Berens Energy Ltd.

May 11, 2007 23:59 ET

Berens Energy Ltd. Releases Financial Results for the First Quarter Ended March 31, 2007

CALGARY, ALBERTA--(Marketwire - May 11, 2007) - Berens Energy Ltd. (TSX:BEN)



FINANCIAL AND OPERATING HIGHLIGHTS

-------------------------------------------------------------------------
($ Cdn thousands, Three months
except as noted) ended March 31,
-------------------------------------------------------------------------
2007 2006 % Change
-------------------------------------------------------------------------
Sales volume
Natural gas (mcf/day) 18,705 16,631 12%
Oil and ngls (bbl/day) 499 420 19%
boe/day (6 to 1) 3,617 3,192 13%
-------------------------------------------------------------------------
Revenue net of royalties 11,793 9,523 24%
Net income (loss) (3,043) (2,121) (44%)
Per share (basic and diluted) $(0.03) $(0.03) -
Funds from operations(1) 6,973 5,893 18%
Per share (basic and diluted)(1) $0.07 $0.07 -
-------------------------------------------------------------------------
Capital costs
Exploration and development 17,078 15,588
Land and seismic 1,071 3,058
Other 180 588
-------------------------------------------------------------------------
Total 18,329 19,234 (2%)
-------------------------------------------------------------------------
Net wells completed (No.) 7 7
Net working capital (deficit)
- including bank debt (67,468) (45,907)
-------------------------------------------------------------------------
Shares outstanding
End of period (000's) 92,947 86,447 7%
-------------------------------------------------------------------------
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.


First Quarter 2007 Operating Highlights

- Production - Q1 2007 production averaged 3,617 boe/d, up 13 percent
over Q1 2006. Ongoing drilling in Pembina, final tie-ins of a
November 2006 drilling program in Lanfine and a winter drilling
program in Marten Hills delivered the first quarter volume growth.
Significant drilling took place in the first quarter of 2007 with
tie-in activity weighted toward the end of the quarter. Twenty-one
(11.3 net) wells were tied in during the quarter with five wells
awaiting completion or tie-in at the end of the quarter. March
production averaged 3,744 boe/d as 12 wells came on production
throughout March. Our April production estimate is 3,925 boe/d.

- Production Costs - Costs averaged $8.12 per boe in Q1 2007, up 23%
compared to $6.59 per boe in Q1 2006. Transportation costs were 17%
lower in the first quarter of 2007 compared to the first quarter of
2006. On a combined basis, production and transportation costs were
$8.99 in the first quarter of 2007, up 18 percent compared to $7.61
in the first quarter of 2006.

- Funds from Operations - Funds from operations Q1 2007 were
$7.0 million ($0.07 per share), up 18% compared to Q1 2006 funds from
operations of $5.9 million ($0.07 per share). Higher production in Q1
2007 and stable year-over-year prices contributed to the increase. On
a per share basis, funds from operations were unchanged due to
additional shares issued mainly for the acquisition of Berland.

- Drilling - A total of 16 wells (7.1 net) were drilled in the first
quarter resulting in 13 (6.0 net) natural gas wells and 3 (1.1 net)
unsuccessful wells for a net success rate of 86 percent. In our key
growth a mbina and the Deep Basin we had drilling success of 5 for 5
and 4 for 4 respectively. Drilling will re-start in mid-June, after
spring break-up, with an ongoing program in Pembina and a 12 well
Lanfine program scheduled for July.

- Land - Berens total undeveloped land (owned and option) currently
stands at 140,000 net acres. Ninety-eight percent of the undeveloped
lands are located in the four core areas of Pembina, Deep Basin,
Lanfine and Marten Hills. This land base sets up a diverse and active
drilling program for the balance of 2007 and beyond. All remaining
wells in the 2007 capital program are already approved and are on
existing lands.
greater than greater than

Report from Management

The first quarter of 2007 picked up where we left off at the end of 2006
with continued success with the drill bit and ongoing production gains. We
continue to add reserves in a cost effective manner. Finding and development
costs in the first quarter remain near the level we experienced in our
successful fourth quarter of 2006. We drilled 5 for 5 in Pembina and 4 for 4
in the Deep Basin along with a 4 for 7 success rate in our developing Marten
Hills play for an overall success rate of 81 percent (86 percent on a net
working interest basis). Pembina drilling was once again strong while our Deep
Basin success was particularly gratifying as we consider it our riskiest area
but also an area that can deliver strong, large reserve wells. Two of our four
wells in the Deep Basin look very strong and we are excited about returning to
Deep Basin drilling in the fourth quarter when we estimate the area will be
dry enough to conduct operations.

