Symbol: BEN - TSX
CALGARY, Aug. 14 /CNW/ -
<<
FINANCIAL AND OPERATING HIGHLIGHTS
-------------------------------------------------------------------------
($ Cdn thousands, Three months Six months
except as noted) ended June 30, ended June 30,
-------------------------------------------------------------------------
% %
2006 2005 Change 2006 2005 Change
-------------------------------------------------------------------------
Sales volume
Natural gas
(mcf/day) 17,224 10,250 16,935 9,706
Oil and ngls
(bbl/day) 494 200 457 216
boe/day (6 to 1) 3,364 1,908 76% 3,280 1,834 79%
-------------------------------------------------------------------------
Revenue net of
royalties 9,845 5,754 19,369 10,665
Net income (loss) (1,606) 887 (3,728) 446
Per share (basic
and diluted) $(0.02) $0.02 $(0.04) $0.01
Funds from
operations(1) 5,375 3,518 54% 11,269 6,225 82%
Per share (basic
and diluted)(1) $0.06 $0.07 (14%) $0.14 $0.13 8%
-------------------------------------------------------------------------
Capital costs
Exploration and
development 14,090 2,693 29,677 7,054
Land and seismic 972 707 4,030 5,779
Other 172 23 651 52
-------------------------------------------------------------------------
Total 15,234 3,423 34,358 12,885 167%
-------------------------------------------------------------------------
Net wells
completed (No.) 11 4 17 11
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Net working capital
(deficit) -
including bank debt (55,766) (13,120) (55,766) (13,120)
-------------------------------------------------------------------------
Shares outstanding
End of period
(000's) 86,447 46,427 86,447 46,427
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Note:
(1) Non-GAAP measure - represents cash flow from operating activities
before non-cash working capital changes. Refer to Management's
Discussion and Analysis for discussion of this measure.
Second Quarter 2006 Operating Highlights
- Production - Q2 2006 production averaged 3,364 boe/d, up 76 percent
over Q2 2005 and up five percent from Q1 2006. Production additions
in the second quarter of 2006 were moderated by delayed drilling in
Q1 2006 due to rig availability, capacity restrictions at partner
plants, weather delays and well declines. A total of 26 wells
(14.5 net) were awaiting completion and tie-in at the end of the
second quarter and are expected to be on stream in the second half of
2006, much of it in the third quarter of 2006. Total productive
capacity awaiting tie-in is estimated to be over 1,200 boe/d at the
end of June.
- Product Mix - The addition of liquids rich natural gas from the
Berland acquisition has changed the production mix from 90% natural
gas and 10% heavy oil to 85% natural gas, 5% heavy oil and 10%
natural gas liquids. The natural gas from the Berland assets has a
high BTU content and commands a premium price.
- Production Costs - Costs averaged $8.02 per boe in Q2 2006, up 12%
compared to $7.16 per boe in Q2 2005. For the first six months of
2006 production costs have averaged $7.33 per boe, down 7% compared
to the first six months of 2005. A continued focus on cost management
has contained costs in an environment of increasing costs in the
industry. As production increases, per unit costs are expected to
trend down from the $7.33 level experienced in the first six months
of 2006.
- Funds from Operations - Funds from operations Q2 2006 was
$5.4 million ($0.06 per share) compared to Q2 2005 funds from
operations of $3.5 million ($0.07 per share). On a per share basis,
increased funds from operations has been offset by additional shares
issued mainly for the acquisition of Berland.
- Drilling - A total of 16 wells (10.6 net) were completed in the
second quarter resulting in 12 (9.1 net) natural gas wells for
success rate of 86 percent. On a year-to-date basis 30 (17.3 net)
wells have been completed with 21 (12.9 net) natural gas wells and
9 (4.4 net) unsuccessful wells for a success rate of 75 percent.
- Land - Berens total undeveloped land (owned and option) decreased
from 172,000 net acres to 158,000 net acres due to drilling activity
(converting undeveloped lands to developed) and expiries on non-core
and option lands. 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
Drilling results in the second quarter of 2006 have shown us the
potential that existed with the Berland acquisition, combined with our already
extensive land position, could deliver solid long term results. We had
100 percent success on seven locations in Lanfine and 65 percent success on
nine (4 net) locations in Pembina and the Deep Basin. Production additions
from this successful drilling look strong for the second half of the year.
In the second quarter of 2006 the high demand our industry is placing on
oil and gas service companies seems to have eased somewhat and services are
more readily available. However, we have not yet seen the reduced activity
translate in to lower costs and we remain ever vigilant in containing cost
pressures on drilling and operations.
Outlook
With more than 158,000 net undeveloped acres of land concentrated in four
operating areas, we continue to be opportunity rich. Our existing land base
will provide ample drilling locations to pursue for the balance of 2006 and
throughout 2007.
Berens is on track to complete our capital budget of $51 million. With
recently stronger natural gas prices we are comfortable that our balance sheet
will support our programmed activity levels and provide continued momentum for
the company.
Sincerely,
"signed"
Robert D. Steele
Chief Executive Officer
Berens Energy Ltd.
