Berens Energy Ltd. Releases Financial Results for the Year and Fourth Quarter Ended December 31, 2006



    Symbol: BEN - TSX

    CALGARY, March 27 /CNW/ -

    
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        FINANCIAL AND OPERATING HIGHLIGHTS

    -------------------------------------------------------------------------
    ($ Cdn thousands,                                     Three months
     except as noted)                                  ended December 31,
    -------------------------------------------------------------------------
                                                 2006       2005    % Change
    -------------------------------------------------------------------------
    Sales volume
      Natural gas (mcf/day)                     18,440     11,537        60%
      Oil and ngls (bbl/day)                       483        176       174%
      boe/day (6 to 1)                           3,556      2,099        69%
    -------------------------------------------------------------------------
    Revenue net of royalties                    11,213      9,537        18%
    Net income (loss)                          (21,951)      (475)
      Per share (basic and diluted)          $   (0.24) $   (0.01)
    Funds from operations(1)                     6,118      6,827       (10%)
      Per share (basic and diluted)(1)       $    0.07  $    0.13       (46%)
    -------------------------------------------------------------------------
    Capital costs
      Exploration and development               11,112      9,198
      Land and seismic                             896      2,955
      Other                                         37        193
    -------------------------------------------------------------------------
      Total                                     12,045      7,165        79%
    -------------------------------------------------------------------------
    Net wells completed (No.)
    -------------------------------------------------------------------------
      Natural gas                                    7          9
    -------------------------------------------------------------------------
      Oil                                            -          1
    -------------------------------------------------------------------------
      Dry                                            1          2
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      Total                                          8         12
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    Net working capital (deficit)
     - including bank debt                     (55,073)     4,273
    -------------------------------------------------------------------------
    Shares outstanding
      End of period (000's)                     92,947     57,163        63%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    ($ Cdn thousands,                                    Twelve months
     except as noted)                                  ended December 31,
    -------------------------------------------------------------------------
                                                  2006       2005   % Change
    -------------------------------------------------------------------------
    Sales volume
      Natural gas (mcf/day)                     17,420     10,451        67%
      Oil and ngls (bbl/day)                       469        193       143%
      boe/day (6 to 1)                           3,373      1,935        74%
    -------------------------------------------------------------------------
    Revenue net of royalties                    40,118     27,868        44%
    Net income (loss)                          (28,340)       504
      Per share (basic and diluted)          $   (0.33) $    0.01
    Funds from operations(1)                    22,471     18,285        23%
      Per share (basic and diluted)(1)       $    0.26  $    0.38       (32%)
    -------------------------------------------------------------------------
    Capital costs
      Exploration and development               51,820     22,613
      Land and seismic                           3,583      9,522
      Other                                        295        260
    -------------------------------------------------------------------------
      Total                                     55,698     32,395        57%
    -------------------------------------------------------------------------
    Net wells completed (No.)
    -------------------------------------------------------------------------
      Natural gas                                   25         24
    -------------------------------------------------------------------------
      Oil                                            -          1
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      Dry                                            4          7
    -------------------------------------------------------------------------
      Total                                         29         32
    -------------------------------------------------------------------------
    Net working capital (deficit)
     - including bank debt                     (55,073)     4,272
    -------------------------------------------------------------------------
    Shares outstanding
      End of period (000's)                     92,947     57,163        63%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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


    Fourth Quarter 2006 Operating Highlights

     -  Production - Q4 2006 production averaged 3,556 boe/d, up 69 percent
        over Q4 2005. Production additions in the fourth quarter of 2006 were
        delivered by ongoing drilling and tie-ins in Pembina and a November
        drilling program in Lanfine that was partially tied in by the end of
        the year. On a full year basis volume in 2006 averaged 3,373 boe/d,
        up 74 percent compared to the year ended December 31, 2005.

     -  Reserves - Total working interest proved plus probable reserves as at
        December 31, 2006 were 7,765,000 boe comprised of 1,487,000 barrels
        of oil and natural gas liquids and 37,673 million cubic feet of
        natural gas. Total proved plus probable reserves grew 224 percent
        from December 31, 2005 to December 31, 2006. On a per share basis
        proved plus probable reserves grew 99 percent from 41.9 boe/1000
        shares outstanding to 83.5 boe/1000 shares outstanding. Proved plus
        probable reserves growth came equally from the exploration and
        development program which added 3.3 million boe and the acquisition
        of Berland Exploration Ltd. in January 2006 which added 3.3 million
        boe. Berens replaced production more than 2.6 times with new proved
        plus probable reserves added from the exploration and development
        drilling program. Combined with the acquisition, production has been
        replaced over 5.2 times with new proved plus probable reserves.

     -  Product Mix - The addition of liquids rich natural gas from the
        Berland acquisition has changed the production mix from 92% natural
        gas and 8% heavy oil in Q3 2005 to a higher value mix of 86% natural
        gas, 13% natural gas liquids and only 1% heavy oil. The natural gas
        produced in Pembina and the Deep Basin which combined represent 41%
        of 2006 production has high BTU content and commands a premium price.

     -  Production Costs - Costs averaged $8.88 per boe in Q4 2006, up 8%
        compared to $8.22 per boe in Q4 2005. Q4 2006 costs were burdened by
        prior quarters' catch up charges from non-operated properties that
        were billed during the quarter. For the 2006 year production costs
        have averaged $7.89 per boe, up 2 percent compared to $7.74 in 2005.

     -  Funds from Operations - Funds from operations Q4 2006 was
        $6.2 million ($0.07 per share) compared to Q4 2005 funds from
        operations of $6.8 million ($0.13 per share). Higher production in Q4
        2006 was offset primarily by weaker natural gas prices. On a per
        share basis, funds from operations declined due to additional shares
        issued mainly for the acquisition of Berland.

     -  Drilling - A total of 13 wells (8.3 net) were completed in the fourth
        quarter resulting in 12 (7.7 net) natural gas wells and one (0.6 net)
        unsuccessful well for a net success rate of 93 percent. In 2006, 50
        (29.3 net) wells have been completed with 39 (24.9 net) natural gas
        wells, 1 (0.3 net) oil well and 10 (4.1 net) unsuccessful wells for a
        net success rate of 86 percent.

     -  Land - Berens total undeveloped land (owned and option) currently
        stands at 145,000 net acres. Ninety-eight percent of the undeveloped
        lands are located in the four core areas of Pembina, Deep Basin,
        Lanfine and Marten Hills. The 2007 drilling program is based entirely
        on existing Berens' controlled undeveloped acreage.
    

    Message to the shareholders
    As all are aware, 2006 was a very interesting year in the energy
industry, particularly the natural gas business. Berens entered 2006 full of
optimism due to an announced major acquisition and substantial land expansion
upon which we planned to apply the drill bit to deliver long term growth for
our shareholders. Natural gas prices were at all time highs and aggressive
plans appeared easily managed.

    The year that was...
    In the course of the year, our excitement was tempered by natural gas
prices that dropped significantly, high service costs that became higher, and
underperformance on some of the wells from our Berland acquisition. Needless
to say, a tough environment.

    
    So what did we do at Berens?
    -   We set about learning our way around the assets that we had acquired.
    -   We cut our capital to make sure we were prudent in our business.
    -   And we did our business very carefully.
    

    Our efforts paid off
    While our early 2006 drilling results were expensive and with limited
success, as earlier reported, we persevered and by the 4th quarter we were
successful on 12 of 13 drilling attempts. As a result, we now have a much
better understanding of the technical and operating skills we need to succeed
with the assets we have.

    On track to deliver in 2007
    We are glad that 2006 is now behind us and that the optimism of early
2006 has been rejuvenated. We have our land position and drilling plans intact
and are on track to deliver with the drill bit.
    We have a great team of people working promising prospects in our four
core areas of Pembina, Lanfine, Deep Basin and Marten Hills. So far in 2007 we
are five for five in Pembina and four for four in the Deep Basin. A fifth Deep
Basin well was unsuccessful, but it was farmed out at no cost to Berens. In
the Marten Hills shallow gas program we drilled four successful wells on seven
attempts. Our people remain committed to succeed, and believe we have "turned
the corner" and are on track for long term growth.

    Industry trends
    Reports of noticeably reduced activity across the western Canadian
sedimentary basin give us reason to believe that costs will decrease. We have
already seen limited evidence of reduced activity early in 2007 and we are
noticing that services are more readily available.
    The oil and gas business has the broad ability to self-correct when
business factors get "out of whack" as they did in early 2006. Natural gas
prices so far in 2007 have met our expectations and they appear to be more
stable than we have seen in the past 12 months.
    Volatility remains a reality in our business, but we are poised to
respond immediately to any price weakness as we operate most of our own
capital program and can adjust our spending as needed without pressure from
partners.
    We believe that "supply and demand" will ultimately balance in 2007. As
the gas supply declines, due to the anticipated reduced drilling activity in
2007, and as demand remains stable, natural gas prices will have a tendency to
react upward. These slightly higher prices along with lower service costs will
foster new activity.
    Berens is active in some of the best oil and gas areas in western Canada.
We have skillful and dedicated staff that are committed to our success. I
would like to thank our staff and management for their efforts and our board
of directors for their guidance and patience through a tough year.
    Most of all, I would like to thank our shareholders who have stood with
us through the difficulties of 2006 and who share our optimism going forward.
I am a shareholder too, as are all of our staff. We are all collectively
committed to succeed.

    Sincerely,

    "Signed"

    Robert D. Steele
    Chief Executive Officer


    Reserves
    Berens' oil and gas reserves were independently evaluated by GLJ
Petroleum Consultants ("GLJ"). The evaluation was completed using the reserve
definitions in the Canadian Oil and Gas Evaluation Handbook and the Canadian
Securities Administrators National Instrument 51-101 ("NI 51-101"). The
effective date of the following reserves is December 31, 2006.
    The following tables summarize the oil and gas reserves and their net
present value based on various discount rates as at December 31, 2006. When
information is presented on a barrel of oil equivalent ("boe") basis, natural
gas is converted to oil in the ratio of six thousand cubic feet of natural gas
to one barrel of oil (6 Mcf:1 bbl).

