Symbol: BEN - TSX Venture Exchange
CALGARY, Aug. 18 /CNW/ -
<<
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FINANCIAL AND OPERATING HIGHLIGHTS
For the periods ended June 30, 2005
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($ Cdn thousands, Three months Six months
except as noted) ended June 30, ended June 30,
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% %
2005 2004 Change 2005 2004 Change
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Sales volume
Natural gas
(mcf/day) 10,250 6,326 9,706 6,131
Oil and ngl's
(bbl/day) 200 292 216 273
boe/day
(6 to 1) 1,908 1,347 42% 1,834 1,294 42%
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Revenue net of
royalties 5,754 4,289 10,665 7,649
Net income 887 335 446 398
Per share
(basic and
diluted) $0.02 $0.01 $0.01 $0.01
Cash flow from
operations 3,518 2,452 43% 6,225 4,197 48%
Per share
(basic and
diluted) $0.07 $0.06 17% $0.13 $0.10 30%
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Capital costs
Exploration
&
development 2,693 2,650 7,054 4,501
Land and
seismic 707 1,849 5,779 2,810
Other 23 234 52 248
Total 3,423 4,733 (28%) 12,885 7,559 70%
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Net wells
drilled 4 3 11 5
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Net working
capital
(deficit) -
including
bank debt (13,120) (1,951) (13,120) (1,951)
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Shares
outstanding
End of
period
(000's) 46,427 43,427 46,427 43,427
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Second Quarter and six month 2005 Operating Highlights
- Production - Q2 2005 production averaged 1,908 boe/d, up 42
percent over Q2 2004 and up 8 percent from Q1 2005. For the first
six months of 2005 production was 1,834 boe/d, up 42 percent over
the first six months of 2004. Production costs declined to $7.16
per boe in Q2 2005 compared to $8.21 per boe in Q2 2004.
- Cash Flow from Operations - Generated Q2 2005 cash flow of
$3.5 million ($0.07 per share), up 43 percent compared to Q2 2004
cash flow of $2.5 million ($0.06 per share). For the first six
months of 2005 cash flow was $6.2 million, up 48 percent compared
to the first six months of 2004.
- Drilling - The Company had a quiet second quarter of drilling with
3 successful gas wells in Lanfine. For the first six months of
year we have participated in 16 wells (11 net) resulting in 11
(8 net) gas wells and 5 wells (3 net) plugged and abandoned. In
the second half of 2005 activity will increase as we plan to
participate in 22 wells (15 net). Nine of these wells (4 net) are
planned for our west central Alberta growth area.
- Land - The Company's focus in the second quarter was to identify
drilling prospects on the recently accumulated land position in
west central Alberta, namely Karr, Berland River and Bigstone.
With partners, we now have 20 gross (15 net) sections in Karr and
an additional 2 net sections in Berland River, south of Bigstone.
Chairman's Message
The momentum Berens started in 2004 was maintained into Q2 of 2005 with
strong production growth and significant operational improvements.
Berens drilled with a 75 percent success rate in Lanfine in Q2 2005
bringing our year-to-date totals in Lanfine to 7 new gas wells in 9 tests.
Lower unit operating costs through increased volumes and strict cost control
was another success story for Berens in the second quarter. Operating costs
were $7.16 per boe in Q2 2005 down from $8.21 per boe in Q2 2004.
We continue to drill our wells in Lanfine as cost efficiently as
possible. We have seen upward pressure on our drilling costs but are still
drilling Lanfine wells for as much as 15 percent less than we were over a year
ago. We have improved our completion techniques in Lanfine, now completing
most wells for as little as one-half our costs from early 2004 while
continuing to deliver excellent productivity. Our undeveloped land position in
Lanfine will continue to deliver drilling locations to support our plans for
the area at least through 2006.
In Q1 2005 our big news was the acquisition of a 17 section position in
the Karr area through land sales and a farm-in. We also purchased two sections
in Berland River. Our land position in Karr is well concentrated and the area
is characterized by multi-zone drilling potential and strong infrastructure.
Berens currently has firm plans to participate in six (3 net) wells in Karr, a
well in Berland River and two wells in Bigstone in the second half of 2005. We
are actively working with potential partners to add land and further drilling
opportunities in these multi-zone regions.
During the second quarter we initiated steps to transfer our stock
listing to the TSX Exchange from the TSX Venture exchange. The final
application was submitted in July and we expect to be listed on the TSX
Exchange in the third quarter.