Management's Discussion and Analysis ("MD&A")
August 11, 2006
OVERVIEW
Berens Energy Ltd. ("Berens" or the "Company") is a full cycle oil and
natural gas exploration and production company with a concentrated production
and land base in Eastern Alberta, Pembina and Deep Basin regions of west
central Alberta.
All calculations converting natural gas to crude oil equivalent have been
made using a ratio of six thousand cubic feet ("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 June 30, 2006 unaudited interim
financial statements. This MD&A was prepared using information that is current
as of August 11, 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
---------------------
($000's except as noted) Q2 Q1
-------------------------------------------------------------------------
Sales volumes:
Natural gas (mcf/day) 17,224 16,631
Oil and ngls (bbl/day) 494 420
Barrels of oil equivalent 3,364 3,192
-------------------------------------------------------------------------
Financial:
Net revenue 9,846 9,523
Net income (loss) (1,606) (2,121)
per share - basic ($/share) $(0.02) $(0.03)
per share - diluted ($/share) $(0.02) $(0.03)
Capital costs 15,233 19,124
Shares outstanding (000's) 86,447 86,447
Bank debt 49,580 32,180
Working capital (deficit) including bank debt (55,766) (45,907)
-------------------------------------------------------------------------
Per unit information:
Natural gas price ($/mcf) $6.28 $7.72
Oil and liquids price ($/barrel) $64.27 $51.07
Oil equivalent price ($/boe) $41.59 $46.09
Operating netback ($/boe) $22.87 $24.59
-------------------------------------------------------------------------
Net wells completed: (No.)
Natural gas 9 4
Oil - -
Dry 1 3
-------------------------------------------------------------------------
Total 10 7
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2005
--------------------------------------------
($000's except as noted) Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Sales volumes:
Natural gas (mcf/day) 11,537 10,832 10,250 9,155
Oil and ngls (bbl/day) 176 165 200 233
Barrels of oil equivalent 2,099 1,970 1,908 1,759
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Financial:
Net revenue 9,537 7,667 5,754 4,910
Net income (loss) (475) 534 887 (441)
per share - basic
($/share) $(0.01) $0.01 $0.02 $(0.01)
per share - diluted
($/share) $(0.01) $0.01 $0.02 $(0.01)
Capital costs 12,346 7,165 3,423 9,462
Shares outstanding (000's) 57,163 52,961 46,427 46,427
Bank debt - - 10,080 10,480
Working capital (deficit)
including bank debt 4,273 (2,137) (13,121) (13,216)
-------------------------------------------------------------------------
Per unit information:
Natural gas price ($/mcf) $11.26 $9.16 $7.29 $6.91
Oil and liquids price
($/barrel) $41.92 $57.47 $33.11 $30.81
Oil equivalent price ($/boe) $65.47 $55.05 $42.61 $40.05
Operating netback ($/boe) $39.78 $34.07 $24.81 $21.12
-------------------------------------------------------------------------
Net wells completed: (No.)
Natural gas 9 7 3 5
Oil 1 0 0 0
Dry 2 2 1 2
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Total 12 9 4 7
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2004
----------------------
($000's except as noted) Q4 Q3
-------------------------------------------------------------------------
Sales volumes:
Natural gas (mcf/day) 7,089 5,310
Oil and ngls (bbl/day) 240 238
Barrels of oil equivalent 1,422 1,123
-------------------------------------------------------------------------
Financial:
Net revenue 3,803 3,322
Net income (loss) (1,652) (512)
per share - basic
($/share) $(0.04) $(0.01)
per share - diluted
($/share) $(0.04) $(0.01)
Capital costs 6,813 5,564
Shares outstanding (000's) 46,427 43,427
Bank debt 4,500 4,250
Working capital (deficit)
including bank debt (6,461) (5,973)
-------------------------------------------------------------------------
Per unit information:
Natural gas price ($/mcf) $6.48 $6.44
Oil and liquids price ($/barrel) $31.88 $40.02
Oil equivalent price ($/boe) $36.08 $38.91
Operating netback ($/boe) $18.96 $19.86
-------------------------------------------------------------------------
Net wells completed: (No.)
Natural gas 11 5
Oil 1 1
Dry - 1
-------------------------------------------------------------------------
Total 12 7
-------------------------------------------------------------------------
>>
Significant production and revenue increases were experienced in the
first quarter of 2006 compared to earlier quarters due to the acquisition of
Berland Exploration Ltd. in January of 2006.
RESULTS OF OPERATIONS
Production Volume
Production volume averaged 3,364 boe/d for the second quarter of 2006,
up 76 percent compared to 1,908 boe/d in the second quarter of 2005. Natural
gas represented 85 percent of production in the second quarter of 2006 with
the remaining production being 10 percent light oil and natural gas liquids
and five percent conventional heavy oil.
Production from the Berland acquisition which closed on January 18, 2006,
contributed the majority of the incremental volumes in the second quarter of
2006. Drilling in the first quarter of 2006 did not add significantly to
volumes in the second quarter quarter as the majority of the drilling was
conducted in March due to lack of rig availability in January and February.