    
                       SUMMARY OF OIL AND GAS RESERVES
                 AND NET PRESENT VALUES OF FUTURE NET REVENUE
                           as of December 31, 2006

                          FORECAST PRICES AND COSTS

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                                         RESERVES
    -------------------------------------------------------------------------
                             LIGHT AND
                            MEDIUM OIL        HEAVY OIL        NATURAL GAS
    -------------------------------------------------------------------------
                        Gross(1)   Net(2) Gross(1)   Net(2) Gross(1)   Net(2)
    RESERVES CATEGORY     (Mbbl)   (Mbbl)   (Mboe)   (Mboe)   (MMcf)   (MMcf)
    -------------------------------------------------------------------------

    PROVED
      Developed
       Producing            168      159       73       67   18,770   14,555
      Developed
       Non-Producing         21       18        9        8    4,266    3,430
      Undeveloped             0        0        0        0    3,381    2,728
    -------------------------------------------------------------------------
    TOTAL PROVED            189      177       82       75   26,417   20,713
    -------------------------------------------------------------------------
    PROBABLE                183      169       36       33   11,256    8,931
    -------------------------------------------------------------------------
    TOTAL PROVED
     PLUS PROBABLE          372      346      118      108   37,673   29,644
    -------------------------------------------------------------------------

    -------------------------------------------------------
                                      RESERVES
    -------------------------------------------------------
                             NATURAL       Oil Equivalent
                           GAS LIQUIDS         (Mboe)
    -------------------------------------------------------
                        Gross(1)   Net(2) Gross(1)   Net(2)
    RESERVES CATEGORY     (Mbbl)   (Mbbl)   (Mboe)   (Mboe)
    -------------------------------------------------------

    PROVED
      Developed
       Producing            502      318    3,870    2,968
      Developed
       Non-Producing        118       79      859      678
      Undeveloped           100       68      664      523
    -------------------------------------------------------
    TOTAL PROVED            720      465    5,393    4,169
    -------------------------------------------------------
    PROBABLE                277      181    2,372    1,871
    -------------------------------------------------------
    TOTAL PROVED
     PLUS PROBABLE          997      646    7,765    6,040
    -------------------------------------------------------

    (1) "Gross Reserves" include total company interest reserves before the
        deduction of royalties.

    (2) "Net Reserves" include total company interest reserves after royalty
        deductions plus royalty interest reserves.


                   NET PRESENT VALUES OF FUTURE NET REVENUE

    -------------------------------------------------------------------------
                                     BEFORE INCOME TAXES
                                    DISCOUNTED AT (%/year)
    -------------------------------------------------------------------------
    RESERVES            0       5       8      10      12      15      20
     CATEGORY         (MM$)   (MM$)   (MM$)   (MM$)   (MM$)   (MM$)   (MM$)

    PROVED
      Developed
       Producing     103,452  82,080  73,824  69,432  65,691  60,999  54,910
      Developed
       Non-Producing  23,327  16,912  14,977  14,013  13,210  12,215  10,918
      Undeveloped     10,179   6,270   4,626   3,731   2,961   1,996     762
    -------------------------------------------------------------------------
    TOTAL PROVED     136,958 105,263  93,427  87,176  81,862  75,210  66,590
    -------------------------------------------------------------------------
    PROBABLE          74,819  43,979  35,174  31,073  27,864  24,173  19,881
    -------------------------------------------------------------------------
    TOTAL PROVED
     PLUS PROBABLE   211,777 149,242 128,601 118,249 109,726  99,383  86,471
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
                                    AFTER INCOME TAXES
                                  DISCOUNTED AT (%/year)
    -------------------------------------------------------------------------
    RESERVES            0       5       8      10      12      15      20
     CATEGORY         (MM$)   (MM$)   (MM$)   (MM$)   (MM$)   (MM$)   (MM$)

    PROVED           131,087 102,525  91,565  85,705  80,684  74,347  66,053
    -------------------------------------------------------------------------
    PROBABLE          52,920  31,758  25,747  22,949  20,758  18,234  15,282
    -------------------------------------------------------------------------
    TOTAL PROVED
     PLUS PROBABLE   184,007 134,283 117,312 108,654 101,442  92,581  81,335
    -------------------------------------------------------------------------


    The forecasted prices used by GLJ to create the net present values of
    future net revenue are as follows:

                                                      Oil
                                 --------------------------------------------

                                             Edmonton                Cromer
                                     WTI    Par Price                Medium
                                  Cushing  40 degrees  Hardisty  29.3 degrees
                                  Oklahoma     API        Heavy       API
    Year                          ($US/bbl) ($Cdn/bbl) ($Cdn/bbl)  ($Cdn/bbl)
                                  --------- ---------- ---------- -----------
    Historical Averages
    2002                             26.08      40.33      26.57       35.48
    2002                             31.07      43.66      26.26       37.55
    2004                             41.38      52.96      29.11       45.75
    2005                             56.58      69.11      34.07       56.62
    2006 (e)                         66.22      73.16      41.87       62.24

    Forecast
    2007                             62.00      70.25      39.25       61.25
    2008                             60.00      68.00      40.00       59.25
    2009                             58.00      65.75      39.75       57.25
    2010                             57.00      64.50      39.75       56.00
    2011                             57.00      64.50      40.25       56.00
    2012                             57.50      65.00      41.50       56.50
    2013                             58.50      66.25      42.50       57.75
    2014                             59.75      67.75      43.50       59.00
    2015                             61.00      69.00      44.25       60.00
    2016                             62.25      70.50      45.25       61.25
    2017                             63.50      71.75      46.00       62.50
    2018+                         +2.0%/yr   +2.0%/yr   +2.0%/yr    +2.0%/yr


                                   Natural
                                     gas       NGLs
                                  ---------  ---------
                                             FOB Field
                                                Gate
                                   AECO-C    (propane/  Inflation   Exchange
                                  Gas Price   butane)    rate(1)%    rate(2)
     Year                       ($Cdn/MMbtu) ($Cdn/bbl)  per year  ($US/Cdn)
                                ------------ ---------- ---------- ----------
     Historical Averages
     2002                             4.04      24.24        2.2       0.637
     2002                             6.66      33.25        2.8       0.721
     2004                             6.88      37.34        1.8       0.768
     2005                             8.58      47.42        2.2       0.825
     2006 (e)                         7.02      55.30        2.0       0.882

     Forecast
     2007                             7.20      50.62        2.0        0.87
     2008                             7.45      46.88        2.0        0.87
     2009                             7.75      45.38        2.0        0.87
     2010                             7.80      44.50        2.0        0.87
     2011                             7.85      44.50        2.0        0.87
     2012                             8.15      44.75        2.0        0.87
     2013                             8.30      45.75        2.0        0.87
     2014                             8.50      46.75        2.0        0.87
     2015                             8.70      47.63        2.0        0.87
     2016                             8.90      48.63        2.0        0.87
     2017                             9.10      49.50        2.0        0.87
     2018+                        +2.0%/yr   +2.0%/yr        2.0        0.87


    Notes:
    (1) Inflation rates for forecasting prices and costs.
    (2) Exchange rates used by GLJ to generate the benchmark reference prices
        in this table.
    

    Reserves Reconciliation
    Berens' reserve additions in 2006 came equally from its exploration and
development program (3.3 million proved plus probable boe) and its acquisition
of Berland Exploration Ltd. (3.3 million proved plus probable boe). Reserve
revisions for 2006 were negligible as were dispositions. With the addition of
significant reserves in Pembina and the Deep Basin during 2006, our reserve
life index improved to 6.0, almost double the reserve life index of 3.2 years
at the end of 2005.
    Capital spending of $53.3 million was directed at seismic and exploration
and development while another $2.5 million was spent on land during 2006. The
reserves continuity reflecting the additions from capital spending, revisions
to opening estimates and production is outlined in the following table:

    
                              RECONCILIATION OF
                          COMPANY INTEREST RESERVES
                         BY BARREL OF OIL EQUIVALENT

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

    December 31, 2005                 1,664                 2,396

    Discoveries                         390                   499
    Extensions                         1817                 2,752
    Infill drilling                       -                     -
    Improved recovery                    15                    20
    Technical revisions                 176                    (3)
    Acquisitions                      2,584                 3,364
    Dispositions                        (23)                  (33)
    Production(1)                    (1,230)               (1,230)

    December 31, 2006                 5,393                 7,765
    -------------------------------------------------------------------------

    Finding and Development Costs
    Finding and development costs for Berens seismic, exploration and
development activities for each of the past three years and on a three year
cumulative basis are outlined below:

    -------------------------------------------------------------------------
                                                                      Three
                                                                       Year
                                       2006       2005       2004     Totals
    -------------------------------------------------------------------------
    Total capital for seismic,
     exploration and development
     (excluding land capital)
     ($000's)                        53,340     25,207     16,230     94,777
    -------------------------------------------------------------------------
    Future development capital
     - proved ($000's)               12,600      1,240        260     12,340
    -------------------------------------------------------------------------
    Future development capital
     - proved plus probable
     ($000's)                        15,400      1,380        346     15,054
    -------------------------------------------------------------------------
    Reserve extensions and
     discoveries - proved (Mboe)      2,222        946      1,091      4,259
    -------------------------------------------------------------------------
    Reserve extensions and
     discoveries - proved plus
     probable (Mboe)                  3,271      1,273      1,493      6,037
    -------------------------------------------------------------------------
    Finding and development
     costs - proved (per boe)     $   29.12  $   27.96  $   15.11  $   25.15
    -------------------------------------------------------------------------
    Finding and development
     costs - proved plus
     probable (per boe)           $   20.59  $   20.88  $   11.10  $   18.19
    -------------------------------------------------------------------------
    

    Berens' three year average finding and development costs on a proved plus
probable basis for exploration and development activities were $18.19 per boe
with 2006 averaging $20.59. Finding and development costs in 2006 improved
throughout the year after a poor first quarter. Berens internal estimate of
fourth quarter 2006 finding and development costs were $13.50 per boe. The
first quarter was characterized by high service industry costs, limited access
to services and poor drilling results in Karr. Early 2007 drilling success in
the Deep Basin and Pembina points to continued strong finding and development
cost efficiency, building on our momentum established in the second half of
2006.
    The Berland Exploration acquisition in January 2006 for $102.7 million
was supplemented in December 2006 by a small acquisition in Pembina for
$1.4 million. Berens also sold small, non-core asset in December 2006 for
$0.7 million. Finding and development costs for 2006 acquisition activity are
outlined below. Acquisition costs were higher than those achieved with the
exploration and development program but a critical contribution from the
acquisitions was the establishment of significant undeveloped land positions
in Pembina and the Deep Basin where we are now experiencing strong drilling
success.

    
    -------------------------------------------------------------------------
                                                                        2006
    -------------------------------------------------------------------------
    Total net acquisition capital ($000's)                           103,450
    -------------------------------------------------------------------------
    Net proved reserves from acquisitions less
     divestitures (Mboe)                                               2,561
    -------------------------------------------------------------------------
    Net proved plus probable reserves from acquisitions less
     divestitures (Mboe)                                               3,331
    -------------------------------------------------------------------------
    Finding and development costs - proved (per boe)              $    40.39
    -------------------------------------------------------------------------
    Finding and development costs - proved plus probable
     (per boe)                                                    $    31.06
    -------------------------------------------------------------------------


    The following table outlines finding and development costs combining the
exploration and development activity with the acquisition activity for 2006.

