Berens Energy Ltd. releases financial results for the fourth quarter and year ended December 31, 2007
Thu Mar 27, 10:12 AMSymbol: BEN - TSX
CALGARY, March 27 /CNW/ -
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FINANCIAL AND OPERATING HIGHLIGHTS
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($ Cdn thousands, Three months Twelve months
except as noted) ended December 31, ended December 31,
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% %
2007 2006 Change 2007 2006 Change
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Sales volume
Natural gas
(mcf/day) 19,018 18,440 3% 18,981 17,420 9%
Oil and ngls
(bbl/day) 626 483 30% 564 469 20%
boe/day (6 to 1) 3,796 3,556 7% 3,728 3,373 11%
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Revenue net of
royalties 13,214 11,213 18% 49,609 40,118 24%
Net income (loss) (680) (21,951) (27,440) (28,340)
Per share (basic
and diluted) $(0.01) $(0.24) $(0.30) $(0.33)
Funds from
operations(1) 7,991 6,118 31% 29,554 22,471 32%
Per share (basic
and diluted)(1) $0.09 $0.07 29% $0.32 $0.26 23%
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Capital costs
Exploration and
development 5,986 11,474 35,468 52,807
Land and seismic 412 896 3,807 3,583
Other 4 37 56 295
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Total 6,402 12,407 (48%) 39,331 56,685 (31%)
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Net wells
completed (No.)
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Natural gas 3 6 14 25
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Oil - - 2 -
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Dry - 1 2 4
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Total 3 7 18 29
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Net working capital
(deficit) -
including bank
debt (59,516) (56,271) 6% (59,516) (56,271) 6%
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Shares outstanding
End of period
(000's) 93,172 92,947 - 93,172 92,947 -
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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.
Message to the shareholders
2007 has been a strong operational year for Berens. We entered 2007
excited about momentum that we had established with strong drilling success in
the second half of 2006. We were achieving repeated drilling success in
Pembina and were convinced we had found an advantage in the area based on
strong integration of technology, geology and geophysics. We were committed to
disciplined cost management for both drilling and operations as industry cost
pressures remained high. We kept a keen eye on natural gas prices and adjusted
our capital spending program to ensure that we could fund most of our spending
with cash flow. Natural gas prices were uncertain and very weak at times
during 2007 so we had to manage our business carefully.
We delivered:
- Drilling success continued with an overall success rate of 86% on our
drilling program. More importantly we had 100% success in our key
growth areas of Pembina and Deep Basin.
- We further defined our Pembina play and have significantly reduced
the risk profile in the area using our integrated technical approach,
evident not only in our drilling success rate but also in our
improved reserve additions.
- We applied a disciplined approach to cost control which delivered
wells and production at significantly lower costs when combined with
easing cost pressures in our industry.
The results are evident:
- Average annual production increased 11% year over year
- Long term value was strengthened with a reserves increase of 16% and
a lengthening of our reserve life index ("RLI") from 6 to 6.5 years.
We replaced production by 2 times with new reserves. All done with
the drill bit.
- Finding and development costs were $12.85 including future
development capital (National Instruments 51-101 definition). We
believe these results are first quartile performance in our industry.
- New wells in Pembina, targeting trends based on our technology, were
40 percent better in terms of production and reserves than we have
experienced historically.
- Operating costs averaged $7.55 for 2007, down 4% from 2006 and we
were drilling wells by the end of 2007 at costs 25% lower than a year
ago.
We are well positioned for 2008
So far in 2008 we are 6 for 6 in Pembina and 2 for 3 in our exploratory efforts in Deep Basin, continuing with the success we had in 2007. Costs continue to come down and we are drilling wells for costs that we have not seen since 2004. We have an extensive inventory of 100 drilling prospects across our three core areas, all on our existing land base. Most of our prospects are seismically defined with low risk. The 2008 capital program is focused on the drill bit with 90 percent of our planned capital targeted for drilling, completion, equipping and tie in activities. We continue to add land in Pembina, with an additional nine sections added already in 2008, building further our strong land position in this key growth area.
Natural gas prices appear more stable and strong after a year of uncertainty and weakness. There is optimism in our industry that the stronger natural gas prices are more sustainable in 2008 and beyond. We continue to be vigilant and ready to adjust our spending as commodity prices increase or decrease.
Berens is prospect rich and looks forward to opportunities to step up our activities as we see strength in natural gas prices. Our staff is committed and enthused about our success and looking forward to build on the momentum established in 2007. I would like to offer special thanks to our staff and management for their efforts and achievements and to our board of directors for their guidance and support in 2007.
Our shareholders experienced a difficult year in 2007 as the oil and gas sector fell out of favor and selling was indiscriminate. We thank those who stood with us through 2007 and we believe in time, you will reap the rewards of our operational success.
Sincerely,
Daniel F. Botterill
President & Chief Executive Officer
Fourth Quarter 2007 Operating Highlights
- Drilling - A total of 4 wells (2.9 net) were drilled in the fourth
quarter, all successful natural gas wells. On a full year basis in
2007, 29 (17.6 net) wells have been drilled with 23 (13.5 net)
natural gas wells, 2 (2.0 net) oil wells and four (2.1 net)
unsuccessful wells for a net success rate of 86 percent. In the key
growth areas of Pembina (12 wells) and the Deep Basin (4 wells),
100 percent drilling success was achieved.
- Reserves - Total working interest proved plus probable reserves as at
December 31, 2007 were 9,016,000 boe, an increase of 16 percent
compared to proved plus probable reserves at December 31, 2006. On a
per share basis proved plus probable reserves also grew 16 percent to
96.8 boe/1000 shares outstanding from 83.5 boe/1000 shares
outstanding. Reserves growth came entirely from the successful 2007
exploration and development drilling program. Berens replaced
production 2.0 times through the addition of new proved plus probable
reserves from the exploration and development drilling program (net
of revisions). The reserve growth in 2007 was accomplished with a net
capital program that was funded almost entirely with cash flow as
debt and working capital grew only $2.9 million during 2007.
- Production - Q4 2007 production averaged 3,796 boe/d, up 7 percent
over Q4 2006 and up 5 percent over the third quarter of 2007.
Production additions in the fourth quarter of 2007 were delivered by
ongoing drilling and tie-ins in Pembina and the completions and tie
in of a summer drilling program in Lanfine. On a full year basis,
volume in 2007 averaged 3,728 boe/d, up 11 percent compared to 2006.
- Production Costs - Costs averaged $7.23 per boe in Q4 2007, down 18%
compared to Q4 2006. For the 2007 year production costs have averaged
$7.55 per boe, down 4 percent compared to 2006. Berens continues to
have success in reducing unit operating cost.
- Funds from Operations - Funds from operations in Q4 2007 was
$8.0 million ($0.09 per share), up 31 percent compared to Q4 2006
funds from operations of $6.1 million ($0.07 per share) and up
17 percent from Q3 2007. Higher production in Q4 2007 was
complemented by reduced operating costs and higher commodity prices
to deliver the increase. December 31, 2007 debt and working capital
was 1.86 times annualized Q4 funds from operations.
- Land - Berens total undeveloped land currently stands at 100,000 net
acres almost all of which is now owned with little remaining land yet
to be earned on farm-ins. Ninety-eight percent of the undeveloped
lands are located in our three core areas of Pembina, Deep Basin and
Lanfine. The 2008 drilling program is based entirely on existing
Berens' controlled undeveloped acreage on which there exist an
inventory of 100 locations.
