Symbol: BEN - TSX
CALGARY, May 10 /CNW/ -
<<
FINANCIAL AND OPERATING HIGHLIGHTS
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($ Cdn thousands, Three months
except as noted) ended March 31,
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2006 2005 % Change
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Sales volume
Natural gas (mcf/day) 16,631 9,155
Oil and ngls (bbl/day) 420 233
boe/day (6 to 1) 3,192 1,759 81%
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Revenue net of royalties 9,523 4,910
Net income (loss) (2,121) (441)
Per share (basic and diluted) $(0.03) $(0.01)
Funds from operations(1) 5,893 2,707 118%
Per share (basic and diluted)(1) $0.07 $0.06 17%
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Capital costs
Exploration and development 15,588 4,361
Land and seismic 3,058 5,072
Other 478 29
Total 19,124 9,462 81%
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Net wells completed 7 12
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Net working capital (deficit)
- including bank debt (45,907) (13,216)
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Shares outstanding
End of period (000's) 86,447 46,427
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Note:
(1) Non-GAAP measure - represents cash flow from operating activities
before non-cash working capital changes
First Quarter 2006 Operating Highlights
- Production - Including Berland production from the closing date of
January 18, 2006 forward Q1 2006 production averaged 3,192 boe/d, up
81 percent over Q1 2005 and up 52 percent from Q4 2005. Including
Berland production on a pro-forma basis from January 1, 2006 the Q1
2006 production average was 3,468 boe/d. In March 2006, average
production was 3,564 boe/d.
- Product Mix - The addition of liquids rich natural gas from the
Berland acquisition has changed the production mix from 92% natural
gas and 8% heavy oil to 87% natural gas, 4% heavy oil and 9% natural
gas liquids. In addition, the natural gas from the Berland assets has
a high BTU content and commands a premium price.
- Production Costs - Declined to $6.59 per boe in Q1 2006, down 23%
compared to $8.61 per boe in Q1 2005. A continued focus on cost
management has reduced per boe costs in Lanfine and the Berland
assets characteristically have lower operating costs than historical
costs at Berens.
- Funds Flow from Operations - Q1 2006 funds flow was $5.9 million
($0.07 per share) compared to Q1 2005 funds flow of $2.7 million
($0.06 per share). On a per share basis funds flow was up 17%.
- Drilling - A total of 20 wells (10 net) were drilled in the first
quarter. The majority of the first quarter drilling activity occurred
in March when as many as 5 rigs were drilling at various times during
the month. Fourteen (6.8 net) of the 20 wells were completed during
the quarter resulting in 9 (3.8 net) natural gas wells and
5 (3.0 net) unsuccessful. The remaining wells are scheduled to be
completed in the second and third quarters depending on weather and
access.
- Land - The land position at March 31, 2006 includes 117,000 net acres
of working interest lands and 56,000 net acres of option lands for a
total of 173,000 net undeveloped acres. This represents a 47%
increase compared to March 31, 2005 and a 21% increase over
December 31, 2005. Ninety-seven percent of the undeveloped lands are
located in the four core areas of Pembina, the Deep Basin, Lanfine
and Marten Hills.
Report from Management
The first quarter of 2006 was a period of tremendous change at Berens. We
closed the acquisition of Berland Exploration Ltd. ("Berland") on January 18,
2006 and officially assumed operation of the Berland assets, welcomed some of
the Berland staff to the Berens team and integrated the operations and
administration. The asset base we have developed with the combination of the
two companies has created optimism and excitement for the long-term growth
prospects.
In the first quarter of 2006 the high demand our industry is placing on
oil and gas service companies has created a challenging operating and cost
environment. Berens was able to complete a significant portion of its first
quarter capital program with much of the activity occurring in March when we
were able to get access to drilling rigs. As we reported on March 30, 2006 the
late drilling program in the first quarter resulted in lower than expected
first quarter production. Consequently we lowered our guidance for average
2006 production.
Outlook
With more than 173,000 net undeveloped acres of land concentrated in four
operating areas, we are embarking on an exciting period of planned growth with
the drill bit. Our existing land base will provide ample drilling locations to
pursue for the balance of 2006 and throughout 2007.
In light of softer natural gas prices in the first quarter of 2006 our
board of directors has approved a reduction in our 2006 capital program from
the previously announced $71 million to $61 million. The reduction in capital
comes primarily from our land acquisition budget as the bidding on crown land
has become overheated. Little of our capital reduction is related to drilling
and completions so we are not changing our production guidance and continue to
expect a range of 4,100 - 4,300 boe/d average for 2006 with an estimated exit
rate of 4,800 boe/d. We control a diversified and concentrated land base and
are well positioned to control the timing of our investment.
