Berens Energy Ltd.

March 27, 2008 23:59 ET

Berens Energy Ltd. Releases Financial Results for the Fourth Quarter and Year Ended December 31, 2007

CALGARY, ALBERTA--(Marketwire - March 27, 2008) -



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FINANCIAL AND OPERATING HIGHLIGHTS

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($ Cdn thousands, Three months Twelve months

except as noted) ended December 31, ended December 31,

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% %

2007 2006 Change 2007 2006 Change

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Sales volume

Natural gas

(mcf/day) 19,018 18,440 3% 18,981 17,420 9%

Oil and ngls

(bbl/day) 626 483 30% 564 469 20%

boe/day (6 to 1) 3,796 3,556 7% 3,728 3,373 11%

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Revenue net of

royalties 13,214 11,213 18% 49,609 40,118 24%

Net income (loss) (680) (21,951) (27,440) (28,340)

Per share (basic

and diluted) $(0.01) $(0.24) $(0.30) $(0.33)

Funds from

operations(1) 7,991 6,118 31% 29,554 22,471 32%

Per share (basic

and diluted)(1) $0.09 $0.07 29% $0.32 $0.26 23%

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Capital costs

Exploration and

development 5,986 11,474 35,468 52,807

Land and seismic 412 896 3,807 3,583

Other 4 37 56 295

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Total 6,402 12,407 (48%) 39,331 56,685 (31%)

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Net wells

completed (No.)

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Natural gas 3 6 14 25

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Oil - - 2 -

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Dry - 1 2 4

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Total 3 7 18 29

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Net working capital

(deficit) -

including bank

debt (59,516) (56,271) 6% (59,516) (56,271) 6%

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Shares outstanding

End of period

(000's) 93,172 92,947 - 93,172 92,947 -

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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.

Message to the shareholders

2007 has been a strong operational year for Berens. We entered 2007 excited
about momentum that we had established with strong drilling success in the second
half of 2006. We were achieving repeated drilling success in Pembina and were
convinced we had found an advantage in the area based on strong integration of
technology, geology and geophysics. We were committed to disciplined cost management
for both drilling and operations as industry cost pressures remained high. We kept
a keen eye on natural gas prices and adjusted our capital spending program to ensure
that we could fund most of our spending with cash flow. Natural gas prices were
uncertain and very weak at times during 2007 so we had to manage our business carefully.

We delivered:

- Drilling success continued with an overall success rate of 86% on our

drilling program. More importantly we had 100% success in our key

growth areas of Pembina and Deep Basin.

- We further defined our Pembina play and have significantly reduced

the risk profile in the area using our integrated technical approach,

evident not only in our drilling success rate but also in our

improved reserve additions.

- We applied a disciplined approach to cost control which delivered

wells and production at significantly lower costs when combined with

easing cost pressures in our industry.

The results are evident:

- Average annual production increased 11% year over year

- Long term value was strengthened with a reserves increase of 16% and

a lengthening of our reserve life index ("RLI") from 6 to 6.5 years.

We replaced production by 2 times with new reserves. All done with

the drill bit.

- Finding and development costs were $12.85 including future

development capital (National Instruments 51-101 definition). We

believe these results are first quartile performance in our industry.

- New wells in Pembina, targeting trends based on our technology, were

40 percent better in terms of production and reserves than we have

experienced historically.

- Operating costs averaged $7.55 for 2007, down 4% from 2006 and we

were drilling wells by the end of 2007 at costs 25% lower than a year

ago.


We are well positioned for 2008

So far in 2008 we are 6 for 6 in Pembina and 2 for 3 in our exploratory efforts
in Deep Basin, continuing with the success we had in 2007. Costs continue to come
down and we are drilling wells for costs that we have not seen since 2004. We have
an extensive inventory of 100 drilling prospects across our three core areas, all
on our existing land base. Most of our prospects are seismically defined with low
risk. The 2008 capital program is focused on the drill bit with 90 percent of our
planned capital targeted for drilling, completion, equipping and tie in activities.
We continue to add land in Pembina, with an additional nine sections added already
in 2008, building further our strong land position in this key growth area.

Natural gas prices appear more stable and strong after a year of uncertainty and weakness.
There is optimism in our industry that the stronger natural gas prices are more sustainable
in 2008 and beyond. We continue to be vigilant and ready to adjust our spending as
commodity prices increase or decrease.

Berens is prospect rich and looks forward to opportunities to step up our activities as
we see strength in natural gas prices. Our staff is committed and enthused about our
success and looking forward to build on the momentum established in 2007. I would like
to offer special thanks to our staff and management for their efforts and achievements
and to our board of directors for their guidance and support in 2007.

Our shareholders experienced a difficult year in 2007 as the oil and gas sector fell
out of favor and selling was indiscriminate. We thank those who stood with us through
2007 and we believe in time, you will reap the rewards of our operational success.

Sincerely,

Daniel F. Botterill

President & Chief Executive Officer



Fourth Quarter 2007 Operating Highlights

- Drilling - A total of 4 wells (2.9 net) were drilled in the fourth

quarter, all successful natural gas wells. On a full year basis in

2007, 29 (17.6 net) wells have been drilled with 23 (13.5 net)

natural gas wells, 2 (2.0 net) oil wells and four (2.1 net)

unsuccessful wells for a net success rate of 86 percent. In the key

growth areas of Pembina (12 wells) and the Deep Basin (4 wells),

100 percent drilling success was achieved.

- Reserves - Total working interest proved plus probable reserves as at

December 31, 2007 were 9,016,000 boe, an increase of 16 percent

compared to proved plus probable reserves at December 31, 2006. On a

per share basis proved plus probable reserves also grew 16 percent to

96.8 boe/1000 shares outstanding from 83.5 boe/1000 shares

outstanding. Reserves growth came entirely from the successful 2007

exploration and development drilling program. Berens replaced

production 2.0 times through the addition of new proved plus probable

reserves from the exploration and development drilling program (net

of revisions). The reserve growth in 2007 was accomplished with a net

capital program that was funded almost entirely with cash flow as

debt and working capital grew only $2.9 million during 2007.

- Production - Q4 2007 production averaged 3,796 boe/d, up 7 percent

over Q4 2006 and up 5 percent over the third quarter of 2007.

Production additions in the fourth quarter of 2007 were delivered by

ongoing drilling and tie-ins in Pembina and the completions and tie

in of a summer drilling program in Lanfine. On a full year basis,

volume in 2007 averaged 3,728 boe/d, up 11 percent compared to 2006.

- Production Costs - Costs averaged $7.23 per boe in Q4 2007, down 18%

compared to Q4 2006. For the 2007 year production costs have averaged

$7.55 per boe, down 4 percent compared to 2006. Berens continues to

have success in reducing unit operating cost.

- Funds from Operations - Funds from operations in Q4 2007 was

$8.0 million ($0.09 per share), up 31 percent compared to Q4 2006

funds from operations of $6.1 million ($0.07 per share) and up

17 percent from Q3 2007. Higher production in Q4 2007 was

complemented by reduced operating costs and higher commodity prices

to deliver the increase. December 31, 2007 debt and working capital

was 1.86 times annualized Q4 funds from operations.

- Land - Berens total undeveloped land currently stands at 100,000 net

acres almost all of which is now owned with little remaining land yet

to be earned on farm-ins. Ninety-eight percent of the undeveloped

lands are located in our three core areas of Pembina, Deep Basin and

Lanfine. The 2008 drilling program is based entirely on existing

Berens' controlled undeveloped acreage on which there exist an

inventory of 100 locations.


RESERVES

Berens' oil and gas reserves were independently evaluated by GLJ Petroleum Consultants ("GLJ"). The evaluation was completed using the reserves definitions in the Canadian Oil and Gas Evaluation Handbook and the Canadian Securities Administrators National Instrument 51-101 ("NI 51-101"). Total working interest proved plus probable reserves as at December 31, 2007 were 9,016,000 boe, an increase of 16 percent compared to proved plus probable reserves at December 31, 2006. On a per share basis proved plus probable reserves also grew 16 percent to 96.8 boe/1000 shares outstanding from 83.5 boe/1000 shares outstanding. Reserves growth came entirely from the successful 2007 exploration and development drilling program. The table below summarizes Berens' working interest reserves on a gross basis (before deduction for royalties) as at December 31, 2007 using forecast prices and costs based on the GLJ January 1, 2008 price forecast.