Spring break-up also limited tie-ins of the wells drilled in the first
quarter. Second quarter production volume was also hampered by capacity
restrictions in a partner plant shutting in all production in Bigstone
(60 boe/d) and a plant turnaround in Pembina in June (50 boe/d).
Production volume averaged 3,280 boe/d for the six months ended June 30,
2006, up 79 percent compared to 1,834 boe/d in the six months ended June 30,
2005 with the majority of the increase due to the Berland purchase.
A drilling success rate of 86 percent was experienced in the second
quarter of 2006 with no volumes from the second quarter drilling contributing
to production in the quarter. A total of 26 wells (14.5 net) were awaiting
completion and tie-in at the end of the second quarter which are expected to
be on stream in the second half of 2006, much of it in the third quarter.
Total productive capacity awaiting tie-in is estimated to be over 1,200 boe/d
at the end of June.
Production Revenue
Natural gas prices averaged $6.28 per mcf for the second quarter of 2006,
down 14 percent compared to $7.29 per mcf in the second quarter of 2005. Oil
and liquids prices averaged $63.67 and $64.52 per barrel respectively in the
first second quarter of 2006 for a blended price of $64.27 per barrel, up
94 percent from the second quarter 2005 liquids price of $33.11 per barrel.
Higher priced light oil and natural gas liquids represent a larger portion of
liquids production in 2006 compared to 2005 when most of the Company's liquids
were heavy oil. On a boe basis, prices averaged $41.59 in the second quarter
of 2006, down two percent compared to the second quarter of 2005.
Revenue was up 72 percent in the second quarter of 2006 compared to the
second quarter of 2005. Volume increased by 76 percent offset by a two percent
decrease in per boe prices.
Natural gas prices averaged $6.98 per mcf for the six months ended
June 30, 2006, down three percent compared to $7.22 per mcf in the six months
ended June 30, 2005. Blended oil and liquids prices averaged $58.24 per barrel
in the six months ended June 30, 2006, up 82 percent from the six months ended
June 30, 2005 liquids price of $31.88 per barrel. On a boe basis, prices
averaged $44.16 in the six months ended June 30, 2006, up five percent
compared to the six months ended June 30, 2005. Revenue was up 91 percent in
the six months ended June 30, 2006 compared to the six months ended June 30,
2005. Volume increased by 79 percent supplemented by a five percent increase
in per boe prices.
Royalties
Royalties, net of Alberta Royalty Tax Credit ("ARTC"), averaged
23 percent of revenue for the second quarter of 2006 compared to 22 percent of
revenue in the second quarter of 2005. Excluding ARTC, royalty rates averaged
24 percent in the second quarter of 2006 and 24 percent in the second quarter
of 2005. For the six months ended June 30, 2006 royalties, net of ARTC
averaged 26 percent of revenue compared to 23 percent of revenue in the six
months ended June 30, 2005. The higher 2006 royalty percentage is attributed
to the following factors:
<<
- Significant 2006 production comes from higher volume liquids rich
wells in Pembina and the Deep Basin that have higher royalty rates
compared to 2005 production which was primarily from lower volume
wells in Lanfine.
- Production from certain farm-in lands in Pembina incurs overriding
royalties which contribute to the higher royalty percentage.
>>
On an ongoing basis, royalties are expected to average approximately
26 percent of revenues. Royalty expense of $2.9 million was recorded in the
second quarter of 2006, up 75 percent compared to the second quarter of 2005
reflecting both higher revenue and higher royalty rates. For the six months
ended June 30, 2006 royalty expense of $7.9 million was up 122 percent
compared to the six months ended June 30, 2005.
Production Expenses
Production expenses were $8.02 per boe in the second quarter of 2006, up
12 percent compared to $7.16 per boe in the second quarter of 2005. For the
six months ended June 30, 2005 production expenses were $7.33 per boe, down
seven percent compared to the six months ended June 30, 2005. A focus on cost
management has reduced per boe costs in Lanfine and the Berland assets have
characteristically low per unit operating costs. Second quarter costs were
higher due to well work-over work in Lanfine. Management expects further per
unit operating expense reduction from the year-to-date rate of $7.33 per boe
with increased third and fourth quarter volumes combined with a continued
focus on cost management.
Second quarter 2006 production expenses were $2.5 million, up 98 percent
compared to the second quarter of 2005 due to a 76 percent increase in volume
and higher per unit costs. For the six months ended June 30, 2006 production
expenses were $4.4 million, up 67 percent compared to the six months ended
June 30, 2005 due to a 79 percent production increase offset by lower per unit
costs.
Transportation costs of $0.3 million increased 37 percent in the second
quarter of 2006 compared to the second quarter of 2005 due to increased
volumes offset by lower per unit costs. For the six months ended June 30, 2006
transportation costs were $0.6 million an increase of 47 percent compared to
the six months ended June 30, 2005.
General and Administrative Expenses
General and administrative costs, including stock-based compensation,
were up 90 percent in the second quarter of 2006 compared to the second
quarter of 2005. Increased costs were incurred in 2006 as the staff contingent
has approximately doubled since the second quarter of 2005 with production
growth and the addition of the Berland assets and staff. Salary and bonus
levels have also increased as a result of industry competitive pressures. On a
per boe basis, general and administrative costs were $4.65 per boe for the
second quarter of 2006, up eight percent compared to $4.32 per boe in the
second quarter of 2005.
