Berens Energy Ltd. releases financial results for the fourth quarter and year ended December 31, 2007



    Symbol: BEN - TSX

    CALGARY, March 27 /CNW/ -

    
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        FINANCIAL AND OPERATING HIGHLIGHTS

    -------------------------------------------------------------------------
    ($ Cdn thousands,           Three months              Twelve months
     except as noted)        ended December 31,         ended December 31,
    -------------------------------------------------------------------------
                                             %                          %
                           2007     2006   Change     2007     2006   Change
    -------------------------------------------------------------------------
    Sales volume
      Natural gas
       (mcf/day)         19,018   18,440       3%   18,981   17,420       9%
      Oil and ngls
       (bbl/day)            626      483      30%      564      469      20%
      boe/day (6 to 1)    3,796    3,556       7%    3,728    3,373      11%
    -------------------------------------------------------------------------
    Revenue net of
     royalties           13,214   11,213      18%   49,609   40,118      24%
    Net income (loss)      (680) (21,951)          (27,440) (28,340)
      Per share (basic
       and diluted)      $(0.01)  $(0.24)           $(0.30)  $(0.33)
    Funds from
     operations(1)        7,991    6,118      31%   29,554   22,471      32%
      Per share (basic
       and diluted)(1)    $0.09    $0.07      29%    $0.32    $0.26      23%
    -------------------------------------------------------------------------
    Capital costs
      Exploration and
       development        5,986   11,474            35,468   52,807
      Land and seismic      412      896             3,807    3,583
      Other                   4       37                56      295
    -------------------------------------------------------------------------
      Total               6,402   12,407     (48%)  39,331   56,685     (31%)
    -------------------------------------------------------------------------
    Net wells
     completed (No.)
    -------------------------------------------------------------------------
      Natural gas             3        6                14       25
    -------------------------------------------------------------------------
      Oil                     -        -                 2        -
    -------------------------------------------------------------------------
      Dry                     -        1                 2        4
    -------------------------------------------------------------------------
      Total                   3        7                18       29
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    Net working capital
     (deficit) -
     including bank
     debt               (59,516) (56,271)      6%  (59,516) (56,271)      6%
    -------------------------------------------------------------------------
    Shares outstanding
      End of period
       (000's)           93,172   92,947        -   93,172   92,947        -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Note:
    (1) Non-GAAP measure - represents cash flow from operating activities
        before non-cash working capital changes. Refer to Management's
        Discussion and Analysis for discussion of this measure.


    Message to the shareholders

    2007 has been a strong operational year for Berens. We entered 2007
excited about momentum that we had established with strong drilling success in
the second half of 2006. We were achieving repeated drilling success in
Pembina and were convinced we had found an advantage in the area based on
strong integration of technology, geology and geophysics. We were committed to
disciplined cost management for both drilling and operations as industry cost
pressures remained high. We kept a keen eye on natural gas prices and adjusted
our capital spending program to ensure that we could fund most of our spending
with cash flow. Natural gas prices were uncertain and very weak at times
during 2007 so we had to manage our business carefully.

    We delivered:

    -   Drilling success continued with an overall success rate of 86% on our
        drilling program. More importantly we had 100% success in our key
        growth areas of Pembina and Deep Basin.
    -   We further defined our Pembina play and have significantly reduced
        the risk profile in the area using our integrated technical approach,
        evident not only in our drilling success rate but also in our
        improved reserve additions.
    -   We applied a disciplined approach to cost control which delivered
        wells and production at significantly lower costs when combined with
        easing cost pressures in our industry.

    The results are evident:

    -   Average annual production increased 11% year over year
    -   Long term value was strengthened with a reserves increase of 16% and
        a lengthening of our reserve life index ("RLI") from 6 to 6.5 years.
        We replaced production by 2 times with new reserves. All done with
        the drill bit.
    -   Finding and development costs were $12.85 including future
        development capital (National Instruments 51-101 definition). We
        believe these results are first quartile performance in our industry.
    -   New wells in Pembina, targeting trends based on our technology, were
        40 percent better in terms of production and reserves than we have
        experienced historically.
    -   Operating costs averaged $7.55 for 2007, down 4% from 2006 and we
        were drilling wells by the end of 2007 at costs 25% lower than a year
        ago.
    

    We are well positioned for 2008

    So far in 2008 we are 6 for 6 in Pembina and 2 for 3 in our exploratory
efforts in Deep Basin, continuing with the success we had in 2007. Costs
continue to come down and we are drilling wells for costs that we have not
seen since 2004. We have an extensive inventory of 100 drilling prospects
across our three core areas, all on our existing land base. Most of our
prospects are seismically defined with low risk. The 2008 capital program is
focused on the drill bit with 90 percent of our planned capital targeted for
drilling, completion, equipping and tie in activities. We continue to add land
in Pembina, with an additional nine sections added already in 2008, building
further our strong land position in this key growth area.
    Natural gas prices appear more stable and strong after a year of
uncertainty and weakness. There is optimism in our industry that the stronger
natural gas prices are more sustainable in 2008 and beyond. We continue to be
vigilant and ready to adjust our spending as commodity prices increase or
decrease.
    Berens is prospect rich and looks forward to opportunities to step up our
activities as we see strength in natural gas prices. Our staff is committed
and enthused about our success and looking forward to build on the momentum
established in 2007. I would like to offer special thanks to our staff and
management for their efforts and achievements and to our board of directors
for their guidance and support in 2007.
    Our shareholders experienced a difficult year in 2007 as the oil and gas
sector fell out of favor and selling was indiscriminate. We thank those who
stood with us through 2007 and we believe in time, you will reap the rewards
of our operational success.

    Sincerely,

    Daniel F. Botterill
    President & Chief Executive Officer


    
    Fourth Quarter 2007 Operating Highlights

    -   Drilling - A total of 4 wells (2.9 net) were drilled in the fourth
        quarter, all successful natural gas wells. On a full year basis in
        2007, 29 (17.6 net) wells have been drilled with 23 (13.5 net)
        natural gas wells, 2 (2.0 net) oil wells and four (2.1 net)
        unsuccessful wells for a net success rate of 86 percent. In the key
        growth areas of Pembina (12 wells) and the Deep Basin (4 wells),
        100 percent drilling success was achieved.

    -   Reserves - Total working interest proved plus probable reserves as at
        December 31, 2007 were 9,016,000 boe, an increase of 16 percent
        compared to proved plus probable reserves at December 31, 2006. On a
        per share basis proved plus probable reserves also grew 16 percent to
        96.8 boe/1000 shares outstanding from 83.5 boe/1000 shares
        outstanding. Reserves growth came entirely from the successful 2007
        exploration and development drilling program. Berens replaced
        production 2.0 times through the addition of new proved plus probable
        reserves from the exploration and development drilling program (net
        of revisions). The reserve growth in 2007 was accomplished with a net
        capital program that was funded almost entirely with cash flow as
        debt and working capital grew only $2.9 million during 2007.

    -   Production - Q4 2007 production averaged 3,796 boe/d, up 7 percent
        over Q4 2006 and up 5 percent over the third quarter of 2007.
        Production additions in the fourth quarter of 2007 were delivered by
        ongoing drilling and tie-ins in Pembina and the completions and tie
        in of a summer drilling program in Lanfine. On a full year basis,
        volume in 2007 averaged 3,728 boe/d, up 11 percent compared to 2006.

    -   Production Costs - Costs averaged $7.23 per boe in Q4 2007, down 18%
        compared to Q4 2006. For the 2007 year production costs have averaged
        $7.55 per boe, down 4 percent compared to 2006. Berens continues to
        have success in reducing unit operating cost.

    -   Funds from Operations - Funds from operations in Q4 2007 was
        $8.0 million ($0.09 per share), up 31 percent compared to Q4 2006
        funds from operations of $6.1 million ($0.07 per share) and up
        17 percent from Q3 2007. Higher production in Q4 2007 was
        complemented by reduced operating costs and higher commodity prices
        to deliver the increase. December 31, 2007 debt and working capital
        was 1.86 times annualized Q4 funds from operations.

    -   Land - Berens total undeveloped land currently stands at 100,000 net
        acres almost all of which is now owned with little remaining land yet
        to be earned on farm-ins. Ninety-eight percent of the undeveloped
        lands are located in our three core areas of Pembina, Deep Basin and
        Lanfine. The 2008 drilling program is based entirely on existing
        Berens' controlled undeveloped acreage on which there exist an
        inventory of 100 locations.
    

    RESERVES

    Berens' oil and gas reserves were independently evaluated by GLJ
Petroleum Consultants ("GLJ"). The evaluation was completed using the reserves
definitions in the Canadian Oil and Gas Evaluation Handbook and the Canadian
Securities Administrators National Instrument 51-101 ("NI 51-101"). Total
working interest proved plus probable reserves as at December 31, 2007 were
9,016,000 boe, an increase of 16 percent compared to proved plus probable
reserves at December 31, 2006. On a per share basis proved plus probable
reserves also grew 16 percent to 96.8 boe/1000 shares outstanding from
83.5 boe/1000 shares outstanding. Reserves growth came entirely from the
successful 2007 exploration and development drilling program. The table below
summarizes Berens' working interest reserves on a gross basis (before
deduction for royalties) as at December 31, 2007 using forecast prices and
costs based on the GLJ January 1, 2008 price forecast.

    
                     SUMMARY OF OIL AND GAS RESERVES(1)

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    WORKING INTEREST
    RESERVES                  OIL AND LIQUIDS              NATURAL GAS
    -------------------------------------------------------------------------
                           2007     2006  Percent     2007     2006  Percent
    RESERVES CATEGORY     (Mbbl)   (Mbbl)  Change    (MMcf)   (MMcf)  Change
    -------------------------------------------------------------------------

    PROVED
      Developed
       Producing          1,050      743     +41%   21,855   18,770     +16%
      Developed
       Non-Producing         82      148     -44%    1,440    4,266     -66%
      Undeveloped           198      100     +98%    4,746    3,381     +40%
    -------------------------------------------------------------------------
    TOTAL PROVED          1,330      991     +34%   28,041   26,417      +6%
    -------------------------------------------------------------------------
    PROBABLE                665      496     +34%   14,085   11,256     +25%
    -------------------------------------------------------------------------
    TOTAL PROVED
     PLUS PROBABLE        1,995    1,487     +34%   42,126   37,673     +12%
    -------------------------------------------------------------------------


                 -----------------------------------------------
                  WORKING INTEREST
                  RESERVES                       BOE
                 -----------------------------------------------
                                         2007     2006  Percent
                  RESERVES CATEGORY     (Mbbl)   (Mbbl)  Change
                 -----------------------------------------------

                  PROVED
                    Developed
                     Producing          4,693    3,871     +21%
                    Developed
                     Non-Producing        322      858     -62%
                    Undeveloped           989      664     +49%
                 -----------------------------------------------
                  TOTAL PROVED          6,003    5,393     +11%
                 -----------------------------------------------
                  PROBABLE              3,013    2,372     +27%
                 -----------------------------------------------
                  TOTAL PROVED
                   PLUS PROBABLE        9,016    7,765     +16%
                 -----------------------------------------------