    -------------------------------------------------------------------------
                                                                        2006
    -------------------------------------------------------------------------
    Total capital (excluding land capital) ($000's)                  156,790
    -------------------------------------------------------------------------
    Change in future development capital - proved ($000's)            11,360
    -------------------------------------------------------------------------
    Change in future development capital - proved plus
     probable ($000's)                                                14,020
    -------------------------------------------------------------------------
    Reserves added - proved (Mboe)                                     4,783
    -------------------------------------------------------------------------
    Reserve added - proved plus probable (Mboe)                        6,602
    -------------------------------------------------------------------------
    Finding and development costs - proved (per boe)              $    35.15
    -------------------------------------------------------------------------
    Finding and development costs - proved plus
     probable (per boe)                                           $    28.87
    -------------------------------------------------------------------------
    


    Berens Energy Ltd.
    Annual and Fourth Quarter 2006
    Management's Discussion and Analysis ("MD&A")
    March 26, 2007

    OVERVIEW

    Berens Energy Ltd. ("Berens" or the "Company") is a full cycle oil and
natural gas exploration and production company with a concentrated production
and land base in Eastern Alberta, Pembina and Deep Basin regions of west
central Alberta.
    All calculations converting natural gas to crude oil equivalent have been
made using a ratio of six thousand cubic feet (six "mcf") of natural gas to
one barrel of crude equivalent. Barrels of oil equivalent ("boe") may be
misleading, particularly if used in isolation. A boe conversion ratio of six
mcf of natural gas to one barrel of crude oil equivalent is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.
    The following discussion of financial position and results of operations
should be read in conjunction with the Company's December 31, 2006 audited
financial statements and notes thereto. This MD&A was prepared using
information that is current as of March 26, 2007 unless otherwise noted.

    FORWARD LOOKING INFORMATION

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

    Additional information on the Company can be found on the SEDAR website
at www.sedar.com.

    
    QUARTERLY INFORMATION
                                                       2006
                                   ------------------------------------------
    ($000's except as noted)             Q4         Q3         Q2         Q1
    -------------------------------------------------------------------------
    Sales volumes:
      Natural gas (mcf/day)          18,440     17,355     17,224     16,631
      Oil and natural gas
       liquids (bbl/day)                483        479        494        420
      Barrels of oil equivalent       3,556      3,372      3,364      3,192
    -------------------------------------------------------------------------
    Financial:
      Net revenue                    11,213      9,536      9,846      9,523
      Net (loss)                    (21,951)    (2,662)    (1,606)    (2,121)
        per share - basic
         ($/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                    (55,073)   (60,182)   (55,766)   (45,907)
    -------------------------------------------------------------------------
    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
    -------------------------------------------------------------------------

                                                       2005
                                   ------------------------------------------
    ($000's except as noted)             Q4         Q3         Q2         Q1
    -------------------------------------------------------------------------
    Sales volumes:
      Natural gas (mcf/day)          11,537     10,832     10,250      9,155
      Oil and natural gas
       liquids (bbl/day)                176        165        200        233
      Barrels of oil equivalent       2,099      1,970      1,908      1,759
    -------------------------------------------------------------------------
    Financial:
      Net revenue                     9,537      7,667      5,754      4,910
      Net income (loss)                (475)       534        887       (441)
        per share - basic
         ($/share)                 $  (0.01)  $   0.01   $   0.02   $  (0.01)
        per share - diluted
         ($/share)                 $  (0.01)  $   0.01   $   0.02   $  (0.01)
      Capital costs                  12,346      7,165      3,423      9,462
      Shares outstanding (000's)     57,163     52,961     46,427     46,427
      Bank debt                           -          -     10,080     10,480
      Working capital (deficit)
       including bank debt            4,273     (2,137)   (13,121)   (13,216)
    -------------------------------------------------------------------------
    Per unit information:
      Natural gas price ($/mcf)    $  11.26   $   9.16   $   7.29   $   6.91
      Oil and liquids price
       ($/barrel)                  $  41.92   $  57.47   $  33.11   $  30.81
      Oil equivalent price ($/boe) $  65.47   $  55.05   $  42.61   $  40.05
      Operating netback ($/boe)    $  39.78   $  34.07   $  24.81   $  21.12
    -------------------------------------------------------------------------
    Net wells completed: (No.)
      Natural gas                         9          7          3          5
      Oil                                 1          0          0          0
      Dry                                 2          2          1          2
    -------------------------------------------------------------------------
      Total                              12          9          4          7
    -------------------------------------------------------------------------
    

    Significant production and revenue increases were experienced in the
first quarter of 2006 compared to earlier quarters due to the acquisition of
Berland Exploration Ltd. in January of 2006. Ongoing drilling has delivered
the production increase to date for 2006. There have been no further material
acquisitions.

    RESULTS OF OPERATIONS

    Production Volume
    Production volume averaged 3,556 boe/d for the fourth quarter of 2006, up
69 percent compared to 2,099 boe/d in the fourth quarter of 2005 and up five
percent compared to the third quarter of 2006. Natural gas represented
86 percent of production in the fourth quarter of 2006 with the remaining
production being 13 percent light oil and natural gas liquids and one percent
conventional heavy oil. Ongoing drilling in Pembina and a November drilling
program in Lanfine delivered the fourth quarter volume growth.
    Production volume averaged 3,373 boe/d for the year ended December 31,
2006, up 74 percent compared to 1,935 boe/d in the year ended December 31,
2005. The increase is attributable to ongoing drilling activity as well as the
Berland purchase that closed on January 18, 2006. On a per share basis
production was almost unchanged from 2005 to 2006, however the reserve and
opportunity base was improved significantly. On a reserve basis, proved plus
probable reserves increased 99 percent on a per share basis comparing
December 31, 2006 to December 31, 2005. Management believes the increased
reserve base and the extensive land position will lead to future per share
growth in production.

    Production Revenue
    Natural gas prices averaged $7.13 per mcf for the fourth quarter of 2006,
down 37 percent compared to $11.26 per mcf in the fourth quarter of 2005. Oil
and liquids prices averaged $46.25 and $54.26 per barrel respectively in the
fourth quarter of 2006 for a blended price of $51.54 per barrel, up 23 percent
from the fourth quarter 2005 blended oil and liquids price of $41.92 per
barrel. Higher priced light oil and natural gas liquids represent a larger
portion of production in 2006 compared to 2005. On a boe basis, prices
averaged $43.96 in the fourth quarter of 2006, down 33 percent compared to
$65.47 per boe in the fourth quarter of 2005 as the large decline in natural
gas prices was partially offset by increased prices for oil and liquids and
the higher oil and liquids content in 2006.
    Revenue, excluding unrealized gains or losses on derivative instruments,
was up 18 percent in the fourth quarter of 2006 compared to the fourth quarter
of 2005 as the Volume increase of 69 percent was partially offset by a
33 percent decrease in per boe prices.
    Natural gas prices averaged $6.75 per mcf for the year ended December 31,
2006, down 23 percent compared to $8.80 per mcf in the year ended December 31,
2005. Blended oil and liquids prices averaged $57.48 per barrel in the year
ended December 31, 2006, up 47 percent from the year ended December 31, 2005
blended price of $39.13 per barrel. On a boe basis, prices averaged $42.86 in
the year ended December 31, 2006, down 17 percent compared to the year ended
December 31, 2005 boe price of $51.43. Revenue was up 44 percent in the year
ended December 31, 2006 compared to the year ended December 31, 2005. Volume
increased by 74 percent offset by the 17 percent decrease in per boe prices.

    Royalties
    Royalties, net of Alberta Royalty Tax Credit ("ARTC"), averaged
22 percent of revenue for the fourth quarter of 2006 compared to 25 percent in
the fourth quarter of 2005. Lower royalties in the fourth quarter of 2006
compared to the fourth quarter of 2005 are mainly due to lower natural gas
prices. For the year ended December 31, 2006 royalties, net of ARTC averaged
24 percent of revenue compared to 23 percent of revenue in the year ended
December 31, 2005. The effect of lower natural gas prices in 2006 on royalty
rates was offset by the following factors.
    
        -  Significant 2006 production comes from higher volume, liquids rich
           wells in Pembina and the Deep Basin that have higher royalty rates
           compared to 2005 production which was primarily from lower volume
           wells in Lanfine.
        -  Production from certain farm-in lands in Pembina incurs overriding
           royalties in addition to crown royalties contributing to the
           higher royalty percentage.
    
    On an ongoing basis, royalties are expected to average approximately
24 percent of revenues without the go-forward benefit of ARTC which has been
rescinded effective January 1, 2007. Royalty expense of $3.2 million was
recorded in the fourth quarter of 2006, up two percent compared to the fourth
quarter of 2005 reflecting higher revenue in the 2006 period offset partially
by a lower royalty rate. For the year ended December 31, 2006 royalty expense
of $12.7 million was up 49 percent compared to the year ended December 31,
2005 due to higher revenues and a slightly higher royalty rate.

    Production Expenses
    Production expenses were $8.88 per boe in the fourth quarter of 2006, up
eight percent compared to $8.22 per boe in the fourth quarter of 2005. The
fourth quarter of 2006 was burdened by prior quarter catch up charges from a
partner for processing fees on non-operated properties. For the year ended
December 31, 2006 production expenses were $7.89 per boe, up two percent from
$7.74 per boe in the year ended December 31, 2005. A focus on cost management
has contained costs in an environment where industry costs have escalated
significantly. Processing costs for the liquids rich Pembina and Deep Basin
natural gas in 2006 added to per unit costs compared to 2005 when most of the
Company's natural gas production was dry gas in eastern Alberta. The Company
acquired an interest in a major Pembina processing plant in December 2006
which will reduce processing cost for natural gas produced in the eastern part
of the Pembina core area. With ongoing volume increases and cost management,
management expects future per unit operating expenses to trend below the $8.00
per boe level.
    Fourth quarter 2006 production expenses were $2.9 million, up 83 percent
compared to the fourth quarter of 2005 due to a 69 percent increase in volume
and slightly higher per unit costs. For the year ended December 31, 2006
production expenses were $9.7 million, up 78 percent compared to the year
ended December 31, 2005 due to a 74 percent production increase and higher per
boe costs in 2006.
    Transportation costs of $0.3 million increased 13 percent in the fourth
quarter of 2006 compared to the fourth quarter of 2005 due to increased
volumes offset by lower per unit costs. For the year ended December 31, 2006
transportation costs were $1.1 million an increase of 30 percent compared to
the year ended December 31, 2005.