SUMMARY OF OIL AND GAS RESERVES(1)

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WORKING INTEREST

RESERVES OIL AND LIQUIDS NATURAL GAS

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2007 2006 Percent 2007 2006 Percent

RESERVES CATEGORY (Mbbl) (Mbbl) Change (MMcf) (MMcf) Change

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PROVED

Developed

Producing 1,050 743 +41% 21,855 18,770 +16%

Developed

Non-Producing 82 148 -44% 1,440 4,266 -66%

Undeveloped 198 100 +98% 4,746 3,381 +40%

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TOTAL PROVED 1,330 991 +34% 28,041 26,417 +6%

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PROBABLE 665 496 +34% 14,085 11,256 +25%

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TOTAL PROVED

PLUS PROBABLE 1,995 1,487 +34% 42,126 37,673 +12%

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WORKING INTEREST

RESERVES BOE

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2007 2006 Percent

RESERVES CATEGORY (Mbbl) (Mbbl) Change

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PROVED

Developed

Producing 4,693 3,871 +21%

Developed

Non-Producing 322 858 -62%

Undeveloped 989 664 +49%

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TOTAL PROVED 6,003 5,393 +11%

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PROBABLE 3,013 2,372 +27%

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TOTAL PROVED

PLUS PROBABLE 9,016 7,765 +16%

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WORKING INTEREST BEFORE TAX 8% BEFORE TAX 10%

RESERVES PRESENT VALUE(1) PRESENT VALUE(1)

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2007 2006 Percent 2007 2006 Percent

RESERVES CATEGORY ($000's) ($000's) Change ($000's) ($000's) Change

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PROVED

Developed

Producing 91,839 73,824 +24% 86,962 69,432 +25%

Developed

Non-Producing 5,316 14,977 -65% 4,842 14,013 -65%

Undeveloped 7,685 4,626 +66% 6,640 3,731 +78%

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TOTAL PROVED 104,840 93,427 +12% 98,444 87,176 +13%

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PROBABLE 39,020 35,174 +11% 34,215 31,073 +10%

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TOTAL PROVED

PLUS PROBABLE 143,860 128,601 +12% 132,659 118,249 +12%

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(1) It should not be assumed that the present values of estimated future

net cash flows shown above are representative of the fair market

value of the reserves. There is no assurance that such price and cost

assumptions will be attained and variances could be material. The

recovery and reserves estimates of crude oil, NGL and natural gas

reserves provided herein are estimates only and there is no guarantee

that the estimated reserves will be recovered. Actual crude oil,

natural gas and NGL reserves may be greater than or less than the

estimates provided herein.


Based on fourth quarter 2007 average production volume the proved plus probable reserve life index at December 31, 2007 is 6.5 years, up from 6.0 years compared to December 31, 2006. The majority of reserve growth in 2007 came at Pembina and Deep Basin where wells typically have long reserve life. Oil and liquids represent 22 percent of December 31, 2007 reserves, up from 19 percent at December 31, 2006 as the majority of the reserves added through 2007 have been from liquids rich natural gas wells in Pembina and the Deep Basin.

The following table reconciles the reserve additions from capital spending, dispositions and revisions to opening estimates.



RECONCILIATION OF

COMPANY INTEREST RESERVES

BY BARREL OF OIL EQUIVALENT

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Proved Plus

Proved Probable

FACTORS (Mboe) (Mboe)

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December 31, 2006 5,393 7,765

Discoveries 174 238

Extensions 1,691 2,738

Infill drilling - -

Technical revisions 191 (259)

Acquisitions - -

Dispositions (88) (108)

Production(1) (1,358) (1,358)

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December 31, 2007 6,003 9,016

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GLJ has also calculated the effects of the Alberta New Royalty Framework ("NRF") on the December 31, 2007 asset value based on low and high case assumptions as defined by GLJ and other reserve engineering firms in Calgary. The evaluation established that on a worst case basis, net asset value would remain unchanged at $132.7 million on a before tax 10% discount basis. In the high case, net asset value would increase by over 3 percent to $137.0 million. This is consistent with the Company's expectations based on its current asset mix and GLJ's December 31, 2007 price assumptions.

All calculations converting natural gas to crude oil equivalent have been made using a ratio of six thousand cubic feet ("mcf") of natural gas to one barrel of crude oil 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.

Finding and Development Costs

Capital spending in 2007 was $32.9 million including $1.4 million spent on land and net of the Marten Hills disposition ($6.75 million). Net future capital as at December 31, 2007 is estimated at $21.2 million compared to $15.4 million at December 31, 2006. Proved plus probable finding and development costs for 2007 excluding land capital and including the change in future development capital of $5.8 million was $12.85 per boe. Including technical revisions, proved plus probable finding and development costs were $14.12 per boe in 2007. It should be noted that GLJ did not include 2007 reserve additions for first quarter drilling results in Marten Hills as it was sold prior to year end. The Company spent $4.6 million in Marten Hills in the first quarter of 2007 that is included in its 2007 capital spending of $32.9 million.

Finding and development costs for Berens seismic, exploration and development activities for each of the past three years and on a three year cumulative basis are outlined below:



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Three

Year

2007 2006 2005 Totals

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Total capital for seismic,

exploration and development

(excluding land capital) ($000's) 31,059 53,101 25,706 109,866

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Future development capital -

proved ($000's) 15,112 12,600 1,240 13,872

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Future development capital -

proved plus probable ($000's) 21,187 15,400 1,380 19,807

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Reserve extensions, discoveries

and dispositions - proved (Mboe) 1,777 2,222 946 4,945

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Reserve extensions, discoveries

and dispositions - proved plus

probable (Mboe) 2,868 3,271 1,273 7,412

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Finding and development costs -

proved (per boe) $18.89 $29.01 $28.48 $25.02

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Finding and development costs -

proved plus probable (per boe) $12.85 $20.52 $21.28 $17.50

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Three year average finding and development costs on a proved plus probable
basis for exploration and development activities were $17.50 per boe, an
improving trend from the three year average at the end of 2006 of $18.19
due to strong results in 2007. Early 2008 drilling success in Pembina and
the Deep Basin points to continued strong finding and development cost efficiency.

Net Asset Value

The Company's net asset value at December 31, 2007 based on the year end
reserves as evaluated by GLJ, including land and debt and working capital
is presented below. The net asset value as determined below may not
necessarily reflect the current market value of the Company.

Category ($000s) $/share(1)

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Proved reserves (discounted at 10%)(2) 98,444 1.06

Probable reserves (discounted at 10%)(2) 34,215 0.37

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132,659 1.43

Land (book value) 21,159 0.23

Debt & Working Capital Deficit (59,516) (0.64)

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Net Asset Value - December 31, 2007 94,302 1.03

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(1) Per share values are based on basic shares outstanding of 93,172,064

as there were no stock options in the money as at December 31, 2007.

(2) Based on an independent evaluation by GLJ effective December 31, 2007

using forecast prices and costs and calculated before deducting

future income taxes.


Berens Energy Ltd.

Annual and Fourth Quarter 2007

Management's Discussion and Analysis ("MD&A")

March 26, 2008

OVERVIEW

Berens Energy Ltd. ("Berens" or the "Company") is a full cycle oil and natural gas exploration and production company with a concentrated production and land base in Eastern Alberta, Pembina and Deep Basin regions of Alberta.

All calculations converting natural gas to crude oil equivalent have been made using a ratio of six thousand cubic feet (six "mcf") of natural gas to one barrel of crude equivalent. Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six mcf of natural gas to one barrel of crude oil equivalent is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

The following discussion of financial position and results of operations should be read in conjunction with the Company's December 31, 2007 audited financial statements and notes thereto. This MD&A was prepared using information that is current as of March 26, 2008 unless otherwise noted.

STRATEGY AND OBJECTIVES

The Company established key performance metrics for 2008 that are evaluated and reviewed quarterly within the context of a planned $30 million capital program plan that is funded by cash flow. Key performance metrics include production volume growth, finding and development costs, reserve additions, operating and corporate netbacks and return on investment.

Volume growth is an important equity market measurement that is reported frequently and measures the ability of the capital spending program to add near term cash flow. The Company expects to exit 2008 with production in a range from 4,100 to 4,300 boe/d, up over 10 percent compared to fourth quarter 2007 average production of 3,796 boe per day.

Longer term value is achieved by adding oil and natural gas reserves at low cost. The Company expects to replace 1.5 times 2008 production with new reserves at finding and development costs below $15.00/boe. Operating and corporate netbacks are expected to be $28.00 and $22.00 respectively assuming a $7.00 per mcf price for natural gas and $80.00 per barrel for oil. Resulting recycle ratios based on the above factors are over 1.9 times on an operating netback basis and 1.5 times based on the corporate netback. Both of these measures deliver long term added value.

FORWARD LOOKING INFORMATION

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

Additional information on the Company can be found on the SEDAR website at www.sedar.com.



QUARTERLY INFORMATION

2007

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($000's except as noted) Q4 Q3 Q2 Q1

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Sales volumes:

Natural gas (mcf/day) 19,018 18,288 19,919 18,705

Oil and natural gas

liquids (bbl/day) 626 570 560 499

Barrels of oil equivalent 3,796 3,618 3,880 3,617

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Financial:

Net revenue 13,214 11,864 12,739 11,793

Net (loss) (680) (23,157) (557) (3,043)

per share - basic

($/share) $(0.01) $(0.25) $(0.00) $(0.03)

per share - diluted

($/share) $(0.01) $(0.25) $(0.00) $(0.03)

Capital costs 6,718 8,541 6,208 18,329

Shares outstanding (000's) 93,172 93,172 93,172 92,947

Bank debt 53,900 50,800 62,700 59,980

Working capital (deficit)

including bank debt (59,516) (59,300) (64,644) (68,502)

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Per unit information:

Natural gas price ($/mcf) $6.52 $5.94 $7.60 $7.75

Oil and liquids price

($/barrel) $71.66 $64.11 $58.98 $55.24

Oil equivalent price ($/boe) $44.48 $40.14 $47.51 $47.72

Operating netback ($/boe) $26.85 $22.95 $27.88 $27.16

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Net wells completed: (No.)

