Berens Energy Ltd.

November 12, 2008 23:59 ET

Berens Energy Ltd. Releases Financial Results for the Three and Nine Months Ended September 30, 2008

CALGARY, ALBERTA--(Marketwire - Nov. 12, 2008) -



FINANCIAL AND OPERATING HIGHLIGHTS

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($ Cdn thousands, Three months Nine months

except as noted) ended September 30, Ended September 30,

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% %

2008 2007 Change 2008 2007 Change

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Sales volume

Natural gas

(mcf/day) 19,592 18,288 7% 19,458 18,969 3%

Oil and ngls

(bbl/day) 845 570 48% 778 543 43%

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boe/day

(6 to 1) 4,110 3,618 14% 4,021 3,705 9%

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Revenue net of

royalties 17,368 10,666 63% 52,623 35,090 50%

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Net income (loss) 8,167 (23,157) 1,412 (26,760)

Per share (basic

and diluted) $0.09 $(0.25) $0.01 $(0.29)

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Funds from

operations(1) 8,943 6,811 31% 30,782 21,564 43%

Per share (basic

and diluted)(1) $0.10 $0.07 43% $0.33 $0.23 43%

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Capital costs

Exploration and

development 12,325 7,255 70% 24,064 29,419 (18%)

Acquisition

(disposition) - (6,750) - (6,750)

Land and seismic 1,606 1,240 30% 4,035 3,396 18%

Other 7 37 (81%) 14 52 (73%)

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Total 13,938 1,782 682% 28,113 26,117 8%

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Net wells completed

(No.) 8 7 13 14

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Net working capital

deficit - excluding

unrealized hedging

gains/losses (56,819) (60,051) (5%) (56,819) (60,051) (5%)

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Net working capital

deficit - including

unrealized hedging

gains/losses (57,040) (58,593) (3%) (57,040) (58,593) (3%)

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Shares outstanding

End of period

(000's) 93,547 93,172 - 93,547 93,172 -

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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.

Third Quarter 2008 Operating Highlights

Berens is pleased to provide our third quarter results that demonstrate
continued growth based on ongoing success on established and repeatable
drilling plays in Pembina and Lanfine:

- Capital Budget - We are on track to execute the $40 million

capital program announced in August. The additional capital

combined with strong drilling results to date is expected to

deliver average quarter 2008 production rates of 4,400 boe/d with

strong momentum established entering 2009.

- Drilling - Strong drilling results continued in Q3 2008 in Pembina

with 100% success on 7 wells (4.9 net). The new Pembina wells are

all showing strong early production results. Seven wells were

drilled in Lanfine in the third quarter with 4 successful (3.75

net) and put on stream by the end of August. We also drilled one

(0.35 net) well in Deep Basin that is a suspended potential gas

well. We have cased our first horizontal well (0.5 net) in Pembina

in early November with strong early test results being measured at

the time of writing of this report. With this success, there are

three additional horizontal wells planned for the first quarter of

2009.

- Production - Q3 2008 production averaged 4,110 boe/d, up 14% over

Q3 2007. The increase in year-over-year production has been

delivered while decreasing debt and working capital balances over

$3.2 million or 5 percent since September 30, 2007.

- Production Costs - Costs averaged $8.76 per boe in Q3 2008 with

costs for the first nine months of 2008 averaging $8.25 per boe,

up 8% compared to the first nine months of 2007 as we continue to

strive to manage inflationary pressures in our industry. We expect

operating costs to be in the $8.00 range for the remainder of the

year.

- Funds from Operations - Funds from operations for Q3 2008 were

$8.9 million ($0.10 per share), up 31% compared to Q3 2007 funds

from operations of $6.8 million ($0.07 per share). Through the

first three quarters of 2008, funds from operations have totaled

$30.8 million or $0.33 per share, up 43% compared to the first

three quarters of 2007. Higher production and stronger commodity

prices contributed to the increase.

- Land - Berens' total undeveloped land currently stands at 81,000

net acres. The undeveloped land base has increased in quality as

29 (15 net) sections of undeveloped land has been added in Pembina

so far in 2008 while reductions occurred due to drilling activity

and expiries primarily in Lanfine and non-core areas. We continue

to have approximately 100 locations in our drilling inventory.


Message to the shareholders

We at Berens are pleased to deliver to our shareholders continued strong production growth and a stronger balance sheet. We have consistently posted strong operating results for 2 years now and with our repeatable drilling plays and low cost structure, we believe we will continue to deliver this level of results.

We drilled actively in the third quarter and continued to be successful.



- Success in Pembina continued in the quarter with 7 (4.9 net) of 7

successes (6 drills and 1 recompletion) generating better than

average results for the quarter. These wells have come on stream

throughout the third quarter and early fourth quarter and are

providing a strong production increase as we enter the fourth

quarter with production levels over 4,300 boe/d.

- We were 4 for 7 in Lanfine, adding 350 boe/d in August from this

core area. An additional well (0.4 net) was drilled in Deep Basin

and is a suspended potential gas well.

- A very exciting development has been the casing of our first

successful horizontal well (0.5 net) in Pembina in early November.

The well is currently being completed and tested with initial

restricted test rates of 10 million cubic feet per day. This well

is expected to have longer term production capability of at least

3 million cubic feet per day. With the success of this well, we

expect to drill 3 more horizontal wells in first quarter of 2009.


Average production in the third quarter of 2008 was 4,110 boe/d which is 14% above a year ago and flat to second quarter as expected due to minimal activity in the second quarter. We are on track to execute the $40 million capital program announced in August with fourth quarter activity to include our Pembina horizontal well, 2 vertical Pembina drills, 2 Pembina recompletions and 1 Deep Basin well. This drilling activity along with our strong production momentum coming out of third quarter drilling results positions us well to achieve our fourth quarter average production guidance of 4,400 boe/d as well as provide strong momentum heading into 2009.

Our balance sheet is stronger with our current bank line of $66 MM now extended out to May, 2009 at which time, with our new reserve report in hand we are expecting another increase in capacity. With our debt levels remaining virtually unchanged from the end of 2007, we anticipate our debt to cash flow to drop to a respectable 1.4 by the end of the year. By maintaining our discipline on growing production by over 15% through spending within cash flow and delivering low cost production and reserves, we expect our balance sheet to continue to strengthen.

We continue to exploit our competitive advantage in our core areas based on intensive integration of technology, geology and geophysics resulting on low risk, repeatable plays. Our continued discipline on maintaining our low cost structure and delivering superior drilling results to date and in the future, makes us confident of our ability to repeat our 2007 finding and development costs of $13.00/boe in 2008 and onwards. We believe this is key to current and future value creation in today's markets.

We are pleased with our results, continue to stay focused on value creation, and are looking forward to our upcoming results that will generate increased shareholder value.



Sincerely,

Daniel F. Botterill

President & Chief Executive Officer

Berens Energy Ltd.

Third Quarter 2008

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

November 10, 2008


OVERVIEW

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

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

The following discussion of financial position and results of operations should be read in conjunction with the Company's December 31, 2007 audited financial statements and notes thereto and the unaudited September 30, 2008 interim financial statements and notes thereto. This MD&A was prepared using information that is current as of November 10, 2008 unless otherwise noted.

STRATEGY AND OBJECTIVES

The 2008 $40 million capital program will be funded by operating cash flow based on an forecasted natural gas price of $7.50 per mcf for the remainder of 2008. This program is expected to generate 2008 fourth quarter average production rates of 4,400 boe/d, about 16 percent higher than the fourth quarter 2007 average.