We are on track to deliver our forecast average 2005 production volume of
1,800 boe/d and exit the year at over 2,000 boe/d. The first quarter capital
was weighted toward land acquisition for a new growth area. Now it is time to
turn the drill bit in our new growth area with the potential to add
significant production and reserve volumes. Our first well in Karr was spud by
a partner in early August and we look forward to a late August spud date for
our first Berens operated well in Karr. These are exciting times for our
company as we continue to execute on the plans we have laid out.
Robert D. Steele
Chief Executive Officer
Berens Energy Ltd.
Management's Discussion and Analysis ("MD&A")
August 17, 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 August 17, 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 completely unrelated to
the oil and gas business.
2005
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($000's except as noted) Q2 Q1
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Sales volumes:
Natural gas (mcf/day) 10,250 9,155
Oil and ngl's (bbl/day) 200 233
Barrels of oil equivalent (boe/day-6 to1) 1,908 1,759
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Financial:
Net revenue 5,754 4,910
Net income (loss) 887 (441)
per share - basic $0.02 $(0.01)
per share - diluted $0.02 $(0.01)
Capital costs 3,452 9,499
Shares outstanding 46,427 46,427
Bank debt 10,080 10,480
Working capital (deficit) including bank debt (13,121) (13,216)
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Per unit information:
Natural gas price ($/mcf) $7.29 $7.13
Oil and liquids price ($/barrel) $33.11 $30.81
Oil equivalent price ($/boe) $42.61 $41.22
Operating netback ($/boe) $24.81 $21.12
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Net wells drilled:
Natural gas 3 5
Oil 0 0
Dry 1 2
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Total 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 to 1) 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 1,908 boe/d for the second quarter of 2005, up
42 percent compared to 1,347 boe/d in the second quarter of 2004. Natural gas
represented 90 percent of production in the second quarter of 2005, up from
78 percent in the second quarter of 2004. The remaining 10 percent of
production is conventional heavy oil and natural gas liquids. For the first
six months of 2005 production volume averaged 1,834 boe/d, up 42 percent
compared to the first six months of 2004. A successful drilling program in the
third and fourth quarter of 2004 established momentum going into the end of
2004. This momentum was continued by four successful gas wells in Lanfine in
the first quarter of 2005 that were tied in late in the first quarter which
boosted second quarter production. Supplementing the drilling success, Berens
conducted a number of successful production optimization activities in Lanfine
which added production volume in the second quarter. Drilling and re-entries
planned for the second quarter in west central Alberta were delayed by wet
weather.
Looking forward it is expected that third quarter 2005 volumes will be
similar to the second quarter as our drilling and re-entry activities in west
central Alberta are being initiated in August. The Company is currently
connecting three wells in Lanfine as of mid-August that are expected to
largely replace natural declines in the third quarter. The Company plans 13
additional wells (12.2 net) in Lanfine and as many as nine (4 net) wells in
west central Alberta prior to the end of 2005. The west central Alberta wells
are expected to add to volumes late in 2005 providing the Company with strong
production momentum into 2006.
Production Revenue
Natural gas prices averaged $7.29 per mcf for the second quarter of 2005
compared to $7.04 per mcf in the second quarter of 2004. Average liquids
prices in the second quarter of 2005 were $33.11 per barrel compared to $32.56
per barrel in the second quarter of 2004. The effect of higher WTI prices in
2005 has been offset by wider light/heavy differentials compared to the same
period in 2004. At the time of writing the light/heavy differential has
narrowed and heavy oil prices are improving significantly.
For the first six months of 2005 gas prices averaged $7.22 per mcf, up
five percent compared to the first six months of 2004. Oil and liquids prices
of $31.88 were almost unchanged in the first six months of 2005 compared to
2004.
On a per barrel of oil equivalent basis, prices averaged $42.61 in the
second quarter of 2005 compared to $40.13 in the second quarter of 2004, up
six percent. In the first six months of 2005 prices were $41.95 per boe, up
eight percent compared to the first six months of 2004.
Revenue was up 48 percent in the second quarter of 2005 compared to the
second quarter of 2004. Volume increases contributed 42 percent to the quarter
over quarter increase while higher prices contributed six percent. For the
first six months of 2005 revenue was up 50 percent compared to the first six
months of 2004 comprised of a 42 percent volume increase and an eight percent
increase in per boe prices.