RESERVES
Berens' oil and gas reserves were independently evaluated by GLJ Petroleum Consultants ("GLJ"). The evaluation was completed using the reserves definitions in the Canadian Oil and Gas Evaluation Handbook and the Canadian Securities Administrators National Instrument 51-101 ("NI 51-101"). Total working interest proved plus probable reserves as at December 31, 2007 were 9,016,000 boe, an increase of 16 percent compared to proved plus probable reserves at December 31, 2006. On a per share basis proved plus probable reserves also grew 16 percent to 96.8 boe/1000 shares outstanding from 83.5 boe/1000 shares outstanding. Reserves growth came entirely from the successful 2007 exploration and development drilling program. The table below summarizes Berens' working interest reserves on a gross basis (before deduction for royalties) as at December 31, 2007 using forecast prices and costs based on the GLJ January 1, 2008 price forecast.
SUMMARY OF OIL AND GAS RESERVES(1)
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WORKING INTEREST
RESERVES OIL AND LIQUIDS NATURAL GAS
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2007 2006 Percent 2007 2006 Percent
RESERVES CATEGORY (Mbbl) (Mbbl) Change (MMcf) (MMcf) Change
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PROVED
Developed
Producing 1,050 743 +41% 21,855 18,770 +16%
Developed
Non-Producing 82 148 -44% 1,440 4,266 -66%
Undeveloped 198 100 +98% 4,746 3,381 +40%
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TOTAL PROVED 1,330 991 +34% 28,041 26,417 +6%
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PROBABLE 665 496 +34% 14,085 11,256 +25%
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TOTAL PROVED
PLUS PROBABLE 1,995 1,487 +34% 42,126 37,673 +12%
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WORKING INTEREST
RESERVES BOE
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2007 2006 Percent
RESERVES CATEGORY (Mbbl) (Mbbl) Change
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PROVED
Developed
Producing 4,693 3,871 +21%
Developed
Non-Producing 322 858 -62%
Undeveloped 989 664 +49%
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TOTAL PROVED 6,003 5,393 +11%
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PROBABLE 3,013 2,372 +27%
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TOTAL PROVED
PLUS PROBABLE 9,016 7,765 +16%
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WORKING INTEREST BEFORE TAX 8% BEFORE TAX 10%
RESERVES PRESENT VALUE(1) PRESENT VALUE(1)
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2007 2006 Percent 2007 2006 Percent
RESERVES CATEGORY ($000's) ($000's) Change ($000's) ($000's) Change
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PROVED
Developed
Producing 91,839 73,824 +24% 86,962 69,432 +25%
Developed
Non-Producing 5,316 14,977 -65% 4,842 14,013 -65%
Undeveloped 7,685 4,626 +66% 6,640 3,731 +78%
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TOTAL PROVED 104,840 93,427 +12% 98,444 87,176 +13%
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PROBABLE 39,020 35,174 +11% 34,215 31,073 +10%
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TOTAL PROVED
PLUS PROBABLE 143,860 128,601 +12% 132,659 118,249 +12%
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(1) It should not be assumed that the present values of estimated future
net cash flows shown above are representative of the fair market
value of the reserves. There is no assurance that such price and cost
assumptions will be attained and variances could be material. The
recovery and reserves estimates of crude oil, NGL and natural gas
reserves provided herein are estimates only and there is no guarantee
that the estimated reserves will be recovered. Actual crude oil,
natural gas and NGL reserves may be greater than or less than the
estimates provided herein.
Based on fourth quarter 2007 average production volume the proved plus probable reserve life index at December 31, 2007 is 6.5 years, up from 6.0 years compared to December 31, 2006. The majority of reserve growth in 2007 came at Pembina and Deep Basin where wells typically have long reserve life. Oil and liquids represent 22 percent of December 31, 2007 reserves, up from 19 percent at December 31, 2006 as the majority of the reserves added through 2007 have been from liquids rich natural gas wells in Pembina and the Deep Basin.
The following table reconciles the reserve additions from capital spending, dispositions and revisions to opening estimates.
RECONCILIATION OF
COMPANY INTEREST RESERVES
BY BARREL OF OIL EQUIVALENT
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Proved Plus
Proved Probable
FACTORS (Mboe) (Mboe)
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December 31, 2006 5,393 7,765
Discoveries 174 238
Extensions 1,691 2,738
Infill drilling - -
Technical revisions 191 (259)
Acquisitions - -
Dispositions (88) (108)
Production(1) (1,358) (1,358)
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December 31, 2007 6,003 9,016
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GLJ has also calculated the effects of the Alberta New Royalty Framework ("NRF") on the December 31, 2007 asset value based on low and high case assumptions as defined by GLJ and other reserve engineering firms in Calgary. The evaluation established that on a worst case basis, net asset value would remain unchanged at $132.7 million on a before tax 10% discount basis. In the high case, net asset value would increase by over 3 percent to $137.0 million. This is consistent with the Company's expectations based on its current asset mix and GLJ's December 31, 2007 price assumptions.
All calculations converting natural gas to crude oil equivalent have been made using a ratio of six thousand cubic feet ("mcf") of natural gas to one barrel of crude oil 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.
Finding and Development Costs
Capital spending in 2007 was $32.9 million including $1.4 million spent on land and net of the Marten Hills disposition ($6.75 million). Net future capital as at December 31, 2007 is estimated at $21.2 million compared to $15.4 million at December 31, 2006. Proved plus probable finding and development costs for 2007 excluding land capital and including the change in future development capital of $5.8 million was $12.85 per boe. Including technical revisions, proved plus probable finding and development costs were $14.12 per boe in 2007. It should be noted that GLJ did not include 2007 reserve additions for first quarter drilling results in Marten Hills as it was sold prior to year end. The Company spent $4.6 million in Marten Hills in the first quarter of 2007 that is included in its 2007 capital spending of $32.9 million.
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
2007 2006 2005 Totals
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Total capital for seismic,
exploration and development
(excluding land capital) ($000's) 31,059 53,101 25,706 109,866
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Future development capital -
proved ($000's) 15,112 12,600 1,240 13,872
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Future development capital -
proved plus probable ($000's) 21,187 15,400 1,380 19,807
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Reserve extensions, discoveries
and dispositions - proved (Mboe) 1,777 2,222 946 4,945
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Reserve extensions, discoveries
and dispositions - proved plus
probable (Mboe) 2,868 3,271 1,273 7,412
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Finding and development costs -
proved (per boe) $18.89 $29.01 $28.48 $25.02
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Finding and development costs -
proved plus probable (per boe) $12.85 $20.52 $21.28 $17.50
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Three year average finding and development costs on a proved plus probable
basis for exploration and development activities were $17.50 per boe, an
improving trend from the three year average at the end of 2006 of $18.19 due
to strong results in 2007. Early 2008 drilling success in Pembina and the Deep
Basin points to continued strong finding and development cost efficiency.
Net Asset Value
The Company's net asset value at December 31, 2007 based on the year end
reserves as evaluated by GLJ, including land and debt and working capital is
presented below. The net asset value as determined below may not necessarily
reflect the current market value of the Company.
Category ($000s) $/share(1)
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Proved reserves (discounted at 10%)(2) 98,444 1.06
Probable reserves (discounted at 10%)(2) 34,215 0.37
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132,659 1.43
Land (book value) 21,159 0.23
Debt & Working Capital Deficit (59,516) (0.64)
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Net Asset Value - December 31, 2007 94,302 1.03
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(1) Per share values are based on basic shares outstanding of 93,172,064
as there were no stock options in the money as at December 31, 2007.
(2) Based on an independent evaluation by GLJ effective December 31, 2007
using forecast prices and costs and calculated before deducting
future income taxes.
Berens Energy Ltd.
Annual and Fourth Quarter 2007
Management's Discussion and Analysis ("MD&A")
March 26, 2008
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 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, 2007 audited financial statements and notes thereto. This MD&A was prepared using information that is current as of March 26, 2008 unless otherwise noted.
