Symbol: BEN - TSX
CALGARY, Nov. 8 /CNW/ -
<<
FINANCIAL AND OPERATING HIGHLIGHTS
For the periods ended September 30, 2005
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($ Cdn thousands, Three months ended Nine months
except as noted) September 30, ended September 30,
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% %
2005 2004 Change 2005 2004 Change
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Sales volume
Natural gas (mcf/day) 10,832 5,310 10,086 5,855
Oil and ngl's (bbl/day) 165 238 199 260
boe/day (6 to 1) 1,970 1,123 75% 1,880 1,236 52%
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Revenue net of royalties 7,667 3,321 18,331 10,970
Net income (loss) 534 (512) 980 (114)
Per share (basic and
diluted) $0.01 $(0.01) $0.02 $(0.00)
Funds flow from
operations 5,233 1,543 239% 11,458 5,741 100%
Per share (basic and
diluted) $0.11 $0.04 175% $0.24 $0.13 85%
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Capital costs
Exploration &
development 6,360 4,021 13,414 8,523
Land and seismic 789 1,541 6,568 4,352
Other 16 2 68 248
Total 7,165 5,564 29% 20,050 13,123 53%
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Net wells drilled 9 7 20 12
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Net working capital
(deficit) - including
bank debt (2,137) (5,973) (2,137) (5,973)
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Shares outstanding
End of period (000's) 52,961 43,427 52,961 43,427
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Third Quarter and nine month 2005 Operating Highlights
- Production - Q3 2005 production averaged 1,970 boe/d, up 75 percent
over Q3 2004 and up 3 percent from Q2 2005. For the first nine
months of 2005 production was 1,880 boe/d, up 52 percent over the
first nine months of 2004. Production costs declined to $7.02 per
boe in Q3 2005 compared to $10.99 per boe in Q3 2004 while on a
first nine month basis, production costs were $7.56 per boe compared
to $8.73 per boe.
- Funds Flow from Operations - Generated Q3 2005 funds flow of
$5.2 million ($0.11 per share), up 239 percent compared to Q3 2004
funds flow of $1.5 million ($0.04 per share). For the first nine
months of 2005 funds flow was $11.5 million, up 100 percent compared
to the first nine months of 2004.
- Drilling - The Company drilled its first Karr well in Q3 and
continued to drill in Lanfine. A total of nine net wells were
drilled in the third quarter. For the first nine months of 2005 we
have participated in 27 wells (20 net) resulting in 18 (14.5 net)
gas wells, 7 wells (5 net) unsuccessful and 2 (0.8 net) awaiting
completion. Subsequent to the end of Q3 the Company drilled and
cased 3 additional wells in Lanfine, 2 wells in Karr and 1 well in
Groat. The first well drilled in Karr in Q3 has been completed
subsequent to the end of Q3 and was not successful. In the fourth
quarter of 2005 activity will consist of 8 wells drilled in Lanfine,
4 in Karr and 1 in Groat.
- Land - The Company's added 7.5 sections of land in Q3 through
farm-ins and crown land sales. We now have 25 gross (16 net)
sections in Karr and an additional 2 net sections in Berland River
with drilling plans for both of these multi-zone areas. Preliminary
work has started on developing a third core area for the Company.
- Financing - The Company completed a private placement equity
financing in Q3, netting $12.9 million in cash proceeds. The
proceeds of the financing will be used to maintain the Company's
momentum on its capital program.
Chairman's Message
Berens maintained steady production in Q3 of 2005 in our busy industry
operating environment while continuing to improve our cost structure in the
field. We also embarked on our drilling program in Karr with our first well
drilled and cased in the quarter.
Berens has drilled with a 76 percent success rate in Lanfine in 2005
bringing our year-to-date totals in Lanfine to 13 new gas wells in 17 tests.
Lowering unit operating costs through volume increases and cost control
continues to be successful as operating costs were $7.02 per boe in Q3 2005
down from $10.99 per boe in Q3 2004. These efficiencies combined with higher
commodity prices have seen our operating margin improve 72 percent in Q3 2005
compared to Q3 of 2004.
We are experiencing upward pressure on service costs but are still
drilling and completing Lanfine wells cheaper in 2005 than we did in 2004.
This is a strong testament to our diligence and ingenuity in the field.
Detailed seismic analysis, enabling us to drill into better reservoir and
changed completion techniques in Lanfine have combined to reduce well
completions to as little as one-half our costs from early 2004. We continue to
work in Lanfine as our core cash flow area and have a large number of drilling
locations and prospects to continue drilling in Lanfine at least into 2007.
