Berens Energy Ltd. releases results for the three and six months ended June 30, 2007.



    Symbol: BEN - TSX

    CALGARY, Aug. 10 /CNW/ -

    
    FINANCIAL AND OPERATING HIGHLIGHTS


    -------------------------------------------------------------------------
    ($ Cdn thousands,          Three months              Six months
     except as noted)         ended June 30,            Ended June 30,
    -------------------------------------------------------------------------
                                             %                          %
                           2007     2006   Change    2007     2006    Change
    -------------------------------------------------------------------------
    Sales volume
      Natural gas
       (mcf/day)         19,919   17,224      16%   19,315   16,935      14%
      Oil and ngls
       (bbl/day)            560      494      13%      530      457      16%
      boe/day
       (6 to 1)           3,880    3,364      15%    3,749    3,280      14%
    -------------------------------------------------------------------------
    Revenue net of
     royalties           12,643    9,845      28%   24,423   19,369      24%
    Net income (loss)      (557)  (1,606)     65%   (3,603)  (3,728)      3%
      Per share (basic
       and diluted)      $(0.01)  $(0.02)     50%   $(0.04)  $(0.04)       -
    Funds from
     operations(1)        7,782    5,375      45%   14,752   11,269      31%
      Per share (basic
       and diluted)(1)    $0.08    $0.06      33%    $0.16    $0.14      14%
    -------------------------------------------------------------------------
    Capital costs
      Exploration and
       development        5,120   14,090            22,198   29,677
      Land and seismic    1,085      972             2,155    4,030
      Other                   3      172                15      651
    -------------------------------------------------------------------------
      Total               6,208   15,234     (57%)  24,368   34,358     (28%)
    -------------------------------------------------------------------------
    Net wells completed
     (No.)                    1        9                 7       17
    -------------------------------------------------------------------------
    Net working capital
     (deficit) -
     including bank
     debt               (63,610) (55,766)          (63,610) (55,766)
    -------------------------------------------------------------------------
    Shares outstanding
      End of period
      (000's)            93,172   86,447       8%   93,172   86,447       8%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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

    Second Quarter 2007 Operating Highlights

    Berens is pleased to provide our second quarter results that show good
production growth, reduced operating costs, increased cash flow and ongoing
drilling success.


        -  Production - Q2 2007 production averaged 3,880 boe/d, up 15% over
           Q2 2006 and up 7% over Q1 2007. Production for the first six
           months of 2007 averaged 3,749 boe/d, up 14% compared to the first
           six months of 2006. Plant turn-around activity in Lanfine in May
           and Pembina in June reduced volume by an average of 50 boe/d
           during the second quarter of 2007. Strong drilling success during
           the final quarter of 2006 and the first quarter of 2007 delivered
           the second quarter volume growth as the majority of second quarter
           capital was spent on completion and tie in of wells. At the end of
           the quarter 5 (2.7 net) wells were at various stages of completion
           and tie-in. These 3 oil wells and 2 natural gas wells are expected
           to be on stream in July and August, adding to the production gains
           made in the second quarter.

        -  Production Costs - Costs averaged $6.87 per boe in Q2 2007, down
           14% compared to $8.02 per boe in Q2 2006. For the six months ended
           June 30, 2007 costs averaged $7.47 per boe, up 2% compared to
           $7.33 per boe for the first six months of 2006. Higher production
           levels and cost vigilance have kept production costs in check
           despite inflationary industry pressures.

        -  Funds from Operations - Funds from operations Q2 2007 were
           $7.8 million ($0.08 per share), up 45% compared to Q2 2006 funds
           from operations of $5.4 million ($0.06 per share). Higher Q2 2007
           production, lower per unit operating costs and stronger natural
           gas prices contributed to the increase. For the six months ended
           June 30, 2007 funds from operations were $14.8 million ($0.16 per
           share), up 31% compared to $11.3 million ($0.14 per share) for the
           first six months of 2006.

        -  Land - Berens total undeveloped land currently stands at 122,000
           net acres. Ninety-eight percent of the undeveloped lands are
           located in the four core areas of Pembina, Deep Basin, Lanfine and
           Marten Hills. Additionally, numerous down-spacing opportunities
           have been identified on developed acreage, particularly in the
           Pembina area. This land base sets up a diverse and high quality
           drilling program for the balance of 2007 and beyond.
    

    Report from Management

    The second quarter of 2007 showed solid production gains as we completed
and tied in wells from our successful drilling program conducted during the
2006/07 winter. Drilling re-commenced late in the second quarter of 2007 due
to normal spring break-up conditions and most of our capital spending was
focused on bringing on production from our winter drilling. By the end of the
quarter we had tied in 21 wells and still had 5 wells to tie-in during July
and August. We returned to drilling in June with three Pembina wells drilled
by the end of July which were all successful, continuing our recent success in
this key growth area. A six well Lanfine program in eastern Alberta in July
has also delivered 3 gas wells and two potential oil wells. Year-to-date we
have drilled 25 wells with an 84% success rate.
    Our production remains weighted to natural gas and the price of natural
gas remained supportive in the second quarter. Natural gas prices weakened
late in the second quarter and have remained weak in July. At these weaker
prices it is not prudent business to be aggressively developing our natural
gas assets. As such, we will slow down and defer drilling in Lanfine, Pembina
and Deep Basin until such time as gas prices recover. The reduced activity has
lowered our capital spending projection for 2007 from $45 million to $39
million or about 13 percent. With year to date June 30, 2007 average volume of
3,749 boe per day, we are now expecting to exit the year at 4,100 to 4,200
boe/d and are estimating our average 2007 production volume to be 3,800 to
3,900 boe/d, down approximately 8 percent from our earlier guidance of 4,200
boe/d. Our revised production guidance is expected to deliver 14 percent
volume growth over our average production in 2006.
    Service costs, particularly for drilling related activities have
moderated somewhat and we expect further improvements in our capital and
operating cost structures in the second half of 2007. We have also made
internal operational changes to better control our drilling and completion
costs. The wells we drilled in Lanfine and Pembina in July incurred lower
costs than we had experienced in some time and we expect this trend to
continue in the second half of the year.
    Our land base continues to be a strong asset and under the current
natural gas price environment we will be selectively exploiting our lands in
anticipation of improved natural gas prices in the future. We currently plan
to drill 6 more wells this year and have over 75 drilling locations in our
inventory.
    Our recent drilling success is beginning to translate into volume growth
with accompanying reserves being added at competitive finding and development
costs. Weak natural gas prices are a concern for our industry and without some
recovery in natural gas prices in the second half of the year, industry
activity is likely to decline. Reduced activity in western Canada will result
in lower production volume and we expect a recovery in natural gas prices in
the latter half of the year. In the meantime, our plans are to continue to
enhance our asset value by selective drilling with a capital spending program
within our cash flow capacity.