Natural gas 3 5 1 5

Oil - 2 - -

Dry - 1 - 1

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Total 3 8 1 6

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2006

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($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 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 (56,271) (61,783) (57,789) (47,357)

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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

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Net wells completed: (No.)

Natural gas 7 3 9 4

Oil - - - -

Dry 1 1 1 3

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Total 8 4 10 7

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Ongoing drilling has delivered the production increases for 2006 and 2007 with the decline in production for the third quarter of 2007 caused mainly by the disposition of Marten Hills production of 250 boe per day. There have been no further material acquisitions or dispositions.

RESULTS OF OPERATIONS

Production Volume

Production volume averaged 3,796 boe/d for the fourth quarter of 2007, up seven percent compared to 3,556 boe/d in the fourth quarter of 2006 and up five percent compared to the third quarter of 2007. Natural gas represented 84 percent of production in the fourth quarter of 2007 with the remaining production being 15 percent light oil and natural gas liquids and one percent conventional heavy oil. Light oil and natural gas liquids have increased as a percent of production as most of the production growth has come from liquids rich natural gas wells in Pembina and Deep Basin. Ongoing drilling success throughout 2007 has delivered steady volume increases.

A six well program was drilled in Lanfine in July. The five successful wells were not completed and put on stream until late October as the decision was made to delay production from these wells until expected improvements in natural gas prices later in the year which contributed to the growth in production from the third to the fourth quarter of 2007. The growth in production was delivered despite the sale of 250 boe/d in September 2007 at Marten Hills.

Volume averaged 3,728 boe/d for the year ended December 31, 2007, up 11 percent compared to 3,373 boe/d for the year ended December 31, 2006. Key reasons for the production growth were improved drilling success rates, primarily in Pembina combined with average well results that were 40 percent better than budgeted on a production and reserve basis. An integrated approach combining petrophysics, geophysics and geological mapping has enabled the Company to target specific trends that have been drilled at higher success rates and for better individual well results than have been experienced in the past. With few new wells to be brought on stream in early 2008, first quarter 2008 production is expected to average approximately 3,800 boe/d, flat to fourth quarter 2007 production. Production improvement is expected beginning in the second quarter of 2008 as the wells from the winter drilling program come on stream in March.

Production Revenue

Natural gas prices averaged $6.52 per mcf for the fourth quarter of 2007 down nine percent compared to $7.13 per mcf in the fourth quarter of 2006. Oil and liquids prices averaged $67.47 and $73.86 per barrel respectively in the fourth quarter of 2007 for a blended price of $71.66 per barrel, up 39 percent from the fourth quarter 2006 blended oil and liquids price of $51.54 per barrel. On a boe basis, prices averaged $44.48 in the fourth quarter of 2007, up one percent compared to $43.96 per boe in the fourth quarter of 2006. Revenue before results from hedging was up eight percent in the fourth quarter of 2007 compared to the fourth quarter of 2006 as production volume increased and prices were up slightly. An additional $2.68 per boe was realized from hedging gains during the fourth quarter of 2007 increasing total revenue per boe to $47.16.

Natural gas prices averaged $6.96 per mcf for the year ended December 31, 2007, up three percent compared to $6.75 per mcf in the year ended December 31, 2006. Oil and liquids prices averaged $60.57 and $64.08 per barrel respectively in the year ended December 31, 2007 for a blended price of $63.02 per barrel, up 10 percent from the year ended December 31, 2006 blended oil and liquids price of $57.48 per barrel. On a boe basis, prices averaged $44.98 in the year ended December 31, 2007, up five percent compared to $42.86 per boe in the year ended December 31, 2006. Revenue before results from hedging was up 16 percent in the year ended December 31, 2007 compared to the year ended December 31, 2006 as both volume and prices increased. An additional $1.65 per boe was realized from hedging gains during the year ended December 31, 2007 for total revenue per boe of $46.63. There were no volumes hedged during 2006.



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Volumes and prices Three months Year

ended December 31 ended December 31

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2007 2006 Change 2007 2006 Change

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Production revenue

($000's) 15,563 14,386 8% 61,281 52,810 16%

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Production volume

Natural gas

(mcf/d) 19,018 18,440 3% 18,981 17,420 9%

Oil and liquids

(bbl/d) 626 483 30% 564 469 20%

BOE (bbl/d) 3,796 3,556 7% 3,728 3,373 11%

Prices

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Natural gas ($/mcf) 6.52 7.13 -8% 6.96 6.75 3%

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Oil and liquids

($/bbl) 71.66 51.54 39% 63.02 57.48 10%

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BOE ($/boe) 44.48 43.96 1% 44.98 42.86 5%

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BOE ($/boe

including hedging) 47.16 43.96 7% 46.63 42.86 9%

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Royalties

Royalties averaged 21 percent of revenue for the fourth quarter of 2007 compared to 22 percent in the fourth quarter of 2006. Royalties have trended lower on a percent of revenue basis as more wells are drilled on owned and earned lands compared to earlier periods when a higher percentage of wells were drilled under farm-in arrangements that provided for overriding royalties to the farmor. Royalties averaged 23 percent of revenue for the year ended December 31, 2007 compared to 24 percent for the year ended December 31, 2006.

Royalty expense of $3.3 million was recorded in the fourth quarter of 2007, up four percent compared to the fourth quarter of 2006 reflecting higher volume offset partially by lower per unit royalty rates. Royalty expense of $13.9 million was recorded in the year ended December 31, 2007, up 10 percent compared to the year ended December 31, 2006 due to higher production volume and lower per unit royalty rates.



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Royalties Three months Year

ended December 31 ended December 31

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2007 2006 Change 2007 2006 Change

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Royalty expense

($000's) 3,286 3,173 4% 13,915 12,692 10%

Royalty cost per boe $9.41 $9.92 (5%) $10.23 $10.67 (4%)

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GLJ Petroleum Consultants ("GLJ") has evaluated the effects of the Alberta New Royalty Framework on the December 31, 2007 asset value based on low and high case assumptions as defined by GLJ and other reserve engineering firms in Calgary. The evaluation established that on a worst case basis, Berens' net asset value would remain unchanged at $132.7 million on a before tax 10% discount basis. In the best case, Berens' net asset value would increase by over 3 percent to $137.0 million. This is consistent with Berens' expectations based on its current asset mix and GLJ's price assumptions.

Production Expenses

Production expenses were $7.23 per boe in the fourth quarter of 2007, down 18 percent compared to $8.88 per boe in the fourth quarter of 2006. Fourth quarter 2007 costs were lower on a per unit basis as production has increased and vigilance on costs remains a key objective. 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 $7.55 per boe in the year ended December 31, 2007, down four percent compared to $7.89 per boe in the year ended December 31, 2006. With ongoing volume increases and cost management, it is expected future per unit operating expenses will be in the $7.50 per boe range.

Fourth quarter 2007 production expenses were $2.5 million, down 13 percent compared to the fourth quarter of 2006 due to lower per unit costs. Production expenses for the year ended December 31, 2007 were $10.3 million, up six percent compared to the year ended December 31, 2006 mainly due to higher volumes.



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

Production expenses Three months Year

ended December 31 ended December 31

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

2007 2006 Change 2007 2006 Change

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

Production expenses

($000's) 2,524 2,905 (13%) 10,280 9,721 6%

Production expenses

per boe $7.23 $8.88 (18%) $7.55 $7.89 (4%)

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

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

Transportation costs increased 14 percent in the fourth quarter of 2007
compared to the fourth 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 exclusive of results from hedging. Fourth
quarter 2007 operating netbacks improved due to higher per boe prices,
lower per unit royalty rates and lower operating costs.

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

Quarterly

Operating Netbacks Three months Year

($'s per boe) ended December 31 ended December 31

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

2007 2006 Change 2007 2006 Change

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

Sales price 44.48 43.96 1% 44.98 42.86 5%

Less:

Royalties

(net of ARTC) 9.41 9.92 (5%) 10.23 10.67 (4%)

Production expenses 7.23 8.88 (18%) 7.55 7.89 (4%)

Transportation

charges 0.99 0.92 8% 0.96 0.91 5%

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

Operating netback 26.85 24.23 11% 26.24 23.39 12%

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

Operating netback

including hedging 29.53 24.23 22% 27.89 23.39 19%

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

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

(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 $1.6 million in the fourth quarter of 2007, up 68 percent compared to the fourth quarter of 2006. Stock based compensation was higher as total outstanding options increased. Also, increased incentive bonus payments were paid in the fourth quarter of 2007 for the strong operating results achieved during 2007. In the year ended December 31, 2007 G&A expenses were $5.3 million, up 11 percent compared to the year ended December 31, 2006.

On per unit basis, general and administrative costs were $4.69 per boe for the fourth quarter of 2007, up 57 percent compared to $2.99 per boe in the fourth quarter of 2006. For the year ended December 31, 2007 per unit G&A costs were $3.92 per boe, almost unchanged from $3.90 per boe for the year ended December 31, 2006 as volume increases offset the dollar increase in costs for the per unit calculation. There were no general and administrative costs capitalized in the fourth quarters or for the years 2007 or 2006.

