Symbol: BEN - TSX
CALGARY, Nov. 7 /CNW/ -
<<
FINANCIAL AND OPERATING HIGHLIGHTS
-------------------------------------------------------------------------
($ Cdn
thousands,
except as Three months ended Nine months ended
noted) September 30, September 30,
-------------------------------------------------------------------------
2006 2005 % Change 2006 2005 % Change
-------------------------------------------------------------------------
Sales volume
Natural
gas
(mcf/day) 17,355 10,832 17,077 10,086
Oil and
ngls
(bbl/day) 479 165 465 199
boe/day
(6 to 1) 3,372 1,970 71% 3,311 1,880 76%
-------------------------------------------------------------------------
Revenue net
of royalties 9,536 7,667 28,905 18,331
Net income
(loss) (2,662) 534 (6,389) 980
Per share
(basic
and
diluted) $ (0.03) $ 0.01 $ (0.08) $ 0.02
Funds from
operations(1) 5,084 5,233 (3%) 16,352 11,458 43%
Per share
(basic
and dilu-
ted)(1) $ 0.06 $ 0.11 (45%) $ 0.19 $ 0.24 (21%)
-------------------------------------------------------------------------
Capital costs
Exploration
and
development 11,031 6,360 40,708 13,414
Land and
seismic (1,343) 789 2,687 6,568
Other 58 16 708 68
-------------------------------------------------------------------------
Total 9,746 7,165 36% 44,103 20,050 120%
-------------------------------------------------------------------------
Net wells
completed
(No.) 4 9 21 20
-------------------------------------------------------------------------
Net working
capital
(deficit)
- including
bank debt (60,182) (2,137) (60,182) (2,137)
-------------------------------------------------------------------------
Shares
outstanding
End of
period
(000's) 86,447 52,961 86,447 52,961
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Note:
(1) Non-GAAP measure - represents cash flow from operating activities
before non-cash working capital changes. Refer to Management's
Discussion and Analysis for discussion of this measure.
Third Quarter 2006 Operating Highlights
- Production - Q3 2006 production averaged 3,372 boe/d, up 71 percent
over Q3 2005. Production additions in the third quarter of 2006 were
delivered by the tie in of significant "behind pipe" production that
existed at the end of June. Much of the tie in activity occurred late
in Q3 due to increasing delays in regulatory approvals and wet
weather in the Pembina area. September 2006 average production was
3,577 boe/d and continues to grow with October production estimated
at over 3,800 boe/d. The Lanfine fall drilling program scheduled to
begin in September will now spud in mid-November 2006 having been
delayed until gas prices showed some upward movement. A portion of
the additional Lanfine production is now not expected until early
2007. The delay at Lanfine, combined with the above noted regulatory
and weather delays will result in an estimated 2006 exit rate of
4,000 boe/d.
- Product Mix - The addition of liquids rich natural gas from the
Berland acquisition has changed the production mix from 92% natural
gas and 8% heavy oil in Q3 2005 to 86% natural gas, 2% heavy oil and
12% natural gas liquids. The natural gas produced in Pembina and the
Deep Basin which combined represent 32% of production has high BTU
content and commands a premium price.
- Production Costs - Costs averaged $7.95 per boe in Q3 2006, up 13%
compared to $7.02 per boe in Q3 2005. For the first nine months of
2006 production costs have averaged $7.54 per boe, compared to $7.56
for the first nine months of 2005. A continued focus on cost
management has contained costs in an environment of increasing costs
in the industry.
- Funds from Operations - Funds from operations Q3 2006 was
$5.1 million ($0.06 per share) compared to Q3 2005 funds from
operations of $5.2 million ($0.11 per share). Higher production in Q3
2006 was offset primarily by weaker natural gas prices. On a per
share basis, funds from operations declined due to additional shares
issued mainly for the acquisition of Berland.
- Drilling - A total of 7 wells (4 net) were completed in the third
quarter resulting in 7 (2.5 net) natural gas wells, 1 (0.3 net) oil
well and 2 (1.3 net) unsuccessful wells for success rate of
70 percent. On a year-to-date basis 37 (21.3 net) wells have been
completed with 25 (15.5 net) natural gas wells, 1 (0.3 net) oil well
and 11 (5.5 net) unsuccessful wells for a success rate of 70 percent.
- Land - Berens total undeveloped land (owned and option) currently
stands at 152,000 net acres. Ninety-seven percent of the undeveloped
lands are located in the four core areas of Pembina, the Deep Basin,
Lanfine and Marten Hills. This land base sets up a diverse and active
drilling program for the balance of 2006 and 2007.
>>
Report from Management
Drilling activity was slower in the third quarter of 2006 as we focused
on the tie in of wells drilled in the first half of the year. The wells we
completed in the third quarter continued to demonstrate the potential that
exists in Pembina. We had 80 percent success on five locations in Pembina and
participated in the drilling of two additional wells in an area just west of
Lanfine, one of which was successful for a 70% overall success rate in the
quarter. Completions and tie-ins in the third quarter have been a challenge,
particularly in Pembina where persistent wet weather has caused delays in many
aspects of our operations.
In the third quarter of 2006 the high demand our industry is placing on
oil and gas service companies seems to have eased somewhat and services are
more readily available. However, we have not yet seen the reduced activity
translate to noticeably lower costs and we remain ever vigilant in containing
cost pressures on drilling and operations.
We had placed the fall Lanfine drilling program, originally scheduled to
spud in September, on hold pending stronger natural gas prices. These
prolific, but small reserve targets rely on strong initial gas prices to
deliver strong economic return. It did not make sense to us to drill these
wells in August only to sell the initial production at "fire sale" prices.
With the recent recovery in natural gas prices this program is now expected to
spud in mid-November. We expect a portion of the Lanfine wells to be on stream
by year-end. The delayed Lanfine drilling and ongoing wet weather in Pembina
has caused us to lower our year end exit production expectation to
approximately 4,000 boe/d.
Outlook
With more than 152,000 net undeveloped acres of land concentrated in four
operating areas, we continue to be opportunity rich. Our existing land base
will provide ample drilling locations to pursue for the balance of 2006 and
throughout 2007. We currently have 37 wells approved for drilling and an
additional 40 locations under review which demonstrates the ongoing
opportunities that our extensive land base provides.