We remain heavily weighted to natural gas in our production mix and the
price of natural gas has been supportive in the first quarter and continues to
be stable into the second quarter. Service costs which were unsustainably high
at this time last year have moderated somewhat and we expect further
improvements in our capital and operating cost structures as we come out of
break-up in June.

We spent approximately 40 percent of our 2007 capital budget in the first
quarter as Marten Hills is winter access only and the Deep Basin is best
drilled in winter. We are pleased with the results of the first quarter and
are on track to spend $45 million in capital for 2007 as communicated earlier.
Our land base continues to be a strong asset and will provide locations for
our entire 2007 drilling program. In fact, the remaining 30 wells in the
remaining 2007 capital plan are already approved, on existing lands and we are
preparing to drill them on schedule.

Our recent drilling success is beginning to translate into volume growth
with strong economic returns at current commodity prices. We are optimistic
that natural gas prices will remain supportive and perhaps further strengthen
in the second half of the year. We are on track with our 2007 plans and remain
excited about our prospects for the remainder of the year.

Sincerely,

(Signed)
Robert D. Steele
Chief Executive Officer


Berens Energy Ltd.
First Quarter 2007
(unaudited)
Management's Discussion and Analysis ("MD&A")
May 10, 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 March 31, 2006
interim financial statements. This MD&A was prepared using information that is
current as of May 10, 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
--------
($000's except as noted) Q1
-------------------------------------------------------------------------
Sales volumes:
Natural gas (mcf/day) 18,705
Oil and natural gas liquids (bbl/day) 499
Barrels of oil equivalent (bbl/day) 3,617
-------------------------------------------------------------------------
Financial:
Net revenue 11,793
Net (loss) (3,043)
per share - basic ($/share) $(0.03)
per share - diluted ($/share) $(0.03)
Capital costs 18,329
Shares outstanding (000's) 92,947
Bank debt 59,980
Working capital (deficit)
including bank debt (67,468)
-------------------------------------------------------------------------
Per unit information:
Natural gas price ($/mcf) $7.75
Oil and liquids price ($/barrel) $55.24
Oil equivalent price ($/boe) $47.72
Operating netback ($/boe) $27.16
-------------------------------------------------------------------------
Net wells completed: (No.)
Natural gas 6
Oil -
Dry 1
-------------------------------------------------------------------------
Total 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
--------------------------------------
($000's except as noted) Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Sales volumes:
Natural gas (mcf/day) 11,537 10,832 10,250 9,155
Oil and natural gas liquids
(bbl/day) 176 165 200 233
Barrels of oil equivalent
(bbl/day) 2,099 1,970 1,908 1,759
-------------------------------------------------------------------------
Financial:
Net revenue 9,537 7,667 5,754 4,910
Net income (loss) (475) 534 887 (441)
per share - basic ($/share) $(0.01) $0.01 $0.02 $(0.01)
per share - diluted ($/share) $(0.01) $0.01 $0.02 $(0.01)
Capital costs 12,346 7,165 3,423 9,462
Shares outstanding (000's) 57,163 52,961 46,427 46,427
Bank debt - - 10,080 10,480
Working capital (deficit)
including bank debt 4,273 (2,137) (13,121) (13,216)
-------------------------------------------------------------------------
Per unit information:
Natural gas price ($/mcf) $11.26 $9.16 $7.29 $6.91
Oil and liquids price ($/barrel) $41.92 $57.47 $33.11 $30.81
Oil equivalent price ($/boe) $65.47 $55.05 $42.61 $40.05
Operating netback ($/boe) $39.78 $34.07 $24.81 $21.12
-------------------------------------------------------------------------
Net wells completed: (No.)
Natural gas 9 7 3 5
Oil 1 0 0 0
Dry 2 2 1 2
-------------------------------------------------------------------------
Total 12 9 4 7
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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 first 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. Until the first quarter of 2007 no commodity price hedges
have been in place and the Company has been fully exposed to variability in
commodity prices.