    Daniel F. Botterill
    President and C.E.O.
    Berens Energy Ltd.
    Second Quarter 2007
    (unaudited)
    Management's Discussion and Analysis ("MD&A")
    August 9, 2007

    OVERVIEW

    Berens Energy Ltd. ("Berens" or the "Company") is a full cycle oil and
natural gas exploration and production company with a concentrated production
and land base in Eastern Alberta, Pembina and Deep Basin regions of west
central Alberta.
    All calculations converting natural gas to crude oil equivalent have been
made using a ratio of six thousand cubic feet (six "mcf") of natural gas to
one barrel of crude equivalent. Barrels of oil equivalent ("boe") may be
misleading, particularly if used in isolation. A boe conversion ratio of six
mcf of natural gas to one barrel of crude oil equivalent is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.
    The following discussion of financial position and results of operations
should be read in conjunction with the Company's December 31, 2006 audited
financial statements and notes thereto and the unaudited June 30, 2007 interim
financial statements. This MD&A was prepared using information that is current
as of August 9, 2007 unless otherwise noted.

    FORWARD LOOKING INFORMATION

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

    
    QUARTERLY INFORMATION
                                                                2007
                                                        ---------------------
    ($000's except as noted)                                 Q2         Q1
    -------------------------------------------------------------------------
    Sales volumes:
      Natural gas (mcf/day)                                19,919     18,705
      Oil and natural gas liquids (bbl/day)                   560        499
      Barrels of oil equivalent (bbl/day)                   3,880      3,617
    -------------------------------------------------------------------------
    Financial:
      Net revenue                                          12,643     11,793
      Net (loss)                                             (557)    (3,043)
        per share - basic ($/share)                        $(0.00)    $(0.03)
        per share - diluted ($/share)                      $(0.00)    $(0.03)
      Capital costs                                         6,208     18,329
      Shares outstanding (000's)                           93,172     92,947
      Bank debt                                            62,700     59,980
      Working capital (deficit)
       including bank debt                                (63,610)   (67,468)
    -------------------------------------------------------------------------
    Per unit information:
      Natural gas price ($/mcf)                             $7.60      $7.75
      Oil and liquids price ($/barrel)                     $58.98     $55.24
      Oil equivalent price ($/boe)                         $47.51     $47.72
      Operating netback ($/boe)                            $27.88     $27.16
    -------------------------------------------------------------------------
    Net wells completed: (No.)
      Natural gas                                               1          6
      Oil                                                       -          -
      Dry                                                       -          1
    -------------------------------------------------------------------------
      Total                                                     1          7
    -------------------------------------------------------------------------

                                                      2006
                                 --------------------------------------------
    ($000's except as noted)           Q4         Q3         Q2         Q1
    -------------------------------------------------------------------------
    Sales volumes:
      Natural gas (mcf/day)          18,440     17,355     17,224     16,631
      Oil and natural gas liquids
       (bbl/day)                        483        479        494        420
      Barrels of oil equivalent
       (bbl/day)                      3,556      3,372      3,364      3,192
    -------------------------------------------------------------------------
    Financial:
      Net revenue                    11,213      9,536      9,846      9,523
      Net (loss)                    (21,951)    (2,662)    (1,606)    (2,121)
        per share - basic
         ($/share)                   $(0.24)    $(0.03)    $(0.02)    $(0.03)
        per share - diluted
         ($/share)                   $(0.24)    $(0.03)    $(0.02)    $(0.03)
      Capital costs                  12,811      9,746     15,234     19,124
      Shares outstanding (000's)     92,947     86,447     86,447     86,447
      Bank debt                      50,080     52,780     49,580     32,180
      Working capital (deficit)
       including bank debt          (55,073)   (60,182)   (55,766)   (45,907)
    -------------------------------------------------------------------------
    Per unit information:
      Natural gas price ($/mcf)       $7.13      $5.91      $6.28      $7.72
      Oil and liquids price
       ($/barrel)                    $51.54     $62.07     $64.27     $51.07
      Oil equivalent price ($/boe)   $43.96     $39.24     $41.59     $46.09
      Operating netback ($/boe)      $24.24     $21.54     $22.87     $24.59
    -------------------------------------------------------------------------
    Net wells completed: (No.)
      Natural gas                         7          3          9          4
      Oil                                 -          -          -          -
      Dry                                 1          1          1          3
    -------------------------------------------------------------------------
      Total                               8          4         10          7
    -------------------------------------------------------------------------


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

    Steady volume increases were delivered throughout 2005 from ongoing
drilling activities in eastern Alberta. Significant production and revenue
increases were experienced in the first quarter of 2006 compared to earlier
quarters due to the acquisition of Berland Exploration Ltd. in January of
2006. Since the acquisition, ongoing drilling has delivered further,
consistent production increases to the end of the second quarter of 2007. The
significant loss in the fourth quarter of 2006 was mainly due to a non-cash
write-down of goodwill. Commodity price fluctuations have been due to normal
market volatility. Commodity price hedging was put in place in 2007 reducing
the Company's exposure to variability in commodity prices.

    RESULTS OF OPERATIONS

    Production Volume

    Production volume averaged 3,880 boe/d for the second quarter of 2007, up
15 percent compared to 3,364 boe/d in the second quarter of 2006 and up seven
percent compared to the first quarter of 2007. Natural gas represented 86
percent of production in the second quarter of 2007 with the remaining
production being 13 percent light oil and natural gas liquids and one percent
conventional heavy oil. Volume averaged 3,749 boe/d for the first six months
of 2006, up 14 percent compared to 3,280 boe/d in the first six months of
2006. Completion and tie-in of successful drilling activities during the
fourth quarter of 2006 and first quarter of 2007 in Pembina, Lanfine, Deep
Basin and Marten Hills have delivered the second quarter and six months to
date volume growth. Twenty-one (10.3 net) wells were tied in during the first
six months of 2007 with five (2.7 net) wells awaiting completion or tie-in at
the end of the quarter.

    Production Revenue

    Natural gas prices averaged $7.60 per mcf for the second quarter of 2007,
up 21 percent compared to $6.28 per mcf in the second quarter of 2006. Oil and
liquids prices averaged $55.25 and $60.40 per barrel respectively in the
second quarter of 2007 for a blended price of $58.98 per barrel, down eight
percent from the second quarter 2006 blended oil and liquids price of
$64.27 per barrel. On a boe basis, prices averaged $47.51 in the second
quarter of 2007, up 14 percent compared to $41.59 per boe in the second
quarter of 2006. Revenue was up 32 percent in the second quarter of 2007
compared to the second quarter of 2006 as both volume and prices increased.
    Natural gas prices averaged $7.67 per mcf for the six months ended
June 30, 2007, up 10 percent compared to $6.98 per mcf in the six months ended
June 30, 2006. Oil and liquids prices averaged $52.78 and $58.87 per barrel
respectively in the six months ended June 30, 2007 for a blended price of
$57.22 per barrel, down two percent from the six months ended June 30, 2006
blended oil and liquids price of $58.24 per barrel. On a boe basis, prices
averaged $47.61 in the six months ended June 30, 2007, up eight percent
compared to $44.16 per boe in the six months ended June 30, 2006. Revenue was
up 23 percent in the six months ended June 30, 2007 compared to the six months
ended June 30, 2006 as both volume and prices increased.