With a recently completed equity issue and stronger natural gas prices we
are comfortable that our balance sheet will support our programmed activity
levels and provide continued momentum for the Company. We are excited about
our future drilling plans and are confident that these wells will deliver
strong growth for Berens.
Berens Energy Ltd.
Management's Discussion and Analysis ("MD&A")
November 6, 2006
OVERVIEW
Berens Energy Ltd. ("Berens" or the "Company") is a full cycle oil and
natural gas exploration and production company with a concentrated production
and land base in Eastern Alberta, Pembina and Deep Basin regions of west
central Alberta.
All calculations converting natural gas to crude oil equivalent have been
made using a ratio of six thousand cubic feet (six "mcf") of natural gas to
one barrel of crude equivalent. Barrels of oil equivalent ("boe") may be
misleading, particularly if used in isolation. A boe conversion ratio of six
mcf of natural gas to one barrel of crude oil equivalent is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.
The following discussion of financial position and results of operations
should be read in conjunction with the Company's December 31, 2005 audited
financial statements and notes thereto and the September 30, 2006 unaudited
interim financial statements. This MD&A was prepared using information that is
current as of November 6, 2006 unless otherwise noted.
FORWARD LOOKING INFORMATION
This MD&A contains forward looking information within the meaning of
applicable securities laws. Forward looking statements may include estimates,
plans, expectations, forecasts, guidance or other statements that are not
statements of fact. Berens believes the expectations reflected in such forward
looking statements are reasonable. However no assurance can be given that such
expectations will prove to be correct. These statements are subject to certain
risks and uncertainties and may be based on assumptions where actual results
could differ materially from those anticipated or implied in the forward
looking statements. These risks include, but are not limited to: crude oil and
natural gas price volatility, exchange rate and interest rate fluctuations,
availability of services and supplies, market competition, uncertainties in
the estimates of reserves, the timing of development expenditures, production
levels and the timing of achieving such levels, the Company's ability to
replace and increase oil and gas reserves, the sources and adequacy of funding
for capital investments, future growth prospects and current and expected
financial requirements of the Company, the cost of future dismantlement and
site restoration, the Company's ability to enter into or renew leases, the
Company's ability to secure adequate product transportation, changes in
environmental and other regulations and general economic conditions. These
statements are as of the date of this MD&A and the Company does not undertake
an obligation to update its forward looking statements except as required by
law.
Additional information on the Company can be found on the SEDAR website
at www.sedar.com.
<<
QUARTERLY INFORMATION
2006
-----------------------------
($000's except as noted) Q3 Q2 Q1
---------------------------------------------------------------
Sales volumes:
Natural gas (mcf/day) 17,355 17,224 16,631
Oil and natural gas liquids
(bbl/day) 479 494 420
Barrels of oil equivalent 3,372 3,364 3,192
---------------------------------------------------------------
Financial:
Net revenue 9,536 9,846 9,523
Net income (loss) (2,662) (1,606) (2,121)
per share - basic ($/share) $ (0.03) $ (0.02) $ (0.03)
per share - diluted
($/share) $ (0.03) $ (0.02) $ (0.03)
Capital costs 9,746 15,234 19,124
Shares outstanding (000's) 86,447 86,447 86,447
Bank debt 52,780 49,580 32,180
Working capital (deficit)
including bank debt (60,182) (55,766) (45,907)
---------------------------------------------------------------
Per unit information:
Natural gas price ($/mcf) $ 5.91 $ 6.28 $ 7.72
Oil and liquids price
($/barrel) $ 62.53 $ 64.27 $ 51.07
Oil equivalent price ($/boe) $ 39.28 $ 41.59 $ 46.09
Operating netback ($/boe) $ 21.54 $ 22.87 $ 24.59
---------------------------------------------------------------
Net wells completed: (No.)
Natural gas 3 9 4
Oil - - -
Dry 1 1 3
---------------------------------------------------------------
Total 4 10 7
---------------------------------------------------------------
2005
---------------------------------------
($000's except as noted) Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Sales volumes:
Natural gas (mcf/day) 11,537 10,832 10,250 9,155
Oil and natural gas liquids
(bbl/day) 176 165 200 233
Barrels of oil equivalent 2,099 1,970 1,908 1,759
-------------------------------------------------------------------------
Financial:
Net revenue 9,537 7,667 5,754 4,910
Net income (loss) (475) 534 887 (441)
per share - basic ($/share) $ (0.01) $ 0.01 $ 0.02 $ (0.01)
per share - diluted
($/share) $ (0.01) $ 0.01 $ 0.02 $ (0.01)
Capital costs 12,346 7,165 3,423 9,462
Shares outstanding (000's) 57,163 52,961 46,427 46,427
Bank debt - - 10,080 10,480
Working capital (deficit)
including bank debt 4,273 (2,137) (13,121) (13,216)
-------------------------------------------------------------------------
Per unit information:
Natural gas price ($/mcf) $ 11.26 $ 9.16 $ 7.29 $ 6.91
Oil and liquids price
($/barrel) $ 41.92 $ 57.47 $ 33.11 $ 30.81
Oil equivalent price ($/boe) $ 65.47 $ 55.05 $ 42.61 $ 40.05
Operating netback ($/boe) $ 39.78 $ 34.07 $ 24.81 $ 21.12
-------------------------------------------------------------------------
Net wells completed: (No.)
Natural gas 9 7 3 5
Oil 1 0 0 0
Dry 2 2 1 2
-------------------------------------------------------------------------
Total 12 9 4 7
-------------------------------------------------------------------------
2004
-------------------------------------------
($000's except as noted) Q4
-------------------------------------------
Sales volumes:
Natural gas (mcf/day) 7,089
Oil and natural gas liquids
(bbl/day) 240
Barrels of oil equivalent 1,422
-------------------------------------------
Financial:
Net revenue 3,803
Net income (loss) (1,652)
per share - basic ($/share) $ (0.04)
per share - diluted
($/share) $ (0.04)
Capital costs 6,813
Shares outstanding (000's) 46,427
Bank debt 4,500
Working capital (deficit)
including bank debt (6,461)
-------------------------------------------
Per unit information:
Natural gas price ($/mcf) $ 6.48
Oil and liquids price
($/barrel) $ 31.88
Oil equivalent price ($/boe) $ 36.08
Operating netback ($/boe) $ 18.96
-------------------------------------------
Net wells completed: (No.)
