Symbol: BEN - TSX Venture Exchange
CALGARY, April 21 /CNW/ -
<<
FINANCIAL AND OPERATING HIGHLIGHTS
For the periods ended December 31, 2004
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Three months ended Year ended
($ Cdn thousands, except as noted) December 31, December 31,
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2004 2003 2004 2003
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Production volume
Natural gas (mmcf/day) 7,089 - 6,165 -
Oil (barrels/day) 240 - 255 -
BOE/day (6 to 1) 1,422 - 1,283 -
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Production revenue net of royalties 3,623 1,192 14,166 1,192
Net loss (1,652) (932) (1,766) (4,102)
Per share (basic and diluted) $(0.04) $(0.04) $(0.04) $(0.23)
Cash flow from operations $1,864 (257) $7,605 (3,090)
Per share (basic and diluted) $0.04 $(0.01) $0.17 $(0.17)
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Capital costs
Exploration & development 5,751 1,149 14,274 1,149
Land and seismic 1,048 - 5,400 -
Other 133 - 326 -
Total 6,932 1,149 20,000 1,149
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Net working capital (deficit) -
including bank debt (6,461) 1,389 (6,461) 1,389
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Shares outstanding
End of period 46,427 19,133 46,427 19,133
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2004 Operating Highlights
- Production - exited 2004 with strong production momentum with Q4
average production of 1,422 boe/d and expected Q1 2005 average of
1,700 boe/d
- Land - increased net undeveloped acreage by 20% to 110,000 acres by
year end. Added significantly to our west central acreage position in
early 2005 with land acquisitions and a farm-in.
- Finding & Development Costs - 2004 capital spent on seismic and
drilling delivered proved + probable F&D costs of $11.10 per boe and
proved costs of $15.11 per boe.
- Reserve Replacement - replaced 152 percent of 2004 production with
proved reserves despite negative revisions to reserves acquired in
2003. On a proved plus probable basis we replaced 189 percent of our
production.
Chairman's Message
The theme of our 2003 annual report was "up and running" as we had just
established our operating base. In this annual report we will describe the
progress we have made following the purchase of Resolution and Matrix at the
end of 2003, and share with you our aggressive plans for "stepping it up" in
the next year. 2004 was a year to build our team, gain control of our asset
base at Lanfine in eastern Alberta, and initiate growth in a second area in
west central Alberta. Berens drilled actively and successfully in Lanfine with
strong production gains late in the year. Our success in Lanfine continues to
be characterized by:
- Drilling success ratio
Through our 3D seismic program in Lanfine we achieved 95 percent
success (20/21 wells) at defining and hitting our drilling
targets.
- Tight cost control
Despite an environment of escalating costs, we managed to reduce
our cost for seismic, drilling, casing and completing our wells by
as much as 20 percent by the end of 2004 compared to wells drilled
early in the year.
- High levels of profitability
We had an estimated rate of return of 60 per cent for wells
drilled in 2004 based on cash flows discounted at 12 percent.
- Continued access to undeveloped land
We added over 20 percent to our already large land base in the
area, with over 88,000 net undeveloped acres of land and option
land in Lanfine by the end of 2004, enough inventory for drilling
plans for 2005 and 2006.
These are things we can control. They are at the heart of our operating
philosophy.
Continued higher gas prices enhance our economics, and make a good story
even better. The higher gas prices along with general concern about long term
gas supply seem to have created a new gas price paradigm in North America. We
will continue to fine tune our seismic and control our costs to ensure we
remain competitive and financially successful.
By mid-year we had embarked on our stated plans to begin to build a
second production base in west central Alberta in order to diversify our
production and seek higher risk/reward opportunities that bring longer reserve
life. By the end of 2004 we had made significant progress on this front with
100 boe/day of production coming from west central Alberta and a developing
land base. Since the end of 2004, we have tripled our west central land
position giving us a strong base for an array of drilling prospects.
We project that this land base will yield a significant number of
drilling opportunities in 2005 and early 2006. We participated in six wells
(1.6 net) in 2004 and early 2005 in west central Alberta with results that
convince us we are on the right track.
Berens' long term strategy to add value for our shareholders continues to
be:
- Use lower risk exploration in eastern Alberta to sustain production
and cash flow for the company
- Build the organic fibre of the company through land purchases, farm-
ins or asset purchases to provide a land base for growth in west
central Alberta
- Develop niche opportunities where we jointly recognize opportunities
that will allow us to use Berens' geological and operating expertise,
and technology to build potential new core areas
- Pursue acquisitions that are accretive and synergistic with our
business plan and operating areas.
We have added six professionals to our staff during the past year which
has enhanced our technical skills and enabled us to organize into multi-
disciplinary teams with sufficient in-house support to accelerate our efforts
in focus areas. Our colleagues are experienced, motivated, energetic and
committed. They continuously bring deals and plays and are attracting interest
from other companies that recognize the technical strength and business acumen
of our overall team.
Looking forward, we expect 2005 to be a strong year. We have set a
$20 million capital program that is projected to yield production growth of 44
percent over 2004, averaging 1800 boe/d, and exiting 2005 at greater than 2000
boe/d. Our balance sheet is in good shape and we have a well defined, balanced
growth strategy.
I would like to thank our staff for their commitment and hard work. Our
board of directors has been diligent on behalf of our shareholders and we are
grateful to them for their wisdom and advice. Finally, thank you to our
shareholders for your support. I encourage you to watch us closely as we are
"stepping it up"!
"signed"
Robert D. Steele
Chief Executive Officer
Reserves
Berens' oil and gas reserves were independently evaluated by Gilbert
Laustsen Jung Associated Ltd. ("GLJ"). The evaluation was completed using the
reserve definitions in the Canadian Oil and Gas Evaluation Handbook and the
Canadian Securities Administrators National Instrument 51-101 ("NI 51-101").