Staff levels are expected to remain fairly constant in 2008. Per unit general and administrative costs are expected to decline as production levels increase.



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

General and

administrative Three months Year

expenses ended December 31 ended December 31

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

2007 2006 Change 2007 2006 Change

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

G&A expenses

($000's) 1,401 844 66% 4,433 4,090 8%

Stock based

compensation 239 133 80% 905 716 26%

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

1,640 977 68% 5,338 4,806 11%

G&A expenses per boe $4.69 $2.99 57% $3.92 $3.90 1%

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

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


Interest Expense

Interest expense was $0.9 million in the fourth quarter of 2007 compared to $1.0 million in the fourth quarter of 2006. For the year ended December 31, 2007 interest expense was $4.0 million compared to $2.6 million for the year ended December 31, 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. Since the first quarter of 2007 the Company's capital program has been funded by cash flows and debt has declined. Average interest rates on the bank line were similar comparing 2007 to 2006.



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

Interest Expense Three months Year

ended December 31 ended December 31

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

2007 2006 Change 2007 2006 Change

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

Interest expenses

($000's) 949 972 (2%) 4,028 2,627 53%

Interest expenses

per boe $2.72 $2.97 (8%) $2.96 $2.13 39%

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

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

Depletion, Amortization and Accretion

Depletion, amortization and accretion ("DA&A") totaled $9.4 million
($26.85 per boe) in the fourth quarter of 2007, down two percent compared
to $9.6 million ($29.24 per boe) in the fourth quarter of 2006. Ongoing
drilling success and low cost reserve additions have brought down per
boe DA&A rates eight percent in the fourth quarter of 2007 compared to
the fourth quarter of 2006. In the year ended December 31, 2007 DA&A
totaled $39.2 million ($28.79 per boe) up seven percent but four percent
lower on a boe basis compared to $36.7 million ($29.85 per boe) for the
year ended December 31, 2006.

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

Depletion,

Amortization Three months Year

and Accretion ended December 31 ended December 31

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

2007 2006 Change 2007 2006 Change

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

DA&A expenses

($000's) 9,379 9,569 (2%) 39,180 36,746 7%

DA&A expenses

per boe $26.85 $29.24 (8%) $28.79 $29.85 (4%)

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

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


Income Taxes

The Company does not expect to pay current income tax during 2008 as there are sufficient capital cost pools and expected future capital spending to shelter taxable income. Current taxes were recorded for flow through share taxes paid in 2007 for 2006 flow through share issue.

Future tax recovery was $2.2 million for the fourth quarter of 2007 (77 percent of loss before taxes) compared to a recovery of $5.2 million for the fourth quarter of 2006 (19 percent of loss before taxes). The percent recovery of future tax was lower in the fourth quarter of 2006 as non-taxable $24 million goodwill impairment was recorded in the fourth quarter of 2006. Future tax recovery was $4.3 million for the year ended December 31, 2007 (14 percent of loss before taxes) compared to a recovery of $10.2 million for the year ended December 31, 2006 (27 percent of loss before taxes). The 2006 recovery was higher as significant tax rate reduction benefits were recorded in 2006 for enacted corporate income tax rate reductions.

GOODWILL IMPAIRMENT

Goodwill, at the time of acquisition, represents the excess of purchase cost of a business over the fair value of net assets acquired. Thereafter, goodwill is not amortized and is assessed for impairment at least annually. If the estimated fair value of the business is less than the book value, a second test is performed to determine the amount of the impairment. Goodwill was originally recorded primarily on the Resolution Resources Ltd. acquisition (2003) and the Berland Exploration Ltd. acquisition (2006).

The Company recorded a partial impairment of goodwill in the fourth quarter of 2006. Since that time oil and gas company valuations eroded further, especially those of natural gas weighted producers primarily due to the decline in natural gas prices and high service costs in the industry. The Company tested the goodwill balance as at September 30, 2007 taking into account the decline in corporate economic value caused in 2007 by the decline in the share price. Recent oil and gas asset sales and corporate sale transactions were also benchmarked for the goodwill test. Based on the Company's assessment, it was determined that the fair value of the assets was less than the book value including the amount of goodwill that was being carried on the balance sheet. As a result, the Company recorded an impairment of goodwill for the remaining amount of the goodwill balance of $20.8 million in the third quarter of 2007.

NET LOSS

The net loss for the fourth quarter of 2007 was $0.1 million ($0.01 per share) compared to a loss of $22.0 million ($0.24 per share) in the fourth quarter of 2006. Goodwill impairment was recorded in the fourth quarter of 2006 causing the higher loss in that period.

The net loss for the year ended December 31, 2007 was $27.4 million ($0.30 per share) compared to a net loss of $28.3 million ($0.33 per share) for the year ended December 31, 2006. Both annual periods had goodwill impairments recorded resulting in the majority of the losses.

CAPITAL COSTS

Capital costs were $6.4 million in the fourth quarter of 2007 compared to $13.3 million in the fourth quarter of 2006. A total of three net wells were drilled in the fourth quarter of 2007 compared to eight net wells in the fourth quarter of 2006. In both quarterly periods the main activity was in the Pembina area. For the year ended December 31, 2007 $32.9 million of capital costs were incurred compared to $57.1 million for the year ended December 31, 2006 with 18 net wells drilled in 2007 compared to 29 net wells in 2006. Capital spending in 2006 also included $102.7 million for the acquisition of Berland. The 2006 period reflects a very active capital program following the acquisition of Berland Exploration in January 2006. The 2007 capital program was funded almost entirely by cash flow resulting in 16 percent reserve growth with a six percent increase in debt.



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

Three months

ended Year ended

($000's) December 31, December 31,

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

2007 2006 2007 2006

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

Drilling and completion 3,510 8,509 24,846 39,465

Equipping and tie-ins 2,476 2,965 10,621 13,342

Land 42 512 1,418 2,535

Geological and geophysical 370 384 2,390 1,048

Office and other 4 37 56 295

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

Total 6,421 12,407 39,331 56,685

Asset retirement obligation - 143 297 462

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

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

Total exploration and

development 6,421 12,550 39,628 57,140

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

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

Net acquisitions (dispositions) - 766 (6,750) 102,723

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

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

Total capital 6,421 13,316 32,878 159,870

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

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


Drilling, completion, equip and tie-in activity represented 93 percent of the capital spent in the fourth quarter of 2007 and 90 percent of capital for the year ended December 31, 2007 as capital activity focused on developing the extensive land base. A $30 million capital budget is planned for 2008, 89 percent of which is targeted toward drilling, completion, equip and tie-in activity. It is expected that 2008 capital spending will be funded by cash flow provided by operating activities.

WORKING CAPITAL

Accounts receivable of $10.3 million at December 31, 2007 were primarily revenue receivables ($5.8 million) and amounts owing from partners ($4.3 million). Accounts payable at December 31, 2007 of $16.5 million were mainly comprised of trade payables for capital and operating costs ($8.9 million), royalties ($1.5 million), amounts owing to partners ($1.3 million), unspent cash calls received from partners ($2.0 million) and capital costs accrued at the end of the quarter for ongoing drilling and completion operations ($1.4 million).

Working capital excluding bank indebtedness was in a deficit position of $5.6 million at December 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 $62.5 million at December 31, 2007, secured by producing properties. At December 31, 2007, $53.9 million was drawn on the bank line. Future capital spending is planned at amounts that can be met with expected Company cash flow.

NON-GAAP MEASUREMENTS

This MD&A contains the term "funds from operations" and "operating netback". As an indicator of the Company's performance, these terms should not be considered an alternative to, or more meaningful than "cash flow from operating activities" or "net income (loss)" as determined in accordance with Canadian generally accepted accounting principles. The Company's determination of funds from operations and operating netback may not be comparable to those reported by other companies, especially those in other industries. Management feels that funds from operations is a useful measure to help investors assess whether the Company is generating adequate cash amounts from its operations for its ongoing operations and planned capital program. Operating netback is a useful measure for comparing the Company's price realization and cost performance against industry competitors.

The reconciliation between net income and funds from operations for the periods ended December 31 is as follows:



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

Three months

ended Year ended

($000's) December 31 December 31

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

2007 2006 2007 2006

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

Cash flow provided by (used in)

operating activities 1,588 4,614 28,318 13,226

Changes in non-cash working

capital items related to

operating activities 6,403 1,504 1,236 9,245

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

Funds from operations 7,991 6,118 29,554 22,471

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

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


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 $0.09 (basic and diluted) for the fourth quarter of 2007 and $0.32 per share (basic and diluted) for the year ended December 31, 2007 compared to $0.07 per share for the fourth quarter of 2006 and $0.26 for the year ended December 31, 2006.

RISKS

Primary financial risks relate to volatility of commodity prices. Interest rate and currency exchange rate fluctuations also have an effect on financial results. The effect of changes in the exchange rate between US and Canadian currencies on natural gas prices is not direct, as variations between the regional markets for natural gas are often much greater than can be explained by currency variability. The Province of Alberta has announced plans for royalty changes for both conventional oil and natural gas and oil sands operations beginning in 2009. The effect of the changes to the royalty structure in Alberta may cause measurement uncertainty for certain oil and natural gas assets as oil and gas assets are valued under the new royalty system using various commodity price scenarios.

