Storm Resources Ltd. (TSX VENTURE:SRX)
Storm has also filed its unaudited consolidated condensed interim financial
statements as at June 30, 2012 for the three and six months then ended along
with the Management's Discussion and Analysis ("MD&A") for the same period. This
information appears on SEDAR at www.sedar.com and on Storm's website at
www.stormresourcesltd.com.
Selected financial and operating information for the three and six months ended
June 30, 2012 appears below and should be read in conjunction with the related
unaudited consolidated condensed interim financial statements and MD&A.
Highlights
Three Three Six Six
Months to Months to Months to Months to
Thousands of Cdn$, except June 30, June 30, June 30, June 30,
volumetric and per-share amounts 2012 2011 2012 2011
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FINANCIAL
Oil sales 6,954 748 8,613 1,231
Gas sales 1,648 1,011 2,803 1,412
NGL sales 1,205 177 1,781 274
Royalty income 12 - 12 -
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Production revenue 9,819 1,936 13,209 2,917
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Funds from operations(1) 3,669 710 3,606 769
Per share - basic ($) 0.07 0.03 0.07 0.03
Per share - diluted ($) 0.07 0.03 0.07 0.03
Net income (loss) 947 (562) (668) (883)
Per share - basic ($) 0.03 (0.02) (0.01) (0.03)
Per share - diluted ($) 0.03 (0.02) (0.01) (0.03)
Field capital expenditures, net
of dispositions 7,223 2,012 9,430 11,714
Net (debt)/working capital (53,667) 12,224 (53,667) 12,224
Weighted average common shares
outstanding (000s)
Basic 61,824 26,377 50,247 26,377
Diluted 61,847 26,377 50,247 26,377
Common shares outstanding (000s)
Basic 61,824 26,377 61,824 26,377
Fully diluted 64,547 28,391 64,547 28,391
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OPERATIONS
Oil equivalent (6:1)
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Barrels of oil equivalent (000s) 235 54 347 79
Barrels of oil equivalent per
day 2,584 595 1,906 436
Average selling price (Cdn$ per
Boe) 41.71 35.74 38.03 36.93
Oil Production
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Barrels (000s) 83 7 102 13
Barrels per day 915 80 562 69
Average selling price (Cdn$ per
barrel) 83.48 103.20 84.22 97.85
Gas production
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Thousand cubic feet (000s) 809 269 1,324 379
Thousand cubic feet per day 8,895 2,958 7,277 2,094
Average selling price (Cdn$ per
Mcf) 2.04 3.76 2.12 3.72
NGL Production
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Barrels (000s) 17 2 24 3
Barrels per day 186 22 132 18
Average selling price (Cdn$ per
barrel) 71.22 86.53 74.38 85.50
Wells drilled
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Gross - - 1.0 -
Net - - 1.0 -
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(1) Funds from operations and funds from operations per share are non-GAAP
measurements. See discussion of Non-GAAP Measurements on page 8 of the MD&A and
the reconciliation of funds from operations to the most directly comparable
measurement under GAAP, "Cash Flows from Operating Activities", on page 17 of
the MD&A.
PRESIDENT'S MESSAGE
SECOND QUARTER 2012 HIGHLIGHTS
-- Production increased by 335% from the year ago period to average 2,584
Boe per day which included 1,101 barrels per day of oil plus natural gas
liquids ("NGL") and 8.9 Mmcf per day of natural gas. Natural gas wells
shut in during early May due to the decline in the price of natural gas
reduced quarterly production by 360 Boe per day. Production was also
reduced by 220 Boe per day due to the failure of a pipeline plus
numerous mechanical failures on wells in the Grande Prairie area.
-- As a result of the Bellamont Exploration Ltd. ("Bellamont") transaction
completed on March 23rd, crude oil and NGL production increased to 43%
of the production mix from 17% in the second quarter of 2011.
-- On a per-share basis, quarterly production of 42 Boe per day per million
shares outstanding is a year-over-year increase of 90%.
-- The fourth horizontal well at Umbach was completed in June, tested at an
average rate of 3.8 Mmcf per day, plus 40 barrels per day of condensate,
over a 41-hour flow period and is expected to commence production in
late August after the four kilometer pipeline tie-in is completed.
-- Funds from operations totaled $3.7 million ($15.60 per Boe) or $0.07 per
basic share which is a 415% improvement from the year earlier period
where funds from operations was $0.7 million. This was primarily the
result of the Bellamont transaction which increased total production and
increased the proportion of higher priced crude oil and NGL production.