The effective date of the following reserves is December 31, 2004.
The following tables summarize the oil and gas reserves and their net
present value based on various discount rates. When information is presented
on a barrel of oil equivalent ("boe") basis, natural gas is converted to oil
in the ratio of six thousand cubic feet of natural gas to one barrel of oil (6
Mcf:1 bbl). Boe's may be misleading, particularly is used in isolation. A boe
conversion ratio of six mcf of natural gas to one barrel of 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.
SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2004
FORECAST PRICES AND COSTS
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RESERVES
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LIGHT AND
MEDIUM OIL HEAVY OIL NATURAL GAS
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RESERVES Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
CATEGORY (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mcf) (Mcf)
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PROVED
Developed
Producing 45 43 127 113 6,778 5,261
Developed
Non-Producing 0 0 0 0 1,719 1,288
Undeveloped 0 0 0 0 0 0
TOTAL PROVED 45 43 127 113 8,497 6,549
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PROBABLE 7 7 37 30 3,345 2,600
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TOTAL PROVED
PLUS PROBABLE 53 49 163 144 11,841 9,148
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RESERVES
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NATURAL GAS Oil Equivalent
LIQUIDS (Mboe)
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RESERVES Gross(1) Net(2) Gross(1) Net(2)
CATEGORY (Mbbl) (Mbbl) (Mboe) (Mboe)
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PROVED
Developed
Producing 52 36 1,353 1,069
Developed
Non-Producing 0 0 286 215
Undeveloped 0 0 0 0
TOTAL PROVED 52 36 1,640 1,284
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PROBABLE 10 7 611 477
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TOTAL PROVED
PLUS PROBABLE 61 43 2,251 1,761
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(1) "Gross Reserves" include total company interest reserves before the
deduction of royalties.
(2) "Net Reserves" include total company interest reserves after royalty
deductions plus royalty interest reserves.
NET PRESENT VALUES OF FUTURE NET REVENUE
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BEFORE INCOME TAXES
DISCOUNTED AT (%)
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RESERVES 0 5 8 10 12 15 20
CATEGORY (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)
PROVED
Developed
Producing 26,211 24,072 23,007 22,368 21,776 20,966 19,786
Developed
Non-Producing 5,168 4,715 4,497 4,367 4,247 4,083 3,843
Undeveloped - - - - - - -
TOTAL PROVED 31,379 28,788 27,504 26,735 26,023 25,049 23,629
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PROBABLE 11,022 9,288 8,483 8,016 7,596 7,038 6,260
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TOTAL PROVED
PLUS PROBABLE 42,401 38,076 35,987 34,751 33,619 32,087 29,889
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AFTER INCOME TAXES
DISCOUNTED AT (%)
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RESERVES 0 5 8 10 12 15 20
CATEGORY (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)
PROVED
Developed
Producing 26,211 24,072 23,007 22,368 21,776 20,966 19,786
Developed
Non-Producing 5,168 4,716 4,497 4,367 4,247 4,083 3,843
Undeveloped - - - - - - -
TOTAL PROVED 31,379 28,788 27,504 26,735 26,023 25,049 23,629
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PROBABLE 9,145 7,678 7,009 6,624 6,280 5,825 5,196
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TOTAL PROVED
PLUS PROBABLE 40,524 36,466 34,513 33,359 32,303 30,874 28,825
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The forecasted prices used by GLJ to create the net present values of
future net revenue are as follows:
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
as of December 31, 2004
FORECAST PRICES AND COSTS
(in then current dollars)
PRICES AS FORECASTED BY GILBERT LAUSTSEN JUNG ASSOCIATES LTD.
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OIL
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Edmonton Hardisty Cromer
Par Price Heavy Medium
WTI Cushing 40 degrees 12 degrees 29.3 degrees
Oklahoma API API API
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl)
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Historical
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2000 30.22 44.56 27.34 39.91
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2001 25.97 39.40 16.94 31.56
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2002 26.08 40.33 26.57 35.48
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2003 31.07 43.66 26.26 37.55
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2004 41.38 52.96 29.11 45.75
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Forecast
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2005 42.00 50.25 27.50 43.75
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2006 40.00 47.75 28.50 41.50
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2007 38.00 45.50 28.75 39.50
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2008 36.00 43.25 27.25 37.75
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2009 34.00 40.75 25.50 35.50
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2010 33.00 39.50 24.75 34.25
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2011 33.00 39.50 24.75 34.25
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2012 33.00 39.50 24.75 34.25
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2013 33.50 40.00 24.75 34.75
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2014 34.00 40.75 25.50 35.50
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2015 34.50 41.25 25.75 36.00
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Thereafter +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr
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NATURAL GAS
LIQUIDS
(propane
NATURAL GAS & butane) INFLATION EXCHANGE
AECO Gas Price Field Gate RATES RATE
Year ($Cdn/MMBtu) ($Cdn/bbl) %/Year ($US/Cdn)
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Historical
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2000 5.08 33.89 2.7 0.673
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2001 6.21 31.51 2.6 0.646
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2002 4.04 24.23 2.2 0.637
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2003 6.66 33.25 2.8 0.721
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2004 6.88 37.79 1.9 0.769
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Forecast
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2005 6.60 34.75 2.0 0.820
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2006 6.35 32.88 2.0 0.820
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2007 6.15 31.38 2.0 0.820
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2008 6.00 29.88 2.0 0.820
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2009 6.00 28.13 2.0 0.820
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2010 6.00 27.25 2.0 0.820
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2011 6.00 27.25 2.0 0.820
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2012 6.00 27.25 2.0 0.820
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2013 6.10 27.50 2.0 0.820
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2014 6.20 28.13 2.0 0.820
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2015 6.30 28.50 2.0 0.820
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Thereafter +2.0%/yr +2.0%/yr 2.0 0.820
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Reserves Reconciliation
Berens' reserve additions in 2004 came primarily from drilling in its
core Lanfine area. No acquisitions were completed in 2004. Revisions to
opening reserves relate primarily to the reserves acquired with the two
corporate acquisitions completed in 2003. In particular, two wells that were
performing strongly at the time of the acquisitions and another well put on
production in December 2003 declined more rapidly than expected in 2004,
accounting for 50 percent of the proved plus probable reserve revision.