STRATEGY AND OBJECTIVES
The Company established key performance metrics for 2008 that are evaluated and reviewed quarterly within the context of a planned $30 million capital program plan that is funded by cash flow. Key performance metrics include production volume growth, finding and development costs, reserve additions, operating and corporate netbacks and return on investment.
Volume growth is an important equity market measurement that is reported frequently and measures the ability of the capital spending program to add near term cash flow. The Company expects to exit 2008 with production in a range from 4,100 to 4,300 boe/d, up over 10 percent compared to fourth quarter 2007 average production of 3,796 boe per day.
Longer term value is achieved by adding oil and natural gas reserves at low cost. The Company expects to replace 1.5 times 2008 production with new reserves at finding and development costs below $15.00/boe. Operating and corporate netbacks are expected to be $28.00 and $22.00 respectively assuming a $7.00 per mcf price for natural gas and $80.00 per barrel for oil. Resulting recycle ratios based on the above factors are over 1.9 times on an operating netback basis and 1.5 times based on the corporate netback. Both of these measures deliver long term added value.
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
2007
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($000's except as noted) Q4 Q3 Q2 Q1
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Sales volumes:
Natural gas (mcf/day) 19,018 18,288 19,919 18,705
Oil and natural gas
liquids (bbl/day) 626 570 560 499
Barrels of oil equivalent 3,796 3,618 3,880 3,617
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Financial:
Net revenue 13,214 11,864 12,739 11,793
Net (loss) (680) (23,157) (557) (3,043)
per share - basic
($/share) $(0.01) $(0.25) $(0.00) $(0.03)
per share - diluted
($/share) $(0.01) $(0.25) $(0.00) $(0.03)
Capital costs 6,718 8,541 6,208 18,329
Shares outstanding (000's) 93,172 93,172 93,172 92,947
Bank debt 53,900 50,800 62,700 59,980
Working capital (deficit)
including bank debt (59,516) (59,300) (64,644) (68,502)
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Per unit information:
Natural gas price ($/mcf) $6.52 $5.94 $7.60 $7.75
Oil and liquids price
($/barrel) $71.66 $64.11 $58.98 $55.24
Oil equivalent price ($/boe) $44.48 $40.14 $47.51 $47.72
Operating netback ($/boe) $26.85 $22.95 $27.88 $27.16
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Net wells completed: (No.)
Natural gas 3 5 1 5
Oil - 2 - -
Dry - 1 - 1
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Total 3 8 1 6
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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) $(0.03)
Capital costs 12,811 9,746 15,234 19,124
Shares outstanding (000's) 92,947 86,447 86,447 86,447
Bank debt 50,080 52,780 49,580 32,180
Working capital (deficit)
including bank debt (56,271) (61,783) (57,789) (47,357)
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Per unit information:
Natural gas price ($/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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Ongoing drilling has delivered the production increases for 2006 and 2007 with the decline in production for the third quarter of 2007 caused mainly by the disposition of Marten Hills production of 250 boe per day. There have been no further material acquisitions or dispositions.
RESULTS OF OPERATIONS
Production Volume
Production volume averaged 3,796 boe/d for the fourth quarter of 2007, up seven percent compared to 3,556 boe/d in the fourth quarter of 2006 and up five percent compared to the third quarter of 2007. Natural gas represented 84 percent of production in the fourth quarter of 2007 with the remaining production being 15 percent light oil and natural gas liquids and one percent conventional heavy oil. Light oil and natural gas liquids have increased as a percent of production as most of the production growth has come from liquids rich natural gas wells in Pembina and Deep Basin. Ongoing drilling success throughout 2007 has delivered steady volume increases.
A six well program was drilled in Lanfine in July. The five successful wells were not completed and put on stream until late October as the decision was made to delay production from these wells until expected improvements in natural gas prices later in the year which contributed to the growth in production from the third to the fourth quarter of 2007. The growth in production was delivered despite the sale of 250 boe/d in September 2007 at Marten Hills.
Volume averaged 3,728 boe/d for the year ended December 31, 2007, up 11 percent compared to 3,373 boe/d for the year ended December 31, 2006. Key reasons for the production growth were improved drilling success rates, primarily in Pembina combined with average well results that were 40 percent better than budgeted on a production and reserve basis. An integrated approach combining petrophysics, geophysics and geological mapping has enabled the Company to target specific trends that have been drilled at higher success rates and for better individual well results than have been experienced in the past. With few new wells to be brought on stream in early 2008, first quarter 2008 production is expected to average approximately 3,800 boe/d, flat to fourth quarter 2007 production. Production improvement is expected beginning in the second quarter of 2008 as the wells from the winter drilling program come on stream in March.
Production Revenue
Natural gas prices averaged $6.52 per mcf for the fourth quarter of 2007 down nine percent compared to $7.13 per mcf in the fourth quarter of 2006. Oil and liquids prices averaged $67.47 and $73.86 per barrel respectively in the fourth quarter of 2007 for a blended price of $71.66 per barrel, up 39 percent from the fourth quarter 2006 blended oil and liquids price of $51.54 per barrel. On a boe basis, prices averaged $44.48 in the fourth quarter of 2007, up one percent compared to $43.96 per boe in the fourth quarter of 2006. Revenue before results from hedging was up eight percent in the fourth quarter of 2007 compared to the fourth quarter of 2006 as production volume increased and prices were up slightly. An additional $2.68 per boe was realized from hedging gains during the fourth quarter of 2007 increasing total revenue per boe to $47.16.
Natural gas prices averaged $6.96 per mcf for the year ended December 31, 2007, up three percent compared to $6.75 per mcf in the year ended December 31, 2006. Oil and liquids prices averaged $60.57 and $64.08 per barrel respectively in the year ended December 31, 2007 for a blended price of $63.02 per barrel, up 10 percent from the year ended December 31, 2006 blended oil and liquids price of $57.48 per barrel. On a boe basis, prices averaged $44.98 in the year ended December 31, 2007, up five percent compared to $42.86 per boe in the year ended December 31, 2006. Revenue before results from hedging was up 16 percent in the year ended December 31, 2007 compared to the year ended December 31, 2006 as both volume and prices increased. An additional $1.65 per boe was realized from hedging gains during the year ended December 31, 2007 for total revenue per boe of $46.63. There were no volumes hedged during 2006.
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Volumes and prices Three months Year
ended December 31 ended December 31
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2007 2006 Change 2007 2006 Change
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Production revenue
($000's) 15,563 14,386 8% 61,281 52,810 16%
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Production volume
Natural gas
(mcf/d) 19,018 18,440 3% 18,981 17,420 9%
Oil and liquids
(bbl/d) 626 483 30% 564 469 20%
BOE (bbl/d) 3,796 3,556 7% 3,728 3,373 11%
Prices
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Natural gas ($/mcf) 6.52 7.13 -8% 6.96 6.75 3%
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Oil and liquids
($/bbl) 71.66 51.54 39% 63.02 57.48 10%
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BOE ($/boe) 44.48 43.96 1% 44.98 42.86 5%
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BOE ($/boe
including hedging) 47.16 43.96 7% 46.63 42.86 9%
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Royalties
Royalties averaged 21 percent of revenue for the fourth quarter of 2007 compared to 22 percent in the fourth quarter of 2006. Royalties have trended lower on a percent of revenue basis as more wells are drilled on owned and earned lands compared to earlier periods when a higher percentage of wells were drilled under farm-in arrangements that provided for overriding royalties to the farmor. Royalties averaged 23 percent of revenue for the year ended December 31, 2007 compared to 24 percent for the year ended December 31, 2006.