Sincerely,
Robert D. Steele
Chief Executive Officer
Berens Energy Ltd.
Management's Discussion and Analysis ("MD&A")
May 9, 2006
OVERVIEW
Berens Energy Ltd. ("Berens" or the "Company") is a full cycle oil and
natural gas exploration and production company with a concentrated production
and land base in Eastern Alberta with new land and production bases in the
Pembina and Deep Basin regions of west central Alberta.
All calculations converting natural gas to crude oil equivalent have been
made using a ratio of six thousand cubic feet ("mcf") of natural gas to one
barrel of crude equivalent. Barrels of oil equivalent ("boe") may be
misleading, particularly if used in isolation. A boe conversion ratio of six
mcf of natural gas to one barrel of crude oil equivalent is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.
The following discussion of financial position and results of operations
should be read in conjunction with the Company's December 31, 2005 Audited
Financial Statements and Notes thereto and the March 31, 2006 unaudited
interim financial statements. This MD&A was prepared using information that is
current as of May 9, 2006 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.
QUARTERLY INFORMATION
2006
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($000's except as noted) Q1
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Sales volumes:
Natural gas (mcf/day) 16,631
Oil and ngls (bbl/day) 420
Barrels of oil equivalent 3,192
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Financial:
Net revenue 9,523
Net income (loss) (2,121)
per share - basic $(0.03)
per share - diluted $(0.03)
Capital costs 19,124
Shares outstanding (000's) 86,447
Bank debt 32,180
Working capital (deficit) including bank debt (45,907)
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Per unit information:
Natural gas price ($/mcf) $7.72
Oil and liquids price ($/barrel) $51.07
Oil equivalent price ($/boe) $46.09
Operating netback ($/boe) $24.59
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Net wells completed:
Natural gas 4
Oil -
Dry 3
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Total 7
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2005
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($000's except as noted) Q4 Q3 Q2 Q1
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Sales volumes:
Natural gas (mcf/day) 11,537 10,832 10,250 9,155
Oil and ngls (bbl/day) 176 165 200 233
Barrels of oil equivalent 2,099 1,970 1,908 1,759
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Financial:
Net revenue 9,537 7,667 5,754 4,910
Net income (loss) (475) 534 887 (441)
per share - basic $(0.01) $0.01 $0.02 $(0.01)
per share - diluted $(0.01) $0.01 $0.02 $(0.01)
Capital costs 12,346 7,165 3,423 9,462
Shares outstanding (000's) 57,163 52,961 46,427 46,427
Bank debt - - 10,080 10,480
Working capital (deficit)
including bank debt 4,273 (2,137) (13,121) (13,216)
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Per unit information:
Natural gas price ($/mcf) $11.26 $9.16 $7.29 $6.91
Oil and liquids price
($/barrel) $41.92 $57.47 $33.11 $30.81
Oil equivalent price ($/boe) $65.47 $55.05 $42.61 $40.05
Operating netback ($/boe) $39.78 $34.07 $24.81 $21.12
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Net wells completed:
Natural gas 9 7 3 5
Oil 1 0 0 0
Dry 2 2 1 2
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Total 12 9 4 7
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2004
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($000's except as noted) Q4 Q3 Q2
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Sales volumes:
Natural gas (mcf/day) 7,089 5,310 6,326
Oil and ngls (bbl/day) 240 238 292
Barrels of oil equivalent 1,422 1,123 1,347
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Financial:
Net revenue 3,803 3,322 4,289
Net income (loss) (1,652) (512) 335
per share - basic $(0.04) $(0.01) $0.01
per share - diluted $(0.04) $(0.01) $0.01
Capital costs 6,813 5,564 4,732
Shares outstanding (000's) 46,427 43,427 43,427
Bank debt 4,500 4,250 100
Working capital (deficit) including
bank debt (6,461) (5,973) (1,951)
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Per unit information:
Natural gas price ($/mcf) $6.48 $6.44 $7.04
Oil and liquids price ($/barrel) $31.88 $40.02 $32.56
Oil equivalent price ($/boe) $36.08 $38.91 $40.13
Operating netback ($/boe) $18.96 $19.86 $24.33
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Net wells completed:
Natural gas 11 5 3
Oil 1 1 -
Dry - 1 -
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Total 12 7 3
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RESULTS OF OPERATIONS
Production Volume
Production volume averaged 3,192 boe/d for the first quarter of 2006, up
81 percent compared to 1,759 boe/d in the first quarter of 2005. Natural gas
represented 87 percent of production in the first quarter of 2006 with the
remaining production being nine percent light oil and natural gas liquids and
four percent conventional heavy oil.
