Berens Energy Ltd.

November 07, 2007 23:59 ET

Berens Energy Ltd. Releases Results for the Three and Nine Months Ended September 30, 2007

CALGARY, ALBERTA--(Marketwire - Nov. 7, 2007) -



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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% %

2007 2006 Change 2007 2006 Change

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Sales volume

Natural gas

(mcf/day) 18,288 17,355 5% 18,969 17,077 11%

Oil and ngls

(bbl/day) 570 479 19% 543 465 17%

boe/day

(6 to 1) 3,618 3,372 7% 3,705 3,311 12%

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Revenue net of

royalties 10,666 9,536 12% 35,089 28,905 21%

Net income (loss) (23,157) (2,662) (26,760) (6,389)

Per share (basic

and diluted) $(0.25) $(0.03) - $(0.29) $(0.07) 14%

Funds from

operations(1) 6,811 5,084 34% 21,563 16,352 32%

Per share (basic

and diluted)(1) $0.07 $0.06 17% $0.23 $0.19 21%

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Capital costs

Exploration and

development 7,264 11,087 (34%) 29,462 40,763 (28%)

Acquisition

(disposition) (6,750) (1,764) (6,750) (1,764)

Land and seismic 1,240 363 42% 3,396 4,396 (23%)

Other 37 60 52 708

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Total 1,791 9,746 26,160 44,103

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Net wells completed

(No.) 7 4 14 21

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Net working capital

(deficit) -

including bank

debt (58,593) (60,182) (58,593) (60,182)

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Shares outstanding

End of period

(000's) 93,172 86,447 8% 93,172 86,447 8%

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Note:

(1) Non-GAAP measure - represents cash flow from operating activities

before non-cash working capital changes. Refer to Management's

Discussion and Analysis for discussion of this measure.

Third Quarter 2007 Operating Highlights

Berens is pleased to provide our third quarter results that show ongoing
drilling success, stable operating costs and increased cash flow:

- Drilling - Third quarter drilling continued to build on recent

success.

- Pembina year-to-date drilling has continued to be successful.

Our results continue to exceed our budgeted expectations with

100% success on 11 wells to the end of October with estimated

average well reserves of 1.4 bcf/well and six month average

production rates of 800 mcf/d.

- In Lanfine, we drilled 5 successful wells out of 6 in July but

chose to delay completion and tie in of the Lanfine wells

awaiting stronger natural gas prices.

- With Pembina leading the way combined with our success in

Lanfine and 100% successful first quarter Deep Basin drilling,

we expect to exceed our originally budgeted reserve additions

for 2007 with a capital program that has been reduced by 15%

due to lower gas prices.

- Year to date we have drilled 28 wells with a success rate of

86%.

- Production - Q3 2007 production averaged 3,618 boe/d, up 7% over

Q3 2006. Production for the first nine months of 2007 averaged

3,705 boe/d, up 12% compared to the first nine months of 2006. The Q3

production volumes were affected by the following decisions and

factors:

- normal production declines after low Q2 activities during

spring break-up

- September 1, 2007 disposition of Marten Hills: -80 boe/d

- Postponement of Lanfine well completion and tie in activities

to the end of October in anticipation of higher natural gas

prices: -100 boe/d

- number of third party plant turn around events: -50 boe/d

Our 2007 exit rate guidance remains at 3,900 boe/d with new

production additions totaling approximately 750 boe/d coming on

stream during Q4.

- Production Costs - Costs averaged $8.06 per boe in Q3 2007, up 1%

compared to $7.95 per boe in Q3 2006. Prior quarter adjustments from

third party processers accounted for $0.33 per boe of the third

quarter production costs. For the nine months ended September 30,

2007 costs averaged $7.67 per boe, down 4% compared to $7.95 per boe

for the first nine months of 2006. Higher production levels and

continued cost vigilance have kept production costs in check despite

inflationary industry pressures.

- Funds from Operations - Funds from operations for Q3 2007 were

$6.8 million ($0.07 per share), up 34% compared to Q3 2006 funds from

operations of $5.1 million ($0.06 per share). Higher Q3 2007

production, stable per unit operating costs, lower royalties and

stronger commodity prices contributed to the increase. For the

nine months ended September 30, 2007 funds from operations were

$21.6 million ($0.23 per share), up 32% compared to $16.4 million

($0.19 per share) for the first nine months of 2006.

- Land - Berens' total undeveloped land currently stands at 98,000 net

acres after the disposition of Marten Hills. All undeveloped lands

are located in the core areas of Pembina, Deep Basin and Lanfine.

Additionally, numerous down-spacing opportunities have been

identified on developed acreage, particularly in the Pembina area.

This land base sets up a diverse and high quality drilling program

throughout 2008 and beyond.

- Royalty Review - Our preliminary assessment of the Alberta royalty

changes suggests the effect on our longer term corporate cash flow

and asset value will be minimal at current forecasted gas prices.

Berens' Pembina and Deep Basin wells will benefit from the announced

Deep Gas royalty rate reductions announced in the royalty changes

beginning in 2009. We also believe we can be selective in our

drilling and production management to minimize the new royalty

effects on cash flow.


Report from Management

The third quarter of 2007 was highlighted by our return to drilling after spring break-up with a focus to continue our success in Pembina and complete our summer drilling program in Lanfine. Pembina drilling has continued to be successful with 6 more consecutive successful wells drilled from July 1 to the end of October 2007. In Lanfine, we drilled 5 successful wells out of 6 in July but chose to delay completion and tie in of the Lanfine wells awaiting stronger natural gas prices. Our results in Pembina continue to exceed our budgeted expectations with 100% success on 11 wells to the end of October with estimated average well reserves of 1.4 bcf/well and six month average production rates of 800 mcf/d. With Pembina leading the way combined with our success in Lanfine and 100% successful first quarter Deep Basin drilling, we expect to exceed our originally budgeted reserve additions for 2007 with a capital program that has been reduced by 15% due to lower gas prices. Year to date we have drilled 28 wells with a success rate of 86%.

