Arsenal (TSX:AEI) is pleased to release its Q4 and full year 2010 financial
results and yearend 2010 reserve report. Q4 results are highlighted by a 47%
increase in cash flow vs. Q409 due to increases in production and reductions in
unit costs. Proven plus probable reserves grew 20% from 8.6 million boe to 10.4
million boe for an all in FD&A cost of $10.13/boe. Most of the added reserves
are high quality, low cost Bakken oil reserves in North Dakota.
Financial
Cash flow from operations in the fourth quarter was $5.1 million ($0.04/share).
This is an increase of 47% vs. the comparable period in 2009. The increase is
due to a 14% increase in production volumes, a 20% decrease in unit operating,
transportation, and royalty costs, and a 48% decrease in unit overhead and
financing charges. These improvements were partially offset by lower unit
revenue due to lower price realizations for natural gas. Annual cash flow of
$18.3 million was flat year over year but 2009 included $9.2 million in hedge
realizations vs. $1.8 million in 2010. Net income for the quarter was nil but
continues the quarterly trend toward profitability.
Capital expenditures for Q4 2010 totaled $13.0 million increasing 272% over the
$3.5 million expended in Q4 2009. Total debt at yearend was $18.8 million. A
subsequent $20 million net equity raise in the first quarter has left the
company essentially debt free.
Operations
Average production of 2132 boe/d for Q4 was an increase of 14% from Q4 2009.
This increase is attributable to growing production volumes from the Bakken in
North Dakota partially offset by noncore property sales.
Arsenal's Q4 production mix was 76% oil and liquids and 24% natural gas. Lower
natural gas prices resulted in 8% lower overall boe prices vs. 2009 but
operating netbacks of $29.28/boe were slightly higher due to lower operating
costs and royalties. Operating costs decreased to $16.98/boe in Q4 2010 from
$19.94/boe in 2009. This decrease is due to the averaging in of lower cost
Bakken production and the sale of noncore high cost production. Operating
margins should continue to improve as additional Bakken production is brought
on.
Arsenal participated in the drilling of 10.2 net wells in the fourth quarter.
Results of those wells have been previously released. Due to a severe shortage
of equipment and trained people in North Dakota, Arsenal's production growth has
been slower than anticipated. Although frustrating, these problems are common in
booms like North Dakota and Arsenal anticipates that they will work themselves
out over the medium term.
SUMMARY OF FINANCIAL AND OPERATIONAL RESULTS
Three Months Ended December 31
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2010 2009 % Change
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FINANCIAL
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Oil and gas revenue 11,250,143 10,759,516 5
Cash provided by operation
activities 5,490,041 4,012,924 37
Funds from operations(1) 5,119,249 3,471,910 47
Per share - basic 0.04 0.03 9
- diluted 0.04 0.03 6
Net loss (233,679) (2,845,384) (92)
Per share - basic - (0.03) -
- diluted - (0.03) -
Total debt 18,787,775 28,739,421 (35)
Capital expenditures 12,989,217 3,491,484 272
Property acquisitions 2,184,049 479,084 356
Property dispositions - (634,095) -
Wells drilled (net)
Oil 4.83 1.50 222
Gas 1.00 - -
Drilling at year end 1.40 - -
Dry 3.00 1.25 140
----------------------------------
Total net wells drilled 10.23 2.75 272
Shares outstanding - end of
year 140,812,472 120,461,890 17
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OPERATIONAL
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Daily production
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Heavy oil (bbl/d) 556 721 (23)
Light oil and NGLs (bbl/d) 1,055 851 24
Natural gas (mcf/d) 3,131 1,804 74
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Oil equivalent (boe @ 6:1)(2) 2,132 1,872 14
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Realized commodity prices
($Cdn.)