Capital spending of $16.2 million was directed at exploration and
development while another 3.4 million was spent on land during 2004. The
reserves continuity reflecting the additions from capital spending, revisions
to opening estimates and production is outlined in the following table:
RECONCILIATION OF
COMPANY INTEREST RESERVES
BY BARREL OF OIL EQUIVALENT
FORECAST PRICES AND COSTS
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BOE
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Proved
Plus
Proved Probable
FACTORS (Mboe) (Mboe)
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December 31, 2003 1,395 1,835
Drilling extensions 206 272
Improved Recovery 0 0
Technical Revisions (379) (610)
Discoveries 885 1,221
Acquisitions 0 0
Dispositions 0 0
Economic Factors 0 0
Production (467) (467)
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December 31, 2004 1,640 2,251
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Finding and Development Costs
Finding and development costs for Berens exploration and development
activities for 2004 are outlined below. The aggregate of the exploration and
development costs incurred in the most recent financial year and the change
during that year in estimated future development costs generally will not
reflect finding and development costs related to reserve additions for that
year.
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Total capital for exploration and development ($000's) 16,230
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Future development capital - proved ($000's) 260
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Future development capital - proved plus probable ($000's) 346
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Reserve extensions and discoveries - proved (Mboe)(1) 1,091
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Reserve extensions and discoveries -
proved plus probable (Mboe)(1) 1,493
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Finding and development costs - proved (per boe)(1) $15.11
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Finding and development costs -
proved plus probable (per boe)(1) $11.10
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(1) Excludes revisions on reserves acquired with corporate acquisitions
in 2003.
Berens Energy Ltd.
Management's Discussion and Analysis ("MD&A")
April 10, 2005
OVERVIEW
Berens Energy Ltd. ("Berens") is a full cycle oil and natural gas
exploration and production company with a concentrated production and land
base in Eastern Alberta approximately 300 kilometers east of the City of
Calgary with new opportunities established north west of Edmonton.
The Company completed a reorganization and major change in the business
of Berens in 2003 which saw the Company exit technology research and
development and enter the oil and natural gas exploration and production
business with its first acquisition in November 2003. As a result of the
reorganization and the late entry into the oil and gas business in 2003, year
over year comparisons of revenue and expense as well as balance sheet items
offer limited insight into our operations. The following discussion will focus
on current activities and account balances to provide a description of the oil
and natural gas asset platform that has been assembled by Berens.
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 audited financial statements and
related notes for the three and twelve month periods ended December 31, 2004
and the audited consolidated financial statements for the year ended
December 31, 2003 and the related MD&A. This MD&A was prepared using
information that is current as of April 10, 2005 unless otherwise noted.
FORWARD LOOKING INFORMATION
This MD&A contains forward looking or outlook information within the
meaning of applicable securities laws. Forward looking statements may include
estimates, plans, expectations, forecasts, guidance or other statements that
are not statements of fact. Berens believes the expectations reflected in such
forward looking statements are reasonable. However no assurance can be given
that such expectations will prove to be correct. These statements are subject
to certain risks and uncertainties and may be based on assumptions that could
cause actual results to differ materially from those anticipated or implied in
the forward looking statements. These risks include, but are not limited to:
crude oil and natural gas price volatility, exchange rate and interest rate
fluctuations, availability of services and supplies, market competition,
uncertainties in the estimates of reserves, the timing of development
expenditures, production levels and the timing of achieving such levels, the
Company's ability to replace and increase oil and gas reserves, the sources
and adequacy of funding for capital investments, future growth prospects and
current and expected financial requirements of the Company, the cost of future
dismantlement and site restoration, the Company's ability to enter into or
renew leases, the Company's ability to secure adequate product transportation,
changes in environmental and other regulations and general economic
conditions. These statements are as of the date of this MD&A and the Company
does not undertake an obligation to update its forward looking statements
except as required by law.
Additional information on the Company can be found on the SEDAR website
at www.sedar.com.
QUARTERLY INFORMATION
The Company became a reporting issuer on November 26, 2003. Prior to that
time, it was a private company involved in a business completely unrelated to
the oil and gas business.