Our production for the third quarter was 3,618 boe/d with over 750 boe/d anticipated to come on stream during fourth quarter. The third quarter volumes were reduced by the strategic sale of 250 boe/d in Marten Hills for $6.75 million on September 1st as we high graded our asset and portfolio base. In addition, completion and tie in of our 5 Lanfine wells was deferred to the fourth quarter to take advantage of expected stronger gas prices late in the year. This strategy has been successful as natural gas is trending above $6.00/mcf as we tie in 300 boe/d of production in Lanfine in late October and early November. Deep Basin production of over 250 boe/d is coming on stream in early November, later than expected, from 3 wells drilled in prior quarters that have been awaiting tie in due to limited plant capacity and surface and weather access issues. In Pembina, we expect an additional 225 boe/d production coming on stream in November and December as new wells are tied in. We remain confident that we will meet our targeted December exit volumes of 3,900 boe/d which will result in over 10% production growth year over year despite the disposition of 250 boe/d in September 2007.

Our continued focus on improving costs continues to pay off as our new well costs, particularly for drilling related activities, have dropped upwards of 20% from a year ago. With our continued emphasis on cost improvements and reduced industry activities we expect this trend to continue through the balance of 2007 and into 2008. Reduced costs, combined with our strong drilling results are resulting in competitive finding and development costs year to date.

We continue to proceed with our plans for first quarter 2008 and beyond. We have evaluated the implications of the recently announced government royalty changes on our cash flow and net asset value. Much of the future growth for Berens is focused in the Pembina and Deep Basin areas where we are successfully developing liquids rich tight gas reserves in the 2,000 to 2,700 metre depth range. These type of wells will benefit from the announced Deep Gas royalty rate reductions announced in the Alberta royalty changes beginning in 2009. Our preliminary assessment suggests the overall effect on our long term corporate cash flow and asset value will be minimal at current forecasted gas prices. We believe we can be selective in our drilling and production management to minimize the new royalty affects on cash flow and maximize value creation for our shareholders. As such, our plans for the fourth quarter of 2007 and into 2008 remain relatively unchanged.

Our recent drilling success, particularly in Pembina, is translating into volume growth with accompanying reserves being added at continually improving finding and development costs. Weak natural gas prices are a concern for our industry, however we remain optimistic prices will improve as western Canadian activity levels and supply volumes continue to drop. In the meantime, we are continuing to high-grade and improve our gas dominant asset base with long life production and reserves that will benefit from anticipated future gas prices while keeping an attentive eye on transactions that would be accretive to our shareholders.

Sincerely,

Daniel F. Botterill

President and C.E.O.



Berens Energy Ltd.

Third Quarter 2007

(unaudited)

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

November 6, 2007

OVERVIEW

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

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

The following discussion of financial position and results of operations should be read in conjunction with the Company's December 31, 2006 audited financial statements and notes thereto and the unaudited September 30, 2007 interim financial statements. This MD&A was prepared using information that is current as of November 6, 2007 unless otherwise noted.

FORWARD LOOKING INFORMATION

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

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



QUARTERLY INFORMATION

2007

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

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Sales volumes:

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

Oil and natural gas liquids (bbl/day) 570 560 499

Barrels of oil equivalent (bbl/day) 3,618 3,880 3,617

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Financial:

Net revenue 11,864 12,739 11,793

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

per share - basic ($/share) $(0.25) $(0.00) $(0.03)

per share - diluted ($/share) $(0.25) $(0.00) $(0.03)

Capital costs 8,541 6,208 18,329

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

Bank debt 50,800 62,700 59,980

Working capital (deficit) including

bank debt (58,593) (63,610) (67,468)

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Per unit information:

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

Oil and liquids price ($/barrel) $64.11 $58.98 $55.24

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

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

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Net wells completed: (No.)

Natural gas 5 1 5

Oil 2 - -

Dry 1 - 1

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Total 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

(bbl/day) 3,556 3,372 3,364 3,192

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Financial:

Net revenue 11,213 9,536 9,846 9,523

Net (loss) (21,951) (2,662) (1,606) (2,121)

per share - basic ($/share) $(0.24) $(0.03) $(0.02) $(0.03)

per share - diluted ($/share) $(0.24) $(0.03) $(0.02) $(0.03)

Capital costs 12,811 9,746 15,234 19,124

Shares outstanding (000's) 92,947 86,447 86,447 86,447

Bank debt 50,080 52,780 49,580 32,180

Working capital (deficit)

including bank debt (55,073) (60,182) (55,766) (45,907)

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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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2005

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($000's except as noted) Q4

Sales volumes:

Natural gas (mcf/day) 11,537

Oil and natural gas liquids

(bbl/day) 176

Barrels of oil equivalent

(bbl/day) 2,099

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Financial:

Net revenue 9,537

Net income (loss) (475)

per share - basic ($/share) $(0.01)

per share - diluted ($/share) $(0.01)

Capital costs 12,346

Shares outstanding (000's) 57,163

Bank debt -

Working capital (deficit)

including bank debt 4,273

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Per unit information:

Natural gas price ($/mcf) $11.26

Oil and liquids price ($/barrel) $41.92

Oil equivalent price ($/boe) $65.47

Operating netback ($/boe) $39.78

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Net wells completed: (No.)

Natural gas 9

Oil 1

Dry 2

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Total 12

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

RESULTS OF OPERATIONS

Production Volume

Production volume averaged 3,618 boe/d for the third quarter of 2007, up seven percent compared to 3,374 boe/d in the third quarter of 2006 and down seven percent compared to the second quarter of 2007. Natural gas represented 84 percent of production in the second quarter of 2007 with the remaining production being 15 percent light oil and natural gas liquids and one percent conventional heavy oil. Third quarter 2007 volumes were down from the second quarter of 2007 due to:



- normal production declines after low activity during spring break-up

in the second quarter of 2007

- 100 boe/d due to the decision to delay Lanfine well completion and

tie in activities to the end of October to take advantage of expected

higher natural gas prices

- 50 boe/d due to a number of third party plant turn around events

during the second quarter

- 80 boe/d due to the September 1, 2007 disposition of Marten Hills


Volume averaged 3,705 boe/d for the first nine months of 2007, up 12 percent compared to 3,311 boe/d in the first nine months of 2006. The expected 2007 exit rate of production is 3,900 boe/d with final quarter natural decline being more than offset by 300 boe/d of production in Lanfine connected in late October and early November, Deep Basin production of over 250 boe/d coming on stream in early November, and an additional 225 boe/d in Pembina production coming on stream in November and December from drilling activity. Nine (7.7 net) wells were drilled in the third quarter of 2007 resulting in 6 (4.7 net) natural gas wells and 2 (2 net) oil wells. Twenty five (14.8 net) wells have been drilled in the first nine months of 2007 resulting in 19 (10.7 net) natural gas wells and 2 (2 net) oil wells for an overall net success rate of 86 percent.