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Heavy oil (bbl) 66.81 65.65 2
Light oil and NGLs (bbl) 71.17 72.06 (1)
Natural gas (mcf) 3.23 4.62 (30)
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Oil equivalent (boe @ 6:1) 57.36 62.48 (8)
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Operating netback ($ per boe)
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Revenue 57.36 62.48 (8)
Royalty (9.95) (12.57) (21)
Operating cost (16.98) (19.94) (15)
Transportation cost (1.15) (2.62) (56)
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Operating netback per boe 29.28 27.36 7
General and administrative (3.57) (6.23) (43)
Finance charges and fees (0.83) (2.22) (63)
Other (0.14) 0.16 (189)
Realized hedging gains
(losses) 1.36 1.09 25
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Cash flow per Boe 26.10 20.16 29
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Year Ended December 31
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2010 2009 % Change
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FINANCIAL
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Oil and gas revenue 43,665,720 36,941,862 18
Cash provided by operation
activities 13,168,825 18,102,343 (27)
Funds from operations(1) 18,295,623 18,706,728 (2)
Per share - basic 0.14 0.18 (24)
- diluted 0.13 0.18 (25)
Net loss (7,675,077) (11,050,516) (31)
Per share - basic (0.06) (0.11) (46)
- diluted (0.06) (0.11) (46)
Total debt 18,787,775 28,739,421 (35)
Capital expenditures 28,042,311 10,471,357 168
Property acquisitions 2,259,529 479,084 372
Property dispositions (5,919,077) (4,121,234) 44
Wells drilled (net)
Oil 7.11 2.51 183
Gas 1.00 - -
Drilling at year end 1.40 - -
Dry 3.00 1.25 140
----------------------------------
Total net wells drilled 12.51 3.76 233
Shares outstanding - end of
year 140,812,472 120,461,890 17
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OPERATIONAL
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Daily production
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Heavy oil (bbl/d) 603 754 (20)
Light oil and NGLs (bbl/d) 985 792 24
Natural gas (mcf/d) 3,032 3,235 (6)
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Oil equivalent (boe @ 6:1)(2) 2,093 2,085 0
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Realized commodity prices
($Cdn.)
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Heavy oil (bbl) 64.48 55.20 17
Light oil and NGLs (bbl) 69.99 59.02 19
Natural gas (mcf) 3.91 3.97 (2)
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Oil equivalent (boe @ 6:1) 57.17 48.54 18
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Operating netback ($ per boe)
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Revenue 57.17 48.54 18
Royalty (10.25) (8.91) 15
Operating cost (18.38) (17.98) 2
Transportation cost (1.07) (1.42) (25)
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Operating netback per boe 27.46 20.22 36
General and administrative (4.61) (4.63) (0)
Finance charges and fees (1.34) (2.09) (36)
Other 0.09 (1.02) (109)
Realized hedging gains
(losses) 2.34 12.10 (81)
---------------------------------------------------------------
Cash flow per Boe 23.95 24.58 (3)
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(1)"Funds from operations", "funds from operations per share", "netbacks" and
"netbacks per boe" are not defined by Generally Accepted Accounting Principles
("GAAP") in Canada and are regarded as non-GAAP measures. Funds from operations
and funds from operations per share are calculated as cash provided by operating
activities before changes in non-cash working capital and asset retirement
expenditures. Funds from operations is used to analyze the Company's operating
performance, the ability of the business to generate the cash flow necessary to
fund future growth through capital investment and to repay debt. Funds from
operations does not have a standardized measure prescribed by GAAP and therefore
may not be comparable with the calculations of similar measures for other
companies. The Company also presents funds from operation per share whereby per
share amounts are calculated using the weighted average number of common shares
outstanding consistent with the calculation of net income or loss per share.
(2) The term barrels of oil equivalent ("boe") may be misleading, particularly
if used in isolation. A boe conversion ratio of six thousand cubic feet per
barrel (6 mcf/bbl) of natural gas to barrels of oil equivalence 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 conversions in
the report are derived from converting gas to oil in the ratio mix of six
thousand cubic feet of gas to one barrel of oil.
Reserves Summary
Reserves as at December 31, 2010, as independently evaluated by AJM Petroleum
Consultants ("AJM"), in accordance with National Instrument 51-101 Standards of
Disclosure for Oil and Gas Reserves ("NI 51-101"). Arsenal's full NI 51-1-1 F1 -
Statements of Reserves Data and Other Oil and Gas Information is filed in
Arsenal's Annual Information Form on SEDAR - "www.SEDAR.com
The following tables summarize certain information related to Arsenal's oil and
gas reserves as of December 31, 2010 based on forecast price and cost
assumptions:
Natural Gas
Light / Medium Oil Heavy Oil Liquids
----------------------------------------------------------------------------
Gross Net Gross Net Gross Net
(Mbbl)(1) (Mbbl)(2) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
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Proved
Producing 2289 1862 187 169 143 110
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Proved Non
Producing 172 145 30 27 5 3
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Proved
Undeveloped 3545 2729 19 17 16 13
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Total
Proved 6006 4736 235 214 163 126
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Probable 2474 1956 371 322 58 45
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Total
Proved +
Probable 8480 6692 606 535 221 172
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Barrels of Oil
Natural Gas Equivalent (3)