Berens' big news earlier in the year was the acquisition of a 19 section
position in the Karr (17 sections) and Berland River (2 sections) areas
through land sales and a farm-in. We have subsequently added to this position
with partners and another farm-in so that the Karr land position now totals 25
gross sections (16 net) with four drilling locations identified for the
balance of 2005 and another five to six in the first quarter of 2006. The Karr
area is characterized by multi-zone drilling potential and strong
infrastructure.
Never satisfied to sit still we have been working on developing a third
core area focused in the central part of Alberta in the general Olds to Edson
corridor. We have acquired a section of land as a start and are pursuing a
number of initiatives to establish a significant land position in this
corridor where our technical staff has strong experience and past success.
Berens began trading on the TSX Exchange on September 8, 2005. We
completed an equity issue in the third quarter, netting $12.9 million which
has put us in excellent financial condition to push forward on planned
drilling and expansion of our opportunity base. We were debt free at the end
of Q3 and we are seeing the debt levels remain low as we enjoy strong
production results and high energy prices as we move into Q4. We are in good
shape to progress on our plans.
Robert D. Steele
Chief Executive Officer
Berens Energy Ltd.
Management's Discussion and Analysis ("MD&A")
November 7, 2005
OVERVIEW
Berens Energy Ltd. ("Berens") is a full cycle oil and natural gas
exploration and production company with a concentrated production and land
base in Eastern Alberta approximately 300 kilometers east of the City of
Calgary with new opportunities established in the Grande Prairie region of
west central Alberta.
All calculations converting natural gas to crude oil equivalent have been
made using a ratio of six thousand cubic feet ("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, 2004 Annual
Report, Audited Financial Statements and Notes thereto and the unaudited
interim financial statements for the current quarter. This MD&A was prepared
using information that is current as of November 7, 2005 unless otherwise
noted.
FORWARD LOOKING INFORMATION
This MD&A contains forward looking or outlook 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 that could
cause actual results to 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.
REVIEW OF INTERIM FINANCIAL STATEMENTS
The financial statements in this interim report and the accompanying
notes and MD&A have not been reviewed by the Company's auditor.
QUARTERLY INFORMATION
The Company became a reporting issuer on November 26, 2003. Prior to that
time, it was a private company involved in a business unrelated to the oil and
gas business.
2005
--------------------------------
($000's except as noted) Q3 Q2 Q1
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Sales volumes:
Natural gas (mcf/day) 10,832 10,250 9,155
Oil and ngl's (bbl/day) 165 200 233
Barrels of oil equivalent
(boe/day-6 to1) 1,970 1,908 1,759
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Financial:
Net revenue 7,667 5,754 4,910
Net income (loss) 534 887 (441)
per share - basic $ 0.01 $ 0.02 $ (0.01)
per share - diluted $ 0.01 $ 0.02 $ (0.01)
Capital costs 7,165 3,423 9,499
Shares outstanding 52,961 46,427 46,427
Bank debt - 10,080 10,480
Working capital (deficit)
including bank debt (2,137) (13,121) (13,216)
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Per unit information:
Natural gas price ($/mcf) $ 9.16 $ 7.29 $ 6.91
Oil and liquids price ($/barrel) $ 57.47 $ 33.11 $ 30.81
Oil equivalent price ($/boe) $ 55.05 $ 42.61 $ 40.05
Operating netback ($/boe) $ 34.07 $ 24.81 $ 21.12
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Net wells drilled:
Natural gas 7 3 5
Oil 0 0 0
Dry 2 1 2
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Total 9 4 7
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2004
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($000's except as noted) Q4 Q3 Q2 Q1
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Sales volumes:
Natural gas (mcf/day) 7,089 5,310 6,326 5,936
Oil and ngl's (bbl/day) 240 238 292 252
Barrels of oil equivalent
(boe/day-6 to1) 1,422 1,123 1,347 1,241
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Financial:
Net revenue 3,803 3,321 4,289 3,360
Net income (loss) (1,652) (512) 335 63
per share - basic $ (0.04) $ (0.01) $ 0.01 $ 0.00
per share - diluted $ (0.04) $ (0.01) $ 0.01 $ 0.00
Capital costs 6,932 5,564 4,732 2,827
Shares outstanding 46,427 43,427 43,427 43,427
Bank debt 4,500 4,250 100 -
Working capital (deficit)
including bank debt (6,461) (5,973) (1,851) 329
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Per unit information:
Natural gas price ($/mcf) $ 6.48 $ 6.44 $ 7.04 $ 6.64
Oil and liquids price
($/barrel) $ 31.88 $ 40.02 $ 32.56 $ 30.16
Oil equivalent price
($/boe) $ 36.08 $ 38.91 $ 40.13 $ 37.88
Operating netback ($/boe) $ 18.96 $ 19.86 $ 24.33 $ 20.71
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Net wells drilled:
Natural gas 11 5 3 2
Oil 1 1 - -
Dry - 1 - -
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Total 12 7 3 2
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RESULTS OF OPERATIONS
Production Volume
Production volume averaged 1,970 boe/d for the third quarter of 2005, up
75 percent compared to 1,123 boe/d in the third quarter of 2004. Natural gas
represented 92 percent of production in the third quarter of 2005, up from 79
percent in the second quarter of 2004. The remaining eight percent of
production is conventional heavy oil and natural gas liquids. The Company
resolved a series of audit discrepancies with a mid-stream company that dated
back as far as 2003 that resulted in a 58 boe/d uplift in the quarter. Net of
the audit adjustment production volume was 1,912 boe/d for the third quarter
of 2005, up 70 percent compared to the third quarter of 2004. For the first
nine months of 2005 production volume averaged 1,880 boe/d, up 52 percent
compared to the first nine months of 2004. Net of the audit adjustment, 2005
nine month volumes were 1,870 boe per day, up 51 percent over the first nine
months of 2005.
