non-cash working capital $ 5,770 $ (3,894)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Relating to:
Operating activities $ (3,912) $ 913
Financing activities - $ -
Investing activities 9,682 (4,807)
----------------------------------------------------------------------------
$ 5,770 $ (3,894)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid during the period $ 1,239 $ 578
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Income taxes paid during the period $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
11. FINANCIAL INSTRUMENTS
Financial Instrument Classification and Measurement
The Company's financial instruments carried on the Consolidated Balance Sheet
are carried at amortized cost with the exception of its investment in derivative
contracts and its investment in Bellamont, which are carried at fair value.
There were no significant differences between the carrying value of financial
instruments and their estimated fair values as at March 31, 2010.
The Company's investment in Bellamont and derivative contracts are transacted in
active markets. Storm classifies the fair value of these transactions according
to the following hierarchy based on the amount of observable inputs used to
value the instrument.
- Level 1 - Quoted prices are available in active markets for identical assets
or liabilities as of the reporting date. Active markets are those in which
transactions occur in sufficient frequency and volume to provide pricing
information on an ongoing basis.
- Level 2 - Pricing inputs are other than quoted prices in active markets
included in Level 1. Prices in Level 2 are either directly or indirectly
observable as of the reporting date. Level 2 valuations are based on inputs,
including quoted forward prices for commodities, time value and volatility
factors, which can be substantially observed or corroborated in the marketplace.
- Level 3 - Valuations in this level are those with inputs for the asset or
liability that are not based on observable market data.
The Company's investment in Bellamont and its derivative contracts have been
assessed on the fair value hierarchy described above. The investment in
Bellamont is classified as Level 1 and the derivative contracts as Level 2.
Assessment of the significance of a particular input to the fair value
measurement requires judgment and may affect the placement within the fair value
hierarchy level.
Risk Management
The Company holds various financial instruments. These financial instruments
expose the Company to the following risks:
- credit risk;
- market risk;
- liquidity risk.
Management has primary responsibility for monitoring and managing financial
instrument risks under direction from the Board of Directors, which has overall
responsibility for establishing the Company's risk management framework. In
certain circumstances, for example, hedging of future production revenue, the
Board has established policies and risk limits and controls, and monitors these
risks in relation to market conditions. In other circumstances, for example,
extending credit to purchasers of the Company's products, the Board has
delegated responsibility for credit assessment to management, but receives
frequent financial and operating reports.
The Company's financial instruments recognized on the consolidated balance sheet
consist of accounts receivable, investments, bank indebtedness, accounts payable
and accrued liabilities and unrealized financial instrument provision. The fair
value of these financial instruments approximates their carrying amounts.
Credit risk
A substantial portion of the Company's accounts receivable is concentrated with
a limited number of purchasers of commodities and joint venture partners in the
oil and gas industry and are subject to normal industry credit risk. Management
considers this concentration of credit risk to be limited, as commodity
purchasers are major industry participants, and receivables from partners are
protected by effective industry standard legal remedies. In addition, the
Company's high working interest in its major operating properties mitigates the
risk of partner default. The Company requires cash calls from its partners on
major field projects in advance of commencement. Receivables related to the sale
of the Company's production are normally collected on the 25th day of the month
following delivery. Nevertheless, the widespread disruption of credit markets
over the last two years, together with falling commodity prices, has exposed the
Company to greater credit risks, necessitating greater vigilance regarding
provision of credit to customers and to joint venture partners.
Market risk
Market risks are as follows and are largely outside the control of the Company:
- commodity prices;
- interest rates;
- foreign exchange.
Commodity prices
The Company is constantly exposed to the risk of declining prices for its
products with a corresponding reduction in cash flow. Reduced cash flow may
result in lower levels of capital being available for field activity, thus
compromising the Company's capacity to grow production while at the same time
replacing continuous production declines from existing properties. When debt
levels are forecast to increase due to capital expenditures exceeding cash flow,
or where the Company has financed, in whole or in part, an acquisition using
bank debt, the Company may enter into oil and natural gas hedging contracts in
order to provide stability of future cash flow and thus predictable debt
reduction. These contracts reduce the fluctuation in production revenue by
fixing prices of future deliveries of oil and natural gas. Such arrangements are
made in accordance with the Company's risk management policy and the Company
does not use these instruments for trading or speculative purposes. The Company
formally documents all relationships between derivative instruments and hedged
items, as well as the risk management objectives and strategy for undertaking
hedge transactions. Certain derivative instruments used by the Company qualify
for hedge accounting treatment. Realized gains and losses on these contracts are
recognized as revenue in the same period in which the revenues associated with
the hedged transactions are recognized. The Company also assesses, both at the
contract's inception and on an ongoing basis, whether the contract is highly
effective in offsetting the changes in fair values or cash flows of hedged
items. However, certain derivative instruments, relating to crude oil, in place
during the reporting periods, 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 months ended March 31, 2010, the Company realized losses on
financial instruments of $418,000 (March 31, 2009 - $52,000).