------------------------------------------------------
Gross Net Gross Net
(MMcf) (MMcf) (MBOE) (MBOE)
------------------------------------------------------
Proved
Producing 3774 3126 3247 2663
------------------------------------------------------
Proved Non
Producing 722 605 326 277
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Proved
Undeveloped 392 312 3645 2810
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Total
Proved 4887 4043 7219 5750
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Probable 2066 1699 3248 2606
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Total
Proved +
Probable 6954 5741 10466 8355
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Reserves Values
The estimated future net revenues before taxes associated with Arsenal's
reserves effective December 31, 2010 and based on the AJM future price forecast
are summarized in the following table:
0 % DCF 5 % DCF 10 % DCF 15 % DCF
(MM$ Cdn) (MM$ Cdn) (MM$ Cdn) (MM$ Cdn)
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Proved Producing 117 82 65 55
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Proved Non Producing 14 9 7 6
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Proved Undeveloped 215 112 71 49
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Total Proved 346 203 143 110
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Probable 243 101 58 39
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Total Proved +
Probable 589 304 201 150
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Price Forecast
AJM employed the following pricing, exchange rate, and inflation rate
assumptions in estimating Arsenal's reserve data as of
December 31, 2010:
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NGLs
WTI Edmonton Edmonton
Cushing Par Price Natural Gas Butanes
Year Oklahoma 40 API AECO-C Price Plant Gate
Forecast ($US/Bbl) ($Cdn/Bbl) ($Cdn/MMBtu) ($Cdn/Bbl)
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2011 85.00 82.80 4.10 70.40
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2012 89.25 88.80 4.60 75.50
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2013 91.55 94.05 5.20 79.95
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2014 95.50 98.15 5.50 83.45
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2015 102.85 105.80 5.75 89.95
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Thereafter + 2 %/yr + 2 %/yr + 2 %/yr + 2 %/yr
----------------------------------------------------------------------------
-------------------------------------------------------------
NGLs
Edmonton
Pentanes Inflation Exchange
Year Plant Gate Rate Rate
Forecast ($Cdn/Bbl) (%) ($US/$Cdn)
-------------------------------------------------------------
2011 86.95 0.00 1.00
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2012 93.25 2.00 0.98
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2013 98.75 2.00 0.95
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2014 103.50 2.00 0.95
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2015 111.10 2.00 0.95
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Thereafter + 2 %/yr 2 %/yr 0.95
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Year End Reconciliation
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Open Close
Dec.31, Acquired Production Activity Dec. 31,
2009 /Sold (4) Adds Revisions 2010
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TP (MBOE) 5,618 392 (764) 765 1,208 7,219
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TP Value (10%
DNAV MM$
Cdn) 132 -4 -21 14 22 143
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P+P (MBOE) 8,662 371 (764) 1,078 1,119 10,466
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P+P Value
(10% DNAV
MM$ Cdn) 202 -4 -21 10 14 201
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Based on the Q4 estimated production rate of 2,132 Boe/d, Arsenal has a reserve
life of 9.3 years based on total proved and 13.4 years based on proved plus
probable reserves.
Reserves Addition Costs
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Change in
Reserve Future
Adds 2010 Capex Capex FD&A Costs
(MBOE) (K$ Cdn) (K$ Cdn) ($/BOE)
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Total Proved 2,366 24,383 (5) 5,052 12.44
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Total Proved + Probable 2,568 24,383 1,637 10.13
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On a total proved basis, reserves increased by 1,602 MBoe and reserves per 1
million shares increased by 4,700 Boe (10 %). Additions replaced production by
209%.
On a total proved plus probable basis, reserves increased by 1,804 MBoe and
reserves per 1 million shares increased by 2,500 Boe (3.5 %). Additions replaced
production by 236%.
Year End Net Asset Value
The following tables summarize certain information related to Arsenal's oil and
gas reserves as of December 31, 2010 based on forecast price and cost
assumptions:
31-Dec-06 31-Dec-07 31-Dec-08 31-Dec-09 31-Dec-10
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P+P PV (10% DNAV
MM$) 77.1 87.6 166.4 200.8 201.4
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Land (MM$) 1.5 1.5 2.0 2.0 6.4(6)
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Seismic (MM$) 0.3 0.8 0.9 1.0 2.0(7)
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Debt + Working
Capital (MM$) -28.5 -20.7 -41.8 -27.0 -18.8
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NAV (MM$) 50.4 69.2 127.5 176.8 191.0
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Shares
Outstanding
(MM) 73.3 83.7 101.6 120.5 140.8(8)
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P+P NAV/Share
($/share)(9) $ 0.69 $ 0.83 $ 1.25 $ 1.47 $ 1.36
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Notes:
1. "Company Gross" reserves means AEI working interest (operated and non-
op) share before deduction of royalties and excluding any royalty
interest.
2. "Net" reserves means AEI working interest (operated and non-op) after
deduction of royalties, plus AEI royalty interest in reserves.
3. Oil equivalent amounts have been calculated using a conversion rate of
six thousand cubic feet of natural gas to one barrel of oil.