    General and Administrative Expenses
    General and administrative costs, including stock-based compensation,
were up five percent in the fourth quarter of 2006 compared to the fourth
quarter of 2005. Costs in the fourth quarter of 2006 benefited by general and
administrative cost recoveries from partners on capital projects operated by
Berens. In 2005, almost all of the Company's capital activity was directed to
100 percent owned lands resulting in little administrative cost recovery. On a
per unit basis, general and administrative costs were $2.99 per boe for the
fourth quarter of 2006, down 37 percent compared to $4.78 per boe in the
fourth quarter of 2005.
    For the year ended December 31, 2006 general and administrative costs
were up 51 percent compared to the year ended December 31, 2005. The Company's
2006 staff contingent increased with the acquisition of Berland and further
additions to core properties. Salary and bonus levels have also increased due
to competitive industry pressures. In addition, costs of $160,000 were
incurred in the first half of 2006 to integrate the Berland operations. On a
per boe basis, general and administrative costs were $3.90 per boe for the
year ended December 31, 2006, down 13 percent compared to $4.51 per boe in the
year ended December 31, 2005. There were no general and administrative costs
capitalized in the fourth quarter or for the year ended December 31, 2006 and
2005.
    Staff levels are expected to remain fairly constant in 2007. Per unit
general and administrative costs are expected to decline as production levels
increase.

    Interest Expense
    Interest expense was $1.0 million in the fourth quarter of 2006 compared
to $6,000 in the fourth quarter of 2005. Berens raised equity in the fourth
quarter of 2005 in anticipation of the acquisition of Berland. The subsequent
closing of the Berland acquisition in January 2006 resulted in significant
borrowing on the bank operating line as 30 percent of the Berland acquisition
cost was in the form of cash and Berens assumed Berland's debt and working
capital deficiency, totaling $28 million. Capital expenditures in 2006 were
higher than funds from operations. Equity was raised in October 2006,
mitigating the increase in the bank operating line. For the year ended
December 31, 2006 interest expense was $2.6 million compared to $0.3 million
in the year ended December 31, 2005.

    Operating Netback(1)
    Operating netback represents the margin realized by the production and
sale of petroleum and natural gas. The primary cause of the lower 2006
netbacks is lower natural gas prices.

    
    -------------------------------------------------------------------------
                                        Three months          Twelve months
    Quarterly Operating Netbacks           ended                  ended
    ($'s per boe)                        December 31           December 31
    -------------------------------------------------------------------------
                                       2006       2005       2006       2005
    -------------------------------------------------------------------------
    Sales price                       43.96      65.47      42.86      51.43
    Less:
      Royalties (net of ARTC)          9.92      16.09      10.67      12.07
      Production expenses              8.88       8.22       7.89       7.74
      Transportation charges           0.92       1.38       0.91       1.22
    -------------------------------------------------------------------------
    Operating netback                 24.24      39.78      23.39      30.40
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) non-GAAP measure - refer to discussion on non-GAAP measures below.
    

    Depletion, Amortization and Accretion
    Depletion, amortization and accretion totaled $9.6 million ($29.24 per
boe) in the fourth quarter of 2006 compared to $7.2 million ($37.15 per boe)
in the fourth quarter of 2005. For the year ended December 31, 2006 depletion,
amortization and accretion totaled $36.7 million ($29.85 per boe) compared to
$18.5 million ($26.25 per boe) for the year ended December 31, 2005. The
depletion rate per boe has trended down throughout 2006 from higher rates
early in the year which were due to the cost of acquiring the Berland reserves
as part of the Berland acquisition and to spending in the deeper Karr drilling
program which had limited reserve additions in the first quarter of 2006. As
drilling results have improved in the latter part of 2006, particularly in the
Pembina area, new reserves have been added at significantly lower per unit
costs compared to the first half of 2006.

    Income Taxes
    Current taxes of $72,000 were recorded in the fourth quarter of 2006
primarily for provincial capital taxes and taxes related predecessor company
final tax returns. The Company does not expect to pay current income tax
during 2007 as there are ample capital cost pools and expected future capital
spending to shelter taxable income.
    Future taxes changed from a small asset position at December 31, 2005 to
a liability of $14.5 million at December 31, 2006. Future tax liabilities of
$16.1 million were recorded on the acquisition of Berland and $9.6 million was
recorded to account for the tax effect of flow-through shares renouncements.
These increases were offset by $4.7 million on losses recorded and a
$5.5 million future tax reduction to reflect future corporate tax rate
reductions which are substantially enacted.

    Goodwill Impairment
    Goodwill, at the time of acquisition, represents the excess of purchase
cost of a business over the fair value of net assets acquired. Thereafter,
goodwill is not amortized and is assessed for impairment at least annually. If
the estimated fair value of the business is less than the book value, a second
test is performed to determine the amount of the impairment. Goodwill was
originally recorded primarily on the Resolution Resources Ltd. acquisition
(2003) and the Berland Exploration Ltd. acquisition (2006).
    Since the closing of these acquisitions oil and gas company valuations
have eroded significantly, especially those of natural gas weighted producers
primarily due to the decline in natural gas prices combined with high service
costs in the industry. The Company tested the goodwill balance as at
December 31, 2006 taking into account the decline in corporate economic value
caused by the 2006 decline in the share price. Recent oil and gas asset sales
and corporate sale transactions were also benchmarked for the goodwill test.
Based on the Company's assessment, it was determined that the fair value of
the assets was less than the book value including the amount of goodwill that
was being carried on the balance sheet. As a result, the Company recorded an
impairment of goodwill in the amount of $24.2 million representing 54 percent
of the goodwill balance.

    NET INCOME (LOSS)

    The net loss for the fourth quarter of 2006 was $21.9 million ($0.24 per
share) compared to a loss of $0.4 million ($0.01 per share) in the fourth
quarter of 2005. The higher 2006 loss has resulted primarily from the goodwill
impairment, higher depletion expense and low natural gas prices more than
offsetting the benefit from increases in production volume. For the year ended
December 31, 2006 the net loss was $28.3 million ($0.33 per share) compared to
net income of $0.5 million ($0.01 per share) for the year ended December 31,
2005.

    CAPITAL COSTS

    Capital costs, excluding net acquisitions were $12.1 million in the
fourth quarter of 2006, down from $12.3 million in the third quarter of 2005.
A small acquisition was completed in the fourth quarter of 2006 for
$1.4 million which added 25 boe/d (100,000 boe of proved plus probable
reserves) and a 7.5 percent interest in a processing facility in Pembina that
processes significant Berens natural gas volume in the eastern half of
Pembina. Miscellaneous, small properties were sold in the fourth quarter
totaling 55 boe/d (35,000 boe of proved plus probable reserves) for $704,000.
    The fourth quarter 2006 capital program was focused on drilling in
Lanfine and Pembina. A total of eight net wells were completed in the fourth
quarter of 2006 compared to 12 net wells in the fourth quarter of 2005.
Average well costs are higher in 2006 as deeper Pembina wells are in the 2006
drilling program whereas in 2005 the shallower Lanfine drilling program was
the majority of the drilling. Capital costs are up as well due to increased
industry costs for most activities. A seismic data base was sold to a seismic
broker in the third quarter of 2006 for proceeds of $1.8 million.

    
    -------------------------------------------------------------------------
                                        Three months          Twelve months
                                           ended                  ended
    ($000's)                             December 31,          December 31,
    -------------------------------------------------------------------------
                                       2006       2005       2006       2005
    -------------------------------------------------------------------------
    Drilling and completion          11,112      9,198     51,820     22,613
    Land                                512      2,392      2,535      7,197
    Geological and geophysical          384        833      1,048      2,595
    Office and other                     37        193        295        260
    -------------------------------------------------------------------------
    Total                            12,045     12,616     55,698     32,665
    Asset retirement obligation         143        334        462        501
    -------------------------------------------------------------------------
    Total exploration and
     development                     12,188     12,950     56,160     33,166
    -------------------------------------------------------------------------
    Net acquisitions (dispositions)     766       (270)   102,723       (270)
    -------------------------------------------------------------------------
    Total capital                    12,954     12,680    158,883     32,896
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Overall, the Company has spent 92 percent of its exploration and
development capital on drilling, completion and tie-in activities during 2006
compared to a capital program that was more focused on land and seismic in
2005. In 2005 there was a focus to build new land positions in central and
west central Alberta. With a large undeveloped land base in place entering
2007, the capital program is again expected to be approximately 90 percent
allocated to drilling and completion activity.

    WORKING CAPITAL

    Accounts receivable of $19.6 million at December 31, 2006 was primarily
revenue receivables ($5.1 million) and amounts owing from partners
($13.4 million) and capital advances to partners for drilling projects
($0.5 million). Accounts payable at December 31, 2006 of $26.6 million were
mainly comprised of trade payables for capital and operating costs
($12.9 million), royalties ($2.1 million), amounts owing to partners
($2.6 million) and capital costs accrued at the end of the quarter for ongoing
drilling and completion operations ($1.5 million).
    Working capital excluding bank indebtedness was in a deficit position of
$5.0 million at December 31, 2006. Borrowings under the bank line and ongoing
cash flows are expected to fund the working capital deficit.