    -------------------------------------------------------------------------
    WORKING INTEREST           BEFORE TAX 8%              BEFORE TAX 10%
    RESERVES                  PRESENT VALUE(1)           PRESENT VALUE(1)
    -------------------------------------------------------------------------
                          2007     2006   Percent    2007     2006   Percent
    RESERVES CATEGORY   ($000's) ($000's)  Change  ($000's) ($000's)  Change
    -------------------------------------------------------------------------

    PROVED
      Developed
       Producing         91,839   73,824     +24%   86,962   69,432     +25%
      Developed
       Non-Producing      5,316   14,977     -65%    4,842   14,013     -65%
      Undeveloped         7,685    4,626     +66%    6,640    3,731     +78%
    -------------------------------------------------------------------------
    TOTAL PROVED        104,840   93,427     +12%   98,444   87,176     +13%
    -------------------------------------------------------------------------
    PROBABLE             39,020   35,174     +11%   34,215   31,073     +10%
    -------------------------------------------------------------------------
    TOTAL PROVED
     PLUS PROBABLE      143,860  128,601     +12%  132,659  118,249     +12%
    -------------------------------------------------------------------------

    (1) It should not be assumed that the present values of estimated future
        net cash flows shown above are representative of the fair market
        value of the reserves. There is no assurance that such price and cost
        assumptions will be attained and variances could be material. The
        recovery and reserves estimates of crude oil, NGL and natural gas
        reserves provided herein are estimates only and there is no guarantee
        that the estimated reserves will be recovered. Actual crude oil,
        natural gas and NGL reserves may be greater than or less than the
        estimates provided herein.
    

    Based on fourth quarter 2007 average production volume the proved plus
probable reserve life index at December 31, 2007 is 6.5 years, up from
6.0 years compared to December 31, 2006. The majority of reserve growth in
2007 came at Pembina and Deep Basin where wells typically have long reserve
life. Oil and liquids represent 22 percent of December 31, 2007 reserves, up
from 19 percent at December 31, 2006 as the majority of the reserves added
through 2007 have been from liquids rich natural gas wells in Pembina and the
Deep Basin.
    The following table reconciles the reserve additions from capital
spending, dispositions and revisions to opening estimates.

    
                              RECONCILIATION OF
                          COMPANY INTEREST RESERVES
                         BY BARREL OF OIL EQUIVALENT

              -------------------------------------------------
                                                   Proved Plus
                                        Proved       Probable
               FACTORS                  (Mboe)        (Mboe)
              -------------------------------------------------

               December 31, 2006         5,393         7,765

               Discoveries                 174           238
               Extensions                1,691         2,738
               Infill drilling               -             -
               Technical revisions         191          (259)
               Acquisitions                  -             -
               Dispositions                (88)         (108)
               Production(1)            (1,358)       (1,358)
              -------------------------------------------------
               December 31, 2007         6,003         9,016
              -------------------------------------------------
    

    GLJ has also calculated the effects of the Alberta New Royalty Framework
("NRF") on the December 31, 2007 asset value based on low and high case
assumptions as defined by GLJ and other reserve engineering firms in Calgary.
The evaluation established that on a worst case basis, net asset value would
remain unchanged at $132.7 million on a before tax 10% discount basis. In the
high case, net asset value would increase by over 3 percent to $137.0 million.
This is consistent with the Company's expectations based on its current asset
mix and GLJ's December 31, 2007 price assumptions.
    All calculations converting natural gas to crude oil equivalent have been
made using a ratio of six thousand cubic feet ("mcf") of natural gas to one
barrel of crude oil equivalent. Barrels of oil equivalent ("boe") may be
misleading, particularly if used in isolation. A boe conversion ratio of
six mcf of natural gas to one barrel of crude oil equivalent is based on an
energy equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the wellhead.

    Finding and Development Costs

    Capital spending in 2007 was $32.9 million including $1.4 million spent
on land and net of the Marten Hills disposition ($6.75 million). Net future
capital as at December 31, 2007 is estimated at $21.2 million compared to
$15.4 million at December 31, 2006. Proved plus probable finding and
development costs for 2007 excluding land capital and including the change in
future development capital of $5.8 million was $12.85 per boe. Including
technical revisions, proved plus probable finding and development costs were
$14.12 per boe in 2007. It should be noted that GLJ did not include 2007
reserve additions for first quarter drilling results in Marten Hills as it was
sold prior to year end. The Company spent $4.6 million in Marten Hills in the
first quarter of 2007 that is included in its 2007 capital spending of
$32.9 million.
    Finding and development costs for Berens seismic, exploration and
development activities for each of the past three years and on a three year
cumulative basis are outlined below:

    
    -------------------------------------------------------------------------
                                                                       Three
                                                                        Year
                                             2007     2006     2005   Totals
    -------------------------------------------------------------------------
    Total capital for seismic,
     exploration and development
     (excluding land capital) ($000's)     31,059   53,101   25,706  109,866
    -------------------------------------------------------------------------
    Future development capital -
     proved ($000's)                       15,112   12,600    1,240   13,872
    -------------------------------------------------------------------------
    Future development capital -
     proved plus probable ($000's)         21,187   15,400    1,380   19,807
    -------------------------------------------------------------------------
    Reserve extensions, discoveries
     and dispositions - proved (Mboe)       1,777    2,222      946    4,945
    -------------------------------------------------------------------------
    Reserve extensions, discoveries
     and dispositions - proved plus
     probable (Mboe)                        2,868    3,271    1,273    7,412
    -------------------------------------------------------------------------
    Finding and development costs -
     proved (per boe)                      $18.89   $29.01   $28.48   $25.02
    -------------------------------------------------------------------------
    Finding and development costs -
     proved plus probable (per boe)        $12.85   $20.52   $21.28   $17.50
    -------------------------------------------------------------------------

    Three year average finding and development costs on a proved plus probable
basis for exploration and development activities were $17.50 per boe, an
improving trend from the three year average at the end of 2006 of $18.19 due
to strong results in 2007. Early 2008 drilling success in Pembina and the Deep
Basin points to continued strong finding and development cost efficiency.

    Net Asset Value

    The Company's net asset value at December 31, 2007 based on the year end
reserves as evaluated by GLJ, including land and debt and working capital is
presented below. The net asset value as determined below may not necessarily
reflect the current market value of the Company.

    Category                                            ($000s)    $/share(1)
    -------------------------------------------------------------------------
    Proved reserves (discounted at 10%)(2)              98,444        1.06
    Probable reserves (discounted at 10%)(2)            34,215        0.37
    -------------------------------------------------------------------------
                                                       132,659        1.43
    Land (book value)                                   21,159        0.23
    Debt & Working Capital Deficit                     (59,516)      (0.64)
    -------------------------------------------------------------------------
    Net Asset Value - December 31, 2007                 94,302        1.03
    -------------------------------------------------------------------------

    (1) Per share values are based on basic shares outstanding of 93,172,064
        as there were no stock options in the money as at December 31, 2007.
    (2) Based on an independent evaluation by GLJ effective December 31, 2007
        using forecast prices and costs and calculated before deducting
        future income taxes.
    


    Berens Energy Ltd.
    Annual and Fourth Quarter 2007
    Management's Discussion and Analysis ("MD&A")
    March 26, 2008

    OVERVIEW

    Berens Energy Ltd. ("Berens" or the "Company") is a full cycle oil and
natural gas exploration and production company with a concentrated production
and land base in Eastern Alberta, Pembina and Deep Basin regions of Alberta.
    All calculations converting natural gas to crude oil equivalent have been
made using a ratio of six thousand cubic feet (six "mcf") of natural gas to
one barrel of crude equivalent. Barrels of oil equivalent ("boe") may be
misleading, particularly if used in isolation. A boe conversion ratio of
six mcf of natural gas to one barrel of crude oil equivalent is based on an
energy equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the wellhead.
    The following discussion of financial position and results of operations
should be read in conjunction with the Company's December 31, 2007 audited
financial statements and notes thereto. This MD&A was prepared using
information that is current as of March 26, 2008 unless otherwise noted.

    STRATEGY AND OBJECTIVES

    The Company established key performance metrics for 2008 that are
evaluated and reviewed quarterly within the context of a planned $30 million
capital program plan that is funded by cash flow. Key performance metrics
include production volume growth, finding and development costs, reserve
additions, operating and corporate netbacks and return on investment.
    Volume growth is an important equity market measurement that is reported
frequently and measures the ability of the capital spending program to add
near term cash flow. The Company expects to exit 2008 with production in a
range from 4,100 to 4,300 boe/d, up over 10 percent compared to fourth quarter
2007 average production of 3,796 boe per day.
    Longer term value is achieved by adding oil and natural gas reserves at
low cost. The Company expects to replace 1.5 times 2008 production with new
reserves at finding and development costs below $15.00/boe. Operating and
corporate netbacks are expected to be $28.00 and $22.00 respectively assuming
a $7.00 per mcf price for natural gas and $80.00 per barrel for oil. Resulting
recycle ratios based on the above factors are over 1.9 times on an operating
netback basis and 1.5 times based on the corporate netback. Both of these
measures deliver long term added value.

    FORWARD LOOKING INFORMATION

    This MD&A contains forward looking information within the meaning of
applicable securities laws. Forward looking statements may include estimates,
plans, expectations, forecasts, guidance or other statements that are not
statements of fact. Berens believes the expectations reflected in such forward
looking statements are reasonable. However no assurance can be given that such
expectations will prove to be correct. These statements are subject to certain
risks and uncertainties and may be based on assumptions where actual results
could differ materially from those anticipated or implied in the forward
looking statements. These risks include, but are not limited to: crude oil and
natural gas price volatility, exchange rate and interest rate fluctuations,
availability of services and supplies, market competition, uncertainties in
the estimates of reserves, the timing of development expenditures, production
levels and the timing of achieving such levels, the Company's ability to
replace and increase oil and gas reserves, the sources and adequacy of funding
for capital investments, future growth prospects and current and expected
financial requirements of the Company, the cost of future abandonment and site
restoration, the Company's ability to enter into or renew leases, the
Company's ability to secure adequate product transportation, changes in
environmental and other regulations and general economic conditions. These
statements are as of the date of this MD&A and the Company does not undertake
an obligation to update its forward looking statements except as required by
law.
    Additional information on the Company can be found on the SEDAR website
at www.sedar.com.