RESULTS OF OPERATIONS

Production Volume

Production volume averaged 3,617 boe/d for the first quarter of 2007, up
13 percent compared to 3,192 boe/d in the first quarter of 2006 and up two
percent compared to the fourth quarter of 2006. Natural gas represented 86
percent of production in the fourth quarter of 2006 with the remaining
production being 13 percent light oil and natural gas liquids and one percent
conventional heavy oil. Ongoing drilling in Pembina, final tie-ins of a
November 2006 drilling program in Lanfine and a winter drilling program in
Marten Hills delivered the first quarter volume growth. Significant drilling
took place in the first quarter of 2007 with tie-in activity weighted toward
the end of the quarter. Twenty-one (11.3 net) wells were tied in during the
quarter with five wells awaiting completion or tie-in at the end of the
quarter. March production averaged 3,744 boe/d as 12 wells came on production
during the month.

Production Revenue

Natural gas prices averaged $7.75 per mcf for the first quarter of 2007
compared to $7.72 per mcf in the first quarter of 2006. Oil and liquids prices
averaged $49.82 and $57.17 per barrel respectively in the first quarter of
2007 for a blended price of $55.24 per barrel, up eight percent from the first
quarter 2006 blended oil and liquids price of $51.07 per barrel. Oil prices
are lower than light benchmark prices as 60 percent of our oil production is
heavy oil from Alsask. On a boe basis, prices averaged $47.72 in the first
quarter of 2007, up four percent compared to $46.09 per boe in the first
quarter of 2006.

Revenue was up 15 percent in the first quarter of 2007 compared to the
first quarter of 2006 as both volume and prices increased.



-------------------------------------------------------------------------
Volumes and prices Three months
ended
March 31
-------------------------------------------------------------------------
2007 2006 Change
-------------------------------------------------------------------------
Production revenue ($000's) 15,557 13,513 15%
-------------------------------------------------------------------------
Production volume
Natural gas (mcf/d) 18,705 16,631 12%
Oil and liquids (bbl/d) 466 420 19%
BOE (bbl/d) 3,617 3,192 13%
Prices
-------------------------------------------------------------------------
Natural gas ($/mmcf) 7.75 7.72 -
-------------------------------------------------------------------------
Oil and liquids ($/bbl) 55.24 51.07 8%
-------------------------------------------------------------------------
BOE ($/boe) 47.72 46.09 4%
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Royalties

Royalties averaged 24 percent of revenue for the first quarter of 2007
compared to 29 percent in the first quarter of 2006. Lower royalties in the
first quarter of 2007 compared to the first quarter of 2006 are mainly due to
first quarter 2006 royalty calculations being based on high reference prices
from the late 2005 period when natural gas was over $10.00 per mcf.

On an ongoing basis, royalties are expected to average approximately 24
percent of revenues without the go-forward benefit of ARTC which has been
rescinded effective January 1, 2007. Royalty expense of $3.8 million was
recorded in the first quarter of 2007, down six percent compared to the first
quarter of 2006 reflecting higher revenue in the 2007 period offset partially
by a lower royalty rate in 2007.



-------------------------------------------------------------------------
Royalties Three months
ended
March 31
-------------------------------------------------------------------------
2007 2006 Change
-------------------------------------------------------------------------
Royalty expense ($000'S) 3,764 3,990 (6%)
Royalty cost per boe $11.56 $13.89 (17%)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Production Expenses

Production expenses were $8.12 per boe in the first quarter of 2007, up
23 percent compared to $6.59 per boe in the first quarter of 2006. A larger
proportion of production incurs higher processing costs for the liquids rich
Pembina and Deep Basin natural gas in 2007 compared to 2006 when dry gas in
eastern Alberta represented a larger part of production. The Company acquired
an interest in a major Pembina processing plant in December 2006 which will
reduce processing costs for natural gas produced in a portion of the Pembina
area. With ongoing volume increases and cost management, it is expected future
per unit operating expenses will trend below the $8.00 per boe level.

First quarter 2007 production expenses were $2.6 million, up 40 percent
compared to the first quarter of 2006 due to higher volumes and higher per
unit costs.



less than less than
-------------------------------------------------------------------------
Production expenses Three months
ended
March 31
-------------------------------------------------------------------------
2007 2006 Change
-------------------------------------------------------------------------
Production expenses ($000's) 2,642 1,893 40%
Production expenses per boe $8.12 $6.59 23%
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Transportation costs of $0.3 million in the first quarter of 2007 were
unchanged from $0.3 million in the first quarter of 2006 as higher volume was
offset by lower per unit costs.

