Berens Energy Ltd. Symbol: BEN - TSX
CALGARY, March 26 /CNW/ -
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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% %
2008 2007 Change 2008 2007 Change
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Sales volume
Natural gas
(mcf/day) 23,632 19,018 24% 20,507 18,981 8%
Oil and ngls
(bbl/day) 882 626 41% 804 564 43%
boe/day (6 to 1) 4,821 3,796 27% 4,222 3,728 13%
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Revenue net of
royalties 15,276 13,214 16% 62,660 49,609 26%
Net income (loss) (699) (680) (3%) 443 (27,440)
Per share (basic
and diluted) $(0.01) $(0.01) $0.01 $(0.30)
Funds from
operations(1) 10,047 7,991 26% 40,829 29,554 38%
Per share (basic
and diluted)(1) $0.11 $0.09 22% $0.44 $0.32 38%
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Capital costs
Exploration and
development 9,619 5,986 33,868 35,468
Disposition - - - (6,750)
Land and seismic 2,334 412 6,369 4,293
Other 26 4 40 745
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Total 11,979 6,402 87% 40,278 33,756 19%
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Net wells
completed (No.)
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Natural gas 2 3 14 14
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Oil - - - 2
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Dry 1 - 4 2
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Total 3 3 18 18
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Net working capital
(deficit) - excluding
unrealized hedging
gains/losses (58,751) (59,678) (1%) (58,751) (59,678) (1%)
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Net working capital
(deficit) - including
unrealized heading
gains/losses (59,386) (59,516) - (59,386) (59,516) -
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Shares outstanding
End of period
(000's) 93,547 93,172 - 93,547 93,172 -
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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
We entered 2008 confident we could deliver additional growth based on our strong, repeatable drilling success experienced over the 18 months leading up to the end of 2007. We had established an advantage in Pembina based on strong integration of technology, geology and geophysics and remained committed to disciplined cost management for both drilling and operations. Natural gas prices were stronger in early 2008 and we were able to take advantage of this price strength by increasing our capital budget during the year and becoming more aggressive in exploiting our advantage. The result was an outstanding year in terms of reserve and production growth and finding and development cost efficiency.
We delivered again, as promised:
- Drilling success continued with 96% success in our key growth area of
Pembina with finding and development costs less than $10 in this key
growth area.
- We continued to further define our Pembina play and have
significantly reduced the risk in the area using our integrated
technical approach, evident not only in our drilling success rate but
also in our improved reserve and production additions.
- An exciting development in Pembina was the drilling of our first
horizontal well which was completed with a multi-stage frac and came
on production at over 8 million cubic feet per day in November and
continues to be a strong producer. This well was followed up with an
equally successful second well in early 2009 and enhances our
opportunity to further reduce finding and development costs.
- We further developed our land position in the greater Pembina area
during 2008 to continue to build our drilling location inventory.
- As planned, we improved our balance sheet by growing production and
expanding our reserve base with the discipline of spending within
cash flow.
Results continue to improve:
- Total capital, including land and future development capital and
including reserve revisions generates an all in finding and
development cost of $11.95 per boe for the year which is first
quartile in our industry. Our 2008 corporate recycle ratio was
2.4 times.
- Average annual production increased 13% year over year with fourth
quarter 2008 production up 27% over the fourth quarter of 2007.
- Long term value was strengthened with a reserves increase of 22%. We
replaced production by 230% with new reserves. All done with the
drill bit.
- On a per share basis, proved plus probable reserves increased from
96.8 boe per 1,000 shares to 117.3 boe per 1000 shares, also a
22 percent increase. Capital spending was equal to cash flow for the
year and a nominal number of shares were issued in 2008.
- We added 32 (18 net) sections of land in the Pembina area. We've
already added another 12 (9 net) sections in the greater Pembina area
so far in 2009.
Opportunity continues into 2009:
We continue to expand our play in Pembina and have enhanced the opportunity with horizontal technology. As new technologies improve we see additional opportunity in Pembina to broaden their application to further improve results.
Berens is prospect rich and we don't believe now is the time to be passive, despite current weak commodity prices and the unstable economic environment. We have worked hard to attain excellence in our operations and lower our cost structure and we intend to maintain the track record we have established. We will manage our debt levels and be ready to adjust our capital spending to meet cash flows as they change.
Our staff is committed, enthusiastic about our success and look forward to building on the achievements we have made to date. 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 2008.
Our shareholders experienced a difficult year in the stock markets in 2008. We thank those shareholders who stood with us through this past year and welcome our new shareholders. In return, we have delivered operational results that should deliver wealth to our shareholders when the markets recover.
Sincerely,
Daniel F. Botterill
President & Chief Executive Officer
Fourth Quarter 2008 Operating Highlights
- Drilling - A total of 5 wells (2.5 net) were drilled in the fourth
quarter resulting in 3 (1.7 net) successful natural gas wells. In
Pembina we were 3 (1.7 net) on 4 (2.2 net) wells with the
unsuccessful well due to mechanical difficulty. In Deep Basin we were
unsuccessful on 1 (0.3 net) well. On a full year basis in 2008, 28
(18.4 net) wells have been drilled with 21 (13.9 net) natural gas
wells and 7 (4.5 net) unsuccessful wells for a net success rate of
75 percent. In the key growth area of Pembina 16 (10.0 net) wells
were drilled resulting in 15 (9.6 net) successful gas wells for a
96 net success ratio in Pembina.
- Reserves - Total working interest proved plus probable reserves as at
December 31, 2008 were 10,972,000 boe, an increase of 22 percent
compared to proved plus probable reserves at December 31, 2007 of
9,016,000. On a per share basis proved plus probable reserves also
grew 22 percent to 117.3 boe/1000 shares outstanding from
96.8 boe/1000 shares outstanding. Reserves growth came entirely from
the successful 2008 exploration and development drilling program
which was funded entirely with cash flow. Berens replaced production
2.3 times through the addition of new proved plus probable reserves
from the exploration and development drilling program with finding
and development costs of $11.95 per boe.
- Production - Q4 2008 production averaged 4,821 boe/d, up 27 percent
over Q4 2007 and up 17 percent over the third quarter of 2008.
Production additions in the fourth quarter of 2008 were delivered by
ongoing strong results in Pembina as well as completion and tie in of
a summer drilling program in Lanfine. On a full year basis, volume in
2008 averaged 4,222 boe/d, up 13 percent compared to 2007.
- Funds from Operations - Funds from operations in Q4 2008 was
$10.0 million ($0.11 per share), up 24 percent compared to Q4 2007
funds from operations of $8.0 million ($0.09 per share). Higher
production in Q4 2008 was complemented by stable operating costs,
offset slightly by lower commodity prices. December 31, 2008 debt and
working capital was 1.5 times annualized Q4 funds from operations.
- Land - Berens total undeveloped land position currently stands at
81,000 net acres. Ninety-seven percent of the undeveloped lands are
located in our three core areas of Pembina, Deep Basin and Lanfine.
In our key growth area of Pembina the undeveloped land position
increased by 6 percent despite a very active drilling program in the
area that converted significant acreage to the developed category.
The 2009 drilling program is based entirely on existing Berens'
controlled undeveloped acreage on which there exists an inventory of
85 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"). The tables below summarize Berens' working interest reserves on a gross basis (before deduction for royalties) as at December 31, 2008 using forecast prices and costs based on the GLJ January 1, 2009 price forecast.
Highlights from the 2008 reserve report:
- Proved and probable reserves grew 22 percent to 11.0 million barrels
with growth coming entirely through the drill bit.
- On a per share basis, proved plus probable reserves increased from
96.8 boe per 1000 shares to 117.3 boe per 1,000 shares, also a
22 percent increase as capital spending was equal to cash flow for
the year.
- 2008 production replacement was 230 percent with new reserves on a
proved plus probable basis.
- Finding and development costs for the year for total capital,
including land, future development capital and reserve revisions were
$11.95 per boe on a proved plus probable basis and results in a 2008
corporate recycle ratio of 2.4 times.
- Finding and development costs for the year were $10.35 per boe on a
proved plus probable basis, excluding land capital and revisions and
including future development capital (NI51-101 definition), a
19 percent improvement compared to $12.85 per boe in 2007. On a three
year rolling average basis proved plus probable finding and
development costs are $14.47 per boe.