    
    QUARTERLY INFORMATION
                                                        2007
                                    -----------------------------------------
    ($000's except as noted)             Q4         Q3         Q2         Q1
    -------------------------------------------------------------------------
    Sales volumes:
      Natural gas (mcf/day)          19,018     18,288     19,919     18,705
      Oil and natural gas
       liquids (bbl/day)                626        570        560        499
      Barrels of oil equivalent       3,796      3,618      3,880      3,617
    -------------------------------------------------------------------------
    Financial:
      Net revenue                    13,214     11,864     12,739     11,793
      Net (loss)                       (680)   (23,157)      (557)    (3,043)
        per share - basic
         ($/share)                   $(0.01)    $(0.25)    $(0.00)    $(0.03)
        per share - diluted
         ($/share)                   $(0.01)    $(0.25)    $(0.00)    $(0.03)
      Capital costs                   6,718      8,541      6,208     18,329
      Shares outstanding (000's)     93,172     93,172     93,172     92,947
      Bank debt                      53,900     50,800     62,700     59,980
      Working capital (deficit)
       including bank debt          (59,516)   (59,300)   (64,644)   (68,502)
    -------------------------------------------------------------------------
    Per unit information:
      Natural gas price ($/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
    -------------------------------------------------------------------------
    Net wells completed: (No.)
      Natural gas                         3          5          1          5
      Oil                                 -          2          -          -
      Dry                                 -          1          -          1
    -------------------------------------------------------------------------
      Total                               3          8          1          6
    -------------------------------------------------------------------------


                                                        2006
                                    -----------------------------------------
    ($000's except as noted)             Q4         Q3         Q2         Q1
    -------------------------------------------------------------------------
    Sales volumes:
      Natural gas (mcf/day)          18,440     17,355     17,224     16,631
      Oil and natural gas
       liquids (bbl/day)                483        479        494        420
      Barrels of oil equivalent       3,556      3,372      3,364      3,192
    -------------------------------------------------------------------------
    Financial:
      Net revenue                    11,213      9,536      9,846      9,523
      Net (loss)                    (21,951)    (2,662)    (1,606)    (2,121)
        per share - basic
         ($/share)                   $(0.24)    $(0.03)    $(0.02)    $(0.03)
        per share - diluted
         ($/share)                   $(0.24)    $(0.03)    $(0.02)    $(0.03)
      Capital costs                  12,811      9,746     15,234     19,124
      Shares outstanding (000's)     92,947     86,447     86,447     86,447
      Bank debt                      50,080     52,780     49,580     32,180
      Working capital (deficit)
       including bank debt          (56,271)   (61,783)   (57,789)   (47,357)
    -------------------------------------------------------------------------
    Per unit information:
      Natural gas price ($/mcf)       $7.13      $5.91      $6.28      $7.72
      Oil and liquids price
       ($/barrel)                    $51.54     $62.07     $64.27     $51.07
      Oil equivalent price ($/boe)   $43.96     $39.24     $41.59     $46.09
      Operating netback ($/boe)      $24.24     $21.54     $22.87     $24.59
    -------------------------------------------------------------------------
    Net wells completed: (No.)
      Natural gas                         7          3          9          4
      Oil                                 -          -          -          -
      Dry                                 1          1          1          3
    -------------------------------------------------------------------------
      Total                               8          4         10          7
    -------------------------------------------------------------------------
    

    Ongoing drilling has delivered the production increases for 2006 and 2007
with the decline in production for the third quarter of 2007 caused mainly by
the disposition of Marten Hills production of 250 boe per day. There have been
no further material acquisitions or dispositions.

    RESULTS OF OPERATIONS

    Production Volume

    Production volume averaged 3,796 boe/d for the fourth quarter of 2007, up
seven percent compared to 3,556 boe/d in the fourth quarter of 2006 and up
five percent compared to the third quarter of 2007. Natural gas represented
84 percent of production in the fourth quarter of 2007 with the remaining
production being 15 percent light oil and natural gas liquids and one percent
conventional heavy oil. Light oil and natural gas liquids have increased as a
percent of production as most of the production growth has come from liquids
rich natural gas wells in Pembina and Deep Basin. Ongoing drilling success
throughout 2007 has delivered steady volume increases.
    A six well program was drilled in Lanfine in July. The five successful
wells were not completed and put on stream until late October as the decision
was made to delay production from these wells until expected improvements in
natural gas prices later in the year which contributed to the growth in
production from the third to the fourth quarter of 2007. The growth in
production was delivered despite the sale of 250 boe/d in September 2007 at
Marten Hills.
    Volume averaged 3,728 boe/d for the year ended December 31, 2007, up
11 percent compared to 3,373 boe/d for the year ended December 31, 2006. Key
reasons for the production growth were improved drilling success rates,
primarily in Pembina combined with average well results that were 40 percent
better than budgeted on a production and reserve basis. An integrated approach
combining petrophysics, geophysics and geological mapping has enabled the
Company to target specific trends that have been drilled at higher success
rates and for better individual well results than have been experienced in the
past. With few new wells to be brought on stream in early 2008, first quarter
2008 production is expected to average approximately 3,800 boe/d, flat to
fourth quarter 2007 production. Production improvement is expected beginning
in the second quarter of 2008 as the wells from the winter drilling program
come on stream in March.

    Production Revenue

    Natural gas prices averaged $6.52 per mcf for the fourth quarter of 2007
down nine percent compared to $7.13 per mcf in the fourth quarter of 2006. Oil
and liquids prices averaged $67.47 and $73.86 per barrel respectively in the
fourth quarter of 2007 for a blended price of $71.66 per barrel, up 39 percent
from the fourth quarter 2006 blended oil and liquids price of $51.54 per
barrel. On a boe basis, prices averaged $44.48 in the fourth quarter of 2007,
up one percent compared to $43.96 per boe in the fourth quarter of 2006.
Revenue before results from hedging was up eight percent in the fourth quarter
of 2007 compared to the fourth quarter of 2006 as production volume increased
and prices were up slightly. An additional $2.68 per boe was realized from
hedging gains during the fourth quarter of 2007 increasing total revenue per
boe to $47.16.
    Natural gas prices averaged $6.96 per mcf for the year ended December 31,
2007, up three percent compared to $6.75 per mcf in the year ended
December 31, 2006. Oil and liquids prices averaged $60.57 and $64.08 per
barrel respectively in the year ended December 31, 2007 for a blended price of
$63.02 per barrel, up 10 percent from the year ended December 31, 2006 blended
oil and liquids price of $57.48 per barrel. On a boe basis, prices averaged
$44.98 in the year ended December 31, 2007, up five percent compared to
$42.86 per boe in the year ended December 31, 2006. Revenue before results
from hedging was up 16 percent in the year ended December 31, 2007 compared to
the year ended December 31, 2006 as both volume and prices increased. An
additional $1.65 per boe was realized from hedging gains during the year ended
December 31, 2007 for total revenue per boe of $46.63. There were no volumes
hedged during 2006.

    
    -------------------------------------------------------------------------
    Volumes and prices         Three months                    Year
                             ended December 31          ended December 31
    -------------------------------------------------------------------------
                           2007     2006   Change     2007     2006   Change
    -------------------------------------------------------------------------
    Production revenue
     ($000's)            15,563   14,386       8%   61,281   52,810      16%
    -------------------------------------------------------------------------
    Production volume
      Natural gas
       (mcf/d)           19,018   18,440       3%   18,981   17,420       9%
      Oil and liquids
       (bbl/d)              626      483      30%      564      469      20%
      BOE (bbl/d)         3,796    3,556       7%    3,728    3,373      11%
    Prices
    -------------------------------------------------------------------------
      Natural gas ($/mcf)  6.52     7.13      -8%     6.96     6.75       3%
    -------------------------------------------------------------------------
      Oil and liquids
       ($/bbl)            71.66    51.54      39%    63.02    57.48      10%
    -------------------------------------------------------------------------
      BOE ($/boe)         44.48    43.96       1%    44.98    42.86       5%
    -------------------------------------------------------------------------
      BOE ($/boe
       including hedging) 47.16    43.96       7%    46.63    42.86       9%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Royalties

    Royalties averaged 21 percent of revenue for the fourth quarter of 2007
compared to 22 percent in the fourth quarter of 2006. Royalties have trended
lower on a percent of revenue basis as more wells are drilled on owned and
earned lands compared to earlier periods when a higher percentage of wells
were drilled under farm-in arrangements that provided for overriding royalties
to the farmor. Royalties averaged 23 percent of revenue for the year ended
December 31, 2007 compared to 24 percent for the year ended December 31, 2006.
    Royalty expense of $3.3 million was recorded in the fourth quarter of
2007, up four percent compared to the fourth quarter of 2006 reflecting higher
volume offset partially by lower per unit royalty rates. Royalty expense of
$13.9 million was recorded in the year ended December 31, 2007, up 10 percent
compared to the year ended December 31, 2006 due to higher production volume
and lower per unit royalty rates.

    
    -------------------------------------------------------------------------
    Royalties                  Three months                    Year
                             ended December 31          ended December 31
    -------------------------------------------------------------------------
                           2007     2006   Change     2007     2006   Change
    -------------------------------------------------------------------------
    Royalty expense
     ($000's)             3,286    3,173       4%   13,915   12,692      10%
    Royalty cost per boe  $9.41    $9.92      (5%)  $10.23   $10.67      (4%)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    GLJ Petroleum Consultants ("GLJ") has evaluated the effects of the
Alberta New Royalty Framework on the December 31, 2007 asset value based on
low and high case assumptions as defined by GLJ and other reserve engineering
firms in Calgary. The evaluation established that on a worst case basis,
Berens' net asset value would remain unchanged at $132.7 million on a before
tax 10% discount basis. In the best case, Berens' net asset value would
increase by over 3 percent to $137.0 million. This is consistent with Berens'
expectations based on its current asset mix and GLJ's price assumptions.

    Production Expenses

    Production expenses were $7.23 per boe in the fourth quarter of 2007,
down 18 percent compared to $8.88 per boe in the fourth quarter of 2006.
Fourth quarter 2007 costs were lower on a per unit basis as production has
increased and vigilance on costs remains a key objective. In addition, the
Company acquired an interest in a major Pembina processing plant in December
2006 which has reduced processing costs for natural gas produced in a portion
of the Pembina area.
    Production expenses were $7.55 per boe in the year ended December 31,
2007, down four percent compared to $7.89 per boe in the year ended
December 31, 2006. With ongoing volume increases and cost management, it is
expected future per unit operating expenses will be in the $7.50 per boe
range.
    Fourth quarter 2007 production expenses were $2.5 million, down
13 percent compared to the fourth quarter of 2006 due to lower per unit costs.
Production expenses for the year ended December 31, 2007 were $10.3 million,
up six percent compared to the year ended December 31, 2006 mainly due to
higher volumes.

    
    -------------------------------------------------------------------------
    Production expenses        Three months                    Year
                             ended December 31          ended December 31
    -------------------------------------------------------------------------
                           2007     2006   Change     2007     2006   Change
    -------------------------------------------------------------------------
    Production expenses
     ($000's)             2,524    2,905     (13%)  10,280    9,721       6%
    Production expenses
     per boe              $7.23    $8.88     (18%)   $7.55    $7.89      (4%)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Transportation costs increased 14 percent in the fourth quarter of 2007
compared to the fourth quarter of 2006 due to higher volume and higher per
unit costs.