Longer term value is achieved by adding oil and natural gas reserves at low cost. The Company expects to replace 2008 production 2.5 times with new reserves at finding and development costs of approximately $13.00/boe. Operating and corporate netbacks are expected to be $35.00 per boe and $28.00 per boe respectively assuming a $7.50 per mcf price for natural gas and $80.00 per barrel for oil. Resulting recycle ratios are expected to be over 3.0 times on an operating netback basis and 2.5 times based on the corporate netback. Both of these measures will result in long term added value.

ECONOMIC UNCERTAINTY

Recent economic events have created volatility and an uncertain environment for stock and credit markets and commodity prices in the foreseeable future. Natural gas prices have fared much better than crude oil in recent months and are at levels above what we were realizing at this time last year. Berens has recently had its bank line of credit re-confirmed at $66 million at the same terms and conditions until a May 31, 2009 review date. Further, the Company has conducted its capital spending program within cash flow since the third quarter of 2006 and has shown consistent growth in both reserves and production volume since that time. Debt and working capital deficiency was $57 million at September 30, 2008, well within the capacity of the line of credit.

Berens has a focused asset base with high working interest and no significant land expiries. The Company operates approximately 85% of its planned capital spending. This high working interest and operatorship allows Berens to control the pace and focus of its capital spending to maintain financial flexibility in various commodity price and economic environments. The Company does not anticipate the current uncertainty in equity and credit markets to have a significant affect on the company's plans.

FORWARD LOOKING INFORMATION

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

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



QUARTERLY INFORMATION

2008

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

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Sales volumes:

Natural gas (mcf/day) 19,592 19,677 19,104

Oil and natural gas liquids (bbl/day) 845 859 628

Barrels of oil equivalent (bbl/day) 4,110 4,139 3,812

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Financial:

Net revenue 17,368 20,738 14,517

Net income (loss) 8,167 (1,612) (5,413)

per share - basic ($/share) $0.09 $(0.02) $(0.06)

per share - diluted ($/share) $0.09 $(0.02) $(0.06)

Capital costs 13,997 2,715 11,586

Shares outstanding (000's) 93,547 93,547 93,172

Bank debt 48,500 53,000 58,500

Working capital (deficit)

including bank debt (57,040) (64,942) (69,711)

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Per unit information:

Natural gas price ($/mcf) $8.77 $10.55 $8.12

Oil and liquids price ($/barrel) $100.31 $103.76 $81.76

Oil equivalent price ($/boe) $62.41 $71.70 $54.16

Operating netback ($/boe) $36.19 $46.31 $32.36

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Net wells completed: (No.)

Natural gas 9 - 5

Oil - - -

Dry 2 - -

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Total 11 - 5

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2007

($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

(bbl/day) 3,796 3,618 3,880 3,617

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Financial:

Net revenue 13,214 11,666 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) (58,593) (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

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Sales volumes:

Natural gas (mcf/day) 18,440

Oil and natural gas liquids

(bbl/day) 483

Barrels of oil equivalent

(bbl/day) 3,556

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Financial:

Net revenue 11,213

Net (loss) (21,951)

per share - basic ($/share) $(0.24)

per share - diluted ($/share) $(0.24)

Capital costs 12,811

Shares outstanding (000's) 92,947

Bank debt 50,080

Working capital (deficit)

including bank debt (56,271)

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Per unit information:

Natural gas price ($/mcf) $7.13

Oil and liquids price ($/barrel) $51.54

Oil equivalent price ($/boe) $43.96

Operating netback ($/boe) $24.24

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Net wells completed: (No.)

Natural gas 7

Oil -

Dry 1

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Total 8

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

RESULTS OF OPERATIONS

Production Volume

Volume averaged 4,110 boe/d for the quarter ended September 30, 2008, up 14 percent compared to 3,618 boe/d for the quarter ended September 30, 2007. Natural gas represented 79 percent of production in the third quarter of 2008 with the remaining production being 20 percent light oil and natural gas liquids and one percent conventional heavy oil. The majority of production additions have been from liquids rich natural gas wells in Pembina which has increased the ratio of oil and liquids in the production mix. For the nine months ended September 30, 2008 volume averaged 4,021 boe/d, up nine percent over the nine months ended September 30, 2007.

Drilling continued in all three core areas in the third quarter. A total of 14 wells (11.0 net) and one re-completion were completed in the third quarter with seven successful (4.9 net) natural gas wells in Pembina, one (0.4 net) suspended potential natural gas well in Deep Basin and four (3.75 net) natural gas wells in Lanfine with three (3.0 net) unsuccessful wells in Lanfine. Most of these wells were brought on stream in the second half of the quarter. As expected, third quarter 2008 production volumes were essentially unchanged from the second quarter of 2008. Production entering the fourth quarter was over 4,300 boe/d. Fourth quarter 2008 production is expected to average 4,400 boe/d as the successful third quarter wells will contribute for the entire fourth quarter and will be supplemented by ongoing drilling activity in Pembina and Deep Basin in the fourth quarter.

Production Revenue

Natural gas prices averaged $8.77 per mcf for the quarter ended September 30, 2008, up 48 percent compared to $5.94 per mcf in the quarter ended September 30, 2007. Oil and liquids prices averaged $112.27 and $97.01 per barrel respectively for the quarter ended September 30, 2008 for a blended price of $100.31 per barrel, up 56 percent from the quarter ended September 30, 2007 blended oil and liquids price of $64.11 per barrel. On a boe basis prices averaged $62.41 per boe in the quarter ended September 30, 2008, up 55 percent compared to $40.14 per boe in the quarter ended September 30, 2007. Oil and natural gas revenue was up 77 percent in the quarter ended September 30, 2008 compared to the quarter ended September 30, 2007 reflecting both volume and price increases. Realized hedging losses during the third quarter of 2008 were $6.98 per boe compared to realized hedging gains of $3.60 per boe in the third quarter of 2007.

For the nine months ended September 30, 2008, natural gas prices averaged $9.15 per mcf up 29 percent compared to $7.11 per mcf in the nine months ended September 30, 2007. Combined oil and liquids prices averaged $96.60 per barrel for the nine months ended September 30, 2008, up 66 percent from the nine months ended September 30, 2007 blended oil and liquids price of $59.66 per barrel. On a boe basis prices averaged $62.99 per boe in the nine months ended September 30, 2008, up 40 percent compared to $45.15 per boe in the nine months ended September 30, 2007. Oil and natural gas revenue was up 52 percent for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007 as both volume and prices increased. Realized hedging losses during the nine months ended September 30, 2008 were $4.78 per boe compared to realized hedging gains of $1.29 per boe in the nine months ended September 30, 2007.



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Three months Nine months

Volumes and prices ended September 30 ended September 30

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2008 2007 Change 2008 2007 Change

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Production revenue ($000's) 23,645 13,390 77% 69,446 45,718 52%

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Production volume

Natural gas (mcf/d) 19,592 18,288 7% 19,458 18,969 3%

Oil and liquids (bbl/d) 845 570 48% 778 543 43%

BOE (bbl/d) 4,110 3,618 14% 4,021 3,705 9%

Prices

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Natural gas ($/mcf) 8.77 5.94 48% 9.15 7.11 29%

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Oil and liquids ($/bbl) 100.31 64.11 56% 96.60 59.66 62%

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BOE ($/boe) 62.41 40.14 55% 62.99 45.15 40%

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BOE ($/boe including

hedging) 55.43 43.74 27% 58.21 46.44 25%

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Royalties

Royalties averaged 26 percent of revenue for the quarter ended September 30, 2008 compared to 20 percent for the quarter ended September 30, 2007. Higher prices in the third quarter of 2008 resulted in higher royalty rates. In addition, the 2007 period benefited from a fixed price sales contract at above Q3 2007 market prices causing the Q3 2007 royalty rate to be lower on a percent of revenue basis. Royalties averaged 24 percent of revenue for the nine months ended September 30, 2008 compared to 23 percent for the nine months ended September 30, 2007. Percent royalties in the third quarter of 2007 were lower due to an above market price fixed price contract that was in place during part of 2007 that caused the percent royalty rate to be lower.