    
    -------------------------------------------------------------------------
                                   Three months ended      Six months ended
    Volumes and prices                  June 30                June 30
    -------------------------------------------------------------------------
                                   2007    2006 Change    2007    2006 Change
    -------------------------------------------------------------------------
    Production revenue ($000's)  16,784  12,737   32%   32,327  26,251   23%
    -------------------------------------------------------------------------
    Production volume
      Natural gas (mcf/d)        19,919  17,224   16%   19,315  16,935   14%
      Oil and liquids (bbl/d)       560     494   13%      530     457   16%
      BOE (bbl/d)                 3,880   3,364   15%    3,749   3,280   14%
    Prices
    -------------------------------------------------------------------------
      Natural gas ($/mcf)          7.60    6.28   21%     7.67    6.98   10%
    -------------------------------------------------------------------------
      Oil and liquids ($/bbl)     58.98   64.27   (8%)   57.22   58.24   (2%)
    -------------------------------------------------------------------------
      BOE ($/boe)                 47.51   41.59   14%    47.61   44.16    8%
    -------------------------------------------------------------------------
    

    Royalties

    Royalties averaged 25 percent of revenue for the second quarter of 2007
compared to 23 percent in the second quarter of 2006. Higher royalties in the
second quarter of 2007 compared to the second quarter of 2006 are mainly due
to higher 2007 natural gas prices. Royalties averaged 24 percent of revenue
for the six months ended June 30, 2007 compared to 26 percent for the six
months ended June 30, 2006 as royalty rates in early 2006 were based on high
reference prices from late 2005 when natural gas prices were above $10.00.
    Royalty expense of $4.1 million was recorded in the second quarter of
2007, up 43 percent compared to the second quarter of 2006 reflecting both
higher volume and higher natural gas prices in the 2007 period. Royalty
expense of $7.9 million was recorded in the six months ended June 30, 2007, up
15 percent compared to the six months ended June 30, 2006.
    On an ongoing basis, royalties are expected to average approximately 24
percent of revenues without the go-forward benefit of ARTC which has been
rescinded effective January 1, 2007.

    
    -------------------------------------------------------------------------
                                   Three months ended      Six months ended
    Royalties                           June 30                June 30
    -------------------------------------------------------------------------
                                   2007    2006 Change    2007    2006 Change
    -------------------------------------------------------------------------
    Royalty expense ($000'S)      4,140   2,892   43%    7,904   6,882   15%
    Royalty cost per boe         $11.73   $9.85   19%   $11.65  $11.53    1%
    -------------------------------------------------------------------------
    

    Production Expenses

    Production expenses were $6.87 per boe in the second quarter of 2007,
down 14 percent compared to $8.02 per boe in the second quarter of 2006.
Higher production volume and ongoing vigilance on costs have improved the per
unit performance. In addition, the Company acquired an interest in a major
Pembina processing plant in December 2006 which has reduced processing costs
for natural gas produced in a portion of the Pembina area. Production expenses
were $7.47 per boe in the six months ended June 30, 2007, up two percent
compared to $7.33 per boe in the six months ended June 30, 2006. With ongoing
volume increases and cost management, it is expected future per unit operating
expenses will trend near the $7.50 per boe level.
    Second quarter 2007 production expenses were $2.4 million, down one
percent compared to the second quarter of 2006 as higher volumes were offset
by lower per unit costs. Production expenses for the six months ended June 30,
2007 were $5.1 million, up 15 percent compared to the six months ended June
30, 2006 as volumes were higher and per unit costs were almost unchanged.

    
    -------------------------------------------------------------------------
                                   Three months ended      Six months ended
    Production expenses                 June 30                June 30
    -------------------------------------------------------------------------
                                   2007    2006 Change    2007    2006 Change
    -------------------------------------------------------------------------
    Production expenses ($000's)  2,426   2,458   (1%)   5,073   4,351   15%
    Production expenses per boe   $6.87   $8.02  (14%)   $7.47   $7.33    2%
    -------------------------------------------------------------------------
    

    Transportation costs increased $0.1 million, or 39 percent in the second
quarter of 2007 compared to the second quarter of 2006 due to higher volume
and higher per unit costs.

    Operating Netback(1)

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

    
    -------------------------------------------------------------------------

    Quarterly Operating          Three months ended      Six months ended
    Netbacks  ($'s per boe)           June 30                June 30
    -------------------------------------------------------------------------
                                   2007    2006 Change    2007    2006 Change
    -------------------------------------------------------------------------
    Sales price                   47.51   41.59   14%    47.61   44.16    8%
    Less:
      Royalties (net of ARTC)     11.73    9.85   19%    11.65   12.01   (3%)
      Production expenses          6.87    8.02  (14%)    7.47    7.33    2%
      Transportation charges       1.03    0.85   21%     0.95    0.93    2%
    -------------------------------------------------------------------------
    Operating netback             27.88   22.87   22%    27.54   23.89   15%
    -------------------------------------------------------------------------

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

    General and Administrative Expenses

    General and administrative ("G&A") expenses, including stock-based
compensation were $1.3 million in the in the second quarter of 2007, down
seven percent compared to the second quarter of 2006. In the six months ended
June 30, 2007 G&A expenses were $2.5 million, down 11 percent compared to the
six months ended June 30, 2006. Costs in the 2007 periods compared to the same
periods of 2006, benefited by general and administrative cost recoveries from
partners on capital projects operated by Berens. In 2006 a higher proportion
of the Company's capital activity was directed to 100 percent owned lands
resulting in less administrative cost recovery. On a per unit basis, general
and administrative costs were $3.75 per boe for the second quarter of 2007,
down 19 percent compared to $4.65 per boe in the second quarter of 2006. In
the six months ended June 30, 2007 per unit G&A costs were $3.63 per boe, down
22 compared to $4.68 per boe for the six months ended June 30, 2006. There
were no general and administrative costs capitalized in the second quarter or
for the first six months of 2007 or 2006.
    Staff levels are expected to remain fairly constant in 2007. Per unit
general and administrative costs are expected to decline as production levels
increase.

    
    -------------------------------------------------------------------------

    General and                    Three months ended      Six months ended
    administrative expenses             June 30                June 30
    -------------------------------------------------------------------------
                                   2007    2006 Change    2007    2006 Change
    -------------------------------------------------------------------------
    G&A expenses ($000's)         1,325   1,424   (7%)   2,461   2,777  (11%)
    G&A expenses per boe          $3.75   $4.65  (19%)   $3.63   $4.68  (22%)
    -------------------------------------------------------------------------
    

    Depletion, Amortization and Accretion

    Depletion, amortization and accretion ("DA&A") totaled $10.6 million
($28.75 per boe) in the second quarter of 2007, up 14 percent but lower on a
boe basis compared to $9.3 million ($30.51 per boe) in the second quarter of
2006. In the six months ended June 30, 2007 DA&A totaled $20.0 million
($29.26 per boe), up eight percent but lower on a boe basis compared to $18.5
million ($31.12 per boe) in the six months ended June 30, 2006. Drilling
results have improved in the latter part of 2006 and early 2007 and new
reserves have been added at lower per unit costs compared to the first half of
2006 resulting in lower per unit depletion rates.

