Berens Energy Ltd. releases results for the three and nine months ended September 30, 2007



    Symbol: BEN - TSX

    CALGARY, Nov. 7 /CNW/ -

    
    FINANCIAL AND OPERATING HIGHLIGHTS

    -------------------------------------------------------------------------
    ($ Cdn thousands,           Three months              Nine months
     except as noted)       ended September 30,       Ended September 30,
    -------------------------------------------------------------------------
                                             %                          %
                           2007     2006   Change     2007     2006   Change
    -------------------------------------------------------------------------
    Sales volume
      Natural gas
       (mcf/day)         18,288   17,355       5%   18,969   17,077      11%
      Oil and ngls
       (bbl/day)            570      479      19%      543      465      17%
      boe/day
       (6 to 1)           3,618    3,372       7%    3,705    3,311      12%
    -------------------------------------------------------------------------
    Revenue net of
     royalties           10,666    9,536      12%   35,089   28,905      21%
    Net income (loss)   (23,157)  (2,662)          (26,760)  (6,389)
      Per share (basic
       and diluted)      $(0.25)  $(0.03)       -   $(0.29)  $(0.07)     14%
    Funds from
     operations(1)        6,811    5,084      34%   21,563   16,352      32%
      Per share (basic
       and diluted)(1)    $0.07    $0.06      17%    $0.23    $0.19      21%
    -------------------------------------------------------------------------
    Capital costs
      Exploration and
       development        7,264   11,087     (34%)  29,462   40,763     (28%)
      Acquisition
       (disposition)     (6,750)  (1,764)           (6,750)  (1,764)
      Land and seismic    1,240      363      42%    3,396    4,396     (23%)
      Other                  37       60                52      708
    -------------------------------------------------------------------------
      Total               1,791    9,746            26,160   44,103
    -------------------------------------------------------------------------
    Net wells completed
     (No.)                    7        4                14       21
    -------------------------------------------------------------------------
    Net working capital
     (deficit) -
     including bank
     debt               (58,593) (60,182)          (58,593) (60,182)
    -------------------------------------------------------------------------
    Shares outstanding
      End of period
       (000's)           93,172   86,447       8%   93,172   86,447       8%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    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.

    Third Quarter 2007 Operating Highlights

    Berens is pleased to provide our third quarter results that show ongoing
drilling success, stable operating costs and increased cash flow:

    -   Drilling - Third quarter drilling continued to build on recent
        success.
           -  Pembina year-to-date drilling has continued to be successful.
              Our results continue to exceed our budgeted expectations with
              100% success on 11 wells to the end of October with estimated
              average well reserves of 1.4 bcf/well and six month average
              production rates of 800 mcf/d.
           -  In Lanfine, we drilled 5 successful wells out of 6 in July but
              chose to delay completion and tie in of the Lanfine wells
              awaiting stronger natural gas prices.
           -  With Pembina leading the way combined with our success in
              Lanfine and 100% successful first quarter Deep Basin drilling,
              we expect to exceed our originally budgeted reserve additions
              for 2007 with a capital program that has been reduced by 15%
              due to lower gas prices.
           -  Year to date we have drilled 28 wells with a success rate of
              86%.

    -   Production - Q3 2007 production averaged 3,618 boe/d, up 7% over
        Q3 2006. Production for the first nine months of 2007 averaged
        3,705 boe/d, up 12% compared to the first nine months of 2006. The Q3
        production volumes were affected by the following decisions and
        factors:
           -  normal production declines after low Q2 activities during
              spring break-up
           -  September 1, 2007 disposition of Marten Hills: -80 boe/d
           -  Postponement of Lanfine well completion and tie in activities
              to the end of October in anticipation of higher natural gas
              prices: -100 boe/d
           -  number of third party plant turn around events: -50 boe/d

        Our 2007 exit rate guidance remains at 3,900 boe/d with new
        production additions totaling approximately 750 boe/d coming on
        stream during Q4.

    -   Production Costs - Costs averaged $8.06 per boe in Q3 2007, up 1%
        compared to $7.95 per boe in Q3 2006. Prior quarter adjustments from
        third party processers accounted for $0.33 per boe of the third
        quarter production costs. For the nine months ended September 30,
        2007 costs averaged $7.67 per boe, down 4% compared to $7.95 per boe
        for the first nine months of 2006. Higher production levels and
        continued cost vigilance have kept production costs in check despite
        inflationary industry pressures.

    -   Funds from Operations - Funds from operations for Q3 2007 were
        $6.8 million ($0.07 per share), up 34% compared to Q3 2006 funds from
        operations of $5.1 million ($0.06 per share). Higher Q3 2007
        production, stable per unit operating costs, lower royalties and
        stronger commodity prices contributed to the increase. For the
        nine months ended September 30, 2007 funds from operations were
        $21.6 million ($0.23 per share), up 32% compared to $16.4 million
        ($0.19 per share) for the first nine months of 2006.

    -   Land - Berens' total undeveloped land currently stands at 98,000 net
        acres after the disposition of Marten Hills. All undeveloped lands
        are located in the core areas of Pembina, Deep Basin and Lanfine.
        Additionally, numerous down-spacing opportunities have been
        identified on developed acreage, particularly in the Pembina area.
        This land base sets up a diverse and high quality drilling program
        throughout 2008 and beyond.

    -   Royalty Review - Our preliminary assessment of the Alberta royalty
        changes suggests the effect on our longer term corporate cash flow
        and asset value will be minimal at current forecasted gas prices.
        Berens' Pembina and Deep Basin wells will benefit from the announced
        Deep Gas royalty rate reductions announced in the royalty changes
        beginning in 2009. We also believe we can be selective in our
        drilling and production management to minimize the new royalty
        effects on cash flow.
    