As at March 31, 2010, Storm has the following derivative contract in place,
which does not meet hedge accounting criteria. The fair market value of this
contract as at March 31, 2010 of ($85,000) is included under current liabilities
and the resulting unrealized mark-to-market gain of $52,000 for the three months
ended March 31, 2010 (March 31, 2009 - $0.6 million) is recognized as an
increase in revenue.
Volume Price Term
----------------------------------------------------------------------------
Crude Oil Swap
450 Bbls/d $ 83.45/Bbl Jan. 1, 2010 - Jun. 30, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at March 31, 2010, Storm has the following derivative contracts in place,
which meet hedge accounting criteria. The fair market value of these contracts
of $4.7 million is included under current assets and the resulting unrealized
mark-to-market gain of $6.5 million for the three months ended March 31, 2010
(March 31, 2009 - $nil) is recognized as an increase in other comprehensive
income.
Volume Price Term
----------------------------------------------------------------------------
Natural Gas Swaps
5,000 GJ/day $5.20 July 2010 - September 2010
21,000 GJ/day 4.78 April 2010 - June 2010
Collar
7,000 GJ/day $ 5.00 - $5.70 April 2010 - September 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest rates
Interest on the Company's revolving bank facility varies with changes in
interest rates, and is most commonly based on bankers' acceptance rates plus a
stamping fee. The Company is thus exposed to increased borrowing costs during
periods of increasing interest rates, with a corresponding reduction in both
cash flows and project economics. As at March 31, 2010, Storm has fixed the
interest rate on $60 million of bankers acceptances at a rate of 0.695%, plus
stamping fees, for the period May 8, 2009 to May 10, 2010. Mark-to-market
measurement of this derivative instrument does not have a material effect on the
value of the Company's debt at March 31, 2010.
Foreign exchange
Although the Company's product revenues are denominated in Canadian dollars, the
underlying market prices are affected by the exchange rate between the Canadian
and the United States dollar. As at March 31, 2010, the Company had no contracts
in place to reduce foreign exchange risk.
Sensitivities
Using the Company's actual production volumes, royalty rates, income tax rates
and debt levels for the three months ended March 31, 2010 and 2009, the
estimated after-tax effects that changes in certain factors would have on net
income and net income per share is as follows:
2010 2009
----------------------------------------------------------------------------
Change Change in Change Change in
in Net Net Income in Net Net Income
Factor Income Per Share Income Per Share
----------------------------------------------------------------------------
US$ 1.00/Bbl change in the
price of WTI $ 82,000 $ 0.00 $ 223,000 $ 0.00
$0.10/Mcf change in the price
of natural gas $ 238,000 $ 0.00 $ 749,000 $ 0.02
1% change in the interest rate $ 684,000 $ 0.01 $ 562,000 $ 0.01
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liquidity risk
Liquidity difficulties would emerge if the Company was unable to meet its
financial obligations as they fell due within normal credit terms. This may be
the consequence of diminished cash flows resulting from lower product prices,
production interruptions, or operating or capital cost increases. Liquidity
difficulties could also occur if the Company's bankers were unable to continue
to provide credit at a level, cost and on terms compatible with the Company's
capital requirements. Generally, the Company will, over a reasonable period of
time, limit its capital programs to cash flow from operations. In addition, the
Company endeavours to maintain its debt at a level less than the maximum amount
of its total bank facility to ensure financial flexibility to deal with
unforeseen or rapidly changing circumstances.
12. CAPITAL MANAGEMENT
Capital management is fundamental to the Company's objective of cost-effective
production growth, while simultaneously replacing continuous production
declines. The Company's capital comprises shareholders' equity, bank
indebtedness and working capital. Capital management involves the preparation of
an annual budget, which may only be implemented after approval by the Company's
Board of Directors. As the Company's business evolves during the fiscal year,
the budget may be amended; however, any changes are again subject to approval by
the Board of Directors. As part of the budget process, and as part of capital
management control procedures, the Company continuously uses a non-GAAP
measurement of net debt to cash flow to measure and control debt levels during
the fiscal year. Debt to cash flow is also used by the Company's bankers to set
the stamping fee applicable to the Company's bank indebtedness.
The measurement is established as follows:
March 31, 2010 December 31, 2009
----------------------------------------------------------------------------
Current assets, less fair value of
financial instruments $ 21,756 $ 19,387
Accounts payable and accrued liabilities 33,900 25,661
----------------------------------------------------------------------------
Working capital deficiency 12,144 6,274
Bank indebtedness 99,137 86,758
----------------------------------------------------------------------------
Net debt $ 111,281 $ 93,032
Year-to-date annualized funds from
operations $ 70,404 $ 44,596
Net debt to non-GAAP funds from
operations 1.6:1 2.1:1
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 decrease in this
ratio at March 31, 2010 is a result of increased cash flow in 2010 due to higher
commodity prices.