Royalty expense of $6.3 million was recorded in the quarter ended September 30, 2008, up 130 percent compared to the quarter ended September 30, 2007 due to higher production volume, higher prices and higher percentage royalty rates. For the nine months ended September 30, 2008 royalty expense was $16.8 million, up 58 percent compared to the nine months ended September 30, 2007 again, due to higher production volume, prices and percent royalty rates.



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Three months Nine months

Royalties ended September 30 ended September 30

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2008 2007 Change 2008 2007 Change

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Royalty expense ($000's) 6,277 2,724 130% 16,823 10,628 58%

Royalty cost per boe $16.56 $8.19 102% $15.26 $10.51 45%

Royalty cost as a percent

of revenue 26% 20% 30% 24% 23% 4%

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Production Expenses

Production expenses were $8.76 per boe in the quarter ended September 30, 2008, up nine percent compared to $8.06 per boe in the quarter ended September 30, 2007. For the nine months ended September 30, 2008 production expenses were $8.25 per boe, up eight percent compared to the nine months ended September 30, 2007. Costs in 2008 have been higher due to ongoing inflationary pressures. Two significant workovers were completed in the quarter ended September 30, 2008 at a total cost of $164,000 ($0.43 per boe). With ongoing volume increases and cost management, it is expected per unit operating expenses will be in the $8.00 per boe range for the remainder of the year.

Production expenses for the quarter ended September 30, 2008 were $3.3 million, up 23 percent compared to the quarter ended September 30, 2007 due to higher volumes and higher per unit costs. For the nine months ended September 30, 2008 production expenses were $9.1 million, up 17 percent due to higher production and higher per unit costs.



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Three months Nine months

Production expenses ended September 30 ended September 30

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2008 2007 Change 2008 2007 Change

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Production expenses ($000's) 3,310 2,684 23% 9,084 7,756 17%

Production expenses per boe $8.76 $8.06 9% $8.25 $7.67 8%

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Transportation costs increased nine percent in the quarter ended September 30, 2008 compared to the quarter ended September 30, 2007 due to higher volumes.

Operating Netback(1)

Operating netback represents the margin realized by the production and sale of petroleum and natural gas exclusive of results from hedging. Third quarter 2008 operating netbacks improved due to higher commodity prices offset by higher percentage royalty costs and higher operating costs. Operating netbacks in 2008 were also eroded by realized hedging losses incurred during the six and nine month periods.



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Quarterly Operating Three months Nine months

Netbacks ($'s per boe) ended September 30 ended September 30

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2008 2007 Change 2008 2007 Change

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Sales price 62.41 40.14 55% 62.99 45.15 40%

Less:

Royalties 16.56 8.19 102% 15.26 10.51 45%

Production expenses 8.76 8.06 9% 8.25 7.67 8%

Transportation charges 0.90 0.94 (4%) 1.04 0.95 (9%)

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Operating netback 36.19 22.95 58% 38.45 26.03 48%

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Operating netback including

hedging 29.21 26.55 10% 33.67 27.32 23%

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


General and Administrative Expenses

For the quarter ended September 30, 2008 general and administrative ("G&A") expenses excluding stock based compensation were $1.5 million, up 46 percent compared to the quarter ended September 30, 2007. Staffing and overall compensation levels increased in 2008. Office maintenance and computer software and maintenance costs have also increased due to inflationary pressures. Stock based compensation expense declined in the third quarter of 2008 compared to the third quarter of 2007. In the second quarter of 2008 certain employees elected to relinquish high priced stock options which accelerated the amortization of the compensation cost for the remaining unvested term of the relinquished options resulting in lower amortization levels on a go forward basis for the remaining options.

On a per unit basis, for the quarter ended September 30, 2008 cash G&A costs excluding stock based compensation were $3.87 per boe, up 29 percent from $3.01 per boe for the quarter ended September 30, 2007 as volume increases partially offset the dollar increase in costs for the per unit calculation. Including stock based compensation, per unit costs were $4.31 per boe for the quarter ended September 30, 2008, up 16% compared to $3.71 for the quarter ended September 30, 2007. There were no general and administrative costs capitalized for the quarters ended September 30, 2008 or 2007.

For the nine months ended September 30, 2008 G&A costs excluding stock based compensation were $4.2 million, up 37 percent compared to the nine months ended September 30, 2007 due to the same reasons as outlined above. On a per unit basis, for the nine months ended September 30, 2008 per unit cash G&A costs excluding stock based compensation were $3.78 per boe, up 26 percent from $3.00 per boe for the nine months ended September 30, 2007 as volume increases partially offset the dollar increase in costs for the per unit calculation.

Staff levels are expected to remain fairly constant in 2008 and 2009. Per unit general and administrative costs are expected to decline as volume increases are experienced in the final quarter of 2008 and into 2009.



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General and Three months Nine months

administrative expenses ended September 30 ended September 30

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2007 2006 Change 2007 2006 Change

G&A expenses ($000's) 1,463 1,003 46% 4,149 3,032 37%

G&A expense per boe $3.87 $3.01 29% $3.78 $3.00 26%

Stock based compensation

($000's) 168 233 (28%) 862 666 29%

Stock based compensation

per boe $0.44 $0.70 (37%) $0.79 $0.66 20%

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Total 1,631 1,236 32% 5,012 3,698 36%

G&A expenses per boe $4.31 $3.71 16% $4.57 $3.66 25%

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Interest Expense

For the quarter ended September 30, 2008 interest expense was $0.7 million or 36 percent lower compared to $1.1 million for the quarter ended September 30, 2007. Average amounts drawn on the bank operating line in the third quarter of 2008 were nine percent lower than in the third quarter of 2007 and average interest rates have been lower in the 2008 period compared to 2007. In addition the borrowing premium charged by the bank has declined as the Company's debt to cash flow ratio has improved resulting in a 0.4 percent reduction in borrowing cost. On a per unit basis, interest expense was 44 percent lower in the quarter ended September 30, 2008 compared to the quarter ended September 30, 2007 as production volume has increased while debt levels and interest rates have decreased.

For the nine months ended September 30, 2008 interest expense was $2.3 million or 24 percent lower compared to $3.1 million for the nine months ended September 30, 2007 for the same reasons described above. On a per unit basis interest expense was 30 percent lower in the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007.



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Three months Nine months

Interest Expense ended September 30 ended September 30

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2008 2007 Change 2008 2007 Change

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Interest expense ($000's) 670 1,054 (36%) 2,332 3,079 (24%)

Interest expense per boe $1.77 $3.17 (44%) $2.12 $3.04 (30%)

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Depletion, Amortization and Accretion

In the quarter ended September 30, 2008 Depletion, Amortization and Accretion ("DA&A") totaled $9.0 million ($23.62 per boe) down eight percent and 19 percent on a per unit basis compared to $9.8 million ($29.21 per boe) for the quarter ended September 30, 2007. Ongoing drilling success and low cost reserve additions have brought down per unit DA&A rates throughout 2007 and 2008 such that overall depletion costs are lower despite increases in production volume. For the nine months ended September 30, 2008 DA&A totaled $28.0 million ($25.10 per boe), down six percent and down 13 percent on a per unit basis from $29.8 million ($29.14 per boe) for the nine months ended September 30, 2007.



