Berens Energy Ltd. releases financial results for the three and six months ended June 30, 2008



    Symbol:  BEN - TSX

    CALGARY, Aug. 13 /CNW/ -

    
                     FINANCIAL AND OPERATING HIGHLIGHTS

    -------------------------------------------------------------------------
    ($ Cdn thousands,                 Three months           Six months
     except as noted)                ended June 30,        ended June 30,
    -------------------------------------------------------------------------
                                             %                          %
                          2008      2007   Change     2008      2007  Change
    -------------------------------------------------------------------------
    Sales volume
      Natural gas
       (mcf/day)        19,677    19,919     (1%)   19,390    19,315       -
      Oil and ngls
       (bbl/day)           859       560     53%       744       530     40%
    -------------------------------------------------------------------------
      boe/day (6 to 1)   4,139     3,880      7%     3,975     3,749      6%
    -------------------------------------------------------------------------
    Revenue net of
     royalties          20,738    12,643     64%    35,255    24,423     44%
    -------------------------------------------------------------------------
    Net (loss)          (1,612)     (557)  (189%)   (7,026)   (3,603)   (95%)
      Per share (basic
       and diluted)     $(0.02)   $(0.01)           $(0.08)   $(0.04)
    -------------------------------------------------------------------------
    Funds from
     operations(1)      12,570     7,782     62%    21,839    14,752     48%
      Per share (basic
       and diluted)(1)   $0.13     $0.08             $0.23     $0.16
    -------------------------------------------------------------------------
    Capital costs
      Exploration and
       development       1,696     5,120    (67%)   11,865    22,198    (46%)
      Land and seismic   1,015     1,085     (6%)    2,429     2,155     13%
      Other                  4         3     25%         7        15    (53%)
    -------------------------------------------------------------------------
    Total                2,715     6,208    (56%)   14,301    24,368    (41%)
    -------------------------------------------------------------------------
    Net wells completed
     (No.)                   -         1                 5         7
    -------------------------------------------------------------------------
    Net working capital
     deficit - excluding
     unrealized hedging
     losses            (51,766)  (65,073)   (20%)  (51,766)  (65,073)   (20%)
    -------------------------------------------------------------------------
    Net working capital
     deficit - including
     unrealized hedging
     losses            (63,942)  (63,610)     1%   (64,942)  (63,610)     2%
    -------------------------------------------------------------------------
    Shares outstanding
      End of period
       (000's)          93,547    93,172       -    93,547    93,172       -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    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.



    Second Quarter 2008 Operating Highlights

    Berens is pleased to provide our second quarter results that demonstrate
record cash flows due to increased production volume from successful first
quarter drilling and strong commodity prices:

    -   Capital Budget - The 2008 capital budget has been increased from $30
        million to $40 million.  The increase reflects higher cash flow
        delivered by increased production volume and stronger commodity
        prices.  The additional capital combined with strong drilling results
        to date is expected to increase the expected exit production rate to
        approximately 4,400 boe/d with strong momentum established entering
        2009 as most of the additional capital will be spent in the final
        four months of 2008.

    -   Production - Q2 2008 production averaged 4,139 boe/d, up 7% over Q2
        2007 and up 9% over Q1 2008 as strong drilling results in the first
        quarter of 2008 resulted in significant new production coming on
        stream early in the second quarter.  This increase in production has
        been delivered while decreasing debt and working capital balances
        over $13 million or 20 percent since June 30, 2007.

    -   Production Costs - Costs averaged $7.68 per boe in Q2 2008 with costs
        for the first six months of 2008 averaging $7.98 per boe, up 6%
        compared to the first six months of 2007.  We expect operating costs
        to be in the $7.50 range for the remainder of the year.

    -   Funds from Operations - Funds from operations for Q2 2008 were a
        record $12.6 million ($0.13 per share), up 62% compared to Q2 2007
        funds from operations of $7.8 million ($0.08 per share).  Higher
        production, stronger commodity prices and stable per unit operating
        costs contributed to the increase.  For the quarter ended June 30,
        2008, the ratio of debt and working capital to annualized funds from
        operation was 1.0 times.

    -   Land - Berens' total undeveloped land currently stands at 87,000 net
        acres.  The undeveloped land base has increased in quality as 20
        (11.7 net) sections of undeveloped land has been added in Pembina,
        our key growth area, while reductions occurred due to drilling
        activity and expiries primarily in Lanfine and non-core areas.  We
        continue to have approximately 100 locations in our drilling
        inventory.
    

    Message to the shareholders

    We at Berens are pleased to deliver to our shareholders continued strong
production growth, a significantly improved balance sheet and continued
control on costs. The strong operating results have now been combined with
stronger commodity prices and as a consequence, we are increasing our drilling
activity for balance of the year. We have achieved this by maintaining our
disciplined business focus on value creation.
    We delivered average production in the second quarter of 2008 of
4,139 boe/d which is 7% above a year ago while reducing debt by $13 MM or 20%.
Second quarter production is also 9% above our Q1 2008 figure of 3,812 boe/d
and is primarily attributed to our strong drilling results in the first
quarter. Third quarter production is expected to stay relatively flat as
second quarter activity was limited due to spring breakup but increases are
expected again for fourth quarter.
    Drilling activity was minimal in the second quarter, however we have been
very active since mid June and to date have drilled an additional 9 wells,
7 wells in Lanfine, with 6 (5.8 net) wells being successful and 2 (net 1.1)
wells in Pembina, both successful. In Pembina this continues our string of
successful wells at 34. These wells will come on stream throughout third
quarter and will provide our production growth for fourth quarter. Through the
remainder of third and fourth quarters, we expect to drill 1 well in Deep
Basin and as many as 10 more wells in Pembina. Two of the Pembina wells will
be horizontal wells using new multi-frac completion technologies and we look
forward to the additional prospects that these horizontal wells provide to our
drilling inventory.
    Capital expenditures are on target to the end of second quarter and with
our strong production results and improved commodity prices, our cash flows
are much stronger. This has allowed us to significantly improve our balance
sheet and increase our capital spending for the second half of the year. Our
2008 budget has been increased to $40 million from $30 million with the
increase in spending targeted for Pembina in the third and fourth quarters.
The increase in spending along with our solid production results to date is
expected to increase our average fourth quarter production rate to
approximately 4,400 boe/d. In addition, as much of the increase in spending
will occur in the final months of the year, we expect strong production
momentum heading into 2009.
    We continue to exploit our competitive advantage in our core areas based
on intensive integration of technology, geology and geophysics which has
reduced our risks. We are confident in our ability to repeat our 2007 finding
and development costs of $13.00 /boe in 2008. As well, drilling, completion
and operating costs remain under control and will be an ongoing focus area for
our team as industry activity increases.
    We are pleased with our results, continue to stay focused on value
creation, and are looking forward as we step up our activity levels to
generate increased shareholder value.

    
    Sincerely,
    Daniel F. Botterill
    President & Chief Executive Officer


    Berens Energy Ltd.
    Second Quarter 2008
    Management's Discussion and Analysis ("MD&A")
    August 12, 2008
    

    OVERVIEW

    Berens Energy Ltd. ("Berens" or the "Company") is a full cycle oil and
natural gas exploration and production company with a concentrated production
and land base in the Eastern Alberta, Pembina and Deep Basin regions of
Alberta.
    All calculations converting natural gas to crude oil equivalent have been
made using a ratio of six thousand cubic feet (six "mcf") of natural gas to
one barrel of crude equivalent. Barrels of oil equivalent ("boe") may be
misleading, particularly if used in isolation. A boe conversion ratio of six
mcf of natural gas to one barrel of crude oil equivalent is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.
    The following discussion of financial position and results of operations
should be read in conjunction with the Company's December 31, 2007 audited
financial statements and notes thereto and the unaudited June 30, 2008 interim
financial statements and notes thereto. This MD&A was prepared using
information that is current as of August 12, 2008 unless otherwise noted.