    Report from Management

    The third quarter of 2007 was highlighted by our return to drilling after
spring break-up with a focus to continue our success in Pembina and complete
our summer drilling program in Lanfine. Pembina drilling has continued to be
successful with 6 more consecutive successful wells drilled from July 1 to the
end of October 2007. In Lanfine, we drilled 5 successful wells out of 6 in
July but chose to delay completion and tie in of the Lanfine wells awaiting
stronger natural gas prices. Our results in Pembina continue to exceed our
budgeted expectations with 100% success on 11 wells to the end of October with
estimated average well reserves of 1.4 bcf/well and six month average
production rates of 800 mcf/d. With Pembina leading the way combined with our
success in Lanfine and 100% successful first quarter Deep Basin drilling, we
expect to exceed our originally budgeted reserve additions for 2007 with a
capital program that has been reduced by 15% due to lower gas prices. Year to
date we have drilled 28 wells with a success rate of 86%.
    Our production for the third quarter was 3,618 boe/d with over 750 boe/d
anticipated to come on stream during fourth quarter. The third quarter volumes
were reduced by the strategic sale of 250 boe/d in Marten Hills for
$6.75 million on September 1st as we high graded our asset and portfolio base.
In addition, completion and tie in of our 5 Lanfine wells was deferred to the
fourth quarter to take advantage of expected stronger gas prices late in the
year. This strategy has been successful as natural gas is trending above
$6.00/mcf as we tie in 300 boe/d of production in Lanfine in late October and
early November. Deep Basin production of over 250 boe/d is coming on stream in
early November, later than expected, from 3 wells drilled in prior quarters
that have been awaiting tie in due to limited plant capacity and surface and
weather access issues. In Pembina, we expect an additional 225 boe/d
production coming on stream in November and December as new wells are tied in.
We remain confident that we will meet our targeted December exit volumes of
3,900 boe/d which will result in over 10% production growth year over year
despite the disposition of 250 boe/d in September 2007.
    Our continued focus on improving costs continues to pay off as our new
well costs, particularly for drilling related activities, have dropped upwards
of 20% from a year ago. With our continued emphasis on cost improvements and
reduced industry activities we expect this trend to continue through the
balance of 2007 and into 2008. Reduced costs, combined with our strong
drilling results are resulting in competitive finding and development costs
year to date.
    We continue to proceed with our plans for first quarter 2008 and beyond.
We have evaluated the implications of the recently announced government
royalty changes on our cash flow and net asset value. Much of the future
growth for Berens is focused in the Pembina and Deep Basin areas where we are
successfully developing liquids rich tight gas reserves in the 2,000 to
2,700 metre depth range. These type of wells will benefit from the announced
Deep Gas royalty rate reductions announced in the Alberta royalty changes
beginning in 2009. Our preliminary assessment suggests the overall effect on
our long term corporate cash flow and asset value will be minimal at current
forecasted gas prices. We believe we can be selective in our drilling and
production management to minimize the new royalty affects on cash flow and
maximize value creation for our shareholders. As such, our plans for the
fourth quarter of 2007 and into 2008 remain relatively unchanged.
    Our recent drilling success, particularly in Pembina, is translating into
volume growth with accompanying reserves being added at continually improving
finding and development costs. Weak natural gas prices are a concern for our
industry, however we remain optimistic prices will improve as western Canadian
activity levels and supply volumes continue to drop. In the meantime, we are
continuing to high-grade and improve our gas dominant asset base with long
life production and reserves that will benefit from anticipated future gas
prices while keeping an attentive eye on transactions that would be accretive
to our shareholders.

    Sincerely,
    Daniel F. Botterill
    President and C.E.O.



    Berens Energy Ltd.
    Third Quarter 2007
    (unaudited)
    Management's Discussion and Analysis ("MD&A")
    November 6, 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 and the unaudited September 30, 2007
interim financial statements. This MD&A was prepared using information that is
current as of November 6, 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
                                                             2007
                                                 ----------------------------
    ($000's except as noted)                        Q3        Q2        Q1
    -------------------------------------------------------------------------
    Sales volumes:
      Natural gas (mcf/day)                       18,288    19,919    18,705
      Oil and natural gas liquids (bbl/day)          570       560       499
      Barrels of oil equivalent (bbl/day)          3,618     3,880     3,617
    -------------------------------------------------------------------------
    Financial:
      Net revenue                                 11,864    12,739    11,793
      Net (loss)                                 (23,157)     (557)   (3,043)
        per share - basic ($/share)               $(0.25)   $(0.00)   $(0.03)
        per share - diluted ($/share)             $(0.25)   $(0.00)   $(0.03)
      Capital costs                                8,541     6,208    18,329
      Shares outstanding (000's)                  93,172    93,172    92,947
      Bank debt                                   50,800    62,700    59,980
      Working capital (deficit) including
       bank debt                                 (58,593)  (63,610)  (67,468)
    -------------------------------------------------------------------------
    Per unit information:
      Natural gas price ($/mcf)                    $5.94     $7.60     $7.75
      Oil and liquids price ($/barrel)            $64.11    $58.98    $55.24
      Oil equivalent price ($/boe)                $40.14    $47.51    $47.72
      Operating netback ($/boe)                   $22.95    $27.88    $27.16
    -------------------------------------------------------------------------
    Net wells completed: (No.)
      Natural gas                                      5         1         5
      Oil                                              2         -         -
      Dry                                              1         -         1
    -------------------------------------------------------------------------
      Total                                            8         1         6
    -------------------------------------------------------------------------


                                                        2006
                                       --------------------------------------
    ($000's except as noted)              Q4        Q3        Q2        Q1
    -------------------------------------------------------------------------
    Sales volumes:
      Natural gas (mcf/day)             18,440    17,355    17,224    16,631
      Oil and natural gas liquids
       (bbl/day)                           483       479       494       420
      Barrels of oil equivalent
       (bbl/day)                         3,556     3,372     3,364     3,192
    -------------------------------------------------------------------------
    Financial:
      Net revenue                       11,213     9,536     9,846     9,523
      Net (loss)                       (21,951)   (2,662)   (1,606)   (2,121)
        per share - basic ($/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
                                       --------
    ($000's except as noted)               Q4
    Sales volumes:
      Natural gas (mcf/day)             11,537
      Oil and natural gas liquids
       (bbl/day)                           176
      Barrels of oil equivalent
       (bbl/day)                         2,099
    -------------------------------------------
    Financial:
      Net revenue                        9,537
      Net income (loss)                   (475)
        per share - basic ($/share)     $(0.01)
        per share - diluted ($/share)   $(0.01)
      Capital costs                     12,346
      Shares outstanding (000's)        57,163
      Bank debt                              -
      Working capital (deficit)
       including bank debt               4,273
    -------------------------------------------
    Per unit information:
      Natural gas price ($/mcf)         $11.26
      Oil and liquids price ($/barrel)  $41.92
      Oil equivalent price ($/boe)      $65.47
      Operating netback ($/boe)         $39.78
    -------------------------------------------
    Net wells completed: (No.)
      Natural gas                            9
      Oil                                    1
      Dry                                    2
    -------------------------------------------
      Total                                 12
    -------------------------------------------
    

    Steady volume increases were delivered throughout 2005 from ongoing
drilling activities in eastern Alberta. 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. Since the acquisition, ongoing drilling has delivered further production
increases to the end of the third quarter of 2007. The significant losses in
the fourth quarter of 2006 and the third quarter of 2007 were mainly due to a
non-cash write-down of goodwill. Commodity price fluctuations have been due to
normal market volatility. Commodity price hedging was put in place in 2007
reducing the Company's exposure to variability in commodity prices.