2004
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($000's except as noted) Full Year Q4 Q3 Q2 Q1
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Sales volumes:
Natural gas (mcf
per day) 6,165 7,089 5,310 6,326 5,936
Oil and natural gas
liquids (barrels
per day) 255 240 238 292 257
Barrels of oil
equivalent (boe per
day - 6:1) 1,283 1,422 1,123 1,347 1,247
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Financial:
Net revenue 14,166 3,623 3,188 4,117 3,237
Net income (loss) (1,766) (1,652) (512) 335 63
per share - basic $(0.04) $(0.04) $(0.01) $0.01 $0.00
per share - diluted $(0.04) $(0.04) $(0.01) $0.01 $0.00
Capital costs 20,000 6,932 5,564 4,732 2,827
Shares outstanding 46,427 46,427 43,427 43,427 43,427
Bank debt 4,500 4,500 4,250 100 -
Working capital
(deficit) -
including bank debt (6,461) (6,461) (5,973) (1,851) 329
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Per unit information:
Natural gas price
($ per mcf) $6.34 $6.21 $6.16 $6.76 $6.22
Oil and liquids price
($ per barrel) $33.54 $31.88 $40.02 $32.52 $29.85
Oil equivalent price
($ per boe) $36.68 $36.93 $37.41 $38.03 $35.62
Operating netback
($ per boe) $20.00 $18.96 $19.86 $24.87 $20.63
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Net wells drilled:
Natural gas 21 (18.7 net) 11 5 3 2
Oil 2 (1.5 net) 1 1 - -
Dry 1 (1.0 net) - 1 - -
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Total 24 (21.2 net) 12 7 3 2
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RESULTS OF OPERATIONS
Production Volume
Volume averaged 1,422 boe/d for the final three months of 2004, 83
percent of which was natural gas. The remaining 17 percent of production was
conventional heavy oil and natural gas liquids. The fourth quarter production
average was up 27 percent over the third quarter, bringing the full year 2004
average production to 1,283 boe/d. A successful drilling program in the third
and fourth quarter of 2004 contributed the strong quarter-over-quarter
increase. The fourth quarter volumes included the Company's initial production
from west central Alberta from a natural gas well put on production in
November 2004, contributing over 100 boe/d in the latter part of the year.
At the end of the third quarter, management estimated that 2004 exit
production rates would be 1,600 boe/d. In fact, the average production rate
for the month of December 2004 was 1,765 boe/d, 88 percent of which was
natural gas.
Production Revenue
Natural gas prices averaged $6.21 per mcf for the final three months and
$6.34 for the full year 2004. Despite strong West Texas Intermediate oil
prices, the Company's oil and liquids prices were weak in the fourth quarter
as light/heavy pricing spreads widened considerably due to a lack of demand
for heavy oil. This brought the fourth quarter average price to $31.88
compared to $40.02 in the third quarter, bringing the full year average oil
and liquids price to $33.54 per barrel. Transportation costs have been netted
from revenue and have not been separately disclosed. Management estimates
transportation costs to be approximately 1.5 percent of total revenues.
Comparing the fourth quarter of 2004 to the third quarter, revenue
increased 25 percent as production volumes increased 27 percent while average
per boe prices were lower by two percent. Berens does not have any of its
production hedged.
Royalties
Royalties averaged 19 percent for 2004, net of Alberta Royalty Tax Credit
(ARTC). Excluding ARTC, royalty rates averaged 22 percent. Fourth quarter 2004
royalty rates averaged 25 percent as all ARTC was fully recorded by the end of
the third quarter. Fourth quarter royalty rates were also higher as the
Company put a number of higher rate natural gas wells on stream that attracted
higher royalties. The Alberta sliding scale royalty rate system causes higher
royalties to be paid on highly productive wells. Total royalties for the
fourth quarter were $1.20 million compared to $0.68 million in the third
quarter.
Interest Income
Interest income declined in 2004 compared to 2003 due to lower cash
reserves as funds were used on technology research in early 2003, the cash
spent on the Resolution acquisition in November 2003 and the capital program
in 2004.
Production Expenses
Production expenses averaged $8.75 per boe in the final three months of
2004 and $8.96 per boe for the full year. Management views production expenses
at these levels to be high and has been focusing on strategies to reduce per
boe costs. These strategies combined with production volume increases are
expected to reduce Berens' per boe costs on a go forward basis. December 2004
costs were $8.12 per boe despite added costs typically experienced during cold
weather months such as costs for thawing frozen pipelines and snow removal.
General and Administrative Expenses
General and administrative costs totaled $2.4 million for the full year
2004 and $0.6 million for the final quarter of the year. Fourth quarter
general and administrative costs were six percent higher compared to the third
quarter. Costs in the last half of 2004 were only 45 percent of the annual
total. This was despite a higher staff contingent in the second half of the
year. The first half of 2004 had added costs for new administrative systems
for land, accounting, corporate governance, regulatory reporting and health
and safety. On a per barrel basis, general and administrative costs were $5.08
for the year ended December 31, 2004. In the final quarter of 2004 general and
administrative costs had declined to $3.99 per boe. Berens did not capitalize
any general and administrative costs in the quarter or year to date.
Interest Expense
Interest expense was incurred for the first time in the second and third
quarter of 2004 as the Company began to utilize its bank operating line to
fund capital costs in amounts greater than cash flow and the cash on hand at
the beginning of 2004.
Netback
Operating netback represents the profit margin realized by the production
and sale of petroleum and natural gas.
2004
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Quarterly Netbacks ($'s per boe) Q4 Q3 Q2 Q1
Sales price 36.93 37.41 38.03 35.62
Less:
Royalties (net of ARTC) 9.22 6.56 5.59 7.10
Production expenses 8.75 10.99 7.57 7.89
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Operating netback 18.96 19.86 24.87 20.63
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Depletion, Amortization and Accretion
Depletion, amortization and accretion in 2004 totaled $9.2 million or
$19.58 per boe. Fourth quarter 2004 depletion was $3.5 million. This was
significantly higher than prior quarters as negative revisions from the year-
end independent petroleum consultants reserve report caused the Company to
record additional depletion to reflect the lower proved reserve base.
Depletion rates are expected to decline as wells are completed, reserves
recognized and additional wells are drilled with finding and on stream costs
below the current depletion rate per boe. Reserve added in calendar year 2004
were put on stream at a proved finding and development cost of $15.11 per boe.
Development Expenses
Development expenses which were incurred in 2003 were costs related to
the electrical storage research and development which efforts were
discontinued in May 2003 as part of the restructuring.
Income Taxes
Cash income taxes of $104,000 were booked in 2004 on final calculation of
2003 income tax returns for Resolution, Matrix and Berens. The remaining cash
taxes recorded for the year ended December 31, 2004 were capital taxes. The
Company does not expect to be cash taxable for 2004 or 2005 as there are ample
loss carry forwards and capital pools to shelter taxable income.