    Operating Netback(1)

    Operating netback represents the margin realized by the production and
sale of petroleum and natural gas exclusive of results from hedging. Fourth
quarter 2007 operating netbacks improved due to higher per boe prices, lower
per unit royalty rates and lower operating costs.

    -------------------------------------------------------------------------
    Quarterly
    Operating Netbacks         Three months                    Year
    ($'s per boe)            ended December 31          ended December 31
    -------------------------------------------------------------------------
                           2007     2006   Change     2007     2006   Change
    -------------------------------------------------------------------------
    Sales price           44.48    43.96       1%    44.98    42.86       5%
    Less:
      Royalties
       (net of ARTC)       9.41     9.92      (5%)   10.23    10.67      (4%)
      Production expenses  7.23     8.88     (18%)    7.55     7.89      (4%)
      Transportation
       charges             0.99     0.92       8%     0.96     0.91       5%
    -------------------------------------------------------------------------
    Operating netback     26.85    24.23      11%    26.24    23.39      12%
    -------------------------------------------------------------------------
    Operating netback
     including hedging    29.53    24.23      22%    27.89    23.39      19%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) non-GAAP measure - refer to discussion on non-GAAP measures below.
    

    General and Administrative Expenses

    General and administrative ("G&A") expenses, including stock-based
compensation were $1.6 million in the fourth quarter of 2007, up 68 percent
compared to the fourth quarter of 2006. Stock based compensation was higher as
total outstanding options increased. Also, increased incentive bonus payments
were paid in the fourth quarter of 2007 for the strong operating results
achieved during 2007. In the year ended December 31, 2007 G&A expenses were
$5.3 million, up 11 percent compared to the year ended December 31, 2006.
    On per unit basis, general and administrative costs were $4.69 per boe
for the fourth quarter of 2007, up 57 percent compared to $2.99 per boe in the
fourth quarter of 2006. For the year ended December 31, 2007 per unit G&A
costs were $3.92 per boe, almost unchanged from $3.90 per boe for the year
ended December 31, 2006 as volume increases offset the dollar increase in
costs for the per unit calculation. There were no general and administrative
costs capitalized in the fourth quarters or for the years 2007 or 2006.
    Staff levels are expected to remain fairly constant in 2008. Per unit
general and administrative costs are expected to decline as production levels
increase.

    
    -------------------------------------------------------------------------
    General and
    administrative             Three months                    Year
    expenses                 ended December 31          ended December 31
    -------------------------------------------------------------------------
                           2007     2006   Change     2007     2006   Change
    -------------------------------------------------------------------------
    G&A expenses
     ($000's)             1,401      844      66%    4,433    4,090       8%
    Stock based
     compensation           239      133      80%      905      716      26%
    -------------------------------------------------------------------------
                          1,640      977      68%    5,338    4,806      11%
    G&A expenses per boe  $4.69    $2.99      57%    $3.92    $3.90       1%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Interest Expense

    Interest expense was $0.9 million in the fourth quarter of 2007 compared
to $1.0 million in the fourth quarter of 2006. For the year ended December 31,
2007 interest expense was $4.0 million compared to $2.6 million for the year
ended December 31, 2006. Berens raised equity in the fourth quarter of 2005 in
anticipation of the acquisition of Berland and had a significant cash position
at the start of 2006. The subsequent closing of the Berland acquisition in
January 2006 resulted in significant borrowing on the bank operating line as
30 percent of the Berland acquisition cost was in the form of cash and Berens
assumed Berland's debt and working capital deficiency, totaling $28 million.
Capital expenditures in 2006 and the first quarter of 2007 were higher than
funds from operations resulting in higher average debt levels in the 2007
periods compared to the same periods in 2006. Since the first quarter of 2007
the Company's capital program has been funded by cash flows and debt has
declined. Average interest rates on the bank line were similar comparing 2007
to 2006.

    
    -------------------------------------------------------------------------
    Interest Expense           Three months                    Year
                             ended December 31          ended December 31
    -------------------------------------------------------------------------
                           2007     2006   Change     2007     2006   Change
    -------------------------------------------------------------------------
    Interest expenses
     ($000's)               949      972      (2%)   4,028    2,627      53%
    Interest expenses
     per boe              $2.72    $2.97      (8%)   $2.96    $2.13      39%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Depletion, Amortization and Accretion

    Depletion, amortization and accretion ("DA&A") totaled $9.4 million
($26.85 per boe) in the fourth quarter of 2007, down two percent compared to
$9.6 million ($29.24 per boe) in the fourth quarter of 2006. Ongoing drilling
success and low cost reserve additions have brought down per boe DA&A rates
eight percent in the fourth quarter of 2007 compared to the fourth quarter of
2006. In the year ended December 31, 2007 DA&A totaled $39.2 million
($28.79 per boe) up seven percent but four percent lower on a boe basis
compared to $36.7 million ($29.85 per boe) for the year ended December 31,
2006.

    -------------------------------------------------------------------------
    Depletion,
    Amortization               Three months                    Year
    and Accretion            ended December 31          ended December 31
    -------------------------------------------------------------------------
                           2007     2006   Change     2007     2006   Change
    -------------------------------------------------------------------------
    DA&A expenses
     ($000's)             9,379    9,569      (2%)  39,180   36,746       7%
    DA&A expenses
     per boe             $26.85   $29.24      (8%)  $28.79   $29.85      (4%)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Income Taxes

    The Company does not expect to pay current income tax during 2008 as
there are sufficient capital cost pools and expected future capital spending
to shelter taxable income. Current taxes were recorded for flow through share
taxes paid in 2007 for 2006 flow through share issue.
    Future tax recovery was $2.2 million for the fourth quarter of 2007
(77 percent of loss before taxes) compared to a recovery of $5.2 million for
the fourth quarter of 2006 (19 percent of loss before taxes). The percent
recovery of future tax was lower in the fourth quarter of 2006 as non-taxable
$24 million goodwill impairment was recorded in the fourth quarter of 2006.
Future tax recovery was $4.3 million for the year ended December 31, 2007
(14 percent of loss before taxes) compared to a recovery of $10.2 million for
the year ended December 31, 2006 (27 percent of loss before taxes). The 2006
recovery was higher as significant tax rate reduction benefits were recorded
in 2006 for enacted corporate income tax rate reductions.

    GOODWILL IMPAIRMENT

    Goodwill, at the time of acquisition, represents the excess of purchase
cost of a business over the fair value of net assets acquired. Thereafter,
goodwill is not amortized and is assessed for impairment at least annually. If
the estimated fair value of the business is less than the book value, a second
test is performed to determine the amount of the impairment. Goodwill was
originally recorded primarily on the Resolution Resources Ltd. acquisition
(2003) and the Berland Exploration Ltd. acquisition (2006).
    The Company recorded a partial impairment of goodwill in the fourth
quarter of 2006. Since that time oil and gas company valuations eroded
further, especially those of natural gas weighted producers primarily due to
the decline in natural gas prices and high service costs in the industry. The
Company tested the goodwill balance as at September 30, 2007 taking into
account the decline in corporate economic value caused in 2007 by the decline
in the share price. Recent oil and gas asset sales and corporate sale
transactions were also benchmarked for the goodwill test. Based on the
Company's assessment, it was determined that the fair value of the assets was
less than the book value including the amount of goodwill that was being
carried on the balance sheet. As a result, the Company recorded an impairment
of goodwill for the remaining amount of the goodwill balance of $20.8 million
in the third quarter of 2007.

    NET LOSS

    The net loss for the fourth quarter of 2007 was $0.1 million ($0.01 per
share) compared to a loss of $22.0 million ($0.24 per share) in the fourth
quarter of 2006. Goodwill impairment was recorded in the fourth quarter of
2006 causing the higher loss in that period.
    The net loss for the year ended December 31, 2007 was $27.4 million
($0.30 per share) compared to a net loss of $28.3 million ($0.33 per share)
for the year ended December 31, 2006. Both annual periods had goodwill
impairments recorded resulting in the majority of the losses.

    CAPITAL COSTS

    Capital costs were $6.4 million in the fourth quarter of 2007 compared to
$13.3 million in the fourth quarter of 2006. A total of three net wells were
drilled in the fourth quarter of 2007 compared to eight net wells in the
fourth quarter of 2006. In both quarterly periods the main activity was in the
Pembina area. For the year ended December 31, 2007 $32.9 million of capital
costs were incurred compared to $57.1 million for the year ended December 31,
2006 with 18 net wells drilled in 2007 compared to 29 net wells in 2006.
Capital spending in 2006 also included $102.7 million for the acquisition of
Berland. The 2006 period reflects a very active capital program following the
acquisition of Berland Exploration in January 2006. The 2007 capital program
was funded almost entirely by cash flow resulting in 16 percent reserve growth
with a six percent increase in debt.

    
    -------------------------------------------------------------------------
                                        Three months
                                            ended              Year ended
    ($000's)                             December 31,          December 31,
    -------------------------------------------------------------------------
                                       2007       2006       2007       2006
    -------------------------------------------------------------------------
    Drilling and completion           3,510      8,509     24,846     39,465
    Equipping and tie-ins             2,476      2,965     10,621     13,342
    Land                                 42        512      1,418      2,535
    Geological and geophysical          370        384      2,390      1,048
    Office and other                      4         37         56        295
    -------------------------------------------------------------------------
    Total                             6,421     12,407     39,331     56,685
    Asset retirement obligation           -        143        297        462
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total exploration and
     development                      6,421     12,550     39,628     57,140
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net acquisitions (dispositions)       -        766     (6,750)   102,723
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total capital                     6,421     13,316     32,878    159,870
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Drilling, completion, equip and tie-in activity represented 93 percent of
the capital spent in the fourth quarter of 2007 and 90 percent of capital for
the year ended December 31, 2007 as capital activity focused on developing the
extensive land base. A $30 million capital budget is planned for 2008,
89 percent of which is targeted toward drilling, completion, equip and tie-in
activity. It is expected that 2008 capital spending will be funded by cash
flow provided by operating activities.

    WORKING CAPITAL

    Accounts receivable of $10.3 million at December 31, 2007 were primarily
revenue receivables ($5.8 million) and amounts owing from partners
($4.3 million). Accounts payable at December 31, 2007 of $16.5 million were
mainly comprised of trade payables for capital and operating costs
($8.9 million), royalties ($1.5 million), amounts owing to partners
($1.3 million), unspent cash calls received from partners ($2.0 million) and
capital costs accrued at the end of the quarter for ongoing drilling and
completion operations ($1.4 million).
    Working capital excluding bank indebtedness was in a deficit position of
$5.6 million at December 31, 2007. Borrowings under the bank line and ongoing
cash flows are expected to fund the working capital deficit.