    RESULTS OF OPERATIONS

    Production Volume

    Production volume averaged 3,618 boe/d for the third quarter of 2007, up
seven percent compared to 3,374 boe/d in the third quarter of 2006 and down
seven percent compared to the second quarter of 2007. Natural gas represented
84 percent of production in the second quarter of 2007 with the remaining
production being 15 percent light oil and natural gas liquids and one percent
conventional heavy oil. Third quarter 2007 volumes were down from the second
quarter of 2007 due to:

    
    -   normal production declines after low activity during spring break-up
        in the second quarter of 2007
    -   100 boe/d due to the decision to delay Lanfine well completion and
        tie in activities to the end of October to take advantage of expected
        higher natural gas prices
    -   50 boe/d due to a number of third party plant turn around events
        during the second quarter
    -   80 boe/d due to the September 1, 2007 disposition of Marten Hills
    

    Volume averaged 3,705 boe/d for the first nine months of 2007, up
12 percent compared to 3,311 boe/d in the first nine months of 2006. The
expected 2007 exit rate of production is 3,900 boe/d with final quarter
natural decline being more than offset by 300 boe/d of production in Lanfine
connected in late October and early November, Deep Basin production of over
250 boe/d coming on stream in early November, and an additional 225 boe/d in
Pembina production coming on stream in November and December from drilling
activity. Nine (7.7 net) wells were drilled in the third quarter of 2007
resulting in 6 (4.7 net) natural gas wells and 2 (2 net) oil wells.
Twenty five (14.8 net) wells have been drilled in the first nine months of
2007 resulting in 19 (10.7 net) natural gas wells and 2 (2 net) oil wells for
an overall net success rate of 86 percent.

    Production Revenue

    Natural gas prices averaged $5.94 per mcf for the third quarter of 2007,
almost unchanged compared to $5.91 per mcf in the third quarter of 2006. Oil
and liquids prices averaged $64.43 and $63.96 per barrel respectively in the
third quarter of 2007 for a blended price of $64.11 per barrel, up three
percent from the third quarter 2006 blended oil and liquids price of
$62.07 per barrel. On a boe basis, prices averaged $40.14 in the third quarter
of 2007, up two percent compared to $39.24 per boe in the third quarter of
2006. Revenue was up 10 percent in the third quarter of 2007 compared to the
third quarter of 2006 as production volume increased and prices were up
slightly. An additional $3.59 per boe was realized from hedging gains during
the third quarter of 2007.
    Natural gas prices averaged $7.11 per mcf for the nine months ended
September 30, 2007, up 20 percent compared to $5.91 per mcf in the nine months
ended September 30, 2006. Oil and liquids prices averaged $57.37 and
$60.59 per barrel respectively in the nine months ended September 30, 2007 for
a blended price of $59.66 per barrel, down four percent from the nine months
ended September 30, 2006 blended oil and liquids price of $62.07 per barrel.
On a boe basis, prices averaged $45.15 in the nine months ended September 30,
2007, up 15 percent compared to $39.24 per boe in the nine months ended
September 30, 2006. Revenue was up 19 percent in the nine months ended
September 30, 2007 compared to the nine months ended September 30, 2006 as
both volume and prices increased. An additional $1.29 per boe was realized
from hedging gains during the nine months ended September 30, 2007.

    
    -------------------------------------------------------------------------
                                      Three months            Nine months
    Volumes and prices             ended September 30     ended September 30
    -------------------------------------------------------------------------
                                   2007    2006 Change    2007    2006 Change
    -------------------------------------------------------------------------
    Production revenue ($000's)  13,390  12,173   10%   45,718  38,424   19%
    -------------------------------------------------------------------------
    Production volume
      Natural gas (mcf/d)        18,288  17,355    5%   18,969  17,077   11%
      Oil and liquids (bbl/d)       570     479   19%      543     465   17%
      BOE (bbl/d)                 3,618   3,372    7%    3,705   3,311   12%
    Prices
    -------------------------------------------------------------------------
      Natural gas ($/mcf)          5.94    5.91    1%     7.11    5.91   20%
    -------------------------------------------------------------------------
      Oil and liquids ($/bbl)     64.11   62.07    3%    59.66   62.07   (4%)
    -------------------------------------------------------------------------
      BOE ($/boe)                 40.14   39.24    2%    45.15   39.24   15%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Royalties

    Royalties averaged 20 percent of revenue for the third quarter of 2007
compared to 23 percent in the third quarter of 2006. Lower royalties in the
third quarter of 2007 compared to the third quarter of 2006 are mainly due to
a fixed price natural gas sales contract at above the Q3 2007 market prices
that are used for royalty calculations. Royalties averaged 23 percent of
revenue for the nine months ended September 30, 2007 compared to 23 percent
for the nine months ended September 30, 2006.
    Royalty expense of $2.7 million was recorded in the third quarter of
2007, up three percent compared to the third quarter of 2006 reflecting higher
volume offset partially by lower per unit royalty rates. Royalty expense of
$10.6 million was recorded in the nine months ended September 30, 2007, up
12 percent compared to the nine months ended September 30, 2006 due to higher
production volume and higher commodity prices.
    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.

    
    -------------------------------------------------------------------------
                                      Three months            Nine months
    Royalties                      ended September 30     ended September 30
    -------------------------------------------------------------------------
                                   2007    2006 Change    2007    2006 Change
    -------------------------------------------------------------------------
    Royalty expense ($000'S)      2,724   2,637    3%   10,628   9,519   12%
    Royalty cost per boe          $8.19   $8.91   (8%)  $10.51   $8.91   18%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Production Expenses

    Production expenses were $8.06 per boe in the third quarter of 2007, up
one percent compared to $7.95 per boe in the third quarter of 2006. Third
quarter 2007 costs were increased by $110,000 ($0.33 per boe) of third party
processing fee adjustments from prior quarters. Higher production volume and
ongoing vigilance on costs have kept per unit costs stable. In addition, the
Company acquired an interest in a major Pembina processing plant in December
2006 which has reduced processing costs for natural gas produced in a portion
of the Pembina area. Production expenses were $7.67 per boe in the nine months
ended September 30, 2007, down four percent compared to $7.95 per boe in the
nine months ended September 30, 2006. With ongoing volume increases and cost
management, it is expected future per unit operating expenses will remain
below $8.00 per boe.
    Third quarter 2007 production expenses were $2.7 million, up nine percent
compared to the third quarter of 2006 due to higher volumes. Production
expenses for the nine months ended September 30, 2007 were $7.8 million, up
14 percent compared to the nine months ended September 30, 2006 mainly due to
higher volumes.

    
    -------------------------------------------------------------------------
                                      Three months            Nine months
    Production expenses            ended September 30     ended September 30
    -------------------------------------------------------------------------
                                   2007    2006 Change    2007    2006 Change
    -------------------------------------------------------------------------
    Production expenses ($000's)  2,684   2,465    9%    7,756   6,816   14%
    Production expenses per boe   $8.06   $7.95    1%    $7.67   $7.95   (4%)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Transportation costs increased $0.1 million, or 20 percent in the third
quarter of 2007 compared to the third quarter of 2006 due to higher volume and
higher per unit costs.

    Operating Netback(1)

    Operating netback represents the margin realized by the production and
sale of petroleum and natural gas. Third quarter 2007 operating netbacks
improved due to higher per boe prices and lower per unit royalty rates.