    STRATEGY AND OBJECTIVES

    The 2008 $40 million capital program is funded by cash flow based on an
assumed natural gas price of $8.50 per mcf for the remainder of 2008. This
program is expected to generate 2008 exit production rates of 4,400 to
4,500 boe/d, about 16 percent higher than the fourth quarter 2007 average.

    Longer term value is achieved by adding oil and natural gas reserves at
low cost. The Company expects to replace 2008 production 1.5 times with new
reserves at finding and development costs below $15.00/boe. Operating and
corporate netbacks are expected to be $35.00 per boe and $28.00 per boe
respectively assuming a $8.50 per mcf price for natural gas and $100.00 per
barrel for oil. Resulting recycle ratios based on the above factors are
expected to be over 2.3 times on an operating netback basis and 1.9 times
based on the corporate netback. Both of these measures will deliver long term
added value.

    FORWARD LOOKING INFORMATION

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

    
    QUARTERLY INFORMATION

                                                                  2008
                                                          -------------------
    ($000's except as noted)                                   Q2         Q1
    -------------------------------------------------------------------------
    Sales volumes:
      Natural gas (mcf/day)                                19,677     19,104
      Oil and natural gas liquids (bbl/day)                   859        628
      Barrels of oil equivalent (bbl/day)                   4,139      3,812
    -------------------------------------------------------------------------
    Financial:
      Net revenue                                          20,738     14,517
      Net (loss)                                           (1,612)    (5,413)
        per share - basic ($/share)                        $(0.02)    $(0.06)
        per share - diluted ($/share)                      $(0.02)    $(0.06)
    Capital costs                                           2,715     11,586
    Shares outstanding (000's)                             93,547     93,172
    Bank debt                                              53,000     58,500
    Working capital (deficit)
     including bank debt                                  (64,942)   (69,711)
    -------------------------------------------------------------------------
    Per unit information:
      Natural gas price ($/mcf)                            $10.55      $8.12
      Oil and liquids price ($/barrel)                    $103.76     $81.76
      Oil equivalent price ($/boe)                         $71.70     $54.16
      Operating netback ($/boe)                            $46.31     $32.36
    -------------------------------------------------------------------------
    Net wells completed: (No.)
      Natural gas                                               -          5
      Oil                                                       -          -
      Dry                                                       -          -
    -------------------------------------------------------------------------
      Total                                                     -          5
    -------------------------------------------------------------------------



                                                        2007
                                    -----------------------------------------
    ($000's except as noted)             Q4         Q3         Q2         Q1
    -------------------------------------------------------------------------
    Sales volumes:
      Natural gas (mcf/day)          19,018     18,288     19,919     18,705
      Oil and natural gas liquids
       (bbl/day)                        626        570        560        499
      Barrels of oil equivalent
       (bbl/day)                      3,796      3,618      3,880      3,617
    -------------------------------------------------------------------------
    Financial:
      Net revenue                    13,214     11,864     12,739     11,793
      Net (loss)                       (680)   (23,157)      (557)    (3,043)
        per share - basic
         ($/share)                   $(0.01)    $(0.25)    $(0.00)    $(0.03)
        per share - diluted
         ($/share)                   $(0.01)    $(0.25)    $(0.00)    $(0.03)
      Capital costs                   6,718      8,541      6,208     18,329
      Shares outstanding (000's)     93,172     93,172     93,172     92,947
      Bank debt                      53,900     50,800     62,700     59,980
      Working capital (deficit)
       including bank debt          (59,516)   (59,300)   (64,644)   (68,502)
    -------------------------------------------------------------------------
    Per unit information:
      Natural gas price ($/mcf)       $6.52      $5.94      $7.60      $7.75
      Oil and liquids price
       ($/barrel)                    $71.66     $64.11     $58.98     $55.24
      Oil equivalent price ($/boe)   $44.48     $40.14     $47.51     $47.72
      Operating netback ($/boe)      $26.85     $22.95     $27.88     $27.16
    -------------------------------------------------------------------------
    Net wells completed: (No.)
      Natural gas                         3          5          1          5
      Oil                                 -          2          -          -
      Dry                                 -          1          -          1
    -------------------------------------------------------------------------
      Total                               3          8          1          6
    -------------------------------------------------------------------------



                                            2006
                                    -------------------
    ($000's except as noted)             Q4         Q3
    ---------------------------------------------------
    Sales volumes:
      Natural gas (mcf/day)          18,440     17,355
      Oil and natural gas liquids
       (bbl/day)                        483        479
      Barrels of oil equivalent
       (bbl/day)                      3,556      3,372
    ---------------------------------------------------
    Financial:
      Net revenue                    11,213      9,536
      Net (loss)                    (21,951)    (2,662)
        per share - basic
         ($/share)                   $(0.24)    $(0.03)
        per share - diluted
         ($/share)                   $(0.24)    $(0.03)
      Capital costs                  12,811      9,746
      Shares outstanding (000's)     92,947     86,447
      Bank debt                      50,080     52,780
      Working capital (deficit)
       including bank debt          (56,271)   (61,783)
    ---------------------------------------------------
    Per unit information:
      Natural gas price ($/mcf)       $7.13      $5.91
      Oil and liquids price
       ($/barrel)                    $51.54     $62.07
      Oil equivalent price ($/boe)   $43.96     $39.24
      Operating netback ($/boe)      $24.24     $21.54
    ---------------------------------------------------
    Net wells completed: (No.)
      Natural gas                         7          3
      Oil                                 -          -
      Dry                                 1          1
    ---------------------------------------------------
    Total                                 8          4
    ---------------------------------------------------
    

    Ongoing drilling has delivered the production increases for the past
eight quarters with the decline in production for the third quarter of 2007
due to the disposition of Marten Hills production of 250 boe per day. There
have been no other material acquisitions or dispositions during the last eight
quarters.

    RESULTS OF OPERATIONS

    Production Volume

    Volume averaged 4,139 boe/d for the quarter ended June 30, 2008, up seven
percent compared to 3,880 boe/d for the quarter ended June 30, 2007 and up
nine percent from the first quarter of 2008. Natural gas represented
79 percent of production in the second quarter of 2008 with the remaining
production being 20 percent light oil and natural gas liquids and one percent
conventional heavy oil. The majority of production additions have been from
liquids rich natural gas wells in Pembina which has increased the ratio of oil
and liquids in the production mix. For the six months ended June 30, 2008
volume averaged 3,975 boe/d, up six percent over the six months ended June
30, 2007.
    High drilling success rates, primarily in Pembina were experienced in the
first quarter of 2008 and significant production brought on stream late in the
first quarter which contributed to the higher production levels in the second
quarter of 2008. A total of nine wells (4.7 net) were completed in the first
quarter with six successful (3.8 net) natural gas wells in Pembina and two
(0.5 net) successful natural gas wells in Deep Basin with one (0.4 net)
unsuccessful well in Deep Basin. Drilling commenced very late in the second
quarter due to spring break-up conditions in all core areas.

    Production Revenue

    Natural gas prices averaged $10.55 per mcf for the quarter ended June
30, 2008, up 39 percent compared to $7.60 per mcf in the quarter ended
June 30, 2007. Oil and liquids prices averaged $115.13 and $99.77 per barrel
respectively for the quarter ended June 30, 2008 for a blended price of
$103.76 per barrel, up 76 percent from the quarter ended June 30, 2007 blended
oil and liquids price of $58.98 per barrel. On a boe basis prices averaged
$71.70 per boe in the quarter ended June 30, 2008, up 51 percent compared to
$47.51 per boe in the quarter ended June 30, 2007. Oil and natural gas revenue
was up 61 percent in the quarter ended June 30, 2008 compared to the quarter
ended June 30, 2007 as both volume and prices increased. Realized hedging
losses during the second quarter of 2008 were $6.91 per boe compared to
realized hedging gains of $0.27 per boe in the second quarter of 2007.
    For the six months ended June 30, 2008, natural gas prices averaged
$9.35 per mcf up 22 percent compared to $7.67 per mcf in the six months ended
June 30, 2007. Combined oil and liquids prices averaged $94.47 per barrel for
the six months ended June 30, 2008, up 65 percent from the six months ended
June 30, 2007 blended oil and liquids price of $57.22 per barrel. On a boe
basis prices averaged $63.29 per boe in the six months ended June 30, 2008, up
33 percent compared to $47.61 per boe in the six months ended June 30, 2007.
Oil and natural gas revenue was up 42 percent for the six months ended June
30, 2008 compared to the six months ended June 30, 2007 as both volume and
prices increased. Realized hedging losses during the six months ended June
30, 2008 were $3.81 per boe compared to realized hedging gains of
$0.14 per boe in the six months ended June 30, 2007.