    LIQUIDITY AND CAPITAL 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 $59.0 million, secured by producing properties at December 31, 2006. The bank line was increased to $65 million subsequent to year end. At December 31, 2006, $50.1 million was drawn on the bank line. On October 26, 2006 a flow-through equity financing was closed for net proceeds of $11.2 million which improved the financial condition of the Company. NON-GAAP MEASUREMENTS This MD&A contains the term "funds from operations" and "operating netback". As an indicator of the Company's performance, these terms should not be considered an alternative to, or more meaningful than "cash flow from operating activities" or "net income (loss)" as determined in accordance with Canadian generally accepted accounting principles. The Company's determination of funds from operations and operating netback may not be comparable to that reported by other companies, especially those in other industries. Management feels that funds from operations is a useful measure to help investors assess whether the Company is generating adequate cash amounts from its operations to fund its ongoing operations and planned capital program. Operating netback is a useful measure for comparing the Company's price realization and cost performance against industry competitors. The reconciliation between net income and funds from operations for the periods ended December 31 is set out in the following chart: ------------------------------------------------------------------------- Three months Twelve months ended ended ($000's) December 31 December 31 ------------------------------------------------------------------------- 2006 2005 2006 2005 ------------------------------------------------------------------------- Net income (loss) (21,951) (475) (28,340) 504 Items not requiring cash: Depletion, depreciation and accretion 9,569 7,174 36,747 18,540 Impairment of goodwill 24,220 - 24,220 Unrealized hedging gains (635) - (635) Future income tax expense (recovery) (5,218) 25 (10,237) (1,098) Stock based compensation 133 103 716 339 ------------------------------------------------------------------------- Funds from operations 6,118 6,827 22,471 18,285 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Funds from operations are also presented on a per share basis consistent with the calculation of net income per share, whereby per share amounts are calculated using the weighted average number of shares outstanding. Funds from operations per share were $0.07 (basic and diluted) for the fourth quarter of 2006 compared to $0.13 per share for the fourth quarter of 2005. Funds from operations per share were $0.26 (basic and diluted) for the year ended December 31, 2006 compared to $0.37 for the year ended December 31, 2005. RISKS Primary financial risks relate to variability in commodity prices. Interest rate and currency exchange rate variability also have an effect on financial results. The effect of changes in the exchange rate between US and Canadian currencies on natural gas prices is not direct, as variations between the regional markets for natural gas are often much greater than can be explained by currency variability. Other risks are related to operations. These risks include, but are not limited to, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, delays or changes in plans with respect to exploration or development projects or capital costs, volatility of commodity prices, currency fluctuations, the uncertainty of reserves estimates, potential environmental liabilities, technology risks, competition, incorrect assessment of the value of acquisitions and failure to realize the anticipated benefits of acquisitions. The foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect operations or financial results are included in a more detailed description of risks in Berens' Annual Information Form on file with Canadian securities regulatory authorities and available on SEDAR at www.sedar.com. Documented environmental health and safety plans are in place as well as a comprehensive emergency response plan to mitigate operating risks. COMMODITY PRICE RISK MANAGEMENT The Company may use financial derivative or fixed price contracts to manage its exposure to fluctuations in commodity prices and foreign currency exchange rates. The Company applies the fair value method of accounting for derivative instruments by initially recording an asset or liability, and recognizing changes in the fair value of the derivative instrument in income. The following is a summary of natural gas price risk management derivative contracts in effect as of December 31, 2006. All contracts are priced in Canadian dollars per gigajoule (GJ). The price per GJ can be converted to an approximate price per MCF by multiplying the per GJ price by 1.05. GJ can be converted to an approximate MCF volume by multiplying the GJ volume by 0.95. ------------------------------------------------------------------------- Daily quantity (GJ) Term of Contract Fixed price per gigajoule ------------------------------------------------------------------------- 2,000 January 1 to March 31, 2007 $6.00 floor; $11.05 cap ------------------------------------------------------------------------- 2,000 April 1 to October 31, 2007 $6.00 floor; $8.50 cap ------------------------------------------------------------------------- 2,000 November 1 to December 31, 2007 $6.00 floor; $11.05 cap ------------------------------------------------------------------------- 2,000 January 1 to March 31, 2007 $7.00 floor; $9.85 cap ------------------------------------------------------------------------- 2,000 April 1 to October 31, 2007 $7.00 floor; $8.00 cap ------------------------------------------------------------------------- 2,000 November 1 to December 31, 2007 $7.00 floor; $9.85 cap ------------------------------------------------------------------------- The fair value of the above natural gas derivative instruments marked to market as at December 31, 2006, results in an unrealized gain of $635,000. There were no realized gains or losses on derivative instruments in 2006. A fixed price contract to sell 2,000 GJ per day from January 1 to October 31, 2007 at a price of $7.65 per GJ was also entered into for the purpose reducing exposure to natural gas price volatility. RELATED PARTY TRANSACTIONS A consulting firm is contracted from time to time in which one of the Company's directors is the chairman and founding partner. The executive services rendered are in the normal course of business and are at normal rates charged by the consulting firm and recorded at the exchange amount. Consulting fees for this firm in the fourth quarter of 2006 were nil and $58,000 for the year ended December 31, 2006. Fees for legal services are paid to a law firm in which the corporate secretary is a partner. The legal services are rendered in the normal course of business at normal rates charged by the law firm. Legal fees for this firm paid in the fourth quarter of 2006 were $39,000 and $571,000 for the year ended December 31, 2006. SHARE DATA As of the date of this MD&A the Company had 92,947,064 issued and outstanding common shares. Additionally, options to purchase 5,268,200 common shares have been issued. DISCLOSURE CONTROLS AND PROCEDURES OVER FINANCIAL REPORTING The Company has established procedures and internal control systems to ensure timely and accurate preparation of financial, internal management and other reports. Disclosure controls and procedures are in place to ensure all ongoing statutory reporting requirements are met and material information is disclosed on a timely basis. The Chief Executive Officer and the Chief Financial Officer, individually, sign certifications that the financial statements, together with the other financial information included in the regulatory filings, fairly present in all material respects the financial conditions, results of operation, and cash flows as of the dates and for the periods represented. The Company's management, including its Chief Executive Officer and its Chief Financial Officer, have evaluated the effectiveness of the Company's disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded that the Corporation's disclosure controls are effective as of the end of the period covered by this annual report, in all material respects, after considering the Canadian Securities Administrators' Multilateral Instrument 52-109 Certification of Disclosures in Issuers' Annual and Interim Filings. Internal control over Financial Reporting Management of Berens is responsible for establishing and maintaining adequate internal controls over financial reporting. Internal controls over financial reporting is a process designed under the supervision of the Chief Executive Officer and the Chief Financial Officer and effected by the Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Management has conducted a review of the design of its internal controls over financial reporting as at December 31, 2006. Based on this assessment, management believes that the Corporation's system of internal controls over financial reporting as defined under MI 52-109 is sufficiently designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. By virtue of the size of the Corporation and its related staff complement, there are inherent limitations on the ability of management to implement internal controls. Management believes that it has designed sufficient internal controls to mitigate these limitations comprised primarily of management review and oversight. Due to its inherent limitations, internal controls over financial reporting may not prevent or detect misstatements on a timely basis. A system of internal controls over financial reporting, no matter how well conceived or operated can provide only reasonable, not absolute, assurance that the objectives of the internal controls over financial reporting are met. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions. Recent Canadian Accounting Pronouncements As of January 1, 2007, the Corporation is required to adopt the Canadian Institute of Chartered Accountants ("CICA") Section 1530 "Comprehensive Income", Section 3251 "Equity", Section 3855 "Financial Instruments - Recognition and Measurement", and Section 3865 "Hedges", which were issued in January 2005. Under the new standards, a new financial statement, the Consolidated Statement of Comprehensive Income, has been introduced that will provide for certain gains and losses and other amounts arising from changes in fair value, to be temporarily recorded outside the income statements. In addition, all financial instruments, including derivatives, are to be included in the Company's Balance Sheets and measured, in most cases, at fair values, and requirements for hedge accounting have been further clarified. The Company is currently evaluating the impact of the new standards. Management does not anticipate the new and revised standards will have a material impact on its consolidated financial statements as the Company currently uses fair value accounting for derivative instruments that do not qualify or are not designated as hedges. As of January 1, 2007, the Company is required to adopt revised CICA Section 1506, "Accounting Changes", which provides expanded disclosures for changes in accounting policies, accounting estimates and corrections of errors, which were issued in July 2006. Under the new standard, accounting changes should be applied retrospectively unless otherwise permitted or where impracticable to determine. As well, voluntary changes in accounting policy are made only when required by a primary source of GAAP or when the change results in more relevant and reliable information. The Company does not expect application of this revised standard to have a material impact on its consolidated financial statements. OUTLOOK Drilling success in late 2006 and in early 2007 has confirmed the potential of the undeveloped land in the Company's portfolio. Drilling opportunities exist across four core areas and are well diversified in terms of risk, reserve potential and value addition. The intention is to remain focused in the four core areas that have been established to take advantage of the high level of technical expertise and experience we have developed in each area. The 2007 capital program will be diversified across the four core areas. Pembina, which is considered to have low risk with strong return potential will receive 60 percent of the 2007 capital program with the balance of 2007 split between the lower risk shallow gas programs in Lanfine and Marten Hills and the higher risk/reward Deep Basin area which has the potential for large reserve discoveries. The 2007 capital plan is drilling focused with over 90 percent of capital budgeted toward drilling and completion activities with the balance directed toward land and seismic acquisitions. Access to services appears to be easing throughout western Canada. We expect some moderation of the industry cost structure as we go forward but capital management and a focus on cost reduction will still be important aspects of our business when carrying out the 2007 capital program. The undeveloped land base totaling 145,000 net acres is expected to provide a strong inventory of drilling prospects to deliver future growth. The 2007 drilling program is well established already. We plan to participate in 50 wells, all on existing land. It is expected that the Company will still have ample undeveloped acreage to continue drilling well beyond the end of 2007. Berens Energy Ltd. Balance Sheets As at, ------------------------------------------------------------------------- (000's) December 31, December 31, 2006 2005 ------------------------------------------------------------------------- ASSETS (note 5) Current Cash and cash equivalents (note 3) $ 10 $ 9,472 Accounts receivable 19,601 9,912 Unrealized gain on risk management (note 12) 635 - Prepaid expenses and deposits 1,412 312 ------------------------------------------------------------------------- 21,658 19,696 Investments 29 