Production grew steadily throughout 2005 primarily from drilling in
Lanfine and exited 2005 at 2,100 boe/d. No drilling activity occurred in
Lanfine in the first quarter of 2006 and the base production declined to
average 2,000 boe/d in the first quarter. Production from the Berland
acquisition, on January 18, 2006, contributed the majority of the incremental
volumes in the quarter. Drilling in the first quarter of 2006 did not add
significantly to volumes in the quarter as the majority of the drilling was
conducted in March due to lack of rig availability in January and February.
Production Revenue
Natural gas prices averaged $7.72 per mcf for the first quarter of 2006,
up 12 percent compared to $6.91 per mcf in the first quarter of 2005 but down
32 percent from the fourth quarter of 2005. Oil and liquids prices averaged
$43.04 and $56.59 per barrel respectively in the first quarter of 2006 for a
blended price of $51.07 per barrel, up 66 percent from the first quarter 2005
liquids price of $30.81. On a boe basis, prices averaged $46.09 in the first
quarter of 2006, up 15 percent compared to the first quarter of 2005.
Revenue was up 113 percent in the first quarter of 2006 compared to the
first quarter of 2005. Volume increased by 81 percent supplemented by a
15 percent increase in per boe prices.
Royalties
Royalties, net of Alberta Royalty Tax Credit ("ARTC"), averaged
29.5 percent of revenue for the first quarter of 2006 compared to 22.7 percent
of revenue in the first quarter of 2005. Excluding ARTC, royalty rates
averaged 30.4 percent in the first quarter of 2006 and 24.7 percent in the
first quarter of 2005. The higher 2006 royalty percentage is attributed to the
following factors:
- Significant 2006 production comes from higher volume liquids rich
wells in Pembina and the Deep Basin that have higher royalty rates
compared to 2005 production which was primarily from lower volume
wells in Lanfine.
- Production from certain farm-in lands in Pembina incur overriding
royalties which contribute to the higher royalty percentage.
- Reference prices used for royalty calculations are based on prior
months' natural gas prices and lag the actual price received. As
natural gas prices declined in the first quarter the royalty rates
were temporarily high as they were based on higher reference prices.
On an ongoing basis, royalties are expected to average approximately
27 percent of revenues. Royalty expense of $4.0 million was recorded in the
first quarter of 2006, up 175 percent compared to the first quarter of 2005
reflecting both higher revenue and higher royalty rates.
Production Expenses
Production expenses declined to $6.59 per boe in Q1 2006, down 23 percent
compared to $8.61 per boe in Q1 2005. A focus on cost management has reduced
per boe costs in Lanfine and the Berland assets have characteristically low
per unit operating costs. Continued cost management is a priority due to the
increased cost pressures in the western Canada oil and gas business.
First quarter 2006 costs were $1.9 million, up 39 percent compared to the
first quarter of 2005 due to an 81 percent increase in volume offset by lower
per unit costs.
Transportation costs increased 59 percent in the first quarter of 2006
compared to the first quarter of 2005 due primarily to increased volumes.
General and Administrative Expenses
General and administrative costs, including stock based compensation,
were up 112 percent in the first quarter of 2006 compared to the first quarter
of 2005. Increased costs were incurred in 2006 as the staff contingent has
approximately doubled since the first quarter of 2005 with production growth
and the addition of the Berland assets and staff. Salary and bonus levels have
also increased as a result of industry competitive pressures. Non-recurring
costs of $160,000 were incurred in the first quarter of 2006 to integrate the
Berland operations. On a per boe basis, general and administrative costs were
$4.71 per boe for the first quarter of 2006, up 17 percent compared to $4.02
per boe in the first quarter of 2005. There were no general and administrative
costs capitalized in the quarter.
Staff levels are expected to remain fairly constant throughout the
balance of 2006. Per unit general and administrative costs are expected to
decline as production levels increase during the year.
Interest Expense
Interest expense increased 201 percent in the first quarter of 2006
compared to the first quarter of 2005. The closing of the acquisition of
Berland resulted in significant borrowing on the bank operating line as
30 percent of the Berland acquisition cost was in the form of cash. In
addition, Berland's debt and working capital, totaling $28 million were
assumed on January 18, 2006, the closing date of the acquisition. In addition,
capital expenditures in the first quarter were significantly higher than funds
from operations.
Operating Netback
Operating netback represents the margin realized by the production and
sale of petroleum and natural gas.