Production Revenue

Natural gas prices averaged $5.94 per mcf for the third quarter of 2007, almost unchanged compared to $5.91 per mcf in the third quarter of 2006. Oil and liquids prices averaged $64.43 and $63.96 per barrel respectively in the third quarter of 2007 for a blended price of $64.11 per barrel, up three percent from the third quarter 2006 blended oil and liquids price of $62.07 per barrel. On a boe basis, prices averaged $40.14 in the third quarter of 2007, up two percent compared to $39.24 per boe in the third quarter of 2006. Revenue was up 10 percent in the third quarter of 2007 compared to the third quarter of 2006 as production volume increased and prices were up slightly. An additional $3.59 per boe was realized from hedging gains during the third quarter of 2007.

Natural gas prices averaged $7.11 per mcf for the nine months ended September 30, 2007, up 20 percent compared to $5.91 per mcf in the nine months ended September 30, 2006. Oil and liquids prices averaged $57.37 and $60.59 per barrel respectively in the nine months ended September 30, 2007 for a blended price of $59.66 per barrel, down four percent from the nine months ended September 30, 2006 blended oil and liquids price of $62.07 per barrel. On a boe basis, prices averaged $45.15 in the nine months ended September 30, 2007, up 15 percent compared to $39.24 per boe in the nine months ended September 30, 2006. Revenue was up 19 percent in the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006 as both volume and prices increased. An additional $1.29 per boe was realized from hedging gains during 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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2007 2006 Change 2007 2006 Change

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Production revenue ($000's) 13,390 12,173 10% 45,718 38,424 19%

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Production volume

Natural gas (mcf/d) 18,288 17,355 5% 18,969 17,077 11%

Oil and liquids (bbl/d) 570 479 19% 543 465 17%

BOE (bbl/d) 3,618 3,372 7% 3,705 3,311 12%

Prices

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Natural gas ($/mcf) 5.94 5.91 1% 7.11 5.91 20%

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Oil and liquids ($/bbl) 64.11 62.07 3% 59.66 62.07 (4%)

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BOE ($/boe) 40.14 39.24 2% 45.15 39.24 15%

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Royalties

Royalties averaged 20 percent of revenue for the third quarter of 2007 compared to 23 percent in the third quarter of 2006. Lower royalties in the third quarter of 2007 compared to the third quarter of 2006 are mainly due to a fixed price natural gas sales contract at above the Q3 2007 market prices that are used for royalty calculations. Royalties averaged 23 percent of revenue for the nine months ended September 30, 2007 compared to 23 percent for the nine months ended September 30, 2006.

Royalty expense of $2.7 million was recorded in the third quarter of 2007, up three percent compared to the third quarter of 2006 reflecting higher volume offset partially by lower per unit royalty rates. Royalty expense of $10.6 million was recorded in the nine months ended September 30, 2007, up 12 percent compared to the nine months ended September 30, 2006 due to higher production volume and higher commodity prices.

On an ongoing basis, royalties are expected to average approximately 24 percent of revenues without the go-forward benefit of ARTC which has been rescinded effective January 1, 2007.



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Three months Nine months

Royalties ended September 30 ended September 30

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2007 2006 Change 2007 2006 Change

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Royalty expense ($000'S) 2,724 2,637 3% 10,628 9,519 12%

Royalty cost per boe $8.19 $8.91 (8%) $10.51 $8.91 18%

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Production Expenses

Production expenses were $8.06 per boe in the third quarter of 2007, up one percent compared to $7.95 per boe in the third quarter of 2006. Third quarter 2007 costs were increased by $110,000 ($0.33 per boe) of third party processing fee adjustments from prior quarters. Higher production volume and ongoing vigilance on costs have kept per unit costs stable. 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 $7.67 per boe in the nine months ended September 30, 2007, down four percent compared to $7.95 per boe in the nine months ended September 30, 2006. With ongoing volume increases and cost management, it is expected future per unit operating expenses will remain below $8.00 per boe.

Third quarter 2007 production expenses were $2.7 million, up nine percent compared to the third quarter of 2006 due to higher volumes. Production expenses for the nine months ended September 30, 2007 were $7.8 million, up 14 percent compared to the nine months ended September 30, 2006 mainly due to higher volumes.



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Three months Nine months

Production expenses ended September 30 ended September 30

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2007 2006 Change 2007 2006 Change

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Production expenses ($000's) 2,684 2,465 9% 7,756 6,816 14%

Production expenses per boe $8.06 $7.95 1% $7.67 $7.95 (4%)

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Transportation costs increased $0.1 million, or 20 percent in the third
quarter of 2007 compared to the third 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. Third quarter 2007 operating netbacks
improved due to higher per boe prices and lower per unit royalty rates.