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Depletion, Amortization Three months Nine months

and Accretion ended September 30 ended September 30

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2008 2007 Change 2008 2007 Change

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DA&A expense ($000's) 9,046 9,836 (8%) 27,979 29,802 (6%)

DA&A expense per boe $23.62 $29.21 (19%) $25.10 $29.14 (13%)

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Income Taxes

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

NET INCOME (LOSS)

Net income for the quarter ended September 30, 2008 was $8.2 million ($0.09 per share) compared to a net loss of $23.2 million ($0.25 per share) for the quarter ended September 30, 2007. The 2008 quarter benefited $12.1 million from a significant reduction in the unrealized hedging loss compared to June 30, 2008 while the 2007 period incurred a Goodwill write-down of $20.8 million. Adjusting for the after tax amount of the unrealized gain on risk management activities of $12.1 million in the third quarter of 2008 a net loss of $0.4 million would be realized. For the nine months ended September 30, 2008 net income was $1.1 million or $0.01 per share compared to a loss of $26.8 million or $0.29 per share for the nine months ended September 30, 2007. Again, adjusting for the after tax unrealized hedging loss recorded in the first nine months of 2008, net income was $1.0 million.

CAPITAL COSTS

For the quarter ended September 30, 2008 $13.9 million in capital costs on exploration and production activities were incurred, 63 percent higher than the amount spent in the quarter ended September 30, 2007. Marten Hills was sold in the quarter ended September 30, 2007 for proceeds of $6.75 million, reducing the net capital in the 2007 period to $1.9 million. A total of 14 (11.0 net) wells were drilled in the third quarter of 2008 compared to 9 (7.9 net) in the third quarter of 2007. For the nine months ended September 30, 2008 total spending was $28.1 million compared to $32.9 million ($26.2 million net of Marten Hills sale proceeds) in the first nine months of 2007. A total of 24 wells (16.4 net) were completed in the first nine months of 2008 compared to 25 wells (15.0 net) completed in the first nine months of 2007.



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Three months Nine months

($000's) ended September 30 ended September 30

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2008 2007 2008 2007

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Drilling and completion 10,162 6,777 19,357 21,293

Equipping and tie-ins 2,163 478 4,707 8,126

Land 1,465 750 3,070 1,376

Geological and geophysical 141 490 965 2,020

Office and other 7 37 14 52

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

Total 13,938 8,532 28,113 32,867

Cost of abandonment and

restoration paid 58 9 186 43

Asset retirement obligation (39) 127 350 298

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

Total capital 13,957 8,668 28,649 32,208

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

Net disposition - (6,750) - (6,750)

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

13,957 1,918 28,649 26,458

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


Drilling, completion, equip and tie-in activity represented 88 percent of the capital spent in the first nine months of 2008 as capital activity focused on developing the extensive land base. A $40 million capital budget is planned for 2008, 90 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 $12.9 million at September 30, 2008 were primarily revenue receivables ($6.5 million) and amounts owing from partners ($6.3 million). Accounts payable at September 30, 2008 of $21.6 million were mainly comprised of trade payables for capital and operating costs ($12.8 million), royalties ($1.9 million), amounts owing to partners ($3.7 million) and capital costs accrued at the end of the quarter for ongoing drilling and completion operations ($2.6 million).

Working capital excluding bank indebtedness and the unrealized loss on risk management activities was in a deficit position of $8.3 million at September 30, 2008 and is expected to be funded by ongoing cash flow and draws on the bank line of credit.

LIQUIDITY AND CAPITAL RESOURCES

The Company plans to fund its current working capital, operations and capital costs with a mix of operating cash flow and debt financing through the bank operating line. A bank line was in place for $66 million at September 30, 2008, secured by producing properties. Based on a recent review, the bank has extended the credit line at $66 million under existing terms and conditions until May 31, 2009. At September 30, 2008, $48.5 million was drawn on the bank line leaving $17.5 million capacity on the line. Future capital spending is planned in amounts that can be met with expected Company cash flow and its borrowing capacity within the bank line limit.

NON-GAAP MEASUREMENTS

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

The reconciliation between net income and funds from operations for the periods ended September 30 is as follows:



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

Three months Nine months

($000's) ended September 30 ended September 30

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

2008 2007 2008 2007

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

Cash flow provided by operating

activities 17,211 15,893 32,119 26,730

Changes in non-cash working

capital items related to

operating activities (8,268) (9,082) (1,337) (5,166)

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

Funds from operations 8,943 6,811 30,782 21,564

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


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 $0.10 per share (basic and diluted) for the quarter ended September 30, 2008 compared to $0.07 for the quarter ended September 30, 2007 as funds from operations increased with higher volume and commodity prices. A total of 375,000 shares were issued in the past year for stock options exercised. For the nine months ended September 30, 2008 funds from operations per share were $0.33 per share compared to $0.23 per share for the nine months ended September 30, 2007.

RISKS

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

The Company entered into an interest rate swap transaction in January 2008 to fix the interest rate on $25.0 million of its variable rate demand bank line. The transaction fixes the interest rate for a two year period at a rate of 5.21 percent including the Company's borrowing margin on its bank line. The fair value of the interest rate derivative instrument marked-to-market as at September 30, 2008 resulted in an unrealized loss of $176,000 as interest rates have declined since the time the interest rate swap was transacted. There were no interest rate derivatives in place in 2007.

Other risks are related to operations. These risks include, but are not limited to, risks associated with oil and gas regulation, 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. All commodity price and interest rate derivatives have been transacted with a major Canadian bank and the transactions are governed by a credit agreement between the Company and the bank.

The following is a summary of natural gas and crude oil price risk management financial derivative contracts in effect as of the date of this MD&A. All natural gas contracts are priced in Canadian dollars per gigajoule (GJ). The price per GJ can be converted to an approximate price per MCF by multiplying the per GJ price by 1.05. GJ can be converted to an approximate MCF volume by multiplying the GJ volume by 0.95.



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

NATURAL GAS HEDGING

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

Daily

quantity

(GJ) Term of Contract Fixed price per gigajoule

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

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

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

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

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

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

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

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

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

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

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

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

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



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

CRUDE OIL HEDGING

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

Daily

quantity Fixed price per barrel

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

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

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

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

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

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


The fair value of the above natural gas derivative instruments marked to market as at September 30, 2008, results in an unrealized loss position of $221,000 compared to an unrealized gain position of $162,000 at December 31, 2007 as crude oil and natural gas prices have increased somewhat since December 31, 2007. There was $2,637,000 ($6.97 per boe) of realized losses on derivative instruments for the quarter ended September 30, 2008 (2007 - $1,198,000 gain). For the nine months ended September 30, 2008 $5,238,000 ($4.77 per boe) in realized losses on derivative instruments were recorded (2007 - $1,306,000 gain). The average fixed price of the natural gas hedging transactions for the remainder of 2008 is $6.76 per GJ ($7.12 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. These amounts are calculated on estimated production amounts of 4,000 boe/d.



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

Commodity Price change Cash flow change

($ 000's)

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

Natural gas ($/mcf) 1.00 $5,900

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

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

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


RELATED PARTY TRANSACTIONS

A consulting firm is contracted from time to time in which one of the Company's directors is the chairman and founding partner. The executive services rendered are in the normal course of business and are at normal rates charged by the consulting firm and recorded at the exchange amount. Consulting fees for this firm in the third quarter and the first nine months of 2008 were $14,600 (2007 - nil). 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 third quarter of 2008 were $68,000 and $230,000 for the nine months ended September 30, 2007 (2007 - $54,000 and $183,000).