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Quarterly Operating Netbacks Three months
($'s per boe) ended March 31
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2006 2005
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Sales price 46.09 40.05
Less:
Royalties (net of ARTC) 13.89 9.15
Production expenses 6.59 8.61
Transportation charges 1.02 1.17
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Operating netback 24.59 21.12
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Depletion, Amortization and Accretion
Depletion, amortization and accretion totaled $9.1 million ($31.80 per
boe) in the first quarter of 2006 compared to $3.1 million ($19.36 per boe) in
the first quarter of 2005. The higher depletion rates are attributable to the
cost of acquiring the Berland reserves through the acquisition and to spending
in the deeper drilling program which had limited reserve additions to the end
of 2005. The 2006 capital plan is focused on drilling, primarily in Pembina
and Lanfine which is expected to add reserves at lower cost on a go forward
basis.
Income Taxes
Current taxes of $6,000 were booked in the first quarter of 2005
primarily for capital taxes. The Company does not expect to pay current income
tax during 2006 as there are ample capital cost pools and expected future
capital spending to shelter taxable income.
Future taxes changed from a small asset position at December 31, 2005 to
a liability of $20.4 million at March 31, 2006. Future tax liabilities of
$16.1 million were recorded on the acquisition of Berland and $6.1 million was
recorded to account for the tax affect of flow-through shares renouncements.
The future tax liabilities recorded in the first quarter were partially offset
by a future tax recovery on the net loss for the first quarter.
NET INCOME
The net loss for the first quarter of 2006 was $2.1 million ($0.03 per
share) compared to a loss of $0.4 million ($0.01 per share) in the first
quarter of 2005. The higher 2006 loss has resulted primarily from higher
depletion expense more than offsetting increases in volume and prices.
CAPITAL COSTS
Capital costs, excluding the acquisition of Berland, were $19.1 million
in the first quarter of 2006, up from $9.5 million in the first quarter of
2005. Although the net well count was comparable in the comparative quarters,
this year's activities included deeper wells in Pembina and the Deep Basin
while no shallow Lanfine wells were drilled in the first quarter of 2006.
Capital costs are up as well due to increased rates charged by drilling and
service companies for most activities.
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Three months
($000's) ended March 31
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2006 2005
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Drilling and completion 15,588 4,361
Land 1,560 4,030
Geological and geophysical 1,498 1,042
Office and other 478 29
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Total 19,124 9,462
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Overall, the Company spent 82 percent of its capital on drilling and
completion activities in the first quarter of 2006 compared to a capital
program that was focused on land and seismic in the first quarter of 2005. In
2005 there was a focus to build new land positions in central and west central
Alberta. With significant undeveloped land in place in the first quarter of
2006 the current year's capital program is focused on drilling.
WORKING CAPITAL
Accounts receivable of $16.5 million at March 31, 2006 was primarily
revenue receivables and amounts owing from partners ($10.2 million) as well as
capital advances to partners for drilling projects ($3.4 million). Accounts
payable at December 31, 2005 of $32.4 million were mainly comprised of trade
payables for capital and operating costs ($23.4 million), royalties
($5.5 million) and capital costs accrued at the end of the quarter for ongoing
drilling operations ($10.0 million).
Working capital excluding bank indebtedness was in a deficit position of
$13.7 million at March 31, 2006. A recent increase in the bank line and
ongoing cash flows, combined with a reduction in the 2006 capital program is
expected to fund this working capital deficit.
LIQUIDITY AND CAPITAL RESOURCES
The Company plans to fund its operations and capital costs with a mix of
operating cash flow and debt financing through the bank operating line. An
operating bank line is in place for $45.0 million, secured by producing
properties. At March 31, 2006, $32.2 million was drawn on the bank line.
NON-GAAP MEASUREMENTS
This MD&A contains the term "funds from operations" and "operating
netback". As an indicator of the Company's performance, these terms should not
be considered an alternative to, or more meaningful than "cash flow from
operating activities" or "net income (loss)" as determined in accordance with
Canadian generally accepted accounting principles. The Company's determination
of funds from operations and operating netback may not be comparable to that
reported by other companies, especially those in other industries. Management
feels that funds 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.
Operating netback is a useful measure for comparing the Company's price
realization and cost performance against industry competitors.
The reconciliation between net income and funds from operations for the
periods ended March 31 is set out in the following chart:
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Three months
($000's) ended March 31
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2006 2005
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Net income (loss) (2,121) (441)
Items not requiring cash:
Depletion, depreciation and accretion 9,135 3,065
Future income tax expense (recovery) (1,281) -
Stock based compensation 160 83
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Funds from operations 5,893 2,707
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Funds from operations are also presented on a per share basis consistent
with the calculation of net income per share, whereby per share amounts are
calculated using the weighted average number of shares outstanding. Funds from
operations per share were $0.07 (basic and diluted) for the first quarter of
2006 compared to $0.06 (basic and diluted) per share for the first quarter of
2005.
