Symbol: BEN - TSX
CALGARY, March 27 /CNW/ -
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FINANCIAL AND OPERATING HIGHLIGHTS
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($ Cdn thousands, Three months
except as noted) ended December 31,
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2006 2005 % Change
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Sales volume
Natural gas (mcf/day) 18,440 11,537 60%
Oil and ngls (bbl/day) 483 176 174%
boe/day (6 to 1) 3,556 2,099 69%
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Revenue net of royalties 11,213 9,537 18%
Net income (loss) (21,951) (475)
Per share (basic and diluted) $ (0.24) $ (0.01)
Funds from operations(1) 6,118 6,827 (10%)
Per share (basic and diluted)(1) $ 0.07 $ 0.13 (46%)
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Capital costs
Exploration and development 11,112 9,198
Land and seismic 896 2,955
Other 37 193
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Total 12,045 7,165 79%
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Net wells completed (No.)
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Natural gas 7 9
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Oil - 1
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Dry 1 2
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Total 8 12
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Net working capital (deficit)
- including bank debt (55,073) 4,273
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Shares outstanding
End of period (000's) 92,947 57,163 63%
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($ Cdn thousands, Twelve months
except as noted) ended December 31,
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2006 2005 % Change
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Sales volume
Natural gas (mcf/day) 17,420 10,451 67%
Oil and ngls (bbl/day) 469 193 143%
boe/day (6 to 1) 3,373 1,935 74%
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Revenue net of royalties 40,118 27,868 44%
Net income (loss) (28,340) 504
Per share (basic and diluted) $ (0.33) $ 0.01
Funds from operations(1) 22,471 18,285 23%
Per share (basic and diluted)(1) $ 0.26 $ 0.38 (32%)
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Capital costs
Exploration and development 51,820 22,613
Land and seismic 3,583 9,522
Other 295 260
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Total 55,698 32,395 57%
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Net wells completed (No.)
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Natural gas 25 24
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Oil - 1
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Dry 4 7
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Total 29 32
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Net working capital (deficit)
- including bank debt (55,073) 4,272
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Shares outstanding
End of period (000's) 92,947 57,163 63%
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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.
Fourth Quarter 2006 Operating Highlights
- Production - Q4 2006 production averaged 3,556 boe/d, up 69 percent
over Q4 2005. Production additions in the fourth quarter of 2006 were
delivered by ongoing drilling and tie-ins in Pembina and a November
drilling program in Lanfine that was partially tied in by the end of
the year. On a full year basis volume in 2006 averaged 3,373 boe/d,
up 74 percent compared to the year ended December 31, 2005.
- Reserves - Total working interest proved plus probable reserves as at
December 31, 2006 were 7,765,000 boe comprised of 1,487,000 barrels
of oil and natural gas liquids and 37,673 million cubic feet of
natural gas. Total proved plus probable reserves grew 224 percent
from December 31, 2005 to December 31, 2006. On a per share basis
proved plus probable reserves grew 99 percent from 41.9 boe/1000
shares outstanding to 83.5 boe/1000 shares outstanding. Proved plus
probable reserves growth came equally from the exploration and
development program which added 3.3 million boe and the acquisition
of Berland Exploration Ltd. in January 2006 which added 3.3 million
boe. Berens replaced production more than 2.6 times with new proved
plus probable reserves added from the exploration and development
drilling program. Combined with the acquisition, production has been
replaced over 5.2 times with new proved plus probable reserves.
- Product Mix - The addition of liquids rich natural gas from the
Berland acquisition has changed the production mix from 92% natural
gas and 8% heavy oil in Q3 2005 to a higher value mix of 86% natural
gas, 13% natural gas liquids and only 1% heavy oil. The natural gas
produced in Pembina and the Deep Basin which combined represent 41%
of 2006 production has high BTU content and commands a premium price.
- Production Costs - Costs averaged $8.88 per boe in Q4 2006, up 8%
compared to $8.22 per boe in Q4 2005. Q4 2006 costs were burdened by
prior quarters' catch up charges from non-operated properties that
were billed during the quarter. For the 2006 year production costs
have averaged $7.89 per boe, up 2 percent compared to $7.74 in 2005.
- Funds from Operations - Funds from operations Q4 2006 was
$6.2 million ($0.07 per share) compared to Q4 2005 funds from
operations of $6.8 million ($0.13 per share). Higher production in Q4
2006 was offset primarily by weaker natural gas prices. On a per
share basis, funds from operations declined due to additional shares
issued mainly for the acquisition of Berland.
- Drilling - A total of 13 wells (8.3 net) were completed in the fourth
quarter resulting in 12 (7.7 net) natural gas wells and one (0.6 net)
unsuccessful well for a net success rate of 93 percent. In 2006, 50
(29.3 net) wells have been completed with 39 (24.9 net) natural gas
wells, 1 (0.3 net) oil well and 10 (4.1 net) unsuccessful wells for a
net success rate of 86 percent.
- Land - Berens total undeveloped land (owned and option) currently
stands at 145,000 net acres. Ninety-eight percent of the undeveloped
lands are located in the four core areas of Pembina, Deep Basin,
Lanfine and Marten Hills. The 2007 drilling program is based entirely
on existing Berens' controlled undeveloped acreage.
Message to the shareholders
As all are aware, 2006 was a very interesting year in the energy industry, particularly the natural gas business. Berens entered 2006 full of optimism due to an announced major acquisition and substantial land expansion upon which we planned to apply the drill bit to deliver long term growth for our shareholders. Natural gas prices were at all time highs and aggressive plans appeared easily managed.
The year that was...
In the course of the year, our excitement was tempered by natural gas prices that dropped significantly, high service costs that became higher, and underperformance on some of the wells from our Berland acquisition. Needless to say, a tough environment.
So what did we do at Berens? - We set about learning our way around the assets that we had acquired. - We cut our capital to make sure we were prudent in our business. - And we did our business very carefully.
Our efforts paid off
While our early 2006 drilling results were expensive and with limited success, as earlier reported, we persevered and by the 4th quarter we were successful on 12 of 13 drilling attempts. As a result, we now have a much better understanding of the technical and operating skills we need to succeed with the assets we have.
On track to deliver in 2007
We are glad that 2006 is now behind us and that the optimism of early 2006 has been rejuvenated. We have our land position and drilling plans intact and are on track to deliver with the drill bit.
We have a great team of people working promising prospects in our four core areas of Pembina, Lanfine, Deep Basin and Marten Hills. So far in 2007 we are five for five in Pembina and four for four in the Deep Basin. A fifth Deep Basin well was unsuccessful, but it was farmed out at no cost to Berens. In the Marten Hills shallow gas program we drilled four successful wells on seven attempts. Our people remain committed to succeed, and believe we have "turned the corner" and are on track for long term growth.
Industry trends
Reports of noticeably reduced activity across the western Canadian sedimentary basin give us reason to believe that costs will decrease. We have already seen limited evidence of reduced activity early in 2007 and we are noticing that services are more readily available.
The oil and gas business has the broad ability to self-correct when business factors get "out of whack" as they did in early 2006. Natural gas prices so far in 2007 have met our expectations and they appear to be more stable than we have seen in the past 12 months.
Volatility remains a reality in our business, but we are poised to respond immediately to any price weakness as we operate most of our own capital program and can adjust our spending as needed without pressure from partners.
We believe that "supply and demand" will ultimately balance in 2007. As the gas supply declines, due to the anticipated reduced drilling activity in 2007, and as demand remains stable, natural gas prices will have a tendency to react upward. These slightly higher prices along with lower service costs will foster new activity.
Berens is active in some of the best oil and gas areas in western Canada. We have skillful and dedicated staff that are committed to our success. I would like to thank our staff and management for their efforts and our board of directors for their guidance and patience through a tough year.
Most of all, I would like to thank our shareholders who have stood with us through the difficulties of 2006 and who share our optimism going forward. I am a shareholder too, as are all of our staff. We are all collectively committed to succeed.
Sincerely,
"Signed"
Robert D. Steele
Chief Executive Officer
Reserves
Berens' oil and gas reserves were independently evaluated by GLJ Petroleum Consultants ("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, 2006.
The following tables summarize the oil and gas reserves and their net present value based on various discount rates as at December 31, 2006. 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).
SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2006
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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Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
RESERVES CATEGORY (Mbbl) (Mbbl) (Mboe) (Mboe) (MMcf) (MMcf)
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PROVED
Developed
Producing 168 159 73 67 18,770 14,555
Developed
Non-Producing 21 18 9 8 4,266 3,430
Undeveloped 0 0 0 0 3,381 2,728
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TOTAL PROVED 189 177 82 75 26,417 20,713
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PROBABLE 183 169 36 33 11,256 8,931
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TOTAL PROVED
PLUS PROBABLE 372 346 118 108 37,673 29,644
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RESERVES
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NATURAL Oil Equivalent
GAS LIQUIDS (Mboe)
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Gross(1) Net(2) Gross(1) Net(2)
RESERVES CATEGORY (Mbbl) (Mbbl) (Mboe) (Mboe)
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PROVED
Developed
Producing 502 318 3,870 2,968
Developed
Non-Producing 118 79 859 678
Undeveloped 100 68 664 523
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TOTAL PROVED 720 465 5,393 4,169
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PROBABLE 277 181 2,372 1,871
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TOTAL PROVED
PLUS PROBABLE 997 646 7,765 6,040
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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 (%/year)
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RESERVES 0 5 8 10 12 15 20
CATEGORY (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)
PROVED
Developed
Producing 103,452 82,080 73,824 69,432 65,691 60,999 54,910
Developed
Non-Producing 23,327 16,912 14,977 14,013 13,210 12,215 10,918
Undeveloped 10,179 6,270 4,626 3,731 2,961 1,996 762
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TOTAL PROVED 136,958 105,263 93,427 87,176 81,862 75,210 66,590
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PROBABLE 74,819 43,979 35,174 31,073 27,864 24,173 19,881
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TOTAL PROVED
PLUS PROBABLE 211,777 149,242 128,601 118,249 109,726 99,383 86,471
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AFTER INCOME TAXES
DISCOUNTED AT (%/year)
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RESERVES 0 5 8 10 12 15 20
CATEGORY (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)
PROVED 131,087 102,525 91,565 85,705 80,684 74,347 66,053
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PROBABLE 52,920 31,758 25,747 22,949 20,758 18,234 15,282
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TOTAL PROVED
PLUS PROBABLE 184,007 134,283 117,312 108,654 101,442 92,581 81,335
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The forecasted prices used by GLJ to create the net present values of
future net revenue are as follows:
Oil
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Edmonton Cromer
WTI Par Price Medium
Cushing 40 degrees Hardisty 29.3 degrees
Oklahoma API Heavy API
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl)
--------- ---------- ---------- -----------
Historical Averages
2002 26.08 40.33 26.57 35.48
2002 31.07 43.66 26.26 37.55
2004 41.38 52.96 29.11 45.75
2005 56.58 69.11 34.07 56.62
2006 (e) 66.22 73.16 41.87 62.24
Forecast
2007 62.00 70.25 39.25 61.25
2008 60.00 68.00 40.00 59.25
2009 58.00 65.75 39.75 57.25
2010 57.00 64.50 39.75 56.00
2011 57.00 64.50 40.25 56.00
2012 57.50 65.00 41.50 56.50
2013 58.50 66.25 42.50 57.75
2014 59.75 67.75 43.50 59.00
2015 61.00 69.00 44.25 60.00
2016 62.25 70.50 45.25 61.25
2017 63.50 71.75 46.00 62.50
2018+ +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr
Natural
gas NGLs
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FOB Field
Gate
AECO-C (propane/ Inflation Exchange
Gas Price butane) rate(1)% rate(2)
Year ($Cdn/MMbtu) ($Cdn/bbl) per year ($US/Cdn)
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Historical Averages
2002 4.04 24.24 2.2 0.637
2002 6.66 33.25 2.8 0.721
2004 6.88 37.34 1.8 0.768
2005 8.58 47.42 2.2 0.825
2006 (e) 7.02 55.30 2.0 0.882
Forecast
2007 7.20 50.62 2.0 0.87
2008 7.45 46.88 2.0 0.87
2009 7.75 45.38 2.0 0.87
2010 7.80 44.50 2.0 0.87
2011 7.85 44.50 2.0 0.87
2012 8.15 44.75 2.0 0.87
2013 8.30 45.75 2.0 0.87
2014 8.50 46.75 2.0 0.87
2015 8.70 47.63 2.0 0.87
2016 8.90 48.63 2.0 0.87
2017 9.10 49.50 2.0 0.87
2018+ +2.0%/yr +2.0%/yr 2.0 0.87
Notes:
(1) Inflation rates for forecasting prices and costs.
(2) Exchange rates used by GLJ to generate the benchmark reference prices
in this table.
Reserves Reconciliation
Berens' reserve additions in 2006 came equally from its exploration and development program (3.3 million proved plus probable boe) and its acquisition of Berland Exploration Ltd. (3.3 million proved plus probable boe). Reserve revisions for 2006 were negligible as were dispositions. With the addition of significant reserves in Pembina and the Deep Basin during 2006, our reserve life index improved to 6.0, almost double the reserve life index of 3.2 years at the end of 2005.
Capital spending of $53.3 million was directed at seismic and exploration and development while another $2.5 million was spent on land during 2006. 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
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BOE
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Proved Plus
FACTORS Proved (Mboe) Probable (Mboe)
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December 31, 2005 1,664 2,396
Discoveries 390 499
Extensions 1817 2,752
Infill drilling - -
Improved recovery 15 20
Technical revisions 176 (3)
Acquisitions 2,584 3,364
Dispositions (23) (33)
Production(1) (1,230) (1,230)
December 31, 2006 5,393 7,765
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Finding and Development Costs
Finding and development costs for Berens seismic, exploration and
development activities for each of the past three years and on a three year
cumulative basis are outlined below:
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Three
Year
2006 2005 2004 Totals
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Total capital for seismic,
exploration and development
(excluding land capital)
($000's) 53,340 25,207 16,230 94,777
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Future development capital
- proved ($000's) 12,600 1,240 260 12,340
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Future development capital
- proved plus probable
($000's) 15,400 1,380 346 15,054
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Reserve extensions and
discoveries - proved (Mboe) 2,222 946 1,091 4,259
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Reserve extensions and
discoveries - proved plus
probable (Mboe) 3,271 1,273 1,493 6,037
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Finding and development
costs - proved (per boe) $ 29.12 $ 27.96 $ 15.11 $ 25.15
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Finding and development
costs - proved plus
probable (per boe) $ 20.59 $ 20.88 $ 11.10 $ 18.19
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Berens' three year average finding and development costs on a proved plus probable basis for exploration and development activities were $18.19 per boe with 2006 averaging $20.59. Finding and development costs in 2006 improved throughout the year after a poor first quarter. Berens internal estimate of fourth quarter 2006 finding and development costs were $13.50 per boe. The first quarter was characterized by high service industry costs, limited access to services and poor drilling results in Karr. Early 2007 drilling success in the Deep Basin and Pembina points to continued strong finding and development cost efficiency, building on our momentum established in the second half of 2006.
The Berland Exploration acquisition in January 2006 for $102.7 million was supplemented in December 2006 by a small acquisition in Pembina for $1.4 million. Berens also sold small, non-core asset in December 2006 for $0.7 million. Finding and development costs for 2006 acquisition activity are outlined below. Acquisition costs were higher than those achieved with the exploration and development program but a critical contribution from the acquisitions was the establishment of significant undeveloped land positions in Pembina and the Deep Basin where we are now experiencing strong drilling success.
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2006
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Total net acquisition capital ($000's) 103,450
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Net proved reserves from acquisitions less
divestitures (Mboe) 2,561
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Net proved plus probable reserves from acquisitions less
divestitures (Mboe) 3,331
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Finding and development costs - proved (per boe) $ 40.39
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Finding and development costs - proved plus probable
(per boe) $ 31.06
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The following table outlines finding and development costs combining the
exploration and development activity with the acquisition activity for 2006.
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2006
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Total capital (excluding land capital) ($000's) 156,790
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Change in future development capital - proved ($000's) 11,360
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Change in future development capital - proved plus
probable ($000's) 14,020
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Reserves added - proved (Mboe) 4,783
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Reserve added - proved plus probable (Mboe) 6,602
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Finding and development costs - proved (per boe) $ 35.15
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Finding and development costs - proved plus
probable (per boe) $ 28.87
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Berens Energy Ltd.
Annual and Fourth Quarter 2006
Management's Discussion and Analysis ("MD&A")
March 26, 2007
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 (six "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, 2006 audited financial statements and notes thereto. This MD&A was prepared using information that is current as of March 26, 2007 unless otherwise noted.
FORWARD LOOKING INFORMATION
This MD&A contains forward looking 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 where actual results could 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 abandonment and site restoration, the Company's ability to enter into or renew leases, the Company's ability to secure adequate product transportation, changes in environmental and other regulations and general economic conditions. These statements are as of the date of this MD&A and the Company does not undertake an obligation to update its forward looking statements except as required by law.
Additional information on the Company can be found on the SEDAR website at www.sedar.com.