SHARE DATA

As of the date of this MD&A the Company had 93,547,064 issued and outstanding common shares. Additionally, as at November 10, 2008 options to purchase 5,968,700 common shares have been issued.

DISCLOSURE CONTROLS AND PROCEDURES OVER FINANCIAL REPORTING

The Company has established procedures and internal control systems designed to ensure timely and accurate preparation of financial, internal management and other reports. Disclosure controls and procedures are in place designed to ensure all ongoing statutory reporting requirements are met and material information is disclosed on a timely basis. The Chief Executive Officer and the Chief Financial Officer, individually, sign certifications that the financial statements, together with the other financial information included in the regulatory filings, fairly present in all material respects the financial condition, results of operation, and cash flows as of the dates and for the periods represented.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Berens is responsible for establishing and maintaining adequate internal controls over financial reporting. Internal controls over financial reporting are part of a process designed under the supervision of the Chief Executive Officer and the Chief Financial Officer and monitored by the Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles ("GAAP").

The Company reported on these controls as part of its 2007 continuous disclosure requirements (please refer to the MD&A for the year ended December 31, 2007 available on SEDAR (www.SEDAR.com) and on our website www.berensenergy.com). There have been no changes to internal controls over financial reporting or management's assessment of the design of these internal controls in the period since December 31, 2007.

RISKS AND UNCERTAINTIES, CRITICAL ACCOUNTING ESTIMATES AND RECENT ACCOUNTING PRONOUNCEMENTS

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

CHANGES IN ACCOUNTING POLICIES

Financial instruments presentation and disclosure

Effective January 1, 2008, the Company adopted the new Canadian Institute of Chartered Accountants (CICA) recommendations relating to Financial Instruments - Disclosure (section 3862) and Financial Instruments - Presentation (section 3863). The new disclosure required by section 3862 concerning the nature and extent of the risks associated with financial instruments and how those risks are managed, is presented in note 10. Effective January 1, 2008 the Company adopted CICA recommendations relating to Capital Disclosures (section 1535).

Inventories

Effective January 1, 2008 new CICA recommendations relating to Inventories (section 3031) came into effect. The new standard provides additional guidance concerning measurement, classification and disclosure and allows the reversal of write-downs to net realizable value when there is a change in the circumstances giving rise to the impairment. The Company had adopted these recommendations for the December 31, 2007 financial statements which resulted in a re-classification of certain inventory to property, plant and equipment. At December 31, 2007 $901,000 of inventory was re-classified to property, plant and equipment.

International Financial Reporting Standards

In February 2008, the Canadian Accounting Standards Board confirmed that the use of International Financial Reporting Standards ("IFRS") will be required in 2011 for publicly accountable profit-oriented enterprises. IFRS will replace Canada's current GAAP for listed companies and other profit-oriented enterprises that are responsible to large or diverse groups of stakeholders. Companies will be required to provide one year of comparative date in accordance with IFRS.

In the second quarter of 2008 the Company began to develop its IFRS changeover plan. Initial activities include training sessions and acquisition of written standards and examples of IFRS disclosure to identify where key differences between Canadian GAAP and IFRS exist. The Company intends to disclose its convergence plan and qualitative effects of IFRS on its financial statements as they become more fully developed.

For a discussion of Risks and Uncertainties, Critical Accounting Estimates and Recent Accounting Pronouncements please refer to the audited financial statements and the Annual Information Form for the year ended December 31, 2007 available on SEDAR (www.SEDAR.com) and on our website (www.berensenergy.com).

OUTLOOK

Consistent drilling success has been experienced throughout 2007 and the first three quarters of 2008 resulting in steady increases to production volume and cash flows. Capital spending has been within the Company's cash flow since the beginning of 2007. The success of the capital spending and resultant increases in cash flow has resulted in a significantly improved balance sheet. An increase to the capital budget was announced in August 2008 to $40 million from the original budget of $30 million. The increase in capital spending is expected to remain within cash flow estimated for the year and debt levels are expected to approximately 1.4 times cash flow at year end.

The increase in the capital spending budget is being focused in Pembina where the reserve life of new wells is longest and the wells have the strongest economics. The Company currently has 100 inventoried drilling locations on existing lands with the majority of these locations in Pembina. A horizontal well in Pembina was cased in early November and will be tied in during November. With the success of this well, the Company has identified a number of additional horizontal well locations to be drilled in 2009. Two remaining vertical wells are planned for Pembina in the fourth quarter of 2008 with one additional well in Deep Basin planned before the end of the year.

Debt and working capital balances have improved and will continue to improve as recent drilling success is repeatable with well defined, technically supported plays. Based on third quarter results, on an annualized basis, debt and working capital represents 1.6 times funds from operations. Fourth quarter 2008 production is expected to average 4,400 boe/d, a 16 percent increase over the fourth quarter of 2007 and 7 percent above Q3 2008. This production gain is forecasted with year-end debt levels expected to be unchanged from the end of 2007.



Berens Energy Ltd.

Balance Sheets - unaudited

As at,

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

September 30, December 31,

(000's) 2008 2007

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

ASSETS (note 6)

Current

Cash and cash equivalents $ 1 $ 1

Accounts receivable 12,878 10,315

Unrealized gain on risk management (note 10) - 162

Prepaid expenses and deposits 378 442

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

13,257 10,920

Property, plant and equipment (note 4) 167,357 166,405

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

$ 180,614 $ 177,325

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

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

LIABILITIES AND SHAREHOLDERS' EQUITY

Current

Bank loan (note 6) $ 48,500 $ 53,900

Accounts payable and accrued liabilities 21,562 16,523

Unrealized loss on risk management (note 10) 221 -

Taxes payable 14 14

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

70,297 70,437

Asset retirement obligations (note 5) 3,907 3,273

Future income taxes 10,615 10,199

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

84,819 83,909

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

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

Shareholders' equity

Capital stock (note 7) 148,638 148,263

Contributed surplus (note 7) 3,057 2,195

Deficit (55,900) (57,042)

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

95,795 93,416

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

$ 180,614 $ 177,325

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

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

See accompanying notes to the unaudited interim financial statements



Berens Energy Ltd.

Statements of Operations, Comprehensive Income (Loss) and Deficit -

unaudited

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

Three months ended Nine months ended

(000's) September 30, September 30,

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

2008 2007 2008 2007

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

Revenue

Oil and natural gas revenue $ 23,645 $ 13,390 $ 69,446 $ 45,718

Royalties (6,277) (2,724) (16,823) (10,628)

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

17,368 10,666 52,623 35,090

Realized gain (loss) on

commodity price risk

management (note 10) (2,637) 1,198 (5,238) 1,306

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

14,731 11,864 47,385 36,396

Unrealized gain (loss) on

commodity price risk

management (note 10) 12,087 (5) (207) 822

Other income - 31 119 31

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

26,818 11,890 47,297 37,249

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

Expenses

Production 3,310 2,684 9,084 7,756

Transportation 341 313 1,146 961

Depletion, amortization and

accretion 9,046 9,836 27,979 29,802

Impairment of goodwill - 20,755 - 20,755

General and administrative

(note 9) 1,463 1,003 4,149 3,032

Stock-based compensation

(note 7) 168 233 862 666

Interest 670 1,054 2,332 3,079

Unrealized loss on interest

rate risk management

(note 10) 132 - 176 -

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

15,130 35,878 45,728 66,051

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

Income (loss) before income

taxes 11,688 (23,988) 1,569 (28,802)

Income taxes

Future expense (recovery) 3,517 (861) 417 (2,077)

Current expense 4 30 10 35

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

3,521 (831) 427 (2,042)

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

Net income (loss) and

comprehensive income

(loss) for the period 8,167 (23,157) 1,142 (26,760)

Deficit, beginning of period (64,067) (33,205) (57,042) (29,602)

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

Deficit, end of period $(55,900) $(56,362) $(55,900) $(56,362)

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

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

Net income (loss) per share

(note 11)

Basic and diluted $ 0.09 $ (0.25) $ 0.01 $ (0.29)

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

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

See accompanying notes to the unaudited interim financial statements



Berens Energy Ltd.