The Company has continued to drill successfully in Lanfine and grow
production throughout the year as planned. By the end of the third quarter
Lanfine production represented 80 percent of total production while production
from the Company's new west central Alberta growth areas was eight percent of
the third quarter production. Drilling, re-entries and completions in west
central Alberta have been delayed by ongoing wet weather and the Company does
not expect significant additional west central Alberta production to be on
stream by year end.
Looking forward it is expected that fourth quarter 2005 volumes will
average over 2,000 boe/d as the Company is tying in four wells in Lanfine that
were drilled in the third quarter and will drill an additional five wells in
Lanfine. The additional wells will be drilled beginning in early November and
some may be on stream prior to year end. West central Alberta drilling is
expected to add to volumes in early 2006 providing the Company with production
momentum early next year.
Production Revenue
Natural gas prices averaged $9.16 per mcf for the third quarter of 2005
compared to $6.44 per mcf in the third quarter of 2004. Average liquids prices
in the third quarter of 2005 were $57.47 per barrel compared to $40.01 per
barrel in the third quarter of 2004. The light/heavy crude oil differentials
narrowed in the third quarter and heavy oil prices are improving significantly
over 2004 and early 2005.
For the first nine months of 2005 gas prices averaged $7.92 per mcf, up
18 percent compared to the first nine months of 2004. Oil and liquids prices
of $38.30 in the first nine months of 2005 were up 12 percent compared 2004.
On a per barrel of oil equivalent basis, prices averaged $55.05 in the third
quarter of 2005 compared to $38.72 in the third quarter of 2004, up 42
percent. In the first nine months of 2005 per boe prices were $46.28 per boe,
up 19 percent compared to the first nine months of 2004.
Revenue was up 149 percent in the third quarter of 2005 compared to the
third quarter of 2004. Volume increases contributed 75 percent to the quarter
over quarter increase compounded by 42 percent higher prices. For the first
nine months of 2005 revenue was up 81 percent compared to the first nine
months of 2004 comprised of a 52 percent volume increase compounded by 19
percent increase in per boe prices.
Royalties
Royalties, net of Alberta Royalty Tax Credit (ARTC), averaged 23 percent
of revenue for the third quarter of 2005 compared to 17 percent of revenue in
the third quarter of 2004. Excluding ARTC, royalty rates averaged 24 percent
in the third quarter of 2005 and 20 percent in the third quarter of 2004.
Lower royalties after ARTC in 2004 were due to the Company recording ARTC as
earned during the year. During 2005 the Company is recording ARTC evenly
throughout the year. For the first nine months of 2005 royalties net of ARTC
averaged 23 percent and 24 percent excluding ARTC compared to 17 percent and
20 percent for the first nine months of 2004. Overall royalty costs were up
241 percent in the third quarter of 2005 compared to the third quarter of 2004
and up 150 percent when comparing royalties on a year-to-date basis due to
increased volumes and commodity prices which attract higher royalty rates.
Production Expenses
Production expenses averaged $7.02 per boe in the third quarter of 2005
down 36 percent compared to $10.99 per boe in the third quarter of 2004. The
Company has focused on operating costs and these efforts combined with
increasing volume have contributed to lower per unit costs. Per unit
production expenses in the third quarter of 2005 benefited from the additional
volume recorded with the above noted audit adjustment. Removing the effect of
the audit adjustment, production expenses for the third quarter of 2005 were
$7.28 for a decrease of 34 percent compared to the third quarter of 2004. For
the first nine months of 2005 production expenses were $7.56 per boe down 13
percent from the first nine months of 2004. Management believes production
expenses in the $7.00 to $7.25 range are achievable on a corporate wide basin
on an ongoing basis.