Operating Netback (1)

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



-------------------------------------------------------------------------
Quarterly Operating Netbacks Three months
($'s per boe) ended
March 31
-------------------------------------------------------------------------
2007 2006
-------------------------------------------------------------------------
Sales price 47.72 46.09
Less:
Royalties (net of ARTC) 11.56 13.89
Production expenses 8.12 6.59
Transportation charges 0.87 1.02
-------------------------------------------------------------------------
Operating netback 27.16 24.59
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 down 16 percent in the first quarter of 2007 compared to
the first quarter of 2006. Costs in the first quarter of 2007, compared to the
first quarter of 2006, benefited by general and administrative cost recoveries
from partners on capital projects operated by Berens. In early 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 $3.46 per boe for the first quarter of
2007, down 27 percent compared to $4.71 per boe in the first quarter of 2006.
There were no general and administrative costs capitalized in the first
quarter 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 administrative expenses Three months
ended
March 31
-------------------------------------------------------------------------
2007 2006 Change
-------------------------------------------------------------------------
G&A expenses ($000's) 1,136 1,353 (16%)
G&A expenses per boe $3.46 $4.71 (27%)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Interest Expense

Interest expense was $1.0 million in the first quarter of 2007 compared
to $0.3 million in the first quarter of 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 were higher than funds from
operations resulting in higher average debt levels in the first quarter of
2007 compared to the first quarter of 2006. The interest rate on the bank line
was also 1.25 percent higher in the first quarter of 2007 compared to the
first quarter of 2006.

Depletion, Amortization and Accretion

Depletion, amortization and accretion ("DA&A") totaled $9.3 million
($28.78 per boe) in the first quarter of 2007 compared to $9.1 million ($31.80
per boe) in the first quarter of 2006. Drilling results have improved in the
latter part of 2006 and early 2007 and new reserves have been added at
significantly lower per unit costs compared to the first half of 2006.



-------------------------------------------------------------------------
Depletion, Amortization and Accretion Three months
ended
March 31
-------------------------------------------------------------------------
2007 2006 Change
-------------------------------------------------------------------------
DA&A expenses ($000's) 9,343 9,135 3%
DA&A expenses per boe $28.78 $31.80 (9%)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Income Taxes

The Company does not expect to pay current income tax during 2007 as
there are ample capital cost pools and expected future capital spending to
shelter taxable income. A small amount of current taxes for capital taxes has
been recorded for the first quarter of 2007.

Future tax recovery was $0.7 million for the first quarter of 2007
compared to a recovery of $1.3 million for the first quarter of 2006 as income
tax rates were higher in the 2006 period.

NET INCOME (LOSS)

The net loss for the first quarter of 2007 was $3.0 million ($0.03 per
share) compared to a loss of $2.1 million ($0.03 per share) in the first
quarter of 2006. The higher 2007 loss resulted primarily from a $1.2 million
swing in the unrealized amount from hedging activities from a gain position of
$0.6 million at December 31, 2006 to a loss position of $0.6 million on March
31, 2007. Excluding the unrealized hedging position change, the net loss was
lower in 2007 compared to 2006 due to higher production volume, stable
commodity prices and lower depletion rates.

CAPITAL COSTS

Capital costs were $18.3 million in the first quarter of 2007 compared to
$19.1 million in the first quarter of 2006. The first quarter 2007 capital
program was drilling focused with activity in Pembina, Deep Basin and Marten
Hills which is a winter access only area. A total of 16 wells (7.1 net) were
drilled in the first quarter of 2007, similar to the totals in the first
quarter of 2007 when seven net wells were drilled.



-------------------------------------------------------------------------
($000's) Three months
ended March 31,
-------------------------------------------------------------------------
2007 2006
-------------------------------------------------------------------------
Drilling and completion 11,793 12,180
Equipping and tie-in 5,285 3,408
Land 107 1,560
Geological and geophysical 964 1,498
Office and other 12 478
-------------------------------------------------------------------------
Total 18,161 19,124
Asset retirement obligation 168 110
-------------------------------------------------------------------------
Total exploration and development 18,329 19,234
-------------------------------------------------------------------------
Net acquisitions (dispositions) - -
-------------------------------------------------------------------------
Total capital 18,329 19,234
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Drilling, completions and tie-in activity represented 93 percent of the
capital spent in the first quarter of 2007 compared to 82 percent in the first
quarter of 2006. A larger component of the capital program was spent on land
and seismic in earlier years to build an inventory of land and drilling
prospects. A $45 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 $25.7 million at March 31, 2007 was primarily
revenue receivables ($5.7 million) and amounts owing from partners ($18.6
million) and capital advances to partners for drilling projects
($0.5 million). Accounts payable at March 31, 2007 of $33.9 million were
mainly comprised of trade payables for capital and operating costs ($20.9
million), royalties ($2.4 million), amounts owing to partners ($2.0 million)
and capital costs accrued at the end of the quarter for ongoing drilling and
completion operations ($2.2 million).
Working capital excluding bank indebtedness was in a deficit position of
$7.4 million at March 31, 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 $67.50
million, secured by producing properties at March 31, 2007. At March 31, 2007,
$60.0 million was drawn on the bank line.