SUMMARY OF OIL AND GAS RESERVES(1)
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WORKING INTEREST
RESERVES OIL AND LIQUIDS NATURAL GAS
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2008 2007 Percent 2008 2007 Percent
RESERVES CATEGORY (Mbbl) (Mbbl) Change (MMcf) (MMcf) Change
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PROVED
Developed
Producing 1,240 1,050 +18% 25,536 21,855 +17%
Developed
Non-Producing 204 82 +149% 2,706 1,440 +88%
Undeveloped 244 198 +23% 5,794 4,746 +22%
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TOTAL PROVED 1,688 1,330 +27% 34,036 28,041 +21%
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PROBABLE 834 665 +25% 16,667 14,085 +18%
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TOTAL PROVED
PLUS PROBABLE 2,522 1,995 +26% 50,703 42,126 +20%
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WORKING INTEREST
RESERVES BOE
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2008 2007 Percent
RESERVES CATEGORY (Mbbl) (Mbbl) Change
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PROVED
Developed
Producing 5,496 4,693 +17%
Developed
Non-Producing 655 322 +103%
Undeveloped 1,210 989 +22%
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TOTAL PROVED 7,361 6,003 +23%
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PROBABLE 3,611 3,013 +20%
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TOTAL PROVED
PLUS PROBABLE 10,972 9,016 +22%
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WORKING INTEREST BEFORE TAX 10% BEFORE TAX 15%
RESERVES PRESENT VALUE(1) PRESENT VALUE(1)
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2008 2007 Percent 2008 2007 Percent
RESERVES CATEGORY ($000's) ($000's) Change ($000's) ($000's) Change
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PROVED
Developed
Producing 110,683 86,962 +27% 95,743 77,205 +24%
Developed
Non-Producing 12,349 4,842 +155% 10,217 3,971 +157%
Undeveloped 11,875 6,640 +79% 8,254 4,598 +80%
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TOTAL PROVED 134,907 98,444 +37% 114,214 85,774 +33%
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PROBABLE 46,484 34,215 +36% 33,901 25,911 +31%
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TOTAL PROVED
PLUS PROBABLE 181,391 132,659 +37% 148,115 111,685 +33%
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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 current production volume of 4,600 boepd the proved plus probable reserve life index at December 31, 2008 is 6.5 years, unchanged from December 31, 2007. Oil and liquids represent 23 percent of December 31, 2008 reserves, up slightly from 22 percent at December 31, 2007 as the majority of the reserves added in 2008 have been from liquids rich natural gas wells in Pembina.
The following table reconciles the reserve additions from capital spending, dispositions and revisions to opening estimates.
RECONCILIATION OF
COMPANY GROSS RESERVES
BY BARREL OF OIL EQUIVALENT
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BOE
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Proved Plus
Proved Probable
FACTORS (Mboe) (Mboe)
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December 31, 2007 6,003 9,016
Discoveries 166 254
Extensions 2,314 3,387
Technical revisions 367 (204)
Acquisitions 30 41
Dispositions (9) (12)
Economic factors 31 31
Production(1) (1,541) (1,541)
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December 31, 2008 7,361 10,972
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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
Berens 2008 capital spending on exploration and development activities was $40.1 million including $3.8 million spent on land acquisitions. Proved plus probable finding and development costs for 2008 excluding land acquisitions and including the change in future development capital was $10.35 per boe on a proved plus probable basis and $15.39 per boe on a proved only basis. On a total capital basis, including land acquisitions and technical reserve revisions, proved plus probable finding and development costs were $11.95 per boe in 2008. This results in a corporate recycle ratio for 2008 of 2.4 times. The table below provides detail on finding and development costs on a three year annual and cumulative basis to December 31, 2008.
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
2008 2007 2006 Totals
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Total capital for seismic,
exploration and development
(excluding land capital) ($000's) 36,315 31,059 53,101 120,475
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Future development capital -
proved ($000's) 17,309 15,112 12,633 16,069
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Future development capital -
proved plus probable ($000's) 22,863 21,187 15,413 21,483
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Reserve extensions, discoveries
and dispositions - proved (Mboe) 2,501 1,777 2,222 6,500
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Reserve extensions, discoveries
and dispositions - proved plus
probable (Mboe) 3,670 2,868 3,271 9,809
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Finding and development costs -
proved (per boe) $15.39 $18.89 $29.12 $21.01
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Finding and development costs -
proved plus probable (per boe) $10.35 $12.85 $20.59 $14.47
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Three year rolling average finding and development costs on a proved plus probable basis for exploration and development activities was $14.47 per boe.
Net Asset Value
The Company's net asset value at December 31, 2008 based on the year end reserves as evaluated by GLJ, including land and debt and working capital is presented below. The net asset value as determined below may not necessarily reflect the current market value of the Company.
Before tax Before tax
10% present Value 15% present Value
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$/ $/
Category ($000's) share(1) ($000's) share(1)
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Proved reserves(2) 134,907 1.44 114,214 1.22
Probable reserves(2) 46,484 0.50 33,901 0.36
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181,391 1.94 148,115 1.58
Land(3) 18,954 0.20 18,954 0.20
Debt & Working Capital Deficit (58,926) (0.63) (58,926) (0.63)
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Net Asset Value -
December 31, 2008 141,419 1.51 108,143 1.15
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(1) Per share values are based on basic shares outstanding of 93,547,064
as there were no dilutive stock options as at December 31, 2008.
(2) Based on an independent evaluation by GLJ effective December 31, 2008
using forecast prices and costs and calculated before deducting
future income taxes.
(3) Land is recorded at December 31, 2008 book value which equates to
$235 per acre.
Berens Energy Ltd.
Annual and Fourth Quarter 2008
Management's Discussion and Analysis ("MD&A")
March 25, 2009
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 Pembina, Deep Basin and Eastern 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, 2008 audited financial statements and notes thereto. This MD&A was prepared using information that is current as of March 25, 2009 unless otherwise noted.
STRATEGY AND OBJECTIVES
The Company has established key performance metrics for 2009 that are evaluated and reviewed quarterly within the context of a planned $40 million capital program plan that is funded by cash flow based on an assumed Cdn$7.00 price for natural gas at AECO and Edmonton Reference light oil at Cdn$70.00. Key performance metrics include production volume growth, finding and development costs, reserve additions, operating and corporate netbacks and return on investment. In the current environment of volatile commodity prices the Company's strategy will adhere to a capital spending program that matches corporate cash flows and as such, actual capital spending may vary from the budget amounts outlined above.
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 production volume to average 4,900 boe per day in 2009 under the $40 million capital plan, up 16 percent compared to 2008 average production of 4,222 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 2009 production with new reserves at finding and development costs below $14.00/boe. Operating and corporate netbacks are expected to be $26.00 and $21.00 respectively assuming a $7.00 per mcf price for natural gas and $70.00 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.
ECONOMIC UNCERTAINTY
Recent economic events have created volatility and an uncertain environment for stock and credit markets and commodity prices in the foreseeable future. Berens' bank line of credit has been renewed at $66 million effective June 1, 2009 at which time the line reduces by $1.0 million per month until a September 30, 2009 review date. Oil and natural gas reserves added in the first three quarters of 2009 will then be taken into consideration to re-establish all or part of the reduction in the bank line. Further, the Company has conducted its capital spending program within cash flow since the third quarter of 2006 in periods of both high and low commodity prices. During this period Berens has shown consistent growth in both reserves and production. Debt and working capital deficiency was $59.4 million at December 31, 2008.
Berens has a focused asset base with high working interest and operates approximately 85% of its planned capital spending. This high working interest and operatorship allows Berens to control the pace and focus of its capital spending to maintain financial flexibility in various commodity price and economic environments.
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
2008
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($000's except as noted) Q4 Q3 Q2 Q1
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Sales volumes:
Natural gas (mcf/day) 23,632 19,592 19,677 19,104
Oil and natural gas
liquids (bbl/day) 882 845 859 628
Barrels of oil equivalent 4,821 4,110 4,139 3,812
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Financial:
Net revenue 14,627 17,368 20,738 14,517
Net income (loss) (698) 8,167 (1,612) (5,413)
per share - basic
($/share) (0.01) 0.09 (0.02) (0.06)
per share - diluted
($/share) (0.01) 0.09 (0.02) (0.06)
Capital costs 11,979 13,997 2,715 11,586
Shares outstanding (000's) 93,547 93,547 93,547 93,172
Bank debt 54,600 48,500 53,000 58,500
Working capital (deficit)
including bank debt (59,386) (57,040) (64,943) (69,711)
Working capital (deficit)
including bank debt and
excluding unrealized
hedging gains and losses (58,751) (56,819) (51,766) (61,996)
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Per unit information:
Natural gas price ($/mcf) 7.10 8.77 10.55 8.12
Oil and liquids price
($/barrel) 47.48 100.31 103.76 81.76
Oil equivalent price ($/boe) 43.49 62.41 71.70 54.16
Operating netback ($/boe) 24.63 36.19 46.31 32.36
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Net wells completed: (No.)
Natural gas 2 8 - 5
Oil - - - -
Dry 1 2 - -
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Total 3 10 - 5
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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
($/share) (0.01) (0.25) (0.00) (0.03)
Capital costs 6,718 8,541 6,208 18,329
Shares outstanding (000's) 93,172 93,172 93,172 92,947
Bank debt 53,900 50,800 62,700 59,980
Working capital (deficit)
including bank debt (59,516) (58,594) (63,610) (67,468)
Working capital (deficit)
including bank debt and
excluding unrealized
hedging gains and losses (59,678) (60,051) (65,073) (66,896)
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Per unit information:
Natural gas price ($/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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Ongoing drilling has delivered the production increases for 2007 and 2008
with the decline in production for the third quarter of 2007 as a result of
the disposition of Marten Hills production of 250 boe per day. There have been
no other material acquisitions or dispositions.
RESULTS OF OPERATIONS
Production Volume
Production volume averaged 4,821 boe/d for the fourth quarter of 2008, up 27 percent compared to 3,796 boe/d in the fourth quarter of 2007 and up 17 percent compared to the third quarter of 2008. Natural gas represented 82 percent of production in the fourth quarter of 2008 with the remaining production being 17 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. Drilling success throughout the third quarter and early fourth quarter of 2008 delivered the fourth quarter volume increases.