Statements of Cash Flows - unaudited

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

Three months ended Nine months ended

(000's) September 30, September 30,

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

2008 2007 2008 2007

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

OPERATING ACTIVITIES

Net income (loss) for the

quarter $ 8,167 $(23,157) $ 1,142 $(26,760)

Add items not involving cash

Depletion, amortization

and accretion 9,046 9,836 27,979 29,802

Impairment of Goodwill - 20,755 - 20,755

Unrealized risk management

loss (gain) (11,955) 5 383 (822)

Future income tax expense

(recovery) 3,517 (861) 417 (2,077)

Stock-based compensation 168 233 862 666

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

8,943 6,811 30,783 21,564

Payments for abandonment and

restoration (58) (9) (186) (43)

Change in non-cash working

capital items related to

operating activities (note 8) 8,268 9,082 1,337 5,166

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

Cash flow provided by operating

activities 17,153 15,884 31,394 26,687

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

FINANCING ACTIVITIES

Change in bank loan (4,500) (11,900) (5,400) 720

Proceeds from exercise of stock

options - - 375 225

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

Cash flow provided by financing

activities (4,500) (11,900) (5,025) 945

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

INVESTING ACTIVITIES

Purchase of property and

equipment (13,938) (8,532) (28,113) (32,867)

Proceeds from sale of

investment - 3 - 29

Proceeds from disposition of

assets - 6,750 - 6,750

Change in non-cash working

capital items related to

investing activities (note 8) 1,285 (2,214) 1,204 (1,553)

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

Cash flow used in investing

activities (12,653) (3,993) (26,909) (27,641)

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

Increase (decrease) in cash and

cash equivalents - (9) - (9)

Cash and cash equivalents,

beginning of period 1 10 1 10

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

Cash and cash equivalents,

end of period $ 1 $ 1 $ 1 $ 1

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

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

See accompanying notes to the unaudited interim financial statements



BERENS ENERGY LTD.

Notes to Financial Statements - unaudited

Three and nine months ended September 30, 2008 and 2007

1. NATURE OF OPERATIONS

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

exploration and production company with activities encompassing land

acquisition, geological and geophysical assessment, drilling and

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

and west central Alberta.

2. SEASONALITY

Significant capital spending activity occurs in the winter months in the

western Canadian oil and natural gas business as many areas are only

accessible or best accessed in the winter months when the ground is

frozen. Limited capital spending activity tends to occur in the second

calendar quarter as the industry experiences "spring break-up" when there

is significant water on the ground due to melting snow and road

capacities are limited as winter frost melts and the roads are wet and

unable to support heavy loads. Normal oil and gas operations tend to

return in June each year.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The financial statements have been prepared by management in accordance

with Canadian generally accepted accounting principles ("GAAP"). The

nature of the business and timely preparation of financial statements

requires that management make estimates and assumptions, and use judgment

regarding assets, liabilities, revenues and expenses. Such estimates

primarily relate to unsettled transactions and events as of the date of

the financial statements. Accordingly, actual results may differ from

estimated amounts. In the opinion of management, these financial

statements have been properly prepared within reasonable limits of

materiality and within the framework of the significant accounting

policies summarized below.

Certain disclosures, which are normally required to be included in notes

to the annual financial statements, are condensed or omitted for interim

reporting purposes. Accordingly, these interim financial statements

should be read in conjunction with the audited annual financial

statements for the year ended December 31, 2007. Certain prior period

amounts have been reclassified to conform to current disclosure.

The financial statements have been prepared following the same accounting

policies and methods of computation as the Annual Financial Statements

for the year ended December 31, 2007 except as noted below.

a) CHANGES IN ACCOUNTING POLICIES

Financial instruments presentation and disclosure

Effective January 1, 2008, the Company adopted the new Canadian Institute

of Chartered Accountants (CICA) recommendations relating to Financial

Instruments - Disclosure (section 3862) and Financial Instruments -

Presentation (section 3863). The new disclosure required by section 3862

concerning the nature and extent of the risks associated with financial

instruments and how those risks are managed, is presented in note 10.

Effective January 1, 2008 the company adopted CICA recommendations

relating to Capital Disclosures (section 1535). As permitted, comparative

information for the disclosure required by section 3862 has not been

provided.

Inventories

Effective January 1, 2008 new CICA recommendations relating to

Inventories (section 3031) came into effect. The new standard provides

additional guidance concerning measurement, classification and disclosure

and allows the reversal of write-downs to net realizable value when there

is a change in the circumstances giving rise to the impairment. The

Company had adopted these recommendations for the December 31, 2007

financial statements which resulted in a re-classification of certain

inventory to property, plant and equipment. At December 31, 2007 $901,000

of inventory was re-classified to property, plant and equipment.

International Financial Reporting Standards

In February 2008, the Canadian Accounting Standards Board confirmed that

the use of International Financial Reporting Standards ("IFRS") will be

required in 2011 for publicly accountable profit-oriented enterprises.

IFRS will replace Canada's current GAAP for listed companies and other

profit-oriented enterprises that are responsible to large or diverse

groups of stakeholders. Companies will be required to provide one year of

comparative date in accordance with IFRS.

In the second quarter of 2008 the Company began to develop its IFRS

changeover plan. Initial activities include training sessions and

acquisition of written standards and examples of IFRS disclosure to

identify where key differences between Canadian GAAP and IFRS will exist.

The Company intends to disclose its convergence plan and qualitative

effects of IFRS on its financial statements as they become more fully

developed.

4. PROPERTY, PLANT AND EQUIPMENT

September 30, 2008 December 31, 2007

Accumulated Accumulated

depletion and depletion and

($000's) Cost depreciation Cost depreciation

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

Petroleum and

natural gas

properties 302,702 135,696 274,067 108,045

Office and

computer

equipment 748 397 734 351

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

303,450 136,093 274,801 108,396

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

Net book value 167,357 166,405

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

At September 30, 2008, costs of $21,420,000 (December 31, 2007 -

$21,159,000) related to undeveloped land have been excluded from the

depletion calculation. At September 30, 2008 estimated future development

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

calculation. A ceiling test was completed at September 30, 2008 resulting

in no impairment. Benchmark pricing used for ceiling test purposes is

shown in the following table.

Edmonton

Crude

Oil FOB

Par Field

Price Hardisty AECO-C Gate Infla-

WTI 40 degrees Heavy Gas (propane/ tion Exchange

Cushing API Oil Price butane) rate % rate

Oklahoma ($Cdn/ ($Cdn/ ($Cdn/ ($Cdn/ per ($US/

Year ($US/bbl) bbl) bbl) MMbtu) bbl) year Cdn)

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

Forecast

2008 Q4 100.00 101.64 83.35 7.13 69.11 2.0 1.00

2009 98.04 99.10 76.31 7.50 69.86 2.0 1.00

2010 96.12 99.10 75.48 7.65 69.86 2.0 1.00

2011 94.23 99.10 75.32 8.00 69.86 2.0 1.00

2012 90.57 99.10 75.32 8.25 69.86 2.0 1.00

2013 90.00 99.10 75.32 8.50 69.86 2.0 1.00

5. ASSET RETIREMENT OBLIGATIONS

The total future asset retirement obligations were estimated based on the

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

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

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

value of the total asset retirement obligations is $4,093,000 as at

September 30, 2008 (December 31, 2007 - $3,273,000) based on a total

future liability of $9,764,000 (December 31, 2007 - $8,611,000). These

payments are expected to be made over the next 5 to 15 years. An

inflation rate of 2 percent and a credit adjusted risk free rate of 10

percent were used to calculate the present value of the asset retirement

obligations.