QUARTERLY INFORMATION
2006
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($000's except as noted) Q4 Q3 Q2 Q1
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Sales volumes:
Natural gas (mcf/day) 18,440 17,355 17,224 16,631
Oil and natural gas
liquids (bbl/day) 483 479 494 420
Barrels of oil equivalent 3,556 3,372 3,364 3,192
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Financial:
Net revenue 11,213 9,536 9,846 9,523
Net (loss) (21,951) (2,662) (1,606) (2,121)
per share - basic
($/share) $ (0.24) $ (0.03) $ (0.02) $ (0.03)
per share - diluted
($/share) $ (0.24) $ (0.03) $ (0.02) $ (0.03)
Capital costs 12,811 9,746 15,234 19,124
Shares outstanding (000's) 92,947 86,447 86,447 86,447
Bank debt 50,080 52,780 49,580 32,180
Working capital
(deficit) including
bank debt (55,073) (60,182) (55,766) (45,907)
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Per unit information:
Natural gas
price ($/mcf) $ 7.13 $ 5.91 $ 6.28 $ 7.72
Oil and liquids
price ($/barrel) $ 51.54 $ 62.07 $ 64.27 $ 51.07
Oil equivalent
price ($/boe) $ 43.96 $ 39.24 $ 41.59 $ 46.09
Operating netback ($/boe) $ 24.24 $ 21.54 $ 22.87 $ 24.59
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Net wells completed: (No.)
Natural gas 7 3 9 4
Oil - - - -
Dry 1 1 1 3
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Total 8 4 10 7
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2005
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($000's except as noted) Q4 Q3 Q2 Q1
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Sales volumes:
Natural gas (mcf/day) 11,537 10,832 10,250 9,155
Oil and natural gas
liquids (bbl/day) 176 165 200 233
Barrels of oil equivalent 2,099 1,970 1,908 1,759
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Financial:
Net revenue 9,537 7,667 5,754 4,910
Net income (loss) (475) 534 887 (441)
per share - basic
($/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)
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Per unit information:
Natural gas price ($/mcf) $ 11.26 $ 9.16 $ 7.29 $ 6.91
Oil and liquids price
($/barrel) $ 41.92 $ 57.47 $ 33.11 $ 30.81
Oil equivalent price ($/boe) $ 65.47 $ 55.05 $ 42.61 $ 40.05
Operating netback ($/boe) $ 39.78 $ 34.07 $ 24.81 $ 21.12
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Net wells completed: (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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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. Ongoing drilling has delivered the production increase to date for 2006. There have been no further material acquisitions.
RESULTS OF OPERATIONS
Production Volume
Production volume averaged 3,556 boe/d for the fourth quarter of 2006, up 69 percent compared to 2,099 boe/d in the fourth quarter of 2005 and up five percent compared to the third quarter of 2006. Natural gas represented 86 percent of production in the fourth quarter of 2006 with the remaining production being 13 percent light oil and natural gas liquids and one percent conventional heavy oil. Ongoing drilling in Pembina and a November drilling program in Lanfine delivered the fourth quarter volume growth.
Production volume averaged 3,373 boe/d for the year ended December 31, 2006, up 74 percent compared to 1,935 boe/d in the year ended December 31, 2005. The increase is attributable to ongoing drilling activity as well as the Berland purchase that closed on January 18, 2006. On a per share basis production was almost unchanged from 2005 to 2006, however the reserve and opportunity base was improved significantly. On a reserve basis, proved plus probable reserves increased 99 percent on a per share basis comparing December 31, 2006 to December 31, 2005. Management believes the increased reserve base and the extensive land position will lead to future per share growth in production.
Production Revenue
Natural gas prices averaged $7.13 per mcf for the fourth quarter of 2006, down 37 percent compared to $11.26 per mcf in the fourth quarter of 2005. Oil and liquids prices averaged $46.25 and $54.26 per barrel respectively in the fourth quarter of 2006 for a blended price of $51.54 per barrel, up 23 percent from the fourth quarter 2005 blended oil and liquids price of $41.92 per barrel. Higher priced light oil and natural gas liquids represent a larger portion of production in 2006 compared to 2005. On a boe basis, prices averaged $43.96 in the fourth quarter of 2006, down 33 percent compared to $65.47 per boe in the fourth quarter of 2005 as the large decline in natural gas prices was partially offset by increased prices for oil and liquids and the higher oil and liquids content in 2006.
Revenue, excluding unrealized gains or losses on derivative instruments, was up 18 percent in the fourth quarter of 2006 compared to the fourth quarter of 2005 as the Volume increase of 69 percent was partially offset by a 33 percent decrease in per boe prices.
Natural gas prices averaged $6.75 per mcf for the year ended December 31, 2006, down 23 percent compared to $8.80 per mcf in the year ended December 31, 2005. Blended oil and liquids prices averaged $57.48 per barrel in the year ended December 31, 2006, up 47 percent from the year ended December 31, 2005 blended price of $39.13 per barrel. On a boe basis, prices averaged $42.86 in the year ended December 31, 2006, down 17 percent compared to the year ended December 31, 2005 boe price of $51.43. Revenue was up 44 percent in the year ended December 31, 2006 compared to the year ended December 31, 2005. Volume increased by 74 percent offset by the 17 percent decrease in per boe prices.
Royalties
Royalties, net of Alberta Royalty Tax Credit ("ARTC"), averaged 22 percent of revenue for the fourth quarter of 2006 compared to 25 percent in the fourth quarter of 2005. Lower royalties in the fourth quarter of 2006 compared to the fourth quarter of 2005 are mainly due to lower natural gas prices. For the year ended December 31, 2006 royalties, net of ARTC averaged 24 percent of revenue compared to 23 percent of revenue in the year ended December 31, 2005. The effect of lower natural gas prices in 2006 on royalty rates was offset by 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 in addition to crown royalties contributing to the
higher royalty percentage.
On an ongoing basis, royalties are expected to average approximately 24 percent of revenues without the go-forward benefit of ARTC which has been rescinded effective January 1, 2007. Royalty expense of $3.2 million was recorded in the fourth quarter of 2006, up two percent compared to the fourth quarter of 2005 reflecting higher revenue in the 2006 period offset partially by a lower royalty rate. For the year ended December 31, 2006 royalty expense of $12.7 million was up 49 percent compared to the year ended December 31, 2005 due to higher revenues and a slightly higher royalty rate.
Production Expenses
Production expenses were $8.88 per boe in the fourth quarter of 2006, up eight percent compared to $8.22 per boe in the fourth quarter of 2005. The fourth quarter of 2006 was burdened by prior quarter catch up charges from a partner for processing fees on non-operated properties. For the year ended December 31, 2006 production expenses were $7.89 per boe, up two percent from $7.74 per boe in the year ended December 31, 2005. A focus on cost management has contained costs in an environment where industry costs have escalated significantly. Processing costs for the liquids rich Pembina and Deep Basin natural gas in 2006 added to per unit costs compared to 2005 when most of the Company's natural gas production was dry gas in eastern Alberta. The Company acquired an interest in a major Pembina processing plant in December 2006 which will reduce processing cost for natural gas produced in the eastern part of the Pembina core area. With ongoing volume increases and cost management, management expects future per unit operating expenses to trend below the $8.00 per boe level.
Fourth quarter 2006 production expenses were $2.9 million, up 83 percent compared to the fourth quarter of 2005 due to a 69 percent increase in volume and slightly higher per unit costs. For the year ended December 31, 2006 production expenses were $9.7 million, up 78 percent compared to the year ended December 31, 2005 due to a 74 percent production increase and higher per boe costs in 2006.
Transportation costs of $0.3 million increased 13 percent in the fourth quarter of 2006 compared to the fourth quarter of 2005 due to increased volumes offset by lower per unit costs. For the year ended December 31, 2006 transportation costs were $1.1 million an increase of 30 percent compared to the year ended December 31, 2005.
General and Administrative Expenses
General and administrative costs, including stock-based compensation, were up five percent in the fourth quarter of 2006 compared to the fourth quarter of 2005. Costs in the fourth quarter of 2006 benefited by general and administrative cost recoveries from partners on capital projects operated by Berens. In 2005, almost all of the Company's capital activity was directed to 100 percent owned lands resulting in little administrative cost recovery. On a per unit basis, general and administrative costs were $2.99 per boe for the fourth quarter of 2006, down 37 percent compared to $4.78 per boe in the fourth quarter of 2005.
For the year ended December 31, 2006 general and administrative costs were up 51 percent compared to the year ended December 31, 2005. The Company's 2006 staff contingent increased with the acquisition of Berland and further additions to core properties. Salary and bonus levels have also increased due to competitive industry pressures. In addition, 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 $3.90 per boe for the year ended December 31, 2006, down 13 percent compared to $4.51 per boe in the year ended December 31, 2005. There were no general and administrative costs capitalized in the fourth quarter or for the year ended December 31, 2006 and 2005.
Staff levels are expected to remain fairly constant in 2007. Per unit general and administrative costs are expected to decline as production levels increase.
Interest Expense
Interest expense was $1.0 million in the fourth quarter of 2006 compared to $6,000 in the fourth quarter of 2005. Berens raised equity in the fourth quarter of 2005 in anticipation of the acquisition of Berland. The subsequent closing of the Berland acquisition in January 2006 resulted in significant borrowing on the bank operating line as 30 percent of the Berland acquisition cost was in the form of cash and Berens assumed Berland's debt and working capital deficiency, totaling $28 million. Capital expenditures in 2006 were higher than funds from operations. Equity was raised in October 2006, mitigating the increase in the bank operating line. For the year ended December 31, 2006 interest expense was $2.6 million compared to $0.3 million in the year ended December 31, 2005.