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Quarterly Operating Three months Nine months

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

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2007 2006 Change 2007 2006 Change

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Sales price 40.14 39.24 2% 45.15 39.24 15%

Less:

Royalties (net of ARTC) 8.19 8.91 (8%) 10.51 8.91 18%

Production expenses 8.06 7.95 1% 7.67 7.95 (4%)

Transportation charges 0.94 0.84 12% 0.95 0.84 13%

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Operating netback 22.95 21.54 7% 26.03 21.54 21%

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(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 $1.2 million in the third quarter of 2007, up 17 percent compared to the third quarter of 2006. In the nine months ended September 30, 2007 G&A expenses were $3.7 million, down three percent compared to the nine months ended September 30, 2006. Costs in 2007 compared to 2006, benefited by general and administrative cost recoveries from partners on capital projects operated by Berens. In 2006 a higher proportion of the Company's capital activity was directed to 100 percent owned lands resulting in less administrative cost recovery. On a per unit basis, general and administrative costs were $3.72 per boe for the third quarter of 2007, up 10 percent compared to $3.39 per boe in the third quarter of 2006. In the nine months ended September 30, 2007 per unit G&A costs were $3.66 per boe, down 14 percent compared to $4.24 per boe for the nine months ended September 30, 2006. There were no general and administrative costs capitalized in the third quarter or for the first nine months of 2007 or 2006.

Staff levels are expected to remain fairly constant for the remainder of 2007 and into 2008. Per unit general and administrative costs are expected to decline as production levels increase.



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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

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G&A expenses ($000's) 1,236 1,053 17% 3,698 3,829 (3%)

G&A expenses per boe $3.72 $3.39 10% $3.66 $4.24 (14%)

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Depletion, Amortization and Accretion

Depletion, amortization and accretion ("DA&A") totaled $9.8 million ($29.55 per boe) in the third quarter of 2007, up 13 percent compared to $8.7 million ($28.05 per boe) in the third quarter of 2006. Marten Hills sales proceeds were lower than the booked value of the related assets sold causing an increase in the per unit depletion rate for the quarter. In the nine months ended September 30, 2007 DA&A totaled $29.8 million ($29.46 per boe), up 10 percent but two percent lower on a boe basis compared to $27.2 million ($30.06 per boe) in the nine months ended September 30, 2006. Drilling results have improved in 2007 and new reserves have been added at lower per unit costs compared to the first nine months of 2006 resulting in lower per unit depletion rates.



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Depletion, Amortization Three months Nine months

and Accretion ended September 30 ended September 30

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2007 2006 Change 2007 2006 Change

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DA&A expenses ($000's) 9,835 8,701 13% 29,802 27,177 10%

DA&A expenses per boe $29.55 $28.05 5% $29.46 $30.06 (2%)

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Interest Expense

Interest expense was $1.1 million in the third quarter of 2007 compared to $0.9 million in the third quarter of 2006. In the nine months ended September 30, 2007 interest expense was $3.1 million compared to $1.7 million in the nine months ended September 30, 2006. Berens raised equity in the fourth quarter of 2005 in anticipation of the acquisition of Berland and had a significant cash position at the start of 2006. The subsequent closing of the Berland acquisition in January 2006 resulted in significant borrowing on the bank operating line as 30 percent of the Berland acquisition cost was in the form of cash and Berens assumed Berland's debt and working capital deficiency, totaling $28 million. Capital expenditures in 2006 and the first quarter of 2007 were higher than funds from operations resulting in higher average debt levels in the 2007 periods compared to the same periods in 2006. The interest rate on the bank line was also 1.25 percent higher in the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006.



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Three months Nine months

Interest Expense ended September 30 ended September 30

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2007 2006 Change 2007 2006 Change

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Interest expenses ($000's) 1,054 856 23% 3,079 1,655 86%

Interest expenses per boe $3.17 $2.76 15% $3.04 $1.83 66%

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Income Taxes

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

Future tax recovery was $0.9 million for the third quarter of 2007 compared to a recovery of $1.2 million for the third quarter of 2006 as the net loss before income taxes was lower in 2007 combined with lower income tax rates in the 2007 period.

NET LOSS

The net loss for the third quarter of 2007 was $23.2 million ($0.25 per share) compared to a loss of $2.7 million ($0.03 per share) in the third quarter of 2006. The larger third quarter 2007 loss resulted primarily from the impairment of goodwill offset by higher production volume and stable per unit operating costs.

The net loss for the nine months ended September 30, 2007 was $26.8 million ($0.29 per share) compared to a net loss of $6.4 million ($0.07 per share) for the nine months ended September 30, 2006. The larger loss in the nine months ended September 30, 2007 period was primarily due to the impairment of goodwill.

CAPITAL COSTS

Capital costs were $8.5 million before accounting for the sale of Marten Hills in the third quarter of 2007 compared to $11.5 million in the third quarter of 2006. The Marten Hills assets were sold in the third quarter of 2007 for proceeds of $6.8 million, reducing the quarterly spending total to $1.9 million. A seismic data base was sold in the third quarter of 2006 for $1.8 million. In the nine months ended September 30, 2007 $32.9 million of capital costs were incurred compared to $46.9 million in the nine months ended September 30, 2006. The 2006 period reflects a very active capital program following the acquisition of Berland Exploration in January 2006. A total of 25 wells (14.8 net) were drilled in the first nine months of 2007, compared to 37 wells (21.3 net) in the first nine months of 2006.



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Three months Nine months

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

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2007 2006 2007 2006

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Drilling and completion 6,786 7,694 21,336 31,011

Equipping and tie-in 478 3,393 8,126 9,752

Land 750 284 1,376 1,967

Geological and geophysical 490 81 2,020 2,429

Office and other 37 58 52 708

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Total 8,541 11,510 32,910 45,867

Asset retirement obligation 127 60 298 319

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Total exploration and development 8,668 11,570 33,208 46,185

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Net acquisitions (dispositions) (6,750) (1,764) (6,750) (1,764)

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Total capital 1,918 9,806 26,458 44,421

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Drilling, completions and tie-in activity represented 85 percent of the capital spent in the third quarter of 2007 and 90 percent of capital for the nine months ended September 30, 2007 as capital activity focused on developing the extensive land base. A $39 million capital budget will be spent in 2007, over 90 percent of which is targeted toward drilling, completion and tie-in activity. It is expected that capital spending for the remainder of the year will be funded by cash flow provided by operating activities.

WORKING CAPITAL

Accounts receivable of $9.9 million at September 30, 2007 was primarily revenue receivables ($4.5 million) and amounts owing from partners ($5.2 million). Accounts payable at September 30, 2007 of $20.8 million were mainly comprised of trade payables for capital and operating costs ($7.7 million), royalties ($2.0 million), amounts owing to partners ($2.5 million), unspent cash calls received from partners ($3.2 million) and capital costs accrued at the end of the quarter for ongoing drilling and completion operations ($3.1 million).