    -------------------------------------------------------------------------
    Quarterly Operating               Three months            Nine months
    Netbacks ($'s per boe)         ended September 30     ended September 30
    -------------------------------------------------------------------------
                                   2007    2006 Change    2007    2006 Change
    -------------------------------------------------------------------------
    Sales price                   40.14   39.24    2%    45.15   39.24   15%
    Less:
      Royalties (net of ARTC)      8.19    8.91   (8%)   10.51    8.91   18%
      Production expenses          8.06    7.95    1%     7.67    7.95   (4%)
      Transportation charges       0.94    0.84   12%     0.95    0.84   13%
    -------------------------------------------------------------------------
    Operating netback             22.95   21.54    7%    26.03   21.54   21%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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

    General and Administrative Expenses

    General and administrative ("G&A") expenses, including stock-based
compensation were $1.2 million in the third quarter of 2007, up 17 percent
compared to the third quarter of 2006. In the nine months ended September 30,
2007 G&A expenses were $3.7 million, down three percent compared to the
nine months ended September 30, 2006. Costs in 2007 compared to 2006,
benefited by general and administrative cost recoveries from partners on
capital projects operated by Berens. In 2006 a higher proportion of the
Company's capital activity was directed to 100 percent owned lands resulting
in less administrative cost recovery. On a per unit basis, general and
administrative costs were $3.72 per boe for the third quarter of 2007, up
10 percent compared to $3.39 per boe in the third quarter of 2006. In the
nine months ended September 30, 2007 per unit G&A costs were $3.66 per boe,
down 14 percent compared to $4.24 per boe for the nine months ended
September 30, 2006. There were no general and administrative costs capitalized
in the third quarter or for the first nine months of 2007 or 2006.
    Staff levels are expected to remain fairly constant for the remainder of
2007 and into 2008. Per unit general and administrative costs are expected to
decline as production levels increase.

    
    -------------------------------------------------------------------------
    General and                       Three months            Nine months
    administrative expenses        ended September 30     ended September 30
    -------------------------------------------------------------------------
                                   2007    2006 Change    2007    2006 Change
    -------------------------------------------------------------------------
    G&A expenses ($000's)         1,236   1,053   17%    3,698   3,829   (3%)
    G&A expenses per boe          $3.72   $3.39   10%    $3.66   $4.24  (14%)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Depletion, Amortization and Accretion

    Depletion, amortization and accretion ("DA&A") totaled $9.8 million
($29.55 per boe) in the third quarter of 2007, up 13 percent compared to
$8.7 million ($28.05 per boe) in the third quarter of 2006. Marten Hills sales
proceeds were lower than the booked value of the related assets sold causing
an increase in the per unit depletion rate for the quarter. In the nine months
ended September 30, 2007 DA&A totaled $29.8 million ($29.46 per boe), up
10 percent but two percent lower on a boe basis compared to $27.2 million
($30.06 per boe) in the nine months ended September 30, 2006. Drilling results
have improved in 2007 and new reserves have been added at lower per unit costs
compared to the first nine months of 2006 resulting in lower per unit
depletion rates.

    
    -------------------------------------------------------------------------
    Depletion, Amortization           Three months            Nine months
    and Accretion                  ended September 30     ended September 30
    -------------------------------------------------------------------------
                                   2007    2006 Change    2007    2006 Change
    -------------------------------------------------------------------------
    DA&A expenses ($000's)        9,835   8,701   13%   29,802  27,177   10%
    DA&A expenses per boe        $29.55  $28.05    5%   $29.46  $30.06   (2%)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Interest Expense

    Interest expense was $1.1 million in the third quarter of 2007 compared
to $0.9 million in the third quarter of 2006. In the nine months ended
September 30, 2007 interest expense was $3.1 million compared to $1.7 million
in the nine months ended September 30, 2006. Berens raised equity in the
fourth quarter of 2005 in anticipation of the acquisition of Berland and had a
significant cash position at the start of 2006. The subsequent closing of the
Berland acquisition in January 2006 resulted in significant borrowing on the
bank operating line as 30 percent of the Berland acquisition cost was in the
form of cash and Berens assumed Berland's debt and working capital deficiency,
totaling $28 million. Capital expenditures in 2006 and the first quarter of
2007 were higher than funds from operations resulting in higher average debt
levels in the 2007 periods compared to the same periods in 2006. The interest
rate on the bank line was also 1.25 percent higher in the nine months ended
September 30, 2007 compared to the nine months ended September 30, 2006.

    
    -------------------------------------------------------------------------
                                      Three months            Nine months
    Interest Expense               ended September 30     ended September 30
    -------------------------------------------------------------------------
                                   2007    2006 Change    2007    2006 Change
    -------------------------------------------------------------------------
    Interest expenses ($000's)    1,054     856   23%    3,079   1,655   86%
    Interest expenses per boe     $3.17   $2.76   15%    $3.04   $1.83   66%
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    Income Taxes

    The Company does not expect to pay current income tax during 2007 as
there are sufficient capital cost pools and expected future capital spending
to shelter taxable income. Current taxes were recorded for flow through share
taxes in the third quarter of 2007.
    Future tax recovery was $0.9 million for the third quarter of 2007
compared to a recovery of $1.2 million for the third quarter of 2006 as the
net loss before income taxes was lower in 2007 combined with lower income tax
rates in the 2007 period.

    NET LOSS

    The net loss for the third quarter of 2007 was $23.2 million ($0.25 per
share) compared to a loss of $2.7 million ($0.03 per share) in the third
quarter of 2006. The larger third quarter 2007 loss resulted primarily from
the impairment of goodwill offset by higher production volume and stable per
unit operating costs.
    The net loss for the nine months ended September 30, 2007 was
$26.8 million ($0.29 per share) compared to a net loss of $6.4 million ($0.07
per share) for the nine months ended September 30, 2006. The larger loss in
the nine months ended September 30, 2007 period was primarily due to the
impairment of goodwill.

    CAPITAL COSTS

    Capital costs were $8.5 million before accounting for the sale of Marten
Hills in the third quarter of 2007 compared to $11.5 million in the third
quarter of 2006. The Marten Hills assets were sold in the third quarter of
2007 for proceeds of $6.8 million, reducing the quarterly spending total to
$1.9 million. A seismic data base was sold in the third quarter of 2006 for
$1.8 million. In the nine months ended September 30, 2007 $32.9 million of
capital costs were incurred compared to $46.9 million in the nine months ended
September 30, 2006. The 2006 period reflects a very active capital program
following the acquisition of Berland Exploration in January 2006. A total of
25 wells (14.8 net) were drilled in the first nine months of 2007, compared to
37 wells (21.3 net) in the first nine months of 2006.