For the six months ended June 30, 2006 general and administrative costs
were up 97 percent compared to the six months ended June 30, 2005. In addition
to the items discussed above, non-recurring costs of $160,000 were incurred in
the first half of 2006 to integrate the Berland operations. On a per boe
basis, general and administrative costs were $4.68 per boe for the six months
ended June 30, 2006, up 12 percent compared to $4.18 per boe in the six months
ended June 30, 2005. There were no general and administrative costs
capitalized in the second quarter or for the six months ended June 30, 2006
and 2005.
Staff levels are expected to remain fairly constant throughout the
balance of 2006. Per unit general and administrative costs are expected to
decline as production levels increase during the year.
Interest Expense
Interest expense increased 343 percent in the second quarter of 2006
compared to the second 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 $28 million were
assumed on January 18, 2006, the closing date of the acquisition. In addition,
capital expenditures in the first half of 2006 were significantly higher than
funds from operations. For the six months ended June 30, 2006 interest expense
increased 282 percent compared to six months ended June 30, 2005.
Operating Netback(1)
Operating netback represents the margin realized by the production and
sale of petroleum and natural gas.
<<
-------------------------------------------------------------------------
Quarterly Operating Netbacks Three months Six months
($'s per boe) ended ended
June 30 June 30
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Sales price 41.59 42.61 44.16 41.95
Less:
Royalties (net of ARTC) 9.85 9.55 12.01 9.36
Production expenses 8.02 7.16 7.33 7.85
Transportation charges 0.85 1.10 0.93 1.13
-------------------------------------------------------------------------
Operating netback 22.87 24.81 23.89 23.61
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) non-GAAP measure - refer to discussion on non-GAAP measures below.
>>
Depletion, Amortization and Accretion
Depletion, amortization and accretion totaled $9.3 million
($30.51 per boe) in the second quarter of 2006 compared to $3.5 million
($20.33 per boe) in the second quarter of 2005. For the six months ended June
30, 2006 depletion, amortization and accretion totaled $18.5 million ($31.12
per boe) compared to $6.6 million ($19.87 per boe) for the six months ended
June 30, 2005. The higher depletion rates are attributable to the cost of
acquiring the Berland reserves through the acquisition and to spending in the
deeper drilling program which had limited reserve additions to the end of
2005. The 2006 capital plan is focused on drilling, primarily in Pembina and
Lanfine which is expected to add reserves at lower cost on a go forward basis.
Income Taxes
Current taxes of $11,000 were recorded in the second quarter of 2006
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 $17.8 million at June 30, 2006. Future tax liabilities of
$16.1 million were recorded on the acquisition of Berland and $6.1 million was
recorded to account for the tax effect of flow-through shares renouncements,
offset by a $1.5 million future tax reduction to reflect future corporate tax
rate reductions which are substantially enacted.
NET INCOME
The net loss for the second quarter of 2006 was $1.6 million
($0.02 per share) compared to net income of $0.9 million ($0.01 per share) in
the second quarter of 2005. The higher 2006 loss has resulted primarily from
higher depletion expense more than offsetting the benefit from increases in
production volume.
CAPITAL COSTS
Capital costs were $15.2 million in the second quarter of 2006, up from
$3.4 million in the second quarter of 2005 as overall activity levels are
higher with the larger asset base. A total of 10 net wells were completed in
the second quarter of 2006 compared to four net wells in the second quarter of
2005. Average well costs are higher in 2006 as deeper Pembina and Deep Basin
wells are in the 2006 drilling program whereas in 2005 the shallower Lanfine
drilling program was the majority of the drilling. Capital costs are up as
well due to increased rates charged by drilling and service companies for most
activities.
<<
-------------------------------------------------------------------------
Three months Six months
($000's) ended June 30, ended June 30,
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Drilling and completion 14,090 2,693 29,677 7,054
Land 122 77 1,683 4,108
Geological and geophysical 850 630 2,347 1,671
Office and other 172 23 651 52
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Total 15,234 3,423 34,358 12,885
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-------------------------------------------------------------------------
>>
Overall, the Company has spent 86 percent of its capital on drilling and
completion activities in the first six months of 2006 compared to a capital
program that was focused on land and seismic in the first half 2005. In 2005
there was a focus to build new land positions in central and west central
Alberta. With a large undeveloped land base in place entering 2006 and the
acquisition of Berland who also had significant undeveloped land the capital
program for 2006 is focused on drilling.
WORKING CAPITAL
Accounts receivable of $18.7 million at June 30, 2006 was primarily
revenue receivables and amounts owing from partners ($16.4 million) as well as
capital advances to partners for drilling projects ($1.8 million). Accounts
payable at June 30, 2006 of $27.7 million were mainly comprised of trade
payables for capital and operating costs ($12.6 million), royalties
($1.8 million), amounts owing to partners ($3.4 million) and capital costs
accrued at the end of the quarter for ongoing drilling and completion
operations ($3.1 million).