Operating Netback(1)
Operating netback represents the margin realized by the production and sale of petroleum and natural gas. The primary cause of the lower 2006 netbacks is lower natural gas prices.
-------------------------------------------------------------------------
Three months Twelve months
Quarterly Operating Netbacks ended ended
($'s per boe) December 31 December 31
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Sales price 43.96 65.47 42.86 51.43
Less:
Royalties (net of ARTC) 9.92 16.09 10.67 12.07
Production expenses 8.88 8.22 7.89 7.74
Transportation charges 0.92 1.38 0.91 1.22
-------------------------------------------------------------------------
Operating netback 24.24 39.78 23.39 30.40
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) non-GAAP measure - refer to discussion on non-GAAP measures below.
Depletion, Amortization and Accretion
Depletion, amortization and accretion totaled $9.6 million ($29.24 per boe) in the fourth quarter of 2006 compared to $7.2 million ($37.15 per boe) in the fourth quarter of 2005. For the year ended December 31, 2006 depletion, amortization and accretion totaled $36.7 million ($29.85 per boe) compared to $18.5 million ($26.25 per boe) for the year ended December 31, 2005. The depletion rate per boe has trended down throughout 2006 from higher rates early in the year which were due to the cost of acquiring the Berland reserves as part of the Berland acquisition and to spending in the deeper Karr drilling program which had limited reserve additions in the first quarter of 2006. As drilling results have improved in the latter part of 2006, particularly in the Pembina area, new reserves have been added at significantly lower per unit costs compared to the first half of 2006.
Income Taxes
Current taxes of $72,000 were recorded in the fourth quarter of 2006 primarily for provincial capital taxes and taxes related predecessor company final tax returns. The Company does not expect to pay current income tax during 2007 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 $14.5 million at December 31, 2006. Future tax liabilities of $16.1 million were recorded on the acquisition of Berland and $9.6 million was recorded to account for the tax effect of flow-through shares renouncements. These increases were offset by $4.7 million on losses recorded and a $5.5 million future tax reduction to reflect future corporate tax rate reductions which are substantially enacted.
Goodwill Impairment
Goodwill, at the time of acquisition, represents the excess of purchase cost of a business over the fair value of net assets acquired. Thereafter, goodwill is not amortized and is assessed for impairment at least annually. If the estimated fair value of the business is less than the book value, a second test is performed to determine the amount of the impairment. Goodwill was originally recorded primarily on the Resolution Resources Ltd. acquisition (2003) and the Berland Exploration Ltd. acquisition (2006).
Since the closing of these acquisitions oil and gas company valuations have eroded significantly, especially those of natural gas weighted producers primarily due to the decline in natural gas prices combined with high service costs in the industry. The Company tested the goodwill balance as at December 31, 2006 taking into account the decline in corporate economic value caused by the 2006 decline in the share price. Recent oil and gas asset sales and corporate sale transactions were also benchmarked for the goodwill test. Based on the Company's assessment, it was determined that the fair value of the assets was less than the book value including the amount of goodwill that was being carried on the balance sheet. As a result, the Company recorded an impairment of goodwill in the amount of $24.2 million representing 54 percent of the goodwill balance.
NET INCOME (LOSS)
The net loss for the fourth quarter of 2006 was $21.9 million ($0.24 per share) compared to a loss of $0.4 million ($0.01 per share) in the fourth quarter of 2005. The higher 2006 loss has resulted primarily from the goodwill impairment, higher depletion expense and low natural gas prices more than offsetting the benefit from increases in production volume. For the year ended December 31, 2006 the net loss was $28.3 million ($0.33 per share) compared to net income of $0.5 million ($0.01 per share) for the year ended December 31, 2005.
CAPITAL COSTS
Capital costs, excluding net acquisitions were $12.1 million in the fourth quarter of 2006, down from $12.3 million in the third quarter of 2005. A small acquisition was completed in the fourth quarter of 2006 for $1.4 million which added 25 boe/d (100,000 boe of proved plus probable reserves) and a 7.5 percent interest in a processing facility in Pembina that processes significant Berens natural gas volume in the eastern half of Pembina. Miscellaneous, small properties were sold in the fourth quarter totaling 55 boe/d (35,000 boe of proved plus probable reserves) for $704,000.
The fourth quarter 2006 capital program was focused on drilling in Lanfine and Pembina. A total of eight net wells were completed in the fourth quarter of 2006 compared to 12 net wells in the fourth quarter of 2005. Average well costs are higher in 2006 as deeper Pembina 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 industry costs for most activities. A seismic data base was sold to a seismic broker in the third quarter of 2006 for proceeds of $1.8 million.
-------------------------------------------------------------------------
Three months Twelve months
ended ended
($000's) December 31, December 31,
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Drilling and completion 11,112 9,198 51,820 22,613
Land 512 2,392 2,535 7,197
Geological and geophysical 384 833 1,048 2,595
Office and other 37 193 295 260
-------------------------------------------------------------------------
Total 12,045 12,616 55,698 32,665
Asset retirement obligation 143 334 462 501
-------------------------------------------------------------------------
Total exploration and
development 12,188 12,950 56,160 33,166
-------------------------------------------------------------------------
Net acquisitions (dispositions) 766 (270) 102,723 (270)
-------------------------------------------------------------------------
Total capital 12,954 12,680 158,883 32,896
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Overall, the Company has spent 92 percent of its exploration and development capital on drilling, completion and tie-in activities during 2006 compared to a capital program that was more focused on land and seismic in 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 2007, the capital program is again expected to be approximately 90 percent allocated to drilling and completion activity.
WORKING CAPITAL
Accounts receivable of $19.6 million at December 31, 2006 was primarily revenue receivables ($5.1 million) and amounts owing from partners ($13.4 million) and capital advances to partners for drilling projects ($0.5 million). Accounts payable at December 31, 2006 of $26.6 million were mainly comprised of trade payables for capital and operating costs ($12.9 million), royalties ($2.1 million), amounts owing to partners ($2.6 million) and capital costs accrued at the end of the quarter for ongoing drilling and completion operations ($1.5 million).
Working capital excluding bank indebtedness was in a deficit position of $5.0 million at December 31, 2006. Borrowings under the bank line and ongoing cash flows are expected to fund the 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 was in place for $59.0 million, secured by producing properties at December 31, 2006. The bank line was increased to $65 million subsequent to year end. At December 31, 2006, $50.1 million was drawn on the bank line. On October 26, 2006 a flow-through equity financing was closed for net proceeds of $11.2 million which improved the financial condition of the Company.
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 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 December 31 is set out in the following chart:
-------------------------------------------------------------------------
Three months Twelve months
ended ended
($000's) December 31 December 31
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Net income (loss) (21,951) (475) (28,340) 504
Items not requiring cash:
Depletion, depreciation
and accretion 9,569 7,174 36,747 18,540
Impairment of goodwill 24,220 - 24,220
Unrealized hedging gains (635) - (635)
Future income tax
expense (recovery) (5,218) 25 (10,237) (1,098)
Stock based compensation 133 103 716 339
-------------------------------------------------------------------------
Funds from operations 6,118 6,827 22,471 18,285
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Funds from operations are also presented on a per share basis consistent with the calculation of net income per share, whereby per share amounts are calculated using the weighted average number of shares outstanding. Funds from operations per share were $0.07 (basic and diluted) for the fourth quarter of 2006 compared to $0.13 per share for the fourth quarter of 2005. Funds from operations per share were $0.26 (basic and diluted) for the year ended December 31, 2006 compared to $0.37 for the year ended December 31, 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.
COMMODITY PRICE RISK MANAGEMENT
The Company may use financial derivative or fixed price contracts to manage its exposure to fluctuations in commodity prices and foreign currency exchange rates. The Company applies the fair value method of accounting for derivative instruments by initially recording an asset or liability, and recognizing changes in the fair value of the derivative instrument in income.
The following is a summary of natural gas price risk management derivative contracts in effect as of December 31, 2006. All contracts are priced in Canadian dollars per gigajoule (GJ). The price per GJ can be converted to an approximate price per MCF by multiplying the per GJ price by 1.05. GJ can be converted to an approximate MCF volume by multiplying the GJ volume by 0.95.