RISKS
Primary financial risks relate to variability in commodity prices.
Interest rate and currency exchange rate variability also have an effect on
financial results. The effect of changes in the exchange rate between US and
Canadian currencies on natural gas prices is not direct, as variations between
the regional markets for natural gas are often much greater than can be
explained by currency variability.
Other risks are related to operations. These risks include, but are not
limited to, risks associated with oil and gas exploration, development,
exploitation, production, marketing and transportation, delays or changes in
plans with respect to exploration or development projects or capital costs,
volatility of commodity prices, currency fluctuations, the uncertainty of
reserves estimates, potential environmental liabilities, technology risks,
competition, incorrect assessment of the value of acquisitions and failure to
realize the anticipated benefits of acquisitions. The foregoing list of
factors is not exhaustive. Additional information on these and other factors
that could affect operations or financial results are included in a more
detailed description of risks in Berens' Annual Information Form on file with
Canadian securities regulatory authorities and available on SEDAR at
www.sedar.com.
Documented environmental health and safety plans are in place as well as
a comprehensive emergency response plan to mitigate operating risks.
RELATED PARTY TRANSACTIONS
A consulting firm is contracted from time to time in which one of its
directors is the managing partner. The executive services rendered are in the
normal course of business and are at normal rates charged by the consulting
firm and recorded at the exchange amount. Consulting fees for this firm in the
first quarter of 2006 were $42,000. Fees for legal services are paid to a law
firm in which the corporate secretary is a partner. The legal services are
rendered in the normal course of business at normal rates charged by the law
firm. Legal fees for this firm paid in the first quarter of 2006 were
$431,000.
SHARE DATA
As of the date of this MD&A the Company had 86,447,064 issued and
outstanding common shares. Additionally, options to purchase 3,781,200 common
shares have been issued.
DISCLOSURE CONTROLS AND PROCEDURES OVER FINANCIAL REPORTING
Disclosure controls and procedures are designed to provide reasonable
assurance that all relevant information is gathered and reported to senior
management, including the Chief Executive Officer ("CEO") and the Chief
Financial Officer ("CFO"), on a timely basis so appropriate decisions can be
made regarding public disclosure. As at December 31, 2005, the CEO and the CFO
have evaluated the effectiveness of the disclosure controls and procedures as
defined in Multilateral Instrument 52-109 of the Canadian Securities
Administrators and have concluded that such disclosure controls and procedures
are effective. No changes to disclosure controls and procedures occurred in
the first quarter of 2006.
OUTLOOK
The acquisition of Berland was an important step to position the Company
with a diverse set of longer life assets. Drilling opportunities now exist
across four core areas and are well diversified in terms of risk and potential
return. Capital efficiency is expected to improve as more capital is spent on
drilling for new reserves and production and less capital is directed toward
land. The intention is to stay focused in the four core areas that have been
established to take advantage of the high level of technical expertise we have
in each area.
The 2006 capital program has greater diversification than the 2005
program both in terms of regions and the mix of risk and return potential.
Drilling at Lanfine represents the lowest risk drilling with the expectation
of solid returns while the Deep Basin is the higher risk drilling with the
potential for significant reserve discoveries. Pembina is considered to have a
medium risk and strong return profile. The 2006 capital plan is more drilling
focused compared to 2005. Land and seismic spending is budgeted for 13 percent
of the 2006 capital program, down from 30 percent of the 2005 capital program.
Access to services has been a challenge in early 2006. Costs have also
climbed for almost every service in the oil and gas industry. Capital
management and a focus on cost management will be important aspects of our
business when carrying out the 2006 capital program. A larger capital program
and a critical mass of wells to drill in 2006 will enable the Company to
contract drilling services on an ongoing basis which improves the ability to
drill wells on schedule and at the lowest cost possible. The undeveloped land
base totaling approximately 173,000 net acres is expected to provide a strong
inventory of drilling prospects to deliver future growth.
Berens Energy Ltd.