Working capital excluding bank indebtedness was in a deficit position of
$6.1 million at June 30, 2006. Borrowings under the bank line and ongoing cash
flows, combined with a capital program for the balance of 2006 that is
expected to be less than cash flow is expected to fund this working capital
deficit.
LIQUIDITY AND CAPITAL RESOURCES
The Company plans to fund its current working capital deficit, operations
and capital costs with a mix of operating cash flow and debt financing through
the bank operating line. An operating bank line is in place for $57.0 million,
secured by producing properties. At June 30, 2006, $49.6 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 June 30 is set out in the following chart:
<<
-------------------------------------------------------------------------
Three months Six months
($000's) ended June 30, ended June 30,
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Net income (loss) (1,606) 887 (3,728) 446
Items not requiring cash:
Depletion, depreciation
and accretion 9,341 3,532 18,476 6,596
Future income tax expense
(recovery) (2,579) (985) (3,859) (985)
Stock based compensation 219 84 379 168
-------------------------------------------------------------------------
Funds from operations 5,375 3,518 11,268 6,225
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
Funds from operations are also presented on a per share basis consistent
with the calculation of net income per share, whereby per share amounts are
calculated using the weighted average number of shares outstanding. Funds from
operations per share were $0.06 (basic and diluted) for the second quarter of
2006 compared to $0.07 per share for the second quarter of 2005. Funds from
operations per share were $0.14 (basic and diluted) for the six months ended
June 30, 2006 compared to $0.13 for the six months ended June 30, 2005.
RISKS
Primary financial risks relate to variability in commodity prices.
Interest rate and currency exchange rate variability also have an effect on
financial results. The effect of changes in the exchange rate between US and
Canadian currencies on natural gas prices is not direct, as variations between
the regional markets for natural gas are often much greater than can be
explained by currency variability.
Other risks are related to operations. These risks include, but are not
limited to, risks associated with oil and gas exploration, development,
exploitation, production, marketing and transportation, delays or changes in
plans with respect to exploration or development projects or capital costs,
volatility of commodity prices, currency fluctuations, the uncertainty of
reserves estimates, potential environmental liabilities, technology risks,
competition, incorrect assessment of the value of acquisitions and failure to
realize the anticipated benefits of acquisitions. The foregoing list of
factors is not exhaustive. Additional information on these and other factors
that could affect operations or financial results are included in a more
detailed description of risks in Berens' Annual Information
Form on file with Canadian securities regulatory authorities and
available on SEDAR at www.sedar.com.
Documented environmental health and safety plans are in place as well as
a comprehensive emergency response plan to mitigate operating risks.
RELATED PARTY TRANSACTIONS
A consulting firm is contracted from time to time in which one of the
Company's directors is the managing partner. The executive services rendered
are in the normal course of business and are at normal rates charged by the
consulting firm and recorded at the exchange amount. Consulting fees for this
firm in the second quarter of 2006 were $16,000 and $58,000 for the six months
ended June 30, 2006. Fees for legal services are paid to a law firm in which
the corporate secretary is a partner. The legal services are rendered in the
normal course of business at normal rates charged by the law firm. Legal fees
for this firm paid in the second quarter of 2006 were $103,000 and $509,000
for the six months ended June 30, 2006.
SHARE DATA
As of the date of this MD&A the Company had 86,447,064 issued and
outstanding common shares. Additionally, options to purchase 4,075,700 common
shares have been issued.
DISCLOSURE CONTROLS AND PROCEDURES OVER FINANCIAL REPORTING
Disclosure controls and procedures are designed to provide reasonable
assurance that all relevant information is gathered and reported to senior
management, including the Chief Executive Officer ("CEO") and the Chief
Financial Officer ("CFO"), on a timely basis so appropriate decisions can be
made regarding public disclosure. As at December 31, 2005, the CEO and the CFO
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 six months of 2006.
OUTLOOK
The acquisition of Berland was an important step to position the Company
for future growth. Drilling opportunities now exist across four core areas and
are well diversified in terms of risk and potential return. The intention is
to stay focused in the four core areas that have been established to take
advantage of the high level of technical expertise we have developed in each
area.
The 2006 capital program has greater diversification than the 2005
program both in terms of regions and the mix of risk and return potential.
Drilling at Lanfine represents the lowest risk drilling with the expectation
of solid returns while the Deep Basin is the higher risk drilling with the
potential for significant reserve discoveries. Pembina is considered to have a
medium risk and strong return profile. The 2006 capital plan is more drilling
focused compared to 2005 and will concentrate in Lanfine and Pembina for the
balance of 2006.
Access to services has been a challenge in early 2006 although the stress
on the service industry seems to have eased recently. Costs have also climbed
for almost every service in the oil and gas industry. Capital management and a
focus on cost reduction will be important aspects of our business when
carrying out the 2006 capital program. A larger capital program and a critical
mass of wells to drill in 2006 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 158,000 net acres is expected to provide a strong inventory of
drilling prospects to deliver future growth.
<<
Berens Energy Ltd.