General and Administrative Expenses
General and administrative costs, including stock based compensation,
were up 67 percent in the third quarter of 2005 compared to the third quarter
of 2004. Increased costs were incurred in the third quarter of 2005 for legal
and stock exchange fees related to the Company's listing on the TSX Exchange
totaling $180,000. On a per boe basis, general and administrative costs were
$4.83 for the third quarter of 2005, down 5 percent compared to $5.06 per boe
in the second quarter of 2004 despite the one time costs related to the TSX
listing. For the first nine months of 2005 general and administrative costs
were up 23 percent compared to the first nine months of 2004. The new listing
costs combined with second quarter costs related to spending on due diligence
efforts for an acquisition pursued in the second quarter contributed to a
significant portion of the increase. On a per unit basis these costs declined
by 18 percent to $4.41 per boe in the first nine months of 2005 compared to
the first nine months of 2004 as increased volume have offset the effect of
the overall increase in costs. Berens does not capitalize any general and
administrative costs.
Interest Expense
Interest expense is incurred on the Company's bank line of credit. The
Company had limited borrowings in the first nine months of 2004.
Operating Netback
Operating netback represents the profit margin realized by the production
and sale of petroleum and natural gas.
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Quarterly Operating Netbacks Three months ended Nine months ended
($'s per boe) September 30 September 30
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2005 2004 2005 2004
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Sales price 55.05 38.72 46.28 38.78
Less:
Royalties (net of ARTC) 12.76 6.56 10.56 6.40
Production expenses 7.02 10.99 7.56 8.73
Transportation charges 1.20 1.29 1.15 1.26
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Operating netback 34.07 19.87 27.01 22.39
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Depletion, Amortization and Accretion
Depletion, amortization and accretion totaled $4.8 million ($26.32 per
boe) in the third quarter of 2005 compared to $2.0 million ($19.37 per boe) in
the third quarter of 2004. For the first nine months of 2005 costs were
$11.4 million ($22.15 per boe) compared to costs of $5.7 million ($16.93 per
boe) for the first nine months of 2004. The higher per boe rates are partially
caused by significant spending that has taken place in west central Alberta
for which few reserves have been booked as the drilling program is in its
early stages. Also contributing to higher per boe rates in 2005 were reserve
revisions from the 2004 year-end independent petroleum consultants reserve
report which resulted in an increased per boe depletion rate.
Income Taxes
Cash income taxes of $24,000 were booked in the third quarter of 2005 and
$55,000 on a year to date basis to accrue for capital and resource taxes. The
Company does not expect to be cash taxable for 2005 or 2006 as there are ample
capital cost pools and expected future capital spending to shelter taxable
income.
Company recorded a future tax credit in the third quarter of 2005 as
depletion and amortization charges exceeded income tax pools claimed which
reduced the timing difference between our book and tax assets. In December
2003 the Company issued 3,000,000 flow-through shares for $4,830,000. In
accordance with the agreements between the Company and the flow-through
shareholders, the Company renounced $4,830,000 of Canadian Cumulative
Exploration Expense ("CEE") as of June 30, 2005. This renunciation gave rise
to a future tax liability of $1,541,000. The tax pools of the Company included
an unrecognized future tax asset in the amount of $985,000 that was realized
in the second quarter and accordingly, a future tax recovery was recognized in
the second quarter.
NET INCOME
Net income for the third quarter of 2005 was $534,000 ($0.01 per share)
compared to a loss of $512,000 ($0.01 per share) in the third quarter of 2004.
For the first nine months of 2005 net income was $980,000 ($0.02 per share)
compared to a loss of $114,000 ($0.00 per share) in the first nine months of
2004. The 2005 year-to-date income has resulted from higher volumes, higher
prices and lower operating costs combined with the recognition of a future tax
asset on the renunciation of CEE in the second quarter.
CAPITAL COSTS
Capital costs were $7.2 million in the third quarter of 2005, up from
$5.6 million in the third quarter of 2004 as operations continued in Lanfine
while drilling in west central Alberta was ramped up. Capital costs were
$20.0 million in the first nine months of 2005 compared to $13.1 million in
the same period in 2004 as the Company has spent more on land in 2005 to
establish a growth base in west central Alberta and has followed the land
acquisitions with initial drilling activity. Berens participated in 20 net
wells in the first nine months of 2005 compared to 12 net wells in the same
period for 2004.