-- Revenue was $41.71 per Boe, an increase of 17% from the year ago period
which was due to the higher proportion of crude oil and NGL production
which more than offset a 46% decrease in the wellhead price of natural
gas.
-- Field operating netback averaged $22.07 per Boe which includes a $1.60
per Boe hedging gain, operating costs of $11.56 per Boe, transportation
costs of $2.97 per Boe and royalties of $5.16 per Boe (13% of total
revenue).
-- Capital investment totaled $7.2 million with $3.9 million invested in
exploration and development activities plus $2.7 million to acquire a
gas plant at Grimshaw.
-- A hedging gain of $0.4 million was realized as a result of fixed price
financial hedges that were put in place to protect the 2012 capital
investment program. Commodity price hedges currently include 450 barrels
of oil per day at Cdn $103.35 to $107.75 per barrel from April to
December, 2012 and 4,500 GJ per day of natural gas (approximately 4 Mmcf
per day) at $2.20 per GJ from July to September, 2012.
-- At June 30, 2012, Storm's debt and working capital deficiency was $53.7
million. After including the value of Storm's investment in publicly
listed companies ($7.5 million at June 30), net debt was $46.2 million.
Storm's bank line is $70.0 million.
OPERATIONS REVIEW
Storm has a focused asset base with an inventory of light oil exploitation
opportunities in the Grande Prairie Area and large land positions in resource
plays at Umbach and in the Horn River Basin ("HRB") which have multi-year
drilling upside.
Umbach, North East British Columbia
Storm's current land holdings at Umbach total 103 gross sections, or 79 net
sections, (57,000 net undeveloped acres) all of which are prospective for
liquids rich natural gas from the Montney formation. Production in the second
quarter averaged 313 Boe per day (27% liquids) at an operating netback of $14.16
per Boe. Liquids recovery was 61 Bbls per Mmcf with approximately 45% being
produced condensate plus pentanes recovered during processing.
The fourth horizontal well was completed in the second quarter with ten
100-tonne fracture stimulations. The flow test was 41 hours in duration with the
average rate being 3.8 Mmcf per day gross raw gas plus 40 barrels per day of
condensate at a final wellhead flowing pressure of 915 psig (cumulative gas
produced during the flow period was 6.5 Mmcf). The test rate and flow period is
generally consistent with earlier horizontal wells, however, the final wellhead
flowing pressure was higher.
Storm's activity in 2012 is focused on drilling horizontal wells to continue
delineating the areal extent of the resource in the Montney formation and to
cost effectively increase rates and reserves per horizontal. Currently, three
horizontal wells are producing from the Montney formation with production
history for each horizontal being regularly updated and shown in the
presentation on Storm's website www.stormresourcesltd.com. The fourth horizontal
well is expected to begin producing in late August after construction of the 4
kilometer pipeline tie-in is completed. First year average rates are ranging
from 0.7 to 1.6 Mmcf per day gross raw gas (145 to 330 Boe per day sales). To
date, the gross cost to drill and complete each horizontal has averaged $5.3
million with tie-in costs averaging $0.6 million. Costs will decline on future
horizontal wells as existing pads are used (reduces lease and pipeline
construction costs) and as logged vertical pilot holes are eliminated. The fifth
horizontal well (60% working interest) is currently being drilled and it is
expected that a total of two to four horizontal wells (0.6 net to 1.8 net) will
be drilled in the second half of 2012. Completion and tie-in of the fifth and
sixth horizontal wells is planned for the second half of 2012 and, if additional
horizontal wells are drilled, they would be completed in the first quarter of
2013. On the next horizontal wells, improvements in rates and reserves are
expected from lowering the wellbore 10 to 15 metres to access more of the
Montney formation and by increasing the intensity of the fracture stimulations
(less sand tonnage on reduced spacing and a larger fluid volume by switching
from emulsified CO2 to slickwater).
Grande Prairie Area, North West Alberta and North East British Columbia
Production in this area comes from the Mica property in North East British
Columbia and from the properties acquired through the transaction with Bellamont
which closed March 23rd. Second quarter production averaged 1,716 Boe per day
(58% oil plus NGL) with the operating netback averaging $24.60 per Boe.