Working capital excluding bank indebtedness was in a deficit position of $7.8 million at September 30, 2007. Borrowings under the bank line and ongoing cash flows are expected to fund the working capital deficit.

LIQUIDITY AND CAPITAL RESOURCES

The Company plans to fund its current working capital deficit, operations and capital costs with a mix of operating cash flow and debt financing through the bank operating line. An operating bank line was in place for $62.5 million, secured by producing properties at September 30, 2007. The line was reduced from $65.0 million during the third quarter of 2007 concurrent with the sale of the Marten Hills assets for proceeds of $6.75 million. At September 30, 2007, $50.8 million was drawn on the bank line. Future capital spending is planned at amounts that can be met with expected Company cash flow.

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 have 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.

NON-GAAP MEASUREMENTS

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

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



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

Three months Nine months

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

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

2007 2006 2007 2006

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

Cash flow provided by (used in)

operating activities 15,893 4,194 26,730 8,611

Changes in non-cash working

capital items related to

operating activities (9,082) 890 (5,166) 7,741

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

Funds from operations 6,811 5,084 21,564 16,352

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

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


Funds from operations are also presented on a per share basis consistent with the calculation of net loss per share, whereby per share amounts are calculated using the weighted average number of shares outstanding. Funds from operations per share were $0.07 (basic and diluted) for the third quarter of 2007 and $0.23 per share (basic and diluted) for the nine months ended September 30, 2007 compared to $0.06 per share for the third quarter of 2006 and $0.19 for the nine months ended September 30, 2006.

RISKS

Primary financial risks relate to volatility of commodity prices. Interest rate and currency exchange rate fluctuations also have an effect on financial results. The effect of changes in the exchange rate between US and Canadian currencies on natural gas prices is not direct, as variations between the regional markets for natural gas are often much greater than can be explained by currency variability. The Province of Alberta announced plans for significant royalty changes for both conventional oil and natural gas and oil sands operations beginning in 2009. The affect of the changes to the royalty structure in Alberta may cause significant 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 September 30, 2007. All contracts are priced in Canadian dollars per gigajoule (GJ). The price per GJ can be converted to an approximate price per MCF by multiplying the per GJ price by 1.05. GJ can be converted to an approximate MCF volume by multiplying the GJ volume by 0.95.



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

Daily

quantity

(GJ) Term of Contract Fixed price per gigajoule

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

2,000 April 1 to October 31, 2007 $6.00 floor; $8.50 cap

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

2,000 November 1 to December 31, 2007 $6.00 floor; $11.05 cap

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

2,000 April 1 to October 31, 2007 $7.00 floor; $8.00 cap

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

2,000 November 1 to December 31, 2007 $7.00 floor; $9.85 cap

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

2,000 April 1 to October 31, 2007 $7.25 floor; $8.25 cap

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

2,000 November 1, 2007 to March 31, 2008 $7.25 floor; $8.65 cap

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

2,000 June 1, 2007 to March 31, 2008 $7.50 floor; $9.45 cap

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


The fair value of the above natural gas derivative instruments marked to market as at September 30, 2007, results in an unrealized gain position of $1,457,000 compared to an unrealized gain position of $635,000 at December 31, 2006. There was $1,198,000 of realized gains on derivative instruments in the third quarter of 2007 and $1,306,000 for the nine months ended September 30, 2007. There were no derivative instruments in place during the first quarter or the first nine months of 2006. A physical fixed price contract to sell 2,000 GJ per day from January 1 to October 31, 2007 at a price of $7.65 per GJ is also in place for the purpose of reducing exposure to natural gas price volatility. The average floor price of the hedging transactions for 2007, including the fixed price sales contract, is $7.01 per GJ ($7.37 per mcf) with the average ceiling set at $8.75 per GJ ($9.21 per mcf).

RELATED PARTY TRANSACTIONS

A consulting firm is contracted from time to time in which one of the Company's directors is the chairman and founding partner. The executive services rendered are in the normal course of business and are at normal rates charged by the consulting firm and recorded at the exchange amount. Consulting fees for this firm in the first nine months of 2007 were 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 2007 were $54,000 and $183,000 for the nine months ended September 30, 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 6,241,533 common shares have been issued.

DISCLOSURE CONTROLS AND PROCEDURES OVER FINANCIAL REPORTING

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

INTERNAL CONTROL OVER FINANCIAL REPORTING

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

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

RISKS AND UNCERTAINTIES, CRITICAL ACCOUNTING ESTIMATES AND RECENT

ACCOUNTING PRONOUNCEMENTS

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

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

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

OUTLOOK

Berens has demonstrated production growth, controlled costs and improved drilling success. Production growth has followed the drilling success experienced in late 2006 and throughout 2007. Production stalled in the third quarter of 2007 as management decided to delay tie ins in Lanfine and to sell the Marten Hills assets. During the first nine months of 2007 the net drilling success has been 86 percent and the average well result for reserves and production have exceeded expectation. There has also been some moderation in the industry cost structure. These factors are combining to lower the Company's finding and development costs in 2007.

Capital spending for 2007 is projected at $39 million and will be aligned with cash flow for the remainder of the year. Net capital spending, after taking into account the sale of Marten Hills, is projected to be $32 million. Capital spending for the remainder of the year will be focused in Pembina where the reserve life of new wells is longest and the wells have the strongest economics. There are currently 75 inventoried drilling locations on existing lands. An active drilling program is planned for the first quarter of 2008 in Pembina and Deep Basin.

Debt and working capital balances have improved and are at manageable levels with the planned capital spending plans. With ongoing production and reserve growth, management anticipates that the Company will be well positioned to develop our asset base once natural gas prices return to more acceptable levels.



Berens Energy Ltd.