Natural gas 11
Oil 1
Dry -
-------------------------------------------
Total 12
-------------------------------------------
>>
Significant production and revenue increases were experienced in the
first quarter of 2006 compared to earlier quarters due to the acquisition of
Berland Exploration Ltd. in January of 2006. Ongoing drilling has delivered
the production increase to date for 2006. There have been no further
acquisitions.
RESULTS OF OPERATIONS
Production Volume
Production volume averaged 3,372 boe/d for the third quarter of 2006, up
71 percent compared to 1,970 boe/d in the third quarter of 2005. Natural gas
represented 86 percent of production in the third quarter of 2006 with the
remaining production being 12 percent light oil and natural gas liquids and
two percent conventional heavy oil.
Significant behind pipe volumes that existed at the end of the second
quarter of 2006 added to third quarter volumes late in the quarter due wet
weather delays in Pembina. September 2006 average production was 3,577 boe/d,
well above the average for the third quarter of 2006. October production
continues to show gains with production estimated at over 3,800 boe/d with
300 boe/d of new production expected to be tied in during October and
November.
Production volume averaged 3,311 boe/d for the nine months ended
September 30, 2006, up 76 percent compared to 1,880 boe/d in the nine months
ended September 30, 2005 with the majority of the increase due to the Berland
purchase that closed on January 18, 2006.
Production Revenue
Natural gas prices averaged $5.91 per mcf for the third quarter of 2006,
down 35 percent compared to $9.16 per mcf in the third quarter of 2005. Oil
and liquids prices averaged $60.96 and $64.52 per barrel respectively in the
third quarter of 2006 for a blended price of $62.07 per barrel, up eight
percent from the third quarter 2005 blended liquids price of $57.47 per
barrel. Higher priced light oil and natural gas liquids represent a larger
portion of production in 2006 compared to 2005. On a boe basis, prices
averaged $39.24 in the third quarter of 2006, down 29 percent compared to
$55.05 per boe in the third quarter of 2005 as the large decline in natural
gas prices was partially offset by increased prices for oil and liquids.
Revenue was up 22 percent in the third quarter of 2006 compared to the
third quarter of 2005. Volume increased by 71 percent offset by a 29 percent
decrease in per boe prices.
Natural gas prices averaged $6.61 per mcf for the nine months ended
September 30, 2006, down 17 percent compared to $7.92 per mcf in the nine
months ended September 30, 2005. Blended oil and liquids prices averaged
$59.57 per barrel in the nine months ended September 30, 2006, up 56 percent
from the nine months ended September 30, 2005 liquids price of $38.30 per
barrel. On a boe basis, prices averaged $42.47 in the nine months ended
September 30, 2006, down eight percent compared to the nine months ended
September 30, 2005 boe price of $46.28. Revenue was up 62 percent in the nine
months ended September 30, 2006 compared to the nine months ended
September 30, 2005. Volume increased by 76 percent offset by an eight percent
decrease in per boe prices.
Royalties
Royalties, net of Alberta Royalty Tax Credit ("ARTC"), averaged
23 percent of revenue for the third quarter of 2006 the same percentage as in
the third quarter of 2005. Excluding the benefit of ARTC, royalty rates
averaged 23 percent in the third quarter of 2006 and 24 percent in the third
quarter of 2005. For the nine months ended September 30, 2006 royalties, net
of ARTC averaged 26 percent of revenue compared to 24 percent of revenue in
the nine months ended September 30, 2005. The higher 2006 royalty percentage
is attributed to the following factors:
<<
- Significant 2006 production comes from higher volume liquids rich
wells in Pembina and the Deep Basin that have higher royalty rates
compared to 2005 production which was primarily from lower volume
wells in Lanfine.
- Production from certain farm-in lands in Pembina incurs overriding
royalties in addition to crown royalties contributing to the higher
royalty percentage.
>>
On an ongoing basis, royalties are expected to average approximately
25 percent of revenues. Royalty expense of $2.6 million was recorded in the
third quarter of 2006, up 14 percent compared to the third quarter of 2005
reflecting higher revenue in the 2006 period. For the nine months ended
September 30, 2006 royalty expense of $9.5 million was up 76 percent compared
to the nine months ended September 30, 2005.
Production Expenses
Production expenses were $7.95 per boe in the third quarter of 2006, up
13 percent compared to $7.02 per boe in the third quarter of 2005. For the
nine months ended September 30, 2005 production expenses were $7.54 per boe,
almost unchanged from $7.56 per boe in the nine months ended September 30,
2005. A focus on cost management has contained costs in an environment where
industry costs have escalated significantly. Management expects future per
unit operating expenses to be in the $7.50 per boe range.
Third quarter 2006 production expenses were $2.4 million, up 92 percent
compared to the third quarter of 2005 due to a 71 percent increase in volume
and higher per unit costs. For the nine months ended September 30, 2006
production expenses were $6.8 million, up 75 percent compared to the nine
months ended September 30, 2005 due to a 76 percent production increase offset
slightly by reduced per boe costs.
Transportation costs of $0.3 million increased 20 percent in the third
quarter of 2006 compared to the third quarter of 2005 due to increased volumes
offset by lower per unit costs. For the nine months ended September 30, 2006
transportation costs were $0.8 million an increase of 38 percent compared to
the nine months ended September 30, 2005.
General and Administrative Expenses
General and administrative costs, including stock-based compensation,
were up 20 percent in the third quarter of 2006 compared to the third quarter
of 2005. Increased costs were incurred in 2006 as the staff contingent has
approximately doubled since the second quarter of 2005 with production growth
and the addition of the Berland assets and several staff members. Salary and
bonus levels have also increased as a result of industry competitive
pressures. On a per unit basis, general and administrative costs were $3.39
per boe for the third quarter of 2006, down 30 percent compared to $4.83 per
boe in the third quarter of 2005.
For the nine months ended September 30, 2006 general and administrative
costs were up 69 percent compared to the nine months ended September 30, 2005.
In addition to the items discussed above, non-recurring costs of $160,000 were
incurred in the first half of 2006 to integrate the Berland operations. On a
per boe basis, general and administrative costs were $4.24 per boe for the
nine months ended September 30, 2006, down four percent compared to $4.41 per
boe in the nine months ended September 30, 2005. There were no general and
administrative costs capitalized in the third quarter or for the nine months
ended September 30, 2006 and 2005.