    
    -------------------------------------------------------------------------

    Depletion, Amortization        Three months ended      Six months ended
    and Accretion                       June 30                June 30
    -------------------------------------------------------------------------
                                   2007    2006 Change    2007    2006 Change
    -------------------------------------------------------------------------
    DA&A expenses ($000's)       10,623   9,341   14%   19,967  18,476    8%
    DA&A expenses per boe        $28.75  $30.51   (6%)  $29.26  $31.12   (6%)
    -------------------------------------------------------------------------
    

    Interest Expense

    Interest expense was $1.0 million in the second quarter of 2007 compared
to $0.5 million in the second quarter of 2006. In the six months ended June
30, 2007 interest expense was $2.0 million compared to $0.8 million in the
six months ended June 30, 2006. Berens raised equity in the fourth quarter of
2005 in anticipation of the acquisition of Berland and had a significant cash
position at the start of 2006. The subsequent closing of the Berland
acquisition in January 2006 resulted in significant borrowing on the bank
operating line as 30 percent of the Berland acquisition cost was in the form
of cash and Berens assumed Berland's debt and working capital deficiency,
totaling $28 million. Capital expenditures in 2006 and the first quarter of
2007 were higher than funds from operations resulting in higher average debt
levels in the 2007 periods compared to the same periods in 2006. The interest
rate on the bank line was also 1.25 percent higher in the six months ended
June 30, 2007 compared to the six months ended June 30, 2006.

    Income Taxes

    The Company does not expect to pay current income tax during 2007 as
there are sufficient capital cost pools and expected future capital spending
to shelter taxable income. A small amount of current taxes for capital taxes
has been recorded for the first quarter of 2007.
    Future tax recovery was $0.5 million for the second quarter of 2007
compared to a recovery of $2.6 million for the second quarter of 2006 as the
net loss before income taxes was lower in 2007 combined with lower income tax
rates in the 2007 period.

    NET INCOME (LOSS)

    The net loss for the second quarter of 2007 was $0.5 million ($0.01 per
share) compared to a loss of $1.6 million ($0.02 per share) in the second
quarter of 2006. The lower second quarter 2007 loss resulted primarily from a
positive $2.6 million swing in the unrealized amount from hedging activities
from a loss position of $0.6 million at March 31, 2007 to a gain position of
$2.0 million on June 30, 2007. Excluding the unrealized hedging position
change, the net loss was lower in the second quarter of 2007 compared to the
second quarter of 2006 due to higher production volume, stable commodity
prices, lower per unit operating costs and lower depletion rates.
    The net loss for the six months ended June 30, 2007 was $3.6 million
($0.04 per share) compared to a net loss of $3.8 million ($0.04 per share) for
the six months ended June 30, 2006. The lower loss in the six months ended
June 30, 2007 period was due to a positive swing in the unrealized amount from
hedging of $1.4 million, higher volumes and lower per unit costs offset by a
larger future tax recovery in the six months ended June 30, 2006.

    CAPITAL COSTS

    Capital costs were $6.2 million in the second quarter of 2007 compared to
$15.2 million in the second quarter of 2006. Capital spending the second
quarter of 2007 was lower following a very active first quarter 2007 program
to take advantage of winter weather when drilling is most effective,
particularly in Deep Basin and Marten Hills which is a winter access only
area. In the six months ended June 30, 2007 $24.4 million of capital costs
were incurred compared to $34.4 million in the six months ended June 30, 2006.
A total of 16 wells (7.1 net) were drilled in the first six months of 2007,
compared to 30 wells (17.3 net) in the first six months of 2006.

    
    -------------------------------------------------------------------------
                                     Three months ended     Six months ended
    ($000's)                              June 30               June 30
    -------------------------------------------------------------------------
                                       2007       2006       2007       2006
    -------------------------------------------------------------------------
    Drilling and completion           2,756     11,138     14,550     23,318
    Equipping and tie-in              2,364      2,951      7,647      6,359
    Land                                519        123        626      1,683
    Geological and geophysical          566        850      1,530      2,348
    Office and other                      3        172         15        650
    -------------------------------------------------------------------------
    Total                             6,208     15,234     24,368     34,358
    Asset retirement obligation           3        148        171        258
    -------------------------------------------------------------------------
    Total exploration and
     development                      6,211     15,382     24,539     34,616
    -------------------------------------------------------------------------
    Net acquisitions (dispositions)       -          -          -     28,682
    -------------------------------------------------------------------------
    Total capital                     6,211     15,382     24,539     63,298
    -------------------------------------------------------------------------
    

    Drilling, completions and tie-in activity represented 82 percent of the
capital spent in the second quarter of 2007 and 91 percent of capital for the
six months ended June 30, 2007 as capital activity focuses on developing the
extensive land base. A revised $39 million capital budget has been approved
for 2007, over 90 percent of which is targeted toward drilling, completion and
tie-in activity. The large undeveloped land base in place entering 2007 is
expected to provide inventory for a drilling focused capital program well
beyond the end of 2007.

    WORKING CAPITAL

    Accounts receivable of $18.3 million at June 30, 2007 was primarily
revenue receivables ($5.5 million) and amounts owing from partners
($12.3 million). Accounts payable at June 30, 2007 of $22.0 million were
mainly comprised of trade payables for capital and operating costs ($10.8
million), royalties ($2.4 million), amounts owing to partners ($3.0 million),
unspent cash calls received from partners ($5.3 million) and capital costs
accrued at the end of the quarter for ongoing drilling and completion
operations ($0.9 million).
    Working capital excluding bank indebtedness was in a deficit position of
$0.9 million at June 30, 2007. Borrowings under the bank line and ongoing cash
flows are expected to fund the working capital deficit.