The following table reconciles the asset retirement obligations:

($000's) 2008

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

Obligation, January 1, 2008 3,273

Increase in obligation during the period 538

Paid for abandonments (186)

Accretion expense 282

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

Obligation, September 30, 2008 3,907

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

6. BANK OPERATING LINE

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

totaling $66.0 million at September 30, 2008. Collateral for the facility

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

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

$75.0 million supplemental debenture with a floating charge over all

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

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

most recent quarterly debt to cash flow calculation. The adjustment

factor ranges from 0.00% if debt to cash flow is below 1 times to 1.25%

if debt to cash flow is above 2.5 times. The average rate paid for the

quarter ended September 30, 2008 was 5.4 percent and for the nine months

ended September 30, 2008 6.1 percent (2007 - 7.7 and 8.2 percent).

7. CAPITAL STOCK

(a) Authorized Capital

The authorized capital consists of an unlimited number of preferred

shares issuable in series and an unlimited number of common shares

without nominal or par value.

(b) Common shares issued

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

Consideration

Number ($000's)

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

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

Shares issued on exercise of stock

options 225,000 225

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

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

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

Shares issued on exercise of stock

options 375,000 375

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

Balance September 30, 2008 93,547,064 148,638

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

(c) Stock Option Plan

A stock option plan is in place under which 10 percent of the number of

outstanding common shares is reserved for options to be granted to

directors, officers, employees and consultants with terms established by

the Board of Directors.

Options granted under the plan generally have a five year term to expiry

and vest equally over a three year period commencing on the first

anniversary date of the grant. The exercise price of each option equals

the closing market price of the Company's common shares on the day prior

to the date of the grant.

The following table sets forth a reconciliation of the plan activity for

the nine months ended September 30, 2008:

2008 2007

Weighted Weighted

average average

exercise exercise

price price

Number of ($ per Number of ($ per

Options share) Options share)

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

Outstanding, beginning of

period 6,238,200 1.42 4,416,200 1.68

Granted 1,791,000 1.00 2,309,500 0.94

Cancelled (1,215,500) 2.63 (259,167) 1.98

Exercised (845,000) 1.00 (225,000) 1.00

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

Outstanding, end of

period 5,968,700 1.11 6,241,533 1.42

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

Exercisable 2,522,056 1.25 2,740,696 1.44

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

The following table sets forth additional information relating to the

stock options outstanding at September 30, 2008:

Options Outstanding Exercisable Options

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

Weighted Weighted

average average

exercise Weighted exercise Weighted

price average price average

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

range Options share) expiry Options share) expiry

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

$0.50 to $0.99 2,739,500 0.89 3.90 591,361 0.89 3.57

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$1.00 to $1.49 2,518,700 1.21 2.74 1,352,030 1.26 1.31

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$1.50 to $1.99 705,500 1.61 1.69 575,332 1.60 1.43

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$2.00 to $2.49 - - - - - -

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$2.50 to $3.00 5,000 2.90 2.17 3,333 2.17 2.90

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$0.50 to $3.00 5,968,700 1.11 3.15 2,522,056 1.25 1.87

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The fair value method for measuring option awards based on the Black

Scholes valuation model is used. Key assumptions used for the Black-

Scholes based valuations of options are: Risk free rate - 3.2%; average

expected life - 4.5 years; no expected dividend yield; 46 percent

volatility. Estimated future forfeiture assumptions are not used in

calculations as forfeitures are recognized as they occur. The weighted

average fair value at the dates of grant for the options outstanding at

September 30, 2008 is $0.60 per option. For the quarter ended September

30, 2008, $168,000 and for the nine months ended September 30, 2008

$862,000 was recorded for stock based compensation (2007 - $233,000 and

$666,000 respectively) with a corresponding increase recorded to

contributed surplus. During 2008 a total of 470,000 options expired and

pursuant to the provisions of the Company's option plan the option

holders elected to receive a cash settlement for the difference between

the market price and the option strike price in lieu of exercising the

stock option resulting in no shares being issued for the exercise of

these options.

(d) Contributed Surplus

The following table sets forth the continuity of contributed surplus for

the period ended September 30, 2008:

($000's)

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

December 31, 2007 2,195

2008 Stock based compensation expense 862

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

September 30, 2008 3,057

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No adjustment has been made to Contributed Surplus for the stock options

exercised during 2008 as these options were issued as a private company

prior to the Company becoming publicly traded and were assigned a nominal

value.

8. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in Non-cash Working Capital

For the nine months ended September 30,

2008 2007

($000's)

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

Accounts receivable (2,564) 9,690

Prepaid expenses and deposits 65 (222)

Accounts payable and accrued liabilities 5,040 (5,836)

Taxes payable - (19)

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Change in non-cash working capital 2,541 (3,613)

Change in non-cash working capital related to investing

activities 1,204 (1,553)

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Change in non-cash working capital related to operating

activities 1,337 5,166

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Cash interest and taxes paid

For the three and nine months ended September 30,

Three Three Nine Nine

($000's) months months months months

2008 2007 2008 2007

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

Income and other taxes - - 10 -

Interest 670 1,054 2,332 3,079

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9. RELATED PARTY TRANSACTIONS

A consulting firm is contracted from time to time in which one of the

Company's directors is the chairman and founding partner. The executive

services rendered are in the normal course of business and are at normal

rates charged by the consulting firm and recorded at the exchange amount.

Consulting fees for this firm in the third quarter and the first nine

months of 2008 were $14,600 (2007 - nil). 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 third

quarter of 2008 were $68,000 and $230,000 for the nine months ended

September 30, 2007 (2007 - $54,000 and $183,000).

10. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Financial assets and liabilities recognized on the balance sheets consist

of cash and cash equivalents, accounts receivable, deposits, accounts

payable, accrued liabilities, bank loan and financial derivatives used to

manage interest rate, natural gas and oil price risk.

Fair value of financial assets and liabilities

Cash, cash equivalents, deposits, financial derivatives and bank

indebtedness are designated as "held-for-trading" and recorded at the

estimated fair market value. The fair value of these financial

instruments approximates their carrying amounts due to their short terms

to maturity except for derivatives used for interest rate and commodity

price risk management which values are outlined below. Accounts

receivable are designated as "loans and receivables" and accounts payable

are designated as "other liabilities" and are recorded at their carrying

costs.

(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 these risks by entering into

transactions with long-standing, reputable counterparties and partners.

If significant amounts of capital are to be spent on behalf of a joint

venture partner the partner is "cash called" in advance of the capital

spending taking place. The maximum credit exposure with accounts

receivable is the carrying value. At September 30, 2008, the largest

single credit exposure was approximately $6.0 million from the Company's

sales agent the balance of which is settled monthly. At September 30,

2008, nine percent of accounts receivable were non-current as defined by

accounts over 90 days outstanding. Management has assessed these

customers and the amounts owing and no allowance for doubtful accounts

receivable was required nor were any balances deemed to be impaired.