299 Future income taxes (note 9) - 225 Property, plant and equipment (note 5) 171,178 53,242 Goodwill (note 4 & 13) 20,755 14,805 ------------------------------------------------------------------------- $ 213,620 $ 88,267 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY Current Bank loan (note 7) $ 50,080 - Accounts payable and accrued liabilities 26,622 $ 15,331 Taxes payable 29 92 ------------------------------------------------------------------------- 76,731 15,423 Asset retirement obligations (note 6) 2,645 1,223 Future income taxes (note 9) 14,518 - ------------------------------------------------------------------------- 93,894 16,646 Commitments (note 15) Shareholders' equity Capital stock (note 8) 148,038 72,309 Contributed surplus (note 8) 1,290 574 Deficit (29,602) (1,262) ------------------------------------------------------------------------- 119,726 71,621 ------------------------------------------------------------------------- $ 213,620 $ 88,267 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the financial statements Berens Energy Ltd. Statements of Operations and Deficit For the three months and year ended December 31, ------------------------------------------------------------------------- (000's) Three months Year ended ended December 31, December 31, ------------------------------------------------------------------------- 2006 2005 2006 2005 ------------------------------------------------------------------------- Revenue Oil and natural gas revenue $ 14,386 $ 12,644 $ 52,810 $ 36,393 Royalties, net of ARTC (3,173) (3,107) (12,692) (8,525) ------------------------------------------------------------------------- 11,213 9,537 40,118 27,868 Unrealized gain on risk management (note 12) 635 - 635 - ------------------------------------------------------------------------- 11,848 9,537 40,753 27,868 Interest - 12 18 14 ------------------------------------------------------------------------- 11,848 9,549 40,771 27,882 ------------------------------------------------------------------------- Expenses Production 2,905 1,588 9,721 5,468 Transportation 302 267 1,116 859 Depletion, amortization and accretion 9,569 7,174 36,747 18,540 Impairment of goodwill (note 13) 24,220 - 24,220 - General and administrative (note 11) 845 821 4,090 2,847 Stock-based compensation (note 8) 133 103 716 339 Interest 972 6 2,627 328 ------------------------------------------------------------------------- 38,946 9,959 79,237 28,381 ------------------------------------------------------------------------- Loss before income taxes (27,098) (410) (38,466) (499) Income taxes (note 9) Future expense (recovery) (5,218) 25 (10,237) (1,098) Current expense 71 40 111 95 ------------------------------------------------------------------------- (5,147) 65 (10,126) (1,003) ------------------------------------------------------------------------- Net income (loss) for the period (21,951) (475) (28,340) 504 Deficit, beginning of period (7,651) (787) (1,262) (1,766) ------------------------------------------------------------------------- Deficit, end of period $ (29,602) $ (1,262) $ (29,602) $ (1,262) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net income (loss) per share (note 14) Basic and diluted $ (0.24) $ (0.01) $ (0.33) $ 0.01 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the financial statements Berens Energy Ltd. Statements of Cash Flows For the three months and year ended December 31, ------------------------------------------------------------------------- (000's) Three months Year ended ended December 31, December 31, ------------------------------------------------------------------------- 2006 2005 2006 2005 ------------------------------------------------------------------------- OPERATING ACTIVITIES Net income (loss) for the period $ (21,951) $ (475) $ (28,340) $ 504 Add items not involving cash Depletion, amortization and accretion 9,569 7,174 36,747 18,540 Impairment of goodwill 24,220 - 24,220 - Unrealized risk management gain (635) - (635) - Future income tax expense (recovery) (5,218) 25 (10,237) (1,098) Stock-based compensation 133 103 716 339 ------------------------------------------------------------------------- 6,118 6,827 22,471 18,285 Change in non-cash working capital items related to operating activities (note 10) (1,274) 1,854 (9,016) 4,248 ------------------------------------------------------------------------- Cash flow provided by (used in) operating activities 4,844 8,681 13,455 22,533 ------------------------------------------------------------------------- FINANCING ACTIVITIES Change in bank loan (2,700) - 30,330 (4,500) Net proceeds from private offerings 11,142 11,928 30,955 24,795 Sale of investment 25 - 269 - Proceeds from the exercise of stock options - - - 49 ------------------------------------------------------------------------- Cash flow provided by (used in) financing activities 8,467 11,928 61,554 20,344 ------------------------------------------------------------------------- INVESTING ACTIVITIES Cash acquired through Berland acquisition - - 109 - Cash component on Berland acquisition - - (28,682) - Purchase of property and equipment (12,811) (12,346) (56,914) (32,396) Change in non-cash working capital items related to investing activities (note 10) (534) (182) 1,016 (1,044) ------------------------------------------------------------------------- Cash flow used in investing activities (13,345) (12,528) (84,471) (33,440) ------------------------------------------------------------------------- Increase (decrease) in cash and cash equivalents (34) 8,081 (9,462) 9,437 Cash and cash equivalents, beginning of period 44 1,391 9,472 35 ------------------------------------------------------------------------- Cash and cash equivalents, end of period $ 10 $ 9,472 $ 10 $ 9,472 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the financial statements BERENS ENERGY LTD. Notes to Financial Statements Year ended December 31, 2006 and 2005 1. NATURE OF OPERATIONS The Company is a full cycle oil and natural gas exploration and production company with activities encompassing land acquisition, geological and geophysical assessment, drilling and completion, and production. The primary areas of operation are in eastern and west central Alberta. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles. The nature of the business and timely preparation of financial statements requires that management make estimates and assumptions, and use judgment regarding assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, actual results may differ from estimated amounts. In the opinion of management, these financial statements have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting policies summarized below. Cash and Cash Equivalents Cash and cash equivalents, consisting of cash and short-term investments with a maturity of less than three months, are recorded at the lower of cost and quoted market value. Capitalized Costs The full cost method of accounting is followed whereby all costs relating to the acquisition of, exploration for and development of oil and gas reserves are capitalized in a single Canadian cost center. Such costs include lease acquisition, lease rentals on undeveloped properties, geological and geophysical costs, drilling both productive and non-productive wells, production equipment and overhead charges directly related to acquisition, exploration and development activities. Gains or losses are not recognized on the disposition of oil and gas properties unless such dispositions would change the depletion rate by 20 percent or more. Gains are recognized on the disposition of other assets. Depletion and Amortization All costs of acquisition, exploration and development of oil and gas reserves, associated tangible plant and equipment costs (net of salvage value), and estimated costs of future development of proved undeveloped reserves are depleted and amortized by the unit of production method. This method is based on estimated gross proved reserves as determined by independent engineers. Costs of unproved properties are initially excluded from oil and gas properties for the purpose of calculating depletion. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion. The volumes of oil and natural gas reserves and production are converted to equivalent barrels of oil based on the relative energy content of each product such that six thousand cubic feet of natural gas equals one barrel of oil, commonly known as a six to one basis. Office and computer equipment is amortized on a straight-line basis over ten and four years, respectively. Asset Retirement Obligations The Company has obligations to abandon and reclaim oil and natural gas wells and production facilities after it is determined that these wells and facilities have no further economic value. Well reclamations generally involve the removal of production tubing in the well, setting a permanent plug, pouring cement on top of the plug, cutting and capping the casing below surface and removal of surface equipment at the well site. Land disturbances are smoothed, native vegetation is re-introduced and the site is left to return to its natural state. In the case of wells on farm land, sites are returned to productive farming use. The fair value of a liability is recognized for an asset retirement obligation in the period in which it is incurred or when a reasonable estimate of its fair value can be made, and records a corresponding increase in the carrying value of the related long-lived asset. The estimated fair value is determined through a review of engineering studies, industry guidelines, and management's estimate on a site-by-site basis. The liability is subsequently adjusted for the passage of time, which is recognized as an accretion expense in the statement of operations and included in asset retirement obligations. The liability is also adjusted due to revisions in either the timing or the amount of the original estimated cash flows associated with the liability. The increase in the carrying value of the asset is amortized using the unit of production method based on estimated gross proved reserves. Actual costs incurred upon settlement of the asset retirement obligations are charged against the asset retirement obligation to the extent of the liability recorded. Any difference between the actual costs incurred upon settlement of the asset retirement obligation and the recorded liability is recognized as a gain or loss in the Company's statement of operations in the period in which the settlement occurs. Ceiling Test The Company applies an impairment test to the net carrying value of petroleum and natural gas assets designed to ensure that such costs do not exceed the estimated amount ultimately recoverable. This amount is the aggregate of estimated undiscounted future net cash flows from production of proved reserves and the cost of unproved properties and seismic. Future cash flows are estimated using future prices and costs without discounting. Should the net carrying value of the petroleum and natural gas assets exceed the amount ultimately recoverable, the amount of impairment is determined by deducting the discounted estimated future cash flows from proved and probable reserves based on the future prices plus the cost of unproved properties, net of impairment allowances, from the book value of the related assets. Any reduction in net carrying value, as a result of the impairment test, is included in depreciation and depletion expense. Goodwill Goodwill, at the time of acquisition, represents the excess of purchase cost of a business over the fair value of net assets acquired. Thereafter, goodwill is not amortized and is assessed for impairment at least annually. If the estimated fair value of the business is less than the book value, a second test is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the estimated fair value of the business' net assets from the fair value of the business to determine the implied fair value of goodwill and comparing that amount to the book value of goodwill. Any excess of the book amount of goodwill over the implied fair value is the impairment amount and is charged to earnings in the period of impairment. Revenue Recognition Oil and natural gas sales are recorded as revenue when the commodities are delivered to purchasers. Income Taxes The liability method of accounting for income taxes is followed. Under this method, future tax assets and liabilities are determined based on the differences between financial reporting and income tax bases of assets and liabilities, and are measured using substantively enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect on future tax assets and liabilities of a change in tax rates is recognized in net income in the period in which the change occurs. Joint Ventures A substantial portion of the Company's exploration, development and production activities is conducted jointly with others. These consolidated financial statements reflect only the Company's proportionate interest in such activities. Stock-Based Compensation Under the stock option plan, options to purchase common shares are granted to directors, officers, employees and consultants at current market prices. Options issued by the Company are accounted for in accordance with the fair value method of accounting for stock-based compensation using the Black-Scholes option pricing model. The resulting cost of the option is charged to earnings over the vesting period of the option with a corresponding increase in contributed surplus. Measurement Uncertainty The amount recorded for depletion and amortization of oil and gas properties, the provision for asset retirement obligations, goodwill measurement and the ceiling test calculation are based on estimates of gross proved reserves, production rates, commodity prices, future costs and other assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future years could be material. Per Share Information Per share information is calculated on the basis of the weighted average number of common shares outstanding during the fiscal year. Diluted per share information reflects the potential dilution that could occur if securities or other contracts to issue common shares were exercised or converted to common shares. Diluted per share information is calculated using the treasury stock method which assumes that any proceeds received by the Company upon the exercise of in-the-money stock options would be used to buy back common shares at the average market price for the period. Investments Long-term investments are recorded at the lower of cost or fair market value. Flow-through Common Shares Resource expenditure deductions for income tax purposes related to exploration and development activities funded by flow-through share arrangements are renounced to investors in accordance with income tax legislation. The estimated tax benefits transferred to shareholders are recorded as future income taxes and a reduction to share capital when the expenditures are renounced, which for accounting purposes, is when the appropriate documentation is filed with Revenue Canada. Financial Instruments The Company may use, from time to time, derivative financial instruments to manage exposure related to changes in oil and natural gas commodity prices. They are not used for trading or speculative purposes. The Company applies the fair value method of accounting for derivative instruments by initially recording an asset or liability, and recognizing changes in the fair value of the derivative instrument in earnings. The resulting unrealized gain or loss is recorded as a receivable or liability with the tax effect included in the future income tax provision. 