    
    -------------------------------------------------------------------------
    Volumes and prices           Three months                Six months
                                ended June 30,              ended June 30,
    -------------------------------------------------------------------------
                          2008      2007   Change     2008      2007  Change
    -------------------------------------------------------------------------
    Production revenue
     ($000's)           27,008    16,784     61%    45,801    32,327     42%
    -------------------------------------------------------------------------
    Production volume
      Natural gas
       (mcf/d)          19,677    19,919     (1%)   19,390    19,315      -
      Oil and liquids
       (bbl/d)             859       560     53%       744       530     40%
      BOE (bbl/d)        4,139     3,880      7%     3,975     3,749      6%
    Prices
    -------------------------------------------------------------------------
      Natural gas
       ($/mcf)           10.55      7.60     39%      9.35      7.67     22%
    -------------------------------------------------------------------------
      Oil and liquids
       ($/bbl)          103.76     58.98     76%     94.47     57.22     65%
    -------------------------------------------------------------------------
      BOE ($/boe)        71.70     47.51     51%     63.29     47.61     33%
    -------------------------------------------------------------------------
      BOE ($/boe
       including
       hedging)          64.79     47.78     36%     59.48     48.00     24%
    -------------------------------------------------------------------------
    

    Royalties

    Royalties averaged 23 percent of revenue for the quarter and six months
ended June 30, 2008 compared to 24 percent for the quarter and six months
ended June 30, 2007. Royalties have trended lower on a percent of revenue
basis as more wells are drilled on owned and earned lands compared to earlier
periods when a higher percentage of wells were drilled under farm-in
arrangements that provided for overriding royalties to the farmor.
    Royalty expense of $6.3 million was recorded in the quarter ended June
30, 2008, up 51 percent compared to the quarter ended June 30, 2007 due to
higher production volume and revenue offset by lower percentage royalty rates.
For the six months ended June 30, 2008 royalty expense was $10.5 million, up
33 percent compared to the six months ended June 30, 2007 again, due to higher
production volume and revenue.

    
    -------------------------------------------------------------------------
    Royalties                    Three months                Six months
                                ended June 30,              ended June 30,
    -------------------------------------------------------------------------
                          2008      2007  Change      2008      2007  Change
    -------------------------------------------------------------------------
    Royalty expense
     ($000's)            6,270     4,140     51%    10,546     7,904     33%
    Royalty cost per
     boe                $16.65    $11.73     42%    $14.58    $11.65     25%
    Royalty cost as a
     percent of revenue    23%       24%     (4%)      23%       24%     (4%)
    -------------------------------------------------------------------------
    

    Production Expenses

    Production expenses were $7.68 per boe in the quarter ended June
30, 2008, up 12 percent compared to $6.87 per boe in the quarter ended June
30, 2007. For the six months ended June 30, 2008 production expenses were
$7.98 per boe, up seven percent compared to the six months ended June
30, 2007. Costs in 2008 have been higher due to ongoing inflationary pressures
in the industry and vigilance on costs remains a key objective. With ongoing
volume increases and cost management, it is expected per unit operating
expenses will be in the $7.50 per boe range for the remainder of the year.
    Production expenses for the quarter ended June 30, 2008 were
$2.9 million, up 19 percent compared to the quarter ended June 30, 2007 due to
higher volumes and higher per unit costs. For the six months ended June
30, 2008 production expenses were $5.8 million, up 14 percent due to higher
production and higher per unit costs.

    
    -------------------------------------------------------------------------
    Production expenses          Three months                Six months
                                ended June 30,              ended June 30,
    -------------------------------------------------------------------------
                          2008      2007  Change      2008      2007  Change
    -------------------------------------------------------------------------
    Production expenses
     ($000's)            2,894     2,426     19%     5,774     5,072     14%
    Production expenses
     per boe             $7.68     $6.87     12%     $7.98     $7.47      7%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Transportation costs increased 10 percent in the quarter ended June 30,
2008 compared to the quarter ended June 30, 2007 due to higher volume and
higher per unit costs due to increased transportation rates on major natural
gas trunk pipelines.

    Operating Netback(1)

    Operating netback represents the margin realized by the production and
sale of petroleum and natural gas exclusive of results from hedging. Second
quarter 2008 operating netbacks improved due to higher per boe prices, lower
percentage royalty costs and stable operating costs.

    -------------------------------------------------------------------------
    Quarterly Operating
    Netbacks                     Three months                Six months
    ($'s per boe)               ended June 30,              ended June 30,
    -------------------------------------------------------------------------
                          2008      2007  Change      2008      2007  Change
    -------------------------------------------------------------------------
    Sales price          71.70     47.51     51%     63.29     47.61     33%
    Less:
      Royalties          16.65     11.73     42%     14.58     11.65     25%
      Production
       expenses           7.68      6.87     12%      7.98      7.47      7%
      Transportation
       charges            1.06      1.03      3%      1.11      0.95     17%
    -------------------------------------------------------------------------
    Operating netback    46.31     27.88     66%     39.62     27.53     44%
    -------------------------------------------------------------------------
    Operating netback
     including hedging   39.40     27.47     43%     35.81     27.34     31%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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

    General and Administrative Expenses

    For the quarter ended June 30, 2008 general and administrative ("G&A")
expenses including stock based compensation were $2.0 million, up 48 percent
compared to the quarter ended June 30, 2007. G&A charged to partners on
capital spending during the second quarter of 2008 was lower than in the
second quarter of 2007 as the total level of capital spending was lower in the
2008 period and wells were being drilled at higher average working interests.
During the second quarter of 2008 certain stock option holders of expiring
options elected to be paid in cash compensation for the difference between the
exercise price and market price of their options which increased G&A for the
quarter by $124,000. Stock based compensation was significantly higher in the
second quarter of 2008 compared to the second quarter of 2007 as certain
employees elected to relinquish high priced stock options which accelerated
the amortization of the compensation cost for the remaining unvested term of
the relinquished options. This resulted in a one time charge to stock based
compensation of $247,000 in the second quarter of 2008.
    On a per unit basis, for the quarter ended June 30, 2008 per unit cash
G&A costs excluding stock based compensation were $3.95 per boe, up 27 percent
from $3.10 per boe for the quarter ended June 30, 2007 as volume increases
partially offset the dollar increase in costs for the per unit calculation.
Including stock based compensation, per unit costs were $5.21 per boe for the
quarter ended June 30, 2008, up 39% compared to $3.75 for the quarter ended
June 30, 2007. There were no general and administrative costs capitalized for
the quarters ended June 30, 2008 or 2007.
    For the six months ended June 30, 2008 G&A costs including stock based
compensation were $3.4 million, up 37 percent compared to the six months ended
June 30, 2007 due to lower capital recoveries, option payouts and higher stock
based compensation charges described above. On a per unit basis, for the six
months ended June 30, 2008 per unit cash G&A costs excluding stock based
compensation were $3.73 per boe, up 25 percent from $2.99 per boe for the six
months ended June 30, 2007 as volume increases partially offset the dollar
increase in costs for the per unit calculation.
    Staff levels are expected to remain fairly constant in 2008. Without the
one-time charges experienced in the second quarter, per unit general and
administrative costs are expected to return to similar levels as in 2007.