Royalties
Royalties, net of Alberta Royalty Tax Credit (ARTC), averaged 22 percent
of revenue for the second quarter of 2005 compared to 14 percent of revenue in
the second quarter of 2004. Excluding ARTC, royalty rates averaged 24 percent
in the second quarter of 2005 and 22 percent in the second 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 six months of 2005 royalties net of ARTC
averaged 23 percent and 24 percent excluding ARTC compared to 16 percent and
21 percent for the first six months of 2004. Overall royalty costs were up 142
percent in the second quarter of 2005 compared to the second quarter of 2004
and up 108 percent when comparing royalties on a year-to-date basis due to
increased volumes and higher royalty rates.
Interest Income
Interest income was earned in 2004 on cash balances which have since been
spent on the 2004 capital program.
Production Expenses
Production expenses averaged $7.16 per boe in the second quarter of 2005
down 13 percent compared to $8.21 per boe in the second quarter of 2004. These
costs are also down significantly from $8.61 per boe in the first quarter of
2005. The Company has focused on operating costs and these efforts combined
with increasing volume have contributed to lower per unit costs. For the first
six months of 2005 production expenses were $7.85 per boe, almost unchanged
from the first six months of 2004. Production expenses in early 2004 benefited
from a single well that was producing approximately 40 percent of the
Company's total production which lowered the overall per boe costs. Early 2005
costs were negatively affected by a charge of $67,000 or $0.18 per boe for the
first six months for historical gathering and processing charges that an
operator had not billed for as much as four years' time.
General and Administrative Expenses
General and administrative costs, including stock based compensation,
were up only 10 percent in the second quarter of 2005 compared to the second
quarter of 2004 notwithstanding a strengthened technical staff contingent in
the 2005 period. Second quarter costs were negatively effected by spending on
due diligence efforts for an acquisition attempted in the second quarter which
was not successful. On a per boe basis, general and administrative costs were
$4.32 for the second quarter of 2005, down 29% compared to $6.05 per boe in
the second quarter of 2004. For the first six months of 2005 general and
administrative costs were up six percent compared to the first six months of
2004. On a per unit basis these costs declined by 25 percent to $4.18 per boe
in the first six months of 2005 compared to the first six months of 2004 as
increased volume has been delivered with only modest increases in staff and
administration costs. Berens does not capitalize any general and
administrative costs.
Interest Expense
Interest expense is incurred on the Company's bank line of credit. The
Company had limited borrowings in the first half of 2004.
Operating Netback
Operating netback represents the profit margin realized by the production
and sale of petroleum and natural gas.
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Quarterly Operating Netbacks Three months Six months
($'s per boe) ended June 30 ended June 30
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2005 2004 2005 2004
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Sales price 42.61 40.13 41.95 39.05
Less:
Royalties (net of ARTC) 9.55 6.06 9.36 6.33
Production expenses 7.16 8.21 7.85 7.74
Transportation charges 1.10 1.52 1.13 1.25
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Operating netback 24.81 24.33 23.61 23.73
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Depletion, Amortization and Accretion
Depletion, amortization and accretion totaled $3.5 million ($20.33 per
boe) in the second quarter of 2005 compared to $2.1 million ($16.87 per boe)
in the second quarter of 2004. For the first six months of 2005 costs were
$6.6 million ($19.87 per boe) compared to 2004 costs of $3.7 million ($15.86
per boe) for the first six months of 2004. The higher per boe rates in 2005
are due to reserve revisions from the 2004 year-end independent petroleum
consultants reserve report which resulted in an increased per boe depletion
rate. Depletion rates on a per boe basis are expected to decline as additional
wells are drilled and reserves are added with lower finding and on stream
costs expected to result in a reduced depletion rate.
Income Taxes
Cash income taxes of $16,000 were booked in the second quarter of 2005
and $31,000 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 loss carry forwards and capital pools to shelter taxable income.
On December 9, 2004, 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 quarter and accordingly, a future tax recovery was
recognized in the second quarter 2005 Statement of Operations. The remaining
future tax liability of $556,000 from the renunciation was recorded as a
future tax liability on the June 30, 2005 Balance Sheet.