Production in the second quarter was impacted by numerous mechanical failures
(loss of 220 Boe per day) and by the shut-in of natural gas wells in early May
producing 3.0 Mmcf per day (loss of 360 Boe per day for the quarter). Current
production capability totals approximately 2,300 Boe per day (150 Boe per day
from Mica) which includes shut-in volumes.
A horizontal well was drilled into the Grande Prairie Dunvegan C light oil pool
in July. It is expected that this well will be completed and tied in by the end
of September.
At Grimshaw, a horizontal well was converted to an injector in the Montney in
July and water injection will commence in late August once all regulatory
approvals have been received. This will result in operating costs being reduced
by approximately $0.5 million per year as produced water is re-injected instead
of being trucked for disposal. The vertical well in the new Montney pool
discovery drilled by Bellamont in late 2011 has averaged 18 barrels of oil per
day since production began in mid-June. Solution gas conservation was initiated
in early June which added 60 Boe per day at a cost of approximately $3 million
to acquire a small gas plant and install a small choke plant to remove natural
gas liquids.
The Grande Prairie area is relatively mature with shallower declines
(approximately 20% per year) and a higher proportion of light oil and NGL
production resulting in a higher operating netback. There is a large inventory
of light oil opportunities in this area including 15 to 30 horizontal wells to
be drilled targeting light oil in the Doe Creek, Dunvegan, Charlie Lake and
Montney formations. There is additional upside associated with initiating
waterfloods in the Montney formation at Grimshaw and in the Charlie Lake
formation at Mica. Storm is planning to re-invest approximately 60% to 70% of
cash flow from this area in maintaining production and the remaining 'free cash
flow' will be directed to advancing exploitation of the Montney formation at
Umbach, which is a larger scale growth opportunity. No further drilling activity
is planned for this area in 2012. In 2013, drilling activity is expected to
include four to six horizontal wells into the Montney at Grimshaw, the Montney I
pool at Grande Prairie, and the Doe Creek and Charlie Lake formations at Saddle
Hills.
Horn River Basin, North East British Columbia
Storm's undeveloped land position in the HRB totals 135 sections at a 100%
working interest (87,700 net acres) and is prospective for natural gas from the
Muskwa, Otter Park and Evie/Klua shales. During the second quarter, production
in the HRB averaged 525 Boe per day at an operating netback of $3.88 per Boe.
The resource in the Muskwa and Otter Park shales is large with the best estimate
of DPIIP in the core producing area being 3.1 Tcf gross raw gas (evaluated by
InSite Petroleum Consultants Ltd. December 31, 2011). The core producing area is
30 gross sections in size (22% of Storm's total land holdings in the HRB) and
productivity has been proven across the area with one horizontal well that has
been on production for 17 months and two vertical wells which were completed
with each well having a final test rate of 0.9 Mmcf per day over the last 24
hours (flow test durations totaled 370 and 279 hours with respective gas
production totaling 16 Mmcf and 9 Mmcf).
Production performance of the first horizontal well (100% Storm) with 12
fracture stimulations continues to exceed expectations with the current rate
being 3.0 to 3.5 Mmcf per day gross raw gas and cumulative production to date of
2.5 Bcf gross raw gas since production commenced on March 7, 2011. The flow rate
is restricted since the pressure in the raw gas gathering pipeline is high and
compression has not yet been installed. Significant improvements in productivity
and reserves are expected on future horizontals by increasing fracture density
(15 to 18 fracture stimulations per horizontal) and by installing field
compression.
Activity in the HRB is being deferred until natural gas prices improve.
INVESTMENTS
At the end of first quarter, Storm had share ownership positions in two publicly
traded companies. The value of the share positions in the two public companies
totaled $7.5 million at the end of the quarter and these securities could
possibly be sold in the future with the proceeds being used to finance the
Company's capital programs.
Chinook Energy Inc. ("Chinook")
Storm holds 4.5 million shares of Chinook which is a TSX-listed oil and gas
exploration and production company (symbol 'CKE') based in Calgary with
operations focused in Tunisia and western Canada.
Bridge Energy ASA ("Bridge")
Storm holds 1.05 million common shares of Bridge (symbol 'Bridge' on the Oslo
Stock Exchange), a Norwegian-based exploration and production company with
production of approximately 1,500 Boe per day (33% light oil) from the UK sector
of the North Sea.