    
    -------------------------------------------------------------------------
    General and administrative   Three months                Six months
    expenses                    ended June 30,              ended June 30,
    -------------------------------------------------------------------------
                          2008      2007  Change      2008      2007  Change
    -------------------------------------------------------------------------
    G&A expenses
     ($000's)            1,487     1,095     36%     2,686     2,028     32%
    G&A expense per boe  $3.95     $3.10     27%     $3.73     $2.99     25%

    Stock based
     compensation
     ($000's)              474       230    106%       693       433     60%
    Stock based
     compensation
     per boe             $1.26     $0.65     93%     $0.96     $0.64     50%
    -------------------------------------------------------------------------
    Total                1,961     1,325     48%     3,379     2,461     37%
    G&A expenses per
     boe                 $5.21     $3.75     39%     $4.69     $3.63     29%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Interest Expense

    For the quarter ended June 30, 2008 interest expense was $0.8 million or
29 percent lower compared to $1.1 million for the quarter ended June 30, 2007.
Average amounts drawn on the bank operating line in the first quarter of 2008
were lower than in the first quarter of 2007 as Marten Hills assets were sold
for $6.75 million in the third quarter of 2007 and capital spending has been
below cash flow for the first six months of 2008. Average interest rates have
been lower in the 2008 period compared to 2007. In addition the borrowing
premium charged by the bank declines as the debt to cash flow ratio improves
resulting in a 0.4 percent reduction in borrowing cost as the debt to cash
flow ratio has declined.
    For the six months ended June 30, 2008 interest expense was $1.7 million
or 18 percent lower compared to $2.0 million for the six months ended
June 30, 2007 for the same reasons described above.

    
    -------------------------------------------------------------------------
    Interest expense             Three months                Six months
                                ended June 30,              ended June 30,
    -------------------------------------------------------------------------
                          2008      2007  Change      2008      2007  Change
    -------------------------------------------------------------------------
    Interest expense
     ($000's)              763     1,070    (29%)    1,662     2,025    (18%)
    Interest expense
     per boe             $2.03     $3.03    (33%)    $2.31     $2.98    (22%)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Depletion, Amortization and Accretion

    In the quarter ended June 30, 2008 Depletion, Amortization and Accretion
("DA&A") totaled $10.0 million ($26.56 per boe) down six percent compared to
$10.6 million ($30.09 per boe) for the quarter ended June 30, 2007. The per
unit depletion rate declined 12 percent comparing the second quarter of 2008
to the second quarter of 2007 as ongoing drilling success and low cost reserve
additions have brought down per unit DA&A rates throughout 2007 and 2008. This
per unit reduction has more than offset the increase in DA&A charge due to
higher production volume. For the six months ended June 30, 2008 DA&A totaled
$18.9 million ($26.32 per boe), down five percent and down 11 percent on a per
unit basis from $20.0 million ($29.42 per boe) for the six months ended
June 30, 2007.

    
    -------------------------------------------------------------------------
    Depletion, Amortization      Three months                Six months
    and Accretion               ended June 30,              ended June 30,
    -------------------------------------------------------------------------
                          2008      2007  Change      2008      2007  Change
    -------------------------------------------------------------------------
    DA&A expense
     ($000's)           10,005    10,623     (6%)   18,933    19,967     (5%)
    DA&A expense per
     boe                $26.56    $30.09    (12%)   $26.32    $29.42    (11%)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Income Taxes

    The Company does not expect to pay current income tax during 2008 as
there are sufficient capital cost pools and expected future capital spending
to shelter taxable income.

    NET LOSS

    The net loss for the quarter ended June 30, 2008 was $1.6 million
($0.02 per share) compared to a net loss of $0.6 million ($0.01 per share) for
the quarter ended June 30, 2007 as higher production volume and commodity
prices were offset primarily by unrealized hedging losses recorded in the
quarter. Adjusting for the after tax amount of the unrealized loss on risk
management activities of $4.6 million in the second quarter of 2008, net
income was $1.6 million. For the six months ended June 30, 2008 the net loss
was $7.0 million or $0.08 per share compared to a loss of $3.6 million or
$0.04 per share for the six months ended June 30, 2007. Again, adjusting for
the after tax unrealized hedging loss recorded in the first six months of
2008, net income was $1.6 million.

    CAPITAL COSTS

    For the quarter ended June 30, 2008 $2.7 million in capital costs on
exploration and production activities were incurred compared to $6.2 million
for the quarter ended June 30, 2007. No wells were drilled in the second
quarter of 2008 until very late in the quarter as spring break-up extended
well into June this year. For the six months ended June 30, 2008 total
spending was $14.3 million compared to $24.4 million in the first six months
of 2007. Five net wells were completed in the first six months of 2008
compared to seven net wells completed in the first six months of 2007. In
addition, significant decreases in drilling costs have been realized in the
2008 period as operations have improved with full time staff dedicated to the
drilling program and a general easing in industry cost pressures.

    
    -------------------------------------------------------------------------
                                           Three months         Six months
    ($000's)                               ended June 30,      ended June 30,
    -------------------------------------------------------------------------
                                          2008      2007      2008      2007
    -------------------------------------------------------------------------
    Drilling and completion              1,638     2,756     9,322    14,550
    Equipping and tie-ins                   58     2,364     2,543     7,647
    Land                                   264       519     1,605       626
    Geological and geophysical             751       566       824     1,530
    Office and other                         4         3         7        15
    -------------------------------------------------------------------------
    Total                                2,715     6,208    14,301    24,368
    Asset retirement obligation             39         3       392       171
    -------------------------------------------------------------------------
    Total capital                        2,754     6,211    14,693    24,539
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Drilling, completion, equip and tie-in activity represented 83 percent of
the capital spent in the first six months of 2008 as capital activity focused
on developing the extensive land base. A $40 million capital budget is planned
for 2008, 92 percent of which is targeted toward drilling, completion, equip
and tie-in activity. It is expected that 2008 capital spending will be funded
by cash flow provided by operating activities.

    WORKING CAPITAL

    Accounts receivable of $14.0 million at June 30, 2008 were primarily
revenue receivables ($9.1 million) and amounts owing from partners
($4.2 million). Accounts payable at June 30, 2008 of $13.3 million were mainly
comprised of trade payables for capital and operating costs ($5.8 million),
royalties ($2.2 million), amounts owing to partners ($1.1 million) and capital
costs accrued at the end of the quarter for ongoing drilling and completion
operations ($1.3 million).
    Working capital excluding bank indebtedness and the unrealized loss on
risk management activities was in a surplus position of $1.2 million at
June 30, 2008.