------------------------------------------------------------------------- Daily quantity (GJ) Term of Contract Fixed price per gigajoule ------------------------------------------------------------------------- 2,000 January 1 to March 31, 2007 $6.00 floor; $11.05 cap ------------------------------------------------------------------------- 2,000 April 1 to October 31, 2007 $6.00 floor; $8.50 cap ------------------------------------------------------------------------- 2,000 November 1 to December 31, 2007 $6.00 floor; $11.05 cap ------------------------------------------------------------------------- 2,000 January 1 to March 31, 2007 $7.00 floor; $9.85 cap ------------------------------------------------------------------------- 2,000 April 1 to October 31, 2007 $7.00 floor; $8.00 cap ------------------------------------------------------------------------- 2,000 November 1 to December 31, 2007 $7.00 floor; $9.85 cap -------------------------------------------------------------------------
The fair value of the above natural gas derivative instruments marked to market as at December 31, 2006, results in an unrealized gain of $635,000. There were no realized gains or losses on derivative instruments in 2006. A fixed price contract to sell 2,000 GJ per day from January 1 to October 31, 2007 at a price of $7.65 per GJ was also entered into for the purpose reducing exposure to natural gas price volatility.
RELATED PARTY TRANSACTIONS
A consulting firm is contracted from time to time in which one of the Company's directors is the chairman and founding 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 fourth quarter of 2006 were nil and $58,000 for the year ended December 31, 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 fourth quarter of 2006 were $39,000 and $571,000 for the year ended December 31, 2006.
SHARE DATA
As of the date of this MD&A the Company had 92,947,064 issued and outstanding common shares. Additionally, options to purchase 5,268,200 common shares have been issued.
DISCLOSURE CONTROLS AND PROCEDURES OVER FINANCIAL REPORTING
The Company has established procedures and internal control systems to ensure timely and accurate preparation of financial, internal management and other reports. Disclosure controls and procedures are in place to ensure all ongoing statutory reporting requirements are met and material information is disclosed on a timely basis. The Chief Executive Officer and the Chief Financial Officer, individually, sign certifications that the financial statements, together with the other financial information included in the regulatory filings, fairly present in all material respects the financial conditions, results of operation, and cash flows as of the dates and for the periods represented.
The Company's management, including its Chief Executive Officer and its Chief Financial Officer, have evaluated the effectiveness of the Company's disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded that the Corporation's disclosure controls are effective as of the end of the period covered by this annual report, in all material respects, after considering the Canadian Securities Administrators' Multilateral Instrument 52-109 Certification of Disclosures in Issuers' Annual and Interim Filings.
Internal control over Financial Reporting
Management of Berens is responsible for establishing and maintaining adequate internal controls over financial reporting. Internal controls over financial reporting is a process designed under the supervision of the Chief Executive Officer and the Chief Financial Officer and effected by the Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Management has conducted a review of the design of its internal controls over financial reporting as at December 31, 2006. Based on this assessment, management believes that the Corporation's system of internal controls over financial reporting as defined under MI 52-109 is sufficiently designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
By virtue of the size of the Corporation and its related staff complement, there are inherent limitations on the ability of management to implement internal controls. Management believes that it has designed sufficient internal controls to mitigate these limitations comprised primarily of management review and oversight.
Due to its inherent limitations, internal controls over financial reporting may not prevent or detect misstatements on a timely basis. A system of internal controls over financial reporting, no matter how well conceived or operated can provide only reasonable, not absolute, assurance that the objectives of the internal controls over financial reporting are met. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions.
Recent Canadian Accounting Pronouncements
As of January 1, 2007, the Corporation is required to adopt the Canadian Institute of Chartered Accountants ("CICA") Section 1530 "Comprehensive Income", Section 3251 "Equity", Section 3855 "Financial Instruments - Recognition and Measurement", and Section 3865 "Hedges", which were issued in January 2005. Under the new standards, a new financial statement, the Consolidated Statement of Comprehensive Income, has been introduced that will provide for certain gains and losses and other amounts arising from changes in fair value, to be temporarily recorded outside the income statements. In addition, all financial instruments, including derivatives, are to be included in the Company's Balance Sheets and measured, in most cases, at fair values, and requirements for hedge accounting have been further clarified. The Company is currently evaluating the impact of the new standards. Management does not anticipate the new and revised standards will have a material impact on its consolidated financial statements as the Company currently uses fair value accounting for derivative instruments that do not qualify or are not designated as hedges.
As of January 1, 2007, the Company is required to adopt revised CICA Section 1506, "Accounting Changes", which provides expanded disclosures for changes in accounting policies, accounting estimates and corrections of errors, which were issued in July 2006. Under the new standard, accounting changes should be applied retrospectively unless otherwise permitted or where impracticable to determine. As well, voluntary changes in accounting policy are made only when required by a primary source of GAAP or when the change results in more relevant and reliable information. The Company does not expect application of this revised standard to have a material impact on its consolidated financial statements.
OUTLOOK
Drilling success in late 2006 and in early 2007 has confirmed the potential of the undeveloped land in the Company's portfolio. Drilling opportunities exist across four core areas and are well diversified in terms of risk, reserve potential and value addition. The intention is to remain focused in the four core areas that have been established to take advantage of the high level of technical expertise and experience we have developed in each area.
The 2007 capital program will be diversified across the four core areas. Pembina, which is considered to have low risk with strong return potential will receive 60 percent of the 2007 capital program with the balance of 2007 split between the lower risk shallow gas programs in Lanfine and Marten Hills and the higher risk/reward Deep Basin area which has the potential for large reserve discoveries. The 2007 capital plan is drilling focused with over 90 percent of capital budgeted toward drilling and completion activities with the balance directed toward land and seismic acquisitions.
Access to services appears to be easing throughout western Canada. We expect some moderation of the industry cost structure as we go forward but capital management and a focus on cost reduction will still be important aspects of our business when carrying out the 2007 capital program.
The undeveloped land base totaling 145,000 net acres is expected to provide a strong inventory of drilling prospects to deliver future growth. The 2007 drilling program is well established already. We plan to participate in 50 wells, all on existing land. It is expected that the Company will still have ample undeveloped acreage to continue drilling well beyond the end of 2007.
Berens Energy Ltd.
Balance Sheets
As at,
-------------------------------------------------------------------------
(000's) December 31, December 31,
2006 2005
-------------------------------------------------------------------------
ASSETS (note 5)
Current
Cash and cash equivalents (note 3) $ 10 $ 9,472
Accounts receivable 19,601 9,912
Unrealized gain on risk management (note 12) 635 -
Prepaid expenses and deposits 1,412 312
-------------------------------------------------------------------------
21,658 19,696
Investments 29 299
Future income taxes (note 9) - 225
Property, plant and equipment (note 5) 171,178 53,242
Goodwill (note 4 & 13) 20,755 14,805
-------------------------------------------------------------------------
$ 213,620 $ 88,267
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Bank loan (note 7) $ 50,080 -
Accounts payable and accrued liabilities 26,622 $ 15,331
Taxes payable 29 92
-------------------------------------------------------------------------
76,731 15,423
Asset retirement obligations (note 6) 2,645 1,223
Future income taxes (note 9) 14,518 -
-------------------------------------------------------------------------
93,894 16,646
Commitments (note 15)
Shareholders' equity
Capital stock (note 8) 148,038 72,309
Contributed surplus (note 8) 1,290 574
Deficit (29,602) (1,262)
-------------------------------------------------------------------------
119,726 71,621
-------------------------------------------------------------------------
$ 213,620 $ 88,267
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the financial statements
Berens Energy Ltd.
Statements of Operations and Deficit
For the three months and year ended December 31,
-------------------------------------------------------------------------
(000's) Three months Year
ended ended
December 31, December 31,
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
Revenue
Oil and natural gas
revenue $ 14,386 $ 12,644 $ 52,810 $ 36,393
Royalties, net of
ARTC (3,173) (3,107) (12,692) (8,525)
-------------------------------------------------------------------------
11,213 9,537 40,118 27,868
Unrealized gain on
risk management
(note 12) 635 - 635 -
-------------------------------------------------------------------------
11,848 9,537 40,753 27,868
Interest - 12 18 14
-------------------------------------------------------------------------
11,848 9,549 40,771 27,882
-------------------------------------------------------------------------
Expenses
Production 2,905 1,588 9,721 5,468
Transportation 302 267 1,116 859
Depletion,
amortization and
accretion 9,569 7,174 36,747 18,540
Impairment of
goodwill (note 13) 24,220 - 24,220 -
General and
administrative
(note 11) 845 821 4,090 2,847
Stock-based
compensation
(note 8) 133 103 716 339
Interest 972 6 2,627 328
-------------------------------------------------------------------------
38,946 9,959 79,237 28,381
-------------------------------------------------------------------------
Loss before income
taxes (27,098) (410) (38,466) (499)
Income taxes (note 9)
Future expense
(recovery) (5,218) 25 (10,237) (1,098)
Current expense 71 40 111 95
-------------------------------------------------------------------------
(5,147) 65 (10,126) (1,003)
-------------------------------------------------------------------------
Net income (loss)
for the period (21,951) (475) (28,340) 504
Deficit, beginning
of period (7,651) (787) (1,262) (1,766)
-------------------------------------------------------------------------
Deficit, end of
period $ (29,602) $ (1,262) $ (29,602) $ (1,262)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income (loss)
per share (note 14)
Basic and diluted $ (0.24) $ (0.01) $ (0.33) $ 0.01
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the financial statements
Berens Energy Ltd.