Staff levels are expected to remain fairly constant throughout the
balance of 2006. Per unit general and administrative costs are expected to
decline as production levels increase.
Interest Expense
Interest expense increased 655 percent in the third quarter of 2006
compared to the third quarter of 2005. The closing of the acquisition of
Berland resulted in significant borrowing on the bank operating line as
30 percent of the Berland acquisition cost was in the form of cash. In
addition, Berland's debt and working capital, totaling $28 million were
assumed on January 18, 2006, the closing date of the acquisition. Capital
expenditures in the first nine months of 2006 were significantly higher than
funds from operations. For the nine months ended September 30, 2006 interest
expense increased 414 percent compared to nine months ended September 30,
2005.
Operating Netback(1)
Operating netback represents the margin realized by the production and
sale of petroleum and natural gas. The primary cause of the lower 2006
netbacks is lower natural gas prices.
<<
-------------------------------------------------------------------------
Quarterly Operating Netbacks Three months Nine months
($'s per boe) ended ended
September 30 September 30
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Sales price 39.24 55.05 42.47 46.28
Less:
Royalties (net of ARTC) 8.91 12.76 10.94 10.56
Production expenses 7.95 7.02 7.54 7.56
Transportation charges 0.84 1.20 0.90 1.15
-------------------------------------------------------------------------
Operating netback 21.54 34.07 23.09 27.01
-------------------------------------------------------------------------
(1) non-GAAP measure - refer to discussion on non-GAAP measures below.
>>
Depletion, Amortization and Accretion
Depletion, amortization and accretion totaled $8.7 million ($28.04 per
boe) in the third quarter of 2006 compared to $4.8 million ($26.32 per boe) in
the third quarter of 2005. For the nine months ended September 30, 2006
depletion, amortization and accretion totaled $27.2 million ($30.07 per boe)
compared to $11.4 million ($22.15 per boe) for the nine months ended
September 30, 2005. The higher depletion rates are attributable to the cost of
acquiring the Berland reserves through the acquisition and to spending in the
deeper drilling program which had limited reserve additions to the end of
2005. The 2006 capital plan is focused on drilling, primarily in Pembina and
Lanfine which is expected to add reserves at lower cost on a go forward basis.
Income Taxes
Current taxes of $22,000 were recorded in the third quarter of 2006
primarily for provincial capital taxes and taxes related to a 2005 flow
through share issue. The Company does not expect to pay current income tax
during 2006 and 2007 as there are ample capital cost pools and expected future
capital spending to shelter taxable income.
Future taxes changed from a small asset position at December 31, 2005 to
a liability of $16.6 million at September 30, 2006. Future tax liabilities of
$16.1 million were recorded on the acquisition of Berland and $6.1 million was
recorded to account for the tax effect of flow-through shares renouncements,
offset by a $1.5 million future tax reduction to reflect future corporate tax
rate reductions which are substantially enacted and recoveries of future tax
on the first nine month 2006 losses.
NET INCOME
The net loss for the third quarter of 2006 was $2.7 million ($0.03 per
share) compared to net income of $0.5 million ($0.01 per share) in the third
quarter of 2005. The higher 2006 loss has resulted primarily from higher
depletion expense and low natural gas prices more than offsetting the benefit
from increases in production volume.
CAPITAL COSTS
Capital costs were $9.7 million in the third quarter of 2006, up from
$7.1 million in the third quarter of 2005 as overall activity levels were
higher with the larger asset base. The focus on the third quarter 2006 capital
program was to bring on stream wells that had been drilled in the first half
of 2006. A total of four net wells were completed in the third quarter of 2006
compared to nine net wells in the third quarter of 2005. Average well costs
are higher in 2006 as deeper Pembina and Deep Basin wells are in the 2006
drilling program whereas in 2005 the shallower Lanfine drilling program was
the majority of the drilling. Capital costs are up as well due to increased
rates charged by drilling and service companies for most activities. A seismic
data base was sold to a seismic broker in the third quarter of 2006 for
proceeds of $1.8 million resulting in spending on geological and geophysical
activities to be negative for the quarter.
<<
-------------------------------------------------------------------------
Three months Nine months
($000's) ended June 30, ended September 30,
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Drilling and completion 11,031 6,360 40,708 13,414
Land 340 663 2,018 4,669
Geological and geophysical (1,683) 126 669 1,899
Office and other 58 16 708 68
-------------------------------------------------------------------------
Total 9,746 7,165 44,103 20,050
-------------------------------------------------------------------------
>>
Overall, the Company has spent 92 percent of its capital on drilling,
completion and tie-in activities in the first nine months of 2006 compared to
a capital program that was more focused on land and seismic in the first nine
months of 2005. In 2005 there was a focus to build new land positions in
central and west central Alberta. With a large undeveloped land base in place
entering 2006 and the acquisition of Berland which also had significant
undeveloped land, the capital program for 2006 is focused on drilling.
WORKING CAPITAL
Accounts receivable of $15.4 million at September 30, 2006 were primarily
revenue receivables and amounts owing from partners ($13.0 million) as well as
capital advances to partners for drilling projects ($1.4 million). Accounts
payable at September 30, 2006 of $25.3 million were mainly comprised of trade
payables for capital and operating costs ($13.8 million), royalties
($2.0 million), amounts owing to partners ($3.4 million) and capital costs
accrued at the end of the quarter for ongoing drilling and completion
operations ($1.0 million).
Working capital excluding bank indebtedness was in a deficit position of
$7.4 million at September 30, 2006. Borrowings under the bank line and ongoing
cash flows, combined with a capital program for the balance of 2006 that is
expected to be within cash flow is expected to fund this working capital
deficit.
LIQUIDITY AND CAPITAL RESOURCES
The Company plans to fund its current working capital deficit, operations
and capital costs with a mix of operating cash flow and debt financing through
the bank operating line. An operating bank line is in place for $62.0 million,
secured by producing properties. At September 30, 2006, $52.8 million was
drawn on the bank line.
On October 26, 2006 a flow-through equity financing was closed for net
proceeds of $11.2 million which has improved the financial condition of the
Company and enable it to continue to conduct its exploration and development
programs.