    LIQUIDITY AND CAPITAL RE

SOURCES The Company plans to fund its current working capital, 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 $66 million at June 30, 2008, secured by producing properties. At June 30, 2008, $53.0 million was drawn on the bank line. Future capital spending is planned in amounts that can be met with expected Company cash flow and its borrowing capacity within the bank line limit. NON-GAAP MEASUREMENTS This MD&A contains the term "funds from operations" and "operating netback". As an indicator of the Company's performance, these terms should not be considered an alternative to, or more meaningful than "cash flow from operating activities" or "net income (loss)" as determined in accordance with Canadian generally accepted accounting principles. The Company's determination of funds from operations and operating netback may not be comparable to those reported by other companies, especially those in other industries. Management feels that funds from operations is a useful measure to help investors assess whether the Company is generating adequate cash amounts from its operations for its ongoing operations and planned capital program. Operating netback is a useful measure for comparing the Company's price realization and cost performance against industry competitors. The reconciliation between net income and funds from operations for the periods ended March 31 is as follows: ------------------------------------------------------------------------- Three months Six months ($000's) ended June 30, ended June 30, ------------------------------------------------------------------------- 2008 2007 2008 2007 ------------------------------------------------------------------------- Cash flow provided by operating activities 9,228 3,184 14,908 10,836 Changes in non-cash working capital items related to operating activities 3,342 4,598 6,931 3,916 ------------------------------------------------------------------------- Funds from operations 12,570 7,782 21,839 14,752 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 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 $0.13 per share (basic and diluted) for the quarter ended June 30, 2008 compared to $0.08 for the quarter ended June 30, 2007 as funds from operations increased with higher volume and commodity prices and only 375,000 shares were issued in the past year for stock options exercised. For the six months ended June 30, 2008 funds from operations per share were $0.23 per share compared to $0.16 per share for the six months ended June 30, 2007. 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 as direct, as variations between the regional markets for natural gas are often much greater than can be explained entirely by currency variability. The Province of Alberta has announced plans for royalty changes for both conventional oil and natural gas and oil sands operations beginning in 2009. The effect of the changes to the royalty structure in Alberta may cause measurement uncertainty for certain oil and natural gas assets as oil and gas assets are valued under the new royalty system using various commodity price scenarios. The Company entered into an interest rate swap transaction in January 2008 to fix the interest rate on $25.0 million of its variable rate demand bank line. The transaction fixes the interest rate for a two year period at a rate of 4.86 percent including the Company's borrowing margin on its bank line. The fair value of the interest rate derivative instrument marked-to- market as at June 30, 2008 resulted in an unrealized loss of $43,000 as interest rates have declined since the time the interest rate swap was transacted. There were no interest rate derivatives in place in 2007. 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 and crude oil price risk management financial derivative contracts in effect as of the date of this MD&A. All natural gas contracts are priced in Canadian dollars per gigajoule (GJ). The price per GJ can be converted to an approximate price per MCF by multiplying the per GJ price by 1.05. GJ can be converted to an approximate MCF volume by multiplying the GJ volume by 0.95. ------------------------------------------------------------------------- NATURAL GAS HEDGING ------------------------------------------------------------------------- Daily quantity (GJ) Term of contract Fixed price per gigajoule ------------------------------------------------------------------------- 2,000 January 1 to December 31, 2008 $6.65 fixed price ------------------------------------------------------------------------- 2,000 April 1 2008 to March 31, 2009 $6.72 fixed price ------------------------------------------------------------------------- 2,000 April 1 to December 31, 2008 $6.65 fixed price ------------------------------------------------------------------------- 2,000 April 1 to December 31, 2008 $6.80 fixed price ------------------------------------------------------------------------- 2,000 April 1 to October 31, 2008 $6.80 fixed price ------------------------------------------------------------------------- 2,000 April 1 to October 31, 2008 $7.45 fixed price ------------------------------------------------------------------------- ------------------------------------------------------------------------- CRUDE OIL HEDGING ------------------------------------------------------------------------- Daily quantity Fixed price per barrel (bbl) Term of contract (US WTI translated to C$) ------------------------------------------------------------------------- 100 January 1 to December 31, 2008 $85.00 floor; $93.30 cap ------------------------------------------------------------------------- 100 January 1 to December 31, 2008 $85.00 floor; $98.10 cap ------------------------------------------------------------------------- The fair value of the above natural gas derivative instruments marked to market as at June 30, 2008, results in an unrealized loss position of $12,133,000 compared to an unrealized gain position of $162,000 at December 31, 2007 as crude oil and natural gas prices have increased significantly since December 31, 2007. There was $2,741,000 ($6.91 per boe) of realized losses on derivative instruments for the quarter ended June 30, 2008 (2007 - $95,000 gain). For the six months ended June 30, 2008 $2,601,000 ($3.81 per boe) in realized losses on derivative instruments were recorded (2007 - $108,000 gain). The average fixed price of the natural gas hedging transactions for the remainder of 2008 is $6.82 per GJ ($7.18 per mcf) which will provide protection to corporate cash flow if natural gas prices fall below these levels. The average floor price for the oil hedges is $85.00 per barrel. Absent the above-noted risk management contracts, the effects of changes in commodity prices on cash flow before working capital changes are summarized in the following table. ------------------------------------------------------------------------- Commodity Price change Cash flow change ($ 000's) ------------------------------------------------------------------------- Natural gas ($/mcf) 1.00 $5,900 ------------------------------------------------------------------------- Oil and liquids ($/bbl) 10.00 $1,600 ------------------------------------------------------------------------- RELATED PARTY TRANSACTIONS Fees for legal services are paid to a law firm in which the corporate secretary is a partner. The legal services are rendered in the normal course of business at normal rates charged by the law firm. Legal fees for this firm paid for the quarter ended June 30, 2008 were $105,000 (2007 - $98,000). SHARE DATA As of the date of this MD&A the Company had 93,547,064 issued and outstanding common shares. Additionally, as at August 12, 2008 options to purchase 6,119,700 common shares have been issued. DISCLOSURE CONTROLS AND PROCEDURES OVER FINANCIAL REPORTING The Company has established procedures and internal control systems designed to ensure timely and accurate preparation of financial, internal management and other reports. Disclosure controls and procedures are in place designed to ensure all ongoing statutory reporting requirements are met and material information is disclosed on a timely basis. The Chief Executive Officer and the Chief Financial Officer, individually, sign certifications that the financial statements, together with the other financial information included in the regulatory filings, fairly present in all material respects the financial condition, results of operation, and cash flows as of the dates and for the periods represented. INTERNAL CONTROL OVER FINANCIAL REPORTING Management of Berens is responsible for establishing and maintaining adequate internal controls over financial reporting. Internal controls over financial reporting are part of a process designed under the supervision of the Chief Executive Officer and the Chief Financial Officer and monitored by the Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles ("GAAP"). The Company reported on these controls as part of its 2007 continuous disclosure requirements (please refer to the MD&A for the year ended December 31, 2007 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, 2007. RISKS AND UNCERTAINTIES, CRITICAL ACCOUNTING ESTIMATES AND RECENT ACCOUNTING PRONOUNCEMENTS The MD&A is based on the consolidated financial statements, which have been prepared in Canadian dollars in accordance with GAAP. The application of GAAP requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates are based on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates under different assumptions or conditions. CHANGES IN ACCOUNTING POLICIES Financial instruments presentation and disclosure Effective January 1, 2008, the Company adopted the new Canadian Instutute of Chartered Accountants (CICA) recommendations relating to Financial Instruments - Disclosure (section 3862) and Financial Instruments - Presentation (section 3863). The new disclosure required by section 3862 concerning the nature and extent of the risks associated with financial instruments and how those risks are managed, is presented in note 11. Effective January 1, 2008 the company adopted CICA recommendations relating to Capital Disclolsures (section 1535). As permitted, comparative information for the disclosure required by section 3862 has not been provided. Inventories Effective January 1, 2008 new CICA recommendations relating to Inventories (section 3031) came into effect. The new standard provides additional guidance concerning measurement, classification and disclosure and allows the reversal of write-downs to net realizable value when there is a change in the circumstances giving rise to the impairment. The Company had adopted these recommendations for the December 31, 2007 financial statements which resulted in a re-classification of certain inventory to property, plant and equipment. At March 31, 2008 $872,000 of inventory was re-classified to property, plant and equipment. International Financial Reporting Standards In February 2008, the Canadian Accounting Standards Board confirmed that the use of International Financial Reporting Standards ("IFRS") will be required in 2011 for publicly accountable profit-oriented enterprises. IFRS will replace Canada's current GAAP for listed companies and other profit-oriented enterprises that are responsible to large or diverse groups of stakeholders. Companies will be required to provide one year of comparative date in accordance with IFRS. In the second quarter of 2008 the Company began to develop its IFRS changeover plan. Initial activities include training sessions and acquisition of written standards and examples of IFRS disclosure to identify where key differences between Canadian GAAP and IFRS will exist. The Company intends to disclose its convergence plan and qualitative effects of IFRS on its financial statements as they become more fully developed. 