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 March 31 is set out in the following chart:

-------------------------------------------------------------------------
($000's) Three months
ended
March 31
-------------------------------------------------------------------------
2007 2006
-------------------------------------------------------------------------
Cash flow provided by operating activities 8,865 13,578
Changes in non-cash working capital items
related to operating activities (1,892) (7,685)
-------------------------------------------------------------------------
Funds from operations 6,973 5,893
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Funds from operations are also presented on a per share basis consistent
with the calculation of net loss per share, whereby per share amounts are
calculated using the weighted average number of shares outstanding. Funds from
operations per share were $0.07 (basic and diluted) for the first quarter of
2007 compared to $0.07 per share for the first quarter of 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
derivative contracts in effect as of March 31, 2007. All contracts are priced
in Canadian dollars per gigajoule (GJ). The price per GJ can be converted to
an approximate price per MCF by multiplying the per GJ price by 1.05. GJ can
be converted to an approximate MCF volume by multiplying the GJ volume by
0.95.



-------------------------------------------------------------------------
Daily
quantity
(GJ) Term of Contract Fixed price per gigajoule
-------------------------------------------------------------------------
2,000 January 1 to March 31, 2007 $6.00 floor; $11.05 cap
-------------------------------------------------------------------------
2,000 April 1 to October 31, 2007 $6.00 floor; $8.50 cap
-------------------------------------------------------------------------
2,000 November 1 to December 31, 2007 $6.00 floor; $11.05 cap
-------------------------------------------------------------------------
2,000 January 1 to March 31, 2007 $7.00 floor; $9.85 cap
-------------------------------------------------------------------------
2,000 April 1 to October 31, 2007 $7.00 floor; $8.00 cap
-------------------------------------------------------------------------
2,000 November 1 to December 31, 2007 $7.00 floor; $9.85 cap
-------------------------------------------------------------------------
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 March 31, 2007, results in an unrealized loss position of
$572,000 compared to an unrealized gain position of $635,000 at December 31,
2006. There was $13,000 of realized gains on derivative instruments in the
first quarter of 2007 which is included in first quarter revenue. There were
no derivative instruments in place during the first quarter 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 was also entered into for the
purpose reducing exposure to natural gas price volatility.

RELATED PARTY TRANSACTIONS

A consulting firm is contracted from time to time in which one of the
Company's directors is the chairman and founding partner. The executive
services rendered are in the normal course of business and are at normal rates
charged by the consulting firm and recorded at the exchange amount. Consulting
fees for this firm in the first quarter of 2007 were nil (Q1 2006 - $42,000).
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 first quarter of 2007 were $109,000 (Q1 2006 - $404,000).

SHARE DATA

As of the date of this MD&A the Company had 92,947,064 issued and
outstanding common shares. Additionally, options to purchase 5,268,200 common
shares have been issued.

DISCLOSURE CONTROLS AND PROCEDURES OVER FINANCIAL REPORTING

The Company has established procedures and internal control systems
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 is a process designed under the supervision of the Chief
Executive Officer and the Chief Financial Officer and effected by the Board of
Directors, management and other personnel to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally
accepted accounting principles.
The Company reported on these controls as part of the 2006 audit (please
refer to the audited financial statements 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 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 Corporation 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 affect on the presentation of
the financial statements.