    LIQUIDITY AND CAPITAL RE

SOURCES The Company plans to fund its current working capital deficit, operations and capital costs with a mix of operating cash flow and debt financing through the bank operating line. An operating bank line was in place for $62.5 million at December 31, 2007, secured by producing properties. At December 31, 2007, $53.9 million was drawn on the bank line. Future capital spending is planned at amounts that can be met with expected Company cash flow. NON-GAAP MEASUREMENTS This MD&A contains the term "funds from operations" and "operating netback". As an indicator of the Company's performance, these terms should not be considered an alternative to, or more meaningful than "cash flow from operating activities" or "net income (loss)" as determined in accordance with Canadian generally accepted accounting principles. The Company's determination of funds from operations and operating netback may not be comparable to those reported by other companies, especially those in other industries. Management feels that funds from operations is a useful measure to help investors assess whether the Company is generating adequate cash amounts from its operations for its ongoing operations and planned capital program. Operating netback is a useful measure for comparing the Company's price realization and cost performance against industry competitors. The reconciliation between net income and funds from operations for the periods ended December 31 is as follows: ------------------------------------------------------------------------- Three months ended Year ended ($000's) December 31 December 31 ------------------------------------------------------------------------- 2007 2006 2007 2006 ------------------------------------------------------------------------- Cash flow provided by (used in) operating activities 1,588 4,614 28,318 13,226 Changes in non-cash working capital items related to operating activities 6,403 1,504 1,236 9,245 ------------------------------------------------------------------------- Funds from operations 7,991 6,118 29,554 22,471 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Funds from operations are also presented on a per share basis consistent with the calculation of net loss per share, whereby per share amounts are calculated using the weighted average number of shares outstanding. Funds from operations per share were $0.09 (basic and diluted) for the fourth quarter of 2007 and $0.32 per share (basic and diluted) for the year ended December 31, 2007 compared to $0.07 per share for the fourth quarter of 2006 and $0.26 for the year ended December 31, 2006. RISKS Primary financial risks relate to volatility of commodity prices. Interest rate and currency exchange rate fluctuations also have an effect on financial results. The effect of changes in the exchange rate between US and Canadian currencies on natural gas prices is not direct, as variations between the regional markets for natural gas are often much greater than can be explained by currency variability. The Province of Alberta has announced plans for royalty changes for both conventional oil and natural gas and oil sands operations beginning in 2009. The effect of the changes to the royalty structure in Alberta may cause measurement uncertainty for certain oil and natural gas assets as oil and gas assets are valued under the new royalty system using various commodity price scenarios. Other risks are related to operations. These risks include, but are not limited to, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, delays or changes in plans with respect to exploration or development projects or capital costs, volatility of commodity prices, currency fluctuations, the uncertainty of reserves estimates, potential environmental liabilities, technology risks, competition for services and personnel, incorrect assessment of the value of acquisitions and failure to realize the anticipated benefits of acquisitions. The foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect operations or financial results are included in a more detailed description of risks in Berens' Annual Information Form on file with Canadian securities regulatory authorities and available on SEDAR at www.sedar.com. Documented environmental health and safety plans are in place as well as a comprehensive emergency response plan to mitigate operating risks. COMMODITY PRICE RISK MANAGEMENT The Company may use financial derivative or fixed price contracts to manage its exposure to fluctuations in commodity prices and foreign currency exchange rates. The Company applies the fair value method of accounting for derivative instruments by initially recording an asset or liability, and recognizing changes in the fair value of the derivative instrument in income. The following is a summary of natural gas price risk management financial derivative contracts in effect as of the date of this MD&A. All contracts are priced in Canadian dollars per gigajoule (GJ). The price per GJ can be converted to an approximate price per MCF by multiplying the per GJ price by 1.05. GJ can be converted to an approximate MCF volume by multiplying the GJ volume by 0.95. ------------------------------------------------------------------------- NATURAL GAS HEDGING ------------------------------------------------------------------------- Daily quantity (GJ) Term of contract Fixed price per gigajoule ------------------------------------------------------------------------- 2,000 January 1 to March 31, 2008 $7.25 floor; $8.65 cap ------------------------------------------------------------------------- 2,000 January 1 to March 31, 2008 $7.50 floor; $9.45 cap ------------------------------------------------------------------------- 2,000 January 1 to December 31, 2008 $6.65 fixed price ------------------------------------------------------------------------- 2,000 April 1 2008 to March 31, 2009 $6.72 fixed price ------------------------------------------------------------------------- 2,000 April 1 to December 31, 2008 $6.65 fixed price ------------------------------------------------------------------------- 2,000 April 1 to December 31, 2008 $6.80 fixed price ------------------------------------------------------------------------- 2,000 April 1 to October 31, 2008 $6.80 fixed price ------------------------------------------------------------------------- 2,000 April 1 to October 31, 2008 $7.45 fixed price ------------------------------------------------------------------------- ------------------------------------------------------------------------- CRUDE OIL HEDGING ------------------------------------------------------------------------- Daily quantity Fixed price per barrel (bbl) Term of contract (US WTI translated to C$) ------------------------------------------------------------------------- 100 January 1 to December 31, 2008 $85.00 floor; $93.30 cap ------------------------------------------------------------------------- 100 January 1 to December 31, 2008 $85.00 floor; $98.10 cap ------------------------------------------------------------------------- The fair value of the above natural gas derivative instruments marked to market as at December 31, 2007, results in an unrealized gain position of $162,000 compared to an unrealized gain position of $635,000 at December 31, 2006. There were $937,000 ($2.68 per boe) of realized gains on derivative instruments in the fourth quarter of 2007 and $2,243,000 ($1.65 per boe) for the year ended December 31, 2007. The average floor price or fixed price of the natural gas hedging transactions for 2008 is $6.87 per GJ ($7.23 per mcf) which will provide protection to corporate cash flow if natural gas prices fall below these levels. The average floor price for the oil hedges is $85.00 per barrel. Absent the above-noted risk management contracts, the effects of changes in commodity prices on cash flow before working capital changes are summarized in the following table. ------------------------------------------------------------------------- Commodity Price change Cash flow change ($ 000's) ------------------------------------------------------------------------- Natural gas ($/mcf) 1.00 $5,800 ------------------------------------------------------------------------- Oil and Liquids ($/bbl) 10.00 $1,600 ------------------------------------------------------------------------- RELATED PARTY TRANSACTIONS Fees for legal services are paid to a law firm in which the corporate secretary is a partner. The legal services are rendered in the normal course of business at normal rates charged by the law firm. Legal fees for this firm paid in the fourth quarter of 2007 were $13,000 and $206,000 for the year ended December 31, 2007. SHARE DATA As of the date of this MD&A the Company had 93,172,064 issued and outstanding common shares. Additionally, options to purchase 6,238,200 common shares have been issued. DISCLOSURE CONTROLS AND PROCEDURES OVER FINANCIAL REPORTING The Company has established procedures and internal control systems designed to ensure timely and accurate preparation of financial, internal management and other reports. Disclosure controls and procedures are in place designed to ensure all ongoing statutory reporting requirements are met and material information is disclosed on a timely basis. The Chief Executive Officer and the Chief Financial Officer, individually, sign certifications that the financial statements, together with the other financial information included in the regulatory filings, fairly present in all material respects the financial condition, results of operation, and cash flows as of the dates and for the periods represented. INTERNAL CONTROL OVER FINANCIAL REPORTING Management of Berens is responsible for establishing and maintaining adequate internal controls over financial reporting. Internal controls over financial reporting are part of a process designed under the supervision of the Chief Executive Officer and the Chief Financial Officer and monitored by the Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company reported on these controls as part of its 2006 continuous disclosure requirements (please refer to the MD&A for the year ended December 31, 2006 available on SEDAR (www.SEDAR.com) and on our website www.berensenergy.com). There have been no changes to internal controls over financial reporting or management's assessment of the design of these internal controls in the period since December 31, 2006. RISKS AND UNCERTAINTIES, CRITICAL ACCOUNTING ESTIMATES AND RECENT ACCOUNTING PRONOUNCEMENTS The MD&A is based on the consolidated financial statements, which have been prepared in Canadian dollars in accordance with GAAP. The application of GAAP requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates are based on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates under different assumptions or conditions. For a discussion of Risks and Uncertainties, Critical Accounting Estimates and Recent Accounting Pronouncements please refer to the audited financial statements and the Annual Information Form for the year ended December 31, 2006 available on SEDAR (www.SEDAR.com) and on our website (www.berensenergy.com). As of January 1, 2007, the Company adopted the Canadian Institute of Chartered Accountants ("CICA") Section 1530 "Comprehensive Income", Section 3251 "Equity", Section 3855 "Financial Instruments - Recognition and Measurement", and Section 3865 "Hedges", which were issued in January 2005. CICA handbook section 1506, "Accounting Changes" was also adopted on January 1, 2007. The adoption of these standards had no effect on the presentation of the financial statements. OUTLOOK Berens has demonstrated production growth, controlled costs and improved drilling success. Production growth has followed the drilling success experienced in late 2006 which continued through 2007. Net drilling success in 2007 was 86 percent and the average well results for reserves and production have exceeded expectations significantly. A disciplined approach to cost management has achieved significant reduction in our cost structure supported by moderation in the overall industry cost structure. These factors combined have lowered the Company's finding and development costs in 2007 to $12.85 per boe. Capital spending for 2008 is projected at $30 million and will be funded with cash flow from operations. Capital spending for 2008 will be focused in Pembina where the reserve life of new wells is longest and the wells have the strongest economics. There are currently 100 inventoried drilling locations on existing lands. An active drilling program is underway in the first quarter of 2008 in Pembina and Deep Basin. Debt and working capital balances have improved and will continue to improve with the planned capital spending plans. With an extensive land base and a large number of inventoried drilling locations, management anticipates that the Company will be positioned to develop our asset base more aggressively as natural gas prices improve. Berens Energy Ltd. Balance Sheets As at, ------------------------------------------------------------------------- (000's) December 31, December 31, 2007 2006 ------------------------------------------------------------------------- ASSETS (note 8) Current Cash and cash equivalents (note 4) $ 1 $ 10 Accounts receivable 10,315 19,601 Unrealized gain on risk management (note 13) 162 635 Prepaid expenses and deposits 442 215 ------------------------------------------------------------------------- 10,920 20,461 Property, plant and equipment (note 6) 166,405 172,404 Goodwill (notes 5 and 14) - 20,755 ------------------------------------------------------------------------- $ 177,325 $ 213,620 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY Current Bank loan (note 8) $ 53,900 $ 50,080 Accounts payable and accrued liabilities 16,523 26,622 Taxes payable 14 29 ------------------------------------------------------------------------- 70,437 76,731 Asset retirement obligations (note 7) 3,273 2,645 Future income taxes (note 10) 10,199 14,518 ------------------------------------------------------------------------- 83,909 93,894 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Commitments (note 16) Shareholders' equity Capital stock (note 9) 148,263 148,038 Contributed surplus (note 9) 2,195 1,290 Deficit (57,042) (29,602) ------------------------------------------------------------------------- 93,416 119,726 ------------------------------------------------------------------------- $ 177,325 $ 213,620 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the financial statements Berens Energy Ltd. Statements of Operations and Comprehensive Loss and Deficit For the three months and year ended December 31, ------------------------------------------------------------------------- (000's) Three months Year ended ended December 31, December 31, ------------------------------------------------------------------------- 2007 2006 2007 2006 ------------------------------------------------------------------------- Revenue Oil and natural gas revenue $ 15,563 $ 14,386 $ 61,281 $ 52,810 Royalties, net of ARTC (3,286) (3,173) (13,915) (12,692) ------------------------------------------------------------------------- 12,277 11,213 47,366 40,118 Realized gain on risk management (note13) 937 - 2,243 - ------------------------------------------------------------------------- 13,214 11,213 49,609 40,118 Unrealized gain (loss) on risk management (note 13) (1,296) 635 (473) 635 ------------------------------------------------------------------------- 11,918 11,848 49,137 40,753 Interest and other income - - 31 18 ------------------------------------------------------------------------- 11,918 11,848 49,167 40,771 ------------------------------------------------------------------------- Expenses Production 2,524 2,905 10,280 9,721 Transportation 346 302 1,307 1,116 Depletion, amortization and accretion 9,377 9,569 39,180 36,747 Impairment of goodwill (note 14) - 24,220 20,755 24,220 General and administrative (note 12) 1,401 845 4,433 4,090 Stock-based compensation (note 9) 239 133 905 716 Interest 949 972 4,027 2,627 ------------------------------------------------------------------------- 14,836 38,946 80,887 79,237 ------------------------------------------------------------------------- Loss before income taxes (2,918) (27,098) (31,720) (38,466) Income taxes (note 10) Future expense (recovery) (2,241) (5,218) (4,319) (10,237) Current expense 3 71 39 111 ------------------------------------------------------------------------- (2,238) (5,147) (4,280) (10,126) ------------------------------------------------------------------------- Net loss and comprehensive loss for the period (680) (21,951) (27,440) (28,340) Deficit, beginning of period (56,362) (7,651) (29,602) (1,262) ------------------------------------------------------------------------- Deficit, end of period $ (57,042) $ (29,602) $ (57,042) $ (29,602) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net income (loss) per share (note 15) Basic and diluted $ (0.01) $ (0.24) $ (0.30) $ (0.33) ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the financial statements Berens Energy Ltd. Statements of Cash Flows For the three months and year ended December 31, ------------------------------------------------------------------------- (000's) Three months Year ended ended December 31, December 31, ------------------------------------------------------------------------- 2007 2006 2007 2006 ------------------------------------------------------------------------- OPERATING ACTIVITIES Net income (loss) for the period $ (680) $ (21,951) $ (27,440) $ (28,340) Add items not involving cash Depletion, amortization and accretion 9,377 9,569 39,180 36,747 Impairment of goodwill - 24,220 20,755 24,220 Unrealized risk management (gain) loss 1,296 (635) 473 (635) Future income tax recovery (2,241) (5,218) (4,319) (10,237) Stock-based compensation 239 133 905 716 ------------------------------------------------------------------------- 7,991 6,118 29,554 22,471 Change in non-cash working capital items related to operating activities (note 10) (6,403) (1,504) (1,236) (9,245) ------------------------------------------------------------------------- Cash flow provided by operating activities 1,588 4,614 28,318 13,226 ------------------------------------------------------------------------- FINANCING ACTIVITIES Change in bank loan 3,100 (2,700) 3,820 30,330 Net proceeds from private offerings - 11,142 - 30,955 Sale of investment - 25 29 269 Proceeds from the exercise of stock options - - 225 - ------------------------------------------------------------------------- Cash flow provided by financing activities 3,100 8,467 4,074 61,554 ------------------------------------------------------------------------- INVESTING ACTIVITIES Cash acquired through Berland acquisition - - - 109 Cash component on Berland acquisition - - - (28,682) Purchase of property and equipment (6,421) (12,581) (39,331) (56,685) Disposition of property and equipment 6,750 Change in non-cash working capital items related to investing activities (note 10) 1,733 (534) 180 1,016 ------------------------------------------------------------------------- Cash flow used in investing activities (4,688) (13,115) (32,401) (84,242) ------------------------------------------------------------------------- Increase (decrease) in cash and cash equivalents - (34) (9) (9,462) Cash and cash equivalents, beginning of period 1 44 10 9,472 ------------------------------------------------------------------------- Cash and cash equivalents, end of period $ 1 $ 10 $ 1 $ 10 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the financial statements BERENS ENERGY LTD. Notes to Financial Statements Years ended December 31, 2007 and 2006 1. NATURE OF OPERATIONS Berens Energy Ltd. (the "Company") is a full cycle oil and natural gas exploration and production company with activities encompassing land acquisition, geological and geophysical assessment, drilling and completion, and production. The primary areas of operation are in eastern and west central Alberta. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles ("GAAP"). The nature of the business and timely preparation of financial statements requires that management make estimates and assumptions, and use judgment regarding assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, actual results may differ from estimated amounts. In the opinion of management, these financial statements have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting policies summarized below. Cash and Cash Equivalents Cash and cash equivalents, consisting of cash and short-term investments with a maturity of less than three months, are recorded at the lower of cost and quoted market value. Capitalized Costs The full cost method of accounting is followed whereby all costs relating to the acquisition of, exploration for and development of oil and gas reserves are capitalized in a single Canadian cost centre. Such costs include lease acquisition, lease rentals on undeveloped properties, geological and geophysical costs, drilling both productive and non-productive wells, production equipment and overhead charges directly related to acquisition, exploration and development activities. Gains or losses are not recognized on the disposition of oil and gas properties unless such dispositions would change the depletion rate by 20 percent or more. Gains and losses are recognized on the disposition of other assets. Depletion and Amortization All costs of acquisition, exploration and development of oil and gas reserves, associated tangible plant and equipment costs (net of salvage value), and estimated costs of future development of proved undeveloped reserves are depleted and amortized using the unit of production method. This method is based on estimated gross proved reserves as determined by independent engineers. Costs of unproved properties are initially excluded from petroleum and natural gas properties for the purpose of calculating depletion. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion. The volumes of oil and natural gas reserves and production are converted to equivalent barrels of oil based on the relative energy content of each product such that six thousand cubic feet of natural gas equals one barrel of oil, commonly known as the six to one basis. Office and computer equipment is amortized on a straight-line basis over ten and four years, respectively. Ceiling Test The Company applies an impairment test to the net carrying amount of petroleum and natural gas assets designed to ensure that such costs do not exceed their estimated fair value ultimately recoverable. The test is a two part test whereby the first step is to compare the net carrying amount of the asset to the aggregate of estimated undiscounted future net cash flows from production of proved reserves and the cost of unproved properties less impairment. Future cash flows are estimated using future prices and costs without discounting. Should the net carrying value of the petroleum and natural gas assets exceed the amount ultimately recoverable, the amount of impairment is determined through the performance of the second part of the test whereby the discounted estimated future cash flows from proved and probable reserves based on the future prices plus the cost of unproved properties, net of impairment allowances, is compared to the book value of the related assets. Any reduction in net carrying value, as a result of the impairment test, is included in depreciation and depletion expense. Asset Retirement Obligations The Company estimates the present value of the asset retirement obligation in the period in which it is incurred or when a reasonable estimate of its fair value can be made, and records a corresponding increase in the carrying value of the related long-lived asset. The estimated fair value is determined through a review of engineering studies, industry guidelines and management's estimate on a site-by-site basis. The liability is subsequently adjusted for the passage of time, which is recognized as an accretion expense in the statement of operations and included in asset retirement obligations. The liability is also adjusted due to revisions in either the timing or the amount of the original estimated cash flows associated with the liability. The increase in the carrying value of the asset is amortized using the unit of production method based on estimated gross proved reserves. Actual costs incurred upon settlement of the asset retirement obligations are charged against the asset retirement obligation to the extent of the liability recorded. Any difference between the actual costs incurred upon settlement of the asset retirement obligation and the recorded liability is recognized as a gain or loss in the Company's statement of operations in the period in which the settlement occurs. Goodwill Goodwill represents the excess of purchase cost of a business over the estimated fair value of net assets acquired at the time of a business combination. Thereafter, goodwill is not amortized and is assessed for impairment at least annually. If the estimated fair value of the net assets of a reporting unit is less than their book value, a second test is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the estimated fair value of the reporting unit's net assets from the total fair value to determine the implied fair value of goodwill and comparing that amount to the book value of goodwill. Revenue Recognition Oil and natural gas sales are recognized when the significant risks and rewards of ownership have transferred to the buyer, the price is determinable and there is reasonable assurance regarding collectability of the consideration. Income Taxes The liability method of accounting for income taxes is followed. Under this method, future tax assets and liabilities are determined based on the differences between financial reporting and income tax bases of assets and liabilities, and are measured using substantively enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect on future tax assets and liabilities of a change in tax rates is recognized in net income in the period in which the change occurs. Joint Ventures A substantial portion of the Company's exploration, development and production activities is conducted jointly with others. These financial statements reflect only the Company's proportionate interest in such activities. Stock-Based Compensation Under the stock option plan described in note 9, options to purchase common shares are granted to directors, officers, employees and consultants with option strike prices based on the market price at the time of the grant. Options issued by the Company are accounted for in accordance with the fair value method of accounting for stock-based compensation using the Black-Scholes option pricing model. The resulting cost of the option is charged to income over the vesting period of the option with a corresponding increase in contributed surplus. At the time of exercise, the related amounts previously credited to contributed surplus are also transferred to share capital. In the event that vested options expire without being exercised, previously recognized compensation costs associated with such stock options are not reversed. Measurement Uncertainty The amount recorded for depletion and amortization of oil and gas properties, the provision for asset retirement obligations, goodwill measurement and the ceiling test calculation are based on estimates of gross proved reserves, production rates, commodity prices, future costs and other assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future years could be material. Per Share Information Per share information is calculated on the basis of the weighted average number of common shares outstanding during the fiscal year. Diluted per share information reflects the potential dilution that could occur if securities or other contracts to issue common shares were exercised or converted to common shares. Diluted per share information is calculated using the treasury stock method which assumes that any proceeds received by the Company upon the exercise of in-the-money stock options would be used to buy back common shares at the average market price for the period. Flow-through Common Shares Resource expenditure deductions for income tax purposes related to exploration and development activities funded by flow-through share arrangements are renounced to investors in accordance with income tax legislation. The estimated tax benefits transferred to shareholders are recorded as future income taxes and a reduction to share capital when the expenditures are renounced, which for accounting purposes, is when the appropriate documentation is filed with Canada Revenue Agency. 