4. Numbers are unaudited management estimates.
5. Capital includes costs and proceeds of property sales and acquisitions.
6. 64 thousand net acres of undeveloped land at $100/acre
7. 200 km2 of proprietary seismic at $10,000/km2
8. Undiluted
9. Unaudited
Outlook
Arsenal has five priorities for 2011. The first priority is to bring more of its
Stanley, North Dakota Bakken reserves into production. At January 1st Arsenal
had an inventory of 10 budgeted gross (4.7 net) proven non producing locations
on 640 acre spacing. Three have now been drilled with one on production. A
fourth is currently drilling. Arsenal has a drilling rig for the program and is
working to secure a frac crew. The first year average production rate to date at
Stanley has been 260 bbls/d/well with initial rates much higher.
The second priority for 2011 is to advance Arsenal's Bakken/Three Forks
depletion plan. Arsenal's independent engineers (AJM) have booked the
Bakken/Three Forks complex on one well per spacing unit with an 8% recovery
factor for proven and two wells per spacing unit with a 12% recovery factor for
proven plus probable. Arsenal has simulated the reservoirs and designed an
optimal depletion plan. The plan calls for four wells per 1280 acre spacing unit
and three wells per 640 acre spacing unit with a total recovery factor of 16%.
AJM has evaluated this plan and has booked as possible reserves an additional 4
million barrels with an incremental NPV of $75 million. Beyond that, further
increases in recovery may be attainable through water or gas injection. This
plan is consistent with other area operators.
The third priority is to advance Bakken development at Rennie Lake in Burke
County where Arsenal has 2500 net acres of undeveloped Bakken rights. Successful
wells have been drilled surrounding Arsenal's lands. Arsenal currently has no
production or booked reserves on its Rennie Lake property.
The fourth priority is the establishment of a new core oil property. Arsenal has
three play concepts that will be tested in the second quarter. At Edgerton,
Alberta, Arsenal has recently shot a 3D seismic program and identified a large
Leduc subcrop structure. At Princess, Alberta, Arsenal is installing high volume
lift to test the productive capability of its 5 Detrital formation wells. Also
at Princess, Arsenal plans to drill a horizontal well into the Glauconitic
formation to test the capability of multi fracturing to increase production.
Each of these has the potential to prove up material oil development
opportunities for Arsenal going forward. In addition, Arsenal is essentially
debt free and evaluating potential acquisitions using an undrawn $40 million
borrowing base.
The fifth priority is continued land acquisition in the Alberta deep basin
Falher formation play. Arsenal is acquiring acreage at relatively low prices and
is looking forward to a time when higher gas prices will make the development of
this play attractive. Arsenal has acquired 15,000 net acres in this play to
date.
Based on the current forward strip, Arsenal anticipates that it will achieve
operating margins in excess of $37/boe in 2011. Arsenal anticipates an exit
production rate of 3000boe/d. Capital expenditures are currently estimated at
$54 million for 2011. This is expected to yield funds from operations before
interest and overhead of approximately $37 million and cash flow of $30 million.
Arsenal has filed its Annual Information Form which contains Arsenal's reserves
data and other oil and gas information for the year ended December 31, 2010 as
mandated by National Instrument 51-101 Standards of Disclosure for Oil and Gas
Activities of the Canadian Securities Administrators. A copy of Arsenal's Annual
Information Form can be obtained on the System for Electronic Document Analysis
and Retrieval website at www.sedar.com or by contacting Arsenal.
Advisory
Certain statements and information contained in this press release, including
but not limited to management's assessment of Arsenal's future plans and
operations, production, reserves, revenue, commodity prices, operating and
administrative expenditures, funds from operations, capital expenditure programs
and debt levels contain forward-looking statements. All statements other than
statements of historical fact may be forward looking statements. These
statements, by their nature, are subject to numerous risks and uncertainties,
some of which are beyond Arsenal's control including the effect of general
economic conditions, industry conditions, changes in regulatory and taxation
regimes, volatility of commodity prices, escalation of operating and capital
costs, currency fluctuations, the availability of services, imprecision of
reserve estimates, geological, technical, drilling and processing problems,
environmental risks, weather, the lack of availability of qualified personnel or
management, stock market volatility, the ability to access sufficient capital
from internal and external sources and competition from other industry
participants for, among other things, capital, services, acquisitions of
reserves, undeveloped lands and skilled personnel that may cause actual results
or events to differ materially from those anticipated in the forward looking
statements. Such forward-looking statements, although considered reasonable by
management at the time of preparation, may prove to be incorrect and actual
results may differ materially from those anticipated in the statements made and
should not unduly be relied on. These statements speak only as of the date of
this press release. Arsenal does not intend and does not assume any obligation
to update these forward-looking statements, whether as a result of new
information, future events or otherwise, except as required by applicable law.
Arsenal's business is subject to various risks that are discussed in its filings
on the System for Electronic Document Analysis and Retrieval (SEDAR).