Balance Sheets
(unaudited)
As at,
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(000's) March 31, December
2006 31, 2005
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ASSETS
Current
Cash and cash equivalents $ 144 $ 9,472
Accounts receivable 16,486 9,912
Prepaid expenses and deposits 2,074 680
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18,704 20,064
Investments 299 299
Future income taxes (note 8) - 225
Property, plant and equipment (note 4) 160,453 53,242
Goodwill (note 3) 44,974 14,805
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$ 224,430 $ 88,635
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LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Bank loan (note 6) $ 32,180 -
Accounts payable and accrued liabilities 32,380 $ 15,699
Taxes payable 51 92
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64,611 15,791
Asset retirement obligation (notes 3 & 5) 2,098 1,223
Future income taxes (note 8) 20,357 -
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87,066 17,014
Shareholders' equity
Capital stock (note 7) 140,013 72,309
Contributed surplus (note 7) 734 574
Deficit (3,383) (1,262)
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137,364 71,621
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$ 224,430 $ 88,635
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See accompanying notes to the financial statements
Berens Energy Ltd.
Statements of Operations and Deficit
(unaudited)
For the three months ended March 31,
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(000's)
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2006 2005
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Revenue
Oil and natural gas revenue $ 13,513 $ 6,358
Royalties, net of ARTC (3,990) (1,448)
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9,523 4,910
Interest 17 -
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9,540 4,910
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Expenses
Production 1,893 1,363
Transportation 293 184
Depletion, depreciation and accretion 9,135 3,065
General and administrative 1,193 553
Stock based compensation (note 7) 160 84
Interest 262 87
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12,936 5,336
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Loss before income taxes (3,396) (426)
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Income taxes
Future expense (recovery) (1,281) -
Current expense 6 15
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(1,275) 58
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Net (loss) for the period (2,121) (441)
Deficit, beginning of period (1,262) (1,766)
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Deficit, end of period $ (3,383) $ (2,207)
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Net (loss) per share (note 10)
Basic and diluted $ (0.03) $ (0.01)
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See accompanying notes to the financial statements
Berens Energy Ltd.
Statements of Cash Flows
(unaudited)
For the three months ended March 31,
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(000's)
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2006 2005
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OPERATING ACTIVITIES
Net income (loss) for the period $ (2,121) $ (441)
Add items not involving cash
Depletion, amortization and accretion 9,135 3,065
Future income tax expense (recovery) (1,281) -
Stock-based compensation 160 83
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5,893 2,707
Change in non-cash working capital items (note 9) 7,685 (67)
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Cash flow from operating activities 13,578 2,640
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FINANCING ACTIVITIES
Change in bank loan 12,430 5,980
Net proceeds from private offerings 19,813 -
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Cash flow from financing activities 32,243 5,980
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INVESTING ACTIVITIES
Cash acquired through Berland acquisition 109 -
Cash component on Berland acquisition (28,682) -
Purchase of property and equipment (19,124) (9,462)
Change in non-cash working capital items (note 9) (7,452) 842
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Cash flow from investing activities (55,149) (8,620)
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Decrease in cash (9,328) -
Cash and cash equivalents, beginning of period 9,472 35
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Cash and cash equivalents, end of period $ 144 $ 35
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See accompanying notes to the financial statements
BERENS ENERGY LTD.
Notes to Financial Statements
(unaudited)
Three months ended March 31, 2006 and 2005
1. NATURE OF OPERATIONS
The Company is a full cycle oil and natural gas exploration and
production company with activities encompassing land acquisition,
geological and geophysical assessment, drilling and completion, and
production. The primary areas of operation are in eastern and west
central Alberta.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The interim financial statements have been prepared by management
following the same accounting policies as the most recent annual audited
financial statements.
Certain disclosures, which are normally required to be included in notes
to the annual financial statements, are condensed or omitted for interim
reporting purposes. Accordingly, these interim financial statements
should be read in conjunction with the audited annual financial
statements for the year ended December 31, 2005. Certain prior period
amounts have been reclassified to conform to current disclosure
standards.
3. ACQUISITION OF BERLAND EXPLORATION LTD.
On January 18, 2006, Berens and Berland Exploration Ltd. ("Berland")
closed a previously announced arrangement that saw Berens acquire
Berland. Pursuant to the arrangement, shareholders of Berland received
$0.96 in cash ($20.0 million) and 0.8784 of a Berens common share
(21,083,795 common shares for $53.8 million) for each Berland common
share. Additionally, certain option and warrant holders received a
differential payment for the difference between their option and warrant
strike prices and $3.20 per Berland share ($8.7 million). Pursuant to the
Arrangement, Berens also assumed $19.7 million of Berland debt and
transaction costs of $0.5 million.
The total cost to Berens to acquire the Berland shares was
$102.7 million. This acquisition has been accounted for using the
purchase method with the Berland results included in the statement of
operations from the closing date of January 18, 2006.