NET LOSS
Net loss for 2004 was $1,766,000 ($(0.04) per share). The fourth quarter
loss was $1,652,000 ($(0.04) per share) compared to a loss of $512,000 in the
third quarter. The losses reflect the large depletion charge in the last
quarter of 2004.
CAPITAL COSTS
Total capital costs were $20 million in 2004 and $6.9 million in the
fourth quarter, broken down as follows:
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Fourth
($000's) Full year quarter
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Drilling and completion 14,274 5,751
Land 3,442 902
Geological and geophysical 1,958 146
Office and other 326 133
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Total 20,000 6,932
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WORKING CAPITAL
Accounts receivable of $3.4 million at December 31, 2004 are made up
primarily of November and December production revenues. Accounts payable at
December 31, 2004 were $5.8 million was comprised mainly of trade payables for
operating and capital commitments totaling $3.5 million, as well as end of
year accruals for in-progress capital programs of $1.5 million as the Company
was drilling through the end of the year in both eastern and west central
Alberta.
Berens' cash flows, and a fourth quarter equity financing for a net
amount of $4.6 million, were adequate to cover an active capital program in
the fourth quarter. The operating bank line of credit grew marginally from
$4.25 million by the end of the third quarter to $4.5 million at December 31,
2004. Excluding the bank line, working capital was in a deficit position of
$2.0, up from $1.7 million at the end of the third quarter. It is expected
that the working capital deficiency will be addressed by draws on the bank
line in the short term and longer term by increased operating revenue
resulting from the capital spending program.
LIQUIDITY AND CAPITAL RESOURCES
Berens completed a flow through common share issue in December 2004 for
gross proceeds of $4.83 million. The Company issued 3.0 million shares
representing seven percent of the existing shares outstanding at a price of
$1.61. This represented a 25 percent flow-through premium over the market
price of the common shares at the time of pricing. The purpose of the small
financing was to ensure adequate financial capacity to carry out a growth-
oriented capital program for 2005.
Berens currently plans to fund its operations and capital expenditures
with a mix of cash flow and debt financing through bank operating lines.
Berens has an operating bank line for a total of $11.0 million secured by
Berens' production properties. This bank line combined with budgeted cash flow
for the remainder of 2005 is expected to fund the capital program budgeted for
2005. Management will consider equity financings from time to time to ensure
adequate financial flexibility to pursue growth opportunities.
NON-GAAP MEASUREMENTS
This MD&A contains the term "cash flow from operations". As an indicator
of the Company's performance, this term should not be considered an
alternative to, or more meaningful than "cash flow from operating activities"
or "net income (loss)" as determined in accordance with Canadian generally
accepted accounting principles. The Company's determination of cash flow from
operations may not be comparable to that reported by other companies,
especially those in other industries. Management feels that cash flow from
operations is a useful measure to help investors assess whether the Company is
generating adequate cash amounts from its operations to fund its ongoing
operations and planned capital program.
The reconciliation between net income and cash flow from operations for
the three months and one year periods ended December 31, 2004 is as follows.
-------------------------------------------------------------------------
Three months Year
ended ended
($000's) December 31 December 31
-------------------------------------------------------------------------
Net loss (1,652) (1,766)
Items not requiring cash:
Depletion, amortization and accretion 3,453 9,169
Stock based compensation 63 202
-------------------------------------------------------------------------
Cash flow from operations 1,864 7,605
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The Company also presents cash flow from operations per share consistent
with the calculation of earnings per share, whereby per share amounts are
calculated using weighted average shares outstanding. Cash flow from
operations per share for the year ended December 31, 2004 was $0.17 (basic and
diluted). Third quarter 2004 cash flow from operations was $0.04 per share
(basic and diluted).
The Company has no long-term contractual obligations other than office
rent and vehicle leases.
The Company has no off-balance sheet arrangements.
The company has no commodity price or interest rate hedges or fixed price
contracts in place.
RISKS
The Company's primary financial risks relate to variability in commodity
prices. Interest rate and currency exchange rate variability also have 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 is often much greater than can be
explained by currency variability.
Based on the Company's plans for 2005 the following sensitivities are
illustrated for key financial factors:
-------------------------------------------------------------------------
Cash Flow
from
Earnings Operations
Sensitivity (000's) Effect Effect
-------------------------------------------------------------------------
Natural gas price - Cdn$0.10 per mcf $182 $285
-------------------------------------------------------------------------
Oil price - Cdn$1.00 per bbl $40 $63
-------------------------------------------------------------------------
Interest rate - 1 percentage point $54 $85
-------------------------------------------------------------------------
Exchange rate - Cdn$0.01 $236 $368
-------------------------------------------------------------------------
Other risks that the Company is exposed to are related to our operations.
They include exploration risks and risks related to safety and environment.
Exploration risk is managed by a thorough analysis to ensure the Company is
exposed to a balanced risk profile of both low risk and higher risk drilling
prospects. The Company also has complete, documented environmental health and
safety plans as well as a comprehensive emergency response plan to mitigate
operating risks.
RELATED PARTY TRANSACTIONS
The Company contracts a recruiting consulting firm in which one of its
directors is the chairman. The executive services rendered are in the normal
course of business and are at normal rates charged by the consulting firm.
SHARE DATA
As of the date of this MD&A the Company had 46,427,469 issued and
outstanding common shares. Additionally, the Company has issued options to
purchase 2,784,500 common shares.