NON-GAAP MEASUREMENTS
This MD&A contains the term "funds from operations" and "operating
netback". As an indicator of the Company's performance, these terms should not
be considered an alternative to, or more meaningful than "cash flow from
operating activities" or "net income (loss)" as determined in accordance with
Canadian generally accepted accounting principles. The Company's determination
of funds from operations and operating netback may not be comparable to that
reported by other companies, especially those in other industries. Management
feels that funds from operations is a useful measure to help investors assess
whether the Company is generating adequate cash amounts from its operations to
fund its ongoing operations and planned capital program. Operating netback is
a useful measure for comparing the Company's price realization and cost
performance against industry competitors.
The reconciliation between net income and funds from operations for the
periods ended September 30 is set out in the following chart:
<<
-------------------------------------------------------------------------
Three months Nine months
ended ended
($000's) September 30 September 30
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Net income (loss) (2,661) 534 (6,389) 980
Items not requiring cash:
Depletion, depreciation and
accretion 8,701 4,770 27,177 11,366
Future income tax expense
(recovery) (1,159) (139) (5,018) (1,124)
Stock based compensation 203 68 583 236
-------------------------------------------------------------------------
Funds from operations 5,084 5,233 16,353 11,458
-------------------------------------------------------------------------
>>
Funds from operations are also presented on a per share basis consistent
with the calculation of net income per share, whereby per share amounts are
calculated using the weighted average number of shares outstanding. Funds from
operations per share were $0.06 (basic and diluted) for the third quarter of
2006 compared to $0.11 per share for the third quarter of 2005. Funds from
operations per share were $0.19 (basic and diluted) for the nine months ended
September 30, 2006 compared to $0.24 for the nine months ended September 30,
2005.
RISKS
Primary financial risks relate to variability in commodity prices.
Interest rate and currency exchange rate variability also have an effect on
financial results. The effect of changes in the exchange rate between US and
Canadian currencies on natural gas prices is not direct, as variations between
the regional markets for natural gas are often much greater than can be
explained by currency variability.
Other risks are related to operations. These risks include, but are not
limited to, risks associated with oil and gas exploration, development,
exploitation, production, marketing and transportation, delays or changes in
plans with respect to exploration or development projects or capital costs,
volatility of commodity prices, currency fluctuations, the uncertainty of
reserves estimates, potential environmental liabilities, technology risks,
competition, incorrect assessment of the value of acquisitions and failure to
realize the anticipated benefits of acquisitions. The foregoing list of
factors is not exhaustive. Additional information on these and other factors
that could affect operations or financial results are included in a more
detailed description of risks in Berens' Annual Information Form on file with
Canadian securities regulatory authorities and available on SEDAR at
www.sedar.com.
Documented environmental health and safety plans are in place as well as
a comprehensive emergency response plan to mitigate operating risks.
HEDGING
Subsequent to the end of the third quarter, a natural gas price hedge was
placed for the calendar year 2007 on 2,000 gigajoules ("GJ") per day. The
hedge is a price "collar" with a floor price for the year at $6.00 per GJ with
a ceiling for the months of January to March and November and December of
$11.05 per GJ and $8.50 per GJ for the April to October period.
RELATED PARTY TRANSACTIONS
A consulting firm is contracted from time to time in which one of the
Company's directors is the managing partner. The executive services rendered
are in the normal course of business and are at normal rates charged by the
consulting firm and recorded at the exchange amount. Consulting fees for this
firm in the third quarter of 2006 were $16,000 and $90,000 for the nine months
ended September 30, 2006. Fees for legal services are paid to a law firm in
which the corporate secretary is a partner. The legal services are rendered in
the normal course of business at normal rates charged by the law firm. Legal
fees for this firm paid in the third quarter of 2006 were $36,000 and $532,000
for the nine months ended September 30, 2006.
SHARE DATA
As of the date of this MD&A the Company had 86,447,064 issued and
outstanding common shares. Additionally, options to purchase 4,075,700 common
shares have been issued.
DISCLOSURE CONTROLS AND PROCEDURES OVER FINANCIAL REPORTING
Disclosure controls and procedures are designed to provide reasonable
assurance that all relevant information is gathered and reported to senior
management, including the Chief Executive Officer ("CEO") and the Chief
Financial Officer ("CFO"), on a timely basis so appropriate decisions can be
made regarding public disclosure. As at December 31, 2005, the CEO and the CFO
evaluated the effectiveness of the disclosure controls and procedures as
defined in Multilateral Instrument 52-109 of the Canadian Securities
Administrators and have concluded that such disclosure controls and procedures
are effective. No changes to disclosure controls and procedures occurred in
the first nine months of 2006.
OUTLOOK
Drilling opportunities exist across four core areas and are well
diversified in terms of risk and potential return. The intention is to stay
focused in the four core areas that have been established to take advantage of
the high level of technical expertise we have developed in each area.
The 2006 capital program has greater diversification than the 2005
program both in terms of regions and the mix of risk and return potential.
Drilling at Lanfine represents the lowest risk drilling with the expectation
of solid returns while the Deep Basin is the higher risk drilling with the
potential for significant reserve discoveries. Pembina is considered to have a
medium risk and strong return profile. The 2006 capital plan is more drilling
focused compared to 2005 and will be concentrated in Lanfine and Pembina for
the balance of 2006. Six wells are planned for each of Pembina and Lanfine in
the remainder of 2006. An additional two wells (0.6 net) are planned for the
Deep Basin.
Access to services has appears to be easing, especially for the shallower
drilling activities that we have planned at Lanfine. Costs have climbed for
almost every service in the oil and gas industry. Capital management and a
focus on cost reduction will be important aspects of our business when
carrying out the 2006 capital program. A larger capital program and a critical
mass of wells to drill in 2006 has enabled the Company to contract drilling
services on an ongoing basis which improves the ability to drill wells with
the same rig on a repeated basis in Pembina. Drilling in Pembina in the third
quarter went very smoothly and wells are being drilled on schedule and at the
lower costs than we have experienced in the past.
The undeveloped land base totaling approximately 152,000 net acres is
expected to provide a strong inventory of drilling prospects to deliver future
growth. We currently have 37 wells approved for drilling and an additional 40
locations under review which demonstrates the ongoing opportunities that our
extensive land base provides.
<<
Berens Energy Ltd.