Royalty expense of $3.3 million was recorded in the fourth quarter of 2007, up four percent compared to the fourth quarter of 2006 reflecting higher volume offset partially by lower per unit royalty rates. Royalty expense of $13.9 million was recorded in the year ended December 31, 2007, up 10 percent compared to the year ended December 31, 2006 due to higher production volume and lower per unit royalty rates.
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Royalties Three months Year
ended December 31 ended December 31
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2007 2006 Change 2007 2006 Change
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Royalty expense
($000's) 3,286 3,173 4% 13,915 12,692 10%
Royalty cost per boe $9.41 $9.92 (5%) $10.23 $10.67 (4%)
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GLJ Petroleum Consultants ("GLJ") has evaluated the effects of the Alberta New Royalty Framework on the December 31, 2007 asset value based on low and high case assumptions as defined by GLJ and other reserve engineering firms in Calgary. The evaluation established that on a worst case basis, Berens' net asset value would remain unchanged at $132.7 million on a before tax 10% discount basis. In the best case, Berens' net asset value would increase by over 3 percent to $137.0 million. This is consistent with Berens' expectations based on its current asset mix and GLJ's price assumptions.
Production Expenses
Production expenses were $7.23 per boe in the fourth quarter of 2007, down 18 percent compared to $8.88 per boe in the fourth quarter of 2006. Fourth quarter 2007 costs were lower on a per unit basis as production has increased and vigilance on costs remains a key objective. In addition, the Company acquired an interest in a major Pembina processing plant in December 2006 which has reduced processing costs for natural gas produced in a portion of the Pembina area.
Production expenses were $7.55 per boe in the year ended December 31, 2007, down four percent compared to $7.89 per boe in the year ended December 31, 2006. With ongoing volume increases and cost management, it is expected future per unit operating expenses will be in the $7.50 per boe range.
Fourth quarter 2007 production expenses were $2.5 million, down 13 percent compared to the fourth quarter of 2006 due to lower per unit costs. Production expenses for the year ended December 31, 2007 were $10.3 million, up six percent compared to the year ended December 31, 2006 mainly due to higher volumes.
-------------------------------------------------------------------------
Production expenses Three months Year
ended December 31 ended December 31
-------------------------------------------------------------------------
2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
Production expenses
($000's) 2,524 2,905 (13%) 10,280 9,721 6%
Production expenses
per boe $7.23 $8.88 (18%) $7.55 $7.89 (4%)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Transportation costs increased 14 percent in the fourth quarter of 2007
compared to the fourth quarter of 2006 due to higher volume and higher per
unit costs.
Operating Netback(1)
Operating netback represents the margin realized by the production and
sale of petroleum and natural gas exclusive of results from hedging. Fourth
quarter 2007 operating netbacks improved due to higher per boe prices, lower
per unit royalty rates and lower operating costs.
-------------------------------------------------------------------------
Quarterly
Operating Netbacks Three months Year
($'s per boe) ended December 31 ended December 31
-------------------------------------------------------------------------
2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
Sales price 44.48 43.96 1% 44.98 42.86 5%
Less:
Royalties
(net of ARTC) 9.41 9.92 (5%) 10.23 10.67 (4%)
Production expenses 7.23 8.88 (18%) 7.55 7.89 (4%)
Transportation
charges 0.99 0.92 8% 0.96 0.91 5%
-------------------------------------------------------------------------
Operating netback 26.85 24.23 11% 26.24 23.39 12%
-------------------------------------------------------------------------
Operating netback
including hedging 29.53 24.23 22% 27.89 23.39 19%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) non-GAAP measure - refer to discussion on non-GAAP measures below.
General and Administrative Expenses
General and administrative ("G&A") expenses, including stock-based compensation were $1.6 million in the fourth quarter of 2007, up 68 percent compared to the fourth quarter of 2006. Stock based compensation was higher as total outstanding options increased. Also, increased incentive bonus payments were paid in the fourth quarter of 2007 for the strong operating results achieved during 2007. In the year ended December 31, 2007 G&A expenses were $5.3 million, up 11 percent compared to the year ended December 31, 2006.
On per unit basis, general and administrative costs were $4.69 per boe for the fourth quarter of 2007, up 57 percent compared to $2.99 per boe in the fourth quarter of 2006. For the year ended December 31, 2007 per unit G&A costs were $3.92 per boe, almost unchanged from $3.90 per boe for the year ended December 31, 2006 as volume increases offset the dollar increase in costs for the per unit calculation. There were no general and administrative costs capitalized in the fourth quarters or for the years 2007 or 2006.
Staff levels are expected to remain fairly constant in 2008. Per unit general and administrative costs are expected to decline as production levels increase.
-------------------------------------------------------------------------
General and
administrative Three months Year
expenses ended December 31 ended December 31
-------------------------------------------------------------------------
2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
G&A expenses
($000's) 1,401 844 66% 4,433 4,090 8%
Stock based
compensation 239 133 80% 905 716 26%
-------------------------------------------------------------------------
1,640 977 68% 5,338 4,806 11%
G&A expenses per boe $4.69 $2.99 57% $3.92 $3.90 1%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Interest Expense
Interest expense was $0.9 million in the fourth quarter of 2007 compared to $1.0 million in the fourth quarter of 2006. For the year ended December 31, 2007 interest expense was $4.0 million compared to $2.6 million for the year ended December 31, 2006. Berens raised equity in the fourth quarter of 2005 in anticipation of the acquisition of Berland and had a significant cash position at the start of 2006. 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 and the first quarter of 2007 were higher than funds from operations resulting in higher average debt levels in the 2007 periods compared to the same periods in 2006. Since the first quarter of 2007 the Company's capital program has been funded by cash flows and debt has declined. Average interest rates on the bank line were similar comparing 2007 to 2006.
-------------------------------------------------------------------------
Interest Expense Three months Year
ended December 31 ended December 31
-------------------------------------------------------------------------
2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
Interest expenses
($000's) 949 972 (2%) 4,028 2,627 53%
Interest expenses
per boe $2.72 $2.97 (8%) $2.96 $2.13 39%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Depletion, Amortization and Accretion
Depletion, amortization and accretion ("DA&A") totaled $9.4 million
($26.85 per boe) in the fourth quarter of 2007, down two percent compared to
$9.6 million ($29.24 per boe) in the fourth quarter of 2006. Ongoing drilling
success and low cost reserve additions have brought down per boe DA&A rates
eight percent in the fourth quarter of 2007 compared to the fourth quarter of
2006. In the year ended December 31, 2007 DA&A totaled $39.2 million
($28.79 per boe) up seven percent but four percent lower on a boe basis
compared to $36.7 million ($29.85 per boe) for the year ended December 31,
2006.
-------------------------------------------------------------------------
Depletion,
Amortization Three months Year
and Accretion ended December 31 ended December 31
-------------------------------------------------------------------------
2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
DA&A expenses
($000's) 9,379 9,569 (2%) 39,180 36,746 7%
DA&A expenses
per boe $26.85 $29.24 (8%) $28.79 $29.85 (4%)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Income Taxes
The Company does not expect to pay current income tax during 2008 as there are sufficient capital cost pools and expected future capital spending to shelter taxable income. Current taxes were recorded for flow through share taxes paid in 2007 for 2006 flow through share issue.
Future tax recovery was $2.2 million for the fourth quarter of 2007 (77 percent of loss before taxes) compared to a recovery of $5.2 million for the fourth quarter of 2006 (19 percent of loss before taxes). The percent recovery of future tax was lower in the fourth quarter of 2006 as non-taxable $24 million goodwill impairment was recorded in the fourth quarter of 2006. Future tax recovery was $4.3 million for the year ended December 31, 2007 (14 percent of loss before taxes) compared to a recovery of $10.2 million for the year ended December 31, 2006 (27 percent of loss before taxes). The 2006 recovery was higher as significant tax rate reduction benefits were recorded in 2006 for enacted corporate income tax rate reductions.