OUTLOOK

Production volumes are growing with the drilling success experienced in
late 2006 and in early 2007. The undeveloped land in the Company's portfolio
will provide all the remaining drilling locations for the balance of 2007
which will see drilling in Pembina, Lanfine and Deep Basin. The recent success
illustrates the increasing understanding that our technical team has of the
newer areas of Marten Hills, Pembina and Deep Basin. The intention is to
continue to remain focused in the four core areas that have been established
to take advantage of the high level of technical expertise and experience we
have developed in each of these areas.
The 2007 capital program will be diversified across the four core areas.
Pembina, which is considered to have low risk with strong return potential
will receive over 60 percent of the 2007 capital program with the balance of
2007 split between the lower risk shallow gas programs in Lanfine and Marten
Hills and the higher risk/reward Deep Basin area which has the potential for
large reserve discoveries. The 2007 capital plan is drilling focused with over
90 percent of capital budgeted toward drilling and completion activities with
the balance directed toward land and seismic acquisitions.
Access to services appears to be improving throughout western Canada. We
expect some moderation of the industry cost structure as we go forward but
capital management and a focus on cost reduction will still be important
aspects of our business when carrying out the balance of our 2007 capital
program.



Berens Energy Ltd.
Balance Sheets
(unaudited)
As at,

-------------------------------------------------------------------------
(000's) March 31, December 31,
2007 2006
-------------------------------------------------------------------------
ASSETS (note 6)
Current
Cash and cash equivalents $ 10 $ 10
Accounts receivable 25,686 19,601
Unrealized gain on risk management(note 10) - 635
Prepaid expenses and deposits 1,327 1,412
-------------------------------------------------------------------------
27,023 21,658

Investments 29 29
Property, plant and equipment(note 5) 180,239 171,178
Goodwill 20,755 20,755
-------------------------------------------------------------------------
$ 228,046 $ 213,620
-------------------------------------------------------------------------
-------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Bank loan (note 6) $ 59,980 50,080
Accounts payable and accrued liabilities 33,906 $ 26,622
Unrealized loss on risk management (note 10) 572 -
Taxes payable 33 29
-------------------------------------------------------------------------
94,491 76,731
-------------------------------------------------------------------------

COMMITMENTS (note 7)
Asset retirement obligations (note 5) 2,888 2,645
Future income taxes 13,781 14,518
-------------------------------------------------------------------------
111,160 93,894
Shareholders' equity
Capital stock (note 7) 148,038 148,038
Contributed surplus (note 7) 1,493 1,290
Deficit (32,645) (29,602)
-------------------------------------------------------------------------
116,886 119,726
-------------------------------------------------------------------------
$ 228,046 $ 213,620
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the financial statements

Berens Energy Ltd.
Statements of Operations and Deficit
(unaudited)
For the quarter ended March 31,
-------------------------------------------------------------------------
(000's)
-------------------------------------------------------------------------
2007 2006
-------------------------------------------------------------------------
Revenue
Oil and natural gas revenue $ 15,557 $ 13,513
Royalties, net of ARTC (3,764) (3,990)
-------------------------------------------------------------------------
11,793 9,523
Unrealized loss on risk management (note 10) (1,207) -
-------------------------------------------------------------------------
10,586 9,523
Interest - 17
-------------------------------------------------------------------------
10,586 9,540
-------------------------------------------------------------------------
Expenses
Production 2,643 1,893
Transportation 285 293
Depletion, amortization and accretion 9,343 9,135
General and administrative 933 1,193
Stock-based compensation (note 7) 203 160
Interest 956 262
-------------------------------------------------------------------------
14,363 12,936
-------------------------------------------------------------------------
Loss before income taxes (3,777) (3,396)
Income taxes
Future expense (recovery) (737) (1,281)
Current expense 3 6
-------------------------------------------------------------------------
(734) (1,275)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income (loss) and Comprehensive income
(loss) for the period (3,043) (2,121)
Deficit, beginning of period (29,602) (1,262)
-------------------------------------------------------------------------
Deficit, end of period $ (32,645) $ (3,383)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income (loss) per share (note 11)
Basic and diluted $(0.03) $(0.03)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the financial statements



Berens Energy Ltd.
Statements of Cash Flows
(unaudited)
For the quarter ended March 31,