Balance Sheets
(unaudited)
As at
-------------------------------------------------------------------------
(000's) June 30, December 31,
2006 2005
-------------------------------------------------------------------------
ASSETS (note 6)
Current
Cash and cash equivalents $ 35 $ 9,472
Accounts receivable 18,743 9,912
Prepaid expenses and deposits 2,773 680
-------------------------------------------------------------------------
21,551 20,064
Investments 299 299
Future income taxes (note 8) - 225
Property, plant and equipment (note 4) 166,553 53,242
Goodwill (note 3) 44,974 14,805
-------------------------------------------------------------------------
$ 233,377 $ 88,635
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Bank loan (note 6) $ 49,580 -
Accounts payable and accrued liabilities 27,716 $ 15,699
Taxes payable 20 92
-------------------------------------------------------------------------
77,316 15,791
Asset retirement obligation (note 5) 2,305 1,223
Future income taxes (note 8) 17,779 -
-------------------------------------------------------------------------
97,400 17,014
Shareholders' equity
Capital stock (note 7) 140,013 72,309
Contributed surplus (note 7) 953 574
Deficit (4,989) (1,262)
-------------------------------------------------------------------------
135,977 71,621
-------------------------------------------------------------------------
$ 233,377 $ 88,635
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the financial statements
Berens Energy Ltd.
Statements of Operations and Deficit
(unaudited)
For the three and six months ended June 30
-------------------------------------------------------------------------
($000's) Three months Six months
ended June 30, ended June 30,
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Revenue
Oil and natural gas revenue $ 12,737 $ 7,411 $ 26,251 $ 13,770
Royalties, net of ARTC (2,892) (1,657) (6,882) (3,105)
-------------------------------------------------------------------------
9,845 5,754 19,369 10,665
Interest 1 - 17 -
-------------------------------------------------------------------------
9,846 5,754 19,386 10,665
-------------------------------------------------------------------------
Expenses
Production 2,458 1,243 4,351 2,606
Transportation 261 190 553 375
Depletion, amortization
and accretion 9,341 3,532 18,476 6,596
General and administrative 1,205 666 2,397 1,219
Stock-based compensation
(note 7) 219 84 380 168
Interest 536 121 799 209
-------------------------------------------------------------------------
14,020 5,836 26,956 11,173
-------------------------------------------------------------------------
Loss before income taxes (4,174) (82) (7,570) (508)
-------------------------------------------------------------------------
Income taxes (note 8)
Future expense (recovery) (2,579) (985) (3,859) (985)
Current expense 11 16 17 31
-------------------------------------------------------------------------
(2,568) (969) (3,842) (954)
-------------------------------------------------------------------------
Net income (loss) for
the period (1,606) 887 (3,728) 446
Deficit, beginning of period (3,383) (2,207) (1,261) (1,766)
-------------------------------------------------------------------------
Deficit, end of period $ (4,989) $ (1,320) $ (4,989) $ (1,320)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income (loss) per share
(note 11)
Basic and diluted $ (0.02) $ 0.02 $ (0.04) $ 0.01
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the financial statements
Berens Energy Ltd.
Statements of Cash Flows
(unaudited)
For the three and six months ended June 30
-------------------------------------------------------------------------
($000's) Three months Six months
ended June 30, ended June 30,
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income (loss) for
the period $ (1,606) $ 887 $ (3,728) $ 446
Add items not involving cash
Depletion, amortization
and accretion 9,341 3,532 18,476 6,596
Future income tax expense
(recovery) (2,579) (985) (3,859) (985)
Stock-based compensation 219 84 379 168
-------------------------------------------------------------------------
5,375 3,518 11,268 6,225
Change in non-cash working
capital items related to
operating activities
(note 9) (14,536) (364) (6,851) (431)
-------------------------------------------------------------------------
Cash flow provided by (used
in) operating activities (9,161) 3,154 4,417 5,794
-------------------------------------------------------------------------
FINANCING ACTIVITIES
Change in bank loan 17,400 (400) 29,830 5,580
Net proceeds from private
offerings - - 19,813 -
-------------------------------------------------------------------------
Cash flow provided by
(used in) financing
activities 17,400 (400) 49,643 5,580
-------------------------------------------------------------------------
INVESTING ACTIVITIES
Cash acquired through
Berland acquisition - - 109 -
Cash component on Berland
acquisition - - (28,682) -
Purchase of property and
equipment (15,234) (3,423) (34,358) (12,885)
Change in non-cash working
capital items related to
investing activities (note 9) 6,886 678 (566) 1,520
-------------------------------------------------------------------------
Cash flow used in investing
activities (8,348) (2,745) (63,497) (11,365)
-------------------------------------------------------------------------
Increase (decrease) in cash (109) 9 (9,437) 9
Cash and cash equivalents,
beginning of period 144 35 9,472 35
-------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 35 $ 44 $ 35 $ 44
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the financial statements
BERENS ENERGY LTD.
Notes to Financial Statements
(unaudited)
Three and six months ended June 30, 2006 and 2005
1. NATURE OF OPERATIONS
The Company is a full cycle oil and natural gas exploration and
production company with activities encompassing land acquisition,
geological and geophysical assessment, drilling and completion, and
production. The primary areas of operation are in eastern and west
central Alberta.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The interim financial statements have been prepared by management
following the same accounting policies as the most recent annual audited
financial statements.