Statements of Cash Flows
For the three months and year ended December 31,
-------------------------------------------------------------------------
(000's) Three months Year
ended ended
December 31, December 31,
-------------------------------------------------------------------------
2006 2005 2006 2005
-------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income (loss) for
the period $ (21,951) $ (475) $ (28,340) $ 504
Add items not
involving cash
Depletion,
amortization and
accretion 9,569 7,174 36,747 18,540
Impairment of
goodwill 24,220 - 24,220 -
Unrealized risk
management gain (635) - (635) -
Future income tax
expense (recovery) (5,218) 25 (10,237) (1,098)
Stock-based
compensation 133 103 716 339
-------------------------------------------------------------------------
6,118 6,827 22,471 18,285
Change in non-cash
working capital items
related to operating
activities (note 10) (1,274) 1,854 (9,016) 4,248
-------------------------------------------------------------------------
Cash flow provided by
(used in) operating
activities 4,844 8,681 13,455 22,533
-------------------------------------------------------------------------
FINANCING ACTIVITIES
Change in bank loan (2,700) - 30,330 (4,500)
Net proceeds from
private offerings 11,142 11,928 30,955 24,795
Sale of investment 25 - 269 -
Proceeds from the
exercise of stock
options - - - 49
-------------------------------------------------------------------------
Cash flow provided by
(used in) financing
activities 8,467 11,928 61,554 20,344
-------------------------------------------------------------------------
INVESTING ACTIVITIES
Cash acquired through
Berland acquisition - - 109 -
Cash component on
Berland acquisition - - (28,682) -
Purchase of property
and equipment (12,811) (12,346) (56,914) (32,396)
Change in non-cash
working capital items
related to investing
activities (note 10) (534) (182) 1,016 (1,044)
-------------------------------------------------------------------------
Cash flow used in
investing activities (13,345) (12,528) (84,471) (33,440)
-------------------------------------------------------------------------
Increase (decrease)
in cash and cash
equivalents (34) 8,081 (9,462) 9,437
Cash and cash
equivalents,
beginning of
period 44 1,391 9,472 35
-------------------------------------------------------------------------
Cash and cash
equivalents,
end of period $ 10 $ 9,472 $ 10 $ 9,472
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the financial statements
BERENS ENERGY LTD.
Notes to Financial Statements
Year ended December 31, 2006 and 2005
1. NATURE OF OPERATIONS
The Company is a full cycle oil and natural gas exploration and
production company with activities encompassing land acquisition,
geological and geophysical assessment, drilling and completion, and
production. The primary areas of operation are in eastern and west
central Alberta.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The consolidated financial statements have been prepared by management in
accordance with Canadian generally accepted accounting principles. The
nature of the business and timely preparation of financial statements
requires that management make estimates and assumptions, and use judgment
regarding assets, liabilities, revenues and expenses. Such estimates
primarily relate to unsettled transactions and events as of the date of
the financial statements. Accordingly, actual results may differ from
estimated amounts. In the opinion of management, these financial
statements have been properly prepared within reasonable limits of
materiality and within the framework of the significant accounting
policies summarized below.
Cash and Cash Equivalents
Cash and cash equivalents, consisting of cash and short-term investments
with a maturity of less than three months, are recorded at the lower of
cost and quoted market value.
Capitalized Costs
The full cost method of accounting is followed whereby all costs relating
to the acquisition of, exploration for and development of oil and gas
reserves are capitalized in a single Canadian cost center. Such costs
include lease acquisition, lease rentals on undeveloped properties,
geological and geophysical costs, drilling both productive and
non-productive wells, production equipment and overhead charges directly
related to acquisition, exploration and development activities.
Gains or losses are not recognized on the disposition of oil and gas
properties unless such dispositions would change the depletion rate by
20 percent or more. Gains are recognized on the disposition of other
assets.
Depletion and Amortization
All costs of acquisition, exploration and development of oil and gas
reserves, associated tangible plant and equipment costs (net of salvage
value), and estimated costs of future development of proved undeveloped
reserves are depleted and amortized by the unit of production method.
This method is based on estimated gross proved reserves as determined by
independent engineers.
Costs of unproved properties are initially excluded from oil and gas
properties for the purpose of calculating depletion. When proved reserves
are assigned or the property is considered to be impaired, the cost of
the property or the amount of the impairment is added to costs subject to
depletion.
The volumes of oil and natural gas reserves and production are converted
to equivalent barrels of oil based on the relative energy content of each
product such that six thousand cubic feet of natural gas equals one
barrel of oil, commonly known as a six to one basis.
Office and computer equipment is amortized on a straight-line basis over
ten and four years, respectively.
Asset Retirement Obligations
The Company has obligations to abandon and reclaim oil and natural gas
wells and production facilities after it is determined that these wells
and facilities have no further economic value. Well reclamations
generally involve the removal of production tubing in the well, setting a
permanent plug, pouring cement on top of the plug, cutting and capping
the casing below surface and removal of surface equipment at the well
site. Land disturbances are smoothed, native vegetation is re-introduced
and the site is left to return to its natural state. In the case of wells
on farm land, sites are returned to productive farming use.
The fair value of a liability is recognized for an asset retirement
obligation in the period in which it is incurred or when a reasonable
estimate of its fair value can be made, and records a corresponding
increase in the carrying value of the related long-lived asset. The
estimated fair value is determined through a review of engineering
studies, industry guidelines, and management's estimate on a site-by-site
basis. The liability is subsequently adjusted for the passage of time,
which is recognized as an accretion expense in the statement of
operations and included in asset retirement obligations. The liability is
also adjusted due to revisions in either the timing or the amount of the
original estimated cash flows associated with the liability. The increase
in the carrying value of the asset is amortized using the unit of
production method based on estimated gross proved reserves. Actual costs
incurred upon settlement of the asset retirement obligations are charged
against the asset retirement obligation to the extent of the liability
recorded. Any difference between the actual costs incurred upon
settlement of the asset retirement obligation and the recorded liability
is recognized as a gain or loss in the Company's statement of operations
in the period in which the settlement occurs.
Ceiling Test
The Company applies an impairment test to the net carrying value of
petroleum and natural gas assets designed to ensure that such costs do
not exceed the estimated amount ultimately recoverable. This amount is
the aggregate of estimated undiscounted future net cash flows from
production of proved reserves and the cost of unproved properties and
seismic. Future cash flows are estimated using future prices and costs
without discounting. Should the net carrying value of the petroleum and
natural gas assets exceed the amount ultimately recoverable, the amount
of impairment is determined by deducting the discounted estimated future
cash flows from proved and probable reserves based on the future prices
plus the cost of unproved properties, net of impairment allowances, from
the book value of the related assets. Any reduction in net carrying
value, as a result of the impairment test, is included in depreciation
and depletion expense.
Goodwill
Goodwill, at the time of acquisition, represents the excess of purchase
cost of a business over the fair value of net assets acquired.
Thereafter, goodwill is not amortized and is assessed for impairment at
least annually. If the estimated fair value of the business is less than
the book value, a second test is performed to determine the amount of the
impairment. The amount of the impairment is determined by deducting the
estimated fair value of the business' net assets from the fair value of
the business to determine the implied fair value of goodwill and
comparing that amount to the book value of goodwill. Any excess of the
book amount of goodwill over the implied fair value is the impairment
amount and is charged to earnings in the period of impairment.
Revenue Recognition
Oil and natural gas sales are recorded as revenue when the commodities
are delivered to purchasers.
Income Taxes
The liability method of accounting for income taxes is followed. Under
this method, future tax assets and liabilities are determined based on
the differences between financial reporting and income tax bases of
assets and liabilities, and are measured using substantively enacted tax
rates and laws that will be in effect when the differences are expected
to reverse. The effect on future tax assets and liabilities of a change
in tax rates is recognized in net income in the period in which the
change occurs.
Joint Ventures
A substantial portion of the Company's exploration, development and
production activities is conducted jointly with others. These
consolidated financial statements reflect only the Company's
proportionate interest in such activities.
Stock-Based Compensation
Under the stock option plan, options to purchase common shares are
granted to directors, officers, employees and consultants at current
market prices. Options issued by the Company are accounted for in
accordance with the fair value method of accounting for stock-based
compensation using the Black-Scholes option pricing model. The resulting
cost of the option is charged to earnings over the vesting period of the
option with a corresponding increase in contributed surplus.
Measurement Uncertainty
The amount recorded for depletion and amortization of oil and gas
properties, the provision for asset retirement obligations, goodwill
measurement and the ceiling test calculation are based on estimates of
gross proved reserves, production rates, commodity prices, future costs
and other assumptions. By their nature, these estimates are subject to
measurement uncertainty and the effect on the financial statements of
changes in such estimates in future years could be material.