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Three months ended Nine months ended
($000's) September 30 September 30
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2005 2004 2005 2004
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Drilling and completion 6,360 4,021 13,414 8,523
Land 663 1,144 4,669 2,540
Geological and geophysical 126 397 1,899 1,812
Office and other 16 2 68 248
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Total 7,165 5,564 20,050 13,123
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WORKING CAPITAL
Accounts receivable of $5.3 million at September 30, 2005 was primarily
August and September production revenues. Accounts payable at September 30,
2005 of $9.4 million were comprised mainly of trade payables for capital and
operating costs, royalties, amounts owing to joint venture partners and
significant capital costs accrued at the end of the quarter for ongoing
drilling operations.
The Company's operating line of credit was completely repaid in the third
quarter of 2005 from the proceeds of an equity issue that netted
$12.9 million. Working capital was in a deficit position of $2.1 million at
September 30, 2005 almost unchanged from $2.0 million at the end of 2004. It
is expected that the working capital deficiency will be financed by the bank
operating line in the short term and by increased operating revenue in the
longer term.
LIQUIDITY AND CAPITAL RESOURCES
Berens currently plans to fund its operations and capital expenditures
with a mix of cash flow and debt financing through the bank operating line.
Berens has an operating bank line of $13.0 million, secured by Berens'
production properties, which was undrawn as at September 30, 2005.
NON-GAAP MEASUREMENTS
This MD&A contains the term "funds flow from operations". As an indicator
of the Company's performance, this term 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 flow from
operations may not be comparable to that reported by other companies,
especially those in other industries. Management feels that funds flow 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.
The reconciliation between net income and funds flow from operations for
the periods ended September 30 is as follows.
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Three months ended Nine months ended
($000's) September 30 September 30
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2005 2004 2005 2004
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Net income $ 534 $ (512) $ 980 $ (114)
Items not requiring cash:
Depletion, amortization and
accretion 4,770 2,001 11,366 5,716
Future income tax recovery (139) - (1,124) -
Stock based compensation 68 54 236 139
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Funds flow from operations 5,233 1,543 11,458 5,741
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The Company also presents funds flow from operations per share consistent
with the calculation of earnings per share, whereby per share amounts are
calculated using weighted average shares outstanding. Funds flow from
operations per share was $0.11 (basic and diluted) for the third quarter of
2005 compared to $0.04 (basic and diluted) per share for the third quarter of
2004. Funds flow from operations per share for the first nine months of 2005
was $0.24 (basic and diluted) compared to $0.13 per share (basic and diluted)
for the first nine months of 2004.
RISKS
The Company's 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.
Based on the Company's plans for 2005 the following sensitivities are
illustrated for key financial factors:
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Funds Flow
from
Earnings Operations
Sensitivity (000's) Effect Effect
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Natural gas price - Cdn$0.10 per mcf $ 182 $ 285
Oil price - Cdn$1.00 per bbl $ 40 $ 63
Interest rate - 1 percentage point $ 54 $ 85
Exchange rate - Cdn$0.01 $ 236 $ 368
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Other risks that the Company is exposed to are related to our operations.
They include exploration risks and risks related to safety and environment.
Exploration risk is managed by a thorough analysis to ensure the Company is
exposed to a balanced risk profile of both low risk and higher risk drilling
prospects. The Company also has documented environmental health and safety
plans as well as a comprehensive emergency response plan to mitigate operating
risks.
The Company has no long-term contractual obligations other than office
rent and vehicle leases.
The Company has no off-balance sheet arrangements.
The Company has no commodity price or interest rate hedges or fixed price
contracts in place.
RELATED PARTY TRANSACTIONS
The Company contracts a recruiting consulting firm in which one of its
directors is the chairman. The executive services rendered are in the normal
course of business and are at normal rates charged by the consulting firm.
SHARE DATA
As of the date of this MD&A the Company had 52,960,769 issued and
outstanding common shares. Additionally, the Company has issued options to
purchase 2,736,200 common shares.
OUTLOOK
Berens' strong land position was enhanced in the first quarter of 2005
with significant land acquisitions made in the Company's west central Alberta
growth area. The Company began drilling on the west central Alberta lands in
the third quarter of 2005 with one Karr wells drilled and cased in the third
quarter. An additional four operated wells are planned for Karr for the
remainder of 2005. In Lanfine the capital program is well defined as there is
sufficient undeveloped acreage in the area for the Lanfine drilling program
for the rest of 2005 and through 2006. Currently there are an additional six
wells planned in Lanfine for the remainder of 2005.