Balance Sheets

(unaudited)

As at,

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

September 30, December 31,

(000's) 2007 2006

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

ASSETS (note 6)

Current

Cash and cash equivalents $ 1 $ 10

Accounts receivable 9,911 19,601

Unrealized gain on risk management (note 10) 1,457 635

Prepaid expenses and deposits 1,634 1,412

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

13,003 21,658

Investments - 29

Property, plant and equipment (note 4) 168,076 171,178

Goodwill (note 11) - 20,755

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

$ 181,079 $ 213,620

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

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

LIABILITIES AND SHAREHOLDERS' EQUITY

Current

Bank loan (note 6) $ 50,800 50,080

Accounts payable and accrued liabilities 20,787 $ 26,622

Taxes payable 10 29

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

71,597 76,731

COMMITMENTS (note 10)

Asset retirement obligations (note 5) 3,185 2,645

Future income taxes 12,440 14,518

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

87,222 93,894

Shareholders' equity

Capital stock (note 7) 148,263 148,038

Contributed surplus (note 7) 1,956 1,290

Deficit (56,362) (29,602)

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

93,857 119,726

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

$ 181,079 $ 213,620

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

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

See accompanying notes to the financial statements



Berens Energy Ltd.

Statements of Operations and Deficit

(unaudited)

For the three and nine months ended September 30,

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

Three months ended Nine months ended

(000's) September 30, September 30,

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

2007 2006 2007 2006

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

Revenue

Oil and natural gas revenue $ 13,390 $ 12,173 $ 45,718 $ 38,424

Realized gain on risk management

(note 10) 1,198 - 1,306 -

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

14,588 12,173 47,024 38,424

Royalties, net of ARTC (2,724) (2,637) (10,628) (9,519)

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

11,864 9,536 36,396 28,905

Unrealized gain (loss) on risk

management (note 10) (5) - 822 -

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

11,859 9,536 37,218 28,905

Other income 31 1 31 18

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

11,890 9,537 37,249 28,923

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

Expenses

Production 2,684 2,465 7,756 6,816

Transportation 313 261 961 814

Depletion, amortization and

accretion 9,836 8,701 29,802 27,177

Impairment of goodwill (note 11) 20,755 - 20,755 -

General and administrative (note 9) 1,003 849 3,032 3,247

Stock-based compensation (note 7) 233 204 666 582

Interest 1,054 856 3,079 1,655

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

35,878 13,336 66,051 40,291

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

Loss before income taxes (23,988) (3,799) (28,802) (11,368)

Income taxes

Future expense (recovery) (861) (1,159) (2,077) (5,018)

Current expense 30 22 35 39

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

(831) (1,137) (2,042) (4,979)

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

Loss and Comprehensive Loss for

the period (23,157) (2,662) (26,760) (6,389)

Deficit, beginning of period (33,205) (4,989) (29,602) (1,262)

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

Deficit, end of period $(56,362) $ (7,651) $(56,362) $ (7,651)

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

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

Loss per share (note 12)

Basic and diluted $ (0.25) $ (0.03) $ (0.29) $ (0.08)

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

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

See accompanying notes to the financial statements



Berens Energy Ltd.

Statements of Cash Flows

(unaudited)

For the three and nine months ended September 30,

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

Three months ended Nine months ended

(000's) September 30, September 30,

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

2007 2006 2007 2006

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

OPERATING ACTIVITIES

Loss for the period $(23,157) $ (2,662) $(26,760) $ (6,389)

Add items not involving cash

Depletion, amortization and

accretion 9,836 8,701 29,802 27,177

Impairment of goodwill 20,755 - 20,755 -

Unrealized risk management

(gain) loss 5 - (822) -

Future income tax expense

(recovery) (861) (1,159) (2,077) (5,018)

Stock-based compensation 233 204 666 582

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

6,811 5,084 21,564 16,352

Change in non-cash working capital

items related to operating

activities (note 8) 9,082 (890) 5,166 (7,741)

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

Cash flow provided by (used in)

operating activities 15,893 4,194 26,730 8,611

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

FINANCING ACTIVITIES

Change in bank loan (11,900) 3,200 720 33,030

Proceeds from exercise of stock

options - - 225 -

Net proceeds from private

offerings - - - 19,813

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

Cash flow provided by financing

activities (11,900) 3,200 945 52,843

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

INVESTING ACTIVITIES

Cash acquired through Berland

acquisition - - - 109

Cash component on Berland

acquisition - - - (28,682)

Proceeds from sale of investment 3 245 29 245

Purchase of property and equipment (8,541) (11,510) (32,910) (45,867)

Proceed from disposition of assets 6,750 1,764 6,750 1,764

Change in non-cash working capital

items related to investing

activities (note 8) (2,214) 2,116 (1,553) 1,550

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

Cash flow used in investing

activities (4,002) (7,385) (27,684) (70,881)

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

Decrease in cash and cash

equivalents (9) 9 (9) (9,427)

Cash and cash equivalents,

beginning of period 10 35 10 9,471

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

Cash and cash equivalents, end

of period $ 1 $ 44 $ 1 $ 44

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

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

See accompanying notes to the financial statements



BERENS ENERGY LTD.

Notes to Financial Statements

(unaudited)

For the three and nine months ended September 30, 2007 and 2006

1. NATURE OF OPERATIONS

The Company is a full cycle oil and natural gas exploration and

production company with activities encompassing land acquisition,

geological and geophysical assessment, drilling and completion, and

production. The primary areas of operation are in eastern and west

central Alberta. Significant capital spending activity occurs in the

winter months in the western Canadian oil and natural gas business as

many areas are only accessible or best accessed in the winter months when

the ground is frozen. Limited capital spending activity tends to occur in

the second calendar quarter as the industry experiences "spring break-

up" when there is significant water on the ground due to melting snow and

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

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

return in the June time frame each year.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The interim financial statements have been prepared by management

following the same accounting policies as the most recent annual audited

financial statements except as noted below.

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

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

reporting purposes. Accordingly, these interim financial statements

should be read in conjunction with the audited annual financial

statements for the year ended December 31, 2006. Certain prior period

amounts have been reclassified to conform to current disclosure.