Per Share Information
Per share information is calculated on the basis of the weighted average
number of common shares outstanding during the fiscal year. Diluted per
share information reflects the potential dilution that could occur if
securities or other contracts to issue common shares were exercised or
converted to common shares. Diluted per share information is calculated
using the treasury stock method which assumes that any proceeds received
by the Company upon the exercise of in-the-money stock options would be
used to buy back common shares at the average market price for the
period.
Investments
Long-term investments are recorded at the lower of cost or fair market
value.
Flow-through Common Shares
Resource expenditure deductions for income tax purposes related to
exploration and development activities funded by flow-through share
arrangements are renounced to investors in accordance with income tax
legislation. The estimated tax benefits transferred to shareholders are
recorded as future income taxes and a reduction to share capital when the
expenditures are renounced, which for accounting purposes, is when the
appropriate documentation is filed with Revenue Canada.
Financial Instruments
The Company may use, from time to time, derivative financial instruments
to manage exposure related to changes in oil and natural gas commodity
prices. They are not used for trading or speculative purposes. The
Company applies the fair value method of accounting for derivative
instruments by initially recording an asset or liability, and recognizing
changes in the fair value of the derivative instrument in earnings. The
resulting unrealized gain or loss is recorded as a receivable or
liability with the tax effect included in the future income tax
provision.
3. CASH AND CASH EQUIVALENTS
Cash and cash equivalents are in the form of cash bank balances or
certificates of deposit from Canadian financial institutions with terms
of less than 90 days. The effective interest rate on the deposits at
December 31, 2006 was 2.3% (2005 - 2.3%).
4. 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
-------------------------------------------------------------------------
5. PROPERTY, PLANT AND EQUIPMENT
December 31, 2006 December 31, 2005
Accumulated Accumulated
depletion and depletion and
($000's) Cost depreciation Cost depreciation
-------------------------------------------------------------------------
Petroleum and natural
gas properties 240,047 69,305 81,030 28,186
Office and computer
equipment 678 242 492 94
-------------------------------------------------------------------------
240,725 69,547 81,522 28,280
-------------------------------------------------------------------------
Net book value 171,178 53,242
-------------------------------------------------------------------------
At December 31, 2006, costs of $25,907,000 (2005 - $10,391,000) related
to undeveloped land have been excluded from the depletion and
depreciation calculation. At December 31, 2006 future development capital
of $13,018,000 have been included in the depletion and depreciation
calculation (2005 - $1,411,000). A ceiling test was completed at
December 31, 2006 resulting in no impairment.
Benchmark pricing used for ceiling test purposes is shown on the
following table.
Oil
----------------------------------------------
Edmonton Cromer
WTI Par Price Medium
Cushing 40 degrees Hardisty 29.3 degrees
Oklahoma API Heavy API
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl)
---------- ---------- ---------- ----------
Historical
Averages
2002 26.08 40.33 26.57 35.48
2002 31.07 43.66 26.26 37.55
2004 41.38 52.96 29.11 45.75
2005 56.58 69.11 34.07 56.62
2006 (e) 66.22 73.16 41.87 62.24
Forecast
2007 62.00 70.25 39.25 61.25
2008 60.00 68.00 40.00 59.25
2009 58.00 65.75 39.75 57.25
2010 57.00 64.50 39.75 56.00
2011 57.00 64.50 40.25 56.00
2012 57.50 65.00 41.50 56.50
Inflation
thereafter +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr
Natural
gas NGLs
---------- ----------
AECO-C FOB
Gas Field Gate
Price (propane/ Inflation Exchange
($Cdn/ butane) rate% rate
Year MMbtu) ($Cdn/bbl) per year ($US/Cdn)
---------- ---------- ---------- ----------
Historical
Averages
2002 4.04 24.24 2.2 0.637
2002 6.66 33.25 2.8 0.721
2004 6.88 37.34 1.8 0.768
2005 8.58 47.42 2.2 0.825
2006 (e) 7.02 55.30 2.0 0.882
Forecast
2007 7.20 50.62 2.0 0.87
2008 7.45 46.88 2.0 0.87
2009 7.75 45.38 2.0 0.87
2010 7.80 44.50 2.0 0.87
2011 7.85 44.50 2.0 0.87
2012 8.15 44.75 2.0 0.87
Inflation
thereafter +2.0%/yr +2.0%/yr 2.0 0.87
6. ASSET RETIREMENT OBLIGATIONS
The total future asset retirement obligations were 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 $2,645,000 as at
December 31, 2006 (2005 - $1,223,000) based on a total future liability
of $6,959,400 (2005 - $3,314,000). These payments are expected to be made
over the next 5 to 15 years. An inflation rate of 2% and a credit
adjusted risk free rate of 10% were used to calculate the present value
of the asset retirement obligations. The inflation rate used for the
asset retirement obligation calculation was increased from 1.5% used in
2005 to reflect higher cost pressures in the industry.
The following table reconciles the asset retirement obligations:
($000's) 2006 2005
-------------------------------------------------------------------------
Obligation, December 31, 2005 $1,223 $ 648
Increase in obligation during the period 430 276
Obligation assumed from Berland acquisition 715 -
Increase due to increase in inflation rate 32 -
Increase due to reduction of risk free rate - 73
Accretion expense 245 226
-------------------------------------------------------------------------
Obligation, December 31, 2006 $2,645 $1,223
-------------------------------------------------------------------------
7. BANK OPERATING LINE
An agreement with a Canadian bank is in place for an operating bank line
totaling $59.3 million at December 31, 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 December 31, 2006 was 7.25 percent
(December 30, 2005 - 4.875 percent). On December 31, 2006, $50,080,000
was drawn on the line. Subsequent to December 31, 2006 the bank line
capacity was increased to $65 million.
8. 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, net of tax - (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
Private placement for cash, net of
commissions 6,500,000 11,238
Future tax effect of flow-through share
renouncements - (9,554)
Future tax effect on share issue costs
and commissions - 565
Share issue costs, net of tax - (272)
---------------------------------------------------------------------
Balance December 31, 2006 92,947,064 148,038
---------------------------------------------------------------------
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 exploration and development 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
were 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 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 (see note 4).
On October 26, 2006, 6,500,000 flow-through common shares were issued in
a private placement at $1.82 per share for cash proceeds of $11,830,000
before agent's commission of $591,500 to finance certain oil and gas
expenditures to be incurred in 2006 and 2007. The renouncement of these
expenditures was made to the purchasers of these shares during 2006.
(c) Stock Option Plan
A stock option plan is in place under which 7,500,000 common shares have
been reserved for options to be distributed to directors, officers,
employees and consultants with terms established by the board of
directors.
Options granted under the plan generally have a five year term to expiry
and vest equally over a three year period commencing on the first
anniversary date of the grant. The exercise price of each option equals
the closing market price of the Company's common shares on the day prior
to the date of the grant.
The following table sets forth a reconciliation of the plan activity
through December 31, 2006.
2006 2005
Weighted Weighted
average average
exercise exercise
Number of price Number of price
Options ($ per share) Options ($ per share)
-------------------------------------------------------------------------
Outstanding,
beginning of year 3,513,700 1.56 2,784,500 1.07
Granted 910,000 1.31 870,000 2.75
Cancelled (7,500) 2.90 (105,000) 1.48
Exercised - - (35,800) 1.38
-------------------------------------------------------------------------
Outstanding, end of
year 4,416,200 1.68 3,513,700 1.56
-------------------------------------------------------------------------
Exercisable 2,449,692 1.34 1,349,022 1.12
-------------------------------------------------------------------------
The following table sets forth additional information relating to the
stock options outstanding at December 31, 2006.
Options Outstanding
-------------------------------------------------------------------------
Weighted
average
exercise Weighted
Number price average
Exercise price of ($ per years to
range Options share) expiry
-------------------------------------------------------------------------
$1.00 to $1.59 3,051,700 1.22 2.32
-------------------------------------------------------------------------
$1.60 to $2.19 184,500 1.75 4.25
-------------------------------------------------------------------------
$2.20 to $2.79 242,500 2.49 4.31
-------------------------------------------------------------------------
$2.80 to $3.39 937,500 2.95 3.95
-------------------------------------------------------------------------
4,416,200 1.68 2.86
-------------------------------------------------------------------------
Exercisable Options
-------------------------------------------------------------------------
Weighted
average
exercise Weighted
Number price average
Exercise price of ($ per years to
range Options share) expiry
-------------------------------------------------------------------------
$1.00 to $1.59 2,172,192 1.15 -
-------------------------------------------------------------------------
$1.60 to $2.19 15,000 1.70 -
-------------------------------------------------------------------------
$2.20 to $2.79 - - -
-------------------------------------------------------------------------
$2.80 to $3.39 262,500 2.90 -
-------------------------------------------------------------------------
2,449,692 1.34 2.09
-------------------------------------------------------------------------
The fair value 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. The weighted
average option price for options outstanding at December 31, 2006 is
$0.596 per option. Based on the fair value method, $133,000 was recorded
as compensation expense during the fourth quarter of 2006 (2005 -
$103,000) and for the full year 2006, $716,000 (2005 - $339,000) for
options issued and outstanding 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 September 30, 2006.