(b) Interest Rate Risk

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

which charges interest at variable market rates. The Company entered into

an interest rate swap transaction in January 2008 to fix the interest

rate on $25.0 million of its variable rate demand bank line. The

transaction fixes the interest rate for a two year period at a rate of

5.21 percent including the Company's borrowing margin on its bank line.

Fair values for interest rate derivatives are provided by the financial

intermediary with whom the transactions were completed and tested by the

Company for reasonableness based on comparing current market prices and

the fixed prices of the contracts. The fair value of the interest rate

derivative instrument marked-to-market as at September 30, 2008 results

in an unrealized loss of $176,000 for the nine months ended September 30,

2008. There were no interest rate derivatives in place in 2007. The net

income effect of a one percent change in short-term interest rates on the

remaining amount of bank debt is approximately $225,000.

(c) Foreign Exchange Risk

The Company is exposed to the risk of changes in the Canadian/US dollar

exchange rates on sales of commodities that are denominated in U.S.

dollars or directly influenced by U.S. dollar benchmark prices. No

specific currency hedging has been undertaken, however, all commodity

price risk management activities hedge revenue into Canadian dollars. The

net income effect of a $0.01 change in the exchange rate between the US

and Canadian dollars is approximately $575,000.

(d) Commodity Price Risk Management

The Company is exposed to the risk of changes in market prices for

natural gas, crude oil and natural gas liquids. The Company may mitigate

this risk by entering into derivatives based fixed price contracts or

price collars or may enter into fixed price physical delivery contracts.

The following is a summary of natural gas price risk management

derivative contracts in effect as of September 30, 2008. All natural gas

contracts are priced in Canadian dollars per gigajoule ("GJ"). The price

per GJ can be converted to an approximate price per million cubic feet

("MCF") by multiplying the per GJ price by 1.05. GJ volume can be

converted to an approximate MCF volume by multiplying the GJ volume by

0.95.

Natural Gas Risk Management Contracts

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

Daily

quantity Fixed price per gigajoule

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

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

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

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

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

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

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

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

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

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

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

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

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

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



Crude Oil Risk Management Contracts

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

Daily

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

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

Fair values for commodity price derivatives are provided by the financial

intermediary with whom the transactions were completed and tested by the

Company for reasonableness based on comparing current market prices and

the fixed prices of the contracts. The fair value of the above natural

gas and crude oil derivative instruments marked-to-market as at September

30, 2008 results in an unrealized loss of $221,000 (December 31, 2007 -

gain of $162,000). For the quarter ended September 30, 2008 a $12,087,000

gain was recorded reflecting the change in the balance sheet mark-to-

market position from June 30, 2008. Total realized losses from risk

management activities in the third quarter of 2008 were $2,637,000

(2007 - $1,198,000 gain). Total realized losses for the nine months ended

September 30, 2008 were $5,238,000 (2007 - $1,306,000 gain). Commodity

price and interest rate derivatives are transacted with large, credit

worthy counterparties and governed by credit agreements between the

Company and its counterparties.

Absent the above-noted risk management contracts, the effects of changes

in commodity prices on annual net income summarized in the following

table on the basis of average annual production of approximately 4,000

boe/d.

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

Commodity Price change Net Income change

($ 000's)

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

Natural gas ($/mcf) 1.00 $4,200

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

Oil and Liquids ($/bbl) 10.00 $1,100

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

(e) Liquidity Risk and Capital Requirements

The Company is exposed to liquidity risk, which is the risk that the

Company may be unable to generate or obtain sufficient cash to meet its

commitments as they become due. The financial liabilities on the balance

sheet consist of accounts payable, bank debt and taxes payable. This risk

is mitigated through the management of cash and debt and the Company may

adjust capital spending, issue new shares or draw or repay its operating

bank line. The Company's primary capital management objective is to

maintain a strong balance sheet to provide the financial flexibility to

respond to cash flow volatility or an investment opportunity. The Company

maintains appropriate unused capacity in its operating bank line to meet

short term fluctuations from forecasted results. The Company has no

externally imposed capital requirements but is subject to a working

capital test as a covenant on its operating bank line.

Forecasted cash flows and operating and capital outlays are updated

frequently to ensure necessary liquidity remains available. The Company

may hedge a portion of its future production and/or its interest rate

exposure to protect cash flows. All of the Company's financial

obligations are either demand or are due within one year. The Company is

targeting to reduce its debt and working capital to funds from operations

ratio to a measure of 1.5:1 on a current quarter annualized basis

(excluding unrealized hedging gains and losses from working capital),

down from historical ratios of over 2:1. For the quarter ended September

30, 2008 this ratio was 1.6:1.

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

Target

At September 30 ($000's) Measure 2008 2007

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

Components of Ratio

Current assets 13,257 13,003

Current liabilities (70,297) (71,597)

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

(57,040) (58,594)

Unrealized risk management loss (gain) 221 (1,457)

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

Debt and working capital (56,891) (60,051)

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

Funds from operations - three months

ended September 30 annualized(1) 35,772 27,244

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

Ratio 1.5:1 1.6:1 2.2:1

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

(1) Funds from operations is a non-GAAP measure defined as: operating

cash flow adjusted for changes in non-cash working capital related to

operating activities, all annualized.

11. PER SHARE INFORMATION

The weighted average number of common shares outstanding for the quarter

ended September 30, 2008 of 93,547,064 was used to calculate basic and

diluted income (loss) per share (2007 - 93,172,064 basic and diluted).

The weighted average number of common shares outstanding for the nine

months ended September 30, 2008 was 93,304,820 to calculate basic income

per share and 93,332,332 to calculate diluted income (2007 - 93,031,771

basic and diluted). The total number of shares which are potentially

dilutive in future periods as of September 30, 2008 was 5,968,700.

Caution Regarding Forward Looking Information

This press release contains forward looking information within the

meaning of applicable securities laws. Forward looking statements may

include estimates, plans, expectations, forecasts, guidance or other

statements that are not statements of fact. Forward looking information

in this Press Release includes, but is not limited to, statements with

respect to capital expenditures and related allocations, production

volumes, production mix and commodity prices.

Forward-looking statements and information are based on current beliefs

as well as assumptions made by and information currently available to

Berens concerning anticipated financial performance, business prospects,

strategies and regulatory developments. Although management considers

these assumptions to be reasonable based on information currently

available to it, they may prove to be incorrect.

By their very nature, forward-looking statements involve inherent risks

and uncertainties, both general and specific, and risks that predictions,

forecasts, projections and other forward-looking statements will not be

achieved. We caution readers not to place undue reliance on these

statements as a number of important factors could cause the actual

results to differ materially from the beliefs, plans, objectives,

expectations and anticipations, estimates and intentions expressed in

such forward-looking statements. These factors include, but are not

limited to: crude oil and natural gas price volatility, exchange rate and

interest rate fluctuations, availability of services and supplies, market

competition, uncertainties in the estimates of reserves, the timing of

development expenditures, production levels and the timing of achieving

such levels, the Company's ability to replace and increase oil and gas

reserves, the sources and adequacy of funding for capital investments,

future growth prospects and current and expected financial requirements

of the Company, the cost of future abandonment and site restoration, the

Company's ability to enter into or renew leases, the Company's ability to

secure adequate product transportation, changes in environmental and

other regulations and general economic conditions.

The forward-looking statements contained in this press release are made

as of the date of this press release, and Berens does not undertake any

obligation to up-date publicly or to revise any of the included forward-

looking statements, whether as a result of new information, future events

or otherwise. This cautionary statement expressly qualifies the forward-

looking statements contained in this press release.

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