Balance Sheets
(unaudited)
As at
-------------------------------------------------------------------------
(000's) September December
30, 2006 31, 2005
-------------------------------------------------------------------------
ASSETS (note 6)
Current
Cash and cash equivalents $ 44 $ 9,472
Accounts receivable 15,425 9,912
Prepaid expenses and deposits 2,435 680
-------------------------------------------------------------------------
17,904 20,064
Investments 54 299
Future income taxes (note 8) - 225
Property, plant and equipment (note 4) 167,722 53,242
Goodwill (note 3) 44,974 14,805
-------------------------------------------------------------------------
$230,654 $ 88,635
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Bank loan (note 6) $ 52,780 -
Accounts payable and accrued liabilities 25,279 $ 15,699
Taxes payable 27 92
-------------------------------------------------------------------------
78,086 15,791
Asset retirement obligations (note 5) 2,431 1,223
Future income taxes (note 8) 16,619 -
-------------------------------------------------------------------------
97,136 17,014
Shareholders' equity
Capital stock (note 7) 140,013 72,309
Contributed surplus (note 7) 1,156 574
Deficit (7,651) (1,262)
-------------------------------------------------------------------------
133,518 71,621
-------------------------------------------------------------------------
$230,654 $ 88,635
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the financial statements
Berens Energy Ltd.
Statements of Operations and Deficit
(unaudited)
For the three and nine months ended September 30,
-------------------------------------------------------------------------
($000's) Three months Nine months
ended ended
September 30, September 30,
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Revenue
Oil and natural gas revenue $ 12,173 $ 9,979 $ 38,424 $ 23,749
Royalties, net of ARTC (2,637) (2,312) (9,519) (5,418)
-------------------------------------------------------------------------
9,536 7,667 28,905 18,331
Interest 1 1 18 2
-------------------------------------------------------------------------
9,537 7,668 28,923 18,333
-------------------------------------------------------------------------
Expenses
Production 2,465 1,273 6,816 3,880
Transportation 261 217 814 592
Depletion, amortization and
accretion 8,701 4,770 27,177 11,366
General and administrative
(note 10) 849 808 3,247 2,026
Stock-based compensation (note 7) 204 68 582 236
Interest 856 113 1,655 322
-------------------------------------------------------------------------
13,336 7,249 40,291 18,422
-------------------------------------------------------------------------
Loss before income taxes (3,799) 419 (11,368) (89)
-------------------------------------------------------------------------
Income taxes (note 8)
Future expense (recovery) (1,159) (139) (5,018) (1,124)
Current expense 22 24 39 55
-------------------------------------------------------------------------
(1,137) (115) (4,979) (1,069)
-------------------------------------------------------------------------
Net income (loss) for the period (2,662) 534 (6,389) 980
Deficit, beginning of period (4,989) (1,320) (1,262) (1,766)
-------------------------------------------------------------------------
Deficit, end of period $ (7,651) $ (786) $ (7,651) $ (786)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income (loss) per share
(note 11)
Basic and diluted $ (0.03) $ 0.01 $ (0.08) $ 0.02
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the financial statements
Berens Energy Ltd.
Statements of Cash Flows
(unaudited)
For the three and nine months ended September 30,
-------------------------------------------------------------------------
($000's) Three months Nine months
ended ended
September 30, September 30,
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income (loss) for the period $ (2,662) $ 534 $ (6,389) $ 980
Add items not involving cash
Depletion, amortization and
accretion 8,701 4,770 27,177 11,366
Future income tax expense
(recovery) (1,159) (139) (5,018) (1,124)
Stock-based compensation 204 68 582 236
-------------------------------------------------------------------------
5,084 5,233 16,352 11,458
Change in non-cash working
capital items related to
operating activities (note 9) (890) 2,826 (7,741) 2,395
-------------------------------------------------------------------------
Cash flow provided by (used in)
operating activities 4,194 8,059 8,611 13,853
-------------------------------------------------------------------------
FINANCING ACTIVITIES
Change in bank loan 3,200 (10,080) 33,030 (4,500)
Net proceeds from private
offerings - 12,869 19,813 12,869
Sale of investment 245 - 245 -
Proceeds from the exercise of
stock options - 46 - 46
-------------------------------------------------------------------------
Cash flow provided by (used in)
financing activities 3,445 2,835 53,088 8,415
-------------------------------------------------------------------------
INVESTING ACTIVITIES
Cash acquired through Berland
acquisition - - 109 -
Cash component on Berland
acquisition - - (28,682) -
Purchase of property and
equipment (9,746) (7,165) (44,103) (20,050)
Change in non-cash working
capital items related to
investing activities (note 9) 2,116 (2,382) 1,550 (862)
-------------------------------------------------------------------------
Cash flow used in investing
activities (7,630) (9,547) (71,126) (20,912)
-------------------------------------------------------------------------
Increase (decrease) in cash 9 1,347 (9,427) 1,356
Cash and cash equivalents,
beginning of period 35 44 9,471 35
-------------------------------------------------------------------------
Cash and cash equivalents, end
of period $ 44 $ 1,391 $ 44 $ 1,391
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the financial statements
BERENS ENERGY LTD.
Notes to Financial Statements
(unaudited)
Three and nine months ended September 30, 2006 and 2005
1. NATURE OF OPERATIONS
The Company is a full cycle oil and natural gas exploration and
production company with activities encompassing land acquisition,
geological and geophysical assessment, drilling and completion, and
production. The primary areas of operation are in eastern and west
central Alberta.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The interim financial statements have been prepared by management
following the same accounting policies as the most recent annual audited
financial statements.
Certain disclosures, which are normally required to be included in notes
to the annual financial statements, are condensed or omitted for interim
reporting purposes. Accordingly, these interim financial statements
should be read in conjunction with the audited annual financial
statements for the year ended December 31, 2005. Certain prior period
amounts have been reclassified to conform to current disclosure.
3. ACQUISITION OF BERLAND EXPLORATION LTD.
On January 18, 2006, Berens and Berland Exploration Ltd. ("Berland")
closed a previously announced arrangement that saw Berens acquire
Berland. Pursuant to the arrangement, shareholders of Berland received
$0.96 in cash ($20.0 million) and 0.8784 of a Berens common share
(21,083,795 common shares for $53.8 million) for each Berland common
share. Additionally, certain option and warrant holders received a
differential payment for the difference between their option and warrant
strike prices and $3.20 per Berland share ($8.7 million). Pursuant to the
Arrangement, Berens also assumed $19.7 million of Berland debt and
transaction costs of $0.5 million.