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 the date of this MD&A. 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.



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

NATURAL GAS HEDGING

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

Daily

quantity

(GJ) Term of contract Fixed price per gigajoule

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

2,000 January 1 to March 31, 2008 $7.25 floor; $8.65 cap

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

2,000 January 1 to March 31, 2008 $7.50 floor; $9.45 cap

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

2,000 January 1 to December 31, 2008 $6.65 fixed price

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

2,000 April 1 2008 to March 31, 2009 $6.72 fixed price

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

2,000 April 1 to December 31, 2008 $6.65 fixed price

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

2,000 April 1 to December 31, 2008 $6.80 fixed price

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

2,000 April 1 to October 31, 2008 $6.80 fixed price

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

2,000 April 1 to October 31, 2008 $7.45 fixed price

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

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

CRUDE OIL HEDGING

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

Daily

quantity Fixed price per barrel

(bbl) Term of contract (US WTI translated to C$)

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

100 January 1 to December 31, 2008 $85.00 floor; $93.30 cap

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

100 January 1 to December 31, 2008 $85.00 floor; $98.10 cap

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


The fair value of the above natural gas derivative instruments marked to market as at December 31, 2007, results in an unrealized gain position of $162,000 compared to an unrealized gain position of $635,000 at December 31, 2006. There were $937,000 ($2.68 per boe) of realized gains on derivative instruments in the fourth quarter of 2007 and $2,243,000 ($1.65 per boe) for the year ended December 31, 2007. The average floor price or fixed price of the natural gas hedging transactions for 2008 is $6.87 per GJ ($7.23 per mcf) which will provide protection to corporate cash flow if natural gas prices fall below these levels. The average floor price for the oil hedges is $85.00 per barrel.

Absent the above-noted risk management contracts, the effects of changes in commodity prices on cash flow before working capital changes are summarized in the following table.



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

Commodity Price change Cash flow change ($ 000's)

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

Natural gas ($/mcf) 1.00 $5,800

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

Oil and Liquids ($/bbl) 10.00 $1,600

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


RELATED PARTY TRANSACTIONS

Fees for legal services are paid to a law firm in which the corporate secretary is a partner. The legal services are rendered in the normal course of business at normal rates charged by the law firm. Legal fees for this firm paid in the fourth quarter of 2007 were $13,000 and $206,000 for the year ended December 31, 2007.

SHARE DATA

As of the date of this MD&A the Company had 93,172,064 issued and outstanding common shares. Additionally, options to purchase 6,238,200 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 are part of a process designed under the supervision of the Chief Executive Officer and the Chief Financial Officer and monitored by the Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

The Company reported on these controls as part of its 2006 continuous disclosure requirements (please refer to the MD&A for the year ended December 31, 2006 available on SEDAR (www.SEDAR.com) and on our website www.berensenergy.com). There have been no changes to internal controls over financial reporting or management's assessment of the design of these internal controls in the period since December 31, 2006.

RISKS AND UNCERTAINTIES, CRITICAL ACCOUNTING ESTIMATES AND RECENT

ACCOUNTING PRONOUNCEMENTS

The MD&A is based on the consolidated financial statements, which have been prepared in Canadian dollars in accordance with GAAP. The application of GAAP requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates are based on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates under different assumptions or conditions.

For a discussion of Risks and Uncertainties, Critical Accounting Estimates and Recent Accounting Pronouncements please refer to the audited financial statements and the Annual Information Form for the year ended December 31, 2006 available on SEDAR (www.SEDAR.com) and on our website (www.berensenergy.com).

As of January 1, 2007, the Company adopted the Canadian Institute of Chartered Accountants ("CICA") Section 1530 "Comprehensive Income", Section 3251 "Equity", Section 3855 "Financial Instruments - Recognition and Measurement", and Section 3865 "Hedges", which were issued in January 2005. CICA handbook section 1506, "Accounting Changes" was also adopted on January 1, 2007. The adoption of these standards had no effect on the presentation of the financial statements.

OUTLOOK

Berens has demonstrated production growth, controlled costs and improved drilling success. Production growth has followed the drilling success experienced in late 2006 which continued through 2007. Net drilling success in 2007 was 86 percent and the average well results for reserves and production have exceeded expectations significantly. A disciplined approach to cost management has achieved significant reduction in our cost structure supported by moderation in the overall industry cost structure. These factors combined have lowered the Company's finding and development costs in 2007 to $12.85 per boe.

Capital spending for 2008 is projected at $30 million and will be funded with cash flow from operations. Capital spending for 2008 will be focused in Pembina where the reserve life of new wells is longest and the wells have the strongest economics. There are currently 100 inventoried drilling locations on existing lands. An active drilling program is underway in the first quarter of 2008 in Pembina and Deep Basin.

Debt and working capital balances have improved and will continue to improve with the planned capital spending plans. With an extensive land base and a large number of inventoried drilling locations, management anticipates that the Company will be positioned to develop our asset base more aggressively as natural gas prices improve.



Berens Energy Ltd.

Balance Sheets

As at,

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

(000's) December 31, December 31,

2007 2006

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

ASSETS (note 8)

Current

Cash and cash equivalents (note 4) $ 1 $ 10

Accounts receivable 10,315 19,601

Unrealized gain on risk management (note 13) 162 635

Prepaid expenses and deposits 442 215

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

10,920 20,461

Property, plant and equipment (note 6) 166,405 172,404

Goodwill (notes 5 and 14) - 20,755

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

$ 177,325 $ 213,620

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

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

LIABILITIES AND SHAREHOLDERS' EQUITY

Current

Bank loan (note 8) $ 53,900 $ 50,080

Accounts payable and accrued liabilities 16,523 26,622

Taxes payable 14 29

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

70,437 76,731

Asset retirement obligations (note 7) 3,273 2,645

Future income taxes (note 10) 10,199 14,518

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

83,909 93,894

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

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

Commitments (note 16)

Shareholders' equity

Capital stock (note 9) 148,263 148,038

Contributed surplus (note 9) 2,195 1,290

Deficit (57,042) (29,602)

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

93,416 119,726

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

$ 177,325 $ 213,620

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

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

See accompanying notes to the financial statements



Berens Energy Ltd.

Statements of Operations and Comprehensive Loss and Deficit

For the three months and year ended December 31,

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

(000's) Three months Year

ended ended

December 31, December 31,

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

2007 2006 2007 2006

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

Revenue

Oil and natural gas

revenue $ 15,563 $ 14,386 $ 61,281 $ 52,810

Royalties, net of ARTC (3,286) (3,173) (13,915) (12,692)

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

12,277 11,213 47,366 40,118

Realized gain on risk

management (note13) 937 - 2,243 -

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

13,214 11,213 49,609 40,118

Unrealized gain (loss)

on risk management (note 13) (1,296) 635 (473) 635

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

11,918 11,848 49,137 40,753

Interest and other income - - 31 18

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

11,918 11,848 49,167 40,771

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

Expenses

Production 2,524 2,905 10,280 9,721

Transportation 346 302 1,307 1,116

Depletion, amortization

and accretion 9,377 9,569 39,180 36,747

Impairment of goodwill

(note 14) - 24,220 20,755 24,220

General and administrative

(note 12) 1,401 845 4,433 4,090

Stock-based compensation

(note 9) 239 133 905 716

Interest 949 972 4,027 2,627

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

14,836 38,946 80,887 79,237

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

Loss before income taxes (2,918) (27,098) (31,720) (38,466)

Income taxes (note 10)

Future expense (recovery) (2,241) (5,218) (4,319) (10,237)

Current expense 3 71 39 111

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

(2,238) (5,147) (4,280) (10,126)

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

Net loss and comprehensive

loss for the period (680) (21,951) (27,440) (28,340)

Deficit, beginning of period (56,362) (7,651) (29,602) (1,262)

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

Deficit, end of period $ (57,042) $ (29,602) $ (57,042) $ (29,602)

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

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

Net income (loss) per

share (note 15)

Basic and diluted $ (0.01) $ (0.24) $ (0.30) $ (0.33)

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

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

See accompanying notes to the financial statements



Berens Energy Ltd.