As of January 1, 2007, the Company was required to adopt the Canadian

Institute of Chartered Accountants ("CICA") Section 1530 "Comprehensive

Income", Section 3251 "Equity", Section 3855 "Financial Instruments -

Recognition and Measurement", and Section 3865 "Hedges", which were

issued in January 2005. Under the new standards, a new financial

statement, the Consolidated Statement of Comprehensive Income (loss), has

been introduced that will provide for certain gains and losses and other

amounts arising from changes in fair value, to be temporarily recorded

outside the income statements. In addition, all financial instruments,

including derivatives, are to be included in the Company's Balance Sheet

and measured, in most cases, at fair values, and requirements for hedge

accounting have been further clarified. The Company has adopted these

pronouncements. The Company uses fair value accounting for derivative

instruments that do not qualify or are not designated as hedges.

As of January 1, 2007, the Company was required to adopt revised CICA

Section 1506, "Accounting Changes", which provides expanded disclosures

for changes in accounting policies, accounting estimates and corrections

of errors, which were issued in July 2006. Under the new standard,

accounting changes should be applied retrospectively unless otherwise

permitted or where they are not practical to determine. As well,

voluntary changes in accounting policy are made only when required by a

primary source of GAAP or when the change results in more relevant and

reliable information.

The effect of adopting these standards on the Company's financial

statements has been negligible.

3. ACQUISITION OF BERLAND EXPLORATION LTD.

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

closed a previously announced arrangement that saw Berens acquire

Berland. The total cost to Berens to acquire the Berland shares was

$102.7 million. This acquisition has been accounted for using the

purchase method with the Berland results included in the statement of

operations from the closing date of January 18, 2006.

The following table summarizes the estimated fair value of the assets

acquired and liabilities assumed as at the closing date.

Assets and liabilities purchased ($000's)

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

Cash and cash equivalents 109

Accounts receivable 10,321

Prepaid expenses and deposits 1,488

Petroleum and natural gas properties 97,616

Goodwill 30,288

Accounts payable and accrued liabilities (20,247)

Future income taxes (16,111)

Asset retirement obligations (715)

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

Total cost to acquire Berland 102,749

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

4. PROPERTY, PLANT AND EQUIPMENT

September 30, 2007 December 31, 2006

Accumulated Accumulated

depletion and depletion and

($000's) Cost depreciation Cost depreciation

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

Petroleum and natural

gas properties 266,452 98,781 240,047 69,305

Office and computer

equipment 730 325 678 242

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

267,182 99,106 240,725 69,547

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

Net book value 168,076 171,178

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

At September 30, 2007, costs of $22,033,000 (2006 - $25,907,000) related

to undeveloped land have been excluded from the depletion and

depreciation calculation. At September 30, 2007 estimated future

development costs of $13,018,000 have been included in the depletion and

depreciation calculation. A ceiling test was completed at September 30,

2007 resulting in no impairment.

5. ASSET RETIREMENT OBLIGATIONS

The total future asset retirement obligations were estimated based on the

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

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

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

value of the total asset retirement obligations is $3,185,000 as at

September 30, 2007 (2006 - $2,431,000) based on a total future liability

of $8,512,000 (2006 - $5,204,000). These payments are expected to be made

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

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

of the asset retirement obligations.

The following table reconciles the asset retirement obligations for the

nine months ended:

September 30, September 30,

($000's) 2007 2006

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

Obligation, beginning of the period 2,645 1,223

Increase in obligation during the period 297 318

Obligation assumed from Berland acquisition - 715

Accretion expense 243 175

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

Obligation, end of the period 3,185 2,431

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

6. BANK OPERATING LINE

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

totaling $62.5 million at September 30, 2007. Collateral for the facility

consists of a general assignment of book debts and a $75.0 million

debenture with a floating charge over all assets of the Company. The bank

line is a demand line and carries an interest rate of the Bank's prime

rate adjusted for a factor based on the most recent quarterly debt to

cash flow calculation. The rate at September 30, 2007 was 7.00 percent

(September 30, 2006 - 6.5 percent). On September 30, 2007, $50,800,000

was drawn on the line (December 31, 2006 - $50,080,000).

7. CAPITAL STOCK

(a) Authorized Capital

The authorized capital consists of an unlimited number of preferred

shares issuable in series and an unlimited number of common shares

without nominal or par value.

(b) Common shares issued

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

Consideration

Number ($000's)

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

Balance March 31, 2007 and December 31, 2006 92,947,064 148,038

Exercise of stock options 225,000 225

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

Balance June 30, 2007 and September 30, 2007 93,172,064 148,263

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

(c) Stock Option Plan

A stock option plan is in place under which 7,500,000 common shares have

been reserved for options to be granted to directors, officers, employees

and consultants with terms established by the board of directors.

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

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

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

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

to the date of the grant.

The following table sets forth a reconciliation of the plan activity

during the nine months ended September 30,

2007 2006

Weighted Weighted

average average

exercise exercise

Number of price ($ Number of price ($

Options per share) Options per share)

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

Outstanding, January 1, 4,416,200 1.68 3,513,700 1.56

Granted 2,309,500 0.94 885,000 2.16

Cancelled (259,167) 1.98 (7,500) 2.90

Exercised (225,000) 1.00 - -

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

Outstanding, end of

period 6,241,533 1.42 4,391,200 1.69

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

Exercisable 2,740,696 1.44 1,975,692 1.15

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

The following table sets forth additional information relating to the

stock options outstanding at September 30, 2007.

Options Outstanding Exercisable Options

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

Weighted Weighted

average average

exercise Weighted exercise Weighted

price average price average

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

range Options share) expiry Options share) expiry

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

$0.50 to $1.39 4,053,500 1.00 3.19 1,537,995 1.07 1.25

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

$1.40 to $2.29 1,127,200 1.54 2.30 846,867 1.51 1.83

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

$2.30 to $3.19 920,833 2.83 3.24 309,167 2.83 3.24

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

$3.20 to $4.09 140,000 3.24 3.32 46,667 3.24 3.32

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

6,241,533 1.42 3.04 2,740,696 1.44 1.69

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

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

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

Scholes based valuation of options are: Risk free rate - 4.3 percent;

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

volatility. Estimated future forfeiture assumptions are not used in

calculations and forfeitures are recognized as they occur. The weighted

average option price for options outstanding at September 30, 2007 is

$0.57 per option. Based on the fair value method, $233,000 was recorded

as compensation expense for the quarter ended September 30, 2007 and

$666,000 was recorded as compensation expense for the nine months ended

September 30, 2007 (2006 - $204,000 and $582,000) with corresponding

increases recorded to contributed surplus.