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, 2007 available on SEDAR (www.SEDAR.com) and on our website (www.berensenergy.com). OUTLOOK Drilling success experienced throughout 2007 and the first quarter of 2008 has resulted in steady increases to production volume and cash flows. The strong cash flows have resulted in an improved balance sheet and the ability to increase the 2008 capital spending program to $40 million from the original budget of $30 million. The increase in capital spending is expected to remain within cash flow for the year and debt levels are expected to remain well below 1.5 times cash flow. The increase in the capital spending budget will be focused in Pembina where the reserve life of new wells is longest and the wells have the strongest economics. The Company currently has 100 inventoried drilling locations on existing lands with the majority of these locations in Pembina. Seven wells have been drilled in Lanfine and two in Pembina since the end of the second quarter with success rates that mirror our recent quarters. As many as 10 more wells are planned for Pembina by the end of 2008 with one additional well in Deep Basin before the end of the year. Debt and working capital balances have improved and will continue to improve with the planned capital spending plans. Based on second quarter results on an annualized basis, debt and working capital (excluding the unrealized loss on risk management) represents 1.0 times funds from operations. With an extensive land base, a large number of inventoried drilling locations and an increased capital budget, management looks forward to developing our asset base more aggressively in the second half of 2008. Berens Energy Ltd. Balance Sheets - unaudited As at, ------------------------------------------------------------------------- (000's) June 30, December 31, 2008 2007 ------------------------------------------------------------------------- ASSETS (note 6) Current Cash and cash equivalents $ 1 $ 1 Accounts receivable 14,021 10,315 Unrealized gain on risk management (note 10) - 162 Prepaid expenses and deposits 557 442 ------------------------------------------------------------------------- 14,579 10,920 Property, plant and equipment (note 4) 162,347 166,405 ------------------------------------------------------------------------- $ 176,926 $ 177,325 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY Current Bank loan (note 7) $ 53,000 $ 53,900 Accounts payable and accrued liabilities 13,335 16,523 Unrealized loss on risk management (note 10) 12,176 - Taxes payable 10 14 ------------------------------------------------------------------------- 78,521 70,437 Asset retirement obligations (note 5) 3,848 3,273 Future income taxes 7,098 10,199 ------------------------------------------------------------------------- 89,467 83,909 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Shareholders' equity Capital stock (note 7) 148,638 148,263 Contributed surplus (note 7) 2,888 2,195 Deficit (64,067) (57,042) ------------------------------------------------------------------------- 87,459 93,416 ------------------------------------------------------------------------- $176,926 $177,325 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the unaudited interim financial statements Berens Energy Ltd. Statements of Operations, Comprehensive Loss and Deficit - unaudited ------------------------------------------------------------------------- (000's) Three months Six months ended June 30, ended June 30, ------------------------------------------------------------------------- 2008 2007 2008 2007 ------------------------------------------------------------------------- Revenue Oil and natural gas revenue $ 27,008 $ 16,784 $ 45,801 $ 32,327 Royalties (6,270) (4,140) (10,546) (7,904) ------------------------------------------------------------------------- 20,738 12,644 35,255 24,423 Realized gain (loss) on commodity price risk management (note 10) (2,741) 95 (2,601) 108 ------------------------------------------------------------------------- 17,997 12,739 32,654 24,531 Unrealized gain (loss) on commodity price risk management (note 10) (4,602) 2,035 (12,295) 828 Other income 119 119 ------------------------------------------------------------------------- 13,514 14,774 20,478 25,359 ------------------------------------------------------------------------- Expenses Production 2,894 2,426 5,774 5,073 Transportation 399 363 806 648 Depletion, amortization and accretion 10,005 10,623 18,933 19,967 General and administrative (note 9) 1,487 1,095 2,686 2,028 Stock-based compensation (note 7) 474 230 693 433 Interest 763 1,070 1,662 2,025 Unrealized loss (gain) on interest rate risk management (note 10) (141) - 43 - ------------------------------------------------------------------------- 15,881 15,807 30,597 30,174 ------------------------------------------------------------------------- Loss before income taxes (2,367) (1,033) (10,119) (4,815) Income taxes Future recovery (758) (479) (3,100) (1,217) Current expense 3 3 7 5 ------------------------------------------------------------------------- (755) (476) (3,093) (1,212) ------------------------------------------------------------------------- Net loss and comprehensive loss for the period (1,612) (557) (7,026) (3,603) Deficit, beginning of period (62,455) (32,648) (57,041) (29,602) ------------------------------------------------------------------------- Deficit, end of period $ (64,067) $(33,205) $(64,067) $(33,205) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net loss per share (note 11) Basic and diluted $ (0.02) $ (0.01) $ (0.08) $ (0.04) ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the unaudited interim financial statements Berens Energy Ltd. Statements of Cash Flows - unaudited ------------------------------------------------------------------------- (000's) Three months Six months ended June 30, ended June 30, ------------------------------------------------------------------------- 2008 2007 2008 2007 ------------------------------------------------------------------------- OPERATING ACTIVITIES Net loss for the quarter $ (1,612) $ (557) $ (7,026) $ (3,603) Add items not involving cash Depletion, amortization and accretion 10,005 10,623 18,933 19,967 Unrealized risk management loss 4,461 (2,035) 12,339 (828) Future income tax recovery (758) (479) (3,100) (1,217) Stock-based compensation 474 230 693 433 ------------------------------------------------------------------------- 12,570 7,782 21,839 14,752 Change in non-cash working capital items related to operating activities (note 8) (3,342) (4,598) (6,931) (3,916) ------------------------------------------------------------------------- Cash flow provided by operating activities 9,228 3,184 14,908 10,836 ------------------------------------------------------------------------- FINANCING ACTIVITIES Change in bank loan (5,500) 2,720 (900) 12,620 Proceeds from exercise of stock options 375 225 375 225 ------------------------------------------------------------------------- Cash flow provided by financing activities (5,125) 2,945 (525) 12,845 ------------------------------------------------------------------------- INVESTING ACTIVITIES Purchase of property and equipment (2,715) (6,208) (14,302) (24,368) Proceeds from sale of investment - 26 - 26 Change in non-cash working capital items related to investing activities (note 8) (1,389) 53 (81) 661 ------------------------------------------------------------------------- Cash flow used in investing activities (4,104) (6,129) (14,383) (23,681) ------------------------------------------------------------------------- Increase in cash and cash equivalents (1) - - - Cash and cash equivalents, beginning of period 2 10 1 10 ------------------------------------------------------------------------- Cash and cash equivalents, end of period $ 1 $ 10 $ 1 $ 10 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the unaudited interim financial statements BERENS ENERGY LTD. Notes to Financial Statements - unaudited Three and six months ended June 30, 2008 and 2007 1. NATURE OF OPERATIONS Berens Energy Ltd. (the "Company") is a full cycle oil and natural gas exploration and production company with activities encompassing land acquisition, geological and geophysical assessment, drilling and completion, and production. The primary areas of operation are in eastern and west central Alberta. 2. SEASONALITY 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 road 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 June each year. 3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles ("GAAP"). The nature of the business and timely preparation of financial statements requires that management make estimates and assumptions, and use judgment regarding assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, actual results may differ from estimated amounts. In the opinion of management, these financial statements have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting policies summarized below. 