A seven (4.9 net) well program was drilled in Pembina in the third quarter of 2008 with 100 percent success. The Pembina success continued into the fourth quarter with an additional 3 (1.7 net) successful natural gas wells on 4 (2.2 net) attempts. Most of the Pembina wells were brought on stream throughout the final four months of 2008 resulting most of the fourth quarter production increase. An additional four (3.8 net) successful natural gas wells in Lanfine were brought on stream late in the third quarter which also contributed to the fourth quarter volume increase. The fourth quarter drilling was highlighted by the Company's first horizontal well in Pembina which was brought on stream in late November at initial production rates in excess of eight million cubic feet per day.
Volume averaged 4,222 boe/d for the year ended December 31, 2008, up 13 percent compared to 3,728 boe/d for the year ended December 31, 2007. Production growth was delivered by ongoing drilling success, primarily in Pembina where 15 (9.6 net) successful natural gas wells were drilled on 16 (10.0 net) attempts for a net success rate of 96 percent.
First quarter 2009 production is expected to be 4,600 boepd with production gains from ongoing drilling being offset by the Company's decision to curtail a total of 250 boepd of higher production wells in Lanfine. This curtailment will preserve net asset value under the new royalty framework which became effective January 1, 2009. The first quarter 2009 drilling program includes 4 (2.4 net) wells in Pembina, three (1.7 net) of which are horizontal wells. One (0.5 net) natural gas well was also drilled in Deep Basin in the first quarter of 2009.
Production Revenue
Natural gas prices averaged $7.10 per mcf for the fourth quarter of 2008, up nine percent compared to $6.52 per mcf in the fourth quarter of 2007. Oil and liquids prices averaged $54.61 and $45.90 per barrel respectively in the fourth quarter of 2008 for a blended price of $47.48 per barrel, down 34 percent from the fourth quarter 2007 blended oil and liquids price of $71.66 per barrel. On a boe basis, prices averaged $43.49 in the fourth quarter of 2008, down two percent compared to $44.48 per boe in the fourth quarter of 2007. Revenue before results from hedging was up 24 percent in the fourth quarter of 2008 compared to the fourth quarter of 2007 as production volume increases were offset slightly by lower prices. An additional $1.47 per boe was realized from hedging gains during the fourth quarter of 2008 increasing total revenue per boe to $44.96 compared to $47.16 including realized hedging gains during the fourth quarter of 2007.
Realized natural gas prices averaged $8.56 per mcf for the year ended December 31, 2008, up 23 percent compared to $6.96 per mcf in the year ended December 31, 2007. Oil and liquids prices averaged $93.58 and $79.75 per barrel respectively in the year ended December 31, 2008 for a blended price of $83.05 per barrel, up 32 percent from the year ended December 31, 2007 blended oil and liquids price of $63.02 per barrel. On a boe basis, prices averaged $57.39 in the year ended December 31, 2008, up 28 percent compared to $44.98 per boe in the year ended December 31, 2007. Revenue before results from hedging was up 45 percent in the year ended December 31, 2008 compared to the year ended December 31, 2007 as both volume and prices were higher. Realized hedging losses reduced annual 2008 revenue by $2.98 per boe to $54.41 while in 2007 annual revenue was $1.65 per boe higher due to hedging gains for total revenue per boe of $46.63.
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Volumes and prices Three months Year
ended December 31 ended December 31
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2008 2007 Change 2008 2007 Change
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Production revenue
($000's) 19,292 15,563 24% 88,738 61,281 45%
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Production volume
Natural gas
(mcf/d) 23,632 19,018 24% 20,507 18,981 8%
Oil and liquids
(bbl/d) 882 626 41% 804 564 43%
BOE (bbl/d) 4,821 3,796 27% 4,222 3,728 13%
Prices
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Natural gas
($/mcf) 7.10 6.52 9% 8.56 6.96 23%
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Oil and liquids
($/bbl) 47.48 71.66 (34%) 83.05 63.02 32%
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BOE ($/boe) 43.49 44.48 (2%) 57.39 44.98 28%
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BOE ($/boe
including hedging) 44.96 47.16 (5%) 54.41 46.63 17%
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Royalties
Royalties averaged 24 percent of revenue for the fourth quarter of 2008 compared to 21 percent in the fourth quarter of 2007. Royalties have trended higher on a percent of revenue basis as a significant number of higher rate wells were brought on stream in 2008, primarily in Pembina. Higher volume wells incur higher crown royalty rates. Royalties averaged 24 percent of revenue for the year ended December 31, 2008 compared to 23 percent for the year ended December 31, 2007.
Royalty expense of $4.7 million was recorded in the fourth quarter of 2008, up 42 percent compared to the fourth quarter of 2007 reflecting higher volume and higher percent royalty rates. Royalty expense of $21.5 million was recorded in the year ended December 31, 2008, up 54 percent compared to the year ended December 31, 2007 due to higher production volume and higher percentage royalty rates.
-------------------------------------------------------------------------
Royalties Three months Year
ended December 31 ended December 31
-------------------------------------------------------------------------
2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Royalty expense
($000's) 4,665 3,286 42% 21,488 13,915 54%
Royalty cost
per boe $10.52 $9.41 12% $13.90 $10.23 36%
Royalty percent 24% 21% 14% 24% 23% 4%
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The effects of the Alberta New Royalty Framework ("NRF") which came in to effect on January 1, 2009 will reduce near term cash flow in a $7.00 natural gas price environment. At a $7.00 per mcf natural gas price royalties are anticipated to increase from historical 24 percent rates to approximately 27 percent. At natural gas prices in the $5.00 to $6.00 range, royalties are expected to be essentially unchanged from historical rates. The Alberta government also announced a new Transitional Royalty Framework ("TRF") which became effective on November 19, 2008 and applies to new wells drilled from 1,000 to 3,000 meters. All new Pembina wells qualify for the TRF with the result that new wells drilled after November 19, 2008 will be subject to royalty rates similar to pre-NRF until 2013 resulting in royalty burden similar to the period prior to the NRF for new production brought on stream in 2009 and beyond.
Further royalty changes and drilling royalty credits were announced by the Alberta government on March 3, 2009. Under this new program wells placed on production after April 1, 2009 will be subject to a 5% royalty rate for one year before reverting back to NRF or TRF as elected. Further, a drilling credit equal to $200 per metre drilled on wells spudded after April 1, 2009 will be awarded on Alberta crown royalties payable. Both of these programs will initially be in place for a one year period with the drilling credits available to offset up to 50% of crown royalties payable for a two year period to March 31, 2011. The Company will benefit from both of these new programs as the entire capital spending program is within Alberta. Management is currently assessing how these new programs may affect the 2009 capital spending program.
Production Expenses
Production expenses were $6.98 per boe in the fourth quarter of 2008, down 3 percent compared to $7.23 per boe in the fourth quarter of 2007. Cost control continues to be a key management objective.
Production expenses were $7.88 per boe in the year ended December 31, 2008, up four percent compared to $7.55 per boe in the year ended December 31, 2007. Inflationary pressures on costs during 2008 combined with increases in certain third party processing fees have caused increased costs. With ongoing volume increases and cost management, it is expected future per unit operating expenses will be in the $8.00 per boe range.
Fourth quarter 2008 production expenses were $3.1 million, up 23 percent compared to the fourth quarter of 2007 due to higher production volume and a slight decrease in per unit costs. Production expenses for the year ended December 31, 2008 were $12.2 million, up 18 percent compared to the year ended December 31, 2007 due to higher volumes and higher per unit costs.
-------------------------------------------------------------------------
Production expenses Three months Year
ended December 31 ended December 31
-------------------------------------------------------------------------
2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Production expenses
($000's) 3,095 2,524 23% 12,180 10,280 18%
Production expenses
per boe $6.98 $7.23 (3%) $7.88 $7.55 4%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Transportation costs increased 25 percent in the fourth quarter of 2008 compared to the fourth quarter of 2007 and 20 percent for the year ended December 31, 2008 compared to the year ended December 31, 2007 mainly due to higher production volume. On a per unit basis, transportation costs remained unchanged in the $1.00 per boe range.
Operating Netback(1)
Operating netback represents the margin realized by the production and sale of petroleum and natural gas. Fourth quarter 2008 operating netbacks, excluding the results of hedging, declined seven percent compared to the fourth quarter of 2007 mainly due to higher percent royalty burden. For the year ended December 31, 2008 operating netbacks, excluding the results of hedging, improved 32 percent compared to the year ended December 31, 2007 due to higher per boe prices, offset by higher royalty burden and higher per unit operating costs.
-------------------------------------------------------------------------
Operating Netbacks Three months Year
($'s per boe) ended December 31 ended December 31
-------------------------------------------------------------------------
2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Sales price 43.49 44.48 (2%) 57.39 44.98 28%
Less:
Royalties
(net of ARTC) 10.52 9.41 12% 13.90 10.23 36%
Production
expenses 6.98 7.23 (3%) 7.88 7.55 4%
Transportation
charges 0.97 0.99 (2%) 1.02 0.96 6%
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Operating netback 24.93 26.85 (7%) 34.59 26.24 32%
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Operating netback
including hedging 26.39 29.53 (11%) 31.61 27.89 13%
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(1) non-GAAP measure - refer to discussion on non-GAAP measures below.