Certain disclosures, which are normally required to be included in notes
to the annual financial statements, are condensed or omitted for interim
reporting purposes. Accordingly, these interim financial statements
should be read in conjunction with the audited annual financial
statements for the year ended December 31, 2005. Certain prior period
amounts have been reclassified to conform to current disclosure
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.
Assets and liabilities purchased (000's) $
-------------------------------------------------------------------------
Cash and cash equivalents 109
Accounts receivable 10,321
Prepaid expenses and deposits 1,488
Petroleum and natural gas properties 97,616
Goodwill 30,288
Accounts payable and accrued liabilities (20,247)
Future income taxes (16,111)
Asset retirement obligations (715)
-------------------------------------------------------------------------
Total cost to acquire Berland 102,749
-------------------------------------------------------------------------
4. PROPERTY, PLANT AND EQUIPMENT
June 30, 2006 December 31, 2005
Accumulated Accumulated
depletion depletion
and and
($000's) Cost depreciation Cost depreciation
-------------------------------------------------------------------------
Petroleum and natural
gas properties 217,382 51,237 81,030 28,186
Office and computer
equipment 583 175 492 94
-------------------------------------------------------------------------
217,965 51,412 81,522 28,280
-------------------------------------------------------------------------
Net book value 166,553 53,242
-------------------------------------------------------------------------
At June 30, 2006, costs of $29,500,000 (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 $2,305,000 as at
June 30, 2006 based on a total future liability of $6,187,000. These
payments are expected to be made over the next 5 to 15 years. An
inflation rate of two percent and a credit adjusted risk free rate of 10%
was used to calculate the present value of the asset retirement
obligations.
The following table reconciles the asset retirement obligations:
(000's) $
-------------------------------------------------------------------------
Obligation, December 31, 2005 1,223
Increase in obligation during the period 258
Obligation assumed from Berland acquisition 715
Accretion expense 109
-------------------------------------------------------------------------
Obligation, June 30, 2006 2,305
-------------------------------------------------------------------------
6. BANK OPERATING LINE
An agreement with a Canadian bank is in place for an operating bank line
totaling $57.0 million at June 30, 2006. Collateral for the facility
consists of a general assignment of book debts and a $75.0 million
debenture with a floating charge over all assets of the Company. The bank
line is a demand line and carries an interest rate of the Bank's prime
rate adjusted for a factor based on the most recent quarterly debt to
cash flow calculation. The rate at June 30, 2006 was 6.5 percent
(June 30, 2005 - 4.625 percent). On June 30, 2006, $49,580,000 was drawn
on the line.
7. CAPITAL STOCK
(a) Authorized Capital
The authorized capital consists of an unlimited number of preferred
shares issuable in series and an unlimited number of common shares
without nominal or par value.
(b) Common shares issued
-------------------------------------------------------------------------
Consideration
Number ($000's)
-------------------------------------------------------------------------
Balance December 31, 2004 46,427,469 48,331
Stock options exercised during the year 35,800 49
Reduction of contributed surplus for
options exercised - 6
Private placements for cash, net of
commissions 10,700,000 24,979
Future tax effect of flow-through share
renouncement - (1,541)
Future tax effect on share issue costs
and commissions - 670
Share issue costs - (185)
-------------------------------------------------------------------------
Balance December 31, 2005 57,163,269 72,309
Private placement for cash on conversion of
subscription receipts, net of commissions 8,200,000 19,988
Shares issued on arrangement with
Berland (note 3) 21,083,795 53,764
Future tax effect of flow-through share
renouncement (6,104)
Future tax effect on share issue costs
and commissions - 231
Share issue costs - (175)
-------------------------------------------------------------------------
Balance June 30, 2006 86,447,064 140,013
-------------------------------------------------------------------------
Private Placements
On September 12, 2005, 4,500,000 common shares were issued by way of a
private placement at $1.95 per common share for cash proceeds of
$8,775,000 before agent's commission of $482,625. The proceeds of the
financing were used to fund oil and gas 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 have been used to incur qualifying expenditures with
respect to the continued exploration and development of the Company's oil
and natural gas properties prior to December 31, 2006. The renouncement
of these expenditures was made to the purchasers of these shares for the
2005 income tax year. The expenditures to satisfy the flow-through
commitment have been made as at June 30, 2006.
Each subscription receipt represented the right to receive one common
share on the closing of the acquisition of Berland Exploration Ltd. The
Berland acquisition closed on January 18, 2006 and all subscription
receipts were converted to common shares and proceeds of $20,500,000 less
commissions of $512,000 were released to the Company. No obligation
remains related to this subscription receipt issue.
On January 18, 2006 21,083,795 common shares were issued in exchange for
the acquisition of Berland shares pursuant to the Arrangement between the
companies.
(c) Stock Option Plan
A stock option plan is in place under which 7,500,000 common shares have
been reserved for options to be distributed to directors, officers,
employees and consultants with terms established by the board of
directors.
Options granted under the plan generally have a five year term to expiry
and vest equally over a three year period commencing on the first
anniversary date of the grant. The exercise price of each option equals
the closing market price of the Company's common shares on the day prior
to the date of the grant.