    LIQUIDITY AND CAPITAL RE

SOURCES The Company plans to fund its current working capital deficit, operations and capital costs with a mix of operating cash flow and debt financing through the bank operating line. An operating bank line was in place for $65.0 million, secured by producing properties at June 30, 2007. At June 30, 2007, $62.7 million was drawn on the bank line. Future capital spending is planned at amounts that can be met with expected Company cash flow as the additional amount available on the operating bank line is limited. NON-GAAP MEASUREMENTS This MD&A contains the term "funds from operations" and "operating netback". As an indicator of the Company's performance, these terms should not be considered an alternative to, or more meaningful than "cash flow from operating activities" or "net income (loss)" as determined in accordance with Canadian generally accepted accounting principles. The Company's determination of funds from operations and operating netback may not be comparable to those reported by other companies, especially those in other industries. Management feels that funds from operations is a useful measure to help investors assess whether the Company is generating adequate cash amounts from its operations to fund its ongoing operations and planned capital program. Operating netback is a useful measure for comparing the Company's price realization and cost performance against industry competitors. The reconciliation between net income and funds from operations for the periods ended June 30 is set out in the following chart: ------------------------------------------------------------------------- Three months ended Six months ended ($000's) June 30 June 30 ------------------------------------------------------------------------- 2007 2006 2007 2006 ------------------------------------------------------------------------- Cash flow provided by (used in) operating activities 1,971 (9,161) 10,836 4,417 Changes in non-cash working capital items related to operating activities 5,811 14,536 3,916 6,851 ------------------------------------------------------------------------- Funds from operations 7,782 5,375 14,752 11,268 ------------------------------------------------------------------------- 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 $0.08 (basic and diluted) for the second quarter of 2007 and $0.16 per share (basic and diluted) for the six months ended June 30, 2007 compared to $0.06 per share for the second quarter of 2006 and $0.14 for the six months ended June 30, 2006. RISKS Primary financial risks relate to volatility of commodity prices. Interest rate and currency exchange rate fluctuations also have an effect on financial results. The effect of changes in the exchange rate between US and Canadian currencies on natural gas prices is not direct, as variations between the regional markets for natural gas are often much greater than can be explained by currency variability. Other risks are related to operations. These risks include, but are not limited to, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, delays or changes in plans with respect to exploration or development projects or capital costs, volatility of commodity prices, currency fluctuations, the uncertainty of reserves estimates, potential environmental liabilities, technology risks, competition for services and personnel, incorrect assessment of the value of acquisitions and failure to realize the anticipated benefits of acquisitions. The foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect operations or financial results are included in a more detailed description of risks in Berens' Annual Information Form on file with Canadian securities regulatory authorities and available on SEDAR at www.sedar.com. Documented environmental health and safety plans are in place as well as a comprehensive emergency response plan to mitigate operating risks. COMMODITY PRICE RISK MANAGEMENT The Company may use financial derivative or fixed price contracts to manage its exposure to fluctuations in commodity prices and foreign currency exchange rates. The Company applies the fair value method of accounting for derivative instruments by initially recording an asset or liability, and recognizing changes in the fair value of the derivative instrument in income. The following is a summary of natural gas price risk management financial derivative contracts in effect as of June 30, 2007. All contracts are priced in Canadian dollars per gigajoule (GJ). The price per GJ can be converted to an approximate price per MCF by multiplying the per GJ price by 1.05. GJ can be converted to an approximate MCF volume by multiplying the GJ volume by 0.95. ------------------------------------------------------------------------- Daily Term of Contract Fixed price per gigajoule quantity (GJ) ------------------------------------------------------------------------- 2,000 April 1 to October 31, 2007 $6.00 floor; $8.50 cap ------------------------------------------------------------------------- 2,000 November 1 to December 31, 2007 $6.00 floor; $11.05 cap ------------------------------------------------------------------------- 2,000 April 1 to October 31, 2007 $7.00 floor; $8.00 cap ------------------------------------------------------------------------- 2,000 November 1 to December 31, 2007 $7.00 floor; $9.85 cap ------------------------------------------------------------------------- 2,000 April 1 to October 31, 2007 $7.25 floor; $8.25 cap ------------------------------------------------------------------------- 2,000 November 1, 2007 to March 31, 2008 $7.25 floor; $8.65 cap ------------------------------------------------------------------------- 2,000 June 1, 2007 to March 31, 2008 $7.50 floor; $9.45 cap ------------------------------------------------------------------------- The fair value of the above natural gas derivative instruments marked to market as at June 30, 2007, results in an unrealized gain position of $1,463,000 compared to an unrealized gain position of $635,000 at December 31, 2006. There was $95,000 of realized gains on derivative instruments in the second quarter of 2007 and $108,000 for the six months ended June 30, 2007. There were no derivative instruments in place during the first quarter or the first six months of 2006. A physical fixed price contract to sell 2,000 GJ per day from January 1 to October 31, 2007 at a price of $7.65 per GJ is also in place for the purpose of reducing exposure to natural gas price volatility. The average floor price of the hedging transactions for 2007, including the fixed price sales contract, is $7.01 per GJ ($7.37 per mcf) with the average ceiling set at $8.75 per GJ ($9.21 per mcf). RELATED PARTY TRANSACTIONS A consulting firm is contracted from time to time in which one of the Company's directors is the chairman and founding partner. The executive services rendered are in the normal course of business and are at normal rates charged by the consulting firm and recorded at the exchange amount. Consulting fees for this firm in the first six months of 2007 were nil (2006 - $58,000). Fees for legal services are paid to a law firm in which the corporate secretary is a partner. The legal services are rendered in the normal course of business at normal rates charged by the law firm. Legal fees for this firm paid in the second quarter of 2007 were $98,000 and $129,000 for the six months ended June 30, 2007 (2006 - $103,000 and $509,000). SHARE DATA As of the date of this MD&A the Company had 93,172,064 issued and outstanding common shares. Additionally, options to purchase 5,419,533 common shares have been issued. DISCLOSURE CONTROLS AND PROCEDURES OVER FINANCIAL REPORTING The Company has established procedures and internal control systems designed to ensure timely and accurate preparation of financial, internal management and other reports. Disclosure controls and procedures are in place designed to ensure all ongoing statutory reporting requirements are met and material information is disclosed on a timely basis. The Chief Executive Officer and the Chief Financial Officer, individually, sign certifications that the financial statements, together with the other financial information included in the regulatory filings, fairly present in all material respects the financial condition, results of operation, and cash flows as of the dates and for the periods represented. INTERNAL CONTROL OVER FINANCIAL REPORTING Management of Berens is responsible for establishing and maintaining adequate internal controls over financial reporting. Internal controls over financial reporting are part of a process designed under the supervision of the Chief Executive Officer and the Chief Financial Officer and effected by the Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company reported on these controls as part of its 2006 continuous disclosure requirements (please refer to the MD&A for the year ended December 31, 2006 available on SEDAR (www.SEDAR.com) and on our website www.berensenergy.com). There have been no changes to internal controls over financial reporting or management's assessment of the design of these internal controls in the period since December 31, 2006. RISKS AND UNCERTAINTIES, CRITICAL ACCOUNTING ESTIMATES AND RECENT ACCOUNTING PRONOUNCEMENTS The MD&A is based on the consolidated financial statements, which have been prepared in Canadian dollars in accordance with GAAP. The application of GAAP requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates are based on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates under different assumptions or conditions. For a discussion of Risks and Uncertainties, Critical Accounting Estimates and Recent Accounting Pronouncements please refer to the audited financial statements and the Annual Information Form for the