    
    -------------------------------------------------------------------------
                                         Three months         Nine months
    ($000's)                          ended September 30  ended September 30
    -------------------------------------------------------------------------
                                          2007      2006      2007      2006
    -------------------------------------------------------------------------
    Drilling and completion              6,786     7,694    21,336    31,011
    Equipping and tie-in                   478     3,393     8,126     9,752
    Land                                   750       284     1,376     1,967
    Geological and geophysical             490        81     2,020     2,429
    Office and other                        37        58        52       708
    -------------------------------------------------------------------------
    Total                                8,541    11,510    32,910    45,867
    Asset retirement obligation            127        60       298       319
    -------------------------------------------------------------------------
    Total exploration and development    8,668    11,570    33,208    46,185
    -------------------------------------------------------------------------
    Net acquisitions (dispositions)     (6,750)   (1,764)   (6,750)   (1,764)
    -------------------------------------------------------------------------
    Total capital                        1,918     9,806    26,458    44,421
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Drilling, completions and tie-in activity represented 85 percent of the
capital spent in the third quarter of 2007 and 90 percent of capital for the
nine months ended September 30, 2007 as capital activity focused on developing
the extensive land base. A $39 million capital budget will be spent in 2007,
over 90 percent of which is targeted toward drilling, completion and tie-in
activity. It is expected that capital spending for the remainder of the year
will be funded by cash flow provided by operating activities.

    WORKING CAPITAL

    Accounts receivable of $9.9 million at September 30, 2007 was primarily
revenue receivables ($4.5 million) and amounts owing from partners
($5.2 million). Accounts payable at September 30, 2007 of $20.8 million were
mainly comprised of trade payables for capital and operating costs ($7.7
million), royalties ($2.0 million), amounts owing to partners ($2.5 million),
unspent cash calls received from partners ($3.2 million) and capital costs
accrued at the end of the quarter for ongoing drilling and completion
operations ($3.1 million).
    Working capital excluding bank indebtedness was in a deficit position of
$7.8 million at September 30, 2007. Borrowings under the bank line and ongoing
cash flows are expected to fund the working capital deficit.