CHANGES IN ACCOUNTING POLICIES AND INITIAL ADOPTION OF ACCOUNTING
POLICIES
Effective January 1, 2004, the Company prospectively adopted the Canadian
Institute of Chartered Accountants Accounting Guideline 16 on Full Cost
Accounting for Oil and Gas Companies. In applying the new full cost guideline,
the Company calculates its ceiling test by comparing the carrying amount of
petroleum and natural gas properties to the sum of undiscounted cash flows
expected to result from the future production of proved reserves and the cost
of unproved properties. Should the ceiling test result in an excess carrying
amount, the Company would then measure the amount of impairment by comparing
the carrying amounts an amount equal to the estimated net present value of
future cash flows from proved plus probable reserves using forecast prices and
costs and costs of unproved properties. Any excess would be recorded as an
impairment and charged to earnings in the period. The adoption of this
guideline had no effect on current or prior year financial statements.
OUTLOOK
Berens' strong land position should enable the Company to continue to add
value with the drill bit. The capital program at Lanfine is well defined as
there is sufficient undeveloped acreage in the area for one and one half to
two years of planned drilling. Management's stated objective has been to
expand with the creation two to four additional production areas generally
moving to the west central and western regions of Alberta. Good progress on
the expansion to the west was made in 2004 with initial land positions and
production established. Berens is actively developing drilling prospects on
the land we have acquired in 2004 and early 2005 with at least four wells
planned in the second and third quarters of 2005 and potential significant
drilling to take place in the winter of 2005/06.
Berens has set a $20 million 2005 capital program that is projected to
yield production growth of approximately 44 percent over 2004, averaging 1800
boe/day, and exiting 2005 greater than 2000 boe/day. The capital program is
split 60 percent toward eastern Alberta and 40 percent to new growth areas in
west central and western Alberta. Company debt levels are low entering 2005
and we have a well defined, balanced growth strategy that delivers low risk
drilling in eastern Alberta combined with higher impact, deeper drilling
opportunities in west central Alberta.
Berens Energy Ltd.
Balance Sheets
As at December 31,
-------------------------------------------------------------------------
(000's) 2004 2003
-------------------------------------------------------------------------
ASSETS
Current
Cash and cash equivalents $ 35 $ 4,022
Accounts receivable 3,365 2,397
Prepaid expenses and deposits 492 253
-------------------------------------------------------------------------
3,892 6,672
Investments 299 299
Capital assets (note 4 & 8) 38,811 27,932
Goodwill 14,805 14,666
-------------------------------------------------------------------------
$ 57,807 $ 49,569
-------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Bank loan (note 8) $ 4,500 $ -
Accounts payable and accrued liabilities 5,795 4,467
Taxes payable 58 817
-------------------------------------------------------------------------
10,353 5,284
Asset retirement obligation (note 5) 648 397
-------------------------------------------------------------------------
11,001 5,681
Shareholders' equity
Capital stock (note 6) 48,331 56,793
Contributed surplus (note 6) 241 39
Deficit (1,766) (12,944)
-------------------------------------------------------------------------
46,806 43,888
-------------------------------------------------------------------------
$ 57,807 $ 49,569
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the financial statements
Berens Energy Ltd.
Statements of Operations and Deficit
For the periods ended December 31,
-------------------------------------------------------------------------
(000's) Three months ended Year ended
December 31, December 31,
-------------------------------------------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------
Revenue
Oil and natural gas revenue $ 4,829 - $ 17,539 -
Royalties, net of ARTC (1,206) - (3,373) -
-------------------------------------------------------------------------
3,623 $ 1,192 14,166 1,192
Interest - 62 17 $ 259
-------------------------------------------------------------------------
3,623 1,254 14,183 1,451
Expenses
Production 1,152 459 4,110 459
Depletion and amortization 3,453 675 9,169 727
General and administrative 489 791 2,183 1,907
Stock based compensation 63 39 202 39
Interest expense 60 22 123 -
Foreign currency translation
loss - - - 22
Research and development - 220 - 2,390
-------------------------------------------------------------------------
5,217 2,206 15,787 5,544
-------------------------------------------------------------------------
Loss before income taxes (1,594) (952) (1,604) (4,093)
Income tax expense 58 8 162 9
-------------------------------------------------------------------------
Net loss for the period (1,652) (960) (1,766) (4,102)
Retained earnings (deficit),
beginning of period (114) (11,984) (12,944) (11,933)
Reduction of stated capital
(note 6) - - 12,944 -
-------------------------------------------------------------------------
Reduction of capital on
reorganization - - - 3,091
-------------------------------------------------------------------------
Deficit, end of period $ (1,766) $(12,944) $ (1,766) $(12,944)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net loss per share (note 9)
Basic and diluted $(0.04) $(0.04) $(0.04) $(0.23)
-------------------------------------------------------------------------
See accompanying notes to the financial statements
Berens Energy Ltd.
Statements of Cash Flows
For the periods ended December 31,
-------------------------------------------------------------------------
(000's) Three months ended Year ended
December 31, December 31,
-------------------------------------------------------------------------
2004 2003 2004 2003
-------------------------------------------------------------------------
OPERATING ACTIVITIES
Net loss for the period $ (1,652) $ (960) $ (1,766) $ (4,102)
Add items not involving cash
Depletion and amortization 3,453 675 9,169 727
Stock-based compensation 63 39 202 39
-------------------------------------------------------------------------
1,864 (246) 7,605 (3,336)
Change in non-cash working
capital items (note 7) 742 (1,005) 546 (1,293)
-------------------------------------------------------------------------
2,606 (1,251) 8,151 (4,629)
-------------------------------------------------------------------------
FINANCING ACTIVITIES
Change in bank loan 250 - 4,500 -
Proceed from the exercise
of warrants - 5,612 - 5,612
Net proceed from private
offerings 4,460 788 4,460 788
Proceeds from the exercise
of stock options - 17 22 17
-------------------------------------------------------------------------
4,710 6,417 8,982 6,417
-------------------------------------------------------------------------
INVESTING ACTIVITIES
Purchase of property and
equipment (6,813) (926) (19,936) (1,149)
Cash component of Resolution
purchase - (11,628) - (11,628)
Net cash acquired on Matrix
purchase - 3,522 - 3,522
Purchase of long-term investment - (41) - (41)
Change in non-cash working
capital items (note 7) (511) - (1,184) (336)
-------------------------------------------------------------------------
(7,324) (9,073) (21,120) (9,632)
-------------------------------------------------------------------------
Decrease in cash and cash
equivalents (8) (3,907) (3,987) (7,844)
Cash and cash equivalents,
beginning of period 43 7,929 4,022 11,866
-------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 35 $ 4,022 $ 35 $ 4,022
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the financial statements
BERENS ENERGY LTD.