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, 2007. Certain prior period amounts have been reclassified to conform to current disclosure. The financial statements have been prepared following the same accounting policies and methods of computation as the Annual Financial Statements for the year ended December 31, 2007. a) CHANGES IN ACCOUNTING POLICIES Financial instruments presentation and disclosure Effective January 1, 2008, the Company adopted the new Canadian Institute of Chartered Accountants (CICA) recommendations relating to Financial Instruments - Disclosure (section 3862) and Financial Instruments - Presentation (section 3863). The new disclosure required by section 3862 concerning the nature and extent of the risks associated with financial instruments and how those risks are managed, is presented in note 11. Effective January 1, 2008 the company adopted CICA recommendations relating to Capital Disclosures (section 1535). As permitted, comparative information for the disclosure required by section 3862 has not been provided. Inventories Effective January 1, 2008 new CICA recommendations relating to Inventories (section 3031) came into effect. The new standard provides additional guidance concerning measurement, classification and disclosure and allows the reversal of write-downs to net realizable value when there is a change in the circumstances giving rise to the impairment. The Company had adopted these recommendations for the December 31, 2007 financial statements which resulted in a re-classification of certain inventory to property, plant and equipment. At June 30, 2008 $863,000 of inventory was re-classified to property, plant and equipment. International Financial Reporting Standards In February 2008, the Canadian Accounting Standards Board confirmed that the use of International Financial Reporting Standards ("IFRS") will be required in 2011 for publicly accountable profit-oriented enterprises. IFRS will replace Canada's current GAAP for listed companies and other profit-oriented enterprises that are responsible to large or diverse groups of stakeholders. Companies will be required to provide one year of comparative date in accordance with IFRS. In the second quarter of 2008 the Company began to develop its IFRS changeover plan. Initial activities include training sessions and acquisition of written standards and examples of IFRS disclosure to identify where key differences between Canadian GAAP and IFRS will exist. The Company intends to disclose its convergence plan and qualitative effects of IFRS on its financial statements as they become more fully developed. 4. PROPERTY, PLANT AND EQUIPMENT June 30, 2008 December 31, 2007 Accumulated Accumulated depletion and depletion and ($000's) Cost depreciation Cost depreciation ------------------------------------------------------------------------- Petroleum and natural gas properties 288,753 126,766 274,067 108,045 Office and computer equipment 740 380 734 351 ------------------------------------------------------------------------- 289,493 127,146 274,801 108,396 ------------------------------------------------------------------------- Net book value 162,347 166,405 ------------------------------------------------------------------------- At June 30, 2008, costs of $22,325,000 (December 31, 2007 - $21,159,000) related to undeveloped land have been excluded from the depletion and depreciation calculation. At June 30, 2008 estimated future development costs of $15,511,000 have been included in the depletion and depreciation calculation. 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 $3,848,000 as at June 30, 2008 (December 31, 2007 - $3,273,000) based on a total future liability of $9,089,000 (December 31, 2007 - $8,611,000). These payments are expected to be made over the next 5 to 15 years. An inflation rate of 2 percent and a credit adjusted risk free rate of 10 percent were used to calculate the present value of the asset retirement obligations. The following table reconciles the asset retirement obligations: ($000's) 2008 ------------------------------------------------------- Obligation, January 1, 2008 3,273 Increase in obligation during the period 392 Accretion expense 183 ------------------------------------------------------- Obligation, June 30, 2008 3,848 ------------------------------------------------------- 6. BANK OPERATING LINE An agreement with a Canadian bank is in place for an operating bank line totaling $66 million at June 30, 2008. Collateral for the facility consists of a general assignment of book debts and a $35.0 million debenture with a floating charge over all assets of the Company and a $75.0 million supplemental debenture with a floating charge over all assets of the Company. The bank line is a demand line and carries an interest rate of the Bank's prime rate adjusted for a factor based on the most recent quarterly debt to cash flow calculation. The average rate paid for the quarter ended June 30, 2008 was 5.6 percent (2007 - 8.2 percent). 7. CAPITAL STOCK (a) Authorized Capital The authorized capital consists of an unlimited number of preferred shares issuable in series and an unlimited number of common shares without nominal or par value. (b) Common shares issued ------------------------------------------------------------------------- Consideration Number ($000's) ------------------------------------------------------------------------- Balance December 31, 2006 92,947,064 148,038 Shares issued on exercise of stock options 225,000 225 ------------------------------------------------------------------------- Balance December 31, 2007 93,172,064 148,263 ------------------------------------------------------------------------- Shares issued on exercise of stock options 375,000 375 ------------------------------------------------------------------------- Balance June 30, 2008 93,547,064 148,638 ------------------------------------------------------------------------- (c) Stock Option Plan A stock option plan is in place under which 10 percent of the number of outstanding common shares is reserved for options to be granted to directors, officers, employees and consultants with terms established by the Board of Directors. Options granted under the plan generally have a five year term to expiry and vest equally over a three year period commencing on the first anniversary date of the grant. The exercise price of each option equals the closing market price of the Company's common shares on the day prior to the date of the grant. The following table sets forth a reconciliation of the plan activity for the six months ended June 30, 2008: 2008 2007 Weighted Weighted average average exercise exercise Number of price ($ Number of price ($ Options per share) Options per share) ------------------------------------------------------------------------- Outstanding, beginning of period 6,238,200 1.42 4,416,200 1.68 Granted 1,779,000 1.01 1,467,000 1.02 Cancelled (1,052,500) 2.88 (238,667) 1.99 Exercised (845,000) 1.00 (225,000) 1.00 ------------------------------------------------------------------------- Outstanding, end of period 6,119,700 1.11 5,419,533 1.52 ------------------------------------------------------------------------- Exercisable 2,320,024 1.28 2,632,028 1.44 ------------------------------------------------------------------------- The following table sets forth additional information relating to the stock options outstanding at June 30, 2008: Options Outstanding Exercisable Options ------------------------------------------------------------------------- Weighted Weighted average average exercise Weighted exercise Weighted price average price average Exercise price Number of ($ per years to Number of ($ per years to range Options share) expiry Options share) expiry ------------------------------------------------------------------------- $0.50 to $0.99 2,740,500 0.88 4.15 341,356 0.99 3.54 ------------------------------------------------------------------------- $1.00 to $1.49 2,668,700 1.20 2.83 1,473,698 1.24 1.36 ------------------------------------------------------------------------- $1.50 to $1.99 705,500 1.61 1.95 501,667 1.60 1.46 ------------------------------------------------------------------------- $2.00 to $2.49 - - - - - - ------------------------------------------------------------------------- $2.50 to $3.00 5,000 2.90 2.42 3,333 2.42 2.90 ------------------------------------------------------------------------- $0.50 to $3.00 6,119,700 1.11 3.32 2,320,024 1.28 1.71 ------------------------------------------------------------------------- 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 valuations of options are: Risk free rate - 3.2%; average expected life - 4.5 years; no expected dividend yield; 46 percent volatility. Estimated future forfeiture assumptions are not used in calculations as forfeitures are recognized as they occur. The weighted average fair value of options outstanding at June 30, 2008 is $0.558 per option. For the quarter ended June 30, 2008, $474,000 and for the six months ended June 30, 2008 $693,000 was recorded for stock based compensation (2007 - $230,000 and $433,000) with a corresponding increase recorded to contributed surplus. (d) Contributed Surplus The following table sets forth the continuity of contributed surplus for the period ended June 30, 2008: ($000's) ------------------------------------------------------- December 31, 2007 2,195 2008 Stock based compensation expense 693 ------------------------------------------------------- June 30, 2008 2,888 ------------------------------------------------------- 8. SUPPLEMENTAL CASH FLOW INFORMATION Changes in Non-cash Working Capital For the six months ended June 30, ($000's) 2008 2007 ------------------------------------------------------------------------- Accounts receivable (3,707) 1,338 Prepaid expenses and deposits (114) 26 Accounts payable and accrued liabilities (3,187) (4,624) Taxes payable (4) 5 ------------------------------------------------------------------------- (7,012) (3,255) Change in non-cash working capital related to investing activities (81) 661 ------------------------------------------------------------------------- Change in non-cash working capital related to operating activities (6,931) (3,916) ------------------------------------------------------------------------- Cash interest and taxes paid For the three and six months ended June 30, Three Three Six Six months months months months ($000's) 2008 2007 2008 2007 ------------------------------------------------------------------------- Income and other taxes 10 (*) 10 - Interest 763 1,070 1,662 2,025 ------------------------------------------------------------------------- 9. RELATED PARTY TRANSACTIONS Fees for legal services are paid to a law firm in which the corporate secretary is a partner. The legal services are rendered in the normal course of business at normal rates charged by the law firm. Legal fees for this firm paid for the quarter ended June 30, 2008 were $105,000 (2007 - $98,000). 10. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT Financial assets and liabilities recognized on the balance sheets consist of cash and cash equivalents, accounts receivable, deposits, accounts payable, accrued liabilities, bank loan and financial derivatives used to manage interest rate, natural gas and oil price risk. Fair value of financial assets and liabilities Cash, cash equivalents, deposits, financial derivatives and bank indebtedness are designated as "held-for-trading". Accounts receivable 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 derivatives used for interest rate and commodity price risk management 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. The maximum credit exposure with accounts receivable is the carrying value. At June 30, 2008, the largest single credit exposure was approximately $8.5 million from the Company's sales agent the balance of which is settled monthly. At June 30, 2008, nine percent of accounts receivable were non-current as defined by accounts over 90 days outstanding. No allowance for doubtful accounts receivable has been recorded nor are any deemed to be impaired. (b) Interest Rate Risk The Company is exposed to fluctuations in interest rates on its bank debt which charges interest at variable market rates. The Company entered into an interest rate swap transaction in January 2008 to fix the interest rate on $25.0 million of its variable rate demand bank line. The transaction fixes the interest rate for a two year period at a rate of 5.21 percent including the Company's borrowing margin on its bank line. Fair values for interest rate derivatives are provided by the financial intermediary with whom the transactions were completed and tested by the Company for reasonableness based on comparing current market prices and the fixed prices of the contracts. The fair value of the interest rate derivative instrument marked-to-market as at June 30, 2008 results in an unrealized gain of $141,000. There were no interest rate derivatives in place in 2007. The net income effect of a one percent change in short-term interest rates on the remaining amount of bank debt is approximately $225,000. (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. No specific currency hedging has been undertaken, however, all commodity price risk management activities hedge revenue into Canadian dollars. The net income effect of a $0.01 change in the exchange rate between the US and Canadian dollars is approximately $575,000. (d) Commodity Price Risk Management The Company is exposed to the risk of changes in market prices for natural gas, crude oil and natural gas liquids. The Company may mitigate this risk by entering into derivatives based fixed price contracts or price collars or may enter into fixed price physical delivery contracts. The following is a summary of natural gas price risk management derivative contracts in effect as of June 30, 2008. All natural gas contracts are priced in Canadian dollars per gigajoule ("GJ"). The price per GJ can be converted to an approximate price per million cubic feet ("MCF") by multiplying the per GJ price by 1.05. GJ volume can be converted to an approximate MCF volume by multiplying the GJ volume by 0.95. Natural Gas Risk Management Contracts ------------------------------------------------------------------------- Daily Term of Contract Fixed price per gigajoule quantity (Cdn$/GJ) (GJ/day) ------------------------------------------------------------------------- 2,000 April 1 to March 31, 2009 $6.72 fixed price ------------------------------------------------------------------------- 2,000 April 1 to December 31, 2008 $6.65 fixed price ------------------------------------------------------------------------- 2,000 January 1 to December 31, 2008 $6.65 fixed price ------------------------------------------------------------------------- 2,000 April 1 to December 31, 2008 $6.80 fixed price ------------------------------------------------------------------------- 2,000 April 1 to October 31, 2008 $6.80 fixed price ------------------------------------------------------------------------- 2,000 April 1 to October 31, 2008 $7.45 fixed price ------------------------------------------------------------------------- Crude Oil Risk Management Contracts ------------------------------------------------------------------------- Daily Term of Contract Fixed price per barrel quantity (WTI in Cdn$) (Barrels/d) ------------------------------------------------------------------------- 100 January 1 to December 31, 2008 $85.00 floor; $93.30 cap ------------------------------------------------------------------------- 100 January 1 to December 31, 2008 $85.00 floor; $98.10 cap ------------------------------------------------------------------------- Fair values for commodity price derivatives are provided by the financial intermediary with whom the transactions were completed and tested by the Company for reasonableness based on comparing current market prices and the fixed prices of the contracts. The fair value of the above natural gas and crude oil derivative instruments marked-to-market as at June 30, 2008 results in an unrealized loss of $12,133,000 (December 31, 2007 - gain of $162,000). Total realized losses from risk management activities in the second quarter of 2008 were $2,742,000 (2007 - $13,000 gain). Total realized losses for the six months ended June 30, 2008 were $2,601,000 (2007 - $95,000 gain). Commodity price and interest rate derivatives are transacted with large, credit worthy counterparties and governed by credit agreements between the Company and its counterparties. Absent the above-noted risk management contracts, the effects of changes in commodity prices on net income summarized in the following table. ------------------------------------------------------------------------- Commodity Price change Cash flow change ($ 000's) ------------------------------------------------------------------------- Natural gas ($/mcf) 1.00 $4,200 ------------------------------------------------------------------------- Oil and Liquids ($/bbl) 10.00 $1,100 ------------------------------------------------------------------------- (e) Liquidity Risk and Capital Requirements The Company is exposed to liquidity risk, which is the risk that the Company may be unable to generate or obtain sufficient cash to meet its commitments as they become due. The financial liabilities on the balance sheet consist of accounts payable, bank debt and taxes payable. This risk is mitigated through the management of cash and debt and the Company may adjust capital spending, issue new shares or draw or repay its operating bank line. The Company's primary capital management objective is to maintain a strong balance sheet to provide the financial flexibility to respond to cash flow volatility or an investment opportunity. The Company maintains appropriate unused capacity in its operating bank line to meet short term fluctuations from forecasted results. The Company has no externally imposed capital requirements but is subject to a working capital test as a covenant on its operating bank line. Forecasted cash flows and operating and capital outlays are updated frequently to ensure necessary liquidity remains available. The Company may hedge a portion of its future production and/or its interest rate exposure to protect cash flows. All of the Company's financial obligations are either demand or are due within one year. The Company is targeting to reduce its debt and working capital to funds from operations ratio to a measure of 1.5:1 on a current quarter annualized basis (excluding unrealized hedging gains and losses from working capital), down from historical ratios of over 2:1. For the quarter ended June 30, 2008 this ratio was 1.0:1. ------------------------------------------------------------------------- Target At June 30 ($000's) Measure 2008 2007 ------------------------------------------------------------------------- Components of Ratio ------------------------------------------------------------------------- Current assets 14,579 21,123 Current liabilities (78,521) (84,733) ------------------------------------------------------------------------- (63,942) (63,610) Unrealized risk management loss (gain) 12,176 (1,463) ------------------------------------------------------------------------- Debt and working capital (51,766) (65,073) ------------------------------------------------------------------------- Funds from operations - three months ended June 30 annualized(1) 50,280 31,128 ------------------------------------------------------------------------- Ratio 1.5:1 1.0:1 2.1:1 ------------------------------------------------------------------------- (1) Funds from operations is a non-GAAP measure defined as: operating cash flow adjusted for changes in non-cash working capital related to operating activities, all annualized. 11. PER SHARE INFORMATION The weighted average number of common shares outstanding for the quarter ended June 30, 2008 of 93,192,668 was used to calculate basic and diluted income (loss) per share (2007 - 92,973,713). The weighted average number of common shares outstanding for the six months ended June 30, 2008 was 93,182,367 (2007 - 92,960,461). All of the outstanding options have been excluded from the calculation of diluted per share information as they were anti-dilutive. The total number of shares which are potentially dilutive in future periods as of June 30, 2008 was 6,119,700. 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; Daniel F. Botterill, President & Chief Executive Officer, Ph: (403)
303-3262

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Berens Energy Ltd.

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