(d) Contributed Surplus

The following table sets forth the continuity of contributed surplus for

the three and nine months ended September 30,

($000's) Three months Nine months

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

Opening balance, beginning of period 1,723 1,290

Stock based compensation expense 233 666

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

Closing balance, September 30, 2007 1,956 1,956

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

8. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in Non-cash Working Capital

For the nine months ended September 30,

($000's) 2007 2006

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

Accounts receivable 9,690 (5,513)

Prepaid expenses and deposits (222) (1,755)

Accounts payable and accrued liabilities (5,836) 9,580

Taxes payable (19) (65)

Non-cash working capital acquired (note 3) - (8,438)

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

3,613 (6,191)

Change in non-cash working capital related to

investing activities (1,553) 1,550

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

Change in non-cash working capital related to

operating activities 5,166 (7,741)

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

Cash interest and taxes paid

For the three and nine months ended September 30,

Three Three Nine Nine

months months months months

($000's) 2007 2006 2007 2006

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

Income and other taxes 27 - 27 117

Interest 1,054 856 3,079 1,655

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

9. RELATED PARTY TRANSACTIONS

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

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

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

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

Consulting fees for this firm in the first nine months of 2007 were nil

(2006 - $90,000). Fees for legal services are paid to a law firm in which

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

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

Legal fees for this firm paid in the third quarter of 2007 were $54,000

and $183,000 for the nine months ended September 30, 2007 (2006 - $36,000

and $532,000).

10. FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments

Financial instruments recognized on the balance sheets consist of cash

and cash equivalents, accounts receivable, deposits, accounts payable,

bank loans and financial derivatives used to manage natural gas price

risk.

Cash, cash equivalents and financial derivatives are designated as "held-

for-trading". Deposits are designated as "held-to-maturity". Accounts

receivable and bank loans are designated as "loans and receivables" and

accounts payable are designated as "other liabilities". The fair value of

these financial instruments approximates their carrying amounts due to

their short terms to maturity except for the financial derivatives which

values are outlined below.

(a) Credit Risk

Accounts receivable are with customers, sales agents and joint venture

partners in the petroleum and natural gas business and are subject to the

usual credit risks. The Company mitigates this risk by entering into

transactions with long-standing, reputable counterparties and partners.

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

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

capital spending taking place.

(b) Interest Rate Risk

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

debt.

(c) Foreign Exchange Risk

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

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

dollars or directly influenced by U.S. dollar benchmark prices. Commodity

price risk management transactions are denominated in Canadian dollars

which mitigates the effect of currency volatility on commodity sales

volumes that are covered by commodity price hedges.

(d) Commodity Price Risk Management

The following is a summary of natural gas price risk management

derivative contracts in effect as of September 30, 2007. All contracts

are priced in Canadian dollars per gigajoule (GJ) and are designated as

"held-for-trading." The price per GJ can be converted to an approximate

price per mcf by multiplying the per GJ price by 1.05. GJ volume can be

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

0.95.

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

Daily

quantity

(GJ) Term of Contract Fixed price per gigajoule

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

2,000 April 1 to October 31, 2007 $6.00 floor; $8.50 cap

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

2,000 November 1 to December 31, 2007 $6.00 floor; $11.05 cap

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

2,000 April 1 to October 31, 2007 $7.00 floor; $8.00 cap

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

2,000 November 1 to December 31, 2007 $7.00 floor; $9.85 cap

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

2,000 April 1 to October 31, 2007 $7.25 floor; $8.25 cap

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

2,000 November 1, 2007 to March 31, 2008 $7.25 floor; $8.65 cap

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

2,000 June 1, 2007 to March 31, 2008 $7.50 floor; $9.45 cap

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

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

market as at September 30, 2007, results in an unrealized gain of

$1,457,000 compared to an unrealized gain of $635,000 at December 31,

2006. There were $1,198,000 in realized gains from derivative instruments

in the quarter ended September 30, 2007 and $1,306,000 in realized gains

for the nine months ended September 30, 2007. There were no derivative

instruments outstanding for the third quarter or first nine months of

2006.

11. GOODWILL

The Company tested the goodwill balance as at September 30, 2007 taking

into account the decline in corporate economic value caused by the 2007

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 estimated 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 $20,755,000.

12. PER SHARE INFORMATION

The weighted average number of common shares outstanding for the quarter

ended September 30, 2007 of 93,172,064 was used to calculate basic and

diluted loss per share (2006 - 86,447,064). The weighted average number

of common shares outstanding for the nine month period ended

September 30, 2007 was 93,031,771 (2006 - 84,516,269). Outstanding

options have been excluded in the calculation of per share information as

they were anti-dilutive.

Caution Regarding Forward Looking Information

This press release contains forward looking information within the

meaning of applicable securities laws. Forward looking statements may

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

statements that are not statements of fact. Forward looking information

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

respect to capital expenditures and related allocations, production

volumes, production mix and commodity prices.

Forward-looking statements and information are based on current beliefs

as well as assumptions made by and information currently available to

Berens concerning anticipated financial performance, business prospects,

strategies and regulatory developments. Although management considers

these assumptions to be reasonable based on information currently

available to it, they may prove to be incorrect.

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

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

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

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

statements as a number of important factors could cause the actual

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

expectations and anticipations, estimates and intentions expressed in

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

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

interest rate fluctuations, availability of services and supplies, market

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

development expenditures, production levels and the timing of achieving

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

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

future growth prospects and current and expected financial requirements

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

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

secure adequate product transportation, changes in environmental and

other regulations and general economic conditions.

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

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

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

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

or otherwise. This cautionary statement expressly qualifies the forward-

looking statements contained in this press release.

Contact Information

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

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