OUTLOOK
Production in the third quarter is forecast to average 2,400 to 2,600 Boe per
day (43% liquids) and this assumes 3 Mmcf per day of natural gas at Grande
Prairie remains shut in until natural gas prices at AECO are greater than $2.75
to $3.00 per GJ. On July 25th, the sale of a 20% working interest in two
producing wells at Red Earth (17 barrels per day light oil) was closed for
proceeds totaling $2.4 million. Debt plus the working capital deficiency is
targeted to be approximately $50 million at the end of 2012 (including the value
of the publicly listed securities owned by Storm) which will result in capital
investment being adjusted higher or lower depending on actual commodity prices
and asset dispositions. Planned capital investment in 2012 is unchanged at
approximately $28 million, however, due to unexpected capital expenditures on
the properties acquired from Bellamont, drilling activity is being reduced to
four to seven gross wells (3.2 to 5.4 net) from six to eight gross wells (5.2 to
7.2 net). Activity will now include one vertical delineation well (1.0 net) at
Umbach, two to four horizontal wells (1.2 to 2.4 net) at Umbach, completing one
standing horizontal well (0.6 net) at Umbach, and one to two horizontal wells
(all 100% working interest) targeting light oil opportunities in the Grande
Prairie Area. The reduction in drilling activity results in a reduction to
fourth quarter production rates which are now forecast to average 2,600 to 2,800
Boe per day (41% liquids). This assumes 500 Boe per day remains shut in due to
low natural gas prices and that the fifth and sixth horizontal wells at Umbach
are completed and tied in before year end. Storm is currently forecasting
commodity prices in 2012 average $2.20 per GJ at AECO for natural gas and Cdn
$85.00 per barrel Edmonton Par for crude oil.
Updated 2012 Guidance
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Forecast Q3 production after deducting 5% for 2,400 to 2,600 Boe per day
unplanned outages (43% oil + NGLs)
Bank credit facility $70.0 million
2012 average operating costs $10 to $12 per Boe
2012 average royalty rate 12% to 15%
2012 operations capital, excluding dispositions $28.0 million
2012 cash G&A(1) $3.5 to $3.8 million
2012 exit or fourth quarter average production 2,600 to 2,800 Boe per day
(41% oil + NGLs)
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(1) Excludes transaction costs which are required to be expensed under IFRS.
Hedging will be done on a more regular basis going forward in order to smooth
out commodity price volatility and protect capital investment. Early in the
second quarter, Storm entered into financial hedges on 450 barrels of oil per
day for April to December 2012 and on 4,500 GJ per day of natural gas for July
to September 2012. It's unlikely that any further hedging will be done for 2012
volumes. In general, Storm's hedges will be done on a financial basis (won't
require physical delivery), will be shorter term at 9 to 18 months duration and
will cover 40% to 45% of current production.
During the second quarter, significant time and effort was expended on
assimilating the properties acquired with the Bellamont transaction that closed
on March 23rd. Numerous operational problems were encountered in the second
quarter on the Bellamont properties which resulted in significant downtime and
reduced production. The additional unplanned capital expenditures to fix the
problems have impacted debt by approximately $10 million (assumed debt at
closing was $4 million higher than expected plus $6 million has been spent to
date on operational problems). In order to offset the financial impact of the
incremental spending on the Bellamont properties, drilling activity has been
reduced which will impact Storm's production growth in 2012. Offsetting this are
operating cost reductions totaling $1.8 million per year that have been realized
to date on the Bellamont properties as a result of a greater focus on cost
control and profitability.
Although there have been many challenges associated with integrating the
Bellamont properties, the addition of higher netback, light oil production with
a relatively shallow decline provides us with the 'free cash flow' to continue
delineation of the liquids rich Montney resource on Storm's large land position
at Umbach. Initial results at Umbach have been very encouraging and improvement
is expected on future horizontal wells by lowering the wellbore to access a
thicker interval and by increasing the intensity of the fracture stimulation in
the completions. With a 25% improvement in the first year average rate,
horizontal wells are expected to generate a 20% to 25% rate of return using
current forward strip pricing for oil and natural gas (approximately $3 per GJ
at AECO and $85 per barrel Edmonton Par).
Near term, Storm is focused on advancing the Montney at Umbach which could
generate significant economic growth in production at the current forward strip
for crude oil and natural gas prices given liquids recovery of 60 barrels per
Mmcf and lower capital costs associated with a shift to development drilling.