The following table summarizes the estimated fair value of the assets
acquired and liabilities assumed as at the closing date. The final
determination of these values has not been completed.
Assets and liabilities purchased $000's
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Cash and cash equivalents 109
Accounts receivable 10,321
Prepaid expenses and deposits 1,488
Petroleum and natural gas properties 97,616
Goodwill 30,288
Accounts payable and accrued liabilities (20,247)
Future income taxes (16,111)
Asset retirement obligations (715)
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Total cost to acquire Berland 102,749
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4. PROPERTY, PLANT AND EQUIPMENT
March 31, 2006 December 31, 2005
Accumulated Accumulated
depletion and depletion and
($000's) Cost depreciation Cost depreciation
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Petroleum and natural gas
properties 202,172 41,985 81,030 28,186
Office and computer equipment 411 145 492 94
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202,583 42,130 81,522 28,280
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Net book value 160,453 53,242
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At March 31, 2006, costs of $32,481,000 (2005 - $13,024,000) related to
undeveloped land have been excluded from the depletion and depreciation
calculation.
5. ASSET RETIREMENT OBLIGATIONS
The total future asset retirement obligation was estimated based on the
net ownership interest in all wells and facilities, estimated costs to
reclaim and abandon the wells and facilities and the estimated timing of
the costs to be incurred in future periods. The estimated net present
value of the total asset retirement obligations is $2,098,000 as at
March 31, 2006 based on a total future liability of $5,281,000. These
payments are expected to be made over the next 5 to 15 years. A credit
adjusted risk free rate of 10% was used to calculate the present value of
the asset retirement obligations.
The following table reconciles the asset retirement obligations:
(000's) $
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Obligation, December 31, 2005 1,223
Increase in obligation during the period 110
Obligation assumed from Berland acquisition 715
Accretion expense 50
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Obligation, March 31, 2006 2,098
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6. BANK OPERATING LINE
An agreement with a Canadian bank is in place for an operating bank line
which was $38.0 million which was subsequently increased to $45.0 million
in May 2006. Collateral for the facility consists of a general assignment
of book debts and a $75.0 million debenture with a floating charge over
all assets of the Company. The bank line is a demand line and carries an
interest rate of the Bank's prime rate which was 5.5 percent at March 31,
2006. On March 31, 2006, $32,180,000 was drawn on the line. Subsequent to
March 31, 2006 the amount available under the bank line was increased to
$45.0 million.
7. CAPITAL STOCK
(a) Authorized Capital
The authorized capital consists of an unlimited number of preferred
shares issuable in series and an unlimited number of common shares
without nominal or par value.
(b) Common shares issued
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Consider-
ation
Number ($000's)
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Balance December 31, 2004 46,427,469 48,331
Stock options exercised during the year 35,800 49
Reduction of contributed surplus for options
exercised - 6
Private placements for cash, net of commissions 10,700,000 24,979
Future tax effect of flow-through share
renouncement - (1,541)
Future tax effect on share issue costs and
commissions - 670
Share issue costs - (185)
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Balance December 31, 2005 57,163,269 72,309
Private placement for cash on conversion of
subscription receipts, net of commissions 8,200,000 19,988
Shares issued on arrangement with Berland
(note 3) 21,083,795 53,764
Future tax effect on share issue costs and
commissions - (6,104)
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Share issue costs - (56)
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Balance March 31, 2006 86,447,064 140,013
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Private Placements
On September 12, 2005, 4,500,000 common shares were issued by way of a
private placement at $1.95 per common share for cash proceeds of
$8,775,000 before agent's commission of $482,625. The proceeds of the
financing were used to fund oil and gas costs and for general corporate
purposes.
On September 12, 2005, 2,000,000 common shares were issued on a flow-
through basis pursuant to the Income Tax Act by way of a private
placement at $2.45 per share for proceeds of $4,900,000, before the
agent's commission of $269,500, to finance certain oil and gas
expenditures to be incurred in 2005 and 2006. The renouncement of these
expenditures was made to the purchasers of these shares for the 2005
income tax year. The expenditures to satisfy the flow-through commitment
will be made during 2005 and 2006.
On December 22, 2005, 4,200,000 common shares were issued on a flow-
through basis pursuant to the Income Tax Act by way of a private
placement at $3.15 per common share for proceeds of $13,230,000 before
agent's commission of $661,500 and 8,200,000 subscription receipts in the
capital of the Corporation issued at a price of $2.50 per subscription
receipt. The net proceeds from the "flow-through" portion of the private
placement are planned to be used to incur qualifying expenditures with
respect to the continued exploration and development of the Company's oil
and natural gas properties prior to December 31, 2006. The renouncement
of these expenditures was made to the purchasers of these shares for the
2005 income tax year. The expenditures to satisfy the flow-through
commitment will be made during 2005 and 2006.