The Company has recently increased its Karr land position by farming in
to 5.5 additional sections (2.8 net) to increase the total number of sections
in Karr to 25 (16 net). The Company intends to continue to work with partners
in west central Alberta to leverage the Company's average interest in most of
its lands to approximately 50 percent while at the same time increasing the
total number of sections of land in which it has ownership.
In the third quarter the board of directors approved a 2005 capital
program increase from $20 million to $27 to enable the Company to aggressively
pursue its drilling plans in west central Alberta. Management currently
estimates average 2005 production in the 1,900 boe/d range that is projected
to yield production growth of approximately 48 percent over 2004. The
additional capital is heavily weighted to west central Alberta drilling. The
west central drilling is not expected to contribute significantly to 2005
productions volumes. With success however, the west central Alberta drilling
can deliver strong production momentum early in 2006. The Company has a well
defined, balanced growth strategy that delivers low risk drilling in eastern
Alberta combined with higher impact, deeper drilling opportunities in west
central Alberta. Work has been initiated on developing a third core area that
will have risk characteristics that sit somewhat in the middle of the
Company's two current operating areas. The intention is to stay focused in a
small number of areas to enable a high level of expertise to be developed in
each area.
Berens Energy Ltd.
Balance Sheets
(unaudited)
As at,
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(000's) September December
30, 2005 31, 2004
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ASSETS
Current
Cash and cash equivalents $ 1,391 $ 35
Accounts receivable 5,269 3,365
Prepaid expenses and deposits 710 492
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7,370 3,892
Investments 299 299
Capital assets (notes 3 & 7) 47,728 38,811
Goodwill 14,805 14,805
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$ 70,202 $ 57,807
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LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Bank loan (note 7) - $ 4,500
Accounts payable and accrued liabilities $ 9,435 5,795
Taxes payable 72 58
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9,507 10,353
Future income taxes 417 -
Asset retirement obligation (note 4) 882 648
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10,806 11,001
Shareholders' equity
Capital stock (note 5) 59,711 48,331
Contributed surplus (note 5) 471 241
Deficit (786) (1,766)
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59,396 46,806
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$ 70,202 $ 57,807
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See accompanying notes to the financial statements
Berens Energy Ltd.
Statements of Operations and Retained Earnings (Deficit)
(unaudited)
For the three and nine months ended September 30,
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(000's) Three months Nine months
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2005 2004 2005 2004
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Revenue
Oil and natural gas revenue $ 9,979 $ 3,999 $ 23,749 $ 13,138
Royalties, net of ARTC (2,312) (678) (5,418) (2,168)
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7,667 3,321 18,331 10,970
Interest 1 - 2 18
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7,668 3,321 18,333 10,988
Expenses
Production 1,273 1,135 3,880 2,959
Transportation 217 134 592 428
Depletion, amortization
and accretion 4,770 2,001 11,366 5,716
General and administrative 808 468 2,026 1,693
Stock based compensation 68 54 236 139
Interest expense 113 48 322 63
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7,249 3,840 18,422 10,998
-------------------------------------------------------------------------
Income (loss) before income taxes 419 (519) (89) (10)
Taxes
Future income tax recovery (139) - (1,124) -
Current income tax expense 24 7 55 104
-------------------------------------------------------------------------
(115) 7 (1,069) 104
-------------------------------------------------------------------------
Net income for the period 534 (512) 980 (114)
Retained earnings (deficit),
beginning of period (1,320) 398 (1,766) -
-------------------------------------------------------------------------
Retained earnings (deficit),
end of period $ (786) $ (114) $ (786) $ (114)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per share (note 8)
Basic and diluted $ 0.01 $ (0.01) $ 0.02 $ (0.00)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
2005 2004 2005 2004
-------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income for the period $ 534 $ (512) $ 980 $ (114)
Add items not involving cash
Depletion, amortization and
accretion 4,770 2,001 11,366 5,716
Future income tax recovery (139) - (1,124) -
Stock-based compensation 68 54 236 139
-------------------------------------------------------------------------
5,233 1,543 11,458 5,741
Change in non-cash working
capital items (note 6) 2,826 235 2,395 (196)
-------------------------------------------------------------------------
8,059 1,778 13,853 5,545
-------------------------------------------------------------------------
FINANCING ACTIVITIES
Change in bank loan (10,080) 4,150 (4,500) 4,250
Net proceeds from private
offerings 12,869 - 12,869 -
Proceeds from the exercise
of stock options 46 - 46 22
-------------------------------------------------------------------------
2,835 4,150 8,415 4,272
-------------------------------------------------------------------------
INVESTING ACTIVITIES
Purchase of property and
equipment (7,165) (5,564) (20,050) (13,123)
Change in non-cash working
capital items (note 6) (2,382) (368) (862) (673)
-------------------------------------------------------------------------
(9,547) (5,932) (20,912) (13,796)
-------------------------------------------------------------------------
Increase (decrease) in cash and
cash equivalents 1,347 (4) 1,356 (3,979)
Cash and cash equivalents,
beginning of period 44 47 35 4,022
-------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 1,391 $ 43 $ 1,391 $ 43
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the financial statements
BERENS ENERGY LTD.