NET INCOME
Net income for the second quarter of 2005 was $887,000 ($0.02 per share)
compared to net income of $335,000 ($0.01 per share) in the second quarter of
2004. For the first six months of 2005 net income was $446,000 ($0.01 per
share) compared to net income of $398,000 ($0.01 per share) in the first six
months of 2004. The 2005 income was mainly due to recognition of a future tax
asset on the renunciation of CEE in the second quarter. Adjusting for the tax
amounts recorded in the second quarter, the Company's results reflect
increased production and higher oil and gas prices offset by higher depletion
charges and increased per boe royalty costs compared to 2004.
CAPITAL COSTS
Capital costs were $3.4 million in the second quarter of 2005, down from
$4.6 million in the second quarter of 2004 as land acquisitions were scaled
back in the second quarter of 2005 after a significant amount of land was
acquired in the first quarter of the year. Capital costs were $12.9 million in
the first six months of 2005 compared to $7.4 million in the same period in
2004 as the Company increased activity levels and spent more on land in 2005
to establish a growth base in west central Alberta. Berens participated in 11
net wells in the first six months of 2005 compared to five net wells in the
same period for 2004.
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Three months Six months
($000's) ended June 30 ended June 30
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2005 2004 2005 2004
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Drilling and completion 2,693 2,650 7,054 4,501
Land 77 1,006 4,108 1,396
Geological and geophysical 630 843 1,671 1,414
Office and other 23 234 52 248
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Total 3,423 4,733 12,885 7,559
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WORKING CAPITAL
Accounts receivable of $3.2 million at June 30, 2005 were primarily May
and June production revenues. Accounts payable at June 30, 2005 of
$6.9 million were comprised mainly of trade payables for capital and operating
costs, royalties and amounts owing to joint venture partners.
The draw on the operating line of credit decreased by $400,000 in the
second quarter to $10,080,000 at June 30, 2005 as operating cash flows were
greater than capital spending in the quarter. Excluding the bank line, working
capital was in a deficit position of $3.0 million, up 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 had $10.1 million drawn as of June 30, 2005.
NON-GAAP MEASUREMENTS
This MD&A contains the term "cash 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 cash flow from
operations may not be comparable to that reported by other companies,
especially those in other industries. Management feels that cash 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 cash flow from operations for
the periods ended June 30, is as follows.
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Three months Six months
($000's) ended June 30 ended June 30
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2005 2004 2005 2004
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Net income 887 335 446 398
Items not requiring cash:
Depletion, amortization and
accretion 3,532 2,068 6,596 3,714
Future income tax recovery (985) - (985) -
Stock based compensation 84 49 168 85
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Cash flow from operations 3,518 2,452 6,225 4,197
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The Company also presents cash flow from operations per share consistent
with the calculation of earnings per share, whereby per share amounts are
calculated using weighted average shares outstanding. Cash flow from
operations per share was $0.07 (basic and diluted) for the second quarter of
2005 compared to $0.06 (basic and diluted) per share for the second quarter of
2004. Cash flow from operations per share for the first six months of 2005 was
$0.13 (basic and diluted) compared to $0.10 per share (basic and diluted) for
the first six 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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Cash 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 complete, 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 46,427,469 issued and
outstanding common shares. Additionally, the Company has issued options to
purchase 2,769,500 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 has begun drilling on the west central Alberta lands
as of early August 2005 with a partner operated well in Karr and plans to spud
its first operated well in Karr in late August. 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 planned drilling in the rest of 2005 and through 2006. Currently there are
an additional 12 wells planned in Lanfine for the remainder of 2005.
Combined with developing drilling prospects, the Company is negotiating
with potential partners to expand its land position in west central Alberta.
The Company has increased its Karr land position by three sections to a total
of 20 sections (15 net) by partnering on adjacent lands. The Company intends
to continue to work with partners in west central Alberta to reduce 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.
A capital program for $20 million has been set for 2005 that is projected
to yield production growth of approximately 44 percent over 2004, averaging
1,800 boe/day, and exiting 2005 greater than 2,000 boe/day. The capital
program is split 60 percent toward eastern Alberta and 40 percent to new
growth areas in west central Alberta. 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.
Berens Energy Ltd.