The Company's credit availability is based on the Company's producing reserves.
The non-GAAP measurement of net debt to funds from operations is used to
determine the interest rate applied to the Company's bank indebtedness, with
interest rates changing at certain threshold levels of net debt to cash flow.
The Company's bankers are entitled to complete a year-end and a mid-year
evaluation of the Company's borrowing base, which, in circumstances of falling
commodity prices, negative changes to the Company's operating activities, or
credit limitations affecting the Company's banking syndicate, may result in a
decrease in the line of credit available to the Company. The Company's bankers
completed a year-end evaluation of the Company's borrowing base and have
increased the bank facility to $140 million.
From time to time, the Company may enter into hedging arrangements if capital
programs or acquisition costs result in a high net debt to cash flow ratio. Such
arrangements provide for stability of cash flow during periods when the Company
applies cash flow to reduce its net debt.
Increased debt levels arising from acquisitions, or capital programs exceeding
cash flow, may be addressed by reduced capital expenditures, disposal of
non-core assets or the issue of common shares.
13. COMMITMENTS
The Company has the following fixed-term commitments relating to its ongoing
business:
2010 2011 2012 2013 2014
----------------------------------------------------------------------------
Lease of premises $ 619 $ 838 $ 838 $ 419 $ -
Equipment leases 126 132 67 9 1
Gas transportation and
processing commitments 1,295 1,434 887 486 240
----------------------------------------------------------------------------
Total $ 2,040 $ 2,404 $ 1,792 $ 914 $ 241
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Senior Management
Brian Lavergne Harry Ediger
President & CEO Vice President, Land
Robert S. Tiberio Eric Blakely
Chief Operating Officer Vice President, Exploration
Donald G. McLean John Devlin
Vice President, Finance & CFO Controller
Directors
Matthew J. Brister (1) (2) Brian Lavergne
CEO
John A. Brussa (3)
Gregory G. Turnbull (3)
Mark Butler (3) Corporate Secretary
Stuart G. Clark (1) P.Grant Wierzba (2)
Chairman
James K. Wilson (1)
(1) Member, Audit Committee (2) Member, Reserves Committee (3) Member,
Compensation, Governance and Nomination Committee
----------------------------------------------------------------------------
Stock Exchange Listing Registrar & Transfer Agent
Toronto Stock Exchange
Trading Symbol SEO Alliance Trust Company
Solicitors Calgary, Alberta
McCarthy Tetrault LLP
Burnet Duckworth & Palmer LLP Executive Offices
Calgary, Alberta
Suite 800, 205 - 5(th) Avenue S.W.
Auditors Calgary, Alberta, T2P 2V7 Canada
Tel: (403) 264-3520 Fax: (403) 264-3552
PricewaterhouseCoopers LLP www.stormexploration.com
Calgary, Alberta
Bankers
Reserve Engineers
CIBC, Oil & Gas Group
Paddock Lindstrom & Associates Ltd. Bank of Montreal
Calgary, Alberta Union Bank
ATB Financial
Calgary, Alberta
----------------------------------------------------------------------------
Abbreviations
3-D Three-dimensional
API American Petroleum Institute
ARTC Alberta Royalty Tax Credit
Bbls Barrels of oil or natural gas liquids
Bbls/d Barrels per day
Bcf Billions of cubic feet
Bcfe Billions of cubic feet equivalent
Boe Barrels of oil equivalent
Boe/d Barrels of oil equivalent per day
Bopd Barrels of oil per day
Cdn$ Canadian dollar
DPIIP Discovered Petroleum Initially in Place
ETAP Entreprise Tunisienne d Activites Petrolieres
FPSO Floating, Production, Storage, Offloading vessel
GJ Gigajoules
GJ/d Gigajoules per day
Mbbls Thousands of barrels
Mboe Thousands of barrels of oil equivalent
Mcf Thousands of cubic feet
Mcf/d Thousands of cubic feet per day
Mmbbls Millions of barrels
Mmbtu Millions of British Thermal Units
Mmbtu/d Millions of British Thermal Units per day
Mmcf Millions of cubic feet
Mmcf/d Millions of cubic feet per day
Mstb Thousand stock tank barrels
NAV Net Asset Value
NGL Natural gas liquids
NPV Net present value
OGIP Original Gas in Place
OPEC Organization of Petroleum Exporting Countries
Scf/ton Standard cubic foot per ton
STOOIP Stock Tank Original Oil in Place
Tcf Trillions of cubic feet
TSX Toronto Stock Exchange
US$ United States dollar
WTI West Texas Intermediate
----------------------------------------------------------------------------
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