year ended December 31, 2006 available on SEDAR (www.SEDAR.com) and on our website (www.berensenergy.com). As of January 1, 2007, the Company adopted the Canadian Institute of Chartered Accountants ("CICA") Section 1530 "Comprehensive Income", Section 3251 "Equity", Section 3855 "Financial Instruments - Recognition and Measurement", and Section 3865 "Hedges", which were issued in January 2005. CICA handbook section 1506, "Accounting Changes" was also adopted on January 1, 2007. The adoption of these standards had no effect on the presentation of the financial statements. OUTLOOK Berens has demonstrated steady production growth, reduced operating costs and ongoing drilling success. Production growth has followed the drilling success experienced in late 2006 and in early 2007. During the first six months of 2007 the drilling success has been 84 percent and there has been some moderation in the industry cost structure. These factors are combining to lower the Company's finding and development costs in 2007. Recent weakness in natural gas prices has resulted in a reduction in 2007 capital spending plans as it is not prudent business to aggressively exploit our natural gas assets at low commodity prices. Capital spending for the year is projected at $39 million, down 13 percent compared to the Company's original 2007 plans and will be aligned with cash flow for the remainder of the year. Capital spending for the remainder of the year will be focused in Pembina and Deep Basin where the reserve life of new wells is longest and the wells have the strongest economics. There are currently 75 inventoried drilling locations on existing lands. Debt and working capital balances are at manageable levels with the planned changes to our capital spending plans. With ongoing production and reserve growth management anticipates that the Company will be well positioned to better develop our asset base once natural gas prices return to more acceptable levels. Berens Energy Ltd. Balance Sheets (unaudited) As at, ------------------------------------------------------------------------- (000's) June 30, December 31, 2007 2006 ------------------------------------------------------------------------- ASSETS (note 6) Current Cash and cash equivalents $ 10 $ 10 Accounts receivable 18,263 19,601 Unrealized gain on risk management (note 10) 1,463 635 Prepaid expenses and deposits 1,387 1,412 ------------------------------------------------------------------------- 21,123 21,658 Investments 3 29 Property, plant and equipment (note 4) 175,907 171,178 Goodwill 20,755 20,755 ------------------------------------------------------------------------- $ 217,788 $ 213,620 ------------------------------------------------------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY Current Bank loan (note 6) $ 62,700 50,080 Accounts payable and accrued liabilities 21,998 $ 26,622 Taxes payable 35 29 ------------------------------------------------------------------------- 84,733 76,731 COMMITMENTS (note 7) Asset retirement obligations (note 5) 2,973 2,645 Future income taxes 13,301 14,518 ------------------------------------------------------------------------- 101,007 93,894 Shareholders' equity Capital stock (note 7) 148,263 148,038 Contributed surplus (note 7) 1,723 1,290 Deficit (33,205) (29,602) ------------------------------------------------------------------------- 116,781 119,726 ------------------------------------------------------------------------- $ 217,788 $ 213,620 ------------------------------------------------------------------------- See accompanying notes to the financial statements Berens Energy Ltd. Statements of Operations and Deficit (unaudited) For the three and six months ended June 30, ------------------------------------------------------------------------- (000's) Three months Six months ended June 30, ended June 30, ------------------------------------------------------------------------- 2007 2006 2007 2006 ------------------------------------------------------------------------- Revenue Oil and natural gas revenue $ 16,784 $ 12,737 $ 32,327 $ 26,251 Realized gain on risk management 95 - 108 - ------------------------------------------------------------------------- 16,879 12,737 32,435 26,251 Royalties, net of ARTC (4,140) (2,892) (7,904) (6,882) ------------------------------------------------------------------------- 12,739 9,845 24,531 19,369 Unrealized gain (loss) on risk management (note 10) 2,035 - 828 - ------------------------------------------------------------------------- 14,774 9,845 25,359 19,369 Interest - 1 - 17 ------------------------------------------------------------------------- 14,774 9,846 25,359 19,386 ------------------------------------------------------------------------- Expenses Production 2,426 2,458 5,073 4,351 Transportation 363 261 648 553 Depletion, amortization and accretion 10,623 9,341 19,967 18,476 General and administrative (note 9) 1,095 1,205 2,028 2,397 Stock-based compensation (note 7) 230 219 433 380 Interest 1,070 536 2,025 799 ------------------------------------------------------------------------- 15,807 14,020 30,174 26,956 ------------------------------------------------------------------------- Loss before income taxes (1,033) (4,174) (4,815) (7,570) Income taxes Future expense (recovery) (479) (2,579) (1,217) (3,859) Current expense 3 11 5 17 ------------------------------------------------------------------------- (476) (2,568) (1,212) (3,842) ------------------------------------------------------------------------- Loss and Comprehensive Loss for the period (557) (1,606) (3,603) (3,728) Deficit, beginning of period (32,648) (3,383) (29,602) (1,261) ------------------------------------------------------------------------- Deficit, end of period $(32,205) $ (4,989) $(32,205) $ (4,989) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Loss per share (note 11) Basic and diluted $ (0.01) $ (0.02) $ (0.04) $ (0.04) ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the financial statements Berens Energy Ltd. Statements of Cash Flows (unaudited) For the three and six months ended June 30, ------------------------------------------------------------------------- (000's) Three months Six months ended June 30, ended June 30, ------------------------------------------------------------------------- 2007 2006 2007 2006 ------------------------------------------------------------------------- OPERATING ACTIVITIES Net income (loss) for the period $ (557) $ (1,606) $ (3,603) $ (3,728) Add items not involving cash Depletion, amortization and accretion 10,623 9,341 19,967 18,476 Unrealized risk management (gain) loss (2,035) - (828) - Future income tax expense (recovery) (479) (2,579) (1,217) (3,859) Stock-based compensation 230 219 433 379 ------------------------------------------------------------------------- 7,782 5,375 14,752 11,268 Change in non-cash working capital items related to operating activities (note 9) (5,811) (14,536) (3,916) (6,851) ------------------------------------------------------------------------- Cash flow provided by (used in) operating activities 1,971 (9,161) 10,836 4,417 ------------------------------------------------------------------------- FINANCING ACTIVITIES Change in bank loan 2,720 17,400 12,620 29,830 Proceeds from exercise of stock options 225 - 225 - Net proceeds from private offerings - - - 19,813 ------------------------------------------------------------------------- Cash flow provided by financing activities 2,945 17,400 12,845 49,643 ------------------------------------------------------------------------- INVESTING ACTIVITIES Cash acquired through Berland acquisition - - - 109 Cash component on Berland acquisition - - - (28,682) Proceeds from sale of investment 26 - 26 - Purchase of property and equipment (6,208) (15,234) (24,368) (34,358) Change in non-cash working capital items related to investing activities (note 8) 1,266 6,886 661 (566) ------------------------------------------------------------------------- Cash flow used in investing activities (4,916) (8,348) (23,681) (63,497) ------------------------------------------------------------------------- Decrease in cash and cash equivalents - (109) - (9,437) Cash and cash equivalents, beginning of period 10 144 10 9,472 ------------------------------------------------------------------------- Cash and cash equivalents, end of period $ 10 $ 35 $ 10 $ 35 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the financial statements BERENS ENERGY LTD. Notes to Financial Statements (unaudited) For the three and six months ended June 30, 2007 and 2006 1. NATURE OF OPERATIONS The Company is a full cycle oil and natural gas exploration and production company with activities encompassing land acquisition, geological and geophysical assessment, drilling and completion, and production. The primary areas of operation are in eastern and west central Alberta. Significant capital spending activity occurs in the winter months in the western Canadian oil and natural gas business as many areas are only accessible or best accessed in the winter months when the ground is frozen. Limited capital spending activity tends to occur in the second calendar quarter as the industry experiences "spring break-up" when there is significant water on the ground due to melting snow and roads capacities are limited as winter frost melts and the roads are wet and unable to support heavy loads. Normal oil and gas operations tend to return in the June time frame each year. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The interim financial statements have been prepared by management following the same accounting policies as the most recent annual audited financial statements except as noted below. Certain disclosures, which are normally required to be included in notes to the annual financial statements, are condensed or omitted for interim reporting purposes. Accordingly, these interim financial statements should be read in conjunction with the audited annual financial statements for the year ended December 31, 2006. Certain prior period amounts have been reclassified to conform to current disclosure. As of January 1, 2007, the Company was required to adopt the Canadian Institute of Chartered Accountants ("CICA") Section 1530 "Comprehensive Income", Section 3251 "Equity", Section 3855 "Financial Instruments - Recognition and Measurement", and Section 3865 "Hedges", which were issued in January 2005. Under the new standards, a new financial statement, the Consolidated Statement of Comprehensive Income, has been introduced that will provide for certain gains and losses and other amounts arising from changes in fair value, to be temporarily recorded outside the income statements. In addition, all financial instruments, including derivatives, are to be included in the Company's Balance Sheet and measured, in most cases, at fair values, and requirements for hedge accounting have been further clarified. The Company has adopted these pronouncements. The Company uses fair value accounting for derivative instruments that do not qualify or are not designated as hedges. As of January 1, 2007, the Company was required to adopt revised CICA Section 1506, "Accounting Changes", which provides expanded disclosures for changes in accounting policies, accounting estimates and corrections of errors, which were issued in July 2006. Under the new standard, accounting changes should be applied retrospectively unless otherwise permitted or where impracticable to determine. As well, voluntary changes in accounting policy are made only when required by a primary source of GAAP or when the change results in more relevant and reliable information. The effect of adopting these standards on the Company's financial statements has been minimal. 3. ACQUISITION OF BERLAND EXPLORATION LTD. On January 18, 2006, Berens and Berland Exploration Ltd. ("Berland") closed a previously announced arrangement that saw Berens acquire Berland. Pursuant to the arrangement, shareholders of Berland received $0.96 in cash ($20.0 million) and 0.8784 of a Berens common share (21,083,795 common shares for $53.8 million) for each Berland common share. Additionally, certain option and warrant holders received a differential payment for the difference between their option and warrant strike prices and $3.20 per Berland share ($8.7 million). Pursuant to the Arrangement, Berens also assumed $19.7 million of Berland debt and transaction costs of $0.5 million. The total cost to Berens to acquire the Berland shares was $102.7 million. This acquisition has been accounted for using the purchase method with the Berland results included in the statement of operations from the closing date of January 18, 2006. The following table summarizes the estimated fair value of the assets acquired and liabilities assumed as at the closing date. Assets and liabilities purchased ($000's) ------------------------------------------------------------------------- Cash and cash equivalents 109 Accounts receivable 10,321 Prepaid expenses and deposits 1,488 Petroleum and natural gas properties 97,616 Goodwill 30,288 Accounts payable and accrued liabilities (20,247) Future income taxes (16,111) Asset retirement obligations (715) ------------------------------------------------------------------------- Total cost to acquire Berland 102,749 ------------------------------------------------------------------------- 4. PROPERTY, PLANT AND EQUIPMENT June 30, 2007 December 31, 2006 Accumulated Accumulated depletion and depletion and ($000's) Cost depreciation Cost depreciation ------------------------------------------------------------------------- Petroleum and natural gas properties 264,571 89,059 240,047 69,305 Office and computer equipment 693 298 678 242 ------------------------------------------------------------------------- 265,264 89,357 240,725 69,547 ------------------------------------------------------------------------- Net book value 175,907 171,178 ------------------------------------------------------------------------- At June 30, 2007, costs of $24,202,000 (2006 - $25,907,000) related to undeveloped land have been excluded from the depletion and depreciation calculation. At June 30, 2007 estimated future development costs of $13,018,000 have been included in the depletion and depreciation calculation. A ceiling test was completed at June 30, 2007 resulting in no impairment. 5. ASSET RETIREMENT OBLIGATIONS The total future asset retirement obligations were estimated based on the net ownership interest in all wells and facilities, estimated costs to reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred in future periods. The estimated net present value of the total asset retirement obligations is $2,973,000 as at June 30, 2007 (2006 - $2,305,000) based on a total future liability of $8,031,000 (2006 - $6,187,000). These payments are expected to be made over the next 5 to 15 years. An inflation rate of 2% and a credit adjusted risk free rate of 10% were used to calculate the present value of the asset retirement obligations. The following table reconciles the asset retirement obligations for the six months ended: ($000's) June 30, June 30, 2007 2006 ------------------------------------------------------------------------- Obligation, beginning of the period 2,645 1,223 Increase in obligation during the period 171 258 Obligation assumed from Berland acquisition - 715 Accretion expense 157 109 ------------------------------------------------------------------------- Obligation, end of the period 2,973 2,305 ------------------------------------------------------------------------- 6. BANK OPERATING LINE An agreement with a Canadian bank is in place for an operating bank line totaling $65 million at June 30, 2007. Collateral for the facility consists of a general assignment of book debts and a $75.0 million debenture with a floating charge over all assets of the Company. The bank line is a demand line and carries an interest rate of the Bank's prime rate adjusted for a factor based on the most recent quarterly debt to cash flow calculation. The rate at June 30, 2007 was 7.00 percent (June 30, 2006 - 6.5 percent). On June 30, 2007, $62,700,000 was drawn on the line. 7. CAPITAL STOCK (a) Authorized Capital The authorized capital consists of an unlimited number of preferred shares issuable in series and an unlimited number of common shares without nominal or par value. (b) Common shares issued ------------------------------------------------------------------------- Consideration Number ($000's) ------------------------------------------------------------------------- Balance March 31, 2007 and December 31, 2006 92,947,064 148,038 Exercise of stock options 225,000 225 ------------------------------------------------------------------------- Balance June 30, 2007 93,172,064 148,263 ------------------------------------------------------------------------- Private Placements On October 26, 2006, 6,500,000 flow-through common shares were issued in a private placement at $1.82 per share for cash proceeds of $11,830,000 before agent's commission of $591,500 to finance certain oil and gas expenditures to be incurred in 2006 and 2007. The renouncement of these expenditures was made to the purchasers of these shares during 2006. The actual qualifying expenditures were completed in the second quarter of 2007. (c) Stock Option Plan A stock option plan is in place under which 7,500,000 common shares have been reserved for options to be granted to directors, officers, employees and consultants with terms established by the board of directors. Options granted under the plan generally have a five year term to expiry and vest equally over a three year period commencing on the first anniversary date of the grant. The exercise price of each option equals the closing market price of the Company's common shares on the day prior to the date of the grant. The following table sets forth a reconciliation of the plan activity during the six months ended June 30, 2007 2006 Weighted Weighted average average exercise exercise Number of price ($ Number of price ($ Options per share) Options per share) ------------------------------------------------------------------------- Outstanding, January 1, 4,416,200 1.68 3,513,700 1.56 Granted 1,467,000 1.02 562,000 2.47 Cancelled (238,667) 1.99 - - Exercised (225,000) 1.00 - - ------------------------------------------------------------------------- Outstanding, end of period 5,419,533 1.52 4,075,700 1.70 ------------------------------------------------------------------------- Exercisable 2,632,028 1.44 1,755,689 1.16 ------------------------------------------------------------------------- The following table sets forth additional information relating to the stock options outstanding at June 30, 2007. Options Outstanding Exercisable Options ------------------------------------------------------------------------- Weighted Weighted average average exercise Weighted exercise Weighted price average price average Exercise price Number of ($ per years to Number of ($ per years to range Options share) expiry Options share) expiry ------------------------------------------------------------------------- $0.99 to $1.39 3,216,000 1.06 2.99 1,502,161 1.07 - ------------------------------------------------------------------------- $1.40 to $2.29 1,135,200 1.54 2.56 773,200 1.51 - ------------------------------------------------------------------------- $2.30 to $3.19 928,333 2.83 3.49 310,000 2.83 - ------------------------------------------------------------------------- $3.20 to $4.09 140,000 3.24 3.57 46,667 3.24 - ------------------------------------------------------------------------- 