The following table sets forth a reconciliation of the plan activity
through June 30, 2006.
Weighted average
Number of exercise price
Options ($ per share)
-------------------------------------------------------------------------
Outstanding, December 31, 2005 3,513,700 1.56
Granted 562,000 2.47
-------------------------------------------------------------------------
Outstanding, June 30, 2005 4,075,700 1.70
-------------------------------------------------------------------------
Exercisable 1,755,689 1.16
-------------------------------------------------------------------------
The following table sets forth additional information relating to the
stock options outstanding at June 30, 2006.
Options Outstanding Exercisable Options
-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
$1.00
to
$1.25 1,867,000 1.06 2.39 1,252,328 1.03 2.07
-------------------------------------------------------------------------
$1.26
to
$1.50 536,700 1.41 2.93 288,363 1.42 2.88
-------------------------------------------------------------------------
$1.51
to
$1.75 390,000 1.59 2.99 214,998 1.56 2.51
-------------------------------------------------------------------------
$1.76
to
$2.00 94,500 1.78 4.93 - - -
-------------------------------------------------------------------------
$2.01
to
$2.25 - - - - - -
-------------------------------------------------------------------------
$2.26
to
$2.50 125,000 2.40 4.87 - - -
-------------------------------------------------------------------------
$2.51
to
$2.75 117,500 2.59 4.75 - - -
-------------------------------------------------------------------------
$2.76
to
$3.00 795,000 2.90 4.42 - - -
-------------------------------------------------------------------------
$3.01
to
$3.25 150,000 3.24 4.57 - - -
-------------------------------------------------------------------------
4,075,700 1.70 3.20 1,755,689 1.16 2.26
-------------------------------------------------------------------------
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, $379,000 was recorded as compensation
expense for the six month period ended June 30, 2006 and $219,000 for the
three month period ended June 30, 2006 (2005 - $168,000 and $84,000) with
a corresponding increase recorded to contributed surplus.
(d) Contributed Surplus
The following table sets forth the continuity of contributed surplus for
the three months ended June 30, 2006.
(000's) $
-------------------------------------------------------------------------
Opening balance, December 31, 2005 574
Stock based compensation expense 379
-------------------------------------------------------------------------
Closing balance, June 30, 2006 953
-------------------------------------------------------------------------
8. INCOME TAXES
Future income taxes were recorded in the six months ended June 30, 2006
as set forth in the following schedule:
(000's) $
-------------------------------------------------------------------------
Future tax asset - December 31, 2005 226
Recorded on Berland acquisition (16,110)
Tax effect of issuance of flow-through shares (6,104)
Future tax recovery - six months ended June 30, 2006 3,859
Tax effect of share issue costs 231
Other 119
-------------------------------------------------------------------------
Future tax liability - June 30, 2006 (17,779)
-------------------------------------------------------------------------
The future tax recovery includes $1,471,000 to record the benefit of
future tax rate reductions that were substantially enacted in the second
quarter of 2006.
9. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in Non-cash Working Capital
For the six months ended June 30,
2006 2005
(000's) $ $
-------------------------------------------------------------------------
Accounts receivable (8,831) 199
Prepaid expenses and deposits (2,093) (231)
Accounts payable and accrued liabilities 12,017 1,150
Income taxes payable (72) (29)
Non-cash working capital acquired (note 3) (8,438) -
-------------------------------------------------------------------------
(7,417) 1,089
Change in non-cash working capital related to
investing activities (566) 1,520
-------------------------------------------------------------------------
Change in non-cash working capital related to
operating activities (6,851) (431)
-------------------------------------------------------------------------
Cash interest and taxes paid
For the three and six months ended June 30,
Three Three Six Six
months months months months
2006 2005 2006 2005
(000's) $ $ $ $
-------------------------------------------------------------------------
Income and other taxes 1 55 137 61
Interest 525 87 783 209
-------------------------------------------------------------------------
10. RELATED PARTY TRANSACTIONS
A consulting firm is contracted from time to time in which one of its
directors is the managing partner. The executive services rendered are in
the normal course of business and are at normal rates charged by the
consulting firm and recorded at the exchange amount. Consulting fees for
this firm in the second quarter of 2006 were $16,000 and $58,000 for the
six months ended June 30, 2006. Fees for legal services are paid to a law
firm in which the corporate secretary is a partner. The legal services
are rendered in the normal course of business at normal rates charged by
the law firm. Legal fees for this firm paid in the second quarter of 2006
were $103,000 and $509,000 for the six months ended June 30, 2006.
11. PER SHARE INFORMATION
The weighted average number of common shares outstanding during the
quarter ended June 30, 2006 of 86,447,064 was used to calculate basic
income (loss) per share (diluted 86,447,064 shares) (2005 - 46,427,469
basic; 46,626,011 diluted). The weighted average number of common shares
outstanding during the six months ended June 30, 2006 of 83,534,863 was
used to calculate basic income (loss) per share (diluted 83,534,863
shares) (2005 - 46,427,469 basic; 46,626,011 diluted). The total number
of shares which are potentially dilutive as of June 30, 2006 was
4,075,700.
>>
%SEDAR: 00020114E