3. CHANGES IN ACCOUNTING POLICIES Effective January 1, 2007, the Company adopted six new accounting standards issued by the Canadian Institute of Chartered Accountants ("CICA"): Handbook Section 3855 "Financial Instruments - Recognition and Measurement", Section 3861 "Financial Instruments - Disclosure and Presentation", Section 3865 "Hedges", Section 1506 "Accounting Changes", Section 1530 "Comprehensive Income" and Section 3251 "Equity". Impact upon adoption of Sections 3855, 3861, 3865, 1506, 1530 and 3251 The adoption of the new standards did not have a significant impact on the Company's financial statements due to the nature of the financial instruments recorded on the balance sheet and the contracts to which the Company is a party. Financial instruments - recognition and measurement Section 3855 establishes standards for recognizing and measuring financial assets, financial liabilities and non-financial derivatives. It requires that financial assets and financial liabilities, including derivatives, be recognized on the balance sheet when the Company becomes a party to the contractual provisions of the financial instrument or non-financial derivative contract. Under this standard, all financial instruments are required to be measured at fair value upon initial recognition except for certain related party transactions. Measurement in subsequent periods depends on whether the financial instrument has been classified as held-for-trading, available-for sale, held-to-maturity, loans or receivables, or other financial liabilities. Financial assets and financial liabilities held-for-trading are measured at fair value with changes in those fair values recognized in net income. Financial assets held-to-maturity, loans and receivables, and other financial liabilities are measured at amortized cost using the effective interest method of amortization. Investments in equity instruments classified as available-for-sale that do not have a quoted market price in an active market are measured at cost. Derivative instruments are recorded on the balance sheet at fair value, including those derivatives that are embedded in financial or non-financial contracts that are not closely related to the host contracts. Changes in the fair values of derivative instruments are recognized in net income, with the exception of derivatives designated as effective cash flow hedges and hedges of the foreign currency exposure of a net investment in a self-sustaining foreign operation, which are recognized in other comprehensive income. In addition, Section 3855 requires that an entity must select an accounting policy of either expensing debt issue costs as incurred or applying them against the carrying value of the related asset or liability. The financial instruments recognized on the Company's balance sheet are deemed to approximate their estimated fair values; therefore, no further adjustments were required upon adoption of the new sections. There were no financial assets on the balance sheet which were designated as held-for-trading, held-to-maturity or available-for-sale. All financial assets were classified as loans or receivables and are accounted for on an amortized cost basis. All financial liabilities were classified as other liabilities. Hedges Section 3865 provides alternative treatments to Section 3855 for entities which choose to designate qualifying transactions as hedges for accounting purposes. It replaces and expands on Accounting Guideline 13 "Hedging Relationships", and the hedging guidance in Section 1650 "Foreign Currency Translation" by specifying how hedge accounting is applied and what disclosures are necessary when it is applied. The Company does not follow hedge accounting for its risk management activities and therefore the adoption of Section 3865 "Hedges" did not have any impact on the Company's financial statements. Accounting changes Section 1506 provides expanded disclosures for changes in accounting policies, accounting estimates and corrections of errors. Under the new standard, accounting changes should be applied retrospectively unless otherwise permitted or where impracticable to determine. As well, voluntary changes in an accounting policy are to be made only when required by a primary source of GAAP or the change results in more relevant and reliable information. Comprehensive income (loss) and accumulated other comprehensive income (loss) Section 1530 introduces comprehensive income, which consists of net income and other comprehensive income ("OCI"). OCI represents changes in shareholders' equity during a period arising from transactions and changes in prices, markets, interest rates and exchange rates. OCI includes unrealized gains and losses on financial assets classified as available-for-sale, unrealized translation gains and losses arising from self-sustaining foreign operations net of hedging activities and changes in the fair value of the effective portion of cash flow hedging instruments. The Company has not entered into any transactions which require any amounts to be recorded to other comprehensive income (loss) or accumulated other comprehensive income (loss). Equity Section 3251 establishes standards for the presentation of equity and changes in equity during the reporting period. The requirements under this Section have been presented in these annual financial statements. Future accounting changes On December 1, 2006, the CICA issued three new accounting standards: Handbook Section 1535, Capital Disclosures; Handbook Section 3862, Financial Instruments - Disclosures, and Handbook Section 3863; Financial Instruments - Presentation. These new standards are effective January 1, 2008. Section 1535 specifies the disclosure of (i) an entity's objectives, policies and processes for managing capital; (ii) quantitative data about what the entity regards as capital; (iii) whether the entity has complied with any capital requirements; and (iv) if it has not complied, the consequences of such non-compliance. The new Sections 3862 and 3863 replace Handbook Section 3861, Financial Instruments - Disclosure and Presentation, revising and enhancing its disclosure requirements and carrying forward unchanged its presentation requirements. These new sections place increased emphasis on disclosures about the nature and extent of risks arising from financial instruments and how the entity manages those risks. The Company is currently assessing the effects of these new standards on our financial statements. On February 13, 2008, the Canadian Accounting Standards Board ("AcSB") confirmed the use of International Financial Reporting Standards ("IFRS") for publicly accountable profit-oriented enterprises, beginning on January 1, 2011 with appropriate comparative data from the prior year. IFRS will replace the current CICA Handbook as Canadian GAAP. Under IFRS significantly increased disclosure is required, especially for interim reporting. While IFRS uses a conceptual framework similar to Canadian GAAP, there are significant differences in accounting policies which must be addressed. The effects of these new standards on the Company's financial statements is currently being assessed. 4. CASH AND CASH EQUIVALENTS Cash and cash equivalents are in the form of cash bank balances or certificates of deposit from Canadian financial institutions with terms of less than 90 days. The effective interest rate on the deposits at December 31, 2007 was 2.3 percent (2006 - 2.3 percent). 5. ACQUISITION OF BERLAND EXPLORATION LTD. On January 18, 2006, the Company and Berland Exploration Ltd. ("Berland") closed a previously announced arrangement that saw the Company acquire Berland. Pursuant to the arrangement, shareholders of Berland received $0.96 in cash ($20.0 million) and 0.8784 of a Berens common share (21,083,795 common shares for $53.8 million) for each Berland common share. Additionally, certain option and warrant holders received a differential payment for the difference between their option and warrant strike prices and $3.20 per Berland share ($8.7 million). Pursuant to the Arrangement, the Company also assumed $19.7 million of Berland debt and transaction costs of $0.5 million. The total cost to the Company to acquire the Berland shares was $102.7 million. This acquisition has been accounted for using the purchase method with the Berland results included in the statement of operations from the closing date of January 18, 2006. The following table summarizes the estimated fair value of the assets acquired and liabilities assumed as at the closing date. Assets and liabilities purchased ($000's) ------------------------------------------------------------------------- Cash and cash equivalents 109 Accounts receivable 10,321 Prepaid expenses and deposits 1,488 Petroleum and natural gas properties 97,616 Goodwill 30,288 Accounts payable and accrued liabilities (20,247) Future income taxes (16,111) Asset retirement obligations (715) ------------------------------------------------------------------------- Total cost to acquire Berland 102,749 ------------------------------------------------------------------------- 6. PROPERTY, PLANT AND EQUIPMENT December 31, 2007 December 31, 2006 Accumulated Accumulated depletion and depletion and ($000's) Cost depreciation Cost depreciation ------------------------------------------------------------------------- Petroleum and natural gas properties 274,067 108,045 241,244 69,305 Office and computer equipment 734 351 707 242 ------------------------------------------------------------------------- 274,801 108,396 241,951 69,547 ------------------------------------------------------------------------- Net book value 166,405 172,404 ------------------------------------------------------------------------- At December 31, 2007, costs of $21,159,000 (2006 - $25,907,000) related to undeveloped land have been excluded from the depletion and depreciation calculation. At December 31, 2007 estimated future development costs of $15,511,000 have been included in the depletion and depreciation calculation (2006 - $13,018,000). A ceiling test was completed at December 31, 2007 resulting in no impairment. Benchmark pricing used for ceiling test purposes is shown in the following table. Oil -------------------------------------------- Cromer Medium WTI Edmonton 29.30 Cushing Par Price Hardisty API Oklahoma 400 API Heavy degree ($US/ ($Cdn/ ($Cdn/ ($Cdn/ bbl) bbl) bbl) bbl) ---------- ---------- ---------- --------- Year Forecast 2008 92.00 91.10 54.02 79.26 2009 88.00 87.10 51.61 75.78 2010 84.00 83.10 49.19 72.30 2011 82.00 81.10 47.98 70.56 2012 82.00 81.10 47.98 70.56 2013 82.00 81.10 49.04 70.56 2014 82.00 81.10 50.09 70.56 2015 82.00 81.10 51.15 70.56 2016 82.02 81.12 52.21 70.57 2017 83.66 82.76 53.29 72.00 2018+ +2.0%/yr +2.0%yr +2.0%/yr +2.0%/yr Natural gas NGLs ------------ ---------- FOB Field AECO-C Gate Inflation Gas (propane/ rate(1)% Exchange Price butane) per year rate(2) ($Cdn/ ($Cdn/ ($Cdn/ ($US/ MMbtu) bbl) MMbtu) Cdn) ----------- ---------- ---------- --------- Year Forecast 2008 6.75 65.59 2.0 1.00 2009 7.55 62.71 2.0 1.00 2010 7.60 59.83 2.0 1.00 2011 7.60 58.39 2.0 1.00 2012 7.60 58.39 2.0 1.00 2013 7.60 58.39 2.0 1.00 2014 7.80 58.39 2.0 1.00 2015 7.97 58.39 2.0 1.00 2016 8.14 58.40 2.0 1.00 2017 8.31 59.59 2.0 1.00 2018+ +2.0%/yr +2.0%/yr 2.0 1.00 7. ASSET RETIREMENT OBLIGATIONS The total future asset retirement obligations were estimated based on the net ownership interest in all wells and facilities, estimated costs to reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred in future periods. The estimated net present value of the total asset retirement obligations is $3,273,000 as at December 31, 2007 (2006 - $2,645,000) based on a total future liability of $8,611,000 (2006 - $6,959,400). These payments are expected to be made over the next 5 to 15 years. An inflation rate of 2 percent and a credit adjusted risk free rate of 10 percent were used to calculate the present value of the asset retirement obligations. The following table reconciles the asset retirement obligations: ($000's) 2007 2006 --------------------------------------------------------------------- Obligation, beginning of year 2,645 1,223 Increase in obligation during the year 297 430 Obligation assumed from Berland acquisition - 715 Increase due to increase in inflation rate - 32 Accretion expense 331 245 --------------------------------------------------------------------- Obligation, end of year 3,273 2,645 --------------------------------------------------------------------- 8. BANK OPERATING LINE An agreement with a Canadian bank is in place for an operating bank line totaling $62.5 million at December 31, 2007. Collateral for the facility consists of a general assignment of book debts and a $35.0 million debenture with a floating charge over all assets of the Company and a $75.0 million supplemental debenture with a floating charge over all assets of the Company. The bank line is a demand line and carries an interest rate of the Bank's prime rate adjusted for a factor based on the most recent quarterly debt to cash flow calculation. The rate at December 31, 2007 was 6.75 percent (December 31, 2006 - 7.25 percent). 