Statements of Cash Flows

For the three months and year ended December 31,

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

(000's) Three months Year

ended ended

December 31, December 31,

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

2007 2006 2007 2006

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

OPERATING ACTIVITIES

Net income (loss) for

the period $ (680) $ (21,951) $ (27,440) $ (28,340)

Add items not involving cash

Depletion, amortization

and accretion 9,377 9,569 39,180 36,747

Impairment of goodwill - 24,220 20,755 24,220

Unrealized risk management

(gain) loss 1,296 (635) 473 (635)

Future income tax recovery (2,241) (5,218) (4,319) (10,237)

Stock-based compensation 239 133 905 716

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

7,991 6,118 29,554 22,471

Change in non-cash working

capital items related to

operating activities

(note 10) (6,403) (1,504) (1,236) (9,245)

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

Cash flow provided by

operating activities 1,588 4,614 28,318 13,226

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

FINANCING ACTIVITIES

Change in bank loan 3,100 (2,700) 3,820 30,330

Net proceeds from private

offerings - 11,142 - 30,955

Sale of investment - 25 29 269

Proceeds from the exercise

of stock options - - 225 -

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

Cash flow provided by

financing activities 3,100 8,467 4,074 61,554

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

INVESTING ACTIVITIES

Cash acquired through

Berland acquisition - - - 109

Cash component on Berland

acquisition - - - (28,682)

Purchase of property

and equipment (6,421) (12,581) (39,331) (56,685)

Disposition of property

and equipment 6,750

Change in non-cash working

capital items related to

investing activities

(note 10) 1,733 (534) 180 1,016

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

Cash flow used in

investing activities (4,688) (13,115) (32,401) (84,242)

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

Increase (decrease) in cash

and cash equivalents - (34) (9) (9,462)

Cash and cash equivalents,

beginning of period 1 44 10 9,472

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

Cash and cash equivalents,

end of period $ 1 $ 10 $ 1 $ 10

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

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

See accompanying notes to the financial statements



BERENS ENERGY LTD.

Notes to Financial Statements

Years ended December 31, 2007 and 2006

1. NATURE OF OPERATIONS

Berens Energy Ltd. (the "Company") is a full cycle oil and natural gas

exploration and production company with activities encompassing land

acquisition, geological and geophysical assessment, drilling and

completion, and production. The primary areas of operation are in eastern

and west central Alberta.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The consolidated financial statements have been prepared by management in

accordance with Canadian generally accepted accounting principles

("GAAP"). The nature of the business and timely preparation of financial

statements requires that management make estimates and assumptions, and

use judgment regarding assets, liabilities, revenues and expenses. Such

estimates primarily relate to unsettled transactions and events as of the

date of the financial statements. Accordingly, actual results may differ

from estimated amounts. In the opinion of management, these financial

statements have been properly prepared within reasonable limits of

materiality and within the framework of the significant accounting

policies summarized below.

Cash and Cash Equivalents

Cash and cash equivalents, consisting of cash and short-term investments

with a maturity of less than three months, are recorded at the lower of

cost and quoted market value.

Capitalized Costs

The full cost method of accounting is followed whereby all costs relating

to the acquisition of, exploration for and development of oil and gas

reserves are capitalized in a single Canadian cost centre. Such costs

include lease acquisition, lease rentals on undeveloped properties,

geological and geophysical costs, drilling both productive and

non-productive wells, production equipment and overhead charges directly

related to acquisition, exploration and development activities.

Gains or losses are not recognized on the disposition of oil and gas

properties unless such dispositions would change the depletion rate by

20 percent or more. Gains and losses are recognized on the disposition of

other assets.

Depletion and Amortization

All costs of acquisition, exploration and development of oil and gas

reserves, associated tangible plant and equipment costs (net of salvage

value), and estimated costs of future development of proved undeveloped

reserves are depleted and amortized using the unit of production method.

This method is based on estimated gross proved reserves as determined by

independent engineers.

Costs of unproved properties are initially excluded from petroleum and

natural gas properties for the purpose of calculating depletion. When

proved reserves are assigned or the property is considered to be

impaired, the cost of the property or the amount of the impairment is

added to costs subject to depletion.

The volumes of oil and natural gas reserves and production are converted

to equivalent barrels of oil based on the relative energy content of each

product such that six thousand cubic feet of natural gas equals one

barrel of oil, commonly known as the six to one basis.

Office and computer equipment is amortized on a straight-line basis over

ten and four years, respectively.

Ceiling Test

The Company applies an impairment test to the net carrying amount of

petroleum and natural gas assets designed to ensure that such costs do

not exceed their estimated fair value ultimately recoverable. The test is

a two part test whereby the first step is to compare the net carrying

amount of the asset to the aggregate of estimated undiscounted future net

cash flows from production of proved reserves and the cost of unproved

properties less impairment. Future cash flows are estimated using future

prices and costs without discounting. Should the net carrying value of

the petroleum and natural gas assets exceed the amount ultimately

recoverable, the amount of impairment is determined through the

performance of the second part of the test whereby the discounted

estimated future cash flows from proved and probable reserves based on

the future prices plus the cost of unproved properties, net of impairment

allowances, is compared to the book value of the related assets. Any

reduction in net carrying value, as a result of the impairment test, is

included in depreciation and depletion expense.

Asset Retirement Obligations

The Company estimates the present value of the asset retirement

obligation in the period in which it is incurred or when a reasonable

estimate of its fair value can be made, and records a corresponding

increase in the carrying value of the related long-lived asset. The

estimated fair value is determined through a review of engineering

studies, industry guidelines and management's estimate on a site-by-site

basis. The liability is subsequently adjusted for the passage of time,

which is recognized as an accretion expense in the statement of

operations and included in asset retirement obligations. The liability is

also adjusted due to revisions in either the timing or the amount of the

original estimated cash flows associated with the liability. The increase

in the carrying value of the asset is amortized using the unit of

production method based on estimated gross proved reserves. Actual costs

incurred upon settlement of the asset retirement obligations are charged

against the asset retirement obligation to the extent of the liability

recorded. Any difference between the actual costs incurred upon

settlement of the asset retirement obligation and the recorded liability

is recognized as a gain or loss in the Company's statement of operations

in the period in which the settlement occurs.

Goodwill

Goodwill represents the excess of purchase cost of a business over the

estimated fair value of net assets acquired at the time of a business

combination. Thereafter, goodwill is not amortized and is assessed for

impairment at least annually. If the estimated fair value of the net

assets of a reporting unit is less than their book value, a second test

is performed to determine the amount of the impairment. The amount of the

impairment is determined by deducting the estimated fair value of the

reporting unit's net assets from the total fair value to determine the

implied fair value of goodwill and comparing that amount to the book

value of goodwill.

Revenue Recognition

Oil and natural gas sales are recognized when the significant risks and

rewards of ownership have transferred to the buyer, the price is

determinable and there is reasonable assurance regarding collectability

of the consideration.

Income Taxes

The liability method of accounting for income taxes is followed. Under

this method, future tax assets and liabilities are determined based on

the differences between financial reporting and income tax bases of

assets and liabilities, and are measured using substantively enacted tax

rates and laws that will be in effect when the differences are expected

to reverse. The effect on future tax assets and liabilities of a change

in tax rates is recognized in net income in the period in which the

change occurs.

Joint Ventures

A substantial portion of the Company's exploration, development and

production activities is conducted jointly with others. These financial

statements reflect only the Company's proportionate interest in such

activities.

Stock-Based Compensation

Under the stock option plan described in note 9, options to purchase

common shares are granted to directors, officers, employees and

consultants with option strike prices based on the market price at the

time of the grant. Options issued by the Company are accounted for in

accordance with the fair value method of accounting for stock-based

compensation using the Black-Scholes option pricing model. The resulting

cost of the option is charged to income over the vesting period of the

option with a corresponding increase in contributed surplus.

At the time of exercise, the related amounts previously credited to

contributed surplus are also transferred to share capital. In the event

that vested options expire without being exercised, previously recognized

compensation costs associated with such stock options are not reversed.

Measurement Uncertainty

The amount recorded for depletion and amortization of oil and gas

properties, the provision for asset retirement obligations, goodwill

measurement and the ceiling test calculation are based on estimates of

gross proved reserves, production rates, commodity prices, future costs

and other assumptions. By their nature, these estimates are subject to

measurement uncertainty and the effect on the financial statements of

changes in such estimates in future years could be material.

Per Share Information

Per share information is calculated on the basis of the weighted average

number of common shares outstanding during the fiscal year. Diluted per

share information reflects the potential dilution that could occur if

securities or other contracts to issue common shares were exercised or

converted to common shares. Diluted per share information is calculated

using the treasury stock method which assumes that any proceeds received

by the Company upon the exercise of in-the-money stock options would be

used to buy back common shares at the average market price for

the period.

Flow-through Common Shares

Resource expenditure deductions for income tax purposes related to

exploration and development activities funded by flow-through share

arrangements are renounced to investors in accordance with income tax

legislation. The estimated tax benefits transferred to shareholders are

recorded as future income taxes and a reduction to share capital when the

expenditures are renounced, which for accounting purposes, is when the

appropriate documentation is filed with Canada Revenue Agency.

3. CHANGES IN ACCOUNTING POLICIES

Effective January 1, 2007, the Company adopted six new accounting

standards issued by the Canadian Institute of Chartered Accountants

("CICA"): Handbook Section 3855 "Financial Instruments - Recognition and

Measurement", Section 3861 "Financial Instruments - Disclosure and

Presentation", Section 3865 "Hedges", Section 1506 "Accounting Changes",

Section 1530 "Comprehensive Income" and Section 3251 "Equity".

Impact upon adoption of Sections 3855, 3861, 3865, 1506, 1530 and 3251

The adoption of the new standards did not have a significant impact on

the Company's financial statements due to the nature of the financial

instruments recorded on the balance sheet and the contracts to which the

Company is a party.

Financial instruments - recognition and measurement

Section 3855 establishes standards for recognizing and measuring

financial assets, financial liabilities and non-financial derivatives.