Notes to Financial Statements
(unaudited)
Three and nine months ended September 30, 2005 and 2004
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 Company's primary areas of operation are in eastern and
west central Alberta.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The interim financial statements of the Company have been prepared by
management following the same accounting policies as the most recent
annual audited financial statements except as discussed below.
Certain disclosures, which are normally required to be included in notes
to the annual financial statements, are condensed or omitted for interim
reporting. Accordingly, the interim financial statements should be read
in conjunction with the Company's audited annual financial statements for
the year ended December 31, 2004. Certain prior period amounts have been
restated to conform to current disclosure standards.
3. CAPITAL ASSETS
-------------------------------------------------------------------------
($000's) September 30, 2005 December 31, 2004
Accumulated Accumulated
depletion, depletion,
amortization amortization
Cost and accretion Cost and accretion
-------------------------------------------------------------------------
Petroleum and natural
gas properties 61,292 21,031 48,394 9,757
Office and computer
equipment 300 83 232 58
-------------------------------------------------------------------------
68,842 21,114 48,626 9,815
-------------------------------------------------------------------------
Net book value 47,728 38,811
-------------------------------------------------------------------------
-------------------------------------------------------------------------
At September 30, 2005, costs of $13,706,000 related to undeveloped land
have been excluded from the depletion calculation (2004 - $7,715,000).
4. ASSET RETIREMENT OBLIGATIONS
The total future asset retirement obligation was estimated by management
based on the Company's 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 paid in future
periods.
The following table reconciles the Company's asset retirement obligation
as follows:
-------------------------------------------------------------------------
($000's)
-------------------------------------------------------------------------
Obligation, December 31, 2004 648
Increase in obligation during the period 353
Amounts paid to retire assets (186)
Accretion expense 67
-------------------------------------------------------------------------
Obligation, September 30, 2005 882
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The total undiscounted obligation for asset retirement is $2,483,000 as
at September 30, 2005. The Company uses a credit adjusted risk free rate
of 12 percent and an inflation rate of 11/2 percent to calculate the
present value of the asset retirement obligations. These payments are
expected to be made over the next 5 to 15 years.
5. CAPITAL STOCK
(a) Authorized Capital
The authorized capital of the Company 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
-------------------------------------------------------------------------
Balance December 31, 2003 43,405,802 $ 56,793
Stock options exercised during the year 21,667 21
Reduction of contributed surplus for
options exercised - 1
Private placement for cash 3,000,000 4,564
Reduction of stated capital - (12,944)
Share issue costs - (104)
-------------------------------------------------------------------------
Balance December 31, 2004 46,427,469 $ 48,331
-------------------------------------------------------------------------
Tax benefits renounced - (1,541)
Stock options exercised during the year 33,300 46
Reduction of contributed surplus for
options exercised - 6
Private placements for cash 6,500,000 12,923
Share issue costs - (54)
-------------------------------------------------------------------------
Balance September 30, 2005 52,960,769 $ 59,711
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Private Placements:
The Company issued 4,500,000 common shares on September 12, 2005 in a
private placement at $1.95 per share for cash proceeds of $8,775,000
before agent's commission of $482,625. The proceeds of the financing are
to be used to finance oil and gas expenditures and for general corporate
purposes.
The Company issued 2,000,000 flow-through common shares on
September 12, 2005 in a private placement at $2.45 per share for cash
proceeds of $4,900,000 before 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 will be made to the purchasers of
these shares for the 2005 income tax year.
The Company issued 3,000,000 flow-through common shares on
December 9, 2004 in a private placement at $1.61 per share for cash
proceeds of $4,830,000 before agent's commission of $266,000 to finance
certain oil and gas expenditures to be incurred in 2005. The renouncement
of these expenditures was made to the purchasers of these shares in the
second quarter of 2005.
(c) Stock Option Plan
The Company has a stock option plan under which 4,000,000 common shares
have been reserved for options to be distributed to directors, officers,
employees and consultants to the Company with terms established by the
board of directors.
Options granted under the plan generally have a five year term to expiry
and vest equally over a three year period commencing on the first
anniversary date of the grant. The exercise price of each option equals
the closing market price of the Company's common shares on the day prior
to the date of the grant.