General and Administrative Expenses
General and administrative ("G&A") expenses were $1.1 million in the fourth quarter of 2008, down 21 percent compared to the fourth quarter of 2007. The 2007 period incurred additional cost for increased incentive bonus payments paid in the fourth quarter of 2007 for the strong operating results achieved during 2007. In the year ended December 31, 2008 G&A expenses were $5.3 million, up 19 percent compared to the year ended December 31, 2007 due to higher salaries and inflationary pressures. In addition company operated wells were generally drilled at higher working interest than in 2007 resulting in lower capital administration costs recovered from partners.
On per unit basis, general and administrative costs were $2.49 per boe for the fourth quarter of 2008, down 38 percent compared to $4.01 per boe in the fourth quarter of 2007 due to increased production volume and lower costs. For the year ended December 31, 2008 per unit G&A costs were $3.40 per boe, up four percent from $3.26 per boe for the year ended December 31, 2007 as volume increases offset the increase in costs for the per unit calculation. There were no general and administrative costs capitalized in the fourth quarters or for the years 2008 or 2007.
Staff levels are expected to remain fairly constant in 2009. 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
-------------------------------------------------------------------------
2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
G&A expenses
($000's) 1,105 1,401 (21%) 5,255 4,433 19%
G&A expenses
per boe $2.49 $4.01 (38%) $3.40 $3.26 4%
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Stock based
compensation
($000's) 172 239 (28%) 1,033 905 14%
Stock based
compensation
per boe $0.39 $0.69 (38%) $0.67 $0.67 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Interest Expense
Interest expense was $0.6 million in the fourth quarter of 2008 compared to $0.9 million in the fourth quarter of 2007. For the year ended December 31, 2008 interest expense was $2.9 million compared to $4.0 million for the year ended December 31, 2007, a decrease of 27 percent. Average debt levels have remained consistent over the 2007 and 2008 period as the Company maintained a capital spending program that was limited to cash flow over the past two years. Interest rates declined significantly in 2008 as the worldwide banking and economic situation worsened and liquidity was added to the financial systems around the world resulting in the decline in year over year and quarter over quarter interest expense. On a per unit basis, annual interest costs have been reduced by 36 percent as production volume has increased while debt levels were essentially unchanged.
-------------------------------------------------------------------------
Interest Expense Three months Year
ended December 31 ended December 31
-------------------------------------------------------------------------
2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Interest expenses
($000's) 594 949 (37%) 2,926 4,028 (27%)
Interest expenses
per boe $1.34 $2.72 (51%) $1.89 $2.96 (36%)
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Depletion, Amortization and Accretion
Depletion, amortization and accretion ("DA&A") totaled $10.4 million ($23.35 per boe) in the fourth quarter of 2008, up 10 percent in total and down 13% on a per unit basis compared to $9.4 million ($26.85 per boe) in the fourth quarter of 2007. Ongoing drilling success and low cost reserve additions have brought down per boe DA&A rates. In the year ended December 31, 2008 DA&A totaled $38.3 million ($24.81 per boe) down two percent and down 14 percent on a boe basis compared to $39.2 million ($28.79 per boe) for the year ended December 31, 2007 as the reduction in the per unit rate more than offset the increase in cost due to increased volume.
-------------------------------------------------------------------------
Depletion,
Amortization Three months Year
and Accretion ended December 31 ended December 31
-------------------------------------------------------------------------
2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
DA&A expenses
($000's) 10,357 9,379 10% 38,336 39,180 (2%)
DA&A expenses
per boe $23.35 $26.85 (13%) $24.81 $28.79 (14%)
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Income Taxes
The Company did not pay current income tax during 2008 and does not expect to pay current income taxes in 2009 as there are sufficient capital cost pools and expected future capital spending to shelter taxable income. Current taxes were recorded for provincial capital taxes.
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 and a further impairment of goodwill for the remaining amount of the goodwill balance of $20.8 million in the third quarter of 2007.
NET INCOME (LOSS)
The net loss for the fourth quarter of 2008 was $0.7 million ($0.01 per share), a 3 percent improvement compared to a loss of $0.7 million ($0.01 per share) in the fourth quarter of 2007. Increased revenue from higher 2008 production volume was partially offset by higher royalties and slightly higher production costs.
Net income for the year ended December 31, 2008 was $0.4 million ($0.01 per share) compared to a net loss of $27.4 million ($0.32 per share) for the year ended December 31, 2007. The 2007 period had goodwill impairment recorded resulting in the majority of the losses.
CAPITAL COSTS
Capital costs were $12.0 million in the fourth quarter of 2008 compared to $6.4 million in the fourth quarter of 2007. A total of three net wells were drilled in the fourth quarter of 2008, equal to the number of net wells drilled in the fourth quarter of 2007. Two re-completions were conducted in the fourth quarter of 2008 with no re-completions conducted in the fourth quarter of 2007. In both years the main activity was in the Pembina area.
For the year ended December 31, 2008 $40.3 million of capital costs were incurred compared to $39.3 million (before disposition proceeds of $6.8 million) for the year ended December 31, 2007 with 18 net wells drilled in 2008 compared to 18 net wells in 2007. The 2008 and 2007 capital programs have been funded entirely by cash flow from operations resulting in average reserve growth of 19% per year over the two year period.
-------------------------------------------------------------------------
Three months Year
($000's) ended December 31, ended December 31,
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Drilling and completion 7,709 3,510 27,252 24,846
Equipping and tie-ins 1,910 2,476 6,617 10,621
Land 852 42 3,922 1,418
Geological and geophysical 1,482 370 2,447 2,390
Office and other 27 4 40 56
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Total cash expenditure 11,980 6,421 40,278 39,331
Asset retirement obligation (486) - (134) 297
-------------------------------------------------------------------------
Total capital before net
acquisitions (dispositions) 11,494 6,421 40,144 39,628
-------------------------------------------------------------------------
Net acquisitions (dispositions) - - - (6,750)
-------------------------------------------------------------------------
Total capital 11,494 6,421 40,144 32,878
-------------------------------------------------------------------------
Total cash expenditure 11,980 6,421 40,278 39,331
Abandonment and restoration (140) (81) (326) (123)
-------------------------------------------------------------------------
Capital per statement of
cash flow 11,840 6,340 39,952 39,208
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Drilling, completion, equip and tie-in activity represented 80 percent of the capital spent in the fourth quarter of 2008 compared to 93 percent in the fourth quarter of 2007 and 84 percent of capital for the year ended December 31, 2008 compared to 90 percent for the year ended December 31, 2007. Capital activity in 2008 was more focused on developing the land base. A $40 million capital budget is planned for 2009, 89 percent of which is targeted toward drilling, completion, equipping and tie-in activity. It is expected that 2009 capital spending will be funded by cash flow provided by operating activities and will be adjusted should lower commodity prices occur.
WORKING CAPITAL
Accounts receivable of $12.9 million at December 31, 2008 were primarily revenue receivables ($5.9 million) and amounts owing from partners ($6.4 million). Accounts payable at December 31, 2008 of $17.3 million were mainly comprised of trade payables for capital and operating costs ($10.9 million), royalties ($1.3 million), amounts owing to partners ($1.9 million) and capital costs accrued at the end of the quarter for ongoing drilling and completion operations ($2.3 million).
Working capital excluding the bank loan was in a deficiency position of $4.8 million at December 31, 2008. Borrowings under the bank line and ongoing cash flows are expected to fund the working capital deficiency.
LIQUIDITY AND CAPITAL RESOURCES
The Company plans to fund its current working capital deficiency, operations and capital costs with a mix of operating cash flow and debt financing through the bank operating line. A operating bank line was in place for $66 million at December 31, 2008, secured by producing properties. At December 31, 2008, $54.6 million was drawn on the bank line leaving $11.4 million of capacity on the line. The line of credit has been renewed at $66 million effective June 1, 2009 at which time the line reduces by $1.0 million per month until a September 30, 2009 review date. Oil and natural gas reserves added in the first three quarters of 2009 will then be taken into consideration to reestablish all or part of the reduction in the bank line. Future capital spending is planned at amounts that can be met with expected operating cash flow and the borrowing capacity within the bank line.
NON-GAAP MEASUREMENTS
This MD&A contains the term "funds from operations" and "operating netback". As an indicator of the Company's performance, these terms should not be considered an alternative to, or more meaningful than "cash flow from operating activities" or "net income (loss)" as determined in accordance with Canadian generally accepted accounting principles. The Company's determination of funds from operations and operating netback may not be comparable to 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 Year
($000's) ended December 31 ended December 31
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Cash flow provided by (used
in) operating activities 6,043 1,508 37,977 28,195
Changes in non-cash working
capital items related to
operating activities 3,664 6,403 2,527 1,236
Cost of abandonment and
restoration 140 80 326 123
-------------------------------------------------------------------------
Funds from operations 10,047 7,991 40,830 29,554
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 $0.11 (basic and diluted) for the fourth quarter of 2008 and $0.44 per share (basic and diluted) for the year ended December 31, 2008 compared to $0.09 per share for the fourth quarter of 2007 and $0.32 for the year ended December 31, 2007.