The total cost to Berens to acquire the Berland shares was
$102.7 million. This acquisition has been accounted for using the
purchase method with the Berland results included in the statement of
operations from the closing date of January 18, 2006.
The following table summarizes the estimated fair value of the assets
acquired and liabilities assumed as at the closing date.
Assets and liabilities purchased (000's) $
-------------------------------------------------------------------------
Cash and cash equivalents 109
Accounts receivable 10,321
Prepaid expenses and deposits 1,488
Petroleum and natural gas properties 97,616
Goodwill 30,288
Accounts payable and accrued liabilities (20,247)
Future income taxes (16,111)
Asset retirement obligations (715)
-------------------------------------------------------------------------
Total cost to acquire Berland 102,749
-------------------------------------------------------------------------
4. PROPERTY, PLANT AND EQUIPMENT
September 30, 2006 December 31, 2005
Accumulated Accumulated
depletion and depletion and
($000's) Cost depreciation Cost depreciation
-------------------------------------------------------------------------
Petroleum and
natural gas
properties 227,129 59,840 81,030 28,186
Office and
computer
equipment 641 209 492 94
-------------------------------------------------------------------------
227,771 60,049 81,522 28,280
-------------------------------------------------------------------------
Net book
value 167,722 53,242
-------------------------------------------------------------------------
At September 30, 2006, costs of $27,148,000 (2005 - $13,706,000) related
to undeveloped land have been excluded from the depletion and
depreciation calculation.
5. ASSET RETIREMENT OBLIGATIONS
The total future asset retirement obligations were estimated based on the
net ownership interest in all wells and facilities, estimated costs to
reclaim and abandon the wells and facilities and the estimated timing of
the costs to be incurred in future periods. The estimated net present
value of the total asset retirement obligations is $2,431,000 as at
September 30, 2006 based on a total future liability of $5,204,000. These
payments are expected to be made over the next 5 to 15 years. An
inflation rate of two percent and a credit adjusted risk free rate of 10%
were used to calculate the present value of the asset retirement
obligations.
The following table reconciles the asset retirement obligations:
(000's) $
-------------------------------------------------------------------------
Obligation, December 31, 2005 1,223
Increase in obligation during the period 318
Obligation assumed from Berland acquisition 715
Accretion expense 175
-------------------------------------------------------------------------
Obligation, September 30, 2006 2,431
-------------------------------------------------------------------------
6. BANK OPERATING LINE
An agreement with a Canadian bank is in place for an operating bank line
totaling $62.0 million at September 30, 2006. The amount available under
the bank line declines by $1.35 million per month beginning October 31,
2006. Collateral for the facility consists of a general assignment of
book debts and a $75.0 million debenture with a floating charge over all
assets of the Company. The bank line is a demand line and carries an
interest rate of the Bank's prime rate adjusted for a factor based on the
most recent quarterly debt to cash flow calculation. The rate at
September 30, 2006 was 6.5 percent (September 30, 2005 - 4.875 percent).
On September 30, 2006, $52,780,000 was drawn on the line.
7. CAPITAL STOCK
(a) Authorized Capital
The authorized capital consists of an unlimited number of preferred
shares issuable in series and an unlimited number of common shares
without nominal or par value.
(b) Common shares issued
-------------------------------------------------------------------------
Consideration
Number ($000's)
-------------------------------------------------------------------------
Balance December 31, 2004 46,427,469 48,331
Stock options exercised during the year 35,800 49
Reduction of contributed surplus for
options exercised - 6
Private placements for cash, net of
commissions 10,700,000 24,979
Future tax effect of flow-through share
renouncement - (1,541)
Future tax effect on share issue costs
and commissions - 670
Share issue costs, net of tax - (185)
-------------------------------------------------------------------------
Balance December 31, 2005 57,163,269 72,309
Private placement for cash on
conversion of subscription receipts,
net of commissions 8,200,000 19,988
Shares issued on arrangement with
Berland (note 3) 21,083,795 53,764
Future tax effect of flow-through
share renouncement (6,104)
Future tax effect on share issue costs
and commissions - 231
Share issue costs, net of tax - (175)
-------------------------------------------------------------------------
Balance September 30, 2006 86,447,064 140,013
-------------------------------------------------------------------------
Private Placements
On September 12, 2005, 4,500,000 common shares were issued by way of a
private placement at $1.95 per common share for cash proceeds of
$8,775,000 before agent's commission of $482,625. The proceeds of the
financing were used to fund oil and gas exploration and development costs
and for general corporate purposes.
On September 12, 2005, 2,000,000 common shares were issued on a flow-
through basis pursuant to the Income Tax Act by way of a private
placement at $2.45 per share for proceeds of $4,900,000, before the
agent's commission of $269,500, to finance certain oil and gas
expenditures to be incurred in 2005 and 2006. The renouncement of these
expenditures was made to the purchasers of these shares for the 2005
income tax year. The expenditures to satisfy the flow-through commitment
were made during 2005 and 2006.
On December 22, 2005, 4,200,000 common shares were issued on a flow-
through basis pursuant to the Income Tax Act by way of a private
placement at $3.15 per common share for proceeds of $13,230,000 before
agent's commission of $661,500 and 8,200,000 subscription receipts in the
capital of the Corporation issued at a price of $2.50 per subscription
receipt. The net proceeds from the "flow-through" portion of the private
placement have been used to incur qualifying expenditures with respect to
the continued exploration and development of the Company's oil and
natural gas properties prior to December 31, 2006. The renouncement of
these expenditures was made to the purchasers of these shares for the
2005 income tax year. The expenditures to satisfy the flow-through
commitment have been made as at June 30, 2006.
Each subscription receipt represented the right to receive one common
share on the closing of the acquisition of Berland Exploration Ltd. The
Berland acquisition closed on January 18, 2006 and all subscription
receipts were converted to common shares and proceeds of $20,500,000 less
commissions of $512,000 were released to the Company. No obligation
remains related to this subscription receipt issue.
On January 18, 2006 21,083,795 common shares were issued in exchange for
the acquisition of Berland shares pursuant to the Arrangement between the
companies.
(c) Stock Option Plan
A stock option plan is in place under which 7,500,000 common shares have
been reserved for options to be distributed to directors, officers,
employees and consultants with terms established by the board of
directors.
Options granted under the plan generally have a five year term to expiry
and vest equally over a three year period commencing on the first
anniversary date of the grant. The exercise price of each option equals
the closing market price of the Company's common shares on the day prior
to the date of the grant.