    LIQUIDITY AND CAPITAL RE

SOURCES The Company plans to fund its current working capital deficit, operations and capital costs with a mix of operating cash flow and debt financing through the bank operating line. An operating bank line was in place for $62.5 million, secured by producing properties at September 30, 2007. The line was reduced from $65.0 million during the third quarter of 2007 concurrent with the sale of the Marten Hills assets for proceeds of $6.75 million. At September 30, 2007, $50.8 million was drawn on the bank line. Future capital spending is planned at amounts that can be met with expected Company cash flow. GOODWILL IMPAIRMENT Goodwill, at the time of acquisition, represents the excess of purchase cost of a business over the fair value of net assets acquired. Thereafter, goodwill is not amortized and is assessed for impairment at least annually. If the estimated fair value of the business is less than the book value, a second test is performed to determine the amount of the impairment. Goodwill was originally recorded primarily on the Resolution Resources Ltd. acquisition (2003) and the Berland Exploration Ltd. acquisition (2006). The Company recorded a partial impairment of goodwill in the fourth quarter of 2006. Since that time oil and gas company valuations have eroded further, especially those of natural gas weighted producers primarily due to the decline in natural gas prices and high service costs in the industry. The Company tested the goodwill balance as at September 30, 2007 taking into account the decline in corporate economic value caused in 2007 by the decline in the share price. Recent oil and gas asset sales and corporate sale transactions were also benchmarked for the goodwill test. Based on the Company's assessment, it was determined that the fair value of the assets was less than the book value including the amount of goodwill that was being carried on the balance sheet. As a result, the Company recorded an impairment of goodwill for the remaining amount of the goodwill balance of $20.8 million. NON-GAAP MEASUREMENTS This MD&A contains the term "funds from operations" and "operating netback". As an indicator of the Company's performance, these terms should not be considered an alternative to, or more meaningful than "cash flow from operating activities" or "net income (loss)" as determined in accordance with Canadian generally accepted accounting principles. The Company's determination of funds from operations and operating netback may not be comparable to those reported by other companies, especially those in other industries. Management feels that funds from operations is a useful measure to help investors assess whether the Company is generating adequate cash amounts from its operations 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 September 30 is set below: ------------------------------------------------------------------------- Three months Nine months ($000's) ended September 30 ended September 30 ------------------------------------------------------------------------- 2007 2006 2007 2006 ------------------------------------------------------------------------- Cash flow provided by (used in) operating activities 15,893 4,194 26,730 8,611 Changes in non-cash working capital items related to operating activities (9,082) 890 (5,166) 7,741 ------------------------------------------------------------------------- Funds from operations 6,811 5,084 21,564 16,352 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Funds from operations are also presented on a per share basis consistent with the calculation of net loss per share, whereby per share amounts are calculated using the weighted average number of shares outstanding. Funds from operations per share were $0.07 (basic and diluted) for the third quarter of 2007 and $0.23 per share (basic and diluted) for the nine months ended September 30, 2007 compared to $0.06 per share for the third quarter of 2006 and $0.19 for the nine months ended September 30, 2006. RISKS Primary financial risks relate to volatility of commodity prices. Interest rate and currency exchange rate fluctuations also have an effect on financial results. The effect of changes in the exchange rate between US and Canadian currencies on natural gas prices is not direct, as variations between the regional markets for natural gas are often much greater than can be explained by currency variability. The Province of Alberta announced plans for significant royalty changes for both conventional oil and natural gas and oil sands operations beginning in 2009. The affect of the changes to the royalty structure in Alberta may cause significant measurement uncertainty for certain oil and natural gas assets as oil and gas assets are valued under the new royalty system using various commodity price scenarios. Other risks are related to operations. These risks include, but are not limited to, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, delays or changes in plans with respect to exploration or development projects or capital costs, volatility of commodity prices, currency fluctuations, the uncertainty of reserves estimates, potential environmental liabilities, technology risks, competition for services and personnel, incorrect assessment of the value of acquisitions and failure to realize the anticipated benefits of acquisitions. The foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect operations or financial results are included in a more detailed description of risks in Berens' Annual Information Form on file with Canadian securities regulatory authorities and available on SEDAR at www.sedar.com. Documented environmental health and safety plans are in place as well as a comprehensive emergency response plan to mitigate operating risks. COMMODITY PRICE RISK MANAGEMENT The Company may use financial derivative or fixed price contracts to manage its exposure to fluctuations in commodity prices and foreign currency exchange rates. The Company applies the fair value method of accounting for derivative instruments by initially recording an asset or liability, and recognizing changes in the fair value of the derivative instrument in income. The following is a summary of natural gas price risk management financial derivative contracts in effect as of September 30, 2007. 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 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 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 ------------------------------------------------------------------------- 2,000 April 1 to October 31, 2007 $7.25 floor; $8.25 cap ------------------------------------------------------------------------- 2,000 November 1, 2007 to March 31, 2008 $7.25 floor; $8.65 cap ------------------------------------------------------------------------- 2,000 June 1, 2007 to March 31, 2008 $7.50 floor; $9.45 cap ------------------------------------------------------------------------- The fair value of the above natural gas derivative instruments marked to market as at September 30, 2007, results in an unrealized gain position of $1,457,000 compared to an unrealized gain position of $635,000 at December 31, 2006. There was $1,198,000 of realized gains on derivative instruments in the third quarter of 2007 and $1,306,000 for the nine months ended September 30, 2007. There were no derivative instruments in place during the first quarter or the first nine months of 2006. A physical 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 is also in place for the purpose of reducing exposure to natural gas price volatility. The average floor price of the hedging transactions for 2007, including the fixed price sales contract, is $7.01 per GJ ($7.37 per mcf) with the average ceiling set at $8.75 per GJ ($9.21 per mcf). 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 first nine months of 2007 were nil. 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 third quarter of 2007 were $54,000 and $183,000 for the nine months ended September 30, 2007. SHARE DATA As of the date of this MD&A the Company had 93,172,064 issued and outstanding common shares. Additionally, options to purchase 6,241,533 common shares have been issued. DISCLOSURE CONTROLS AND PROCEDURES OVER FINANCIAL REPORTING The Company has established procedures and internal control systems designed to ensure timely and accurate preparation of financial, internal management and other reports. Disclosure controls and procedures are in place designed to ensure all ongoing statutory reporting requirements are met and material information is disclosed on a timely basis. The Chief Executive Officer and the Chief Financial Officer, individually, sign certifications that the financial statements, together with the other financial information included in the regulatory filings, fairly present in all material respects the financial condition, results of operation, and cash flows as of the dates and for the periods represented. INTERNAL CONTROL OVER FINANCIAL REPORTING Management of Berens is responsible for establishing and maintaining adequate internal controls over financial reporting. Internal controls over financial reporting are part of a process designed under the supervision of the Chief Executive Officer and the Chief Financial Officer and 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. The Company reported on these controls as part of its 2006 continuous disclosure requirements (please refer to the MD&A for the year ended December 31, 2006 available on SEDAR (www.SEDAR.com) and on our website (www.berensenergy.com). There have been no changes to internal controls over financial reporting or management's assessment of the design of these internal controls in the period since December 31, 2006. RISKS AND UNCERTAINTIES, CRITICAL ACCOUNTING ESTIMATES AND RECENT ACCOUNTING PRONOUNCEMENTS The MD&A is based on the consolidated financial statements, which have been prepared in Canadian dollars in accordance with GAAP. The application of GAAP requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates are based on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates under different assumptions or conditions. For a discussion of Risks and Uncertainties, Critical Accounting Estimates and Recent Accounting Pronouncements please refer to the audited financial statements and the Annual Information Form for the year ended December 31, 2006 available on SEDAR (www.SEDAR.com) and on our website (www.berensenergy.com). As of January 1, 2007, the Company adopted the Canadian Institute of Chartered Accountants ("CICA") Section 1530 "Comprehensive Income", Section 3251 "Equity", Section 3855 "Financial Instruments - Recognition and Measurement", and Section 3865 "Hedges", which were issued in January 2005. CICA handbook section 1506, "Accounting Changes" was also adopted on January 1, 2007. The adoption of these standards had no effect on the presentation of the financial statements. OUTLOOK Berens has demonstrated production growth, controlled costs and improved drilling success. Production growth has followed the drilling success experienced in late 2006 and throughout 2007. Production stalled