9. CAPITAL STOCK (a) Authorized Capital The authorized capital consists of an unlimited number of preferred shares issuable in series and an unlimited number of common shares without nominal or par value. (b) Common shares issued ------------------------------------------------------------------------- Consideration Number ($000's) ------------------------------------------------------------------------- Balance December 31, 2005 57,163,269 72,309 Private placement for cash on conversion of subscription receipts, net of commissions 8,200,000 19,988 Shares issued on arrangement with Berland (note 5) 21,083,795 53,764 Private placement for cash, net of commissions 6,500,000 11,238 Future tax effect of flow-through share renouncements - (9,554) Future tax effect on share issue costs and commissions - 565 Share issue costs, net of tax - (272) ------------------------------------------------------------------------- Balance December 31, 2006 92,947,064 148,038 Shares issued on exercise of stock options 225,000 225 ------------------------------------------------------------------------- Balance December 31, 2007 93,172,064 148,263 ------------------------------------------------------------------------- Private Placements On October 26, 2006, 6,500,000 flow-through common shares were issued in a private placement at $1.82 per share for cash proceeds of $11,830,000 before agent's commission of $591,500. The renouncement of these expenditures was filed with the tax authorities during 2006 and the tax effect of the renunciation of $9,554,000 was recognized. The expenditures to satisfy the flow-through commitment had been made by June 30, 2007. (c) Stock Option Plan A stock option plan is in place under which 7,500,000 common shares have been reserved for options to be granted to directors, officers, employees and consultants with terms established by the Board of Directors. Options granted under the plan generally have a five year term to expiry and vest equally over a three year period commencing on the first anniversary date of the grant. The exercise price of each option equals the closing market price of the Company's common shares on the day prior to the date of the grant. The following table sets forth a reconciliation of the plan activity through December 31, 2007: 2007 2006 Weighted Weighted average average exercise exercise Number of price ($ Number of price ($ Options per share) Options per share) ------------------------------------------------------------------------- Outstanding, beginning of year 4,416,200 1.68 3,513,700 1.56 Granted 2,309,500 0.94 910,000 1.31 Forfeited (262,500) 1.99 (7,500) 2.90 Exercised (225,000) 1.00 - - ------------------------------------------------------------------------- Outstanding, end of year 6,238,200 1.42 4,416,200 1.68 ------------------------------------------------------------------------- Exercisable 3,216,359 1.54 2,449,692 1.34 ------------------------------------------------------------------------- The following table sets forth additional information relating to the stock options outstanding at December 31, 2007: Options Outstanding Exercisable Options ------------------------------------------------------------------------- Weighted Weighted average average exercise Weighted exercise Weighted price average price average Exercise price Number of ($ per years to Number of ($ per years to range Options share) expiry Options share) expiry ------------------------------------------------------------------------- $0.50 to $1.39 4,053,500 1.00 2.94 1,735,333 1.08 1.12 ------------------------------------------------------------------------- $1.40 to $2.29 1,127,200 1.54 2.05 866,867 1.51 1.58 ------------------------------------------------------------------------- $2.30 to $3.19 917,500 2.83 2.99 567,492 2.86 2.96 ------------------------------------------------------------------------- $3.20 to $4.09 140,000 3.24 3.07 46,667 3.24 3.07 ------------------------------------------------------------------------- 6,238,200 1.42 2.79 3,216,359 1.54 1.59 ------------------------------------------------------------------------- The fair value method for measuring option awards based on the Black Scholes valuation model is used. Key assumptions used for the Black Scholes based valuation of options are: Risk free rate - 4.3 percent; average expected life - 4.5 years; no expected dividend yield; 46 percent volatility. Estimated future forfeiture assumptions are not used in calculations as forfeitures are recognized as they occur. The weighted average option price for options outstanding at December 31, 2007 is $0.567 per option. For the year ended December 31 2007, $905,000 (2006 - $716,000) was recorded for options issued and outstanding with a corresponding increase recorded to contributed surplus. (d) Contributed Surplus The following table sets forth the continuity of contributed surplus for the year ended December 31, 2007: ($000's) --------------------------------------------------------------------- Balance, December 31, 2005 574 2006 Stock based compensation expense 716 --------------------------------------------------------------------- December 31, 2006 1,290 2007 Stock based compensation expense 905 --------------------------------------------------------------------- December 31, 2007 2,195 --------------------------------------------------------------------- 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. 10. 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) 2007 2006 ------------------------------------------------------------------------- Loss before income taxes (31,720) (38,466) ------------------------------------------------------------------------- Current statutory income tax rate 32.13% 34.54% ------------------------------------------------------------------------- Anticipated tax recovery (10,193) (13,286) Decrease in recovery resulting from: Effect of future tax rate reductions (957) (5,511) Impairment of goodwill 6,669 8,365 Unrealized risk management gains (152) (219) Non-deductible Crown payments - 1,293 Resource allowance - (1,085) Alberta royalty tax credits - (54) Non-deductible expenses 300 260 Other 14 - ------------------------------------------------------------------------- Future income tax recovery (4,319) (10,237) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Capital tax 12 29 Other 27 82 ------------------------------------------------------------------------- Current income tax expense 39 111 ------------------------------------------------------------------------- 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) 2007 2006 ------------------------------------------------------------------------- Future tax liabilities Net book value of capital assets in excess of tax pools (12,132) (16,819) Future tax assets Share issue costs 432 848 Attributed Canadian royalty income 683 682 Asset retirement obligation 818 771 ------------------------------------------------------------------------- Net future tax liabilities (10,199) (14,518) ------------------------------------------------------------------------- Tax Pools At December 31, 2007 the petroleum and natural gas properties had an approximate tax basis of $125,700,000. 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. 11. SUPPLEMENTAL CASH FLOW INFORMATION Changes in Non-cash Working Capital For the years ended December 31, ($000's) 2007 2006 ------------------------------------------------------------------------- Accounts receivable 9,286 (9,690) Prepaid expenses and deposits (228) (1,329) Accounts payable and accrued liabilities (10,099) 11,291 Taxes payable (16) (63) Non-cash working capital acquired (note 4) - (8,438) ------------------------------------------------------------------------- (1,057) (8,229) Change in non-cash working capital related to investing activities 180 1,016 ------------------------------------------------------------------------- Change in non-cash working capital related to operating activities (1,237) (9,245) ------------------------------------------------------------------------- Cash interest and taxes paid For the year ended December 31, ($000's) 2007 2006 ------------------------------------------------------------------------- Cash income and other taxes paid 28 220 Cash interest paid 4,028 2,627 ------------------------------------------------------------------------- 12. 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 year ended December 31, 2007 were $206,000. 13. FINANCIAL INSTRUMENTS Fair Value of Financial Instruments Financial instruments recognized on the balance sheets consist of cash and cash equivalents, accounts receivable, deposits, investments, accounts payable, accrued liabilities, bank loan and financial derivatives used to manage natural gas price risk. The fair value of these financial instruments approximates their carrying amounts due to their short terms to maturity except for the financial derivatives which values are outlined below. (a) Credit Risk Accounts receivable are with customers, sales agents and joint venture partners in the petroleum and natural gas business and are subject to the usual credit risks. The Company mitigates this risk by entering into transactions with long-standing, reputable counterparties and partners. If significant amounts of capital are to be spent on behalf of a joint venture partner the partner is "cash called" in advance of the capital spending taking place. (b) Interest Rate Risk The Company is exposed to fluctuations in interest rates on its bank debt. The Company entered into an interest rate swap transaction in January 2008 to fix the interest rate on $25.0 million of its variable rate demand bank line. The transaction fixes the interest rate for a two year period at a rate of 5.21 percent including the Company's borrowing margin on its bank line. (c) Foreign Exchange Risk The Company is exposed to the risk of changes in the Canadian/US dollar exchange rates on sales of commodities that are denominated in U.S. dollars or directly influenced by U.S. dollar benchmark prices. (d) Commodity Price Risk Management The following is a summary of natural gas price risk management derivative contracts in effect as of December 31, 2007. All contracts are priced in Canadian dollars per gigajoule (GJ). The price per GJ can be converted to an approximate price per million cubic feet ("MCF") by multiplying the per GJ price by 1.05. GJ volume can be converted to an approximate MCF volume by multiplying the GJ volume by 0.95. Natural Gas Risk Management Contracts ------------------------------------------------------------------------- Daily quantity Fixed price per (GJ/day) Term of Contract gigajoule (Cdn$/GJ) ------------------------------------------------------------------------- 2,000 January 1 to March 31, 2008 $7.25floor; $8.65 cap ------------------------------------------------------------------------- 2,000 January 1 to March 31, 2008 $7.50 floor; $9.45 cap ------------------------------------------------------------------------- 2,000 April 1 to March 31, 2009 $6.72 fixed price ------------------------------------------------------------------------- 2,000 April 1 to December 31, 2008 $6.65 fixed price ------------------------------------------------------------------------- 2,000 January 1 to December 31, 2008 $6.65 fixed price ------------------------------------------------------------------------- Crude Oil Risk Management Contracts ------------------------------------------------------------------------- Daily quantity Fixed price per barrel (Barrels/d) Term of Contract (WTI in Cdn$) ------------------------------------------------------------------------- 100 January 1 to December 31, 2008 $85.00 floor; $93.30 cap ------------------------------------------------------------------------- 100 January 1 to December 31, 2008 $85.00 floor; $98.10 cap ------------------------------------------------------------------------- The fair value of the above natural gas derivative instruments marked-to- market as at December 31, 2007 results in an unrealized gain of $162,000 (December 31, 2006 - $635,000). Total realized gains from risk management activities in 2007 were $2,243,000 (2006 - nil). Subsequent to December 31, 2007 the following natural gas risk management contracts have been put in place. ------------------------------------------------------------------------- Daily quantity Fixed price per (GJ/day) Term of Contract gigajoule (Cdn$/GJ) ------------------------------------------------------------------------- 2,000 April 1 to December 31, 2008 $6.80 fixed price ------------------------------------------------------------------------- 2,000 April 1 to October 31, 2008 $6.80 fixed price ------------------------------------------------------------------------- 2,000 April 1 to October 31, 2008 $7.45 fixed price ------------------------------------------------------------------------- 14. 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. 15. PER SHARE INFORMATION The weighted average number of common shares outstanding for the year ended December 31, 2007 of 93,067,132 was used to calculate basic and diluted income (loss) per share (2006 - 86,178,274). All of the outstanding options have been excluded from the calculation of diluted per share information as they were anti-dilutive. The total number of shares which are potentially dilutive in future periods as of December 31, 2007 was 6,238,200. 16. COMMITMENTS Commitments exist for leased office space and vehicles. The amounts for leased space exclude operating costs, taxes, insurance and utilities: Year ($000's) -------------------------- 2008 305 2009 215 2010 97 Thereafter - -------------------------- Total 617 -------------------------- 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. 17. COMPARATIVE FIGURES Certain figures have been re-classified to conform to the financial statement presentation adopted in 2007. 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.

For further information:

For further information: Dell P. Chapman, V.P. Finance & CFO, Ph: (403)
303-3267; Daniel F. Botterill, President & Chief Executive Officer, Ph: (403)
303-3262

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Berens Energy Ltd.

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