The following table sets forth a reconciliation of the plan activity
through September 30, 2006.
Weighted average
Number of exercise price
Options ($ per share)
-------------------------------------------------------------------------
Outstanding, December 31, 2005 3,513,700 1.56
Granted 885,000 2.16
Cancelled 7,500 2.90
Outstanding, September 30, 2005 4,391,200 1.69
-------------------------------------------------------------------------
Exercisable 1,975,692 1.15
-------------------------------------------------------------------------
The following table sets forth additional information relating to the
stock options outstanding at September 30, 2006.
Options Outstanding Exercisable Options
-------------------------------------------------------------------------
Weighted Weighted
average average
exercise Weighted exercise Weighted
Exercise price average price average
price Number of ($ per years to Number of ($ per years to
range Options share) expiry Options share) expiry
-------------------------------------------------------------------------
$1.00 to
$1.25 1,867,000 1.06 2.14 1,433,998 1.03 1.81
-------------------------------------------------------------------------
$1.26 to
$1.50 536,700 1.41 2.68 326,696 1.41 2.66
-------------------------------------------------------------------------
$1.51 to
$1.75 713,000 1.56 3.70 214,998 1.56 2.26
-------------------------------------------------------------------------
$1.76 to
$2.00 94,500 1.78 4.68 - - -
-------------------------------------------------------------------------
$2.26 to
$2.50 125,000 2.40 4.61 - - -
-------------------------------------------------------------------------
$2.51 to
$2.75 117,500 2.59 4.50 - - -
-------------------------------------------------------------------------
$2.76 to
$3.00 787,500 2.90 4.17 - - -
-------------------------------------------------------------------------
$3.01 to
$3.25 150,000 3.24 4.32 - - -
-------------------------------------------------------------------------
4,391,200 1.69 3.09 1,975,692 1.15 2.00
-------------------------------------------------------------------------
The fair value based method for measuring option awards based on the
Black Scholes valuation model is used. Key assumptions used for the Black
Scholes based valuation of options are: Risk free rate - 4.4 percent;
average expected life - 4.5 years; no expected dividend yield; 46 percent
volatility. Estimated future forfeiture assumptions are not used in
calculations and forfeitures are recognized as they occur. Based on the
fair value method, $582,000 was recorded as compensation expense for the
nine month period ended September 30, 2006 and $204,000 for the three
month period ended September 30, 2006 (2005 - $236,000 and $68,000) with
a corresponding increase recorded to contributed surplus.
(d) Contributed Surplus
The following table sets forth the continuity of contributed surplus for
the three months ended September 30, 2006.
(000's) $
-------------------------------------------------------------------------
Opening balance, December 31, 2005 574
Stock based compensation expense 582
-------------------------------------------------------------------------
Closing balance, September 30, 2006 1,156
-------------------------------------------------------------------------
8. INCOME TAXES
Future income taxes were recorded in the nine months ended September 30,
2006 as set forth in the following schedule:
(000's) $
-------------------------------------------------------------------------
Future tax asset - December 31, 2005 225
Recorded on Berland acquisition (16,110)
Tax effect of issuance of flow-through shares (6,104)
Future tax recovery - nine months ended September 30, 2006 5,018
Tax effect of share issue costs 231
Other 121
-------------------------------------------------------------------------
Future tax liability - September 30, 2006 (16,619)
-------------------------------------------------------------------------
The future tax recovery for the three and nine months ended September 30,
2006 includes $1,292,000 to record the benefit of future tax rate
reductions that were substantially enacted in the second quarter of 2006.
9. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in Non-cash Working Capital
For the nine months ended September 30,
2006 2005
(000's) $ $
-------------------------------------------------------------------------
Accounts receivable (5,513) (1,904)
Prepaid expenses and deposits (1,755) (217)
Accounts payable and accrued liabilities 9,580 3,640
Taxes payable (65) 14
Non-cash working capital acquired (note 3) (8,438) -
-------------------------------------------------------------------------
(6,191) 1,533
Change in non-cash working capital related to
investing activities 1,550 (862)
-------------------------------------------------------------------------
Change in non-cash working capital related to
operating activities (7,741) 2,395
-------------------------------------------------------------------------
Cash interest and taxes paid
For the three and six months ended September 30,
Three Three Nine Nine
months months months months
2006 2005 2006 2005
(000's) $ $ $ $
-------------------------------------------------------------------------
Income and other taxes - 23 117 83
Interest 856 113 1,655 322
-------------------------------------------------------------------------
10. RELATED PARTY TRANSACTIONS
A consulting firm is contracted from time to time in which one of its
directors is the managing partner. The executive services rendered are in
the normal course of business and are at normal rates charged by the
consulting firm and recorded at the exchange amount. Consulting fees for
this firm in the third quarter of 2006 were $16,000 and $90,000 for the
nine months ended September 30, 2006. Fees for legal services are paid to
a law firm in which the corporate secretary is a partner. The legal
services are rendered in the normal course of business at normal rates
charged by the law firm. Legal fees for this firm paid in the third
quarter of 2006 were $36,000 and $532,000 for the nine months ended
September 30, 2006.
11. PER SHARE INFORMATION
The weighted average number of common shares outstanding during the
quarter ended September 30, 2006 of 86,447,064 was used to calculate
basic and diluted income (loss) per share (2005 - 48,015,117 basic;
48,663,407 diluted). The weighted average number of common shares
outstanding during the nine months ended September 30, 2006 of 84,516,269
was used to calculate basic and diluted income (loss) per share (2005 -
46,962,501). The total number of shares which are potentially dilutive in
future periods as of September 30, 2006 was 4,391,200.
12. SUBSEQUENT EVENT
On October 11, 2006 the Company issued by way of a bought deal private
placement, 6,500,000 common shares of the Company on a "flow-through"
basis pursuant to the Income Tax Act (Canada) (the "Flow-Through
Shares"), at a price of $1.82 per Flow-Through Share for total gross
proceeds of $11.83 million before agent's commission of $591,500. The
proceeds from the "flow-through" private placement will be used to incur
qualifying expenditures with respect to the continued exploration and
development of the Company's oil and natural gas properties prior to
December 31, 2007. The renouncement of these expenditures will be made to
the purchasers of these shares for the 2006 income tax year.
>>
%SEDAR: 00020114E