5,419,533 1.52 3.00 2,632,028 1.44 1.87 ------------------------------------------------------------------------- The fair value method for measuring option awards based on the Black Scholes valuation model is used. Key assumptions used for the Black Scholes based valuation of options are: Risk free rate - 4.3 percent; average expected life - 4.5 years; no expected dividend yield; 46 percent volatility. Estimated future forfeiture assumptions are not used in calculations and forfeitures are recognized as they occur. The weighted average option price for options outstanding at June 30, 2007 is $0.59 per option. Based on the fair value method, $230,000 was recorded as compensation expense for the quarter ended June 30, 2007 and $433,000 was recorded as compensation expense for the six months ended June 30, 2007 (2006 - $219,000 and $379,000) with corresponding increases recorded to contributed surplus. (d) Contributed Surplus The following table sets forth the continuity of contributed surplus for the quarter ended June 30, 2007. ($000's) ------------------------------------------------------------------------- Opening balance, December 31, 2006 1,290 Stock based compensation expense 433 ------------------------------------------------------------------------- Closing balance, June 30, 2007 1,723 ------------------------------------------------------------------------- 8. SUPPLEMENTAL CASH FLOW INFORMATION Changes in Non-cash Working Capital For the six months ended June 30, ($000's) 2007 2006 ------------------------------------------------------------------------- Accounts receivable 1,338 (8,831) Prepaid expenses and deposits 26 (2,093) Accounts payable and accrued liabilities (4,624) 12,017 Taxes payable 5 (72) Non-cash working capital acquired (note 3) - (8,438) ------------------------------------------------------------------------- (3,255) (7,417) Change in non-cash working capital related to investing activities 661 (566) ------------------------------------------------------------------------- Change in non-cash working capital related to operating activities (3,916) (6,851) ------------------------------------------------------------------------- Cash interest and taxes paid For the three and six months ended June 30, Three Three Six Six ($000's) months months months months 2007 2006 2007 2006 ------------------------------------------------------------------------- Income and other taxes - 1 - 137 Interest 1,070 525 2,025 783 ------------------------------------------------------------------------- 9. RELATED PARTY TRANSACTIONS A consulting firm is contracted from time to time in which one of the Company's directors is the chairman and founding partner. The executive services rendered are in the normal course of business and are at normal rates charged by the consulting firm and recorded at the exchange amount. Consulting fees for this firm in the first six months of 2007 were nil (2006 - $58,000). Fees for legal services are paid to a law firm in which the corporate secretary is a partner. The legal services are rendered in the normal course of business at normal rates charged by the law firm. Legal fees for this firm paid in the second quarter of 2007 were $98,000 and $129,000 for the six months ended June 30, 2007 (2006 - $103,000 and $509,000). 10. FINANCIAL INSTRUMENTS Fair Value of Financial Instruments Financial instruments recognized on the balance sheets consist of cash and cash equivalents, accounts receivable, deposits, investments, accounts payable, bank loans and financial derivatives used to manage natural gas price risk. Cash, investments, cash equivalents and financial derivatives are designated as "held-for-trading". Deposits are designated as "held-to- maturity". Accounts receivable and bank loans are designated as "loans and receivables" and accounts payable are designated as "other liabilities". The fair value of these financial instruments approximates their carrying amounts due to their short terms to maturity except for the financial derivatives which values are outlined below. (a) Credit Risk Accounts receivable are with customers, sales agents and joint venture partners in the petroleum and natural gas business and are subject to the usual credit risks. The Company mitigates this risk by entering into transactions with long-standing, reputable counterparties and partners. If significant amounts of capital are to be spent on behalf of a joint venture partner the partner is "cash called" in advance of the capital spending taking place. (b) Interest Rate Risk The Company is exposed to fluctuations in interest rates on its bank debt. (c) Foreign Exchange Risk The Company is exposed to the risk of changes in the Canadian/US dollar exchange rates on sales of commodities that are denominated in U.S. dollars or directly influenced by U.S. dollar benchmark prices. Commodity price risk management transactions are denominated in Canadian dollars which mitigates the effect of currency volatility on commodity sales volumes that are covered by commodity price hedges. (d) Commodity Price Risk Management The following is a summary of natural gas price risk management derivative contracts in effect as of June 30, 2007. All contracts are priced in Canadian dollars per gigajoule (GJ) and are designated as "held-for-trading. The price per GJ can be converted to an approximate price per MCF by multiplying the per GJ price by 1.05. GJ volume can be converted to an approximate MCF volume by multiplying the GJ volume by 0.95. ------------------------------------------------------------------------- Daily Term of Contract Fixed price per gigajoule quantity (GJ) ------------------------------------------------------------------------- 2,000 April 1 to October 31, 2007 $6.00 floor; $8.50 cap ------------------------------------------------------------------------- 2,000 November 1 to December 31, 2007 $6.00 floor; $11.05 cap ------------------------------------------------------------------------- 2,000 April 1 to October 31, 2007 $7.00 floor; $8.00 cap ------------------------------------------------------------------------- 2,000 November 1 to December 31, 2007 $7.00 floor; $9.85 cap ------------------------------------------------------------------------- 2,000 April 1 to October 31, 2007 $7.25 floor; $8.25 cap ------------------------------------------------------------------------- 2,000 November 1, 2007 to March 31, 2008 $7.25 floor; $8.65 cap ------------------------------------------------------------------------- 2,000 June 1, 2007 to March 31, 2008 $7.50 floor; $9.45 cap ------------------------------------------------------------------------- The fair value of the above natural gas derivative instruments marked-to- market as at June 30, 2007, results in an unrealized gain of $1,463,000 compared to an unrealized gain of $635,000 at December 31, 2006. There were $95,000 in realized gains derivative instruments in the quarter ended June 30, 2007 and $108,000 in realized gains for the six months ended June 30, 2007. There were no derivative instruments outstanding for the second quarter or first six months ended June 30, 2006. 11. PER SHARE INFORMATION The weighted average number of common shares outstanding for the quarter ended June 30, 2007 of 92,973,713 was used to calculate basic and diluted loss per share (2006 - 86,447,064). The weighted average number of common shares outstanding for the six month period ended June 30, 2007 was 92,960,461 (2006 - 83,534,863). All outstanding options have not been included in the calculation of per share information as they were anti- dilutive. Caution Regarding Forward Looking Information This press release contains forward looking information within the meaning of applicable securities laws. Forward looking statements may include estimates, plans, expectations, forecasts, guidance or other statements that are not statements of fact. Forward looking information in this Press Release includes, but is not limited to, statements with respect to capital expenditures and related allocations, production volumes, production mix and commodity prices. Forward-looking statements and information are based on current beliefs as well as assumptions made by and information currently available to Berens concerning anticipated financial performance, business prospects, strategies and regulatory developments. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect. By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: crude oil and natural gas price volatility, exchange rate and interest rate fluctuations, availability of services and supplies, market competition, uncertainties in the estimates of reserves, the timing of development expenditures, production levels and the timing of achieving such levels, the Company's ability to replace and increase oil and gas reserves, the sources and adequacy of funding for capital investments, future growth prospects and current and expected financial requirements of the Company, the cost of future abandonment and site restoration, the Company's ability to enter into or renew leases, the Company's ability to secure adequate product transportation, changes in environmental and other regulations and general economic conditions. The forward-looking statements contained in this press release are made as of the date of this press release, and Berens does not undertake any obligation to up-date publicly or to revise any of the included forward- looking statements, whether as a result of new information, future events or otherwise. This cautionary statement expressly qualifies the forward- looking statements contained in this press release. %SEDAR: 00020114E

For further information:

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

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