Notes to Financial Statements
Three months and year ended December 31, 2004 and 2003
(all amounts in thousands except for share and per share amounts and
where indicated)
1. NATURE OF OPERATIONS
Having completed two oil and natural gas corporate acquisitions late in
2003, the Company has become a full cycle oil and natural gas exploration
and production company with activities encompassing land acquisition,
geological and geophysical assessment, drilling and completion, and
production. The Company's primary areas of operation are in eastern and
west central Alberta.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The interim financial statements of the Company have been prepared by
management following the same accounting policies as the most recent
annual audited financial statements except as discussed below.
Certain disclosures, which are normally required to be included in notes
to the annual financial statements, are condensed or omitted for interim
reporting. Accordingly, the interim financial statements should be read
in conjunction with the Company's audited annual financial statements for
the year ended December 31, 2004.
3. CHANGE IN ACCOUNTING POLICIES
Effective January 1, 2004, the Company prospectively adopted the Canadian
Institute of Chartered Accountants Accounting Guideline 16 on Full Cost
Accounting for Oil and Gas Companies. In applying the new full cost
guideline, the Company calculates its ceiling test by comparing the
carrying amount of property and equipment to the sum of undiscounted cash
flows expected to result from the future production of proved reserves
and the cost of unproved properties. Cash flows are estimated using
forecast prices and costs. Should the ceiling test result in an excess
carrying value, the Company would then measure the amount of impairment
by comparing the carrying amounts of property and equipment to an amount
equal to the estimated net present value of future cash flows from proved
plus probable reserves using forecast prices and costs and unproved
properties. Any excess would be recorded as an impairment and charged to
earnings in the period.
There was no effect on current or prior year financial statements as a
result of the adoption of this guideline.
4. CAPITAL ASSETS
December 31,
-------------------------------------------------------------------------
(000's) 2004 2003
Accumulated Accumulated
depletion and depletion and
Cost amortization Cost amortization
$ $ $ $
-------------------------------------------------------------------------
Petroleum and natural
gas properties 48,394 9,757 28,516 674
Office and computer equipment 232 57 109 19
-------------------------------------------------------------------------
48,626 9,814 28,625 693
-------------------------------------------------------------------------
Net book value 38,811 27,932
-------------------------------------------------------------------------
-------------------------------------------------------------------------
At December 31, 2004, costs of $7,220 related to undeveloped land have
been excluded from the depletion calculation (2003 - $6,965).
5. ASSET RETIREMENT OBLIGATIONs
The total future asset retirement obligation was estimated by management
based on the Company's net ownership interest in all wells and
facilities, estimated costs to reclaim and abandon the wells and
facilities and the estimated timing of the costs to be incurred in future
periods.
The following table reconciles the Company's asset retirement obligation
as follows:
(000's) $
-------------------------------------------------------------------------
Obligation, December 31, 2003 397
Increase in obligation during the period 203
Accretion expense 48
-------------------------------------------------------------------------
Obligation, December 31, 2004 648
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The total undiscounted obligation for asset retirement is $2,155 as at
December 31, 2004. The Company uses a credit adjusted risk free rate of
12 percent and an inflation rate of 1 1/2 percent to calculate the
present value of the asset retirement obligations. These payments are
expected to be made over the next 5 to 15 years.
6. CAPITAL STOCK
(a) Authorized Capital
The authorized capital of the Company consists of an unlimited number of
preferred shares issuable in series and an unlimited number of common
shares without nominal or par value.
(b) Common shares issued
-------------------------------------------------------------------------
Balance, December 31, 2002 19,133,000 $ 23,578
Relinquishment of exchangeable shares pursuant
to May 15, 2003 reorganization (7,734,000) (5)
Distribution of Plurion Systems Limited
investment in Plurion Systems, Inc. pursuant
to May 15, 2003 reorganization - recorded as
a return of capital - (3,357)
Stock options exercised during the year 16,667 17
Exercise of warrants for cash 5,612,263 5,612
Private placement for cash 787,737 788
Shares issued on arrangement with Resolution 15,865,453 15,865
Shares issued on acquisition of Matrix 9,724,682 14,295
-------------------------------------------------------------------------
Balance December 31, 2003 43,405,802 $ 56,793
Stock options exercised during the year 21,667 21
Reduction of contributed surplus for options
exercised - 1
Private placement for cash 3,000,000 4,564
Reduction of stated capital - (12,944)
Share issue costs - (104)
-------------------------------------------------------------------------
Balance December 31, 2004 46,427,469 $ 48,331
-------------------------------------------------------------------------
Issue of Warrants
Pursuant to the May 15, 2003 reorganization, the Company issued 5,699,500
warrants to purchase one common share for each warrant at a price of
$1.00 per share. The warrants expired on the earlier of May 15, 2005 or
the date of the next equity financing completed by the Company after May
15, 2003. The warrants were triggered by an equity financing that closed
on November 7, 2003 resulting in the issue of 5,612,263 common shares.
There are no warrants outstanding as of December 31, 2004.