RISKS
Primary financial risks relate to volatility of commodity prices. Interest 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 announced further changes to royalties for new wells drilled after November 19, 2008 described as the Transitional Royalty Framework. The Transitional Royalty Framework adds a layer of complexity on the New Royalty Framework implemented on January 1, 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.
The Company is exposed to fluctuations in interest rates on its bank loan which charges interest at variable market rates. The Company entered into an interest rate swap transaction effective February 2008 to fix the interest rate on $25.0 million of its variable rate demand bank line. The transaction fixes the interest rate for a two year period at an underlying borrowing rate of 3.61 percent. Including the Company's borrowing margin on its bank line the current all in rate of this transaction is 5.21 percent. Fair values for interest rate derivatives are provided by the financial intermediary with whom the transactions were completed and tested by the Company for reasonableness based on comparing current market prices and the fixed prices of the contracts. The fair value of the interest rate derivative instrument marked-to-market as at December 31, 2008 results in an unrealized loss of $748,000 for the year ended December 31, 2008. There were no interest rate derivatives in place in 2007. Subsequent to the end of the year, the Company cancelled the interest rate swap and simultaneously replaced it with a $40 million fixed interest rate swap for two years beginning in February 2009 which fixes the interest rate at an underlying borrowing rate of 2.39 percent. Including the Company's borrowing margin on its bank line the current all in rate of this transaction is 3.99 percent.
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 April 1, 2008 to March 31, 2009 $6.72 fixed price -------------------------------------------------------------------------
The fair value of the above natural gas derivative instruments marked to market as at December 31, 2008, results in an unrealized gain position of $114,000 compared to an unrealized gain position of $162,000 at December 31, 2007. There were $648,000 ($1.46 per boe) of realized gains on derivative instruments in the fourth quarter of 2008 (2007 - $937,000 gain; $2.68 per boe) and realized losses of $4,589,000 ($2.98 per boe) for the year ended December 31, 2008 (2007 - $2,243,000 gain; $1.65 per boe).
Absent the above-noted risk management contracts, the effects of changes in commodity prices on cash flow before working capital changes are summarized in the following table.
------------------------------------------------------------------------- Commodity Price change Cash flow change ($ 000's) ------------------------------------------------------------------------- Natural gas ($/mcf) 1.00 4,600 ------------------------------------------------------------------------- Oil and Liquids ($/bbl) 10.00 1,500 -------------------------------------------------------------------------
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 for the quarter ended December 31, 2008 were $32,000 and for the year ended December 31, 2008 $261,000 (2007 - $27,000 and $206,000).
SHARE DATA
As of the date of this MD&A the Company had 93,547,064 issued and outstanding common shares. Additionally, options to purchase 7,397,700 common shares have been issued.
DISCLOSURE CONTROLS AND PROCEDURES
The Company's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company's Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company's disclosure controls and procedures at the financial year end of the Company and have concluded that the Company's disclosure controls and procedures are effective at the financial year end of the Company for the foregoing purposes.
INTERNAL CONTROL OVER FINANCIAL REPORTING
The Company's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, internal control over financial reporting to provide reasonable assurance regarding the reliability of the Company's financial reporting and the preparation of financial statements for external purposes in accordance with the Canadian GAAP. The control framework the Company's officers have used to design the issuer's ICFR is the COSO financial framework. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company's internal control over financial reporting at the financial year end of the Company and concluded that the Company's internal control over financial reporting is effective, at the financial year end of the Company, for the foregoing purpose the Company is required to disclose herein any change in the Company's internal control over financial reporting that occurred during the period beginning on October 1, 2008 and ended on December 31, 2008 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting. No material changes in the Company's internal control over financial reporting were identified during such period that has materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.
It should be noted that a control system, including the Company's disclosure and internal controls and procedures over financial reporting, no matter how well conceived or operated, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.
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.
CHANGES IN ACCOUNTING POLICIES Financial instruments presentation and disclosure
Effective January 1, 2008, the Company adopted the new Canadian Institute of Chartered Accountants (CICA) recommendations relating to Financial Instruments - Disclosure (section 3862) and Financial Instruments - Presentation (section 3863). The new disclosure required by section 3862 concerning the nature and extent of the risks associated with financial instruments and how those risks are managed, is presented in note 11 to the 2008 Financial Statements. Effective January 1, 2008 the Company adopted CICA recommendations relating to Capital Disclosures (section 1535).
FUTURE ACCOUNTING PRONOUNCEMENTS International Financial Reporting Standards
In February 2008, the Canadian Accounting Standards Board confirmed that the use of International Financial Reporting Standards ("IFRS") will be required in 2011 for publicly accountable profit-oriented enterprises. IFRS will replace Canada's current GAAP for listed companies and other profit-oriented enterprises that are responsible to large or diverse groups of stakeholders. Companies will be required to provide one year of comparative data in accordance with IFRS.
In the second quarter of 2008 the Company began to develop its IFRS changeover plan. Initial activities include training sessions and acquisition of written standards and examples of IFRS disclosure to identify where key differences between Canadian GAAP and IFRS exist. A key determination that has significant effect on the financial statements will be the identification of cash generating units within the Company's production properties which are currently considered as a whole. The Company intends to disclose its convergence plan and qualitative effects of IFRS on its financial statements as they become more fully developed.
Credit Risk and Fair Value of Financial Assets and Financial Liabilities
On January 20, 2009, the Emerging Issues Committee of the CICA issued Abstract No. 173, "Credit Risk and the Fair Value of Financial Assets and Financial Liabilities", concerning the measurement of financial assets and financial liabilities. There has been diversity in practice as to whether an entity's own credit risk and the credit risk of the counterparty are taken into account in determining the fair value of financial instruments. The Committee reached a consensus that these risks should be taken into account in the measurement of financial assets and financial liabilities. The Abstract is effective for all financial assets and financial liabilities measured at fair value for the interim and annual financial statements issued for periods ending on or after the date of issuance of the Abstract with retrospective application without restatement of prior periods. The Company will apply the Abstract at the beginning of its 2009 fiscal year. The Company does not expect the implementation to have a significant effect on the Company's financial position or disclosures.
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, 2008 available on SEDAR (www.SEDAR.com) and on our website (www.berensenergy.com).
OUTLOOK
Berens has developed a low cost, repeatable drilling program in Pembina which has resulted in consistent reserve and production growth over the past two years. The growth has been based on capital spending programs equal to cash flow over this same period. Net overall drilling success in 2008 was 75 percent and the average well results for reserves and production have significantly exceeded results experienced by Berens prior to 2007. A disciplined approach to cost management has achieved significant reduction in our cost structure both for drilling and ongoing operations. The Company lowered its finding and development costs in 2008 to $10.35 per boe and had operating costs of $7.88 per boe. With this low cost structure, economic returns and positive re-cycle ratios are achievable at natural gas prices as low as $5.00.
Capital spending for 2009 is projected at $40 million and will be funded with cash flow from operations based on assumptions of $7.00 per mcf at AECO and $70 light oil prices at Edmonton. However, the Company is committed to keeping the capital spending amounts within cash flow for 2009 and tracks spending and cash flows closely to ensure this commitment is met. An active drilling program of five wells is planned for the first quarter of 2009 with three of those wells being horizontal wells in Pembina. Capital spending in 2009 will be focused in Pembina where the Company has established a strong drilling record and the wells have the strongest economics. There are currently 85 inventoried drilling locations on existing company lands.
Debt and working capital will continue to be a focus for the Company. With the current weak natural gas price environment, the debt to cash flow ratio may increase due to weaker cash flows as capital spending will be held within cash flows to keep debt levels controlled.
Berens Energy Ltd.