It requires that financial assets and financial liabilities, including

derivatives, be recognized on the balance sheet when the Company becomes

a party to the contractual provisions of the financial instrument or

non-financial derivative contract. Under this standard, all financial

instruments are required to be measured at fair value upon initial

recognition except for certain related party transactions. Measurement in

subsequent periods depends on whether the financial instrument has been

classified as held-for-trading, available-for sale, held-to-maturity,

loans or receivables, or other financial liabilities. Financial assets

and financial liabilities held-for-trading are measured at fair value

with changes in those fair values recognized in net income. Financial

assets held-to-maturity, loans and receivables, and other financial

liabilities are measured at amortized cost using the effective interest

method of amortization. Investments in equity instruments classified as

available-for-sale that do not have a quoted market price in an active

market are measured at cost.

Derivative instruments are recorded on the balance sheet at fair value,

including those derivatives that are embedded in financial or

non-financial contracts that are not closely related to the host

contracts. Changes in the fair values of derivative instruments are

recognized in net income, with the exception of derivatives designated as

effective cash flow hedges and hedges of the foreign currency exposure of

a net investment in a self-sustaining foreign operation, which are

recognized in other comprehensive income.

In addition, Section 3855 requires that an entity must select an

accounting policy of either expensing debt issue costs as incurred or

applying them against the carrying value of the related asset or

liability.

The financial instruments recognized on the Company's balance sheet are

deemed to approximate their estimated fair values; therefore, no further

adjustments were required upon adoption of the new sections. There were

no financial assets on the balance sheet which were designated as

held-for-trading, held-to-maturity or available-for-sale. All financial

assets were classified as loans or receivables and are accounted for on

an amortized cost basis. All financial liabilities were classified as

other liabilities.

Hedges

Section 3865 provides alternative treatments to Section 3855 for entities

which choose to designate qualifying transactions as hedges for

accounting purposes. It replaces and expands on Accounting Guideline 13

"Hedging Relationships", and the hedging guidance in Section 1650

"Foreign Currency Translation" by specifying how hedge accounting is

applied and what disclosures are necessary when it is applied.

The Company does not follow hedge accounting for its risk management

activities and therefore the adoption of Section 3865 "Hedges" did not

have any impact on the Company's financial statements.

Accounting changes

Section 1506 provides expanded disclosures for changes in accounting

policies, accounting estimates and corrections of errors. Under the new

standard, accounting changes should be applied retrospectively unless

otherwise permitted or where impracticable to determine. As well,

voluntary changes in an accounting policy are to be made only when

required by a primary source of GAAP or the change results in more

relevant and reliable information.

Comprehensive income (loss) and accumulated other comprehensive

income (loss)

Section 1530 introduces comprehensive income, which consists of net

income and other comprehensive income ("OCI"). OCI represents changes in

shareholders' equity during a period arising from transactions and

changes in prices, markets, interest rates and exchange rates. OCI

includes unrealized gains and losses on financial assets classified as

available-for-sale, unrealized translation gains and losses arising from

self-sustaining foreign operations net of hedging activities and changes

in the fair value of the effective portion of cash flow hedging

instruments.

The Company has not entered into any transactions which require any

amounts to be recorded to other comprehensive income (loss) or

accumulated other comprehensive income (loss).

Equity

Section 3251 establishes standards for the presentation of equity and

changes in equity during the reporting period. The requirements under

this Section have been presented in these annual financial statements.

Future accounting changes

On December 1, 2006, the CICA issued three new accounting standards:

Handbook Section 1535, Capital Disclosures; Handbook Section 3862,

Financial Instruments - Disclosures, and Handbook Section 3863; Financial

Instruments - Presentation. These new standards are effective

January 1, 2008. Section 1535 specifies the disclosure of (i) an entity's

objectives, policies and processes for managing capital; (ii)

quantitative data about what the entity regards as capital; (iii) whether

the entity has complied with any capital requirements; and (iv) if it has

not complied, the consequences of such non-compliance. The new

Sections 3862 and 3863 replace Handbook Section 3861, Financial

Instruments - Disclosure and Presentation, revising and enhancing its

disclosure requirements and carrying forward unchanged its presentation

requirements. These new sections place increased emphasis on disclosures

about the nature and extent of risks arising from financial instruments

and how the entity manages those risks. The Company is currently

assessing the effects of these new standards on our financial statements.

On February 13, 2008, the Canadian Accounting Standards Board ("AcSB")

confirmed the use of International Financial Reporting Standards ("IFRS")

for publicly accountable profit-oriented enterprises, beginning on

January 1, 2011 with appropriate comparative data from the prior year.

IFRS will replace the current CICA Handbook as Canadian GAAP. Under IFRS

significantly increased disclosure is required, especially for interim

reporting. While IFRS uses a conceptual framework similar to Canadian

GAAP, there are significant differences in accounting policies which must

be addressed. The effects of these new standards on the Company's

financial statements is currently being assessed.

4. CASH AND CASH EQUIVALENTS

Cash and cash equivalents are in the form of cash bank balances or

certificates of deposit from Canadian financial institutions with terms

of less than 90 days. The effective interest rate on the deposits at

December 31, 2007 was 2.3 percent (2006 - 2.3 percent).

5. ACQUISITION OF BERLAND EXPLORATION LTD.

On January 18, 2006, the Company and Berland Exploration Ltd. ("Berland")

closed a previously announced arrangement that saw the Company 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, the Company also assumed $19.7 million of Berland debt and

transaction costs of $0.5 million.

The total cost to the Company 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

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

6. PROPERTY, PLANT AND EQUIPMENT

December 31, 2007 December 31, 2006

Accumulated Accumulated

depletion and depletion and

($000's) Cost depreciation Cost depreciation

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

Petroleum and natural

gas properties 274,067 108,045 241,244 69,305

Office and computer

equipment 734 351 707 242

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

274,801 108,396 241,951 69,547

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

Net book value 166,405 172,404

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

At December 31, 2007, costs of $21,159,000 (2006 - $25,907,000) related

to undeveloped land have been excluded from the depletion and

depreciation calculation. At December 31, 2007 estimated future

development costs of $15,511,000 have been included in the depletion and

depreciation calculation (2006 - $13,018,000). A ceiling test was

completed at December 31, 2007 resulting in no impairment.

Benchmark pricing used for ceiling test purposes is shown in the

following table.

Oil

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

Cromer

Medium

WTI Edmonton 29.30

Cushing Par Price Hardisty API

Oklahoma 400 API Heavy degree

($US/ ($Cdn/ ($Cdn/ ($Cdn/

bbl) bbl) bbl) bbl)

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

Year

Forecast

2008 92.00 91.10 54.02 79.26

2009 88.00 87.10 51.61 75.78

2010 84.00 83.10 49.19 72.30

2011 82.00 81.10 47.98 70.56

2012 82.00 81.10 47.98 70.56

2013 82.00 81.10 49.04 70.56

2014 82.00 81.10 50.09 70.56

2015 82.00 81.10 51.15 70.56

2016 82.02 81.12 52.21 70.57

2017 83.66 82.76 53.29 72.00

2018+ +2.0%/yr +2.0%yr +2.0%/yr +2.0%/yr

Natural gas NGLs

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

FOB

Field

AECO-C Gate Inflation

Gas (propane/ rate(1)% Exchange

Price butane) per year rate(2)

($Cdn/ ($Cdn/ ($Cdn/ ($US/

MMbtu) bbl) MMbtu) Cdn)

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

Year

Forecast

2008 6.75 65.59 2.0 1.00

2009 7.55 62.71 2.0 1.00

2010 7.60 59.83 2.0 1.00

2011 7.60 58.39 2.0 1.00

2012 7.60 58.39 2.0 1.00

2013 7.60 58.39 2.0 1.00

2014 7.80 58.39 2.0 1.00

2015 7.97 58.39 2.0 1.00

2016 8.14 58.40 2.0 1.00

2017 8.31 59.59 2.0 1.00

2018+ +2.0%/yr +2.0%/yr 2.0 1.00

7. ASSET RETIREMENT OBLIGATIONS

The total future asset retirement obligations were estimated based on the

net ownership interest in all wells and facilities, estimated costs to

reclaim and abandon the wells and facilities and the estimated timing of

the costs to be incurred in future periods. The estimated net present

value of the total asset retirement obligations is $3,273,000 as at

December 31, 2007 (2006 - $2,645,000) based on a total future liability

of $8,611,000 (2006 - $6,959,400). These payments are expected to be made

over the next 5 to 15 years. An inflation rate of 2 percent and a credit

adjusted risk free rate of 10 percent were used to calculate the present

value of the asset retirement obligations.

The following table reconciles the asset retirement obligations:

($000's) 2007 2006

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

Obligation, beginning of year 2,645 1,223

Increase in obligation during the year 297 430

Obligation assumed from Berland acquisition - 715

Increase due to increase in inflation rate - 32

Accretion expense 331 245

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

Obligation, end of year 3,273 2,645

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

8. BANK OPERATING LINE

An agreement with a Canadian bank is in place for an operating bank line

totaling $62.5 million at December 31, 2007. Collateral for the facility

consists of a general assignment of book debts and a $35.0 million

debenture with a floating charge over all assets of the Company and a

$75.0 million supplemental debenture with a floating charge over all

assets of the Company. The bank line is a demand line and carries an

interest rate of the Bank's prime rate adjusted for a factor based on the

most recent quarterly debt to cash flow calculation. The rate at

December 31, 2007 was 6.75 percent (December 31, 2006 - 7.25 percent).