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).
The Company recorded a partial impairment of goodwill in the fourth quarter of 2006. Since that time oil and gas company valuations eroded further, especially those of natural gas weighted producers primarily due to the decline in natural gas prices and high service costs in the industry. The Company tested the goodwill balance as at September 30, 2007 taking into account the decline in corporate economic value caused in 2007 by the 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 for the remaining amount of the goodwill balance of $20.8 million in the third quarter of 2007.
NET LOSS
The net loss for the fourth quarter of 2007 was $0.1 million ($0.01 per share) compared to a loss of $22.0 million ($0.24 per share) in the fourth quarter of 2006. Goodwill impairment was recorded in the fourth quarter of 2006 causing the higher loss in that period.
The net loss for the year ended December 31, 2007 was $27.4 million ($0.30 per share) compared to a net loss of $28.3 million ($0.33 per share) for the year ended December 31, 2006. Both annual periods had goodwill impairments recorded resulting in the majority of the losses.
CAPITAL COSTS
Capital costs were $6.4 million in the fourth quarter of 2007 compared to $13.3 million in the fourth quarter of 2006. A total of three net wells were drilled in the fourth quarter of 2007 compared to eight net wells in the fourth quarter of 2006. In both quarterly periods the main activity was in the Pembina area. For the year ended December 31, 2007 $32.9 million of capital costs were incurred compared to $57.1 million for the year ended December 31, 2006 with 18 net wells drilled in 2007 compared to 29 net wells in 2006. Capital spending in 2006 also included $102.7 million for the acquisition of Berland. The 2006 period reflects a very active capital program following the acquisition of Berland Exploration in January 2006. The 2007 capital program was funded almost entirely by cash flow resulting in 16 percent reserve growth with a six percent increase in debt.
-------------------------------------------------------------------------
Three months
ended Year ended
($000's) December 31, December 31,
-------------------------------------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Drilling and completion 3,510 8,509 24,846 39,465
Equipping and tie-ins 2,476 2,965 10,621 13,342
Land 42 512 1,418 2,535
Geological and geophysical 370 384 2,390 1,048
Office and other 4 37 56 295
-------------------------------------------------------------------------
Total 6,421 12,407 39,331 56,685
Asset retirement obligation - 143 297 462
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total exploration and
development 6,421 12,550 39,628 57,140
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net acquisitions (dispositions) - 766 (6,750) 102,723
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total capital 6,421 13,316 32,878 159,870
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Drilling, completion, equip and tie-in activity represented 93 percent of the capital spent in the fourth quarter of 2007 and 90 percent of capital for the year ended December 31, 2007 as capital activity focused on developing the extensive land base. A $30 million capital budget is planned for 2008, 89 percent of which is targeted toward drilling, completion, equip and tie-in activity. It is expected that 2008 capital spending will be funded by cash flow provided by operating activities.
WORKING CAPITAL
Accounts receivable of $10.3 million at December 31, 2007 were primarily revenue receivables ($5.8 million) and amounts owing from partners ($4.3 million). Accounts payable at December 31, 2007 of $16.5 million were mainly comprised of trade payables for capital and operating costs ($8.9 million), royalties ($1.5 million), amounts owing to partners ($1.3 million), unspent cash calls received from partners ($2.0 million) and capital costs accrued at the end of the quarter for ongoing drilling and completion operations ($1.4 million).
Working capital excluding bank indebtedness was in a deficit position of $5.6 million at December 31, 2007. 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 $62.5 million at December 31, 2007, secured by producing properties. At December 31, 2007, $53.9 million was drawn on the bank line. Future capital spending is planned at amounts that can be met with expected Company cash flow.
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 those 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 for 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 as follows:
-------------------------------------------------------------------------
Three months
ended Year ended
($000's) December 31 December 31
-------------------------------------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Cash flow provided by (used in)
operating activities 1,588 4,614 28,318 13,226
Changes in non-cash working
capital items related to
operating activities 6,403 1,504 1,236 9,245
-------------------------------------------------------------------------
Funds from operations 7,991 6,118 29,554 22,471
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Funds from operations are also presented on a per share basis consistent with the calculation of net loss per share, whereby per share amounts are calculated using the weighted average number of shares outstanding. Funds from operations per share were $0.09 (basic and diluted) for the fourth quarter of 2007 and $0.32 per share (basic and diluted) for the year ended December 31, 2007 compared to $0.07 per share for the fourth quarter of 2006 and $0.26 for the year ended December 31, 2006.
RISKS
Primary financial risks relate to volatility of commodity prices. Interest rate and currency exchange rate fluctuations 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. The Province of Alberta has announced plans for royalty changes for both conventional oil and natural gas and oil sands operations beginning in 2009. The effect of the changes to the royalty structure in Alberta may cause measurement uncertainty for certain oil and natural gas assets as oil and gas assets are valued under the new royalty system using various commodity price scenarios.
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 for services and personnel, 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 financial derivative contracts in effect as of the date of this MD&A. 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.
-------------------------------------------------------------------------
NATURAL GAS HEDGING
-------------------------------------------------------------------------
Daily
quantity
(GJ) Term of contract Fixed price per gigajoule
-------------------------------------------------------------------------
2,000 January 1 to March 31, 2008 $7.25 floor; $8.65 cap
-------------------------------------------------------------------------
2,000 January 1 to March 31, 2008 $7.50 floor; $9.45 cap
-------------------------------------------------------------------------
2,000 January 1 to December 31, 2008 $6.65 fixed price
-------------------------------------------------------------------------
2,000 April 1 2008 to March 31, 2009 $6.72 fixed price
-------------------------------------------------------------------------
2,000 April 1 to December 31, 2008 $6.65 fixed price
-------------------------------------------------------------------------
2,000 April 1 to December 31, 2008 $6.80 fixed price
-------------------------------------------------------------------------
2,000 April 1 to October 31, 2008 $6.80 fixed price
-------------------------------------------------------------------------
2,000 April 1 to October 31, 2008 $7.45 fixed price
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CRUDE OIL HEDGING
-------------------------------------------------------------------------
Daily
quantity Fixed price per barrel
(bbl) Term of contract (US WTI translated to C$)
-------------------------------------------------------------------------
100 January 1 to December 31, 2008 $85.00 floor; $93.30 cap
-------------------------------------------------------------------------
100 January 1 to December 31, 2008 $85.00 floor; $98.10 cap
-------------------------------------------------------------------------
The fair value of the above natural gas derivative instruments marked to market as at December 31, 2007, results in an unrealized gain position of $162,000 compared to an unrealized gain position of $635,000 at December 31, 2006. There were $937,000 ($2.68 per boe) of realized gains on derivative instruments in the fourth quarter of 2007 and $2,243,000 ($1.65 per boe) for the year ended December 31, 2007. The average floor price or fixed price of the natural gas hedging transactions for 2008 is $6.87 per GJ ($7.23 per mcf) which will provide protection to corporate cash flow if natural gas prices fall below these levels. The average floor price for the oil hedges is $85.00 per barrel.
Absent the above-noted risk management contracts, the effects of changes in commodity prices on cash flow before working capital changes are summarized in the following table.
-------------------------------------------------------------------------
Commodity Price change Cash flow change ($ 000's)
-------------------------------------------------------------------------
Natural gas ($/mcf) 1.00 $5,800
-------------------------------------------------------------------------
Oil and Liquids ($/bbl) 10.00 $1,600
-------------------------------------------------------------------------
RELATED PARTY TRANSACTIONS
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 2007 were $13,000 and $206,000 for the year ended December 31, 2007.