($000's)
-------------------------------------------------------------------------
Opening balance, December 31, 2005 574
Stock based compensation expense 716
-------------------------------------------------------------------------
Closing balance, December 31, 2006 1,290
-------------------------------------------------------------------------
9. INCOME TAXES
The income tax expense or benefit differs from the amount computed by
applying the Canadian statutory rates to the loss before tax as follows:
($000's) 2006 2005
-------------------------------------------------------------------------
Loss before income taxes (38,466) (499)
-------------------------------------------------------------------------
Current statutory income tax rate 34.54% 37.82%
-------------------------------------------------------------------------
Anticipated tax recovery (13,286) (189)
Decrease in recovery resulting from:
Effect of future tax rate reductions (5,511) (301)
Impairment of goodwill 8,365
Unrealized risk management gains (219) -
Non-deductible Crown payments 1,293 1,748
Resource allowance (1,085) (1,444)
Alberta royalty tax credits (54) (113)
Provincial royalty rebates - (96)
Non-deductible expenses 260 135
Other - 46
Future tax asset valuation allowance - (884)
-------------------------------------------------------------------------
Future income tax recovery (10,237) (1,098)
-------------------------------------------------------------------------
Capital tax 29 95
Other 82 -
-------------------------------------------------------------------------
Current income tax expense 111 95
-------------------------------------------------------------------------
Future income taxes reflect the net tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial
reporting purposes and the amounts used for income tax purposes. The
components of the future tax assets are as follows:
($000's) 2006 2005
-------------------------------------------------------------------------
Future tax liabilities
Net book value of capital assets in excess of
tax pools (16,819) (1,379)
Future tax assets
Share issue costs 848 746
Attributed Canadian royalty income 683 444
Asset retirement obligation 771 414
-------------------------------------------------------------------------
Net future tax (liabilities) assets (14,517) 225
-------------------------------------------------------------------------
Tax Pools
At December 31, 2006 the petroleum and natural gas properties had an
approximate tax basis of $123,000,000.
Capital loss carry-forwards exist totaling $3,363,000 which are available
to offset future capital gains for which no future income tax asset has
been recognized in the accounts.
10. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in Non-cash Working Capital
For the years ended December 31,
($000's) 2006 2005
-------------------------------------------------------------------------
Accounts receivable (9,690) (6,547)
Prepaid expenses and deposits (1,100) (187)
Accounts payable and accrued liabilities 11,291 9,904
Taxes payable (63) 34
Non-cash working capital acquired (note 4) (8,438) -
-------------------------------------------------------------------------
(8,000) 3,204
Change in non-cash working capital related to
investing activities 1,016 (1,044)
-------------------------------------------------------------------------
Change in non-cash working capital related to
operating activities (9,016) 4,248
-------------------------------------------------------------------------
Cash interest and taxes paid
For the three and twelve months ended December 31,
Three Three Twelve Twelve
months months months months
($000's) 2006 2005 2006 2005
-------------------------------------------------------------------------
Income and other taxes 69 23 220 103
Interest 972 113 2,627 328
-------------------------------------------------------------------------
11. RELATED PARTY TRANSACTIONS
A consulting firm is contracted from time to time in which one of its
directors is the chairman and founding 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 fourth quarter of 2006 were nil and
$58,000 for the year ended December 31, 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
fourth quarter of 2006 were $39,000 and $571,000 for the year ended
December 31, 2006. The 2006 fees related to assistance with the Berland
acquisition and the related equity issues, the equity issue in October
2006 and general corporate matters.
12. FINANCIAL INSTRUMENTS
Fair Value of Financial Instruments
Financial instruments recognized on the balance sheets consist of cash
and cash equivalents, accounts receivable, long-term investments,
accounts payable, bank loans and financial derivatives used to manage
natural gas price risk. The fair value of these financial instruments
approximates their carrying amounts due to their short terms to maturity
except for the financial derivatives which values are outlined below.
(a) Credit Risk
Accounts receivable are with customers, sales agents and joint venture
partners in the petroleum and natural gas business and are subject to the
usual credit risks. The Company mitigates this risk by entering into
transactions with long-standing, reputable counterparties and partners.
If significant amounts of capital are to be spent on behalf of a joint
venture partner the partner is "cash called" in advance of the capital
spending taking place.
(b) Interest Rate Risk
The Company is exposed to fluctuations in interest rates on its bank
debt.
(c) Foreign Exchange Risk
The Company is exposed to the risk of changes in the Canadian/US dollar
exchange rates on sales of commodities that are denominated in U.S.
dollars or directly influenced by U.S. dollar benchmark prices.
(d) Commodity Price Risk Management
The following is a summary of natural gas price risk management
derivative contracts in effect as of December 31, 2006. All contracts are
priced in Canadian dollars per gigajoule (GJ). The price per GJ can be
converted to an approximate price per MCF by multiplying the per GJ price
by 1.05. GJ can be converted to an approximate MCF volume by multiplying
the GJ volume by 0.95.
-------------------------------------------------------------------------
Daily quantity Term of Contract Fixed price per gigajoule
(GJ)
-------------------------------------------------------------------------
2,000 January 1 to March 31, 2007 $6.00 floor; $11.05 cap
-------------------------------------------------------------------------
2,000 April 1 to October 31, 2007 $6.00 floor; $8.50 cap
-------------------------------------------------------------------------
2,000 November 1 to December 31, 2007 $6.00 floor; $11.05 cap
-------------------------------------------------------------------------
2,000 January 1 to March 31, 2007 $7.00 floor; $9.85 cap
-------------------------------------------------------------------------
2,000 April 1 to October 31, 2007 $7.00 floor; $8.00 cap
-------------------------------------------------------------------------
2,000 November 1 to December 31, 2007 $7.00 floor; $9.85 cap
-------------------------------------------------------------------------
The fair value of the above natural gas derivative instruments
marked-to-market as at December 31, 2006, results in an unrealized gain
of $635,000. There were no realized gains or losses on derivative
instruments in 2006 and there were no derivative instruments outstanding
in 2005.
13. GOODWILL
The Company tested the goodwill balance as at December 31, 2006 taking
into account the decline in corporate economic value caused by the 2006
decline in the share price. Recent oil and gas asset sales and corporate
sale transactions were also benchmarked for the goodwill test. Based on
the Company's assessment, it was determined that the estimated fair value
of the assets was less than the book value including the amount of
goodwill that was being carried on the balance sheet. As a result, the
Company recorded an impairment of goodwill in the amount of $24.2 million
representing 54 percent of the goodwill balance.
14. PER SHARE INFORMATION
The weighted average number of common shares outstanding during the
quarter ended December 31, 2006 of 91,110,107 was used to calculate basic
and diluted income (loss) per share (2005 - 53,372,046). The weighted
average number of common shares outstanding during the 12 months ended
December 31, 2006 of 86,178,274 was used to calculate basic and diluted
income (loss) per share (2005 - 48,500,438). Outstanding options have not
been included in the calculation of per share information as they were
anti-dilutive. The total number of shares which are potentially dilutive
in future periods as of December 31, 2006 was 4,416,200. The total number
of shares outstanding as of the date of the MD&A is 92,947,064.
15. COMMITMENTS
Commitments exist for leased office space and vehicles. The amounts for
leased space exclude operating costs, taxes, insurance and utilities:
Amount
Year $000's
---------------------------
2007 208
2008 168
2009 112
Thereafter -
---------------------------
Total 488
---------------------------
Directors and officers are indemnified against any and all claims or
losses reasonably incurred in the performance of their service to the
Company to the extent permitted by law. The Company has acquired and
maintains liability insurance for its directors and officers.
A fixed price contract to sell 2,000 GJ per day from January 1 to
October 31, 2007 at a price of $7.65 per GJ was also entered into for the
purpose reducing exposure to natural gas price volatility.
16. COMPARATIVE FIGURES
Certain figures have been re-classified to conform to the financial
statement presentation adopted in 2005.
Caution Regarding Forward Looking Information
This press release contains forward looking 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. Forward looking information in this Press Release includes, but is not limited to, statements with respect to capital expenditures and related allocations, production volumes, production mix and commodity prices.
Forward-looking statements and information are based on current beliefs as well as assumptions made by and information currently available to Berens concerning anticipated financial performance, business prospects, strategies and regulatory developments. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.
By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors 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 abandonment 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.
The forward-looking statements contained in this press release are made as of the date of this press release, and Berens does not undertake any obligation to up-date publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. This cautionary statement expressly qualifies the forward-looking statements contained in this press release.
%SEDAR: 00020114E