9. CAPITAL STOCK

(a) Authorized Capital

The authorized capital consists of an unlimited number of preferred

shares issuable in series and an unlimited number of common shares

without nominal or par value.

(b) Common shares issued

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

Consideration

Number ($000's)

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

Balance December 31, 2005 57,163,269 72,309

Private placement for cash on conversion

of subscription receipts, net of commissions 8,200,000 19,988

Shares issued on arrangement with Berland

(note 5) 21,083,795 53,764

Private placement for cash, net of commissions 6,500,000 11,238

Future tax effect of flow-through share

renouncements - (9,554)

Future tax effect on share issue costs and

commissions - 565

Share issue costs, net of tax - (272)

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

Balance December 31, 2006 92,947,064 148,038

Shares issued on exercise of stock options 225,000 225

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

Balance December 31, 2007 93,172,064 148,263

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

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. The renouncement of these

expenditures was filed with the tax authorities during 2006 and the tax

effect of the renunciation of $9,554,000 was recognized. The expenditures

to satisfy the flow-through commitment had been made by June 30, 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 December 31, 2007:

2007 2006

Weighted Weighted

average average

exercise exercise

Number of price ($ Number of price ($

Options per share) Options per share)

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

Outstanding, beginning

of year 4,416,200 1.68 3,513,700 1.56

Granted 2,309,500 0.94 910,000 1.31

Forfeited (262,500) 1.99 (7,500) 2.90

Exercised (225,000) 1.00 - -

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

Outstanding, end of year 6,238,200 1.42 4,416,200 1.68

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

Exercisable 3,216,359 1.54 2,449,692 1.34

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

The following table sets forth additional information relating to the

stock options outstanding at December 31, 2007:

Options Outstanding Exercisable Options

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

Weighted Weighted

average average

exercise Weighted exercise Weighted

price average price average

Exercise price Number of ($ per years to Number of ($ per years to

range Options share) expiry Options share) expiry

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

$0.50 to $1.39 4,053,500 1.00 2.94 1,735,333 1.08 1.12

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

$1.40 to $2.29 1,127,200 1.54 2.05 866,867 1.51 1.58

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

$2.30 to $3.19 917,500 2.83 2.99 567,492 2.86 2.96

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

$3.20 to $4.09 140,000 3.24 3.07 46,667 3.24 3.07

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

6,238,200 1.42 2.79 3,216,359 1.54 1.59

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

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 as forfeitures are recognized as they occur. The weighted

average option price for options outstanding at December 31, 2007 is

$0.567 per option. For the year ended December 31 2007, $905,000 (2006 -

$716,000) 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 year ended December 31, 2007:

($000's)

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

Balance, December 31, 2005 574

2006 Stock based compensation expense 716

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

December 31, 2006 1,290

2007 Stock based compensation expense 905

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

December 31, 2007 2,195

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

At the time of exercise of a stock option, the related amounts previously

credited to contributed surplus are also transferred to share capital. In

the event that vested options expire without being exercised, previously

recognized compensation costs associated with such stock options are not

reversed.

10. INCOME TAXES

The income tax expense or recovery differs from the amount computed by

applying the Canadian statutory rates to the loss before tax as follows:

($000's) 2007 2006

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

Loss before income taxes (31,720) (38,466)

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

Current statutory income tax rate 32.13% 34.54%

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

Anticipated tax recovery (10,193) (13,286)

Decrease in recovery resulting from:

Effect of future tax rate reductions (957) (5,511)

Impairment of goodwill 6,669 8,365

Unrealized risk management gains (152) (219)

Non-deductible Crown payments - 1,293

Resource allowance - (1,085)

Alberta royalty tax credits - (54)

Non-deductible expenses 300 260

Other 14 -

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

Future income tax recovery (4,319) (10,237)

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

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

Capital tax 12 29

Other 27 82

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

Current income tax expense 39 111

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

Future income taxes reflect the net tax effects of temporary differences

between the carrying amounts of assets and liabilities for financial

reporting purposes and the amounts used for income tax purposes. The

components of the future tax assets are as follows:

($000's) 2007 2006

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

Future tax liabilities

Net book value of capital assets

in excess of tax pools (12,132) (16,819)

Future tax assets

Share issue costs 432 848

Attributed Canadian royalty income 683 682

Asset retirement obligation 818 771

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

Net future tax liabilities (10,199) (14,518)

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

Tax Pools

At December 31, 2007 the petroleum and natural gas properties had an

approximate tax basis of $125,700,000.

Capital loss carry-forwards exist totaling $3,363,000 which are available

to offset future capital gains for which no future income tax asset has

been recognized in the accounts.

11. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in Non-cash Working Capital

For the years ended December 31,

($000's) 2007 2006

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

Accounts receivable 9,286 (9,690)

Prepaid expenses and deposits (228) (1,329)

Accounts payable and accrued liabilities (10,099) 11,291

Taxes payable (16) (63)

Non-cash working capital acquired (note 4) - (8,438)

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

(1,057) (8,229)

Change in non-cash working capital

related to investing activities 180 1,016

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

Change in non-cash working capital

related to operating activities (1,237) (9,245)

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

Cash interest and taxes paid

For the year ended December 31,

($000's) 2007 2006

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

Cash income and other taxes paid 28 220

Cash interest paid 4,028 2,627

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

12. RELATED PARTY TRANSACTIONS

Fees for legal services are paid to a law firm in which the corporate

secretary is a partner. The legal services are rendered in the normal

course of business at normal rates charged by the law firm. Legal fees

for this firm paid for the year ended December 31, 2007 were $206,000.

13. 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, accrued liabilities, bank loan and financial

derivatives used to manage natural gas price risk. 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. The Company entered into an interest rate swap transaction in

January 2008 to fix the interest rate on $25.0 million of its variable

rate demand bank line. The transaction fixes the interest rate for a two

year period at a rate of 5.21 percent including the Company's borrowing

margin on its bank line.

(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 December 31, 2007. All contracts are

priced in Canadian dollars per gigajoule (GJ). The price per GJ can be

converted to an approximate price per million cubic feet ("MCF") by

multiplying the per GJ price by 1.05. GJ volume can be converted to an

approximate MCF volume by multiplying the GJ volume by 0.95.

Natural Gas Risk Management Contracts

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

Daily

quantity Fixed price per

(GJ/day) Term of Contract gigajoule (Cdn$/GJ)

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

2,000 January 1 to March 31, 2008 $7.25floor; $8.65 cap

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

2,000 January 1 to March 31, 2008 $7.50 floor; $9.45 cap

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

2,000 April 1 to March 31, 2009 $6.72 fixed price

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

2,000 April 1 to December 31, 2008 $6.65 fixed price

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

2,000 January 1 to December 31, 2008 $6.65 fixed price

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



Crude Oil Risk Management Contracts

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

Daily

quantity Fixed price per barrel

(Barrels/d) Term of Contract (WTI in Cdn$)

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

100 January 1 to December 31, 2008 $85.00 floor; $93.30 cap

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

100 January 1 to December 31, 2008 $85.00 floor; $98.10 cap

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

The fair value of the above natural gas derivative instruments marked-to-

market as at December 31, 2007 results in an unrealized gain of $162,000

(December 31, 2006 - $635,000). Total realized gains from risk management

activities in 2007 were $2,243,000 (2006 - nil).

Subsequent to December 31, 2007 the following natural gas risk management

contracts have been put in place.

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

Daily

quantity Fixed price per

(GJ/day) Term of Contract gigajoule (Cdn$/GJ)

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

2,000 April 1 to December 31, 2008 $6.80 fixed price

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

2,000 April 1 to October 31, 2008 $6.80 fixed price

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

2,000 April 1 to October 31, 2008 $7.45 fixed price

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

14. GOODWILL

The Company recorded an impairment of goodwill in the amount of

$24.2 million in 2006 and a further impairment to the remaining goodwill

balance of $20.8 million in the third quarter of 2007.

15. PER SHARE INFORMATION

The weighted average number of common shares outstanding for the year

ended December 31, 2007 of 93,067,132 was used to calculate basic and

diluted income (loss) per share (2006 - 86,178,274). All of the

outstanding options have been excluded from the calculation of diluted

per share information as they were anti-dilutive. The total number of

shares which are potentially dilutive in future periods as of

December 31, 2007 was 6,238,200.

16. COMMITMENTS

Commitments exist for leased office space and vehicles. The amounts for

leased space exclude operating costs, taxes, insurance and utilities:

Year

($000's)

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

2008 305

2009 215

2010 97

Thereafter -

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

Total 617

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

Directors and officers are indemnified against any and all claims or

losses reasonably incurred in the performance of their service to the

Company to the extent permitted by law. The Company has acquired and

maintains liability insurance for its directors and officers.

17. COMPARATIVE FIGURES

Certain figures have been re-classified to conform to the financial

statement presentation adopted in 2007.

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