-------------------------------------------------------------------------
(000's)
-------------------------------------------------------------------------
2007 2006
-------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income (loss) for the period $ (3,043) $ (2,121)
Add items not involving cash
Depletion, amortization and accretion 9,343 9,135
Unrealized risk management (gain) loss 1,207 -
Future income tax expense (recovery) (737) (1,281)
Stock-based compensation 203 160
-------------------------------------------------------------------------
6,973 5,893
Change in non-cash working capital items
related to operating activities (note 9) 1,892 7,685
-------------------------------------------------------------------------
Cash flow provided by operating activities 8,865 13,578
-------------------------------------------------------------------------
FINANCING ACTIVITIES
Change in bank loan 9,900 12,430
Net proceeds from private offerings - 19,813
-------------------------------------------------------------------------
Cash flow provided by financing activities 9,900 32,243
-------------------------------------------------------------------------
INVESTING ACTIVITIES
Cash acquired through Berland acquisition - 109
Cash component on Berland acquisition - (28,682)
Purchase of property and equipment (18,161) (19,124)
Change in non-cash working capital items
related to investing activities (note 8) (604) (7,452)
-------------------------------------------------------------------------
Cash flow used in investing activities (18,765) (55,149)
-------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents - (9,328)
Cash and cash equivalents, beginning of period 10 9,472
-------------------------------------------------------------------------
Cash and cash equivalents, end of period $ 10 $ 144
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the financial statements


BERENS ENERGY LTD.
Notes to Financial Statements
(unaudited)
First quarter ended March 31, 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 Corporation 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 Sheets
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.

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

March 31, 2007 December 31, 2006
Accumulated Accumulated
depletion depletion
and depre- and depre-
($000's) Cost ciation Cost ciation
-------------------------------------------------------------------------
Petroleum and
natural gas properties 258,363 78,544 240,047 69,305
Office and computer
equipment 690 270 678 242
-------------------------------------------------------------------------
259,053 78,814 240,725 69,547
-------------------------------------------------------------------------
Net book value 180,239 171,178
-------------------------------------------------------------------------


At March 31, 2007, costs of $25,907,000 (2006 - $10,391,000) related to
undeveloped land have been excluded from the depletion and depreciation
calculation. At March 31, 2007 estimated future development costs of
$13,018,000 have been included in the depletion and depreciation
calculation. A ceiling test was completed at March 31, 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 $2,888,000 as at
March 31, 2007 (2006 - $2,098,000) based on a total future liability of
$8,019,000 (2006 - $5,281,000). 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
quarters ended:



($000's) March 31, March 31,
2007 2006
-------------------------------------------------------------------------
Obligation, beginning of the period 2,645 1,223
Increase in obligation during the period 167 110
Obligation assumed from Berland acquisition - 715
Accretion expense 76 50
-------------------------------------------------------------------------
Obligation, end of the period 2,888 2,098
-------------------------------------------------------------------------


6. BANK OPERATING LINE

An agreement with a Canadian bank is in place for an operating bank line
totaling $67.5 million at March 31, 2007 which total declines by
$1.25 million per month starting on April 30, 2007 until it reaches
$65 million. 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
March 31, 2007 was 6.75 percent (March 31, 2006 - 5.5 percent). On
March 31, 2007, $59,980,000 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
-------------------------------------------------------------------------


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 are expected to be 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
through March 31, 2007.



2007 2006

Weighted Weighted
average average
exercise exercise
price price
Number of ($ per Number of ($ per
Options share) Options share)
-------------------------------------------------------------------------
Outstanding, beginning
of period 4,416,200 1.68 3,513,700 1.56
Granted 1,057,000 0.99 267,500 2.95
Cancelled (205,000) 1.19 - -
Exercised - - - -
-------------------------------------------------------------------------
Outstanding, end of
period 5,268,200 1.53 3,781,200 1.66
-------------------------------------------------------------------------
Exercisable 2,696,360 1.39 1,539,853 1.16
-------------------------------------------------------------------------

The following table sets forth additional information relating to the
stock options outstanding at March 31, 2007.

Options Outstanding Exercisable Options
-------------------------------------------------------------------------
Weighted Weighted
average average
exercise Weighted exercise Weighted
Exercise Number price average Number price average
price of ($ per years to of ($ per years to
range Options share) expiry Options share) expiry
-------------------------------------------------------------------------
$0.99
to
$1.39 3,039,000 1.05 2.76 1,727,161 1.06 -
-------------------------------------------------------------------------
$1.40
to
$2.29 1,149,200 1.54 2.83 650,866 1.50 -
-------------------------------------------------------------------------
$2.30
to
$3.19 930,000 2.83 3.74 268,333 2.89 -
-------------------------------------------------------------------------
$3.20
to
$4.09 150,000 3.24 3.82 50,000 3.24 -
-------------------------------------------------------------------------
5,268,200 1.53 2.86 2,696,360 1.39 1.89
-------------------------------------------------------------------------


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 March 31, 2007 is $0.57
per option. Based on the fair value method, for the quarter ended
March 31, 2007, $203,000 (2006 - $160,000) was recorded for options
issued and outstanding with a corresponding increase recorded to
contributed surplus.