Balance Sheets
As at,
-------------------------------------------------------------------------
(000's) December 31, December 31,
2008 2007
-------------------------------------------------------------------------
ASSETS (note 6)
Current
Cash $ 1 $ 1
Accounts receivable 12,854 10,315
Unrealized gain on risk management (note 11) 114 162
Prepaid expenses and deposits 300 442
-------------------------------------------------------------------------
13,269 10,920
Property, plant and equipment (note 4) 168,564 166,405
-------------------------------------------------------------------------
$ 181,833 $ 177,325
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Bank loan (note 6) $ 54,600 $ 53,900
Accounts payable and accrued liabilities 17,291 16,523
Unrealized loss on risk management (note 11) 748 -
Taxes payable 16 14
-------------------------------------------------------------------------
72,655 70,437
Asset retirement obligations (note 5) 3,491 3,273
Future income taxes (note 8) 10,420 10,199
-------------------------------------------------------------------------
$ 86,566 $ 83,909
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Commitments (note 14)
Shareholders' equity
Capital stock (note 7) $ 148,638 $ 148,263
Contributed surplus (note 7) 3,228 2,195
Deficit (56,599) (57,042)
-------------------------------------------------------------------------
95,267 93,416
-------------------------------------------------------------------------
$ 181,833 $ 177,325
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 December 31, ended December 31,
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
Revenue
Oil and natural gas
revenue $ 19,292 $ 15,563 $ 88,738 $ 61,281
Royalties (4,665) (3,286) (21,488) (13,915)
-------------------------------------------------------------------------
14,627 12,277 67,250 47,366
Realized gain (loss) on
risk management (note 11) 649 937 (4,589) 2,243
Unrealized gain (loss) on
risk management (note 11) 159 (1,296) (48) (473)
-------------------------------------------------------------------------
15,435 11,918 62,613 49,136
Interest and other income - - 119 31
-------------------------------------------------------------------------
15,435 11,918 62,732 49,167
-------------------------------------------------------------------------
Expenses
Production 3,095 2,524 12,180 10,280
Transportation 432 346 1,578 1,307
Depletion, amortization
and accretion 10,357 9,377 38,336 39,180
Impairment of goodwill
(note 12) - - - 20,755
General and administrative
(note 10) 1,105 1,401 5,255 4,433
Stock-based compensation
(note 7) 172 239 1,033 905
Interest 594 949 2,926 4,027
Unrealized loss on interest
rate risk management
(note 11) 573 - 748 -
-------------------------------------------------------------------------
16,328 14,836 62,056 80,887
-------------------------------------------------------------------------
Income (loss) before
income taxes (893) (2,918) 676 (31,720)
Income taxes (note 8)
Future expense (recovery) (196) (2,241) 221 (4,319)
Current expense 2 3 12 39
-------------------------------------------------------------------------
(194) (2,238) 233 (4,280)
-------------------------------------------------------------------------
Net income (loss) and
comprehensive income
(loss) for the period (699) (680) 443 (27,440)
Deficit, beginning
of period (55,900) (56,362) (57,042) (29,602)
-------------------------------------------------------------------------
Deficit, end of period $ (56,599) $ (57,042) $ (56,599) $ (57,042)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income (loss) per
share (note 13)
Basic and diluted $ (0.01) $ (0.01) $ 0.00 $ (0.30)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 December 31, ended December 31,
-------------------------------------------------------------------------
2008 2007 2008 2007
-------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income (loss) for
the period $ (699) $ (680) $ 443 $ (27,440)
Add items not involving
cash
Depletion, amortization
and accretion 10,357 9,377 38,336 39,180
Impairment of goodwill - - - 20,755
Unrealized loss on risk
management 413 1,296 797 473
Future income tax
expense (recovery) (196) (2,241) 221 (4,319)
Stock-based compensation 172 239 1,033 905
-------------------------------------------------------------------------
10,047 7,991 40,830 29,554
Payments for abandonment
and restoration (140) (81) (326) (123)
Change in non-cash working
capital items related to
operating activities
(note 9) (3,864) (6,403) (2,527) (1,236)
-------------------------------------------------------------------------
Cash flow provided by
operating activities 6,043 1,507 37,977 28,195
-------------------------------------------------------------------------
FINANCING ACTIVITIES
Change in bank loan 6,100 3,100 700 3,820
Sale of investment - - - 29
Proceeds from the exercise
of stock options - - 375 225
-------------------------------------------------------------------------
Cash flow provided by
financing activities 6,100 3,100 1,075 4,074
-------------------------------------------------------------------------
INVESTING ACTIVITIES
Purchase of property and
equipment (11,840) (6,340) (39,952) (39,208)
Disposition of property
and equipment - 6,750
Change in non-cash
working capital items
related to investing
activities (note 9) (303) 1,733 900 180
-------------------------------------------------------------------------
Cash flow used in
investing activities (12,143) (4,607) (39,052) (32,278)
-------------------------------------------------------------------------
Increase (decrease) in cash - - - (9)
Cash, beginning of period 1 1 1 10
-------------------------------------------------------------------------
Cash, end of period $ 1 $ 1 $ 1 $ 1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the financial statements
BERENS ENERGY LTD.
Notes to Financial Statements
Years ended December 31, 2008 and 2007
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 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.
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 estimated 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 and costs 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 depletion expense.
Asset Retirement Obligations
The Company estimates the present value of the asset retirement
obligation in the period in which it is incurred and 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.
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 the Company's proportionate interest in such
activities.
Stock-Based Compensation
Under the stock option plan described in note 7, 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 capital stock. 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, stock based
compensation, measurement of risk management instruments and the ceiling
test calculation are based on estimates of gross proved reserves,
production rates, commodity prices, future costs, options pricing model
inputs 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 period. 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.
Financial Instruments - Recognition and Measurement
Financial assets and financial liabilities, including derivatives, are
recognized on the balance sheet when the Company becomes a party to the
contractual provisions of the financial instrument or derivative
contract. All financial instruments are 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.
Held-to-maturity financial assets, loans and receivables, and other
financial liabilities are measured at amortized cost using the effective
interest method of amortization.
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.
Debt issue costs are expensed as incurred.
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.
Accounting changes
Accounting changes are applied retrospectively unless otherwise permitted
or where impracticable to determine. Voluntary changes in an accounting
policy are 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)
Comprehensive income consists of net income and other comprehensive
income ("OCI"). 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).
3. CHANGES IN ACCOUNTING POLICIES
Financial Instruments Presentation and Disclosure
Effective January 1, 2008, the Company adopted the new Canadian Institute
of Chartered Accountants (CICA) recommendations relating to Financial
Instruments - Disclosure (section 3862) and Financial Instruments -
Presentation (section 3863). The new disclosure required by section 3862
concerning the nature and extent of the risks associated with financial
instruments and how those risks are managed, is presented in note 11.
Effective January 1, 2008 the Company adopted CICA recommendations
relating to Capital Disclosures (section 1535) which establishes
standards for disclosing information about an entity's capital and how it
is managed. As permitted, comparative information for the disclosure
required by section 3862 has not been provided. The adoption of these
sections did not affect the Company's financial position or operating
results.
Future accounting changes
International Financial Reporting Standards
In February 2008, the Canadian Accounting Standards Board confirmed that
the use of International Financial Reporting Standards ("IFRS") will be
required in 2011 for publicly accountable profit-oriented enterprises.
IFRS will replace Canada's current GAAP for listed companies and other
profit-oriented enterprises that are responsible to large or diverse
groups of stakeholders. Companies will be required to provide one year of
comparative data in accordance with IFRS.
In the second quarter of 2008 the Company began to develop its IFRS
changeover plan. Initial activities include training sessions and
acquisition of written standards and examples of IFRS disclosure to
identify where key differences between Canadian GAAP and IFRS exist. A
key determination that has significant effect on the financial statements
will be the identification of cash generating units within the Company's
production properties which are currently considered as a whole. The
Company intends to disclose its convergence plan and qualitative effects
of IFRS on its financial statements as they become more fully developed.
Credit Risk and Fair Value of Financial Assets and Financial Liabilities
On January 20, 2009, the Emerging Issues Committee of the CICA issued
Abstract No. 173, "Credit Risk and the Fair Value of Financial Assets and
Financial Liabilities", concerning the measurement of financial assets
and financial liabilities. There has been diversity in practice as to
whether an entity's own credit risk and the credit risk of the
counterparty are taken into account in determining the fair value of
financial instruments. The Committee reached a consensus that these risks
should be taken into account in the measurement of financial assets and
financial liabilities. The Abstract is effective for all financial assets
and financial liabilities measured at fair value for the interim and
annual financial statements issued for periods ending on or after the
date of issuance of the Abstract with retrospective application without
restatement of prior periods. The Company will apply the Abstract at the
beginning of its 2009 fiscal year. The Company does not expect the
implementation to have a significant affect on the Company's financial
position or disclosures.
4. PROPERTY, PLANT AND EQUIPMENT
December 31, 2008 December 31, 2007
Accumulated Accumulated
depletion and depletion and
($000's) Cost depreciation Cost depreciation
-------------------------------------------------------------------------
Petroleum and
natural gas
properties 314,170 145,966 274,067 108,045
Office and
computer
equipment 774 414 734 351
-------------------------------------------------------------------------
314,944 146,380 274,801 108,396
-------------------------------------------------------------------------
Net book value 168,564 166,405
-------------------------------------------------------------------------
At December 31, 2008, costs of $18,954,000 (2007 - $21,159,000) related
to undeveloped land have been excluded from the depletion and
depreciation calculation. At December 31, 2008 estimated future
development costs of $17,698,000 have been included in the depletion and
depreciation calculation (2007 - $15,511,000). A ceiling test was
completed at December 31, 2008 resulting in no impairment.
Benchmark pricing used for ceiling test purposes is shown in the
following table.