in the third quarter of 2007 as management decided to delay tie ins in Lanfine and to sell the Marten Hills assets. During the first nine months of 2007 the net drilling success has been 86 percent and the average well result for reserves and production have exceeded expectation. There has also been some moderation in the industry cost structure. These factors are combining to lower the Company's finding and development costs in 2007. Capital spending for 2007 is projected at $39 million and will be aligned with cash flow for the remainder of the year. Net capital spending, after taking into account the sale of Marten Hills, is projected to be $32 million. Capital spending for the remainder of the year will be focused in Pembina where the reserve life of new wells is longest and the wells have the strongest economics. There are currently 75 inventoried drilling locations on existing lands. An active drilling program is planned for the first quarter of 2008 in Pembina and Deep Basin. Debt and working capital balances have improved and are at manageable levels with the planned capital spending plans. With ongoing production and reserve growth, management anticipates that the Company will be well positioned to develop our asset base once natural gas prices return to more acceptable levels. Berens Energy Ltd. Balance Sheets (unaudited) As at, ------------------------------------------------------------------------- September 30, December 31, (000's) 2007 2006 ------------------------------------------------------------------------- ASSETS (note 6) Current Cash and cash equivalents $ 1 $ 10 Accounts receivable 9,911 19,601 Unrealized gain on risk management (note 10) 1,457 635 Prepaid expenses and deposits 1,634 1,412 ------------------------------------------------------------------------- 13,003 21,658 Investments - 29 Property, plant and equipment (note 4) 168,076 171,178 Goodwill (note 11) - 20,755 ------------------------------------------------------------------------- $ 181,079 $ 213,620 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY Current Bank loan (note 6) $ 50,800 50,080 Accounts payable and accrued liabilities 20,787 $ 26,622 Taxes payable 10 29 ------------------------------------------------------------------------- 71,597 76,731 COMMITMENTS (note 10) Asset retirement obligations (note 5) 3,185 2,645 Future income taxes 12,440 14,518 ------------------------------------------------------------------------- 87,222 93,894 Shareholders' equity Capital stock (note 7) 148,263 148,038 Contributed surplus (note 7) 1,956 1,290 Deficit (56,362) (29,602) ------------------------------------------------------------------------- 93,857 119,726 ------------------------------------------------------------------------- $ 181,079 $ 213,620 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the financial statements Berens Energy Ltd. Statements of Operations and Deficit (unaudited) For the three and nine months ended September 30, ------------------------------------------------------------------------- Three months ended Nine months ended (000's) September 30, September 30, ------------------------------------------------------------------------- 2007 2006 2007 2006 ------------------------------------------------------------------------- Revenue Oil and natural gas revenue $ 13,390 $ 12,173 $ 45,718 $ 38,424 Realized gain on risk management (note 10) 1,198 - 1,306 - ------------------------------------------------------------------------- 14,588 12,173 47,024 38,424 Royalties, net of ARTC (2,724) (2,637) (10,628) (9,519) ------------------------------------------------------------------------- 11,864 9,536 36,396 28,905 Unrealized gain (loss) on risk management (note 10) (5) - 822 - ------------------------------------------------------------------------- 11,859 9,536 37,218 28,905 Other income 31 1 31 18 ------------------------------------------------------------------------- 11,890 9,537 37,249 28,923 ------------------------------------------------------------------------- Expenses Production 2,684 2,465 7,756 6,816 Transportation 313 261 961 814 Depletion, amortization and accretion 9,836 8,701 29,802 27,177 Impairment of goodwill (note 11) 20,755 - 20,755 - General and administrative (note 9) 1,003 849 3,032 3,247 Stock-based compensation (note 7) 233 204 666 582 Interest 1,054 856 3,079 1,655 ------------------------------------------------------------------------- 35,878 13,336 66,051 40,291 ------------------------------------------------------------------------- Loss before income taxes (23,988) (3,799) (28,802) (11,368) Income taxes Future expense (recovery) (861) (1,159) (2,077) (5,018) Current expense 30 22 35 39 ------------------------------------------------------------------------- (831) (1,137) (2,042) (4,979) ------------------------------------------------------------------------- Loss and Comprehensive Loss for the period (23,157) (2,662) (26,760) (6,389) Deficit, beginning of period (33,205) (4,989) (29,602) (1,262) ------------------------------------------------------------------------- Deficit, end of period $(56,362) $ (7,651) $(56,362) $ (7,651) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Loss per share (note 12) Basic and diluted $ (0.25) $ (0.03) $ (0.29) $ (0.08) ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the financial statements Berens Energy Ltd. Statements of Cash Flows (unaudited) For the three and nine months ended September 30, ------------------------------------------------------------------------- Three months ended Nine months ended (000's) September 30, September 30, ------------------------------------------------------------------------- 2007 2006 2007 2006 ------------------------------------------------------------------------- OPERATING ACTIVITIES Loss for the period $(23,157) $ (2,662) $(26,760) $ (6,389) Add items not involving cash Depletion, amortization and accretion 9,836 8,701 29,802 27,177 Impairment of goodwill 20,755 - 20,755 - Unrealized risk management (gain) loss 5 - (822) - Future income tax expense (recovery) (861) (1,159) (2,077) (5,018) Stock-based compensation 233 204 666 582 ------------------------------------------------------------------------- 6,811 5,084 21,564 16,352 Change in non-cash working capital items related to operating activities (note 8) 9,082 (890) 5,166 (7,741) ------------------------------------------------------------------------- Cash flow provided by (used in) operating activities 15,893 4,194 26,730 8,611 ------------------------------------------------------------------------- FINANCING ACTIVITIES Change in bank loan (11,900) 3,200 720 33,030 Proceeds from exercise of stock options - - 225 - Net proceeds from private offerings - - - 19,813 ------------------------------------------------------------------------- Cash flow provided by financing activities (11,900) 3,200 945 52,843 ------------------------------------------------------------------------- INVESTING ACTIVITIES Cash acquired through Berland acquisition - - - 109 Cash component on Berland acquisition - - - (28,682) Proceeds from sale of investment 3 245 29 245 Purchase of property and equipment (8,541) (11,510) (32,910) (45,867) Proceed from disposition of assets 6,750 1,764 6,750 1,764 Change in non-cash working capital items related to investing activities (note 8) (2,214) 2,116 (1,553) 1,550 ------------------------------------------------------------------------- Cash flow used in investing activities (4,002) (7,385) (27,684) (70,881) ------------------------------------------------------------------------- Decrease in cash and cash equivalents (9) 9 (9) (9,427) Cash and cash equivalents, beginning of period 10 35 10 9,471 ------------------------------------------------------------------------- Cash and cash equivalents, end of period $ 1 $ 44 $ 1 $ 44 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the financial statements BERENS ENERGY LTD. Notes to Financial Statements (unaudited) For the three and nine months ended September 30, 2007 and 2006 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. Significant capital spending activity occurs in the winter months in the western Canadian oil and natural gas business as many areas are only accessible or best accessed in the winter months when the ground is frozen. Limited capital spending activity tends to occur in the second calendar quarter as the industry experiences "spring break- up" when there is significant water on the ground due to melting snow and roads capacities are limited as winter frost melts and the roads are wet and unable to support heavy loads. Normal oil and gas operations tend to return in the June time frame each year. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The interim financial statements have been prepared by management following the same accounting policies as the most recent annual audited financial statements except as noted below. Certain disclosures, which are normally required to be included in notes to the annual financial statements, are condensed or omitted for interim reporting purposes. Accordingly, these interim financial statements should be read in conjunction with the audited annual financial statements for the year ended December 31, 2006. Certain prior period amounts have been reclassified to conform to current disclosure. As of January 1, 2007, the Company was 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 (loss), 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 Sheet and measured, in most cases, at fair values, and requirements for hedge accounting have been further clarified. The Company has adopted these pronouncements. The Company uses fair value accounting for derivative instruments that do not qualify or are not designated as hedges. As of January 1, 2007, the Company was 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 they are not practical 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 effect of adopting these standards on the Company's financial statements has been negligible. 3. 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. 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 ------------------------------------------------------------------------- 4. PROPERTY, PLANT AND EQUIPMENT September 30, 2007 December 31, 2006 Accumulated Accumulated depletion and depletion and ($000's) Cost depreciation Cost depreciation ------------------------------------------------------------------------- Petroleum and natural gas properties 266,452 98,781 240,047 69,305 Office and computer equipment 730 325 678 242 ------------------------------------------------------------------------- 267,182 99,106 240,725 69,547 ------------------------------------------------------------------------- Net book value 168,076 171,178 ------------------------------------------------------------------------- At September 30, 2007, costs of $22,033,000 (2006 - $25,907,000) related to undeveloped land have been excluded from the depletion and depreciation calculation. At September 30, 2007 estimated future development costs of $13,018,000 have been included in the depletion and depreciation calculation. A ceiling test was completed at September 30, 2007 resulting in no impairment. 