SHARE DATA
As of the date of this MD&A the Company had 93,172,064 issued and outstanding common shares. Additionally, options to purchase 6,238,200 common shares have been issued.
DISCLOSURE CONTROLS AND PROCEDURES OVER FINANCIAL REPORTING
The Company has established procedures and internal control systems designed to ensure timely and accurate preparation of financial, internal management and other reports. Disclosure controls and procedures are in place designed 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 condition, results of operation, and cash flows as of the dates and for the periods represented.
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 are part of a process designed under the supervision of the Chief Executive Officer and the Chief Financial Officer and monitored 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.
The Company reported on these controls as part of its 2006 continuous disclosure requirements (please refer to the MD&A for the year ended December 31, 2006 available on SEDAR (www.SEDAR.com) and on our website www.berensenergy.com). There have been no changes to internal controls over financial reporting or management's assessment of the design of these internal controls in the period since December 31, 2006.
RISKS AND UNCERTAINTIES, CRITICAL ACCOUNTING ESTIMATES AND RECENT
ACCOUNTING PRONOUNCEMENTS
The MD&A is based on the consolidated financial statements, which have been prepared in Canadian dollars in accordance with GAAP. The application of GAAP requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates are based on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates under different assumptions or conditions.
For a discussion of Risks and Uncertainties, Critical Accounting Estimates and Recent Accounting Pronouncements please refer to the audited financial statements and the Annual Information Form for the year ended December 31, 2006 available on SEDAR (www.SEDAR.com) and on our website (www.berensenergy.com).
As of January 1, 2007, the Company adopted 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. CICA handbook section 1506, "Accounting Changes" was also adopted on January 1, 2007. The adoption of these standards had no effect on the presentation of the financial statements.
OUTLOOK
Berens has demonstrated production growth, controlled costs and improved drilling success. Production growth has followed the drilling success experienced in late 2006 which continued through 2007. Net drilling success in 2007 was 86 percent and the average well results for reserves and production have exceeded expectations significantly. A disciplined approach to cost management has achieved significant reduction in our cost structure supported by moderation in the overall industry cost structure. These factors combined have lowered the Company's finding and development costs in 2007 to $12.85 per boe.
Capital spending for 2008 is projected at $30 million and will be funded with cash flow from operations. Capital spending for 2008 will be focused in Pembina where the reserve life of new wells is longest and the wells have the strongest economics. There are currently 100 inventoried drilling locations on existing lands. An active drilling program is underway in the first quarter of 2008 in Pembina and Deep Basin.
Debt and working capital balances have improved and will continue to improve with the planned capital spending plans. With an extensive land base and a large number of inventoried drilling locations, management anticipates that the Company will be positioned to develop our asset base more aggressively as natural gas prices improve.
Berens Energy Ltd.
Balance Sheets
As at,
-------------------------------------------------------------------------
(000's) December 31, December 31,
2007 2006
-------------------------------------------------------------------------
ASSETS (note 8)
Current
Cash and cash equivalents (note 4) $ 1 $ 10
Accounts receivable 10,315 19,601
Unrealized gain on risk management (note 13) 162 635
Prepaid expenses and deposits 442 215
-------------------------------------------------------------------------
10,920 20,461
Property, plant and equipment (note 6) 166,405 172,404
Goodwill (notes 5 and 14) - 20,755
-------------------------------------------------------------------------
$ 177,325 $ 213,620
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Bank loan (note 8) $ 53,900 $ 50,080
Accounts payable and accrued liabilities 16,523 26,622
Taxes payable 14 29
-------------------------------------------------------------------------
70,437 76,731
Asset retirement obligations (note 7) 3,273 2,645
Future income taxes (note 10) 10,199 14,518
-------------------------------------------------------------------------
83,909 93,894
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Commitments (note 16)
Shareholders' equity
Capital stock (note 9) 148,263 148,038
Contributed surplus (note 9) 2,195 1,290
Deficit (57,042) (29,602)
-------------------------------------------------------------------------
93,416 119,726
-------------------------------------------------------------------------
$ 177,325 $ 213,620
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the financial statements
Berens Energy Ltd.
Statements of Operations and Comprehensive Loss and Deficit
For the three months and year ended December 31,
-------------------------------------------------------------------------
(000's) Three months Year
ended ended
December 31, December 31,
-------------------------------------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Revenue
Oil and natural gas
revenue $ 15,563 $ 14,386 $ 61,281 $ 52,810
Royalties, net of ARTC (3,286) (3,173) (13,915) (12,692)
-------------------------------------------------------------------------
12,277 11,213 47,366 40,118
Realized gain on risk
management (note13) 937 - 2,243 -
-------------------------------------------------------------------------
13,214 11,213 49,609 40,118
Unrealized gain (loss)
on risk management (note 13) (1,296) 635 (473) 635
-------------------------------------------------------------------------
11,918 11,848 49,137 40,753
Interest and other income - - 31 18
-------------------------------------------------------------------------
11,918 11,848 49,167 40,771
-------------------------------------------------------------------------
Expenses
Production 2,524 2,905 10,280 9,721
Transportation 346 302 1,307 1,116
Depletion, amortization
and accretion 9,377 9,569 39,180 36,747
Impairment of goodwill
(note 14) - 24,220 20,755 24,220
General and administrative
(note 12) 1,401 845 4,433 4,090
Stock-based compensation
(note 9) 239 133 905 716
Interest 949 972 4,027 2,627
-------------------------------------------------------------------------
14,836 38,946 80,887 79,237
-------------------------------------------------------------------------
Loss before income taxes (2,918) (27,098) (31,720) (38,466)
Income taxes (note 10)
Future expense (recovery) (2,241) (5,218) (4,319) (10,237)
Current expense 3 71 39 111
-------------------------------------------------------------------------
(2,238) (5,147) (4,280) (10,126)
-------------------------------------------------------------------------
Net loss and comprehensive
loss for the period (680) (21,951) (27,440) (28,340)
Deficit, beginning of period (56,362) (7,651) (29,602) (1,262)
-------------------------------------------------------------------------
Deficit, end of period $ (57,042) $ (29,602) $ (57,042) $ (29,602)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income (loss) per
share (note 15)
Basic and diluted $ (0.01) $ (0.24) $ (0.30) $ (0.33)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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,
-------------------------------------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income (loss) for
the period $ (680) $ (21,951) $ (27,440) $ (28,340)
Add items not involving cash
Depletion, amortization
and accretion 9,377 9,569 39,180 36,747
Impairment of goodwill - 24,220 20,755 24,220
Unrealized risk management
(gain) loss 1,296 (635) 473 (635)
Future income tax recovery (2,241) (5,218) (4,319) (10,237)
Stock-based compensation 239 133 905 716
-------------------------------------------------------------------------
7,991 6,118 29,554 22,471
Change in non-cash working
capital items related to
operating activities
(note 10) (6,403) (1,504) (1,236) (9,245)
-------------------------------------------------------------------------
Cash flow provided by
operating activities 1,588 4,614 28,318 13,226
-------------------------------------------------------------------------
FINANCING ACTIVITIES
Change in bank loan 3,100 (2,700) 3,820 30,330
Net proceeds from private
offerings - 11,142 - 30,955
Sale of investment - 25 29 269
Proceeds from the exercise
of stock options - - 225 -
-------------------------------------------------------------------------
Cash flow provided by
financing activities 3,100 8,467 4,074 61,554
-------------------------------------------------------------------------
INVESTING ACTIVITIES
Cash acquired through
Berland acquisition - - - 109
Cash component on Berland
acquisition - - - (28,682)
Purchase of property
and equipment (6,421) (12,581) (39,331) (56,685)
Disposition of property
and equipment 6,750
Change in non-cash working
capital items related to
investing activities
(note 10) 1,733 (534) 180 1,016
-------------------------------------------------------------------------
Cash flow used in
investing activities (4,688) (13,115) (32,401) (84,242)
-------------------------------------------------------------------------
Increase (decrease) in cash
and cash equivalents - (34) (9) (9,462)
Cash and cash equivalents,
beginning of period 1 44 10 9,472
-------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 1 $ 10 $ 1 $ 10
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the financial statements
BERENS ENERGY LTD.