Oil
-----------------------------------------------
WTI Edmonton Cromer
Cushing Par Price Hardisty Medium
Oklahoma 40 API Heavy 29 API
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl)
-------------------------------------------------------------------------
Forecast
2009 57.50 68.61 43.10 59.00
2010 68.00 78.94 49.76 68.68
2011 74.00 83.54 54.35 73.52
2012 85.00 90.92 59.23 80.01
2013 92.01 95.91 62.54 84.40
Natural gas NGLs
------------------------
FOB
Field Gate Inflation
AECO-C gas (propane/ rate Exchange
Price butane) % per rate
Year ($Cdn/MMbtu) ($Cdn/bbl) year ($US/Cdn)
-------------------------------------------------------------------------
Forecast
2009 7.58 47.68 2.0 0.825
2010 7.94 55.65 2.0 0.850
2011 8.34 58.90 2.0 0.875
2012 8.70 64.10 2.0 0.925
2013 8.95 67.62 2.0 0.950
5. 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 $3,491,000 as at
December 31, 2008 (2007 - $3,273,000) based on a total undiscounted
future liability of $11,231,000 (2007 - $8,611,000). These payments are
expected to be made over the next 5 to 30 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) 2008 2007
-------------------------------------------------------------------------
Obligation, beginning of year 3,273 2,645
Increase in obligation during the year 612 420
Revision to estimates (421) -
Paid for abandonments (326) (123)
Accretion expense 352 331
-------------------------------------------------------------------------
Obligation, end of year 3,491 3,273
-------------------------------------------------------------------------
6. BANK LOAN
An agreement with a Canadian bank is in place for an operating bank line
totaling $66.0 million at December 31, 2008 which is subject to periodic
review. The line of credit has been renewed at $66 million effective
June 1, 2009 at which time the line reduces by $1.0 million per month
until a September 30, 2009 review date. 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 adjustment
factor ranges from 0.00% if debt to cash flow ratio is below 1
(calculated on a trailing quarter annualized basis), to 1.25% if debt to
cash flow ratio is above 2.5. The average rate paid for the quarter ended
December 31, 2008 was 4.7% (2007 - 7.5%) and for the year ended
December 31, 2008 was 5.4% (2007 - 7.7%). At December 31, 2008,
$54.6 million was drawn on the bank loan, leaving $11.4 million of
undrawn capacity.
7. CAPITAL STOCK
(a) Authorized Capital
The authorized capital consists of an unlimited number of preferred
shares issuable in series and an unlimited number of common shares
without nominal or par value.
(b) Common shares issued
---------------------------------------------------------------------
Consideration
Number ($000's)
---------------------------------------------------------------------
Balance December 31, 2006 92,947,064 148,038
Shares issued on exercise of
stock options 225,000 225
---------------------------------------------------------------------
Balance December 31, 2007 93,172,064 148,263
---------------------------------------------------------------------
Shares issued on exercise of
stock options 375,000 375
---------------------------------------------------------------------
Balance December 31, 2008 93,547,064 148,638
---------------------------------------------------------------------
(c) Stock Option Plan
A stock option plan is in place under which 10 percent of the number of
outstanding common shares is reserved for options to be granted to
directors, officers, employees and consultants with terms established by
the Board of Directors.
Options granted under the plan generally have a five year term to expiry
and vest equally over a three year period commencing on the first
anniversary date of the grant. The exercise price of each option equals
the closing market price of the Company's common shares on the day prior
to the date of the grant.
The following table sets forth a reconciliation of the plan activity
through December 31, 2008:
2008 2007
Weighted Weighted
average average
exercise exercise
Number of price ($ Number of price ($
Options per share) Options per share)
-------------------------------------------------------------------------
Outstanding, beginning
of year 6,238,200 1.42 4,416,200 1.68
Granted 3,521,500 0.74 2,309,500 0.94
Cancelled (1,259,500) 1.12 (262,500) 1.99
Exercised (845,000) 1.00 (225,000) 1.00
-------------------------------------------------------------------------
Outstanding, end of year 7,655,200 0.96 6,238,200 1.42
-------------------------------------------------------------------------
Exercisable 2,488,056 1.25 3,216,359 1.54
-------------------------------------------------------------------------
The following table sets forth additional information relating to the
stock options outstanding at December 31, 2008:
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
-------------------------------------------------------------------------
$0.25 to $0.79 2,470,000 0.54 4.53 244,035 0.76 3.70
-------------------------------------------------------------------------
$0.80 to $1.34 4,083,000 1.05 3.27 1,271,989 1.13 1.83
-------------------------------------------------------------------------
$1.35 to $1.89 1,097,200 1.54 1.07 967,032 1.52 0.86
-------------------------------------------------------------------------
$1.90 to $2.44 - - - - - -
-------------------------------------------------------------------------
$2.45 to $3.00 5,000 2.90 1.92 5,000 2.90 1.92
-------------------------------------------------------------------------
7,655,200 0.96 3.36 2,488,056 1.25 1.64
-------------------------------------------------------------------------
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 - 2.7 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 fair value at the dates of grant for the options outstanding at
December 31, 2008 is $0.515 per option. For the quarter ended
December 31, 2008 $171,000 and for the year ended December 31, 2008
$1,033,000 was recorded for stock based compensation (2007 - $239,000 and
$905,000 respectively) with a corresponding increase recorded to
contributed surplus. During 2008 a total of 470,000 expiring options were
exercised pursuant to the provisions of the Company's option plan whereby
the Board of Directors approved certain option holders to receive a cash
settlement for the difference between the market price and the option
strike price in lieu of exercising the stock option resulting in no
shares being issued for the exercise of these options.
(d) Contributed Surplus
The following table sets forth the continuity of contributed surplus for
the year ended December 31, 2008:
($000's)
-------------------------------------------------------------------------
December 31, 2006 1,290
2007 Stock based compensation expense 905
-------------------------------------------------------------------------
December 31, 2007 2,195
2008 Stock based compensation expense 1,033
-------------------------------------------------------------------------
December 31, 2008 3,228
-------------------------------------------------------------------------
At the time of exercise of a stock option, 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.
8. INCOME TAXES
The income tax expense or recovery differs from the amount computed by
applying the Canadian statutory rates to the loss before tax as follows:
($000's) 2008 2007
-------------------------------------------------------------------------
Income (Loss) before income taxes 676 (31,720)
-------------------------------------------------------------------------
Current statutory income tax rate 29.51% 32.13%
-------------------------------------------------------------------------
Anticipated tax expense (recovery) 199 (10,193)
Increase (decrease) in recovery resulting from:
Adjust to actual tax return (164) -
Effect of future tax rate reductions (121) (957)
Impairment of goodwill - 6,669
Unrealized risk management gains - (152)
Non-deductible expenses 319 300
Other (12) 14
-------------------------------------------------------------------------
Future income tax expense (recovery) 221 (4,319)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capital tax 12 12
Other - 27
-------------------------------------------------------------------------
Current income tax expense 12 39
-------------------------------------------------------------------------
Future income taxes reflect the net tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial
reporting purposes and the amounts used for income tax purposes. The
components of the future tax assets are as follows:
($000's) 2008 2007
-------------------------------------------------------------------------
Future tax liabilities
Net book value of capital assets in
excess of tax pools (12,272) (12,132)
Future tax assets
Share issue costs 297 432
Attributed Canadian royalty income 683 683
Asset retirement obligation 872 818
-------------------------------------------------------------------------
Net future tax liabilities (10,420) (10,199)
-------------------------------------------------------------------------
Tax Pools
At December 31, 2008 the petroleum and natural gas properties had an
approximate tax basis of $127,000,000.
Capital loss carry-forwards exist totaling $3,363,000 which are available
to offset future capital gains for which no future income tax asset has
been recognized in the accounts.
9. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in Non-cash Working Capital
For the years ended December 31,
($000's) 2008 2007
-------------------------------------------------------------------------
Accounts receivable (2,539) 9,286
Prepaid expenses and deposits 142 (228)
Accounts payable and accrued liabilities 768 (10,099)
Taxes payable 2 (16)
-------------------------------------------------------------------------
(1,627) (1,057)
Change in non-cash working capital related
to investing activities 900 180
-------------------------------------------------------------------------
Change in non-cash working capital related
to operating activities (2,527) (1,237)
-------------------------------------------------------------------------
Cash interest and taxes paid
For the year ended December 31,
($000's) 2008 2007
-------------------------------------------------------------------------
Cash income and other taxes paid 10 28
Cash interest paid 2,926 4,028
-------------------------------------------------------------------------
10. 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 for the quarter ended December 31, 2008 were $32,000
and for the year ended December 31, 2008 $261,000 (2007 - $27,000 and
$206,000).
11. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Financial assets and liabilities recognized on the balance sheets consist
of cash, accounts receivable, accounts payable, bank loan and commodity
price and interest rate risk management instruments.
Fair value of financial assets and liabilities
Cash, commodity price and interest rate risk management instruments are
designated as "held-for-trading" and recorded at the estimated fair
market value. The fair value of these financial instruments approximates
their carrying amounts due to their short terms to maturity except for
derivatives used for interest rate and commodity price risk management
which values are outlined below. Accounts receivable, prepaid expenses
and the bank loan are designated as "loans and receivables" and accounts
payable are designated as "other liabilities" and are recorded at their
amortized costs.
(a) Credit Risk
Accounts receivable are with customers, sales agents and joint venture
partners in the petroleum and natural gas business and are subject to the
usual credit risks. The Company mitigates these risks by entering into
transactions with long-standing, reputable counterparties and partners.
If significant amounts of capital are to be spent on behalf of a joint
venture partner the partner is "cash called" in advance of the capital
spending taking place. The maximum credit exposure with accounts
receivable is the carrying value. At December 31, 2008, the largest
single credit exposure was approximately $5.5 million from the Company's
sales agent the balance of which is settled monthly. At December 31,
2008, 18 percent of accounts receivable were non-current as defined by
accounts over 90 days outstanding. The majority of the overdue accounts
receivable are with a single counterparty with which the Company is
working with to reconcile older operating and capital billings. This
party is current on recent billings. Management has assessed the
Company's accounts receivable customers and concluded the amounts owing
and no allowance for doubtful accounts receivable was required nor were
any balances deemed to be impaired.