The following table sets forth a reconciliation of the plan activity
through September 30, 2005.
-------------------------------------------------------------------------
Weighted average
Number of exercise price
Options ($ per share)
-------------------------------------------------------------------------
Outstanding, beginning of period 2,784,500 1.22
Granted 75,000 1.20
Cancelled (90,000) 1.70
Exercised (33,300) 1.40
-------------------------------------------------------------------------
Outstanding, end of period 2,736,200 1.19
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Exercisable 1,140,024 1.11
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The following table sets forth additional information relating to the
stock options outstanding at September 30, 2005.
-------------------------------------------------------------------------
Options Outstanding Exercisable Options
-------------------------------------------------------------------------
Weighted Weighted
average Weighted average Weighted
exercise average exercise average
Exercise Number price years Number price years
price of ($ per to of ($ per to
range Options share) expiry Options share) expiry
-------------------------------------------------------------------------
$1.00 to $1.10 1,220,000 1.00 2.56 888,327 1.00 2.49
$1.11 to $1.20 577,500 1.17 4.22 - - -
$1.21 to $1.30 152,000 1.27 4.08 21,666 1.30 3.95
$1.31 to $1.40 274,200 1.39 3.78 49,199 1.38 3.73
$1.41 to $1.50 197,500 1.47 3.46 65,833 1.47 3.46
$1.51 to $1.60 300,000 1.55 3.26 99,999 1.55 3.26
$1.61 to $1.70 15,000 1.70 3.17 15,000 1.70 3.17
-------------------------------------------------------------------------
$1.00 to $1.70 2,736,200 1.19 3.26 1,140,024 1.11 2.71
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The Company has adopted the fair value method for measuring option
awards. For 2004 and 2005 calculations the key assumptions used for the
Black Scholes-based valuation of issued options were: Risk free rate -
4.00 percent; average expected life - 4.5 years; no expected dividend
yield; 42 percent volatility. The Company has not incorporated an
estimated future forfeiture assumption in its calculations, and will
recognize forfeitures as they occur. Based on the fair value method,
$235,977 was recorded as compensation expense for the nine month period
ended September 30, 2005 and $67,977 for the three month period ended
September 30, 2005 (2004 - $139,112 and $53,975) with corresponding
increases recorded to contributed surplus.
The following table reconciles the Company's contributed surplus balance
as follows:
-------------------------------------------------------------------------
($000's)
-------------------------------------------------------------------------
Contributed surplus, December 31, 2004 241
Stock based compensation 236
Reduction of contributed surplus for options exercised (6)
-------------------------------------------------------------------------
Contributed surplus, September 30, 2005 471
-------------------------------------------------------------------------
-------------------------------------------------------------------------
6. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in Non-cash Working Capital
For the nine month periods ended September 30,
-------------------------------------------------------------------------
($000's) 2005 2004
Accounts receivable (1,904) 91
Prepaid expenses and deposits (217) (240)
Accounts payable and accrued liabilities 3,640 99
Income taxes payable 14 (817)
-------------------------------------------------------------------------
1,533 (869)
Less:
Change in non-cash working capital related to
investing activities (862) (673)
-------------------------------------------------------------------------
Change in non-cash working capital related to
operating activities 2,395 (196)
-------------------------------------------------------------------------
Cash taxes and interest paid during the three and six month periods ended
September 30,
Three months Nine months
-------------------------------------------------------------------------
($000's) 2005 2004 2005 2004
-------------------------------------------------------------------------
Cash income and other taxes 23 - 83 1,056
Cash interest paid 113 48 322 63
-------------------------------------------------------------------------
7. BANK OPERATING LINE
Berens has an agreement with a Canadian bank for a revolving operating
line for $13.0 million. Collateral for the operating line of credit
includes a general assignment of book debts and a $35 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 plus
3/8th of one percent or 4.875 percent at September 30, 2005. On
September 30, 2005 the bank line was at a zero balance.
8. PER SHARE INFORMATION
The weighted average number of common shares outstanding during the nine
month period ended September 30, 2005 was 46,962,501 (2004: 43,455,533).
The weighted average number of common shares outstanding during the
quarter ended September 30, 2005 was 48,015,117 (2004: 43,427,469). These
share amounts were used to calculate basic income and loss per share. On
a diluted basis the weighted average number of common shares outstanding
during the nine month period ended September 30, 2005 was 47,918,737
(2004 - 43,647,609). No changes to share capital have occurred from
September 30, 2005 to the date of the Management's Discussion and
Analysis in this report.
>>
%SEDAR: 00020114E