Notes to Financial Statements
Years ended December 31, 2007 and 2006
1. NATURE OF OPERATIONS
Berens Energy Ltd. (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
("GAAP"). 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 centre. 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 and losses 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 using 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 petroleum and
natural 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 the six to one basis.
Office and computer equipment is amortized on a straight-line basis over
ten and four years, respectively.
Ceiling Test
The Company applies an impairment test to the net carrying amount of
petroleum and natural gas assets designed to ensure that such costs do
not exceed their estimated fair value ultimately recoverable. The test is
a two part test whereby the first step is to compare the net carrying
amount of the asset to the aggregate of estimated undiscounted future net
cash flows from production of proved reserves and the cost of unproved
properties less impairment. 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 through the
performance of the second part of the test whereby 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, is compared to 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.
Asset Retirement Obligations
The Company estimates the present value of the 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.
Goodwill
Goodwill represents the excess of purchase cost of a business over the
estimated fair value of net assets acquired at the time of a business
combination. Thereafter, goodwill is not amortized and is assessed for
impairment at least annually. If the estimated fair value of the net
assets of a reporting unit is less than their 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
reporting unit's net assets from the total fair value to determine the
implied fair value of goodwill and comparing that amount to the book
value of goodwill.
Revenue Recognition
Oil and natural gas sales are recognized when the significant risks and
rewards of ownership have transferred to the buyer, the price is
determinable and there is reasonable assurance regarding collectability
of the consideration.
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 financial
statements reflect only the Company's proportionate interest in such
activities.
Stock-Based Compensation
Under the stock option plan described in note 9, options to purchase
common shares are granted to directors, officers, employees and
consultants with option strike prices based on the market price at the
time of the grant. 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 income over the vesting period of the
option with a corresponding increase in contributed surplus.
At the time of exercise, the related amounts previously credited to
contributed surplus are also transferred to share capital. In the event
that vested options expire without being exercised, previously recognized
compensation costs associated with such stock options are not reversed.
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.
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 Canada Revenue Agency.
3. CHANGES IN ACCOUNTING POLICIES
Effective January 1, 2007, the Company adopted six new accounting
standards issued by the Canadian Institute of Chartered Accountants
("CICA"): Handbook Section 3855 "Financial Instruments - Recognition and
Measurement", Section 3861 "Financial Instruments - Disclosure and
Presentation", Section 3865 "Hedges", Section 1506 "Accounting Changes",
Section 1530 "Comprehensive Income" and Section 3251 "Equity".
Impact upon adoption of Sections 3855, 3861, 3865, 1506, 1530 and 3251
The adoption of the new standards did not have a significant impact on
the Company's financial statements due to the nature of the financial
instruments recorded on the balance sheet and the contracts to which the
Company is a party.
Financial instruments - recognition and measurement
Section 3855 establishes standards for recognizing and measuring
financial assets, financial liabilities and non-financial derivatives.
It requires that financial assets and financial liabilities, including
derivatives, be recognized on the balance sheet when the Company becomes
a party to the contractual provisions of the financial instrument or
non-financial derivative contract. Under this standard, all financial
instruments are required to be measured at fair value upon initial
recognition except for certain related party transactions. Measurement in
subsequent periods depends on whether the financial instrument has been
classified as held-for-trading, available-for sale, held-to-maturity,
loans or receivables, or other financial liabilities. Financial assets
and financial liabilities held-for-trading are measured at fair value
with changes in those fair values recognized in net income. Financial
assets held-to-maturity, loans and receivables, and other financial
liabilities are measured at amortized cost using the effective interest
method of amortization. Investments in equity instruments classified as
available-for-sale that do not have a quoted market price in an active
market are measured at cost.
Derivative instruments are recorded on the balance sheet at fair value,
including those derivatives that are embedded in financial or
non-financial contracts that are not closely related to the host
contracts. Changes in the fair values of derivative instruments are
recognized in net income, with the exception of derivatives designated as
effective cash flow hedges and hedges of the foreign currency exposure of
a net investment in a self-sustaining foreign operation, which are
recognized in other comprehensive income.
In addition, Section 3855 requires that an entity must select an
accounting policy of either expensing debt issue costs as incurred or
applying them against the carrying value of the related asset or
liability.
The financial instruments recognized on the Company's balance sheet are
deemed to approximate their estimated fair values; therefore, no further
adjustments were required upon adoption of the new sections. There were
no financial assets on the balance sheet which were designated as
held-for-trading, held-to-maturity or available-for-sale. All financial
assets were classified as loans or receivables and are accounted for on
an amortized cost basis. All financial liabilities were classified as
other liabilities.
Hedges
Section 3865 provides alternative treatments to Section 3855 for entities
which choose to designate qualifying transactions as hedges for
accounting purposes. It replaces and expands on Accounting Guideline 13
"Hedging Relationships", and the hedging guidance in Section 1650
"Foreign Currency Translation" by specifying how hedge accounting is
applied and what disclosures are necessary when it is applied.
The Company does not follow hedge accounting for its risk management
activities and therefore the adoption of Section 3865 "Hedges" did not
have any impact on the Company's financial statements.
Accounting changes
Section 1506 provides expanded disclosures for changes in accounting
policies, accounting estimates and corrections of errors. Under the new
standard, accounting changes should be applied retrospectively unless
otherwise permitted or where impracticable to determine. As well,
voluntary changes in an accounting policy are to be made only when
required by a primary source of GAAP or the change results in more
relevant and reliable information.
Comprehensive income (loss) and accumulated other comprehensive
income (loss)
Section 1530 introduces comprehensive income, which consists of net
income and other comprehensive income ("OCI"). OCI represents changes in
shareholders' equity during a period arising from transactions and
changes in prices, markets, interest rates and exchange rates. OCI
includes unrealized gains and losses on financial assets classified as
available-for-sale, unrealized translation gains and losses arising from
self-sustaining foreign operations net of hedging activities and changes
in the fair value of the effective portion of cash flow hedging
instruments.
The Company has not entered into any transactions which require any
amounts to be recorded to other comprehensive income (loss) or
accumulated other comprehensive income (loss).
Equity
Section 3251 establishes standards for the presentation of equity and
changes in equity during the reporting period. The requirements under
this Section have been presented in these annual financial statements.
Future accounting changes
On December 1, 2006, the CICA issued three new accounting standards:
Handbook Section 1535, Capital Disclosures; Handbook Section 3862,
Financial Instruments - Disclosures, and Handbook Section 3863; Financial
Instruments - Presentation. These new standards are effective
January 1, 2008. Section 1535 specifies the disclosure of (i) an entity's
objectives, policies and processes for managing capital; (ii)
quantitative data about what the entity regards as capital; (iii) whether
the entity has complied with any capital requirements; and (iv) if it has
not complied, the consequences of such non-compliance. The new
Sections 3862 and 3863 replace Handbook Section 3861, Financial
Instruments - Disclosure and Presentation, revising and enhancing its
disclosure requirements and carrying forward unchanged its presentation
requirements. These new sections place increased emphasis on disclosures
about the nature and extent of risks arising from financial instruments
and how the entity manages those risks. The Company is currently
assessing the effects of these new standards on our financial statements.
On February 13, 2008, the Canadian Accounting Standards Board ("AcSB")
confirmed the use of International Financial Reporting Standards ("IFRS")
for publicly accountable profit-oriented enterprises, beginning on
January 1, 2011 with appropriate comparative data from the prior year.