3. CASH AND CASH EQUIVALENTS Cash and cash equivalents are in the form of cash bank balances or certificates of deposit from Canadian financial institutions with terms of less than 90 days. The effective interest rate on the deposits at December 31, 2006 was 2.3% (2005 - 2.3%). 4. ACQUISITION OF BERLAND EXPLORATION LTD. On January 18, 2006, Berens and Berland Exploration Ltd. ("Berland") closed a previously announced arrangement that saw Berens acquire Berland. Pursuant to the arrangement, shareholders of Berland received $0.96 in cash ($20.0 million) and 0.8784 of a Berens common share (21,083,795 common shares for $53.8 million) for each Berland common share. Additionally, certain option and warrant holders received a differential payment for the difference between their option and warrant strike prices and $3.20 per Berland share ($8.7 million). Pursuant to the Arrangement, Berens also assumed $19.7 million of Berland debt and transaction costs of $0.5 million. The total cost to Berens to acquire the Berland shares was $102.7 million. This acquisition has been accounted for using the purchase method with the Berland results included in the statement of operations from the closing date of January 18, 2006. The following table summarizes the estimated fair value of the assets acquired and liabilities assumed as at the closing date. Assets and liabilities purchased ($000's) ------------------------------------------------------------------------- Cash and cash equivalents 109 Accounts receivable 10,321 Prepaid expenses and deposits 1,488 Petroleum and natural gas properties 97,616 Goodwill 30,288 Accounts payable and accrued liabilities (20,247) Future income taxes (16,111) Asset retirement obligations (715) ------------------------------------------------------------------------- Total cost to acquire Berland 102,749 ------------------------------------------------------------------------- 5. PROPERTY, PLANT AND EQUIPMENT December 31, 2006 December 31, 2005 Accumulated Accumulated depletion and depletion and ($000's) Cost depreciation Cost depreciation ------------------------------------------------------------------------- Petroleum and natural gas properties 240,047 69,305 81,030 28,186 Office and computer equipment 678 242 492 94 ------------------------------------------------------------------------- 240,725 69,547 81,522 28,280 ------------------------------------------------------------------------- Net book value 171,178 53,242 ------------------------------------------------------------------------- At December 31, 2006, costs of $25,907,000 (2005 - $10,391,000) related to undeveloped land have been excluded from the depletion and depreciation calculation. At December 31, 2006 future development capital of $13,018,000 have been included in the depletion and depreciation calculation (2005 - $1,411,000). A ceiling test was completed at December 31, 2006 resulting in no impairment. Benchmark pricing used for ceiling test purposes is shown on the following table. Oil ---------------------------------------------- Edmonton Cromer WTI Par Price Medium Cushing 40 degrees Hardisty 29.3 degrees Oklahoma API Heavy API Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ---------- ---------- ---------- ---------- Historical Averages 2002 26.08 40.33 26.57 35.48 2002 31.07 43.66 26.26 37.55 2004 41.38 52.96 29.11 45.75 2005 56.58 69.11 34.07 56.62 2006 (e) 66.22 73.16 41.87 62.24 Forecast 2007 62.00 70.25 39.25 61.25 2008 60.00 68.00 40.00 59.25 2009 58.00 65.75 39.75 57.25 2010 57.00 64.50 39.75 56.00 2011 57.00 64.50 40.25 56.00 2012 57.50 65.00 41.50 56.50 Inflation thereafter +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr Natural gas NGLs ---------- ---------- AECO-C FOB Gas Field Gate Price (propane/ Inflation Exchange ($Cdn/ butane) rate% rate Year MMbtu) ($Cdn/bbl) per year ($US/Cdn) ---------- ---------- ---------- ---------- Historical Averages 2002 4.04 24.24 2.2 0.637 2002 6.66 33.25 2.8 0.721 2004 6.88 37.34 1.8 0.768 2005 8.58 47.42 2.2 0.825 2006 (e) 7.02 55.30 2.0 0.882 Forecast 2007 7.20 50.62 2.0 0.87 2008 7.45 46.88 2.0 0.87 2009 7.75 45.38 2.0 0.87 2010 7.80 44.50 2.0 0.87 2011 7.85 44.50 2.0 0.87 2012 8.15 44.75 2.0 0.87 Inflation thereafter +2.0%/yr +2.0%/yr 2.0 0.87 6. ASSET RETIREMENT OBLIGATIONS The total future asset retirement obligations were estimated based on the net ownership interest in all wells and facilities, estimated costs to reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred in future periods. The estimated net present value of the total asset retirement obligations is $2,645,000 as at December 31, 2006 (2005 - $1,223,000) based on a total future liability of $6,959,400 (2005 - $3,314,000). These payments are expected to be made over the next 5 to 15 years. An inflation rate of 2% and a credit adjusted risk free rate of 10% were used to calculate the present value of the asset retirement obligations. The inflation rate used for the asset retirement obligation calculation was increased from 1.5% used in 2005 to reflect higher cost pressures in the industry. The following table reconciles the asset retirement obligations: ($000's) 2006 2005 ------------------------------------------------------------------------- Obligation, December 31, 2005 $1,223 $ 648 Increase in obligation during the period 430 276 Obligation assumed from Berland acquisition 715 - Increase due to increase in inflation rate 32 - Increase due to reduction of risk free rate - 73 Accretion expense 245 226 ------------------------------------------------------------------------- Obligation, December 31, 2006 $2,645 $1,223 ------------------------------------------------------------------------- 7. BANK OPERATING LINE An agreement with a Canadian bank is in place for an operating bank line totaling $59.3 million at December 31, 2006. Collateral for the facility consists of a general assignment of book debts and a $75.0 million debenture with a floating charge over all assets of the Company. The bank line is a demand line and carries an interest rate of the Bank's prime rate adjusted for a factor based on the most recent quarterly debt to cash flow calculation. The rate at December 31, 2006 was 7.25 percent (December 30, 2005 - 4.875 percent). On December 31, 2006, $50,080,000 was drawn on the line. Subsequent to December 31, 2006 the bank line capacity was increased to $65 million. 8. CAPITAL STOCK (a) Authorized Capital The authorized capital consists of an unlimited number of preferred shares issuable in series and an unlimited number of common shares without nominal or par value. (b) Common shares issued --------------------------------------------------------------------- Consideration Number ($000's) --------------------------------------------------------------------- Balance December 31, 2004 46,427,469 48,331 Stock options exercised during the year 35,800 49 Reduction of contributed surplus for options exercised - 6 Private placements for cash, net of commissions 10,700,000 24,979 Future tax effect of flow-through share renouncement - (1,541) Future tax effect on share issue costs and commissions - 670 Share issue costs, net of tax - (185) --------------------------------------------------------------------- Balance December 31, 2005 57,163,269 72,309 Private placement for cash on conversion of subscription receipts, net of commissions 8,200,000 19,988 Shares issued on arrangement with Berland (note 3) 21,083,795 53,764 Private placement for cash, net of commissions 6,500,000 11,238 Future tax effect of flow-through share renouncements - (9,554) Future tax effect on share issue costs and commissions - 565 Share issue costs, net of tax - (272) --------------------------------------------------------------------- Balance December 31, 2006 92,947,064 148,038 --------------------------------------------------------------------- Private Placements On September 12, 2005, 4,500,000 common shares were issued by way of a private placement at $1.95 per common share for cash proceeds of $8,775,000 before agent's commission of $482,625. The proceeds of the financing were used to fund oil and gas exploration and development costs and for general corporate purposes. On September 12, 2005, 2,000,000 common shares were issued on a flow-through basis pursuant to the Income Tax Act by way of a private placement at $2.45 per share for proceeds of $4,900,000, before the agent's commission of $269,500, to finance certain oil and gas expenditures to be incurred in 2005 and 2006. The renouncement of these expenditures was made to the purchasers of these shares for the 2005 income tax year. The expenditures to satisfy the flow-through commitment were made during 2005 and 2006. On December 22, 2005, 4,200,000 common shares were issued on a flow-through basis pursuant to the Income Tax Act by way of a private placement at $3.15 per common share for proceeds of $13,230,000 before agent's commission of $661,500 and 8,200,000 subscription receipts in the capital of the Corporation issued at a price of $2.50 per subscription receipt. The net proceeds from the "flow-through" portion of the private placement have been used to incur qualifying expenditures with respect to the continued exploration and development of the Company's oil and natural gas properties prior to December 31, 2006. The renouncement of these expenditures was made to the purchasers of these shares for the 2005 income tax year. The expenditures to satisfy the flow-through commitment have been made as at June 30, 2006. Each subscription receipt represented the right to receive one common share on the closing of the acquisition of Berland Exploration Ltd. The Berland acquisition closed on January 18, 2006 and all subscription receipts were converted to common shares and proceeds of $20,500,000 less commissions of $512,000 were released to the Company. No obligation remains related to this subscription receipt issue. On January 18, 2006 21,083,795 common shares were issued in exchange for the acquisition of Berland shares pursuant to the Arrangement between the companies (see note 4). On October 26, 2006, 6,500,000 flow-through common shares were issued in a private placement at $1.82 per share for cash proceeds of $11,830,000 before agent's commission of $591,500 to finance certain oil and gas expenditures to be incurred in 2006 and 2007. The renouncement of these expenditures was made to the purchasers of these shares during 2006. (c) Stock Option Plan A stock option plan is in place under which 7,500,000 common shares have been reserved for options to be distributed to directors, officers, employees and consultants with terms established by the board of directors. Options granted under the plan generally have a five year term to expiry and vest equally over a three year period commencing on the first anniversary date of the grant. The exercise price of each option equals the closing market price of the Company's common shares on the day prior to the date of the grant. The following table sets forth a reconciliation of the plan activity through December 31, 2006. 