(b) Interest Rate Risk
The Company is exposed to fluctuations in interest rates on its bank debt
which charges interest at variable market rates. The Company entered into
an interest rate swap transaction in January 2008 to fix the interest
rate on $25.0 million of its variable rate demand bank line beginning in
February 2008. The transaction fixes the interest rate for a two year
period at an underlying borrowing rate of 3.61 percent. Including the
Company's borrowing margin on its bank line the current all in rate of
this transaction is 5.21 percent. Fair values for interest rate
derivatives are provided by the financial intermediary with whom the
transactions were completed and tested by the Company for reasonableness
based on comparing current market prices and the fixed prices of the
contracts. The fair value of the interest rate swap as at December 31,
2008 results in an unrealized loss of $748,000 for the year ended
December 31, 2008. A one percent change in interest rates for the
remaining term of this interest rate swap at December 31, 2008 would
change the fair value of the derivative instrument by approximately
$280,000. There were no interest rate derivatives in place in 2007. The
net income effect of a one percent change in short-term interest rates on
the remaining amount of bank debt is approximately $234,000. Subsequent
to the end of the year, the Company cancelled the interest rate swap and
simultaneously replaced it with a $40 million fixed interest rate swap
for two years beginning in February 2009 which fixes the interest rate
for a two year period at an underlying borrowing rate of 2.39 percent.
Including the Company's borrowing margin on its bank line the current all
in rate of this transaction is 3.99 percent.
(c) Commodity Price Risk Management
The Company is exposed to the risk of changes in market prices for
natural gas, crude oil and natural gas liquids. The Company may mitigate
this risk by entering into derivatives based fixed price contracts or
price collars or may enter into fixed price physical delivery contracts.
The following is a summary of natural gas price risk management
derivative contracts in effect as of December 31, 2008. All natural gas
contracts are priced in Canadian dollars per gigajoule ("GJ"). The price
per GJ can be converted to an approximate price per million cubic feet
("MCF") by multiplying the per GJ price by 1.05. GJ volume can be
converted to an approximate MCF volume by multiplying the GJ volume by
0.95.
Natural Gas Risk Management Contracts
-------------------------------------------------------------------------
Daily
quantity Fixed price per gigajoule
(GJ/day) Term of Contract (Cdn$/GJ)
-------------------------------------------------------------------------
2,000 April 1 to March 31, 2009 $6.72 fixed price
-------------------------------------------------------------------------
Fair values for commodity price derivatives are provided by the financial
intermediary with whom the transactions were completed and tested by the
Company for reasonableness based on comparing current market prices and
the fixed prices of the contracts. The fair value of the above natural
gas derivative instruments marked-to-market as at December 31, 2008
results in an unrealized gain of $114,000 (December 31, 2007 - gain of
$162,000). For the quarter ended December 31, 2008 a $159,000 gain was
recorded reflecting the change in the balance sheet mark-to-market
position from December 31, 2008. For the year ended December 31, 2008 a
$48,000 loss was recorded reflecting the change in the balance sheet
mark-to-market position from December 31, 2007. Total realized gains from
risk management activities in the fourth quarter of 2008 were $648,000
(2007 - $937,000 gain). Total realized losses for the year ended
December 31, 2008 were $4,589,000 (2007 - $2,243,000 gain). Commodity
price and interest rate derivatives are transacted with large, credit
worthy counterparties and governed by credit agreements between the
Company and its counterparties.
The estimated change in the fair value of the commodity price derivatives
in place at December 31, 2008 for a $1/mcf change in the natural gas
price is $180,000. Absent the above-noted risk management contracts, the
effects of changes in commodity prices on annual net income summarized in
the following table on the basis of average annual production of
approximately 4,600 boe/d.
-------------------------------------------------------------------------
Commodity Price change Net Income change
($000's)
-------------------------------------------------------------------------
Natural gas ($/mcf) 1.00 $4,600
-------------------------------------------------------------------------
Oil and Liquids ($/bbl) 10.00 $1,500
-------------------------------------------------------------------------
(d) Liquidity Risk and Capital Requirements
The Company is exposed to liquidity risk, which is the risk that the
Company may be unable to generate or obtain sufficient cash to meet its
commitments as they become due. The financial liabilities on the balance
sheet consist of accounts payable, bank loan and taxes payable. This risk
is mitigated through the management of cash and bank loan and the Company
may adjust capital spending, issue new shares or draw or repay its
operating bank line. The Company's primary capital management objective
is to maintain a strong balance sheet to provide the financial
flexibility to respond to cash flow volatility or an investment
opportunity. The Company maintains appropriate unused capacity in its
operating bank line to meet short term fluctuations from forecasted
results. The Company has no externally imposed capital requirements but
is subject to a working capital test as a covenant on its operating bank
line.
Forecasted cash flows and operating and capital outlays are updated
frequently to ensure necessary liquidity remains available. The Company
may hedge a portion of its future production and/or its interest rate
exposure to protect cash flows. All of the Company's financial
obligations are either demand or are due within one year. The Company is
targeting its debt and working capital to funds from operations ratio to
a measure of 1.5:1 or lower on a current quarter annualized basis
(excluding unrealized hedging gains and losses). For the quarter ended
December 31, 2008 this ratio was 1.5:1 down from 1.9:1 for the quarter
ended December 31, 2007.
-------------------------------------------------------------------------
Target
At December 31 ($000's) Measure 2008 2007
-------------------------------------------------------------------------
Components of Ratio
Current assets 13,269 10,920
Current liabilities (72,655) (70,436)
-------------------------------------------------------------------------
(59,386) (59,516)
Unrealized risk management
loss (gain) 635 (162)
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Debt and working capital (58,751) (59,678)
-------------------------------------------------------------------------
Funds from operations - three
months ended December 31
annualized(1) 40,188 31,996
-------------------------------------------------------------------------
Ratio 1.5:1 1.5:1 1.9:1
-------------------------------------------------------------------------
(1) Funds from operations is a non-GAAP measure defined as: operating
cash flow adjusted for changes in non-cash working capital related to
operating activities, all annualized.
12. GOODWILL
The Company recorded an impairment of goodwill in the amount of
$24.2 million in 2006 and a further impairment to the remaining goodwill
balance of $20.8 million in the third quarter of 2007.
13. PER SHARE INFORMATION
The weighted average number of common shares outstanding for the quarter
ended December 31, 2008 of 93,547,064 was used to calculate basic and
diluted income (loss) per share (2007 - 93,172,064 basic and diluted).
The weighted average number of common shares outstanding for the year
ended December 31, 2008 was 93,365,712 to calculate basic and diluted
income per share (2007 - 93,067,132 basic and diluted). The stock options
are considered as anti-dilutive for the year ended December 31, 2008. The
total number of shares issuable under the stock option plan which are
potentially dilutive in future periods as of December 31, 2008 was
7,655,200.
14. COMMITMENTS
Commitments exist for leased office space, software and vehicles. The
amounts for leased space exclude operating costs, taxes, insurance and
utilities:
Year
($000's)
------------------------------
2009 387
2010 450
2011 330
2012 314
2013 314
Thereafter 209
------------------------------
Total 2,004
------------------------------
Directors and officers are indemnified against any and all claims or
losses reasonably incurred in the performance of their service to the
Company to the extent permitted by law. The Company has acquired and
maintains liability insurance for its directors and officers.
15. COMPARATIVE FIGURES
Certain figures have been re-classified to conform to the financial
statement presentation adopted in 2008.
Caution Regarding Forward Looking Information
This press release contains forward looking information within the
meaning of applicable securities laws. Forward looking statements may
include estimates, plans, expectations, forecasts, guidance or other
statements that are not statements of fact. Forward looking information
in this Press Release includes, but is not limited to, statements with
respect to capital expenditures and related allocations, production
volumes, production mix and commodity prices.
Forward-looking statements and information are based on current beliefs
as well as assumptions made by and information currently available to
Berens concerning anticipated financial performance, business prospects,
strategies and regulatory developments. Although management considers
these assumptions to be reasonable based on information currently
available to it, they may prove to be incorrect.
By their very nature, forward-looking statements involve inherent risks
and uncertainties, both general and specific, and risks that predictions,
forecasts, projections and other forward-looking statements will not be
achieved. We caution readers not to place undue reliance on these
statements as a number of important factors could cause the actual
results to differ materially from the beliefs, plans, objectives,
expectations and anticipations, estimates and intentions expressed in
such forward-looking statements. These factors include, but are not
limited to: crude oil and natural gas price volatility, exchange rate and
interest rate fluctuations, availability of services and supplies, market
competition, uncertainties in the estimates of reserves, the timing of
development expenditures, production levels and the timing of achieving
such levels, the Company's ability to replace and increase oil and gas
reserves, the sources and adequacy of funding for capital investments,
future growth prospects and current and expected financial requirements
of the Company, the cost of future abandonment and site restoration, the
Company's ability to enter into or renew leases, the Company's ability to
secure adequate product transportation, changes in environmental and
other regulations and general economic conditions.
The forward-looking statements contained in this press release are made
as of the date of this press release, and Berens does not undertake any
obligation to up-date publicly or to revise any of the included forward-
looking statements, whether as a result of new information, future events
or otherwise. This cautionary statement expressly qualifies the forward-
looking statements contained in this press release.
%SEDAR: 00020114E