Private Placements
The Company issued 3,000,000 flow-through common shares on December 9,
2004 in a private placement at $1.61 per share for cash proceeds of
$4,830 before agent's commission of $266 to finance certain oil and gas
expenditures to be incurred in 2005. The renouncement of these
expenditures will be made to the purchasers of these shares in 2005.
At the time of the warrant financing on November 7, 2003, the Company
issued 787,737 additional shares in a private placement to the Company's
management and directors at $1.00 per share for total proceeds of $788.
No transaction costs were incurred on this issuance.
(c) Stock Option Plan
The Company has a stock option plan under which 4,000,000 common shares
have been reserved for options to be distributed to directors, officers,
employees and consultants to the Company with terms established by the
board of directors.
Options granted under the plan generally have a five year term to expiry
and vest equally over a three year period commencing on the first
anniversary date of the grant. The exercise price of each option equals
the closing market price of the Company's common shares on the day prior
to the date of the grant. Options issued prior to the Company trading
publicly were issued at either $2.75 per share or $1.00 per share. On
June 25, 2003 the Berens directors approved a reduction to the exercise
price of all outstanding options at that time to $1.00 per common share.
The following table sets forth a reconciliation of the plan activity
through December 31, 2004.
2004 2003
Weighted Weighted
average average
Number of exercise price Number of exercise price
Options ($ per share) Options ($ per share)
-------------------------------------------------------------------------
Outstanding,
beginning
of year 1,590,000 1.11 640,000 1.00
Granted 1,467,000 1.37 1,350,000 1.13
Cancelled (250,833) 1.43 (383,333) 1.00
Exercised (21,667) 1.00 (16,667) 1.00
-------------------------------------------------------------------------
Outstanding,
end of year 2,784,500 1.22 1,590,000 1.11
-------------------------------------------------------------------------
Exercisable 536,662 1.07 96,667 1.00
-------------------------------------------------------------------------
The following table sets forth additional information relating to the
stock options outstanding at December 31, 2004.
Options Outstanding Exercisable Options
-------------------------------------------------------------------------
Weighted Weighted
average average
exercise Weighted exercise Weighted
price average price average
Exercise price Number of ($ per years to Number of ($ per years to
range Options share) expiry Options share) expiry
-------------------------------------------------------------------------
$1.00 to $1.10 1,220,000 1.00 3.31 481,662 1.00 3.18
-------------------------------------------------------------------------
$1.11 to $1.20 502,500 1.16 4.96 - - -
-------------------------------------------------------------------------
$1.21 to $1.30 152,000 1.27 4.83 - - -
-------------------------------------------------------------------------
$1.31 to $1.40 307,500 1.39 4.52 - - -
-------------------------------------------------------------------------
$1.41 to $1.50 197,500 1.47 4.21 - - -
-------------------------------------------------------------------------
$1.51 to $1.60 - - - - - -
-------------------------------------------------------------------------
$1.61 to $1.70 405,000 1.70 3.99 55,000 1.70 3.92
-------------------------------------------------------------------------
$1.00 to $1.70 2,784,500 1.22 3.99 536,662 1.07 3.26
-------------------------------------------------------------------------
The Company has adopted the fair value method for measuring option awards
beginning on January 1, 2003. Based on the fair value method, $39 was
recorded as compensation expense in 2003 for options issued and re-priced
during the year with a corresponding increase recorded to contributed
surplus. Key assumptions used for the Black Scholes-based valuation of
issued and re-priced options were: Risk free rate - 4.00 percent; average
expected life - 4.5 years; no expected dividend yield; 1 percent
volatility was assumed as the Company's shares were not publicly traded
at the time of the option grants and no meaningful volatility measure was
possible. For 2004 calculations the key assumptions used for the Black
Scholes-based valuation of issued options were: Risk free rate - 4.00
percent; average expected life - 4.5 years; no expected dividend yield;
42 percent volatility. The Company has not incorporated an estimated
future forfeiture assumption in its calculations, and will recognize
forfeitures as they occur. Based on the fair value method, $202 was
recorded as compensation expense in 2004 for options issued during the
year with a corresponding increase recorded to contributed surplus.
7. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in Non-cash Working Capital
For the quarters and years ended December 31,
2004 2003
Quarter Year Quarter Year
($000's) ended ended ended ended
-------------------------------------------------------------------------
Accounts receivable (1,057) (967) (2,383) (2,314)
Prepaid expenses and deposits - (239) (249) 156
Accounts payable and accrued
liabilities 1,229 1,327 4,462 3,433
Income taxes payable 58 (759) 817 813
Non-cash working capital
deficiency acquired in
acquisitions 230 (638) (3,717) (3,717)
Change in non-cash working
capital related to investing
activities 512 1,184 336 336
-------------------------------------------------------------------------
742 546 (734) (1,293)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash taxes and interest paid during the quarters and years ended
December 31,
2004 2003
Quarter Year Quarter Year
($000's) ended ended ended ended
-------------------------------------------------------------------------
Cash income and other taxes - 1,055 - 4,036
-------------------------------------------------------------------------
Cash interest paid 60 123 - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
8. BANK OPERATING LINE
Berens has an agreement with a Canadian bank for a revolving operating
line for $7.5 million. Collateral for the operating line of credit
includes a general assignment of book debts and a $35 million debenture
with a floating charge over all assets of the Company. This bank line was
increased to $11 million subsequent to year end. The bank line is a
demand line and carries an interest rate of the bank's prime rate plus
3/8th of one percent or 4.625 percent at December 31, 2004. On December
31, 2004 $4,500,000 was drawn on the bank line.
9. PER SHARE INFORMATION
The weighted average number of common shares outstanding during the year
ended December 31, 2004 of 43,868,650 (2003 - 18,059,798) was used to
calculate basic and diluted loss per share.
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