Longer term, significant leverage to an improvement in natural gas prices is
offered by the very large DPIIP in the Muskwa and Otter Park shales of the HRB.
The hard work and effort of Storm's employees and the continued patience of
Storm's shareholders is greatly appreciated and we look forward to providing
updates on our progress over the remainder of this year and into 2013.
Respectfully,
Brian Lavergne, President and Chief Executive Officer
August 13, 2012
Discovered-Petroleum-Initially-in-Place ("DPIIP") - is defined in the Canadian
Oil and Gas Evaluation Handbook ("COGEH") as the quantity of hydrocarbons that
are estimated to be in place within a known accumulation. DPIIP is divided into
recoverable and unrecoverable portions, with the estimated future recoverable
portion classified as reserves and contingent resources. There is no certainty
that it will be economically viable or technically feasible to produce any
portion of this DPIIP except for those portions identified as proved or probable
reserves.
Contingent Resources - are those quantities of petroleum estimated, as of a
given date, to be potentially recoverable from known accumulations using
established technology or technology under development, but which are not
currently considered to be commercially recoverable due to one or more
contingencies. Contingencies may include factors such as economic, legal,
environmental, political and regulatory matters, or a lack of markets. It is
also appropriate to classify as contingent resources the estimated discovered
recoverable quantities associated with a project at an early stage of
development. Estimates of contingent resources described herein are estimates
only; the actual resources may be higher or lower than those calculated in the
independent evaluation. There is no certainty that the resources described in
the evaluation will be commercially produced.
Boe Presentation - For the purpose of calculating unit revenues and costs,
natural gas is converted to a barrel of oil equivalent ("Boe") using six
thousand cubic feet ("Mcf") of natural gas equal to one barrel of oil unless
otherwise stated. Boe may be misleading, particularly if used in isolation. A
Boe conversion ratio of six Mcf to one barrel ("Bbl") is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead. All Boe measurements and
conversions in this report are derived by converting natural gas to oil in the
ratio of six thousand cubic feet of gas to one barrel of oil. Mboe means 1,000
Boe.
Forward-Looking Information - This press release contains forward-looking
statements and forward-looking information within the meaning of applicable
securities laws. The use of any of the words "will", "expects", "believe",
"plans", "potential" and similar expressions are intended to identify
forward-looking statements or information. More particularly, and without
limitation, this press release contains forward-looking statements and
information concerning: production; drilling plans; reserve volumes; capital
expenditures; royalties; and production and general and administrative costs.
The forward-looking statements and information in this press release are based
on certain key expectations and assumptions made by Storm, including: prevailing
commodity prices and exchange rates; applicable royalty rates and tax laws;
future well production rates; reserve and resource volumes; the performance of
existing wells; success to be expected in drilling new wells; the adequacy of
budgeted capital expenditures to carrying out planned activities; the
availability and cost of services; and the receipt, in a timely manner, of
regulatory and other required approvals. Although the Company believes that the
expectations and assumptions on which such forward-looking statements and
information are based are reasonable, undue reliance should not be placed on
these forward-looking statements and information because of their inherent
uncertainty. In particular, there is no assurance that exploitation of the
Company's undeveloped lands and prospects will result in the emergence of
profitable operations.
Since forward-looking statements and information address future events and
conditions, by their very nature they involve inherent risks and uncertainties.
Actual results could differ materially from those currently anticipated due to a
number of factors and risks. These include, but are not limited to the risks
associated with the oil and gas industry in general such as: operational risks
in development, exploration and production; delays or changes in plans with
respect to exploration or development projects or capital expenditures; the
uncertainty of reserve estimates; the uncertainty of estimates and projections
relating to reserves, production, costs and expenses; health, safety and
environmental risks; commodity price and exchange rate fluctuations; marketing
and transportation of petroleum and natural gas and loss of markets;
environmental risks; competition; ability to access sufficient capital from
internal and external sources; stock market volatility; and changes in
legislation, including but not limited to tax laws, royalty rates and
environmental regulations.
Readers are cautioned that the foregoing list of factors is not exhaustive.
Additional information on these and other factors that could affect the
operations or financial results of the Company are included or are incorporated
by reference in the company's MD&A for the three and six months ended June 30,
2012.
The forward-looking statements and information contained in this press release
are made as of the date hereof and the Company undertakes no obligation to
update publicly or revise any forward-looking statements or information, whether
as a result of new information, future events or otherwise, unless so required
by applicable securities laws.
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