2006 2005 Weighted Weighted average average exercise exercise Number of price Number of price Options ($ per share) Options ($ per share) ------------------------------------------------------------------------- Outstanding, beginning of year 3,513,700 1.56 2,784,500 1.07 Granted 910,000 1.31 870,000 2.75 Cancelled (7,500) 2.90 (105,000) 1.48 Exercised - - (35,800) 1.38 ------------------------------------------------------------------------- Outstanding, end of year 4,416,200 1.68 3,513,700 1.56 ------------------------------------------------------------------------- Exercisable 2,449,692 1.34 1,349,022 1.12 ------------------------------------------------------------------------- The following table sets forth additional information relating to the stock options outstanding at December 31, 2006. Options Outstanding ------------------------------------------------------------------------- Weighted average exercise Weighted Number price average Exercise price of ($ per years to range Options share) expiry ------------------------------------------------------------------------- $1.00 to $1.59 3,051,700 1.22 2.32 ------------------------------------------------------------------------- $1.60 to $2.19 184,500 1.75 4.25 ------------------------------------------------------------------------- $2.20 to $2.79 242,500 2.49 4.31 ------------------------------------------------------------------------- $2.80 to $3.39 937,500 2.95 3.95 ------------------------------------------------------------------------- 4,416,200 1.68 2.86 ------------------------------------------------------------------------- Exercisable Options ------------------------------------------------------------------------- Weighted average exercise Weighted Number price average Exercise price of ($ per years to range Options share) expiry ------------------------------------------------------------------------- $1.00 to $1.59 2,172,192 1.15 - ------------------------------------------------------------------------- $1.60 to $2.19 15,000 1.70 - ------------------------------------------------------------------------- $2.20 to $2.79 - - - ------------------------------------------------------------------------- $2.80 to $3.39 262,500 2.90 - ------------------------------------------------------------------------- 2,449,692 1.34 2.09 ------------------------------------------------------------------------- The fair value method for measuring option awards based on the Black Scholes valuation model is used. Key assumptions used for the Black Scholes based valuation of options are: Risk free rate - 4.3 percent; average expected life - 4.5 years; no expected dividend yield; 45 percent volatility. Estimated future forfeiture assumptions are not used in calculations and forfeitures are recognized as they occur. The weighted average option price for options outstanding at December 31, 2006 is $0.596 per option. Based on the fair value method, $133,000 was recorded as compensation expense during the fourth quarter of 2006 (2005 - $103,000) and for the full year 2006, $716,000 (2005 - $339,000) for options issued and outstanding with a corresponding increase recorded to contributed surplus. (d) Contributed Surplus The following table sets forth the continuity of contributed surplus for the three months ended September 30, 2006. ($000's) ------------------------------------------------------------------------- Opening balance, December 31, 2005 574 Stock based compensation expense 716 ------------------------------------------------------------------------- Closing balance, December 31, 2006 1,290 ------------------------------------------------------------------------- 9. INCOME TAXES The income tax expense or benefit differs from the amount computed by applying the Canadian statutory rates to the loss before tax as follows: ($000's) 2006 2005 ------------------------------------------------------------------------- Loss before income taxes (38,466) (499) ------------------------------------------------------------------------- Current statutory income tax rate 34.54% 37.82% ------------------------------------------------------------------------- Anticipated tax recovery (13,286) (189) Decrease in recovery resulting from: Effect of future tax rate reductions (5,511) (301) Impairment of goodwill 8,365 Unrealized risk management gains (219) - Non-deductible Crown payments 1,293 1,748 Resource allowance (1,085) (1,444) Alberta royalty tax credits (54) (113) Provincial royalty rebates - (96) Non-deductible expenses 260 135 Other - 46 Future tax asset valuation allowance - (884) ------------------------------------------------------------------------- Future income tax recovery (10,237) (1,098) ------------------------------------------------------------------------- Capital tax 29 95 Other 82 - ------------------------------------------------------------------------- Current income tax expense 111 95 ------------------------------------------------------------------------- Future income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the future tax assets are as follows: ($000's) 2006 2005 ------------------------------------------------------------------------- Future tax liabilities Net book value of capital assets in excess of tax pools (16,819) (1,379) Future tax assets Share issue costs 848 746 Attributed Canadian royalty income 683 444 Asset retirement obligation 771 414 ------------------------------------------------------------------------- Net future tax (liabilities) assets (14,517) 225 ------------------------------------------------------------------------- Tax Pools At December 31, 2006 the petroleum and natural gas properties had an approximate tax basis of $123,000,000. Capital loss carry-forwards exist totaling $3,363,000 which are available to offset future capital gains for which no future income tax asset has been recognized in the accounts. 10. SUPPLEMENTAL CASH FLOW INFORMATION Changes in Non-cash Working Capital For the years ended December 31, ($000's) 2006 2005 ------------------------------------------------------------------------- Accounts receivable (9,690) (6,547) Prepaid expenses and deposits (1,100) (187) Accounts payable and accrued liabilities 11,291 9,904 Taxes payable (63) 34 Non-cash working capital acquired (note 4) (8,438) - ------------------------------------------------------------------------- (8,000) 3,204 Change in non-cash working capital related to investing activities 1,016 (1,044) ------------------------------------------------------------------------- Change in non-cash working capital related to operating activities (9,016) 4,248 ------------------------------------------------------------------------- Cash interest and taxes paid For the three and twelve months ended December 31, Three Three Twelve Twelve months months months months ($000's) 2006 2005 2006 2005 ------------------------------------------------------------------------- Income and other taxes 69 23 220 103 Interest 972 113 2,627 328 ------------------------------------------------------------------------- 11. RELATED PARTY TRANSACTIONS A consulting firm is contracted from time to time in which one of its directors is the chairman and founding partner. The executive services rendered are in the normal course of business and are at normal rates charged by the consulting firm and recorded at the exchange amount. Consulting fees for this firm in the fourth quarter of 2006 were nil and $58,000 for the year ended December 31, 2006. Fees for legal services are paid to a law firm in which the corporate secretary is a partner. The legal services are rendered in the normal course of business at normal rates charged by the law firm. Legal fees for this firm paid in the fourth quarter of 2006 were $39,000 and $571,000 for the year ended December 31, 2006. The 2006 fees related to assistance with the Berland acquisition and the related equity issues, the equity issue in October 2006 and general corporate matters. 12. FINANCIAL INSTRUMENTS Fair Value of Financial Instruments Financial instruments recognized on the balance sheets consist of cash and cash equivalents, accounts receivable, long-term investments, accounts payable, bank loans and financial derivatives used to manage natural gas price risk. The fair value of these financial instruments approximates their carrying amounts due to their short terms to maturity except for the financial derivatives which values are outlined below. (a) Credit Risk Accounts receivable are with customers, sales agents and joint venture partners in the petroleum and natural gas business and are subject to the usual credit risks. The Company mitigates this risk by entering into transactions with long-standing, reputable counterparties and partners. If significant amounts of capital are to be spent on behalf of a joint venture partner the partner is "cash called" in advance of the capital spending taking place. (b) Interest Rate Risk The Company is exposed to fluctuations in interest rates on its bank debt. (c) Foreign Exchange Risk The Company is exposed to the risk of changes in the Canadian/US dollar exchange rates on sales of commodities that are denominated in U.S. dollars or directly influenced by U.S. dollar benchmark prices. (d) Commodity Price Risk Management The following is a summary of natural gas price risk management derivative contracts in effect as of December 31, 2006. All contracts are priced in Canadian dollars per gigajoule (GJ). The price per GJ can be converted to an approximate price per MCF by multiplying the per GJ price by 1.05. GJ can be converted to an approximate MCF volume by multiplying the GJ volume by 0.95. ------------------------------------------------------------------------- Daily quantity Term of Contract Fixed price per gigajoule (GJ) ------------------------------------------------------------------------- 2,000 January 1 to March 31, 2007 $6.00 floor; $11.05 cap ------------------------------------------------------------------------- 2,000 April 1 to October 31, 2007 $6.00 floor; $8.50 cap ------------------------------------------------------------------------- 2,000 November 1 to December 31, 2007 $6.00 floor; $11.05 cap ------------------------------------------------------------------------- 2,000 January 1 to March 31, 2007 $7.00 floor; $9.85 cap ------------------------------------------------------------------------- 2,000 April 1 to October 31, 2007 $7.00 floor; $8.00 cap ------------------------------------------------------------------------- 2,000 November 1 to December 31, 2007 $7.00 floor; $9.85 cap ------------------------------------------------------------------------- The fair value of the above natural gas derivative instruments marked-to-market as at December 31, 2006, results in an unrealized gain of $635,000. There were no realized gains or losses on derivative instruments in 2006 and there were no derivative instruments outstanding in 2005. 13. GOODWILL The Company tested the goodwill balance as at December 31, 2006 taking into account the decline in corporate economic value caused by the 2006 decline in the share price. Recent oil and gas asset sales and corporate sale transactions were also benchmarked for the goodwill test. Based on the Company's assessment, it was determined that the estimated fair value of the assets was less than the book value including the amount of goodwill that was being carried on the balance sheet. As a result, the Company recorded an impairment of goodwill in the amount of $24.2 million representing 54 percent of the goodwill balance. 14. PER SHARE INFORMATION The weighted average number of common shares outstanding during the quarter ended December 31, 2006 of 91,110,107 was used to calculate basic and diluted income (loss) per share (2005 - 53,372,046). The weighted average number of common shares outstanding during the 12 months ended December 31, 2006 of 86,178,274 was used to calculate basic and diluted income (loss) per share (2005 - 48,500,438). Outstanding options have not been included in the calculation of per share information as they were anti-dilutive. The total number of shares which are potentially dilutive in future periods as of December 31, 2006 was 4,416,200. The total number of shares outstanding as of the date of the MD&A is 92,947,064. 15. COMMITMENTS Commitments exist for leased office space and vehicles. The amounts for leased space exclude operating costs, taxes, insurance and utilities: Amount Year $000's --------------------------- 2007 208 2008 168 2009 112 Thereafter - --------------------------- Total 488 --------------------------- Directors and officers are indemnified against any and all claims or losses reasonably incurred in the performance of their service to the Company to the extent permitted by law. The Company has acquired and maintains liability insurance for its directors and officers. A fixed price contract to sell 2,000 GJ per day from January 1 to October 31, 2007 at a price of $7.65 per GJ was also entered into for the purpose reducing exposure to natural gas price volatility. 16. COMPARATIVE FIGURES Certain figures have been re-classified to conform to the financial statement presentation adopted in 2005. Caution Regarding Forward Looking Information This press release contains forward looking information within the meaning of applicable securities laws. Forward looking statements may include estimates, plans, expectations, forecasts, guidance or other statements that are not statements of fact. Forward looking information in this Press Release includes, but is not limited to, statements with respect to capital expenditures and related allocations, production volumes, production mix and commodity prices. Forward-looking statements and information are based on current beliefs as well as assumptions made by and information currently available to Berens concerning anticipated financial performance, business prospects, strategies and regulatory developments. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect. By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: crude oil and natural gas price volatility, exchange rate and interest rate fluctuations, availability of services and supplies, market competition, uncertainties in the estimates of reserves, the timing of development expenditures, production levels and the timing of achieving such levels, the Company's ability to replace and increase oil and gas reserves, the sources and adequacy of funding for capital investments, future growth prospects and current and expected financial requirements of the Company, the cost of future abandonment and site restoration, the Company's ability to enter into or renew leases, the Company's ability to secure adequate product transportation, changes in environmental and other regulations and general economic conditions. The forward-looking statements contained in this press release are made as of the date of this press release, and Berens does not undertake any obligation to up-date publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. This cautionary statement expressly qualifies the forward-looking statements contained in this press release. %SEDAR: 00020114E

For further information:

For further information: Dell P. Chapman, V.P. Finance & CFO, Ph: (403)
303-3267; Robert D. Steele, Chief Executive Officer, Ph: (403) 303-3264

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Berens Energy Ltd.

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