Balance Sheets
(unaudited)
As at,
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June 30, December
(000's) 2005 31, 2004
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ASSETS
Current
Cash and cash equivalents $ 44 $ 35
Accounts receivable 3,166 3,365
Prepaid expenses and deposits 723 492
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3,933 3,892
Investments 299 299
Capital assets (notes 3 & 7) 45,207 38,811
Goodwill 14,805 14,805
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$ 64,244 $ 57,807
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LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Bank loan (note 7) $ 10,080 $ 4,500
Accounts payable and accrued liabilities 6,945 5,795
Taxes payable 29 58
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17,054 10,353
Future income taxes 556 -
Asset retirement obligation (note 4) 755 648
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18,365 11,001
Shareholders' equity
Capital stock (note 5) 46,790 48,331
Contributed surplus (note 5) 409 241
Deficit (1,320) (1,766)
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45,879 46,806
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$ 64,244 $ 57,807
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Berens Energy Ltd.
Statements of Operations and Retained Earnings (Deficit)
(unaudited)
For the three and six months ended June 30,
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Three months ended Six months ended
(000's) June 30, June 30,
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2005 2004 2005 2004
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Revenue
Oil and natural gas revenue $ 7,411 $ 4,974 $ 13,770 $ 9,139
Royalties, net of ARTC (1,657) (685) (3,105) (1,490)
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5,754 4,289 10,665 7,649
Interest - 2 - 17
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5,754 4,291 10,665 7,666
Expenses
Production 1,243 927 2,606 1,823
Transportation 190 172 375 295
Depletion, amortization and
accretion 3,532 2,068 6,596 3,714
General and administrative 666 634 1,219 1,224
Stock based compensation 84 49 168 85
Interest expense 121 16 209 17
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5,836 3,866 11,173 7,158
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Income (loss) before income taxes (82) 426 (508) 508
Taxes
Future income tax recovery (985) - (985) -
Income tax expense 16 91 31 110
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(969) 91 (954) 110
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Net income for the period 887 335 446 398
Retained earnings (deficit),
beginning of period (2,207) 63 (1,766) -
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Retained earnings (deficit), end
of period $ (1,320) 398 (1,320) $ 398
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Net income per share (note 8)
Basic and diluted $ 0.02 $ 0.01 $ 0.01 $ 0.01
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Berens Energy Ltd.
Statements of Cash Flows
(unaudited)
For the three and six months ended June 30,
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Three months ended Six months ended
(000's) June 30, June 30,
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2005 2004 2005 2004
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OPERATING ACTIVITIES
Net income for the period $ 887 $ 335 $ 446 $ 398
Add items not involving cash
Depletion, amortization and
accretion 3,532 2,068 6,596 3,714
Future income tax recovery (985) - (985) -
Stock-based compensation 84 49 168 85
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3,518 2,452 6,225 4,197
Change in non-cash working
capital items (note 6) (364) 648 (431) (431)
-------------------------------------------------------------------------
3,154 3,100 5,794 3,766
-------------------------------------------------------------------------
FINANCING ACTIVITIES
Change in bank loan (400) 100 5,580 100
Proceeds from the exercise of
stock options - - - 22
-------------------------------------------------------------------------
(400) 100 5,580 122
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INVESTING ACTIVITIES
Purchase of property and
equipment (3,423) (4,733) (12,885) (7,559)
Change in non-cash working
capital items (note 6) 678 (294) 1,520 (304)
-------------------------------------------------------------------------
(2,745) (5,027) (11,365) (7,863)
-------------------------------------------------------------------------
Increase (decrease) in cash and
cash equivalents 9 (1,827) 9 (3,975)
Cash and cash equivalents,
beginning of period 35 1,874 35 4,022
-------------------------------------------------------------------------
Cash and cash equivalents, end
of period $ 44 $ 47 $ 44 $ 47
-------------------------------------------------------------------------
-------------------------------------------------------------------------
BERENS ENERGY LTD.
Notes to Financial Statements
(unaudited)
Three and six months ended June 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 with current disclosure standards.
3. CAPITAL ASSETS
-------------------------------------------------------------------------
June 30, 2005 December 31, 2004
Accumu- Accumu-
lated lated
depletion, depletion
amortiza- amortiza-
tion and tion and
($000's) Cost accretion Cost accretion
-------------------------------------------------------------------------
Petroleum and natural gas
properties 61,292 16,295 48,394 9,757
Office and computer equipment 284 74 232 58
-------------------------------------------------------------------------
61,576 16,369 48,626 9,815
-------------------------------------------------------------------------
Net book value 45,207 38,811
-------------------------------------------------------------------------
-------------------------------------------------------------------------
At June 30, 2005, costs of $13,043,000 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 incurred 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 65
Accretion expense 42
-------------------------------------------------------------------------
Obligation, March 31, 2005 755
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The total undiscounted obligation for asset retirement is $2,480,000 as
at June 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)
Balance June 30, 2005 46,427,469 $ 46,790
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Private Placements:
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 $266,000 to finance certain oil
and gas expenditures to be incurred in 2005. The renouncement of these
expenditures was made to the purchasers of these shares in the second
quarter of 2005.