Each subscription receipt represented the right to receive one common
share on the closing of the acquisition of Berland Exploration Ltd. The
Berland acquisition closed on January 18, 2006 and all subscription
receipts were converted to common shares and proceeds of $20,500,000 less
commissions of $512,000 were released to the Company.
On January 18, 2006 21,083,795 common shares were issued in exchange for
the acquisition of Berland shares pursuant to the Arrangement between the
companies.
(c) Stock Option Plan
A stock option plan is in place under which 7,500,000 common shares have
been reserved for options to be distributed to directors, officers,
employees and consultants with terms established by the board of
directors.
Options granted under the plan generally have a five year term to expiry
and vest equally over a three year period commencing on the first
anniversary date of the grant. The exercise price of each option equals
the closing market price of the Company's common shares on the day prior
to the date of the grant.
The following table sets forth a reconciliation of the plan activity
through March 31, 2006.
2006
Weighted
average
exercise
price
Number of ($ per
Options share)
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Outstanding, beginning of period 3,513,700 1.56
Granted 267,500 2.95
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Outstanding, end of period 3,781,200 1.66
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Exercisable 1,539,853 1.16
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The following table sets forth additional information relating to the
stock options outstanding at March 31, 2006.
Options Outstanding Exercisable Options
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Weighted Weighted
average average
exercise Weighted exercise Weighted
Exercise Number price average Number price average
price of ($ per years to of ($ per years to
range Options share) expiry Options share) expiry
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$1.00
to
$1.25 1,867,000 1.06 2.64 1,102,325 1.03 2.33
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$1.26
to
$1.50 536,700 1.41 3.18 222,531 1.42 3.12
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$1.51
to
$1.75 315,000 1.56 2.76 214,998 1.56 2.76
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$1.76
to
$2.50 - - - - - -
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$2.51
to
$2.75 117,500 2.59 5.00 - - -
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$2.76
to
$3.00 795,000 2.90 4.67 - - -
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$3.01
to
$3.25 150,000 3.24 4.82 - - -
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3,781,200 1.66 3.31 1,539,853 1.16 2.50
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The fair value based method for measuring option awards based on the
Black Scholes valuation model is used. Key assumptions used for the Black
Scholes based valuation of options are: Risk free rate - 4.3 percent;
average expected life - 4.5 years; no expected dividend yield; 45 percent
volatility. Estimated future forfeiture assumptions are not used in
calculations and forfeitures are recognized as they occur. Based on the
fair value method, $160,000 was recorded as compensation expense during
the first quarter of 2006 with a corresponding increase recorded to
contributed surplus (2005 - $83,000).
(d) Contributed surplus
The following table sets forth the continuity of contributed surplus for
the three months ended March 31, 2006.
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(000's) $
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Opening balance, December 31, 2005 574
Stock based compensation expense 160
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Closing balance, March 31, 2006 734
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8. INCOME TAXES
Future income taxes were recorded in the three months ended March 31,
2006 as set forth in the following schedule:
(000's) $
Future tax asset - December 31, 2005 225
Recorded on Berland acquisition (16,111)
Tax effect of issuance of flow-through shares (6,104)
Future tax recovery - three months ended March 31, 2006 1,281
Tax effect of share issue costs 231
Other 121
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Future tax liability - March 31, 2006 (20,357)
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9. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in Non-cash Working Capital
For the three months ended March 31,
2006 2005
(000's) $ $
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Accounts receivable (6,574) (173)
Prepaid expenses and deposits (1,667) (81)
Accounts payable and accrued liabilities 16,953 1,020
Income taxes payable (41) 9
Non-cash working capital acquired (8,438) -
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233 775
Change in non-cash working capital related to
investing activities (7,452) 842
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Change in non-cash working capital related to
operating activities 7,685 (67)
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Cash interest and taxes paid
For the three months ended March 31,
2006 2005
(000's) $ $
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Income and other taxes 98 6
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Interest 262 87
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10. PER SHARE INFORMATION
The weighted average number of common shares outstanding during the
quarter ended March 31, 2006 of 80,590,305 was used to calculate basic
income (loss) per share (diluted 81,797,406 shares) (2005 - 46,427,469
basic; 46,604,492 diluted). The total number of shares which are
potentially dilutive as of March 31, 2006 was 3,781,200.
>>
%SEDAR: 00020114E
