Berens Energy Ltd.

August 10, 2007 23:59 ET

Berens Energy Ltd. Releases Results for the Three and Six Months Ended June 30, 2007

CALGARY, ALBERTA--(Marketwire - Aug. 10, 2007) -



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%
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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
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Total 6,208 15,234 (57%) 24,368 34,358 (28%)
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Net wells completed
(No.) 1 9 7 17
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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%
-------------------------------------------------------------------------
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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
---------------------
($000's except as noted) Q2 Q1
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Sales volumes:
Natural gas (mcf/day) 19,919 18,705
Oil and natural gas liquids (bbl/day) 560 499
Barrels of oil equivalent (bbl/day) 3,880 3,617
-------------------------------------------------------------------------
Financial:
Net revenue 12,643 11,793
Net (loss) (557) (3,043)
per share - basic ($/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
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Net wells completed: (No.)
Natural gas 1 6
Oil - -
Dry - 1
-------------------------------------------------------------------------
Total 1 7
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2006
--------------------------------------------
($000's except as noted) Q4 Q3 Q2 Q1
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Sales volumes:
Natural gas (mcf/day) 18,440 17,355 17,224 16,631
Oil and natural gas liquids
(bbl/day) 483 479 494 420
Barrels of oil equivalent
(bbl/day) 3,556 3,372 3,364 3,192
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Financial:
Net revenue 11,213 9,536 9,846 9,523
Net (loss) (21,951) (2,662) (1,606) (2,121)
per share - basic
($/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
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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.



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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.



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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 RESOURCES

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.

less than less than
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.

Contact Information

  • Berens Energy Ltd.
    Dell P. Chapman
    V.P. Finance & CFO
    (403) 303-3267

    OR

    Berens Energy Ltd.
    Daniel F. Botterill
    President & Chief Executive Officer
    (403) 303-3262