(d) Contributed Surplus

The following table sets forth the continuity of contributed surplus for
the quarter ended March 31, 2007.



($000's)
-------------------------------------------------------------------------
Opening balance, December 31, 2006 1,290
Stock based compensation expense 203
-------------------------------------------------------------------------
Closing balance, March 31, 2007 1,493
-------------------------------------------------------------------------

8. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in Non-cash Working Capital
For the quarters ended March 31,

2007 2006
($000's)
-------------------------------------------------------------------------
Accounts receivable (6,085) (6,574)
Prepaid expenses and deposits 86 (1,667)
Accounts payable and accrued liabilities 7,284 16,953
Taxes payable 3 (41)
Non-cash working capital acquired (note 3) - (8,438)
-------------------------------------------------------------------------
(1,288) 233
Change in non-cash working capital related
to investing activities (604) (7,452)
-------------------------------------------------------------------------
Change in non-cash working capital related
to operating activities (1,892) 7,685
-------------------------------------------------------------------------


Cash interest and taxes paid
For the 3 months ended March 31,

($000's) 2007 2006
-------------------------------------------------------------------------
Income and other taxes - 98
Interest 956 262
-------------------------------------------------------------------------


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 quarter of 2007 were nil (Q1
2006 - $42,000). 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 first quarter of 2007 were $109,000
(Q1 2006 - $404,000).

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 and bank indebtedness are
designated as "held-to-maturity". Accounts receivable are designated as
"loans and receivables" and accounts payable are designated as "other
liabilities". The fair value of these financial instruments approximates
their carrying amounts due to their short terms to maturity except for
the financial derivatives which values are outlined below.

(a) Credit Risk

Accounts receivable are with customers, sales agents and joint venture
partners in the petroleum and natural gas business and are subject to the
usual credit risks. The Company mitigates this risk by entering into
transactions with long-standing, reputable counterparties and partners.
If significant amounts of capital are to be spent on behalf of a joint
venture partner the partner is "cash called" in advance of the capital
spending taking place.

(b) Interest Rate Risk

The Company is exposed to fluctuations in interest rates on its bank
debt.

(c) Foreign Exchange Risk

The Company is exposed to the risk of changes in the Canadian/US dollar
exchange rates on sales of commodities that are denominated in U.S.
dollars or directly influenced by U.S. dollar benchmark prices.

(d) Commodity Price Risk Management

The following is a summary of natural gas price risk management
derivative contracts in effect as of March 31, 2007. All contracts are
priced in Canadian dollars per gigajoule (GJ) and are designated as
"held-for-trading. The price per GJ can be converted to an approximate
price per MCF by multiplying the per GJ price by 1.05. GJ volume can be
converted to an approximate MCF volume by multiplying the GJ volume by
0.95.



-------------------------------------------------------------------------
Daily
quantity
(GJ) Term of Contract Fixed price per gigajoule
-------------------------------------------------------------------------
2,000 January 1 to March 31, 2007 $6.00 floor; $11.05 cap
-------------------------------------------------------------------------
2,000 April 1 to October 31, 2007 $6.00 floor; $8.50 cap
-------------------------------------------------------------------------
2,000 November 1 to December 31, 2007 $6.00 floor; $11.05 cap
-------------------------------------------------------------------------
2,000 January 1 to March 31, 2007 $7.00 floor; $9.85 cap
-------------------------------------------------------------------------
2,000 April 1 to October 31, 2007 $7.00 floor; $8.00 cap
-------------------------------------------------------------------------
2,000 November 1 to December 31, 2007 $7.00 floor; $9.85 cap
-------------------------------------------------------------------------
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 March 31, 2007, results in an unrealized loss of $572,000
compared to an unrealized gain of $635,000 at December 31, 2006. There
were $13,000 in realized gains derivative instruments in the quarter
ended March 31, 2007 (Q1, 2006 - nil).

11. PER SHARE INFORMATION

The weighted average number of common shares outstanding for the quarter
ended March 31, 2007 of 92,947,064 was used to calculate basic and
diluted income (loss) per share (2006 - 80,590,305). 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.
    Robert D. Steele
    Chief Executive Officer
    (403) 303-3264