IFRS will replace the current CICA Handbook as Canadian GAAP. Under IFRS
significantly increased disclosure is required, especially for interim
reporting. While IFRS uses a conceptual framework similar to Canadian
GAAP, there are significant differences in accounting policies which must
be addressed. The effects of these new standards on the Company's
financial statements is currently being assessed.
4. 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, 2007 was 2.3 percent (2006 - 2.3 percent).
5. ACQUISITION OF BERLAND EXPLORATION LTD.
On January 18, 2006, the Company and Berland Exploration Ltd. ("Berland")
closed a previously announced arrangement that saw the Company 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, the Company also assumed $19.7 million of Berland debt and
transaction costs of $0.5 million.
The total cost to the Company 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
-------------------------------------------------------------------------
6. PROPERTY, PLANT AND EQUIPMENT
December 31, 2007 December 31, 2006
Accumulated Accumulated
depletion and depletion and
($000's) Cost depreciation Cost depreciation
-------------------------------------------------------------------------
Petroleum and natural
gas properties 274,067 108,045 241,244 69,305
Office and computer
equipment 734 351 707 242
-------------------------------------------------------------------------
274,801 108,396 241,951 69,547
-------------------------------------------------------------------------
Net book value 166,405 172,404
-------------------------------------------------------------------------
At December 31, 2007, costs of $21,159,000 (2006 - $25,907,000) related
to undeveloped land have been excluded from the depletion and
depreciation calculation. At December 31, 2007 estimated future
development costs of $15,511,000 have been included in the depletion and
depreciation calculation (2006 - $13,018,000). A ceiling test was
completed at December 31, 2007 resulting in no impairment.
Benchmark pricing used for ceiling test purposes is shown in the
following table.
Oil
--------------------------------------------
Cromer
Medium
WTI Edmonton 29.30
Cushing Par Price Hardisty API
Oklahoma 400 API Heavy degree
($US/ ($Cdn/ ($Cdn/ ($Cdn/
bbl) bbl) bbl) bbl)
---------- ---------- ---------- ---------
Year
Forecast
2008 92.00 91.10 54.02 79.26
2009 88.00 87.10 51.61 75.78
2010 84.00 83.10 49.19 72.30
2011 82.00 81.10 47.98 70.56
2012 82.00 81.10 47.98 70.56
2013 82.00 81.10 49.04 70.56
2014 82.00 81.10 50.09 70.56
2015 82.00 81.10 51.15 70.56
2016 82.02 81.12 52.21 70.57
2017 83.66 82.76 53.29 72.00
2018+ +2.0%/yr +2.0%yr +2.0%/yr +2.0%/yr
Natural gas NGLs
------------ ----------
FOB
Field
AECO-C Gate Inflation
Gas (propane/ rate(1)% Exchange
Price butane) per year rate(2)
($Cdn/ ($Cdn/ ($Cdn/ ($US/
MMbtu) bbl) MMbtu) Cdn)
----------- ---------- ---------- ---------
Year
Forecast
2008 6.75 65.59 2.0 1.00
2009 7.55 62.71 2.0 1.00
2010 7.60 59.83 2.0 1.00
2011 7.60 58.39 2.0 1.00
2012 7.60 58.39 2.0 1.00
2013 7.60 58.39 2.0 1.00
2014 7.80 58.39 2.0 1.00
2015 7.97 58.39 2.0 1.00
2016 8.14 58.40 2.0 1.00
2017 8.31 59.59 2.0 1.00
2018+ +2.0%/yr +2.0%/yr 2.0 1.00
7. 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 $3,273,000 as at
December 31, 2007 (2006 - $2,645,000) based on a total future liability
of $8,611,000 (2006 - $6,959,400). These payments are expected to be made
over the next 5 to 15 years. An inflation rate of 2 percent and a credit
adjusted risk free rate of 10 percent were used to calculate the present
value of the asset retirement obligations.
The following table reconciles the asset retirement obligations:
($000's) 2007 2006
---------------------------------------------------------------------
Obligation, beginning of year 2,645 1,223
Increase in obligation during the year 297 430
Obligation assumed from Berland acquisition - 715
Increase due to increase in inflation rate - 32
Accretion expense 331 245
---------------------------------------------------------------------
Obligation, end of year 3,273 2,645
---------------------------------------------------------------------
8. BANK OPERATING LINE
An agreement with a Canadian bank is in place for an operating bank line
totaling $62.5 million at December 31, 2007. Collateral for the facility
consists of a general assignment of book debts and a $35.0 million
debenture with a floating charge over all assets of the Company and a
$75.0 million supplemental 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, 2007 was 6.75 percent (December 31, 2006 - 7.25 percent).
9. 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, 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 5) 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
Shares issued on exercise of stock options 225,000 225
-------------------------------------------------------------------------
Balance December 31, 2007 93,172,064 148,263
-------------------------------------------------------------------------
Private Placements
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. The renouncement of these
expenditures was filed with the tax authorities during 2006 and the tax
effect of the renunciation of $9,554,000 was recognized. The expenditures
to satisfy the flow-through commitment had been made by June 30, 2007.
(c) Stock Option Plan
A stock option plan is in place under which 7,500,000 common shares have
been reserved for options to be granted to directors, officers, employees
and consultants with terms established by the Board of Directors.
Options granted under the plan generally have a five year term to expiry
and vest equally over a three year period commencing on the first
anniversary date of the grant. The exercise price of each option equals
the closing market price of the Company's common shares on the day prior
to the date of the grant.
The following table sets forth a reconciliation of the plan activity
through December 31, 2007:
2007 2006
Weighted Weighted
average average
exercise exercise
Number of price ($ Number of price ($
Options per share) Options per share)
-------------------------------------------------------------------------
Outstanding, beginning
of year 4,416,200 1.68 3,513,700 1.56
Granted 2,309,500 0.94 910,000 1.31
Forfeited (262,500) 1.99 (7,500) 2.90
Exercised (225,000) 1.00 - -
-------------------------------------------------------------------------
Outstanding, end of year 6,238,200 1.42 4,416,200 1.68
-------------------------------------------------------------------------
Exercisable 3,216,359 1.54 2,449,692 1.34
-------------------------------------------------------------------------
The following table sets forth additional information relating to the
stock options outstanding at December 31, 2007:
Options Outstanding Exercisable Options
-------------------------------------------------------------------------
Weighted Weighted
average average
exercise Weighted exercise Weighted
price average price average
Exercise price Number of ($ per years to Number of ($ per years to
range Options share) expiry Options share) expiry
-------------------------------------------------------------------------
$0.50 to $1.39 4,053,500 1.00 2.94 1,735,333 1.08 1.12
-------------------------------------------------------------------------
$1.40 to $2.29 1,127,200 1.54 2.05 866,867 1.51 1.58
-------------------------------------------------------------------------
$2.30 to $3.19 917,500 2.83 2.99 567,492 2.86 2.96
-------------------------------------------------------------------------
$3.20 to $4.09 140,000 3.24 3.07 46,667 3.24 3.07
-------------------------------------------------------------------------
6,238,200 1.42 2.79 3,216,359 1.54 1.59
-------------------------------------------------------------------------
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; 46 percent
volatility. Estimated future forfeiture assumptions are not used in
calculations as forfeitures are recognized as they occur. The weighted
average option price for options outstanding at December 31, 2007 is
$0.567 per option. For the year ended December 31 2007, $905,000 (2006 -
$716,000) was recorded 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 year ended December 31, 2007:
($000's)
---------------------------------------------------------------------
Balance, December 31, 2005 574
2006 Stock based compensation expense 716
---------------------------