5. ASSET RETIREMENT OBLIGATIONS The total future asset retirement obligations were estimated based on the net ownership interest in all wells and facilities, estimated costs to reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred in future periods. The estimated net present value of the total asset retirement obligations is $3,185,000 as at September 30, 2007 (2006 - $2,431,000) based on a total future liability of $8,512,000 (2006 - $5,204,000). 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 following table reconciles the asset retirement obligations for the nine months ended: September 30, September 30, ($000's) 2007 2006 ------------------------------------------------------------------------- Obligation, beginning of the period 2,645 1,223 Increase in obligation during the period 297 318 Obligation assumed from Berland acquisition - 715 Accretion expense 243 175 ------------------------------------------------------------------------- Obligation, end of the period 3,185 2,431 ------------------------------------------------------------------------- 6. BANK OPERATING LINE An agreement with a Canadian bank is in place for an operating bank line totaling $62.5 million at September 30, 2007. 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 September 30, 2007 was 7.00 percent (September 30, 2006 - 6.5 percent). On September 30, 2007, $50,800,000 was drawn on the line (December 31, 2006 - $50,080,000). 7. CAPITAL STOCK (a) Authorized Capital The authorized capital consists of an unlimited number of preferred shares issuable in series and an unlimited number of common shares without nominal or par value. (b) Common shares issued ------------------------------------------------------------------------- Consideration Number ($000's) ------------------------------------------------------------------------- Balance March 31, 2007 and December 31, 2006 92,947,064 148,038 Exercise of stock options 225,000 225 ------------------------------------------------------------------------- Balance June 30, 2007 and September 30, 2007 93,172,064 148,263 ------------------------------------------------------------------------- (c) Stock Option Plan A stock option plan is in place under which 7,500,000 common shares have been reserved for options to be granted to directors, officers, employees and consultants with terms established by the board of directors. Options granted under the plan generally have a five year term to expiry and vest equally over a three year period commencing on the first anniversary date of the grant. The exercise price of each option equals the closing market price of the Company's common shares on the day prior to the date of the grant. The following table sets forth a reconciliation of the plan activity during the nine months ended September 30, 2007 2006 Weighted Weighted average average exercise exercise Number of price ($ Number of price ($ Options per share) Options per share) ------------------------------------------------------------------------- Outstanding, January 1, 4,416,200 1.68 3,513,700 1.56 Granted 2,309,500 0.94 885,000 2.16 Cancelled (259,167) 1.98 (7,500) 2.90 Exercised (225,000) 1.00 - - ------------------------------------------------------------------------- Outstanding, end of period 6,241,533 1.42 4,391,200 1.69 ------------------------------------------------------------------------- Exercisable 2,740,696 1.44 1,975,692 1.15 ------------------------------------------------------------------------- The following table sets forth additional information relating to the stock options outstanding at September 30, 2007. Options Outstanding Exercisable Options ------------------------------------------------------------------------- Weighted Weighted average average exercise Weighted exercise Weighted price average price average Exercise price Number of ($ per years to Number of ($ per years to range Options share) expiry Options share) expiry ------------------------------------------------------------------------- $0.50 to $1.39 4,053,500 1.00 3.19 1,537,995 1.07 1.25 ------------------------------------------------------------------------- $1.40 to $2.29 1,127,200 1.54 2.30 846,867 1.51 1.83 ------------------------------------------------------------------------- $2.30 to $3.19 920,833 2.83 3.24 309,167 2.83 3.24 ------------------------------------------------------------------------- $3.20 to $4.09 140,000 3.24 3.32 46,667 3.24 3.32 ------------------------------------------------------------------------- 6,241,533 1.42 3.04 2,740,696 1.44 1.69 ------------------------------------------------------------------------- The fair value method for measuring option awards based on the Black Scholes valuation model is used. Key assumptions used for the Black Scholes based valuation of options are: Risk free rate - 4.3 percent; average expected life - 4.5 years; no expected dividend yield; 46 percent volatility. Estimated future forfeiture assumptions are not used in calculations and forfeitures are recognized as they occur. The weighted average option price for options outstanding at September 30, 2007 is $0.57 per option. Based on the fair value method, $233,000 was recorded as compensation expense for the quarter ended September 30, 2007 and $666,000 was recorded as compensation expense for the nine months ended September 30, 2007 (2006 - $204,000 and $582,000) with corresponding increases recorded to contributed surplus. (d) Contributed Surplus The following table sets forth the continuity of contributed surplus for the three and nine months ended September 30, ($000's) Three months Nine months ------------------------------------------------------------------------- Opening balance, beginning of period 1,723 1,290 Stock based compensation expense 233 666 ------------------------------------------------------------------------- Closing balance, September 30, 2007 1,956 1,956 ------------------------------------------------------------------------- 8. SUPPLEMENTAL CASH FLOW INFORMATION Changes in Non-cash Working Capital For the nine months ended September 30, ($000's) 2007 2006 ------------------------------------------------------------------------- Accounts receivable 9,690 (5,513) Prepaid expenses and deposits (222) (1,755) Accounts payable and accrued liabilities (5,836) 9,580 Taxes payable (19) (65) Non-cash working capital acquired (note 3) - (8,438) ------------------------------------------------------------------------- 3,613 (6,191) Change in non-cash working capital related to investing activities (1,553) 1,550 ------------------------------------------------------------------------- Change in non-cash working capital related to operating activities 5,166 (7,741) ------------------------------------------------------------------------- Cash interest and taxes paid For the three and nine months ended September 30, Three Three Nine Nine months months months months ($000's) 2007 2006 2007 2006 ------------------------------------------------------------------------- Income and other taxes 27 - 27 117 Interest 1,054 856 3,079 1,655 ------------------------------------------------------------------------- 9. 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 first nine months of 2007 were nil (2006 - $90,000). 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 third quarter of 2007 were $54,000 and $183,000 for the nine months ended September 30, 2007 (2006 - $36,000 and $532,000). 10. FINANCIAL INSTRUMENTS Fair Value of Financial Instruments Financial instruments recognized on the balance sheets consist of cash and cash equivalents, accounts receivable, deposits, accounts payable, bank loans and financial derivatives used to manage natural gas price risk. Cash, cash equivalents and financial derivatives are designated as "held- for-trading". Deposits are designated as "held-to-maturity". Accounts receivable and bank loans are designated as "loans and receivables" and accounts payable are designated as "other liabilities". 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 usually "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. Commodity price risk management transactions are denominated in Canadian dollars which mitigates the effect of currency volatility on commodity sales volumes that are covered by commodity price hedges. (d) Commodity Price Risk Management The following is a summary of natural gas price risk management derivative contracts in effect as of September 30, 2007. All contracts are priced in Canadian dollars per gigajoule (GJ) and are designated as "held-for-trading." The price per GJ can be converted to an approximate price per mcf by multiplying the per GJ price by 1.05. GJ volume can be converted to an approximate mcf volume by multiplying the GJ volume by 0.95. ------------------------------------------------------------------------- Daily quantity (GJ) Term of Contract Fixed price per gigajoule ------------------------------------------------------------------------- 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 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 ------------------------------------------------------------------------- 2,000 April 1 to October 31, 2007 $7.25 floor; $8.25 cap ------------------------------------------------------------------------- 2,000 November 1, 2007 to March 31, 2008 $7.25 floor; $8.65 cap ------------------------------------------------------------------------- 2,000 June 1, 2007 to March 31, 2008 $7.50 floor; $9.45 cap ------------------------------------------------------------------------- The fair value of the above natural gas derivative instruments marked-to- market as at September 30, 2007, results in an unrealized gain of $1,457,000 compared to an unrealized gain of $635,000 at December 31, 2006. There were $1,198,000 in realized gains from derivative instruments in the quarter ended September 30, 2007 and $1,306,000 in realized gains for the nine months ended September 30, 2007. There were no derivative instruments outstanding for the third quarter or first nine months of 2006. 11. GOODWILL The Company tested the goodwill balance as at September 30, 2007 taking into account the decline in corporate economic value caused by the 2007 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 for the remaining amount of the goodwill balance of $20,755,000. 12. PER SHARE INFORMATION The weighted average number of common shares outstanding for the quarter ended September 30, 2007 of 93,172,064 was used to calculate basic and diluted loss per share (2006 - 86,447,064). The weighted average number of common shares outstanding for the nine month period ended September 30, 2007 was 93,031,771 (2006 - 84,516,269). Outstanding options have been excluded in the calculation of per share information as they were anti-dilutive. 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, Berens
Energy Ltd., Ph: (403) 303-3267; Daniel F. Botterill, President & Chief
Executive Officer, Berens Energy Ltd., Ph: (403) 303-3262

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Berens Energy Ltd.

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