(c) Stock Option Plan
The Company has a stock option plan under which 4,000,000 common shares
have been reserved for options to be distributed to directors, officers,
employees and consultants to the Company with terms established by the
board of directors.
Options granted under the plan generally have a five year term to expiry
and vest equally over a three year period commencing on the first
anniversary date of the grant. The exercise price of each option equals
the closing market price of the Company's common shares on the day prior
to the date of the grant.
The following table sets forth a reconciliation of the plan activity
through June 30, 2005.
-------------------------------------------------------------------------
Weighted
average
exercise
price
Number of ($ per
Options share)
-------------------------------------------------------------------------
Outstanding, beginning of period 2,784,500 1.22
Granted 75,000 1.20
Cancelled (90,000) 1.70
Exercised - -
-------------------------------------------------------------------------
Outstanding, end of period 2,769,500 1.21
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Exercisable 953,327 1.14
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The following table sets forth additional information relating to the
stock options outstanding at June 30, 2005.
-------------------------------------------------------------------------
Options Outstanding Exercisable Options
-------------------------------------------------------------------------
Weighted Weighted
average average
exercise Weighted exercise Weighted
price average price average
Exercise Number of ($ per years to Number of ($ per years to
price range Options share) expiry Options share) expiry
-------------------------------------------------------------------------
$1.00 to
$1.10 1,220,000 1.00 2.82 706,662 1.00 2.67
$1.11 to
$1.20 577,500 1.17 4.47 - - -
$1.21 to
$1.30 152,000 1.27 4.34 - - -
$1.31 to
$1.40 307,500 1.39 4.02 65,833 1.40 3.94
$1.41 to
$1.50 197,500 1.47 3.71 65,833 1.47 3.71
$1.51 to
$1.60 - - - - - -
$1.61 to
$1.70 315,000 1.70 3.51 114,999 1.70 3.50
-------------------------------------------------------------------------
$1.00 to
$1.70 2,769,500 1.21 3.52 953,327 1.14 2.93
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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,
$168,000 was recorded as compensation expense for the six month period
ended June 30, 2005 and $84,000 for the three month period ended June 30,
2005 (2004 - $85,000 and 49,000) 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 168
-------------------------------------------------------------------------
Contributed surplus, June 30, 2005 409
-------------------------------------------------------------------------
-------------------------------------------------------------------------
6. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in Non-cash Working Capital
For the six month periods ended June 30,
-------------------------------------------------------------------------
($000's) 2005 2004
Accounts receivable 199 (137)
Prepaid expenses and deposits (231) (393)
Accounts payable and accrued liabilities 1,150 612
Income taxes payable (29) (817)
-------------------------------------------------------------------------
1,089 (735)
Less:
Change in non-cash working capital related to
investing activities 1,520 (304)
-------------------------------------------------------------------------
Change in non-cash working capital related to
operating activities (431) (431)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash taxes and interest paid during the three and six month periods ended
June 30,
-------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
-------------------------------------------------------------------------
($000's) 2005 2004 2005 2004
-------------------------------------------------------------------------
Cash income and other taxes 55 19 61 1,057
Cash interest paid 87 - 209 16
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 4.625 percent at June 30, 2005. On June 30, 2005
$10,080,000 was drawn on the bank line.
8. PER SHARE INFORMATION
The weighted average number of common shares outstanding during the six
month period and the quarter ended June 30, 2005 of 46,427,469 (2004: six
months - 43,422,533; quarter - 43,427,469) was used to calculate basic
income and loss per share. On a diluted basis the weighted average number
of common shares outstanding during the six month period ended June 30,
2005 was 46,626,011 (2004 - 43,647,609). No changes to share capital have
occurred from June 30, 2005 to the date of the Management's Discussion
and Analysis in this report.
The TSX Venture Exchange has neither approved nor disapproved of the
contents of this press release.
>>
%SEDAR: 00020114E
